-I enm :::! s:: 0z -< 0 0z -I .9 G) m C5 m }J c.. z BEFORE THE PUBLIC UTILITIES COMMISSION OF THE STATE OF COLORADO
IN THE MATTER OF ADVICE LETTER ) NO. 530, FILED BY ATMOS ENERGY ) CORPORATION TO PLACE INTO ) Proceeding No. 17AL-_G EFFECT TARIFF SHEET CHANGES TO ) BE EFFECTIVE ON JULY 27, 2017 )
DIRECT TESTIMONY AND ATTACHMENTS OF
JARED N. GEIGER
June 26, 2017
SUBMITTED ON BEHALF OF ATMOS ENERGY CORPORATION TABLE OF CONTENTS
I. EXECUTIVE SUMMARY ...... 1
II. INTRODUCTION AND PURPOSE OF TESTIMONY ...... 2
UL BILLING DETERMINANTS ...... 4
IV. WEATHER NORMALIZATION ADJUSTMENT ...... 7
V. CONSOLIDATED GCA ...... 11
VI. OTHERADJUSTMENTS ...... 18
VII. PROPOSED RATES ...... 22
VIII. TARIFF CHANGES ...... 23
IX. CONCLUSION ...... 24
ATTACHMENTS:
Attachment JN G-1 - Baseline Schedule 2
Attachment JNG-2 - GCA Consolidation Analysis
Attachment JNG-3 - Craig Compressor Station Impact
Attachment JNG-4 - Summary of Adjustments to Transport Customers
Attachment JNG-5 -Proposed Tariffs in Legislative Format
Attachment JNG-6 -Proposed Tariffs in Clean Format
i. l Q. PLEASE STATE YOUR NAME AND BUSINESS ADDRESS.
2 A. My name is Jared N. Geiger. I am the Senior Rate Analyst for Atmos Energy
3 Corporation's ("Atmos Energy" or the "Company") Colorado-Kansas Division.
4 My business address is 1555 Blake Street, Suite 400, Denver, Colorado 80202.
5 I. EXECUTIVE SUMMARY
6 In my direct testimony, l address the development of billing determinants
7 for Atmos Energy's Colorado Division. As part of this discussion, I explain how
8 Atmos Energy's Billing Determinants Study ("BDS") was conducted, and how the
9 results from the BDS are used to calculate the Company's revenues based on both
10 current and proposed rates. The BDS provides detailed data which can be used in
11 order to describe and calculate adjustments for normalized weather and customer
12 bill proration. These adjustments provide the utility with the opportunity to collect
13 the revenue approved by the Commission. In addition, I describe why
14 consolidating the Company's four Gas Cost Adjustment ("GCA") divisions into
15 two divisions aligns the rate divisions with the functional manner in which the
16 Company provides services to the state. The alignment results in a more efficient
17 practice and provides enhanced flexibility and optionality to the Company and
18 benefits to its ratepayers.
19 I then discuss the Company's Weather Nonnalization Adjustment
20 ("WNA"), which is used to reduce or eliminate the impact of abnormal weather
21 conditions on Atmos Energy's customer's consumption of natural gas. The
22 Weather Normalization Adjustment is an important component of accurately
23 forecasting the Company's revenues. I propose using the methodology settled upon
Direct Testimony of Jared N. Geiger Page 1 Colorado I Geiger Direct Testimony in the Company's most recent rate case. Finally, I address how the Company has
2 calculated the forecasted revenues that would result from Atmos Energy's proposal
3 in this proceeding.
4 II. INTRODUCTION AND PURPOSE OF TESTIMONY
5 Q. PLEASE DESCRIBE YOUR CURRENT RESPONSIBILITIES AND
6 PROFESSIONALAND EDUCATIONAL BACKGROUND.
7 A. I received my Bachelor of Business Administration degree in Finance from the
8 University of Nmih Texas in 2008. I was hired by Atmos Energy in 2008 as an
9 Associate Rate Analyst in the Rates and Regulatory Affairs department. In this role
10 I prepared annual Weather Normalization Adjustment filings in Kansas and annual
11 rate stabilization mechanism filings in Louisiana. In 2011, I was promoted to the
12 position of Rate Analyst within the same department. In this position I prepared
13 billing determinant studies in rate filings for several jurisdictions. In addition, I
14 reviewed various analytical exhibits, provided requested data to regulatory bodies,
15 reviewed testimony, and supported witnesses during filing procedures for rate
16 filings. In 2012, I assumed the role of Regulatory and Financial Planning Analyst
17 for Atmos Energy's Business Planning and Analysis group. There, I helped prepare
18 annual divisional and depa1imental budgets and assisted in preparing Atmos
19 Energy's 5-Year Plan and Budget Board Book for the Atmos Energy Board of
20 Directors. In 2013, I relocated to the Company's Colorado-Kansas Division and
21 assumed my cun-ent role. As Senior Rate Analyst, I am responsible for the
22 determination of cun·ent revenues based on cunent rates, pro fotma customers and
Direct Testimony of Jared N. Geiger Page2 Colorado I Geiger Direct Testimony 1 weather-normalized volumes, as well as revenues to be generated by the
2 Company's proposed rates.
3 Q. HAVE YOU EVER SUBMITTED TESTIMONY BEFORE THE
4 COLORADO PUBLIC UTILITIES COMMISSION?
5 A. Yes, I filed testimony before the Colorado Public Utilities Commission
6 ("Commission") in several of the Company's most recent general rate case
7 proceedings. 1
8 Q. HAVE YOU PREVIOUSLY TESTIFIED BEFORE OTHER REGULATORY
9 COMMISSIONS?
10 A. Yes, I submitted testimony before the Kansas Corporation Commission in the
11 Company's prior general rate case proceedings.2
12 Q. WHAT IS THE PURPOSE OF YOUR TESTIMONY IN TIDS
13 PROCEEDING?
14 A. I discuss the following issues:
15 1. The development of Atmos Energy Colorado's BDS.
16 2. The consolidation of Atmos Energy's four GCA divisions into two
17 divisions.
18 3. The revenues resulting from the billing determinants using both the present
19 and the proposed rates.
20 Q. ARE YOU SPONSORING ANY ATTACHMENTS?
21 A. Yes. I am sponsoring the following attachments:
Proceeding Nos. 13AL-0496G, 14AL-0300G and 15AL-0299G. 2 Docket Nos. 14-ATMG-320-RTS and 16-ATMG-079-RTS.
Direct Testimony of Jared N. Geiger Page3 Colorado I Geiger Direct Testimony 1. JNG-1 - Baseline Schedule 2
2 2. JNG-2 - GCA Consolidation Analysis
3 3. JNG-3 - Craig Compressor Station Impact
4 4. JNG-4 - Summary of Adjustments to Transport Customers
5 5. JNG-5 - Proposed Tariffs in legislative format
6 6. JNG-6 - Proposed Tariffs in clean format
7 III. BILLING DETERMINANTS
8 Q. WHAT ARE BILLING DETERMINANTS?
9 A. Billing determinants are units of service to which the Company's distribution rates
10 are applied. Specifically, these units include gas throughput sold or transported,
11 customer counts, and quantities of various non-recuning customer service
12 transactions.
13 Q. WHAT IS THE PURPOSE OF CONDUCTING A BDS?
14 A. The BOS provides the data and calculations necessary to adjust volumes delivered
15 to reflect normal weather conditions, annualize changes in usage patterns by
16 industrial customers, and account for other known and measurable adjustments.
17 Some of the other known and measurable adjustments include large volume sales
18 adjustments made separate from the weather normalization, and a proration
19 adjustment to bill counts. In doing so, the BDS aggregates revenue from all of the
20 Company's rates in Colorado. The BOS calculations, also refen-ed to as "Revenues
21 at Present Rates," are shown in Schedule 2 of the Company's Cost of Service
Direct Testimony of Jared N. Geiger Page4 Colorado I Geiger Direct Testimony ("COS") model filed in this case. 3 Schedule 2 shows the total effect of the
2 aforementioned adjustments. The billing determinants are critical in order to more
3 accurately forecast Company revenues for the 12-month period after rates become
4 effective.
5 Q. PLEASE DESCRIBE THE CALCULATIONS REFLECTED IN SCHEDULE
6 2 OF THE COS MODEL.
7 A. Table JN G-1 provides the impact to per book revenues resulting from the calculated
8 adjustments reflected in Schedule 2.
9 Table JNG-1 - Total Revenue Impact from Adjustments (Increase/Decrease)
Large Adjusted Per Book Volumes Present Base Class Revenue WNA Sales Proration Revenue Residential $28 323,211 $995.955 $(298.996) $29.020. 171 Commercial $9 357 812 $330.012 $(1 214) $(50.487) $9.636.124 Irrigation $10 561 $(110) $10.451 Max Rate- Commercial $999,584 $85,490 $1,085,074 Special Contract $1,469,023 $(65,721) $1,403,303 Other Revenues $376,952 $376,952 Total $40,537,144 $1,325,967 $18,555 $(349,593) $41 532 075
10 The calculated adjustments contained in Schedule 2 are comprised of the following:
11 • Columns (b) and ( c) reflect actual, per books bill counts and billed volumes
12 by tariff for the test year in this proceeding (i.e., the 12-rnonth period ended
13 March 31, 2017).
Attachment JTC-5 contains the complete COS. Attachment JNG-1 is a copy of Schedule 2 from the COS, provided for the convenience of the Commission and parties.
Direct Testimony of Jared N. Geiger Page 5 Colorado I Geiger Direct Testimony 1 • Column ( d) shows the adjustments necessary for tariff sales volumes to
2 reflect "normal" weather for the period. It also includes a volume
3 adjustment to reflect an isolated adjustment to Commercial Sales volumes.
4 • Columns (e) and (f) demonstrate a proration adjustment to sales service
5 customer bills. Specifically, Column (e) demonstrates the variance of
6 approved and collected customer charges during the test period. Column
7 (f) shows the adjustment made to the number of sales service customer bills
8 to reflect the proration. Column (k) computes the revenue at present rates,
9 applying current monthly customer charges to the adjusted bill counts and
10 the current commodity rate to the adjusted, normalized volumes for each
11 tariff.
12 Q. WHAT DETERMINED THE BDS METHODOLOGY BEING PRESENTED
13 INTIDSCASE?
14 A. Consistent with the agreement in the Company's last rate case settlement,4 I used
15 an annual WNA methodology as described in the next section. I also included large
16 volume sales adjustments and a proration adjustment to bill counts consistent with
17 the settlement.
4 Proceeding No. lSAL-02990, Decision Nos. RIS-1146 and CIS-1187.
Direct Testimony of Jared N. Geiger Page6 Colorado I Geiger Direct Testimony 1 IV. WEATHER NORMALIZATION ADJUSTMENT
2 Q. PLEASE EXPLAIN THE CONCEPT OF WEATHER NORMALIZATION
3 AND WHY IT IS IMPORTANT IN ESTABLISHING JUST AND
4 REASONABLE RATES FOR NATURAL GAS SERVICE.
5 A. The Residential and Commercial customer classes are considered "weather
6 sensitive," because they alter daily consumption as a result of weather. These two
7 classes make up approximately 99% of the customers receiving gas from Atmos
8 Energy's Colorado distribution system. Their consumption accounts for
9 approximately 69% of the total gas sold by the Company. Of that, 71 % of their
10 consumption is used for space heating. This is commonly referred to as "heat load."
11 This means that roughly 50% of the total gas consumed by Atmos Energy's
12 Colorado customer base is affected by weather. When using the BDS to calculate
13 revenue levels at present rates, as well as revenue levels generated by proposed
14 rates, customer usage should be adjusted to reflect usage that can be expected in a
15 "normal" or "typical" year. The amount of gas consumed in non-heating months is
16 considered to be the "baseload" and represents the minimum amount of gas
17 consumed, mostly for water heating and cooking. The Company used the average
18 of July and August 2016 to determine base load, assuming no space heating was
19 taking place at that time.
20 Q. HOW IS WEATHER MEASURED?
21 A. The Company uses heating degree days ("HDDs") as a measure for how actual
22 weather compares to normal weather during the test period. A HDD is calculated
23 by subtracting the daily average temperature from 65 degrees Fahrenheit. Sixty-
Direct Testimony of Jared N. Geiger Page7 Colorado I Geiger Direct Testimony 1 five degrees was used because it's assumed that when average daily temperatures
2 reach a level below 65 degrees, heat sensitive customers will turn their heater on
3 for space heating. In the gas industry, 65 degrees Fahrenheit is commonly used for
4 this calculation and was used by Atmos Energy in its prior case in Colorado. Below
5 is an example of how HDDs were calculated for actual temperatures experienced
6 on January 1, 2016:
7 Maximum (high) Temperature= 42° Fahrenheit
8 Minimum (low) Temperature = 13° Fahrenheit
9 The sum of 42° and 13° is 55°.
10 5 5° divided by 2 is 2 7 .5°.
5 11 65° M 27.5° = 37 HDDs
12 This calculation is done for each day in the year and the monthly totals are
13 the sums of the days in that month. The Company compares these HDDs to climate
14 normals to determine if weather was warmer or colder than normal. Climate
15 normals are the latest threeMdecade averages of temperature and are measured in
16 normal heating degree days ("NDDs"). How the weather in the test period
17 compares to notmal weather determines if the usage needs to be adjusted and, if so,
18 whether to adjust it up or down.
19 Q. WHAT IS THE SOURCE OF THE WEATHER DATA USED IN THIS
20 ANALYSIS?
21 A. The actual and normal weather data used in the model were obtained from National
22 Oceanic and Atmospheric Administration ("NOAA") weather stations. The
HDDs are rounded down to the nearest integer.
Direct Testimony of Jared N. Geiger Page8 Colorado I Geiger Direct Testimony 1 weather stations utilized in the BDS are the same stations utilized in Atmos Energy's
2 last rate case.6 The weather n01mal data produced by NOAA is based on thirty
3 years of records - from 1981-2010.
4 Q. WHAT INFORMATION DOES THIS ANALYSIS PROVIDE?
5 A. When there are fewer HDDs than NDDs during the test period, the weather
6 experienced by customers was warmer than normal. During warmer than normal
7 weather, it is reasonable to assume that weather sensitive customers, such as the
8 Residential and Commercial classes, used less gas than they would have otherwise
9 used in normal conditions.
10 Q. HOW DOES THIS AFFECT REVENUES AT PRESENT RATES?
11 A. If weather is warmer than normal, the WNA calculation is designed to increase
12 volumes sold on Schedule 2 of the COS model to more accurately reflect volumes
13 of gas that will be sold at the time new rates go into effect, assuming normal weather
14 during that period. The base revenues on Schedule 2 consist of revenues from
15 facility charges and commodity charges. Commodity charge revenue is calculated
16 by multiplying volumes sold (or quantity) by the commodity charge (or price). The
17 WNA adjustment affects the volumes sold and as a result affect the revenues
18 generated. As a result of Atmos Energy's current rate structure in Colorado, more
19 than 50% of Residential and Commercial revenues are generated through
20 volumetric charges. If there are fewer HDDs than NDDs, too little volume of gas
21 was sold relative to a n01mal year, and the WNA calculation would generate an
6 Proceeding No. 15AL-0299G.
Direct Testimony of Jared N. Geiger Page9 Colorado I Geiger Direct Testimony adjustment to increase the volumes of gas represented on Schedule 2, which, in
2 turn, would increase revenues. The opposite is true if there were more HDDs than
3 NDDs.
4 Q. DID THE COMPANY EXPERIENCE WARMER OR COLDER THAN
5 NORMAL WEATHER DURING THE TEST PERIOD?
6 A. The weather was warmer than normal in each of the seven weather stations that are
7 located throughout the four divisions of Atmos Energy's Colorado distribution
8 system. A comparison of I-IDDs to NDDs by station is provided in Table JNG-2
9 below.
10 Table JNG-2 - HDDs vs NDDs Experienced During the Test Period
Degree Days Resulting Weather HDDs for Test Above/(Below) Variance from Adjustment to Station Period NDDs Normal Normal Volumes Greeley 4,933 5,423 (490) (9.04)% Positive Craig 7,463 8,157 (695) (8.51)% Positive Gunnison 9,273 10,167 (894) (8.79)% Positive Steamboat 8,237 9,316 (1,080) (11.59)% Positive Canon 4,763 5,457 (695) (12.73)% Positive Lamar 4,926 5,452 (527) (9.66)% Positive Durango 6,131 6,810 (680) (9.98)% Positive
11 Q. WHAT WNA METHODOLOGY DID ATMOS ENERGY UTILIZE IN THIS
12 RATE CASE?
13 A. As previously mentioned, I used an annual WNA adjustment that replicates what
14 was agreed upon in the Company's last rate case settlement.
15 Q. WHAT IMPACT DOES THE WNAHAVE ON REVENUES?
16 A. Table 3 provides the adjustment to revenue that resulted from the WNA adjustment.
Direct Testimony of Jared N. Geiger Page 10 Colorado I Geiger Direct Testimony Table JNG-3 - WNA Impact to Revenues
Adjustment to Volumetric Adjustment to Volumes Charge Revenues Residential 5,273,791 $0.18885 $995,955 Commercial 2,961,076 $0.11145 $330,012 Total $1,325,967 2
3 V. CONSOLIDATED GCA
4 Q. HOW MANY GAS COST ADJUSTMENT DIVISIONS DOES THE
5 COMPANY CURRENTLY HAVE IN COLORADO?
6 A. The Company currently has four GCA divisions: Northeast; Northwest/Central;
7 Southeast; and Southwest. For the reasons I discuss below, the Company proposes
8 consolidation of the Northeast; Northwest/Central; and Southeast into one GCA
9 division. The Southwest GCA division would remain on its own.
10 Q. WHY IS THE COMPANY ASKING FOR GCA CONSOLIDATION?
11 A. The current four GCA divisions are a historical holdover from Greeley Gas
12 Company ("Greeley Gas"). My understanding is that Greeley Gas operated
13 divisions broken out based on gas supply contracts. As an example, in 1993
14 Greeley Gas filed 14 cases with the Commission to modify its gas cost rates. 7 Since
15 the acquisition of Greeley Gas as a division of Atmos Energy in 1993, the Company
16 has consolidated many of its rate divisions in its various jurisdictions. Aligning the
17 rate divisions with the functional manner in which the Company provides services
Proceeding Nos. 93A-152G, 93A-153G, 93A-l54G, 93A-155G, 93A-156G, 93A-537G, 93A-538G, 93A-539G, 93A-540G, 93A-541G, 93A-542G, 93A-543G, 93A-544G, and 93A-565G.
Direct Testimony of Jared N. Geiger Page 11 Colorado I Geiger Direct Testimony 1 to the state is a more efficient practice and provides enhanced flexibility and
2 optionality to the Company and benefits to its ratepayers.
3 Q. IS THERE ANYTHING THAT WOULD PROIDBIT THE COMPANY
4 FROM CONSOLIDATING ITS GCA DIVISIONS?
5 A. The Company is not aware of any regulatory barriers that would prohibit such an
6 action.
7 Q. WHAT ARE THE ADMINISTRATIVE BENEFITS OF CONSOLIDATING
8 THE GCA DIVISIONS?
9 A. The Company and the Commission will experience greater efficiencies and a
10 reduction in their administrative processes if the GCA divisions are consolidated.
11 There would only be two internal GCA calculations made each month by the
12 Company and two GCA divisions instead of four for the Commission to review
13 when the Company makes an annual or interim filing.
14 Q. WHY NOT CONSOLIDATE ALL OF THE GCADIVISIONS INTO ONE
15 DIVISION?
16 A. The reasons for not consolidating the Southwest GCA is that its gas supply and
17 transportation costs are fundamentally different from the other three GCA divisions.
18 The three divisions that would be con so ti dated have similar firm transportation
19 capacity (i.e., year round and up to the maximum design day) in addition to third
20 party storage demand costs. In contrast, the Southwest rate division makes
21 significant use of full requirements delivered supply an-angements as well as
22 sculpted seasonal firm transpmtation capacity. There is also no third party storage
23 capacity available for use in that area. These different arrangements result in a
Direct Testimony ofJared N. Geiger Page 12 Colorado I Geiger Direct Testimony markedly different cost structure for the Southwest GCA division's transportation
2 charges and I believe warrant continued treatment of that division as a stand-alone
3 GCA division. If facts changed in the future, for example if the transportation
4 situation were to change, it might make sense to consolidate that division as well.
5 Q. WHAT ARE THE FINANCIAL BENEFITS OF CONSOLIDATION OF THE
6 THREE GCA DIVISIONS?
7 A. Combining the three GCA divisions into a single division would create the potential
8 for efficiencies and modest cost savings in the Company's Rate Administration
9 department. It would also enable the Company's Gas Supply department to have
10 significantly more flexibility in arranging gas supply and asset management
11 arrangements for the Company. Lastly, combining the three GCA divisions into a
12 single division would help those customers avoid potential rate shocks gomg
13 forward.
14 Q. HOW WOULD CONSOLIDATION BE MORE EFFICIENT FOR RATE
15 ADMINISTRATION?
16 A. The Company's current GCA filing is voluminous, and consolidation would
17 essentially reduce the number of documents and pages by half. If the GCA
18 divisions are consolidated, it would also enhance the Company's ability to make
19 interim filings throughout the year, which would assist in aligning projected
20 expenses with actual costs. Currently, the four GCAs on their own are so unwieldy
21 as to make frequent GCA filings very challenging.
Direct Testimony of Jared N. Geiger Page 13 Colorado I Geiger Direct Testimony 1 Q. WHAT IS THE BENEFIT OF MORE FREQUENT GCAFILINGS?
2 A. More frequent GCA filings would allow rates customers are paying to more closely
3 match current costs. It would promote better price signals, and thus, more efficient
4 use.
5 Q. HOW WOULD CONSOLIDATION ALLOW GAS SUPPLY MORE
6 FLEXIBILITY?
7 A. Atmos Energy manages the gas supply for all of its divisions through a centralized
8 Gas Supply department. Currently, Gas Supply must conduct separate RFP
9 processes for each of the four GCA divisions resulting in a diverse mix of local
10 production, intrastate and interstate transactions. By consolidating the three GCA
11 divisions, Gas Supply would be able to potentially combine more assets into an
12 Asset Management Arrangement, improving gas procurement and potentially
13 capturing greater overall value for rate payers. For all intents and purposes, the fact
14 that Atmos Energy conducts separate RFPs for each division is the only remaining
15 difference between the three divisions. Once consolidation occurs and Atmos
16 Energy is able to issue a single RFP, the three divisions will be treated as one service
17 area for GCA purposes.
18 Q. WHAT IMPACT WOULD THIS HAVE ON THE RFP PROCESS?
19 A. As stated previously, in 1993 Greeley Gas operated the various divisions based on
20 gas supply contracts. However, with the market developments that have occurred
21 over the last several decades, there is no reason to silo off a division based solely
22 on the number of natural gas suppliers. Atmos Energy chooses the supplier that
23 wins the RFP bid. In fact, in its most recent interim GCA filing, Concord Energy
Direct Testimony of Jared N. Geiger Page 14 Colorado I Geiger Direct Testimony 1 was selected to provide gas supply to all three of these Atmos Energy's GCA
2 divisions. The only division Concord Energy is not supplying cunently is the
3 Southwest division - the division Atmos Energy is not proposing for consolidation.
4 Q. HOW IS HEDGING CURRENTLY CONDUCTED ON A STATEWIDE
5 BASIS?
6 A. Hedges are entered into based on aggregated normal usage for the entire state, and
7 then allocated based on nonnal usage per rate division. This effectively means that
8 hedging is already conducted on a statewide basis. There would be no change via
9 consolidation of the three GCA divisions.
10 Q. FINALLY, HOW WOULD CONSOLIDATION HELP THESE CUSTOMERS
11 AVOID POTENTIAL FUTURE RATE SHOCKS?
12 A. Both expected and unforeseen events can considerably impact customers' gas
13 prices. Expected events could include an increase in population and an imminent
14 need for more capacity. This is happening in our Northwest/Central division where
15 PSCo is currently constructing new compressors in Craig (proposed completion in
16 2017) and Gunnison (proposed completion in 2018) to increase supply to those
17 areas as well as overall supply on the PSCo system. As a result of these necessary
18 compressors, Atmos Energy expects transpmiation rates for its Northwest/Central
19 division to increase. Depending upon the outcome of PSCo's pending rate case in
20 Proceeding No. 17 AL-0363G, the increase in transpmiation rates as a result of the
21 compressor construction could result in a bill increase of anywhere from pennies
22 up to $2.44 per month. For greater detail, please see Attachment JNG-3 - Craig
23 Compressor Station Impact, which contains an excerpt from the filed direct
Direct Testimony of Jared N. Geiger Page 15 Colorado I Geiger Direct Testimony 1 testimony and a supporting exhibit of Scott B. Brockett in Proceeding No. 17AL-
2 0363G.
3 Unforeseen events could include an event that interrupts supply in a region,
4 such as Force Majeure or an Operational Flow Order. An event like this can cause
5 rapid gas price hikes. We utilize hedging and storage to help mitigate these types
6 of events, but risk mitigation instruments cannot reduce all risk of rate shock.
7 When either foreseen or unforeseen events occur having a larger base of
8 customers allows these costs fluctuations to be more easily absorbed and minimizes
9 the chance of rate shock.
10 Q. HOW WOULD CONSOLIDATION BE IMPLEMENTED?
11 A. The Company is proposing to implement the consolidation of the three GCA
12 divisions in two phases. In the Company's Annual GCA filing made each October,
13 the Company would consolidate the commodity and upstream pieces. The third
14 piece, the deferred balance rate, would remain in place for each of the three
15 divisions. Over the next several months, the Company would monitor the deferred
16 balances until they were sufficiently low enough to consolidate the deferred rate
17 into one rate with minimal impact to any single division. The Company would file
18 with the Commission, exhibits demonstrating the balances and anticipated
19 customer bill impact upon consolidation. This would complete the transition. The
20 Company would implement the first phase in October of 2018 and believes it could
21 accomplish the second phase within 12 months. During the first phase, the deferred
22 gas costs for the Northeast, Northwest/Central, and Southeast divisions included on
23 Tariff Sheet No. 9 would be specific to each of those divisions, as we zero-out the
Direct Testimony of Jared N. Geiger Page 16 Colorado I Geiger Direct Testimony deferred balance from when each GCA division was separate. At the conclusion of
2 the second phase, when consolidation is completed, all of the charges for the
3 Northeast, Northwest/Central, and Southeast division would be identical.
4 Q. WILL THERE BE ANY OTHER ACTIONS NEEDED AFTER THE
5 DEFERRED RATE IS CONSOLIDATED?
6 A. No. Consolidation of the third and final piece of the Company's GCA rate would
7 complete the transition.
8 Q. DOES DIFFERING COMMODITY PRICES, UPSTREAM PRICES, AND
9 DEFERRED BALANCES SUPPORT RETENTION OF THE FOUR GCA
10 DIVISIONS?
11 A. No. As described before, the fact that the four GCA divisions have different
12 commodity prices, upstream prices, and deferred balances simply demonstrates that
13 the gas supply has been acquired utilizing four RFPs for some time. They are
14 nothing more than a relic of past practices. At the conclusion of the consolidation,
15 they would no longer necessarily be different for the three consolidated GCA
16 divisions.
17 Q. WILL THERE BE A MATERIAL IMPACT TO RATEPAYERS BY
18 COMBINING THE THREE GCA DIVISIONS?
19 A. No, there will not be a material impact to rate payers due to consolidation of the
20 three GCA divisions. The Company has conducted an analysis comparing its most
21 recent GCA filing for each division with the filing that would have been made had
22 the three GCA divisions been consolidated. The minor impacts that would occur to
Direct Testimony of Jared N. Geiger Page 17 Colorado I Geiger Direct Testimony 1 anticipated customer bills is set forth in the analysis attached as Attachment JNG-
2 2.
3 Q. ARE THERE ANY DRAWBACKS TO CONSOLIDATING THE THREE
4 GCA DIVISIONS?
5 A. The Company does not anticipate that there will be any material impact to
6 customers or the Commission as a result of consolidating the three GCA divisions
7 and sees no drawbacks to the consolidation.
8 VI. OTHER ADJUSTMENTS
9 Q. PLEASE DESCRIBE FURTHER THE ADJUSTMENTS TO LARGE
10 VOLUME SALES AND TRANSPORTATION SERVICES.
11 A. These adjustments account for changes relating to larger customer volume data
12 confirmed by Atmos Energy's marketing representatives. Specifically, the
13 adjustments (1) account for six customers that have switched from the Special
14 Contract customer class to Max-Rate Transportation customer class beginning on
15 May I, 2017, and (2) account for a Max-Rate Transportation customer class that
16 was mistakenly billed as a Commercial Sales customer. These adjustments are
17 found in Attachment JNG-4 and are quantified in Table JNG-4 below:
18 Table JNG-4 - Large Volume Sales Adjustments
Volume Adjustments Adjustment to Customer Volumetric Adjustment to (CcO Bills Charge Charge Revenues Max-Rate Commercial 828,645 112 $85 $0.09172 $85,490 Special Contract $(65,721) Total Adjustment $19,769 19
Direct Testimony of Jared N. Geiger Page 18 Colorado I Geiger Direct Testimony 1 Q. PLEASE DESCRIBE THE REASONING FOR ADJUSTING CUSTOMER
2 BILLS FOR PRORATION.
3 A. Customer bills do not always consist of a standard monthly billing period, yet the
4 Company's billing system reports bill counts as integers. Proration is designed to
5 adjust for the billing system's over statement of bill counts during the test period.
6 Sheet No. R6 of the Company's tariff states that "if the initial, final or regular
7 monthly bill ~or service is for a period of less than twenty-seven days or more than
8 thirty-three days, such bills will be prorated to the nearest one-tenth of a month, in
9 the ratio of the number of days in the billing period to a month of thirty days."
10 When a customer initiates service or terminates service with Atmos Energy, the
11 customer will, under the tenns of our tariff, receive a bill that has a prorated
12 customer charge depending on the number of days in the customer's first or last
13 billing period that the customer is on the system.
14 lf you take the number of bills Atmos Energy sends out multiplied by the
15 tariff customer charge, you will be overstating the actual revenue we get from
16 customers because you will not take into account the fact that some portion of those
17 bills are for a prorated month. For example, if a customer moves out on the first of
18 the month and their no1mal billing cycle would have their meter read on the 15th,
19 they would receive a bi11 count of one in the Company's billing system and would
20 be paying approximately Yz the tariff customer charge, or $5 .84. If a new customer
21 moves into the same premise on the 2nd of the month and they're billed on the same
22 cycle, they too would receive a bill count of one in billing system and pay
23 approximately Yz the tariff customer charge, or $5.84. The result is a bill count of
Direct Testimony of Jared N. Geiger Page 19 Colorado I Geiger Direct Testimony I two with an equivalent of one customer charge, or $11.68. To avoid this problem,
2 the actual number of sales customer bills needs to be adjusted to reflect that same
3 proration. The Company's reporting system does not have the capability of
4 reporting customer bill counts in percentages, or fractions of a bill count, and so a
5 proration to the reported bill counts is necessary to accurately reflect the revenue
6 collected from customer charges throughout the test year and the period at which
7 proposed rates become effective.
8 Q. PLEASE DESCRIBE HOW THE ACTUAL NUMBER OF SALES
9 CUSTOMER BILLS WAS ADJUSTED FOR PRORATION?
10 A. Workpaper 2-3 of the Company's Cost of Service attached to Mr. Christian's
11 testimony demonstrates the calculations used for the proration adjustment. The
12 Company used monthly customer revenue and divided it by the monthly customer
13 charge counts by sales customer class to derive an actual facility charge collected
14 by sales service class. During this particular test period, the Company had three
15 different periods of effective facility charges. The variance, or percentage change,
16 between the approved and collected facility charge was calculated for each of the
17 three periods to ensure that the facility charge revenue collected was compared to
· 18 the customer charge effective in the tariff during that time. The variance is displayed
19 in Schedule 2 Column (g). This percentage was then applied as a proration
20 adjustment to the test period number of bills as displayed in Schedule 2, Column
21 (h). This adjustment was calculated separately for each of the Company's four
22 operating divisions and more specifically by weather station and by Residential and
Direct Testimony ofJared N. Geiger Page 20 Colorado I Geiger Direct Testimony 1 Commercial customer classes. Table JNG-5 provides the adjustment to revenue that
2 resulted from the adjustment.
3 Table JNG-5 - Proration Adjustment to Bills
Adjustment to Custome1· Ad,justment to Bills Charge Revenues Residential (25,776) $11.60 ($298,996) Commercial (1,788) $28.24 ($50,487) Irrigation (2) $45.17 ($110) Total ($349 593) 4
5 Table JNG-6 provides the ranges of actual facility charges collected in each of the
6 three periods:
7 Table JNG-6 - Examples of Ranges of Actual Facility Charges Collected 8 for Each Customer Class
Actual Facility Charge Tariff in Class Division Station Description Collected Effect Residential Northeast Greeley Low $11.36 $11.68 Residential Northwest/Centr Craig High $11.58 $11.68 Commercial Northeast Greeley Low $27.84 $28.44 Commercial Southwest Durango High $28.53 $28.44 Irrigation Southeast Low $37.90 $45.48 Irrigation Southeast High $51.76 $45.48 9
10 Q. ARE THERE ANY VOLUME ADJUSTMENTS ASSOCIATED WITH THE
11 PRORATION ADJUSTMENT TO CUSTOMER BILLS?
12 A. No. The proration adjustment to customer bills is not a change in the number of
13 customers the Company expects to be distributing gas to when the proposed rates
14 become effective, but only corrects for how the Company's database reports data.
Direct Testimony of Jared N. Geiger Page 21 Colorado I Geiger Direct Testimony 1 Q. DOES FINAL METER READING CHARGE REVENUE COLLECTED BY
2 THE COMPANY WHEN A CUSTOMER DISCONTINUES SERVICE
3 OFFSET THE NEED FOR A PRORATION ADJUSTMENT?
4 A. No. If a customer leaves mid-month and is only charged a portion of a facility
5 charge and another customer moves into that location and is charged a prorated
6 facility charge, the customers together pay a total of one whole facility charge. If
7 the Company's reporting system counts that as two bill counts, the Schedule 2
8 calculations of revenues at present rates is overstated. The "Final Meter Reading
9 Fee" of $15 .00 collected by the Company does not offset the need to correct for the
10 bill count. The final meter reading fee is already being included as part of "Other
11 Revenues" in Schedule 2 ofthe COS model. Table JNG-7 provides the amounts
12 that are included in other revenues:
13 Table JNG-7 - Other Revenues
Colorado Service Area Account Revenue Number Account Description Increase/(Decrease) 4870 Forfeited discounts $ 73,427 4880 Miscellaneous service revenues $ 303,525 4950 Other gas revenues $0 Total $ 376,952 14 15 VII. PROPOSED RATES
16 Q. HOW WILL THE PROPOSED RATES BE IMPLEMENTED?
17 A. The rate design being proposed, as agreed upon by the Company in the settlement
18 of Proceeding No. 14AL-0300G, will be implemented through a new General Rate
19 Schedule Adjustment ("GRSA") that applies a uniform percentage increase to all
20 non-gas facilities charges and distribution system rates.
Direct Testimony of Jared N. Geiger Page 22 Colorado I Geiger Direct Testimony Q. HOW DID YOU GO ABOUT DETERMINING PROPOSED REVENUES?
2 A. The calculation of revenue at present rates is a mechanical process that applies the
3 current rates in effect to the appropriate customer counts and volumes to arrive at
4 the revenue that would be created by current rates. A similar set of calculations are
5 made for proposed revenues, except that instead of using current rates, the rates
6 proposed use the new proposed ORSA.
7 VIII. TARIFF CHANGES
8 Q. WHAT TARIFF SHEETS IS ATMOS ENERGY SEEKING TO CHANGE IN
9 TIDS PROCEEDING?
10 A. Attachment JNG-5 consists of the following tariff sheets Atmos Energy is seeking
11 to change in this proceeding in legislative format, while Attachment JNG-6 is a
12 clean version of the proposed tariff sheets:
13 • Sheet No. 9 - changes provide updates to Residential, Commercial, and
14 Irrigation rates
15 • Sheet No. 11 - changes provide updates to Transportation rates
16 • Sheet No. 15 - changes provide update to Residential and Commercial rates
17 • Sheet No. 17 - changes provide update to Irrigation Service rates
18 • Sheet No. 19 - changes describe the General Rate Schedule Adjustment
19 Rider
20 • Sheet No. 23 - changes provide update to Firm Transportation Service rates
21 • Sheet No. 27 - changes describe the System Safety and Integrity Rider
22 • Sheet No. R5 - changes provide update to customer deposit
Direct Testimony of Jared N. Geiger Page23 Colorado I Geiger Direct Testimony 1 • Sheet No. R29 - changes provide update to installation requirements of
2 Excess Flow Valve ("EFV") for new customers
3 IX. CONCLUSION
4 Q. PLEASE SUMMARIZE YOUR TESTIMONY AND RECOMMENDATION
5 FOR THE COMMISSION TO CONSIDER.
6 A. If billing determinants are not established at levels reasonably expected to occur
7 during the period that the rates go into effect, the Company may not have a
8 reasonable opportunity to recover operating costs and earn a fair rate of return. The
9 adjustments presented in this testimony are based on the best information currently
10 available. I recommend using Schedule 2 for purposes of determining the revenues
11 and creating proposed rates in this proceeding. Additionally, consolidating three of
12 Atmos Energy's four GCA divisions into a single GCA division better aligns the
13 rate divisions with the functional manner in which the Company provides services,
14 is a more efficient practice, and provides enhanced flexibility and optionality to the
15 Company and benefits to its ratepayers.
16 Q. DOES TIDS CONCLUDE YOUR DIRECT TESTIMONY?
17 A. Yes.
Direct Testimony of Jared N. Geiger Page24 Colorado I Geiger Direct Testimony Attachment JNG-1 Page 1of16
Atmos Energy Corporation - Colorado Service Areas Summary of Revenue at Present Rates Test Year Ended March 31, 2017
WNA& Line Vol. Ccf Avg 14.65 Adjustments to Proration Adjusted Adjusted Total No. Description Number of Bills psi VolumeCcf % Variance Adjustment Total Bills Volumes (a) (b) (c) (d) (e) (f) (g) (h)
1 Residential 1,270,158 71,958,583 5,273,791 -2.0% (25,776) 1,244,382 77,232,374 2 Commercial 146,418 46,863,776 2,950,941 -1.2% (1,788) 144,627 49,814,717 3 Irrigation 121 49,443 0 -2.0% (2) 119 49,443 4 5 Total Colorado Sales Revenue 1,416,697 118,871,802 8,224,732 -1.9% (27,566) 1,389,128 127,096,534 6
7 Vol. Ccf Avg 14.65 Adjustments to Adjustments to Proration Adjusted Adjusted Total Nwnber of Bills psi VolumeCcf Bills Adjustment Total Bills Volumes 8 Trans]lortation Revenues 9 Max Rate - Commercial 1,676 9,350,490 828,645 112 1,788 10,179,135 10 Special Contract 2,556 43,708,940 (938,190) (84) 2,472 42,770,750 11 Total Transportation Revenues 4,232 53,059,430 (109,545) 28 4,260 52,949,885 12 13 Other Revenues 14 15 Total Colorado Revenue
Schedule 2 1 of3 Attachment JNG-1 Page 2of16
Atmos Energy Corporation - Colorado Service Areas Summary of Revenue at Present Rates Test Year Ended March 31, 2017
Line Adjusted Present Adjusted Gas Cost Adjusted Present No. Description Customer Charge Commodity Charge Base Revenue Revenues Total Revenue (a) (i) U) (k) (I) (m)
Residential $ 11.60 $ 0.18885 $ 29,020,171 $ 35,625,566 $ 64,645,737 2 Commercial 28.24 0.11145 9,636,124 23,075,200 32,711,324 3 Irrigation 45.17 0.10305 10,451 22,013 32,464 4 5 Total Colorado Sales Revenue $ 38,666,746 $ 58,722,779 $ 97,389,525 6
7 Transportation Transportation Transportation Adjusted Gas Cost Adjusted Present Customer Charge Commodity Charge Revenue Revenues Total Revenue 8 TransJlortation Revenues 9 Max Rate - Commercial $ 84.70 $ 0.09172 $ 1,085,074 $ $ 1,085,074 10 Special Contract 1,403,303 1,403,303 11 Total Transportation Revenues $ 2,488,377 $ $ 2,488,377 12 13 Other Revenues $ 376,952 $ 376,952 14 15 Total Colorado Revenue $ 41,532,075 $ 58,722,779 $ 100,254,854
Schedule 2 2 of3 .·.·.-.··.·.·
Attachment JNG-1 Page 3of16
Atmos Energy Corporation - Colorado Service Areas Snmmary ofRevenne at Present Rates Test Year Ended March 31, 2017 Proposed Base Rates Proposed Base Rates with Rate Case Expense Proposed Proposed Proposed Proposed Line Customer Commodity Customer Commodity No. Description Charge Rates Proposed Revenue Charge Rates Proposed Revenue (a) (n) (o) (p) (q) (r) (s) (t)
Residential $ 12.45 $ 0.20269 $ 66,772,358 $ 12.59 $ 0.20494 $ 67,120,344 2 Commercial 30.31 0.11962 33,417,687 30.65 0.12095 33,533,114 3 Irrigation 48.48 0.11060 33,230 49.02 0.11183 33,354 4 5 Total Colorado Sales Revenue $ 100,223,275 $ 100,686,812 6 Proposed Proposed Proposed Proposed 7 Customer Commodity Customer Commodity Charge Rates Proposed Revenue Charge Rates Proposed Revenue 8 Tran~llortation Revenues 9 Max Rate - Commercial $ 90.91 $ 0.09844 $ 1,164,581 $ 91.92 $ 0.09953 $ 1,177,482 10 Special Contract 1,403,303 1,403,303 11 Total Transportation Revenues $ 2,567,884 $ 2,580,785 12 13 Other Revenues $ 376,952 $ 376,952 14 15 Total Colorado Revenue $ 103,168,111 $ 103,644,549
Schedule 2 3 of3 . :·.-·.
Attachment JNG-1 Page 4of16
Atmos Energy Corporation - Colorado Service Areas Summary of Per Books Revenues and Adjusted Transportation Revenue Test Year Ended March 31, 2017
Line No. Description Total (a) (b)
1 Per Book Revenues: 2 Sales Revenue (Including Unbilled) $ 78,866,219 3 4 Transportation Revenues 2,570,375 5 Other Revenues 376,952 6 Total "Transportation & Other" Revenue - Per Book (Sum Ln 4 + 5) $ 2,947,327 7 8 Total Revenues - Per Book (Sum Ln 2 + 6) $ 81,813,546 9 10 Transportation Revenue Adjustment: 11 Transportation Revenues (Ln 4) $ 2,570,375 12 Adjustments to Transportation Revenues (81,998) 13 Adjusted Transportation Revenues (Ln 11 + 12) $ 2,488,377 14 15 Other Revenues (Ln 5) $ 376,952 16 Adjustments to Miscellaneous Service Revenues 17 Adjusted Miscellaneous Service Revenues (Ln 15 + 16) $ 376,952 18 19 Transportation GCA Revenue $ 20 Total Transportation and Other Revenues -Adjusted (Sum Lns 13, 17, 19) $ 2,865,329
WP2-1 1of1 Attachment JNG-1 Page 5of16
Atmos Energy Corporation - Colorado Service Areas Volume Adjustments Summary Test Year Ended March 31, 2017
Line Weather Stations (1) No. Description GGRE GCRA GGUN GSTE GCAN GLAM GDUR TOTAL (a) (b) (c) (d) (e) (f) (g) (h) (i)
1 Residential Ccf 2 NE Weather Adjustment 2,095,015 3 NE Non-Weather Adjustment 0 0 0 0 0 0 0 5 NE Volume Adjustment 2,095,015 0 0 0 0 0 0 2,095,015 6 7 NW/Central Weather Adjustment 0 222,101 498,326 587,613 0 0 0 8 NW/Central Non-Weather Adjustment 0 0 0 0 0 0 0 10 NW/Central Volume Adjustment 0 222,101 498,326 587,613 0 0 0 1,308,040 11 12 SE Weather Adjustment 0 0 0 0 771,348 267,362 0 13 SE Non-Weather Adjustment 0 0 0 0 0 0 0 15 SE Volume Adjustment 0 0 0 0 771,348 267,362 0 1,038,710 16 17 SW Weather Adjustment 0 0 0 0 0 0 832,026 18 SW Non-Weather Adjustment 0 0 0 0 0 0 0 20 SW Volume Adjustment 0 0 0 0 0 0 832,026 832,026 21
WP2-2 1 of2 Attachment JNG-1 Page 6of16
Atmos Energy Corporation - Colorado Service Areas Volume Adjustments Summary Test Year Ended March 31, 2017
Line Weather Stations (1) No. Description GGRE GCRA GGUN GSTE GCAN GLAM GDUR TOTAL (a) (b) (c) (d) (e) (f) (g) (h) (i)
22 Commercial Ccf 23 NE Weather Adjustment 1,045,507 0 0 0 0 0 0 24 NE Non-Weather Adjustment 0 0 0 0 0 0 0 26 NE Volume Adjustment 1,045,507 0 0 0 0 0 0 1,045,507 27 28 NW/Central/Weather Adjustment 0 167,903 329,697 522,446 0 0 0 29 NW/Central/ Non-Weather Adjustment 0 0 0 0 0 0 0 31 NW/Central Volume Adjustment 0 167,903 329,697 522,446 0 0 0 1,020,046 32 33 SE Weather Adjustment 0 0 0 0 246,236 138,170 0 34 SE Non-Weather Adjustment 0 0 0 0 (10,135) 0 0 36 SE Volume Adjustment 0 0 0 0 236,101 138,170 0 374,271 37 38 SW Weather Adjustment 0 0 0 0 0 0 511,117 39 SW Non-Weather Adjustment 0 0 0 0 0 0 0 41 SW Volume Adjustment 0 0 0 0 0 0 511,117 511,117 42 43 Total 3,140,522 390,004 828,023 1,110,059 1,007,449 405,532 1,343,143 8,224,732 44 45 Note: 46 1. Weather stations are as follows: GGRE =Greeley; GCRA =Craig; GGUN = Gunnison; GSTE =Steamboat; GCAN =Canon; GLAM =Lamar; GDUR =Durango.
WP2-2 2of2 Attachment JNG-1 Page 7of16
Atmos Energy Corp. - Cqlorado Service Areas Weather Normalization - Northeast Division 033 Test Year Ended March 31, 2017
Line No. Description Residential Commercial Total (a) (b) (c) (d) 1 Revenue: 2 Ccf Sold, Including non Weather Adjustments GGRE 3 (Greeley) 30,862,766 16,768,299 47,631,066 Average Customers, Including non Weather 4 Adjustment GGRE 47,783 4,500 52,284 5 6 Ccf Sold per Customer GGRE (Ln 3 I Ln 4) 646.0 3,726 7 8 Non-heating Sales: 9 July 2016 CcfSales/Customer GGRE 14.2 105.4 10 August 2016 Ccf Sales/Customer GGRE 12.6 87.3 11 Total GGRE (Ln 9 + Ln 10) 26.8 192.7 12 Annualized GGRE (Ln 11 * 6) 160.6 1,156.3 13 14 Heating Sales per Customer GGRE (Ln 6 - Ln 12) 485.0 2,570.0 15 Average Number of Customers GGRE 47,783 4,500 52,284 16 17 Total Heating Sales CcfGGRE (Ln 14 * Ln 15) 23,174,947 11,565,340 34,740,287 18 19 Degree Days GGRE: 20 12 Months ended 3/31/17 4,933 4,933 21 Normal GGRE 5,423 5,423 22
WP2-3 1 of2 Attachment JNG-1 Page 8of16
Atmos Energy Corp. ~ Colorado Service Areas Weather Normalization~ Northeast Division 033 Test Year Ended March 31, 2017
Line No. Description Residential Commercial Total (a) (b) (c) (d) 23 24 Percent Change ((Ln 21 - Ln 20) I Ln 21) 9.04% 9.04% 25 26 Ccf Weather Adjustment GGRE (Ln 24 * Ln 17) 2,095,015 1,045,507 3,140,522 27 Total Normalized Heating Volumes (Ln 17 + Ln 26) 25,269,962 12,610,847 28 29 Normal Heating Usage Per Customer (Ln 27 I Ln 15) 529 2,802 30 31 Avg Monthly Base Load (Ln 12I12) 13.4 96.4 32 33 Total Normal Usage Per customer (Ln 12 + Ln 29) 689 3,959
WP2-3 2 of2 Attachment JNG-1 Page 9of16
Atmos Energy Corp. - Colorado Service Areas Weather Normalization - Northwest/Central Division 034 Test Year Ended March 31, 2017
Line No. Description Residential Commercial Total (a) (b) (c) (d) Revenue: 2 CcfSold, Including non Weather Adjustment GCRA 3 (Craig) 3,388,619 2,795,960 6,184,579 Average Customers, Including non Weather Adjustment 4 GCRA 4,595 676 5,271 5 6 CcfSold per Customer GCRA (Ln 3 I Ln 4) 737.0 4,134 7 8 Non-heating Sales: 9 July 20 I 6 CcfSales/Customer GCRA 15.6 108.8 10 August 2016 CcfSales/Customer GCRA 12.6 94.1 11 Total GCRA (Ln 9 + Ln 10) 28.2 202.9 12 Annualized GCRA (Ln 11 * 6) 169.3 1,217.3 13 14 Heating Sales per Customer GCRA (Ln 6 - Ln 12) 568.0 2,917.0 15 Average Number of Customers GCRA 4,595 676 5,271 16 17 Total Heating Sales CcfGCRA (Ln 14 * Ln 15) 2,609,881 1,973,013 4,582,894 18 19 Degree Days - GCRA: 20 12 Months ended 3/31/17 7,463 7,463 21 NormalGCRA 8,157 8,157 22 23 24 Percent Change ((Ln21- Ln 20) I Ln 21) 8.51% 8.51% 25 26 CcfWeather Adjustment GCRA (Ln 24 * Ln 17) 222,101 167,903 390,004 27 Total Normalized Heating Volumes (Ln 17 + Ln 26) 2,831,982 2,140,916 28 29 Normal Heating Usage Per Customer (Ln 27 I Ln 15) 616 3,165 30 31 Avg Monthly Base Load (Ln 12 I 12) 14.I 101.4 32 33 Total Normal Usage Per customer (Ln 12 + Ln 29) 786 4,382
WP2-4 1 of3 Attachment JNG-1 Page 10of16
Atmos Energy Corp. - Colorado Service Areas Weather Normalization - Northwest/Central Division 034 Test Year Ended March 31, 2017
Line No. Description Residential Commercial Total (a) (b) (c) (d) 34 Revenue: 35 CcfSold, Including non Weather Adjustment GGUN 36 (Gunnison) 8,116,083 7,562,309 15,678,392 Average Customers, Including non Weather Adjustment 37 GGUN 10,142 1,665 11,807 38 39 CcfSold per Customer GGUN (Ln 36 I Ln 37) 800.0 4,542 40 41 Non-heating Sales: 42 July 2016 Ccf Sales/Customer GGUN 20.9 184.4 43 August 2016 Ccf Sales/Customer GGUN 19.2 197.2 44 Total GGUN (Ln 42 + Ln 43) 40.l 381.6 45 Annualized GGUN (Ln 44 * 6) 240.5 2,289.5 46 47 Heating Sales per Customer GGUN (Ln 39 - Ln 45) 559.0 2,253.0 48 Average Number of Customers GGUN 10,142 1,665 11,807 49 50 Total Heating Sales Ccf GGUN (Ln 4 7 * Ln 48) 5,669,238 3,750,816 9,420,054 51 52 Degree Days - GGUN: 53 12 Months ended 3/31/17 9,273 9,273 54 NormalGGUN 10,167 10,167 55 56 57 Percent Change ((Ln 54 - Ln 53) I Ln 54) 8.79% 8.79% 58 59 CcfWeather Adjustment GGUN (Ln 50 * Ln 57) 498,326 329,697 828,023 60 Total Normalized Heating Volumes (Ln 50 + Ln 59) 6,167,564 4,080,513 61 62 Normal Heating Usage Per Customer (Ln 60 I Ln 48) 608 2,451 63 64 Avg Monthly Base Load (Ln 45 / 12) 20.0 190.8 65 66 Total Normal Usage Per customer (Ln 45 + Ln 62) 849 4,741
WP2-4 2 of3 ·.···-·.·
Attachment JNG-1 Page 11of16
Atmos Energy Corp. - Colorado Service Areas Weather Normalization - Northwest/Central Division 034 Test Year Ended March 31, 2017
Line No. DescriEtion Residential Commercial Total (a) (b) (c) (d) 67 Revenue: 68 CcfSold, Including non Weather Adjustment GSTE 69 (Steamboat) 7,081,834 6,973,774 14,055,608 Average Customers, Including non Weather Adjustment 70 GSTE 7,212 1,221 8,433 71 72 CcfSold per Customer GSTE (Ln 69 / Ln 70) 982.0 5,713 73 74 Non-heating Sales: 75 July 2016 Ccf Sales/Customer GSTE 24.0 175.4 76 August 2016 CcfSales/Customer GSTE 22.5 161.3 77 Total GSTE (Ln 75 + Ln 76) 46.5 336.7 78 Annualized GSTE (Ln 77 * 6) 279.0 2,020.0 79 80 Heating Sales per Customer GSTE (Ln 72 - Ln 78) 703.0 3,693.0 81 Average Number of Customers GSTE 7,212 1,221 8,433 82 83 Total Heating Sales CcfGSTE (Ln 80 * Ln 81) 5,070,002 4,507,732 9,577,734 84 85 Degree Days - GSTE: 86 12 Months ended 3/31/17 8,237 8,237 87 Norma!GSTE 9,316 9,316 88 89 90 Percent Change ((Ln 87 - Ln 86) I Ln 87) 11.59% 11.59% 91 92 CcfWeather Adjustment GSTE (Ln 83 * Ln 90) 587,613 522,446 1,110,059 93 Total Normalized Heating Volumes (Ln 83 + Ln 92) 5,657,615 5,030,178 94 95 Normal Heating Usage Per Customer (Ln 93 / Ln 81) 784 4,121 96 97 AvgMonthlyBaseLoad{Ln 78/ 12) 23.3 168.3 98 99 Total Normal Usage Per customer (Ln 78 + Ln 95) 1,063 6,141
WP2-4 3 of3 Attachment JNG-1 Page 12of16
Atmos Energy Corp. - Colorado Service Areas Weather Normalization - Southeast Division 035 Test Year Ended March 31, 2017
Line No. Description Residential Commercial Total (a) (b) (c) (d) 1 Revenue: 2 Ccf Sold, Including non Weather Adjustment GCAN 3 (Canon) 7,910,050 2,642,136 10,552,186 Average Customers, Including non Weather Adjustment 4 GCAN 13,003 1,004 14,007 5 6 Ccf Sold per Customer GCAN (Ln 3 I Ln 4) 608.0 2,631 7 8 Non-heating Sales: 9 July 2016 Ccf Sales/Customer GCAN 12.5 67.0 10 August 2016 CcfSales/Customer GCAN 11.I 50.4 11 Total GCAN (Ln 9 + Ln 10) 23.6 117.4 12 Annualized GCAN (Ln 11 * 6) 141.8 704.7 13 14 Heating Sales per Customer GCAN (Ln 6 - Ln 12) 466.0 1,926.0 15 Average Number of Customers GCAN 13,003 1,004 14,007 16 17 Total Heating Sales CcfGCAN (Ln 14 * Ln 15) 6,059,295 I,934,300 7,993,595 18 19 Degree Days - GCAN; 20 12 Months ended 3/31/17 4,763 4,763 21 Normal GCAN 5,457 5,457 22 23 24 Percent Change ((Ln 21 - Ln 20) I Ln 21) 12.73% 12.73% 25 26 Ccf Weather Adjustment GCAN (Ln 24 * Ln 17) 771,348 246,236 1,017,584 27 Total Normalized Heating Volumes (Ln 17 + Ln 26) 6,830,643 2,180,536 28 29 Normal Heating Usage Per Customer (Ln 27 / Ln 15) 525 2,171 30 31 Avg Monthly Base Load (Ln 12 / 12) 11.8 58.7 32 33 Total Normal Usage Per customer (Ln 12 + Ln 29) 667 2,876
WP2-5 1 of2 Attachment JNG-1 Page 13of16
Atmos Energy Corp. - Colorado Service Areas Weather Normalization - Southeast Division 035 Test Year Ended March 31, 2017
Line No. Description Residential Commercial Total (a) (b) (c) (d) 34 Revenue: 35 Ccf Sold, Including non Weather Adjustment GLAM 36 (Lamar) 3,599,813 2,068,038 5,667,851 Average Customers, Inc1uding non Weather Adjustment 37 GLAM 5,778 881 6,659 38 39 Ccf Sold per Customer GLAM (Ln 36 / Ln 37) 623.0 2,347 40 41 Non-heating Sales: 42 July 2016 Ccf Sales/Customer GLAM 12.7 60.0 43 August 2016 CcfSales/Customer GLAM 11.3 60.7 44 Total GLAM (Ln 42 + Ln 43) 24.0 120.7 45 Annualized GLAM (Ln 44 * 6) 144.0 724.4 46 47 Heating Sales per Customer GLAM (Ln 39 - Ln 45) 479.0 1,623.0 48 Average Number of Customers GLAM 5,778 881 6,659 49 so Total Heating Sales CcfGLAM (Ln 47 * Ln 48) 2,767,727 1,430,332 4,198,059 51 52 Degree Days - GLAM: 53 12 Months ended 3/31/17 4,926 4,926 54 NormalGLAM 5,452 5,452 55 56 57 Percent Change ((Ln 54 - Ln 53) I Ln 54) 9.66% 9.66% 58 59 CcfWeather Adjustment GLAM (Ln 50 * Ln 57) 267,362 138,170 405,532 60 Total Normalized Heating Volumes (Ln 50 + Ln 59) 3,035,089 1,568,502 61 62 Normal Heating Usage Per Customer (Ln 60 I Ln 48) 525 1,780 63 64 Avg Monthly Base Load (Ln 45 / 12) 12.0 60.4 65 66 Total Normal Usage Per customer (Ln 45 + Ln 62) 669 2,504
WP2-5 2of2 Attachment JNG-1 Page 14of16
Atmos Energy Corp. - Colorado Service Areas Weather Normalization - Southwest Division 036 Test Year Ended March 31, 2017
Line No. Description Residential Commercial Total (a) (b) (c) (d) Revenue: 2 CcfSold, Including non Weather Adjustments GDUR 3 (Durango) 10,999,418 8,053,259 19,052,677 Average Customers, Including non Weather Adjustment 4 GDUR 15,186 2,105 17,291 5 6 Ccf Sold per Customer GDUR (Ln 3 I Ln 4) 724.0 3,826 7 8 Non-heating Sales: 9 July 2016 CcfSales/Customer GDUR 15.6 119.4 10 August 2016 CcfSales/Customer GDUR 13.6 112.8 11 Total GDUR (Ln 9 + Ln 10) 29.2 232.2 12 Annualized GDUR (Ln 11 * 6) 175.1 1,393.3 13 14 Heating Sales per Customer GDUR (Ln 6 - Ln 12) 549.0 2,433.0 15 Average Number of Customers GDUR 15,186 2,105 17,291 16 17 Total Heating Sales CcfGDUR (Ln 14 * Ln 15) 8,336,931 5,121,415 13,458,346 18 19 Degree Days - GDUR: 20 12 Months ended 3/31117 6,131 6,131 21 NonnalGDUR 6,810 6,810 22 23 24 Percent Change ((Ln 21 - Ln 20) I Ln 21) 9.98% 9.98% 25 26 CcfWeather Adjustment GDUR (Ln24*Ln17) 832,026 511,117 1,343,143 27 Total Normalized Heating Volumes (Ln 17 + Ln 26) 9,168,957 5,632,532 28 29 Normal Heating Usage Per Customer (Ln 27 I Ln 15) 604 2,676 30 31 Avg Monthly Base Load (Ln 12 / 12) 14.6 116.1 32 33 Total Normal Usage Per customer (Ln 12 + Ln 29) 779 4,069
WP2-6 1 ofl Attachment JNG-1 Page 15of16
Atmos Energy Corp. - Colorado Service Areas Actual Degree Days and Lagged Degree Days Test Year Ended March 31, 2017
Actual Degree Days Lagged Degree Days Line Greeley Craig Gunnison Steamboat Canon Lamar Durango Greeley Craig Gunnison Steamboat Canon Lamar Durango No. Month-Year Ddays Ddays Ddays Ddays Ddays Ddays Ddays Ddaxs Ddays Ddays Ddays Ddaxs Ddays Ddays (a) (b) (c) (d) (e) (f) (g) (h) (i) 0) (k) (!) (m) (n) (o)
1 Mar-16 631 967 1,002 1,100 662 599 791 2 3 Apr-16 412 660 722 769 459 352 622 522 814 862 935 561 476 707 4 May-16 268 472 523 548 259 194 407 340 566 623 659 359 273 515 5 Jun-16 4 60 152 150 8 1 34 136 266 338 349 134 98 221 6 Jul-16 0 3 131 61 0 0 I 2 32 142 106 4 1 18 7 Aug-16 6 52 226 124 9 0 43 3 28 179 93 5 0 22 8 Sep-16 37 231 381 293 51 33 184 22 142 304 209 30 17 114 9 Oct-16 208 477 656 543 221 202 401 123 354 519 418 136 118 293 10 Nov-16 543 805 953 845 509 584 705 376 641 805 694 365 393 553 11 Dec-16 1,198 1,399 1,564 1,481 1,024 1,221 1,129 871 1,102 1,259 1,163 767 903 917 12 Jan-17 1,080 1,468 1,673 1,474 1,009 1,091 1,191 1,139 1,434 1,619 1,478 1,017 1,156 1,160 13 Feb-17 639 961 1,245 969 633 677 648 860 1,215 1,459 1,222 821 884 920 14 Mar-17 445 782 1,092 859 499 542 740 542 872 1,169 914 566 610 694 15 16 Total (Sum Ln 3 -14) 4,840 7,370 9,318 8,116 4,681 4,897 6,105 4,933 7,463 9,273 8,237 4,763 4,926 6,131 17
18 2010 30 YearNonnals (1) 5,423 8,157 10,167 9,316 5,457 5,452 6,810 5,423 8,157 10,167 9,316 5,457 5,452 6,810 19 Percentage (2) 20 (Ln 16 -Ln 18) I (Ln 18) -10.75% -9.65% -8.35% -12.88% -14.22% -10.18% -10.35% -9.04% -8.51% -8.79% -11.59% -12.73% -9.66% -9.98% Degree Days From 21 Normal (Ln 16 - Ln 18) (583) (787) (849) (1,200) (776) (555) (705) 22 23 Notes: 24 1. The source for the 2010 30 Year Normals was the National Oceanic and Atmospheric Administration (NOAA) (website: http://www.ncdc.noaa.gov/cdo-web/). 25 2. "Negative" percent indicates actual weather was warmer than nonnal.
WP2-7 1 ofl Attachment JNG-1 Page 16of16
Atmos Energy Corporation - Colorado Service Areas Summary of Present Rates Test Year Ended March 31, 2017
Tariff Tariff Tariff Calculated Adjusted Commodity Total Line Customer Commodity Gas Cost Margin Customer Adjusted Tariff Charge GCA Commodity No. Description Charge {1) Charge {1) Charge (cl - {d2 Rider% Charge Margin Gas Cost Excluding GCA Jun - 11 c2) Charge (a) (b) (c) (d) (e) (f) (g) (h) (i) G) (k) (1)
1 Northeast 0.00% 2 Residential $ 11.60 $ 0.18885 $ - $ 0.18885 $ 11.60 $ 0.18885 $ - $ 0.18885 $ 0.48845 $ 0.67730 3 Commercial 28.24 0.11145 0.11145 28.24 0.11145 0.11145 0.48845 0.59990 4 Irrigation 45.17 0.10305 0.10305 45.17 0.10305 0.10305 0.48845 0.59150 5 6 Northwest 7 Residential $ 11.60 $ 0.18885 $ - $ 0.18885 $ 11.60 $ 0.18885 $ - $ 0.18885 $ 0.50681 $ 0.69566 8 Commercial 28.24 0.11145 0.11145 28.24 0.11145 0.11145 0.50681 0.61826 9 10 11 Southeast 12 Residential $ 11.60 $ 0.18885 $ - $ 0.18885 $ 11.60 $ 0.18885 $ - $ 0.18885 $ 0.44100 $ 0.62985 13 Commercial 28.24 0.11145 0.11145 28.24 0.11145 0.11145 0.44100 0.55245 14 Inigation 45.17 0.10305 0.10305 45.17 0.10305 0.10305 0.44100 0.54405 15 16 17 Southwest 18 Residential $ 11.60 $ 0.18885 $ - $ 0.18885 $ 11.60 $ 0.18885 $ - $ 0.18885 $ 0.33053 $ 0.51938 19 Commercial 28.24 0.11145 0.11145 28.24 0.11145 0.11145 0.33053 0.44198 20 21 Notes: 1. Both the Tariff Customer and the Tariff Commodity Charge exclude the Rate Case Rider expense associated with Proceeding No. 15AL-0299G. The Company 22 also excludes the SSIR rates as the respective capital is not subject to a return. The Demand Side Management Cost Adjustment and Demand Side Management Volumetric Cost Adjustment rates are surcharges which are not recorded to a revenue account; therefore, these rates are also excluded. 23 2. The GCA rate (Col k) has been updated to June 2017 rates.
WP2-8 1 ofl Attachment JNG-2 Page 1 of2
Atmos Energy Corp.oration I Rate Division 1 ( Divs 33,34,35) Rate Division 2 (Div 36) Percent Change in Total Bill for Average Usage by GustomerClass
NE DIVISION % NWC DIVISION % SE DIVISION % SW DIVISION % CURRENT PROPOSED CHANGE CURRENT PROPOSED CHANGE CURRENT PROPOSED CHANGE CURRENT PROPOSED OHA:N'!IE RESIDENTIAL Mon1hly Faciltties Charge $11.68 511.68 $11.68 $11.68 $11.68 $11.68 $11.68 $11.68 Low Income Rider $0.00 $0.00 SO.DO $0.00 $0.00 $0.00 $0.00 $0.00 Dernand Side Management $0.10 $0.10 S0.10 $0.10 $0.10 $0,10 $0.10 $0.10 Average Usage in CCF 55 55 72 72 53 53 62 62 Gas Cost Adjustment(GCAJ: Commodity per CCF 0.33365 0.32956 0.32796 0.32956 0.32321 0,32956 0.33110 0.3311 Upstream Pipeline Costs per CCF 0.18200 D.17152 0.19745 0.17152 0.09999 0.17152 0,02423 0,02423 Deferred Gas Cost per CCF (0.02740) {0.02740) (0.01860) (0.01660) 0.01780 0.01780 (0.02480) (0.02480) Total GCA $0.48845 S0.47368 S0.50681 $0.48248 $0,44100 $0,51868 $0.33053 $0.33053 Distribution System Rate per CCF 0.19016 0.19016 0.19016 0.19016 0.19016 0,19016 0.19016 0.19016 Volumetric DSMCA 0.00156 0.00156 0.00156 0.00156 0.00156 0,00156 0.00156 0.00156 Volumetric SSIR Surcharge 0,01987 0.01987 0.01987 0,01987 0.01987 0.01987 0.01987 0.01987 Total volumetric rate for class $0.70004 $0.68527 S0.71640 $0.69407 $0.65259 $0.73047 $0.54212 $0.54212 TOTAL BILL $50.28 $49.47 ..2% $63.50 $61.75 -3"/a $46.37 $50.49 9% $45.39 $45.39 0%
NE DIVISION % NWC DIVISION % SEDl\llS1011t o/o SW DIVISION o/o CURRENT PROPOSED CHANGE CURRENT PROPOSED CHANGE CURRENT PROPOSED CHA~Gli CURRENT PROPOSED CHANGE" SMALL COMMERCIAL & COMMERCIAL Monthly Facilities Charge $28.44 $28.44 $28.44 $26.44 $28.44 $28.44 $28.44 $26.44 Low Income Rider (Public Authority does not pay) so.co so.co $0.00 $0.00 $0.00 $0.00 $0.00 SO.OD Demand Side Management $0.55 $0.55 $0.05 $0.55 $0.55 S0.55 $0.55 $0.55 Average Usage in CCF 312 312 415 415 213 213 329 329 Gas Cost Adjustment(GCA): Commodity per CCF 0.33385 0.32956 0.32796 0.32956 0.32321 0.32956 0.33110 0.3311 Upstream Pipeline Costs per CCF 0.18200 0.17152 0.19745 0.17152 0.09999 0.17152 0.02423 0.02423 Deferred Gas Cost per CCF (0.02740) (0.02740) (0.01860) (0.01860) 0,01780 0.01780 f0.02480) {0.02480) Total GCA $0.48845 S0.47368 S0.50681 $0.46248 $0.44100 $0.51888 $0.33053 $0.33053 Distribution Sys.tern Rate per CCF 0,11222 0.11222 0.11222 0.11222 0.11222 0.11222 0.11222 0.11222 Volumetric DSMCA 0.00215 0.00215 0.00215 0.00215 0.00215 0Jl0215 0.00215 0.00215 Volumetric SSIR Surcharge 0.01173 0.01173 0.01173 0.01173 0.01173 0Jl1173 0.01173 0.01173 Tote[ volurnefric rate for class $0.61455 S0.59978 $0.63291 $0.60858 $0.56710 $0.64498 $0.45663 $0.45663 TOTAL BILL $220.73 $216.12 -2% $291.65 $2.81.55 -3% $149.78 $166.37 11% $179.22 $179.22 0%
NE DIVISION % SE DIVISION o/o CURRENT PROPOSED CHAN.GE CURRENT PROPOSED CHANGE IRRIGATION Monthly Facilities Charge $45.48 $45.48 $45.48 $45.48 Low Income. Rider $0.00 so.co $0.00 $0.00 Average: Usage in CCF 135 135 467 467 Gas Cost Adjustment(GCA): Commodity per CCF 0.33385 0.32956 0.32321 0.32956 Upstream Pipeline- Cosis per CCF 0.18200 0.17152 o,0999g D.17152 Deferred Gas Cost per ccF (0.02740) (0.02740) 0.01780 0.01780 Tota!GCA $0.48845 $0.47366 $0.44100 $0.51888 Distribution System Rate per CCF 0.10376 0.10376 0.10376 0.10376 Vclumeb'ie SSIR Surcharge 0.01084 0.01084 0.01084 0.01084 Total valumeiric rate for class $0.60305 $0.5882.B $0.55560 $0.63348 TOTAL BILL $126.89 $124.90 -2% $304.95 $341.32 12%
Cc-.ndotidatio:n • Bitl tmpai:t Attachment JNG-2 Page 2 of2
Atmos Energy Corporation Current Gas Cost Calculation
Division 1 (Northeast· Div 33, Northwest/Central - Div 34, Southeast· Div 35)
!Jn.e.~ Mi.l'=.11 Jun-17 Jul-17 Aug-17 Sop-17 Oct-17 ~ Dec-17 Jan-18 ~ Mar-18 Apr-18 Tu!ill (•) (b) (c) (d) (•) en (g) (h) (i) (j) (k) (I) (m) (n) (o)
1 Gas Commodity Cost $1,122,9T2 $852,093 $786,697 $762,674 $805,179 $1,705,448 $3,496,733 $5,510,699 $5,678,909 $4,585,132 $3,402,968 51,866,122 $30,595,626 2 Gas Purchase Quan1ity $429,420 $299,846 $265,096 $259,777 $270,216 $570,678 $1,142,585 $1,691,279 $1,702,064 $1,398,940 $1, 111,434 $707,778 9,849,112 3 Market Prices 2.62 2.B4 2.97 $ 3.01 2.98 $ 2.99 s 3.06 $ 3.26 $ 3.34 $ 3.28 $ 3.06 $ 2.64 3.11 4 Upstream Service Cost 1,148,467 1,0B4,278 1,073,516 $ 1,071,667 1,128,569 $ 1,247,572 s 1,495,621 $ 1,624,132 $ 1,627,568 $ 1,558,548 $ 1,478,236 $ 1,385,080 $15,923,254 5 6 Sales Gas Ouan1i!;i 406,244 283,503 250,422 245,415 256,270 539,165 1,075,724 1,591,889 1,602,352 1,317,149 1,047,474 668,069 $9,283,676 7 [email protected],65 psia 8 9 Commodity Cost 3.2956 10 [email protected] psia 11 12 UQstream Servj~e g:i;i;st 1.7152 [email protected] psia 14 15 Current Gas Cost 5.0108 16 Mcf@ 14.65 psi•
Second Division (Southwest - 36) Line Forecasted: May-17 Jun-17 Jul-17 Aug-17 Sep-17 Oct-17 Nov-17 Dec-17 Jan:ll\ Feb-18 Mar-18 Allr:J..e. Total (•) (b) (c) (d) (e) 1 Gas Commodity Cost $223,235 $152,948 $141,931 5140,925 5162,358 $354,675 $659,297 $1,026,975 $1,075,527 $833,685 $637,906 $345,481 $5,754,943 2 Gas Purchase QuantHy $84,993 $53,939 $47,814 $46,776 $54,302 $119,219 $216,177 $308,781 $316,900 $248,653 $207,173 $139,532 1,844,258 3 Market Prices $ 2.63 2.84 2.97 $ 3.01 $ 2.99 $ 2,97 3.05 3.33 s 3.39 3.35 3,08 2.48 3,12 4 Upstream Service Cost $ 17,400 15,888 16,237 $ 16,204 $ 15,900 $ 18,472 58,766 63,465 $ 63,719 56,183 60,285 18,567 $421,086 5 6 S~l~s G@§ Quanli!:i [email protected] psia 80,101 50,834 45,062 44,084 51,177 112,357 203,735 291,009 298,662 234,343 195,249 131,501 $1,738,114 8 Q: Commodi:t!i Cost [email protected] psia $ 3.3110 11 12 U!;!sfream Service Cost 13 Mcf@ 14.65 psia $ 0.2423 14 15 Current Gas Cost 16 Mof@ 14.65 psia $ 3,5533 ConsolfdaH.o-n ..Ra:te Calcul•tf.l)n$ Attachment JNG-3 Page 1of3 Atmos Energy Corporation Bill Impact of Craig Compressor Station on Northwest/Central-Division 34 Northwest/Central DMsion 34 Northwest/Central Division 34 Annual Residential Usaq• Peak Residential Monthl)l Bill Annual Usage Curren! wl Compressor Peak Bill Current wl Com~res.so~ Monthly Facilities Charge $140.16 $140.16 Monthly Facilities Charge $11.68 $11.68 Low Income Rider $0.00 $0.00 Low Income Rider $0.00 $0.00 Demand Side Management $1.20 $1.20 Demand Side Management $0.10 $0.10 Average Usage in MCF 86.4 86.4 Average Usage in MCF 16.9 16.9 Gas Cos! Adjus!ment(GCA): Gas Cost Adjustmant[GCA): Commodity per MCF 3.16780 3.18780 Commodity per MCF 3.18780 3.18780 Upstream Pipeline Costs per MCF 1.75080 1.75080 Upstream Pipeline Costs per MCF 1.75080 1.75080 Deferred Gas Cost per MCF (1.19100) [1.19100) Deferred Gas Cost per MCF (1.19100) (1.19100) Craig Compressor per MCF 0.33840 Craig Compressor per MCF 0.33840 TolalGCA $3.74760 $4.08600 TotalGCA $3.74760 $4.08600 Distribution System Rate per MCF 1.90160 1.90160 Distribution System Rate par MCF 1.90160 1.90160 Volumetric DSMCA 0.01560 0.01560 Volumetric DSMCA 0.01560 0.01560 Volumetric SS!R Surcharge 0.19870 0.19870 0.19870 0.19870 Total volumetric rate for class $5.86350 $6.20190 Total volumetric rate for class $5.86350 $6.20190 TOTAL BILL $647.97 $677.20 Monthly Bill $110.87 $116.59 Average Monthly Bill $54.00 $56.43 Peak Bill Increase $5,72 5.2% Monthly Increase $2.44 4.5% Total Res Mo. Increase $53, 774.331 Northwest/Central Division 34 Northwest/Central Division 34 Average Commercial 8111 Peak Commercial Bill Annual Usage wt Comoressor Peak Bill Current wl Comg;ressor Monthly Facilities Charge $341.28 $341.28 Monthly Faciliiies Charge $26.44 $28.44 Low Income Rider (Public Authority does not pay) $0.00 $0.00 Low Income Rider (Public Authority does not pay) $0.00 $0.00 Demand Side Management $6.60 $6.60 Demand Side Management $0.55 $0.55 Average Usage in MCF 499,2 499.2 Average Usage in MCF 90.3 90.3 Gas Cost Adjustment(GCA}: Gas Cost Ad)ustment(GCA): Commodity perMCF 3.18780 3.18780 Commodity per MCF 3.18780 3.18780 Upstream Pipeline Costs per MCF 1.75080 1.75080 Upstream Pipeline Costs per MCF 1.75080 1.75080 DeferredGasCostperMCF [1.19100) (1.19100) Deferred Gas Cost per MCF (1.19100) (1.19100) Craig Compressor per MCF ___~=----~o'-'.3.,_3,.,B,.,4.,,._0 Craig Compressor per MCF 0.33840 Total GCA $3.74760 $4.08600 Total GCA $3.74760 $4.08600 Distribution System Rate per MCF 1.12220 1.12220 Distribution System Rate per MCF 1.12220 1.12220 Volumetric DSMCA 0.02150 0.02150 Volumetrlc DSMCA 0.02150 0.02150 VolumetrlcSSIR Surcharge 0.11730 0.11730 0.11730 0.11730 Total volumetric rate for class ___,$,.;5'-;.o,.;o"'se"'o;----.,.,$5~.3"'4;;7,.;0..;...0 Total volumetric rate for class $5.00860 $5.34700 TOTAL BILL $2,848.17 $3,017.10 Monthly Bill $481.27 $511.82 Average Commercial Bill $237.35 $251.43 Peok Bill Increase $30.56 6.3% Monthly Increase $14.08 5.9% Total Com Mo. Increase $50,294.19 ! IRRIGATION •NWIC HAS NO IRRIGATION CUSTOMERS Monthly Facilities Charge Low Income Rider Average Usage in MCF Gas Cost Adjustment(GCA): Commodity per MCF Upstream Pipeline Costs per MCF Deferred Gas Cost per MCF Total GCA Distribution System Rate per MCF Total volumetric rate for class TOTAL BILL Attachment JNG-3 Page 2 of3 Atmos Energy Corporation Average Usage Per Customer By Customer Class Average Average Average PEAK MONTH PEAK MONTH Annual Usage Annual Number Monthly Usage Monthly Usage Annual Usage USAGE USAGE Line Division Class (Mcf@ 14.65} 1 of Monthl~ Bills 2 MCF CCF MCF CCF MCF (a) (b) (c) (d) (e} (f) (g) (h) (i) 1 Northeast Colorado Residential 3,148,066 574,751 5.5 55.0 66.0 141 14.l 2 Commercial 1,738,025 54,569 31.9 319.0 382.8 771 77.1 3 Irrigation 1,619 24 67.4 674.0 808.8 1,972 197.2 4 Northwest/Central Colorado Residential 1,917,611 264,845 7.2 72.0 86.4 169 16.9 5 Commercial 1,785,609 42,872 41.6 416.0 499.2 903 90.3 Southeast Colorado Residential 1,182,916 228,949 5.2 52.0 62.4 135 13.5 6 Commercial 472,542 22,796 20.7 207.0 248.4 511 51.1 Irrigation 5,715 97 58.9 589.0 706.8 2,123 212.3 Southwest Colorado Residential 1,126,369 183,777 6.1 61.0 73.2 142 14.2 Cornrnercial 843,975 25,550 33.0 330.0 396.0 721 72.1 Annual Usage Annual Number Volumes/Bills by Division (Mcf@ 14.65) of Monthl~ Bills Northeast Colorado 4,887,709 629,344 Northwest/Central Colorado 3,703,220 307,717 Southeast Colorado 1,661,173 251,842 Southwest Colorado 1,970,344 209,327 Total 12,222,447 1,398,230 Attachment JNG-3 Page 3 of3 Craig Compressor Incremental Service Charge Calculation October 1, 2015 Incremental DPQ 2,300 DTH 18,320 DTH Estimated Load Factor 26.4% $ 219,834 Estimated Annual Volume (note 1) 221,628 DTH Construction Allowance for TFL Distribution Main $3.43/DTH Calculated Construction Allowance (note 2) ($760,184) Estimated Compressor Costs $8,553,558 Calculated Construction Allowance ($760,184) Net Construction Costs after allowance $7,793,374 Revenue Requirement Factor (Note 3) 16.08% $ 1,253,175 Monthly Firm Capacity Reservation Charge $6.75/DTH GRSA 18.77% Total Annual Revenue Requirement For Compressor $ 1,253,175 Less Incremental Annual Capacity (PDQ) Charges (note 4) $ 221,269 Remaining Incremental Service Charge (note 5) $ 1,031,906 Monthly Incremental Capacity (PDQ) Charge $ 8.02 $ 18,439.04 Monthly Incremental Service Charge $ 37.39 $ 85,992.17 $ 45.40 $ 104,431.21 Annual Incremental $ 1,253,174.53 Notes: 1 The estimated annual volume is calculated by multiplying the annualized PDQ by Atmos' western operational area load factor. 2 The Construction Allowance (CA) is calculated by multiplying the CA rate per DTH by the estimated annual volume. 3 The revenue requirement is calculated by multiplying the net construction cost after CA by the revenue requirement factor as noted on tariff page R34 4 The incremental annual capacity charges are the product of the PDQ multiplied by the monthly firm capacity reservation charge plus the GRSA. 5 The remaining incremental service charge is the total annual revenue requirement less the annual capacity charges. Attachment JNG-4 Page 1 of 13 Atmos Energy Gorpqration 2017 Colorado Rate case T••I Year Ending March 31, 2017 Colorado Customer Counl Unk:s to Schedule: 2 Actual Counts 2016 2017 GrondTotol Customer 04 05 I 06 I 07 I 08 OS 10 11 12 01 02 I 03 Commercial Customer1 1 1 1 ! 1 1 1 1 1 1 1 1 12 customer2 11 1 1 Customa.r3 1 1 1 1 4 cu•tomer4 1 1 1 1 1 1 1 1 1 1 1 12 Customers 8 8 8 !I 8 8 8 8 8 8 8 8 Q6 CuslomerS 1 1 1 1 1 1 1 1 1 1 1 12 cuslomer7 2 2 2 2 2 2 2 2 2 2 2 24 CustomerB 1 1 1 ~I 1 1 1 1 1 1 1 1 12 Cuslomer9 1 1 1 1 1 1 1 1 1 1 1 1 12 cuslomer1a 4 4 4 4 4 4 4 4 4 4 4 4 481 Cu.stomer11 1 1 1 1 1 1 1 1 1 1 1 1 12 customer12 1 1 1 1 1 1 6' Customer13 1 1 1 1 1 1 1 1 1 1 1 1 12 Cu.stomer14 1 1 1 1 1 1 1 1 1 1 1 1 12 Customer15 4 4 4 4 4 4 4 4 4 4 4 4 48 Customer 16 1 1 1 1 1 1 1 1 1 1 1 1 12 cuolomer17 1 1 1 1 1 1 1 1 1 1 1 1 12 Customer18 1 1 1 1 1 1 1 1 1 1 1 1 12 Customer19 2 2 2 2 2 2 2 2 2 2 2 2 241 Customer20 1 1 1 1 1 1 1 1 1 1 1 1 12 2 2 2 2 Customer21 2 2 2 2 2 2 2 21 241 Customer22 1 1 1 1 1 1 1 1 1 1 1 1 I 12 Customer23 2 2 2 2 2 2 2 2 2 2 2 2! 24 Customer24 1 1 1 1 1 1 1 1 1 1 1 11 12 Customer25 1 1 1 1 1 1 1 1 1 1 1 1 12 Customer26 1 3 1 1 1 1 1 1 1 11 c1.1stomer27 3 3 3 3 3 3 3 3 3 3 3 3 36 Customer28 3 3 3 3 3 3 3 3 3 3 3 3 36 Custamer29 4 4 4 4 4 4 4 4 4 4 4 48 Customer.30 2 ii 2 2 2 2 2 2 2 2 2 2 24 Customer.31 1 1 1 1 1 1 1 1 1 1 1 11 Customer32 1 1 1 1 1 1 1 1 1 1 1 1 12 Customer.33 1 1 1 1 1 1 1 1 1 1 1 11 12 CU$tomer34 1 1 1 1 1 1 1 1 1 1 1 1 12 Customer35 1 1 Customer.36 1 1 1 1 1 1 1 1 1 1 1 1 12 Cu:stomer37 1 1 1 1 1 1 1 1 1 1 1 1 12 Customer38 1 1 1 1 1 1 1 1 1 1 1 1 12 Customer39 3 3 3 3 3 3 3 3 3 3 3 3 36 Customer40 1 1 1 1 1 1 1 1 1 1 1 1 12 ·customer 41 2 2 2 2 2 2 2 2 2 2 2 2 24 Cus.tomer42 1 1 1 1 1 1 1 1 1 1 1 1 12 Customer-4.3 1 1 1 1 1 1 1 1 1 1 1 1 12 Customer44 3 3 3 3 3 3 3 3 3 3 3 3 36 I Customer-45 1 1 1 1 1 1 1 1 1 1 1 1 12 i Customer46 1 1 1 1 1 1 1 1 1 1 1 1 12 I Customer47 1 1 1 1 1 1 1 1 1 1 1 1 12 I customer4a " - - 1 1 1 1 1 1 1 1 1 s 1 Customer49 7 7 7 7 7 7 7 7 7 7 7 7 841 Customer50 1 1 1 1 1 1 1 1 1 1 1 1 121 Customer51 2 2 2 2 2 2 2 2 2 2 2 2 24 Customer52 1 Customer53 4 4 4 4 4 4 4 4 4 4 4 4 4~ I Customer.5-4 2 2 2 2 2 2 12 Customer55 1 1 1 1 1 1 1 1 1 1 1 1 12 Customer.56 2 2 2 2 2 2 2 2 2 2 2 2 24 Cust.omer57 2 2 2 2 2 2 2 2 2 2 24 2 21 Customers.a 6 6 6 6 6 6 6 6 6 6 6 72 Customer59 4 4 : I 4 4 4 4 4 4 4 4 4 48 CustomerfiO 34 34 34 34 34 34 34 34 34 34 34 406 customer61 1 a; I 1 1 1 1 1 1 1 1 1 1 12 I I I I' Commercial T.otal 135 136 I 137 137 140 139 141 141 I 142 I 142 143 143 1,676 Negotiated Customer62 2 2 2 2 2 2 2 2 2 2 2 2 24 customer63 1 1 1 1 1 1 1 1 1 1 1 1 12 Customer64 21 21 21 21 21 21 21 21 21 21 21 21 252 Customer65 1 1 1 1 1 1 1 1 1 1 1 1 12 Customer66 1 1 1 1 1 1 1 1 1 1 1 1 12 Customer67 1 1 1 1 1 1 1 1 1 1 1 1 12 Customer66 3 3 3 3 3 3 3 3 3 3 3 3 36 Customer69 4 4 4 4 4 4 4 4 4 4 4 4 48 Customer70 1 1 1 1 1 1 1 1 1 1 1 1 12 Customer71 1 1 1 1 1 1 1 1 1 1 1 1 12 Cus-tomer72 1 1 1 1 1 1 1 1 1 1 1 1 12 customer73 3 3 3 3 3 3 3 3 3 3 3 3 36 Customer74 1 1 1 1 1 1 1 1 1 1 1 1 12 customer75 166 166 166 166 166 166 166 166 166 166 166 166 1,992 Customer76 1 1 1 1 1 1 1 1 1 1 1 1 12 Cu:s.tamer77 1 1 1 1 1 1 1 1 1 1 1 1 12 Customar78 1 1 1 1 1 1 1 1 1 1 1 1 12 customer79 1 1 1 1 1 1 1 1 1 1 1 1 12 Customer.ao 2 2 i 2 2 2 2 2 2 2 2 2 2 24 Neootia1edTotal 213 213 213 213 213 213 213 213 213 I 213 213 213 2,556 Grand Tclal 348 349 350 350 353 352 354 354 355 355 356 356 4,232 Attachment JNG-4 Page 2of13 Adjustments 2016 2017 Grand Tota Customer 04 05 06 07 I 08 09 10 I 11 12 01 02 03 Commercial Customer1 i - Cu.stomer2 1 1 1 1 1 1 I 1 1 1 1 11 Cu.slomer3 1 1 1 1 1 1 1 8 cu.stomer4 : I - Customers - Cu.stomer6 - custamer7 - CustomerB - cuotomer9 Customer10 Customer11 Customer12 1 1 1 1 1 1 Customer13 Customer14 Customer15 ~I Custamer18 CU$tomer17 Customer18 customer19 ~I Customer20 - Customer21 - Cu:s.tomer22 - Customer2.3 - Cu.s.tomer24 - Customer25 - Customer26 1 1 1 (2) 1 cu•1omer27 - Customer:28 - Customer2:9 - Customer JO - Customer31 1 1 cuotomer32 - Customer33 Customer34 :j Cust-omer35 (1) {1)1 Customer36 -I Customer37 -1 Customer38 -; customor39 I Customer-40 :i I Cuotomer41 - Customer42 I - Customer43 - Customor44 I - Customer45 - customer46 - Customer47 - cuattJmer48 1 1 1 3 Customer49 - Customer50 - customoro1 ·1 Customer52 (1) (1)1 Customer53 Customer54 :I Cus,omer55 _, ' Customer56 I - Cuslomer57 I " Customer SS I - Customer59 I I I - Customer60 - Customer61 I I Cus,omer62 2 2 2 2 2 2 2 2 2 21 24 Customer63 1 1 1 1 1 1 ~I 1 1 1 12 Cuslorner 65 1 1 1 1 1 1 1 1 1 12 !I j 12 Cu.stomer71 1 1 1 1 1 1 11 1 1 Customer72 1 1 1 1 1 1 1. 1 1 1 12 1 1 i1,I 12 Customer76 1 1 1 1 1 I 1 1 1 ii g g gl gl Commercial Total 13 12 11 11 a B 7 7 112 Nogotiated Customer62 (2) (2) (2) (2) (2) (2) (2), (2)j (2)! (2) (2) {2) (24)1 cuotomer63 (1) (1) (1) (1) (1) (1) (1)! (1)! (1)1 (1) (1) (1) (12)1 Cuslomer64 I Cuslomer65 (1) (1) (1) (1) (1) (1) (1)! (1)! (1)1 (1) (1) (1) Customer66 (1~1 Customer67 I -1 Cus,omer66 Cus,omer69 I Customer70 I Cuslornar71 (1) (1) (1) (1) (1) (1) (1)! (1) (1) (1) (1) (1) (J Cu.stomer72 (1) (1) (1) (1) (1) (1) (1)! (1) (1) (1) (1) (1) (12) Customor73 - Customer74 i I - Cus•omer75 I - Customer76 (1) (1) (1) (1) (1) (1) (1)1 (1) (1) (1) (1) (12) Customer77 - Customar78 Customer79 :1 Customer SO I "'I -i Negotiated Total 17 {7] m m m m (7)1 m1 (71 m (7 17! 184\ Grand Total 6 5 4 4 t 2 2 I . 2 11 1 -I - 28 Attachment JNG-4 Page 3of13 Adjusted Counts I 2016 2017 Grand Tota I customer 04 05 06 07 08 09 10 I 11 12 01 02 I 03 commercial Customer1 1 1 1 1 1 1 1 ! 1 1 1 1 1 12 customer2 1 1 1 1 1 1 1 1 1 1 , 1 12 Customer3 1 1 1 1 1 1 1 1 1 1 1 1 12 Customer4 1 1 1 1 1 1 1 1 1 1 1 1 12 customer!5 8 8 8 8 8 8 8 8 8 8 a 8 96 Customers 11 1 1 1 1 1 1 1 1 1 1 1 12 Cu:s.torner7 21 2 2 2 2 2 2 2 2 2 2 2 24 Cu:stomar8 1' 1 1 1 1 1 1 1 1 1 1 1 12 Cus.tomer9 1 1 1 1 1 1 1 1 1 1 1 1 12 customar10 4 4 4 4 4 4 4 4 4 4 4 4 48 Customer11 1 1 1 1 1 1 1 1 1 1 1 1 12 cu.stomer12 1 1 1 1 1 1 1 1 1 1 1 1 12 Customer13 1 1 1 1 1 1 1 , 1 1 1 1 12 Custcmer14 1 1 1 1 1 1 1 1 1 1 1 1 12 Customer1.5 4 4 4 4 4 4 4 4 4 4 4 4 48 Cuslomer16 1 1 1 1 1 1 1 1 1 1 1 1 12 I Gu.Starner 17 1 1 1 1 1 1 1 1 1 1 1 1 12 I Customer18 1 1 1 1 1 1 1 1 1 1 1 1 12 Customer19 2 2 2 2 2 2 2 2 2 2 21 a 24 I Custamer20 1 1 1 1 1 1 1 1 1 1 1 12 I Customer21 2 2 2 2 2 2 2 2 2 2 ~I 2 24 Customer22 1 1 1 1 1 1 1 1 1 1 1 1 12 Customer23 2 2 2 2 2 2 2 2 2 2 2 2 24 Customer24 1 1 1 1 1 1 1 1 1 1 1 1 12 c1.1stomer25 1 1 1 1 1 1 1 1 1 1 1 1 12 Customar26 1 1 1 1 1 1 1 1 1 1 1 1 12 customer27 3 3 3 3 3 3 3 3 3 3 3 3 36 Customer28 3 3 3 3 3 3 3 3 3 3 3 3 36 Cus!omer29 4 4 4 4 4 4 4 4 4 4 4 4 48 Customer30 2 2 2 2 2 2 2 2 2 2 2 2 24 Cuslomar31 1 1 1 1 1 1 1 1 1 1 1 1 12 Cu.slomer32 1 1 1 1 1 1 1 1 1 1 , 1 12 Cuslomer33 1 1 1 1 1 1 1 1 1 1 1 12 Cus1cm1er 34 1 1 1 1 1 1 1 i I 1 1 1 1 12 cust.amer35 ------1 - - - -I - Customer36 1 1 1 1 1 1 1 1 1 1 11 12 customer37 1 1 1 1 1 1 1 ; I 1 1 1 12 Cust.amar38 1 1 1 1 1 1 1 11 1 1 1 12 Customer39 3 3 3 3 3 3 3 3 3 3 3,: I 36 Customer40 1; 1 1 1 1 1 1 ~i 1 1 1 1' 12 Customer41 2 2 2 2 2 2 21 2 2 2 21 24 I custamer42 ~I 1 1 1 1 1 1 1 1 1 1 12 Customer43 1 1 1 1 1 1 1 1 1 1 1 12 Cu:stomer44 3 3 3 3 3 3 3 ii 3 3 3 3 36 Cu:stomer45 1 1 1 1 1 1 1 1 1 1 i 1 1 12 Customer46 1 1 1 1 1 1 1 1 1 1 1 12 customer47 1 1 1 , 1 1 1 1 1 1 1 12 I Cusfomer-48 1 1 1 1 1 1 1 1 1 :I 1 1 121 c1.1stomer49 7 7 7 7 7 7 7 7 7 7 7 84 Customer.SO 1 1 1 1 1 1 1 1 1 ii 1 1 Customer.51 2 2 2 2 2 2 2 2 2 I 2 2 ~!I_, Customer.52 ------:1 -! - Cuslomer53 4 4 4 4 4 4 4 4. 4 41 4 481 customor64 ------2 2 2 2 ii 2 12 I Custome-r55 1 1 1 1 1 1 1 1 1 1 1 I 1 12 customer56 2 2 2 2 2 2 2 2 2 2 2! 2 24 Customer67 2 2 2 2 2 2 2 2 2 2 21 2 24 Customer58 6 6 6 6 6 6 6 6 6 6 6 72 Customer59 4 4 4 4 4 4 4 4 4 4 :l 4 48 Cuslomar60 34 34 34 34 34 34 34 34 34 34 34 t 34 408 Cuslome-r61 1 1 1 1 1 1 1 1 1 1 1 j 1 12 Cuslomer62 2 2 2 2 2 2 2 2 2 2 2 i 2 24 Customer63 1 1 1 1 1 1 1 1 1 1 1 ! 1 12 Gustomer65 1 1 1 1 1 1 1 1 1 1 11 1 12 Customer71 1 , 1 1 1 1 1 1 1 1 1 f 1 12 customer72 1 1 1 1 1 1 1 1 1 1 12 Customer7S : I 1 1 1 1 1 1 1 1 11 : I 1 12 Commercial Total 148 I 141 141 141 I 141 141 143 143 143 143 I 143 f 143 I 1,788 Negotiated customer62 ------. - -- Custome:r63 -- . ------customar64 21 21 21 21 21 21 21 21 21 21 21 21 252 Customer 65 ------C"slomer66 1 1 1 1 1 1 1 1 1 1 1 1 12 Customer67 1 1 1 1 1 1 1 1 1 1 1 1 12 Cuslomer68 3 3 3 3 3 3 3 3 3 3 3 3 36 Cuslomer69 4 4 4 4 4 4 4 4 4 4 4 4 48 Cuslomer70 1 1 1 1 1 1 1 1 1 1 1 1 12 Cuslomer71 ------Cuslomar72 ------C1.1stomer73 3 3 3 3 3 3 3 3 3 3 3 3 36 Customer74 1 1 1 1 1 1 1 1 1 1 1 1 12 Customer75 166 166 166 166 166 166 166 166 166 166 166 166 1,992 G1..1stomer76 - -I ------Customer77 1 1 i 1 1 1 1 1 1 1 1 1 1 12 customer78 1 1 i 1 1 1 1 1 1 1 1 1 1 12 Customar79 1 1 ! 1 1 1 1 1 1 1 1 1 1 12 I Customer BO 2 2i 2 2 2 2 2 2 2 2 2 2 24 INecotiated Total 206 206 206 206 206 206 206 206 206 206 206 206 2,472 !Grand Tolal 354 347 I 347 I 347 347 347 349 I 349 349 349 I 349 349 4,260 Attachment JNG-4 Page4of13 Atmos. l:.llorgy Corporation 2017 Clllorado Rate Case Tes.t Year .E.nd~ng March 31, 2017 Cok1rado Billed Trang.poftelon Volumllil Lin'ki io Schedijle 2 Actual Volumes 2016 2017 GrancJTo!al Custemer 54 05 07 OB 09 10 11 12 01 02 03 Gomme.rclal Customer1 1.70 ""1,793 760 317 1,554 1,850 636 292 7,:Y2 Customer2 301 301 CUstomer3 467 1.127 1,009 638 3,241 CU5tomer.tl 1"4 172 162 12B 129 136 142 100 159 200 200 167 1,949 CUStQmlil:r:S 2,4(13 1,609 •44 301 319 375 2B5 960 1,55') 3,316 3,836 2,5B3 10,490 Customl!l:r6 128 63 20 1 1 1 1 13 120 409 439 270 1,471 CU!iltomer7 1,383 1,006 923 851 753 "49 7B3 796 92'5 1,220 1,204 910 11,604 Custome:r:S 257 214 109 51 51 49 61 117 256 475 475 306 2,431 Gustomer9 ... 570 465 254 357 369 366 508 ... 1,0JO 915 722 6,9'17 Gustomer10 2,708 2,047 1,598 BOB w 655 1,040 1,410 1,974 3,301 3,358 2,367 22,315 C'Ustomer11 154 12B 129 123 121 122 127 167 225 305 246 179 2,026 C\Jstooier12 107 124 15" 262 243 173 1,002 CUst-omer13 138 110 B4 49 39 36 47 •• 119 226 215 136 1.248 Cust-ome:r14 1.'13 990 ... 1,150 720 OBB 694 775 1,174 1,875 1,531 1,542 13,537 Cust.amer15 l'll4 267 119 3 1 10 128 802 2,547 2,570 i,290 B,5::ti Cust-orner1S 7 6 3 3 3 4 8 14 20 21 17 115 Cust-amer17 24• 1,281 7 1,169 51 534 43 67 3,176 Cusk1tnet18 1.124 1,072 1,260 1,137 951 910 922 1,013 1.176 1,680 1,5~8 1,182 13,005 Customer1:!1 346 252 164 18 18 ,. 30 111 330 750 735 437 3,217 Castorner:lO 387 287 341 204 251 291 179 2'!3 307 507 459 323 3,818 Castamer21 560 407 286 1eB 190 199 201 243 470 846 B33 .,, 4,-445 Cu~t'Clmer22 123 61 49 5 4 9 15 37 115 348 325 1ea 1.277 Customer23 3,004 2,B04 2,a20 2,267 2,26:5 2,:ID9 2,357 2,713 2,1!166 3,592 3,415 2.711 33,223 Cu&tomer24 261 226 125 60 62 65 75 112 236 see 608 355 2.751 Customer25 658 552 542 501 472 500 SM 516 567 BOB 870 724 7,'Z22 Customer26 36 11 8 13 43 104 219 199 121 754 Customer 27 1,342 1,003 6.56 240 231 260 356 627 1,266 2,650 2,421 1,.594 12,:898 Cuslomer 28. 332 222 90 20 20 23 29 45 297 697 752 362 2,899 CU:!!.to.rner.29 907 583 197 47 40 132 182 242 891 1,732 1,801 1,064 7,808 Customer30 140 110 85 54 41 42 50 B2 124 225 21• 153 1,324 Cti:s:tomer31 87 00 33 25 39 63 122 213 204 130 1,{]93 Customer 32 3,766 4,639 6,754 14,.593 1.2,641 16,039 ifi,007 10,.556"' 3,941 33 87,969 Cl.ls1~er.33 2,.so 1,964 2,002 1.•31 1,11g 1,981 1,968 2,040 2,00S 2,:381 2,582 2,341 25,266 Custcm.er.34 4,493 3,661 3,144 2,121 2,03.B 1,936 2,316 2,95D 3-546 4,616 4,489 3,760 J:9,i20 C1.l:&o1rJiTI-er35 392 392 Cu:&tom-er36 80 1,518 1,800 3,362 5,166 7,199 5,424 7,636 4,303 2,020 70 77 3-8,767 Cu&1omerJ7 434 396 427 372 31S 325 237 250 261 422 477 422 4,340 Cue.1orner:!8 15B 133 121 96 110 9B 94 119 154 235 187 148 1,648 CustomerJ9 756 406 = 36 28 Jl4 100 357 639 1,556 1,399 "44 6,630 Cus.tom-er40 1,475 1,331 1,376 1,402 1,335 1,284 1,213 1,120 1,049 1,327 1,121 ... 15,021 Cust1Jmer41 345 182 45 1 350 "20 ... 520 3,119 Custamer42 966 820 738 625 567 563 776• 972 1,321 1,272 1,022 10,252 Cust1Jmer43 74 66 •••42 41 ., 41 50 82 192 162 100 969 Customer44 24 ""4 3 3 3 3 3 18 159 132 39 394 Customer45 209 174• 154 135 136 139 140 149 172 271 262 193 2.134 Cus1omer46 283 215 1'1 137 3 140 12" 184 250 315 36B 267 2,442 CUB!omer47 687 269 91 66 .. 120 271 553 1,035 1,019 B45 5,377 CUB!om'e!r4a '"' 153 1'5 143 142 254 3'6 53B 537 393 2,661 Cus,omer49 504 361 290 132 125 147 260 517 "72 97" 540 4,007 Cu!ii;l'Jmer:SO 155 '"" 155 Cus~omer51 2,292 1,9:!5 1,680 1,210 1,280 1,.431 1,389 1,7.56 1,965 2,793 2,685 2,316 22,732. Cl.l!ii!l'Jmer:Sl! 106 106 Cue,omer53 457 375 312 SB 3 6 233 396 874 702 466 3,686 Customer54 16 243 647 552 2ea 1.004 Cuslomer55 21,993 2..ili,000 29,304 30,7(16 32,144 31,040 30,697 29,1n"" 26,618 34,231 31,382 2.1,7-42 343,934 Customer56 400 266 171 89 84 87 as 122 267 475 492 325 2,003 Cuslomerfif 2,5S2 2,88:5 2,639 2,025 965 1,115 1,293 1,141 1,0:34 BBS 933 693 18,170 Customer58 1,527 1,072 837 226 164 233 35B 783 1,1;oo 3,078 2,625 1,687 14,090 Custamer59 1,53(1 1.027 6"7 SB 39 90 257 507 1,041 2,509 2,411 1,400 11,671 Cuslomer60 5,995 3,9'" .2,Q37 446 389 ... 717 1,773 5,7i1 i-4,676 13,656 7,e92 58,579 Customer61 366 294 2'2 124 117 126 150 242 366 600 536 3B4 3,639 Ccimme:rcial Tola! 74!161 69,392 6911586 70,612 87,93"4 75,611 73,262 74,831 76,259 10~773 102,611 70,9Hi 935,049 Negotiated CIJ!iit.ome:r62 4,279 3,555 3,336 2.744 2,531 2,-056 3,031 3,375 4,211 -4,900 4,879 4,172 43,005 Custome:r63 471 391 344 253 262 264 324 396 509 7B5 749 522 6,237 Cl.l!iitomer64 30.fi9B 24,604 17,•44 10.431 9,e~ 10,.50~ 11.145 1",!lll5 27,898 45,142 "12,.833 3G,666 280,"4{18 Custome:r65 1,246 1,071 620 615 712 2eB 578 743 945 1,1M 1,232 1,056 10,184 CustomerG"6 4,492 4,659 4,396 4,059 4,024 3,522 3,220 3,661 4,369 4,406 4.388 3.309 4S,5Q5 Customer& 12.212 9,551 7,633 5,020 4,931 4,931 5,222 7,028 9,606 15,9112 15,756 11,257 108,949 CustomeT68 12,1352 12,507 13,283 11,071 10.940 6,530 8,884 10,641 i2,078 13,618 12,815 10,953 13B,172 Customer69 99,194 86,308 136,956 .82,296 73,046 75,:Y31 73,167 79,245 -66,269 96,62:1 102,127 99,697 1,031,059 CUstomer70 64,929 59,638 58,QBB .51,678 53,532 55,666 51,25" 50,4\13 58,702 79,745 1g,C196 64,616 727,531 Ci.J9U!m.et71 1,664 1,346 1,031 662 646 796 7BO 003 1,269 2,591 2,762 1,SOO 15,962 Customiar72 721 523 396 226 171 200 201 313 5"7 991 1,012 765 6,126 Cl.l!i!t¢mef73 11,719 9,588 a,.ioa 6,904 6,664 7,189 7,:201 B,426 10,24<' 1~220 14,247 11,674 117,540 Customaf74 101,9!54 97,.887 99,1997 94,740 1Q0,651'.8 99,358" 94,173 102,069 96,544 89,-454 99,.837 BS,7\17 1,165,416 Cl.li;itQlller75 11,278 22,720 31,179 54.259 :58,974 6:5,907 33,686 16,677 10,006 2,9:59 2,a20 ,,277 315,"4:02 Custorm1:r 7.S 1,3a§ 1,227 1,32{} 1,17.5 972 795 ... 899 741 773 1,112 1,260 12,2:95 C'U!iitQl111Jf77 502 478 6,633 2,293 791 304 4BO 2.069 344 1,WS 2,248 266 16,115 CUstom~;r7a Q.istomer7:9 25,753 17,441 2.1,639 37,573 21,143 18,050 25,070 31.346 18,861 15,642 12,991 24,66CI 271,B69 CustometSO 5,""98 4.476 4,247 3952 3,871 4,686 3,7.86 4,147 4920 4,793 5,202 4,729 54,107 N'l!lE1~~1:1tet1Total 390,497 358,170 367,386 369.973 353.441 Je0.700 323,"1)2 343.146 348.072 396.72'! -405,606 353,37B 4,370,004 Gr.and Total 464;6!58 427,562 437!07"4 "140,585 421,37:5 436,311 397,064 417,977 424,331 fi00,400 50.8,217 42"1j293 5,305.943 Attachment JNG-4 Page 5of13 Adjustments 201• 2017 Grand Total customer 04 05 00 fil 00 09 10 11 12 01 02 03 Commercial Custarner1 C1.1slorner:a 258 258 258 258 258 258 253 253 258 258 258 ('3) 2,795 Cuslomer3 SIT/ 507 507 507 507 507 507 507 40 (620) (502) !131) 2,843 Cust<1mer4 Custamer5 Custamer6 Cll!.tamer7 Custamer8 CU$tQmv.r9 Customw 10 C1.$$tQITTW11 Customer12 162 162 162 162 162 162 55 38 (100) (81) (11] 882 CU$t1Jmlllr1J Custorner14 Custom111r15 Customer16 Custamer17 Customer18 Customer19 Customer20 Customer21 Custometll Gust-omer23 CtJstomer'i!"4 Gl.lstamer25 C1Jstort1£1r:2Ei 86 86 75 73 73 43 (18) (13') [113) (35) 278 Custcmer27 •• '" Cu&tomer2.8 CUstamer29 Cu&tamerJO Custamer 31 114 27 34 81 89 75 51 17 !8) (96) (90) (16) 275 Cusl:Qmer 32 Cus.mrner33 CustoC1mer 34 CQs;lamer 35 (392) !362] CustQmer 36 1,587 M9 (223] (1,695) (3,519) (5,532) (3,757) (5,971] (2,636) (353) 1,59'7 1,590 (18,767) C~to1;1mer37 Custamar36 CUliil:Qmer 3g Customer 40 CU!Fl:omer41 Cus.tomer42 Cus.IDmer43 Cue.tomer-44 Customer 45 Cus.tomer-46 Cnstamer47 Cm.1orner 46 406 355 253 1,013 Cm1amer 49 c111.1oi:r.er5Q Cwi.1omer51 Cu:!l.1amet5l (10SJ (100) Cu:i.tomer53 CIJ~omer54 109 169 189 100 169 169 153 10!l (74) (478) (383) (117) 224 Customer55 Cl.lii-,omer56 Cu~omerSl Cl.l:&,Qmer58 Ct1stomerS9 C~stomer50 Ct1slomer61 Customer62 4,279 3,5551 3,336 2,744 I 2.531 2.858 ~.0:31 3,375 4,211 ..... 4,879 Cuslomer63 471 3911 344 253 I 282 284 324 3'36 506 785 749 ·~:; ! 578 "~I1,056 Customer65 1,246 1,0'711 620 a15 ! 712 285 743 845 1.160 1,:>32 10:18• 1 Customer71 1.004 1,.031 6821 6'16 798 780 803 1,289 2,59( 2,782 15,962 1.:1 1.;:1 Customer72 n1 39" 228 I 171 208 201 313 597 991 1,012 6,1<6 Custotllet76 1.335 1.221 I 1,320 1,175 972 785 896 61!9 741 713 1,112 1.200 I 12,295 Commercial Tot3i 13,004 9,628 8,25"6 fi,2.65 .J.005 J,150 5,740 :9,791 12.040 10,002 Negolialed Cu:!lt011)1!1t :82 (4,279) (3.555) (2,744) (2.531) [2,856) (3.031) (3,375) (4.211) (4,996) (4,679) (4,172) j43,965) Cu!Storner83 (471) (391) (253) 1262) (284) (324) (J96) (505) (785) (749] (522) (5,267) Cus,ornar64 Cuslomar85 (1,246) (1,071) (820) (615) (712) (285) (578) (743) (6451 (1.180) (1,232) (1,056) (10,164) Cl.l!ii;QIOOr 6a Cuslomerffl CIJ!ii~omer6a Cus!omer6S Customer70 Customer71 (1,654) (1,346) j1,031) (682] (546) (798) (780) (803] (1,269) (2,591) (2,762) (1,500) (15,962) Customer72. (721) (523) (396) (228) (171] (208) (201) (313) (597] (091) (1,012) (765) (6,128) cuslomern Cus!omer74 Cus!omer75 Cus!omer78 (1,335) (1,227) (1,3201 (1,175) (972) (785) (696) (699) (741] (n3) (1,112) (1.200) (12,295) Cus10.111..ar7l Cus!nmar78 CU!i!,omer79 CUBtomer.SO /9,716) (6.113) 17.0471 (5,697) (£,294} [5,217) (5,810} [6,.329) (B,169) (11,316) (11,746] (9,365) j93-819l Grand Total 3,2Ba 1,713 1,200 {432] (2.259! (4.389) (2,615DJ f.4.999] (2,4291 11.525) 294 1,237 (10,955) Attachment JNG-4 Page 6of13 Adjusted Volumes 2016 ~17 Cus.Wmer 05 07 06 09 10 11 12 01 02 03 Commercial CusLomer1 170 1,700 700 317 1,554 1,850 2921 7.372 Cusr:ome~:2 25S '58 25B 25B 258 258 258 """258 258 l 258 258 258 3,000 Cu:i.tomer3 507 507 507 507 507 507 507 507 507 I 507 507 507 6,064 Cuirtomer4 194 172 182 128 129 138 142 160 200 200 167 1,949 Cuirtamer5 2,403 1,609 944 301 319 375 285 960 1.~;~ I l,316 3,636 2.583 10,490 Cust-cimer6 128 68 20 1 1 1 1 13 120 439 270 1,.471 Customer7 1,as3 1,006 920 851 753 849 783 796 926 I 1,220""" 1,204 810 11,604 Customer 8 267 214 100 51 51 61 117 475 475 300 2,431 Custon,er 9 570 Ml5 264 357 369•• 386 500 ~:1 1,030 915 '6,947 C~stomer 10 2,708••• 2,047 1,598 741 ass 1,o Atmos Energy Corporation 2017 Colorado Rate Case Test Year Ending March 31, 2017 Colorado Special Contract Value Links to Selledule 2 Actual Revenues ! Description ··-···--·-----~--~-~------1sum of NetAmt Ac:ctYear AcctMonth i 2016 2017 Grand Total i ~_!NonN~LJ 04 05 06 07 08 09 10 11 12 i01 02 03 Negotiated Customer62 2,537 2,136 2,015 1,668 1,570 i,750 1,847 2,037 2,933 ····2.869 2,476 26,360 Customer63 481 414 374 298 305 324 357 418 2,:~~ i 745 714 524 5,465 Customer64 25,320 20,689 15,575 9,895 9,383 9,928 10,435 16,346 23,306 ! 36,527 34,768 25,376 237,548 Customer65 1,132 985 606 602 683 326 571 709 795 i 1,076 1,120 972 9,578 Customer66 3,659 3,999 3,778 3,495 3,465 3,044 2,790 3,161 3,755 ! 3,786 3,771 2,865 41,766 Customer67 3,821 3,007 2,420 1,621 1,563 1,594 1,683 2,235 3,024 i 4,950 4,905 3,529 34,351 Customer68 2,786 2,757 2,912 2,470 2,444 1,962 2,033 2,384 2,671 i 3,019 2,819 2,446 30,705 Customer69 20,180 17,603 17,733 16,800 14,950 15,527 14,975 16,190 17,595 ! 19,665 20,767 16,321 210,306 Customer7o 11,773 10,856 10,538 9,387 9,721 10,105 9,312 9,158 10,652 14,439 14,323 11,716 131,979 i Customer71 738 613 490 353 339 396 391 400 583 1,102 1,169 709 7,285 ! I Customer72 634 463 386 259 215 243 238 323 539 839 855 667 5,682 i I Customer73 9,167 7,547 6,690 5,506 5,323 5,722 5,732 6,663 6,047 11,829 11,089 9,133 92,446 j I i Customer74 14,767 14,181 14,485 13,728 14,566 14,393 13,646 14,783 13,SBB 12,967 14,462 12,859 168,644: i Customer75 22,003 29,883 35,737 51,881 54,889 59,943 37,403 27,223 21,125 16,206 15,764 16,426 388,482 ' Customer76 1,207 1,116 1,194 1,072 902 745 836 672 708 735 1,019 1,144 I 11,3s1 I Customer77 116 115 492 226 134 104 115 212 106 190 223 102 ! 2,135 Customer78 85 85 85 85 85 85 I 512 Customer79 1,723 1,195 1,462 2,475 1,430 1,291 1,731 2,079 1,285' 1,080 912 1,654 I 18,314 Customer80 4628 3,799 3 614 3,374 3, 147 3 970 3,240 3533 4,159 i 4,056 4,386 4004 i 45,912 126,956 121462 120,567 107,335 108.527 115,348 I 136,146 135,936 114924 I 1,469,D];?_ Attachment JNG-4 Page 8of13 ~~j_!!~-!~.!!_'!~-- l!?.~~£i:l?.~!eD.. ---··········-····J Sum of NetAmt IAcctYear -,A-oot...,M'"'o-n""th------·------2016 !Neg I Non Neg .Negotiated 2136 (414) I ,,. ,,,,] .... 1 ...,1 .ooi1 ...,1 ,, .,,.,, "·""'' ,,,,,.;-----; I I ;-' _____,i -·173iill---·-@1·3ir····--gsorr····--t3·53ir······1:;a·0i"f··········(ssiiJf·-·····Iss1ir···-1460ir=J~~1 .11.169)~; (1,2as21 F...rss4)[ ___(483>f"" ... -·{siisir""-·-r2siiJr-·-· <:Fisi -····-··r24ai ··········,23sJr-·····(s23)f (sssi1 (assi! -{s55il . (667li ts,sa2)! I ~:---___.! i [1---~ ..__(1-.2-01-i_~-r1-,1-1s-n'--<1-.1-e4-i:--r1-,o~n-it--(-90-2~)1--,-74-5~)[--(-B3-8~)t--(-67-2~)j--(-70--iar·'rnr1i~a1ei, (1,144l!~l I ..---· Grand Total 6,12a' s,747' s,066 · 4,212 i ~~4,242)i ~~~5=63=5~~~) 7,746 (~4§1A2 __(§§J~l. Attachment JNG-4 Page e of 13 25,320 20,689 15,575 9,895 9,383 9,928 23,3061 25,376 237,548 I - I - ---=-·9167 7 547 i ! 14767 14181; 14,485 I 13,728 i 14 586 I 14,393 I 13 646 I 14,783 13,988 12,967 14 462 12,859 I 168,844 i i._-=="-'--'===.;..-..:::.:3fl,m 22,003 29,883 I l_.2.:!.Jl_!l.Ll_s~h§~E!..e43: 31403 2122s 21,12s_,_..!1?_,g_ll§_~~§i._...1§J42s I 388,482 I i -- -- ______: ___ !____ _:_ e----.;.-.,.,,...1---.;.--=-1---.;.-~1---.;.-=-'-----<--. -- ;-----;---.,..,.,,-+---,4"'"92-;---,2-2'"5"""i 116 115 134 104 115 212 106 190 223 102 I 2,135 f'--~=-+---=+---=a5 85 85 85 85 85 ------r s12 i 1,723 1,195 1,462- 2,475 1,430 1 291 1,731 2,079 1,285 1,080 912 I 1,654 ! 18,314 ' 4,626 3,799 3,614 3,374 3,147 3,970 3,240 3 533 4,159 4,056 4,388; 4,004 I 45 912 Grand Tola! I 120,227 115,715 115,521 120,944 121,120 127,6.§! _:l.Q.~,Q§~-~..!Q~.967 109,713 128,716 128,190 f 108430 i 1,403,303 .. ·-········-··········-·············-··-······- ...... ------·------Attachment JNG-4 Page 10 of13 Atmos Energy COJ'})Oration Tran1port Cndomer Adjustments Line No. (a) (b) (o) (d) (•) (l) (gJ (h) (i) Gl (l) (O>) (n) (o) (p) (q) (r) Adjustment 1 Adjust per OOck volumes and -count tor cus.1omcr tbo.t .mi:; 5'r.1ti1chl.ni; from Spc:>1:i1LI Contmi:::ttoFlrm 'rrMiliport.uei.or.i AddOOto-Tr.o:n:gi;icirt.oii.on Spt:efo.lCotttl'lletRc"!En!:!~ ItDrli!!l'.!Dl:!!rlt.iti•:i;rn;;t.tmaM'6.2. Vol1:1m.i:ICcf 'l'ransnor:tDlion Volu1ne.tril!: Riiiie ~ ~ April 2016- March 2017 439,IS:SCJ s (JJJ9~6 • 4CJ.,fi06 ' - {26,3:S9.62) $. {26.359.&i) T,.~1Jl:!l[!C1rr.iiti!llr:i • C1.1.1tMmer 6l Added 1!:! Irn11~1Mi!rl:atior.i 8~~et~l Ccinlr.oct RiWer.Jllll:!I Vol~r.nill!CcF Trrms~ortntion Volu111efric: l.blie ~ ~ ~ April!Dl-15- March20t7 52.870 s 0.D!ii~6 s 4,883 (5,464.56) :II (S:.464.:56) 10 • ll !:i;:nn~IJC1!l!tjn.n - ~!J!l.'M!Jlol!r 6:5: Odd~ 1CI IT.111J!llC!r..tt1ti.n.~ ~i;:~r,:ial i;;;eolrns;t E~ismJ!ii!! 12 ~ I!:ill~5!'1Elilill1JD :fg] !.l!J!~IIi G. B:!!.l!ii Removed T.r.ilatlmrmi=t 13 April 2016- Mcreb 2CJ!7 lOl.340 s 0.051236 s 9.406 (9,S78.04) :£. (!:1.5'18.04] 14 - ' 15 T£ii1!1:EIJnrrstl1u1 .. :f,;;w:lmn er 71 ~!i(d~ lo, Tr.nrul!;!Drto(ior.i 8!;!cciol Ccmtr.ai;it R~·i:.r.iucs 16 ~ Iamsii!i!l1!l!tim1 Vi;itg1m:!l:ic: &1-11 Revenue rtemcl'lred Tr.il.blTm11aec 17 April2016-March:2m7 lS'Sl,620 s (t.09236 14.'i'43 f7,28:S.:.;;9) s {7,2:!1:S.:i:9} 18 • • 19 Tc!!MI!:l!:'!:li!tion - Cu1tta.m,e-.. "72 ~ 1t1:IrnIW12llilll2!J ~l:!li:Gillil ~!J!i!!~Ei!!!Sn~s 20 ~ Tl]!rL'l.~gtici!J V!i!lumc:tclc:~tr: R.eyenue R:emc:ved Tl)t:!lTl'nJ!!!CC 21 April 2016-M.urch2017 6!,260 O.OSl236 s !i,6:58 lS.6&1.69) S (:S.6;11.I,!Si;I) 22 • • 23 T1":ll!Ji!e1!:11i!!:l:iCIPJnf;;;U.tt.!l!~f!l'71'i 6dd'.cdtoTrnr.isfJ:Qnatign S~cfal Coricr:i.ct Rc.'lli:nui:;s 24 Va-lumc.ICcf Tr.ans:~rt:icion Volcmu::ITic Race: Re.venue: ~ Tofa.IIrnmiet 25 April 2D16~M.omh2DI7 122."9.SiO • D.051236 s 11,356 s (11,.351.28) (ll.3S1.28J 26 ' 27 AdJllsCmlln,lTol.cl U,i5:S2 • {M,721} $ 20,931 28 w 30 31 Adjustme111 2 32 T1~D~[!r>rt11tian • C11;;;m~er 41 33 Adj1:1!l't' tx:t book -vc-lttmes and oo~r.it fot et1siomet "41mc was l ni"dven~ntlr 34 bined 1te Coiitit1erdol S:olee lSotltheustDLvlsion3:i)April 2016- I= :20115 Redpii;t[Mttl ~ ~ ~ ~ !i;;!i!DJOJ!£1"gj11:lf.!11l~o'll F:ollilitics: Tmn:!lpr.irmtion; Tm11!m0t!:~1tl'n'I Re\·ised:Ca:un! Re\·iscd.Volume 35 ~ ~ Pc:r &ck Cclum~Ccf AdjuscOOCciuni AtCj:usledVntume ~ ~ ~ ~ ~ ~ ~ 36 37 Apdl 2016 4,DS6 4,056 28.24 0.11145 (41tfl; W.7-D O.O!H72. 4S7 (23} 38 Ma~·2Ct16 l,:S:Sl l,:5:Si 213.24 ' 0.11145 (4:24} $84.70 • 0.091?2 •' 410 (14) 39 .luac.2016 2,S28 :2,S2S 28..:W 0.11145 (llD) $84.1Q • .C..051172 317 40 July2Ct16 1.s:.3-0 1,S30 0 28.~4 0.11145 S84.7o0 0.09172 41 A1.1st1~.20l6 i.:m 1,350 28..24 Ct.11145 $84,70 -D.O!il172. 4i Seplember2Ctt6 1.430 1,43CJ " 28.24 • 0.1114S S84.JD {)_[151[?2. 43 Octol>i::r~016 1,4~0 1,420 2S.24 0-.1114S S&4.7D -0.09[7.!. • 44 ND'lli::mbcr. 2016 2.~o l,S40 2:11.24 G.lll4S S84.i0 0.0911.2. • 45 Dci:<:mbctWl6 3,66D J,66(1 ~S.24 Co.1114:5 $64.70 O.O'i1'1'7l 46 J1muniy201i :5,'380 ::i,3:11G :;?S.24 0.1114;5 S84.W O.OSH7.!: 47 Fel:ituary:;!L'.111 :S.3;70 5,31Ct. 2:0..24 • 0.11145 S34.70 0.09-1'7? s 48 M:irch20-17 J,930 393(). 0 28.24 • 0.11145 S84.'i'O O.CJ9r'1:i -·--·- 49 T-C>t1.l 26.6HJ ll .36.74.S I0,13S (1..214] ' ' l.L:04 • (30) Attachment JNG-4 Page 11of13 Adjuotment 3 Tt'11.~~~11omtlL'l1t • C8~tirnt-t' 2 New Trn11;sp!!irt Customer DS. crFc:hnml}' .iC!17 ~ :E&itB!:!Qk C:al!.!m!i1tC:!iif ~ ~ Adi1L'1.tcdCou11t AdjustedVG1ume Ap:ril:'.!016 :l:,5;110. 2.:iBO May2.016 - :2.S:llCJ. 2.l"' Junc:2016 :2,:S:llO 2.S~ July:.1016 .2,S:llCJ 2,,5.80 Augusl:2016 2,:S81'.J ,J.. Scplicmbcr 20 I6 :2,580 2,:5:80 Ocloba:r2016 2,S80 2,:iBO November 2016 2.sso '2,=i:BO Ikcmnb~2016 2,:S80 :2,5:11() Jammy2017 2.:580 2,:5:8(1. Fc:brua:ry201i 2,:580 I 2,:5:110- M:m:h2017 3.01{) 2,S80 0 (43(1 Tola.1 3,010 12 j(:i,960 11 :i7,9:SO Adjustment 4 Trn~tJ.'l'IHnota • Ctl!Ulloltll!'l'".3 '.Ne:w !Jmispo-rl C1,1ptome!I' 11.$ ~ ~ J'c:r ~ool: CrJ!umelCcr ~ Rell'is:edVCJlume ~= Adjus;!gdyPlpm:!i April2016 0 5Jl]f) S:.070 Ml.y 20[6 0 51110 S:,070 Jµm=;20lei 0 5,070 S,070 July20I6 0 5.0?0 S,010 A.ugus.t2DI6 0 l .5,070 S,OiO s~p~mh~2Dl6 0 I .i,070 S,011'.J. Ctclc-ber201D 0 l .S,D70 S,0'11Jo Navcm1Mlr.2Crl6 D I .5,D?D S,O?Qo Th:ccmbc;r'.:!016. 4,610 I S:,070 4li(I JILOU8IJ2017 11.270 l S.070 (r5.20G) FC!brunry2ot' 10,00() I $,OiO lS.020) Mcircb:2Dl7 6.31!!-0 I 5.Q70 0.3HH Tomi l2,.41-0 12 .DD.840 2S.430 Adjustment 5 TranGf!Bl"hltion-C'u:!dome?"1'! New Tr.1mspDrt Cg111lom~r :is ofSqi.1~bcr 2015 ~ ~ Es:i::B!ll~:i;;:11:111rn1;/~i!if ~ ~ Adjus.ted:Ccmt1 AditatedVo.lumii: Aprll20I6 0 1.62(). J,620 Mn~·10115 0 1.62'.lo ,.. ,. J~mi::ID115 0 1,62(1. ,.. ,. Jt1l)•:l{lili; 0 1,620. AugusllOHi 0 1,62(1. '·""'l,62D September :2616 0 l,6W 0i.1tDbcr2016 1,070 1.62(). 550 Nc'llembe:r2011S 1)40 l,620. '""">Ill Di:c::cmbi::rWl6 l.S30 1,62(). Jamml}'201'1 2,62:0 l,OW (J.allo,"" Febrwuy 2017 2,i430 l,i521J (11:10) Mornb2017 l.731l ],'5:21'.J 110 Tob>l 10,l!i:?D ll 19.440 """" Adjuotment 6 Tt"1trun0irr:11.tian. Cu."!fom~r '26 l;lew Tr.011spllrt Cti!damcr 1!15. oiMay 2010 ~ 'Pu 'Rook Co1mt Pc:r !loQk ColumcfC:if ~ Rl:'l~sc:i:IVclurnc Adius.tcdCgu:nt Adh111ted Vc.lume Apri120l6 0 .., ~y20l6 0 ...""" .., ,!t1:qe2016 '..li60 ... 0 $DO J~ly20lfi 0 I ... I Aug~lZD11$ 110 .., l2) 7$0'" Slf:Ptll:mb"f2'Dl6 I BO ' .., D Ocrtcber2D16 I J:.::o ' .., '" November .20-16 I 430 'I 860 430'" Dec1m1bcr:20l6 I 1.040 1 860 {180) Jam1;ey2-D17 I 2.100 1 .., (1.:1:1D) Fo:ihnmcy:2:{)]7 I I 860 {1,130, M.oroh2:Dl1 I '·"'"l..2IO I {350 Total 11 7,S40 12 10,320''" 2,780 .: ... ·-·· ... :. -~- ·... : Attachment JNG-4 Page 12of13 Adjustment 7 Tr:nTl:!l!:!!:l'f:ntion • Cu!ilt!JimCT"3I N"ei.v"Tm11llpc-rt C:asccmer as of" A-prlt 2016 .Psri!l!! Per'Bc.r..kCcunt :Pl!"r 'Book Ccluma/Ccf ~ ~ Adju*dCauna 6-ili!!i!!li;i;!Vi;illi!m& April>Olo l,l40 1.14() Mlly2016 "70" 1,140 270 Jwie20liS J.140 340 Jaly2016 ""'330 1,140 810 Aagast:'.!.016 ,,. t,140 8ll:_ptet.1tbe:r2Cll6 I l I,140 ''° Oc.11;1bl!"r :201-6 l "" l l.140 ''°SlO NCo11~:mbi.V:2.016 l "" l l,J.40 170 Decembcr20l6 l 1,220"" l l_l.40 ([!IJ) J.onuiiry:2D17 l 2,130 l 1,140 (990) F'chruacy~017 l 2,040 l l.l-40 (l>OOJ Moreh:2Dl1 l l.300 l 1-140 160) Tct.nl 11 lCi,930 12 13,680 2.7S"O Adjustment S Tli"IM[!S:l1~tfi.~ y !t'.;ll~Hll!'lll!I' 35 New Tr:iMport Cu~Wm~ :P.111 of liebn:i:lfY ;;!(ll 7 ~ ~ Elr;[ Ikzg~ :C!i!llli![l~Qs;f ~ R-ayCscdVolaml!! AdjusledCmml AdjustedVclurnl!l April26l() Moy.2016 Ju.n-c?016 Ju.ly2016 Au.g;usc.:20t6 0 Scp~mbcr .2016 0 Oc1obc:r:2(J.16 0 Nci~·cmtii:rlOl-fi 0 Di:oi:::mbi::;t 2016 0 .rn:n."lf.Jl}'"20l7 0 0 0 Fc-bruitl)'Wl7 3,920 (l) (3.9201 MMoCh:Wl7 0 0 0 Tool 3,920. (lJ (~.!)20) Adjustment 9 T1-a!!;!![!2~l:11tjat1 y CU:1;t11ontl!".-3rj; ,A.dj 11str.nei:it fa-:r nJll:ici pored usose Jl;tloO ~ P:!il'. I!2e~ QalYme!Qi:::f ~ ~ Adjui;tcdCounl A.tljl111:ledVolume Aprll.2016 1 .., M,657 lS:,SCi7 M:i.y:i!Oli5 I IS.ISO 16,667 1,487 Janc201D I l8,510G 16,W (l.lJJJ July201D I 33,620 16,667 (16.9:53) August:2l01!) I Sl,SQO I .16.,667 (JS:.193) Scpti:mbcr2016 I 71,9510 I t.S-,667 (55323) Odoha20lD I S4,24() I !G,667 (37.$73) Neivcmbcr:2016 I 76,3:00 I Hi-,667 (.59.713) Dcccmbcx2016 I 43,0-30. I t6..667 (:'.!5,363) Jamr.ary2017 I 20.200 I ti5.,667 (3..533) Fe:bruo:ry:2017 I 700 I t6.,667 1.S:,$11$1 Maroh2017 l 770 I IQ..667 1.S..897 Tool 12 38:7,6-70- 12 200..000 (!01.670) Adj11stment 10 Tl'D!!;!![!!!:~l:11tfot1·Ctl11;111oinl!"1'S4 Nei.v tJllll!lpa-:rt Cue~i:mi:r as .W:Sepcember :i!ll!J Period Pcr"BCoBkC:ourit Per :Boo.k Columl!"ICd' RcviscdCoucit R:l!:l.'"isedVo1ume Adh.1sted C:ounl Adjl11tled Vo1um-e. AprU20tfi 0 1,690 1.6510 M4y20I6 0 1.690 1,6510. lime20ID- 0 l,fi91'.J l.(i~(J- Jllly20Ii5 0 1,691'.J 1,651(} Augus.t:'.!:01!) 0 1,691'.J I,figo Sii=p1mn.bll=r2016 1,1590 J,69G Oclc-bcr:l:016 ,.,' 1,691'.1 1,:530 November .2016 600 l,1590 1,090 D!!!eember2CH6 2.4:3(.1 1,690 {/40_1. J1Lnwey2017 6,.47'0 l,1590 (4.7:110-} Fc=br1:1ary20!7 .5.S.W 1,690 (3,83G'} Mm-¢112017 2..,1!;!)[] l.Ci!ilO rt.17(1') Toitil 12 1S,D4D 12 2-0,:?80 2,::!4() ooooo!§'oooooog q c. I ::::. ::::;. QOOooSooooooE; it ..:::io.:::i.o<:'.>o.o.;:,.-=ioooo II OOOOCC..QOOO..::>Ci.0 J 00000~..::lOOOOO~• I00000-'000000-' ~ t I ;:: ~ ~ ~ ~ ~ ~a '!l -~a 11 . i: ~ ~~~ ~~~~ ~~ ~~~j JI~°'~ ~ =~ ~ ~Jh ri~ H: t!i! .; .li.i: il ~ Attachment JNG-5 Page 1 of 14 ATMOS ENERGY CORPORATION Colo. P.U.C. No. 7 Gas 1555 Blake St., Suite 400 Thirty-lltffl:IFomih Revised Sheet No. 9 Denver, Colorado 80202 Cancels Thirty-SeeanEI Third Revised Sheet No. 9 NATURAL GAS RATES Cost Atljustment & Rate Component Summary All volumetric rates at $ per CCF Class/Sheet Division 1 Division 2 No. Tl'.l!e of Charge NE NWIC SE SW Residential 15 Facilities Charge $~12.59 $-1+.6& 12.59 $~12.59 $-l+.6&12.59 £.LLLl} PIPP $0.00 $0.00 $0.00 $0.00 GasDSMCA $0.10 $0.10 $0.10 $0.10 Gas Cost Adjustment (GCA): Commodity $0.33385 $0.32796 $0.32321 $0.33110 ~ Upstream Pipeline 0.18200 0.19745 0.09999 0.02423 (R,l,R,}iC) Deferred Gas Cost (0.02740) (0.01860) 0.01780 (0.02480) ~ Total GCA $0.48845 $0.50681 $0.44100 $0.33053 ~ Distribution System Rate O.-l-9Q.l.620494 O.-l-9Q.l.620494 O.-l-9Q.l.620494 0.19016 20494 rum Volumetric DSMCA 0.00156 0.00156 0.00156 0.00156 Volumetric SSlR Surcharge 0.01987 0.01987 0.01987 0.01987 Total volumetric rate for class $0 ..+oo-0471482$0 ..'.7-l-S4-0733 l 8 $0.~6673 7$0.5 4212 55690 (I,I,1,1) Small Commercial & Commercial 15 Facilities Charge $~30.65 $~30.65 (I ,I,J.I PIPP $0.00 $0.00 $0.00 $0.00 GasDSMCA $0.55 $0.55 $0.55 $0.55 Gas Cost Adjustment (GCA): Commodity $0.33385 $0.32796 $0.32321 $0.33110 flJ,I;l} Upstream Pipeline 0.18200 0.19745 0.09999 0.02423 (R,l,R,}~C) Deferred Gas Cost (0.02740) (0.01860) 0.01780 (0.02480) ~ TotalGCA $0.48845 $0.50681 $0.44100 $0.33053 ~ Distribution System Rate o.m12095 o.m12095 o.m12095 o.m12095 Irrigation Service 17 Facilities Charge NA $4M&49.02 NA a.n PIPP $0.00 Gas Cost Adjustment (GCA): Commodity $0.33385 NA $0.32321 NA M Upstream Pipeline 0.18200 0.09999 fR,Rj Deferred Gas Cost (0.02740) 0.01780 AA TotaIGCA $0.48845 $0.44100 AA Distribution System Rate o.~11.183 0.10376 11183 Volumetric SSIR Surcharge 0.01084 0.01084 Total volumetric rate for class $0.™61112 $0.55560 56367 (I,I) Attachment JNG-5 Page 2of14 DO NOT WRITE INTIDSSPACE Advice Letter No. ~530 s/Jennifer Ries Issue Date: June 26Mfty-39, 2017 Decision or Authority No. C17 9418 Title: Vice-President Effective Date: Jtme-.2..Julv 27. 2017 Rates and Regulatory Affairs Attachment JNG-5 Page 3of14 ATMOS ENERGY CORPORATION Colo. P.U.C. No. 7 Gas 1555 Blake St., Suite 400 Eightee1tthNineteenth Revised Sheet No. 11 Denver, Colorado 80202 Cancels SeveHteeetltEighteenth-Revised Sheet No. 11 NATURAL GAS RATES Cost Adjustment & Rate Component Summary All volumetric rates at $ per CCF Class/Sheet Division I Division 2 __lfu,__ Type of Charge Transportatfon Set'Vice 23, 25 Facilities Charge $~91.92 Gas Cost Adjustment (GCA): Commodity NA NA NA NA Upstream Pipeline NA NA NA NA Deferred Gas Cost NA NA NA NA Transp011ation Gas Cost Adj. $0.00601 $0.00601 $0.00601 $0.00601 fR,R:,R;~ Tota!GCA $0.00601 $0.00601 $0.00601 $0.00601 (R,R,R,~ Max Distribution System Rate o.~9953 o.~09953 o.~09953 0.~09953 CI.I.I.I) Volumetric SSIR Surcharge 0.00965 ---0.00965 0.00965 0.00965 Total volumetric rate for class $0.Mmll519 $0.i--G™ll519 $0.Mmll519 $0. Mm! 1519 J11L.U(R,R,R_,R) DO NOT WRITE IN THIS SPACE Advice Letter No. S29~ s/Jennifer Ries Issue Date: June 26Mev:W. 2017 Title: Vice-President Attachment JNG-5 Page 4of14 Decision or Authority No. Cl7 1Hl8 Rates and Regulatory Affairs Effective Date:-July 2 7J.tme.-l.. 2017 Attachment JNG-5 Page 5of14 ATMOS ENERGY CORPORATION Colo. P.U.C. No. 7 Gas 1555 Blake St., Suite 400 Se•t'enthEightb Revised Sheet No.15 Denver, Colm·ado 80202 Cancels Sffth.Seventh Revised Sheet No. 15 NATURAL GAS RATES (General Service Classification) GENERAL SERVICE (Rate Title or Number) AVAILABILITY Available in entire service area of the Company within the state of Colorado. APPLICABILITY Applicable to residential, small commercial and commercial service. This rate is not RATE applicable to resale or standby service. The residential monthly facilities charge is applicable to all metered individual dwelling units. The commercial monthly facilities charge is applicable to all other firm services. MONTHLY RATESllH21 Facilities Charge: Residential $ I Small Commercial and Commercial ++:&& 12.59 I $ ~30.65 Distribution System Rate, per CCF (Billing Pressure Base 14.65 PSIA) Residential I Small Commercial and Commercial $0.+9Q..l.420 I 494 ~-~12 095 GAS COST ADJUSTMENT This rate schedule is subject to Gas Cost Adjustments stated in the Cost Adjustment & Rate Component Summary Schedule. GAS DEMAND-SIDE MANAGEMENT COST ADJUSTMENT This rate schedule is subject to Gas Cost Adjustments stated in the Cost Adjustment & Rate Component Summary Schedule. OTHER RIDERS This rate schedule may from time to time be subject to rider(s) as permitted by the Public Utilities Commission. RULES AND REGULATIONS Service supplied under this schedule is subject to the terms and conditions set forth in the Company's Rules and Regulations on file with The Public Utilities Commission of the State of Colorado. [1] See Sheet No. 's 3 and 4 for applicable local pressure base and Sheet No. 14 for computation of bill information. [2] See Sheet No. 19 for applicable General Rate Schedule Adjustment DONOTWRITE Rider applying unifmm percentage increase to all non-gas facilities IN THIS SPACE charges and distribution system rates to all tariff rate classes. Attachment JNG-5 Page 6of14 Advice Letter No. W530 s/Jennifer Ries 1.. ue Date: Doeemhe• lllJune 26, 2017$ Decision or Authority No. !ill...!!l!1 Title: Vice·P1·esident Effective Date: July 27.Janum:y-t-, 20176 Rates & Regulatm·y Affaii's Attachment JNG-5 Page 7of14 ATMOS ENERGY CORPORATION Colo. P.U.C. No. 7 Gas 1555 Blake St., Suite 400 FifthSixth Revised Sheet No. 17 Denver, Colorado 80202 Cancels Fau.rtk Fifth Revised Sheet No. 17 NATURAL GAS RATES (General Service Classification) IRRIGATION SERVICE (Rate Title or Number) AVAILABILITY Available in entire service area of the Company within the state of Colorado. The Company reserves the right to render service only where it has adequate distribution capacity. APPLICABILITY Applicable to any individually metered customer using gas engine driven RATE pumps for irrigating land. Gas service under this schedule is not available for resale or for standby service. MONTHLY RATElll N Facilities Charge $ I Distribution System Rate, per CCF @ 14.65 PSIA 444849.02 I $0 .-lfil-7611 183 GAS COST ADJUSTMENT This rate schedule is subject to Gas Cost Adjustments stated in the Gas Cost Adjustment & Rate Component Summary Schedule. OTHER RIDERS This rate schedule may from time to time be subject to rider(s) as permitted by the Public Utilities Commission. RULES AND REGULATIONS Service supplied under this schedule is subject to the terms and conditions set forth in the Company's Rules and Regulations on file with the Public Utilities Commission and the following special conditions: I. The inte1Tuption of gas deliveries in whole or in part under this schedule shall not be the basis for claims for damages sustained by customers. 2. Customers may be required to install an adequate pulsation chamber ahead of the gas engine. 3. For service to gas engine driven irrigation pumps the point of delive1y and location of the meter shall be determined by the Company. Except in unusual situations, such point and meter locations shall be at the line nearest the Company's source of natural gas. All piping beyond point of delivery shall be installed, owned, and maintained by cust~o_m_e_r.______~------< 4. The Company reserves the right to limit or curtail the DO NOT WRITE quantity of gas supplied hereunder depending upon the IN THIS SPACE supply and facilities available to render services. illSee Sheet No. 19 for applicable General Rate Schedule Adjustment Rider applying unifotm percentage increase to all non-gas facilities charges and distribution system rates to all tariff rate classes. Attachment JNG-5 Page 8of14 Advice Letter No. SY530 s/Jennifer Ries Issue Date: Qeeemller l6 ,June 26, 2017!'; Decision 01· Authm·ity No. Cl§ 1187 Title: Vice-President Effective Date: January 1July27, 2017{> Rates & Regulatory Affairs Attachment JNG-5 Page 9of14 ATMOS ENERGY CORPORATION Colo. P.U.C. No. 7 Gas 1555 Blake St., Suite 400 Feu-FfuFifth Revised Sheet No. 19 Denver, Colorado 80202 Cancels :fh.WEIFourth -Revised Sheet No. 19 NATURAL GAS RATES (General Service Classification) GENERAL RATE SCHEDULE ADJUSTMENT RIDER APPLICABILITY The General Rate Schedule Adjustment ("GRSA") Rider applies to charges for gas service calculated as a percentage of base revenues. The GRSA, as approved in Proceeding No. 15AL-0299G, will be applied evenly to all tariff rate classes and shall be implemented as the percentage(s) listed below commencing on the effective date of this tariff. Facilities Charge: 6.l-+8.52% l Volumetric Charge: 6.l-+8.52% l The GRSA is in addition to each class' existing base rates resulting in the following increases: Facilities GRSA Volumetric GRSA Residential $Q-..6&0.99 $0.011050.01609 l Commercial $-1-.662.41 $0.006520.00950 l lll'igation $~3.85 $0.000030.00878 l Transportation $4»07.22 $0.005370.00781 l RA TE CASE EXPENSE The ORSA includes Rate Case Expenses of ~1.19%. The Rate Case Expense percentage will be Q recovered over a tweone-year period. At the end of the period, Atmos Energy will malce a compliance filing removing the Rate Case Expense percentage from the ORSA. REFUND/RECOVERY If the ORSA billed rate case expense amounts exceed or fail to recover the total approved amount from I Proceeding No. 1 SAL 0299G 17AL- G-within the tweone year period, Atmos Energy will refund or collect amounts +/- $5,000 difference from the amount approved by adding/subtracting the amount to/from the GRSA base revenue percentage. DO NOT WRITE INTIDSSPACE Advice Letter No. Y.J530 s/Jennifer Ries Issue Date: Deeemher HiJune 26, 2011§ Decision or Authority No. Cl§ 1187 Title: Vice-President Effective Date: Jnnu1U'Y !July 27, 2011' Rates & Regulatory Affairs Attachment JNG-5 Page 10of14 ATMOS ENERGY CORPORATION Colo. P.U.C. No. 7 Gas 1555 Blake St., Suite 400 EighthNinth Revised Sheet No. 23 Denver, Colorado 80202 Cancels Se-.·enthEigltth Revised Sheet No. 23 GAS TRANSPORTATION RATES (General Service Classification) FIRM TRANSPORTATION SERVICE COMPANY (Rate Title or Number) RATE CODE AVAILABILITY Transportation service is available to all Small Commercial, Commercial, and Irrigation Customers within the Company's service territory where unsubscribed firm gas supply capacity exists. APPLICABILITY RATE Applicable to Company's End Users that have purchased supplies of natural gas by separate agreement (transport gas) and that have requested Company to utilize its system to transport such gas to End User's place of utilization. Service provided hereunder shall be in accordance with a Transportation Service Agreement of not less than one Year in duration between Company and End User. The Company's sole obligation here1mder is to redeliver Equivalent Volumes of End User's gas from the Receipt Point to the Delivery Point. Transportation service hereunder will be subject to the terms and conditions herein set forth and to the availability of adequate capacity on Company's system to perform such service without detriment to its other customers. MONTHLY RATESl 1l N Facility Charge I Transportation gas cost adjustment chargelll Note 1 Transportation charge, All gas transported per CCF: All Divisions Minimum Rate, per CCF@ BPB $0.00500 All Divisions Maximum Rate, per CCF @ 14.65 PSIA $0.~09953 I [IJ See Sheet No. 19 for applicable General Rate Schedule Adjustment Rider applying uniform percentage increase to all non-gas facilities charges and distribution system rates to all tariff rate classes. [iJ Applicable to End Users in all service areas with no EFM device installed. DONOTWRITE IN THIS SPACE Advice L"tte1· Nn. ~SlO s/Jennifer Ries IssueDate: ~Jnne26.2017a Decision or Autliol'ity No.~ Title: Vke·P•·esident Effective Date: if!m!ttry-fJuly 17. 20I7li Rates & Regulatory Affairs Attachment JNG-5 Page 11 of 14 ATMOS ENERGY CORPORATION Colo. P.U.C. No. 7 Gas 1555 Blake St., Suite 400 FauFth Fifth Revised Sheet No. 27 Denver, Colondo 80202 Cancels :i::IHFdFourth Revised Sheet No. 27 NATURAL GAS RATES SYSTEM SAFETY AND INTEGRITY RIDER 1. APPLICABILITY. Rate Schedules for natural gas service are subject to a System Safety Integrity Rider I ("SSIR") designed to collect Eligible System Safety and Integtity Costs, as defined herein. The SSIR rates }}':W.W be subject to annual changes to be effective on January I of each year. The SSIR will be implemented For aR iRitial three year term beginning January 1, 2016 and ending December 31, 20+823 and recover capital i!nvestments made between September 1, 2015 and December 31, 2023+&. The SSIRrates to be applied to each Rate Schedule are as set forth on Sheet Nos. 9 and 11 (exclude special contracts and other revenue). 2. ANNUAL FILINGS. Each proposed revision in the SSIR rates will be accomplished by filing an advice I ll,etter on November 1 of each year to take effect on the following January l, except for the initial filing. On November 2, 2015, the company will make as advice letter filing to be effective January 1, 2016 with the first SSIR Cost Recovery Request. On February 1, 2016, the Company will submit the SSIR 5 Year Forecast and Company's confidential DIM Plan. The Company will include in its annual SSIR filings all pertinent infmmation and supporting data, including a 5 Year Forecast gGocument, related to Eligible System Safety and Integrity Costs, including but not limited to, SSIR prioritization results, project name, project scope, project prioritization score, estimated construction start and completion dates, project cost estimate, discussion of risk modifiers, diagram of proposed replacement project, change of right-of-way, change of capacity, and status update. On or before Pebmary I March 15 of each year the Company will file a true-up report with the Commission that will match final costs with revenues collected. No later than April 3QMarch 15 of each year beginning in 2017 and ending in 2024-1-9 unless otherwise ordered by the Commission, the Company will file the SSIR Cost Prudency Review describing the Projects completed in the prior year and their associated costs. 3. DEFINITIONS. 3 .1 "Deferred SSIR Balance" shall be equal to the balance, positive or negative, of SSIR revenues at the end of the 12-month period for the year prior to the annual SSIR filing less the Eligible System Safety and Integrity Costs as projected by the Company for that 12-month period. 3.2 "Eligible System Safety and Integrity Costs" shall mean (1) a return, at a percentage equal to the Company's weighted average cost of capital grossed up for taxes, approved in Proceeding No. l 5AL-0299G on the projected increase in the average 12 month-ending net plant in-service balances associated with the projects for the following 12-month period in which the SSIR rates will be in effect, exclusive of all plant in-service included in the determination of the revenue requirements approved in the Company's last general rate case; (2) the plant related ownership costs associated with such incremental plant investment, including depreciation, accwnulated deferred income taxes (if the Company has no regulated net operation loss), and all taxes including income taxes and property taxes; and (3) no operations and maintenance expenses shall be included as an SSIR Eligible Cost DO NOT WRITE IN THIS SPACE Advice Letter No. 53021 f,111euded s/Jermifer Ries Issue Date: DeeemheF 4, :JillSJm1e 26. 2017 Attachment JNG-5 Page 12of14 Decision or Authority No. Cla 1187 Title: Vice-J>resident Effective Date: J111111ary l, 21H6 July rz.2011 Rates & Regnlatory Affairs Attachment JNG-5 Page 13of14 ATMOS ENERGY CORPORATION Colo. P.U.C. No. 7 Gas lSSS Blake St., Suite 400 ¥f.pff-Second Revised Sheet No. RS Denver, Colorndo 80202 Cancels 01·igiualFil'st Revised Sheet No. RS Rules, Re~ulations or Extension Policy RULES AND REGULATIONS NATURAL GAS SERVICE GENERAL DEPOSITS When an application for residential, small commercial or commercial service is made, the Company will apply :J: non-discriminatory criteria with respect to the decision to require a deposit. If the Applicant for residential service has not previously received service from the Company, a deposit wilHlet I may be required if a RiskView query indicates that the Applicant has a risk analysis score ofunder 600 or if the risk analysis score from a different Company selected third-party credit score vendor is less than 5001Hghef. Ifthe Applicant has previously received se1vice from the Company, a new or additional deposit will be required only if the Applicant's previous payment history includes recent or substantial delinquencies. In cases where the Applicant for new service is in default on payment of bills for any service previously rendered to Applicant by the Company, a settlement of the prior account or an arrangement satisfactory to the Company related to the settlement will be required before the new service is rendered. Settlement of the prior account will not exempt the Applicant from the need to make a deposit with respect to the current application for service. A deposit will not be required if an Applicant provides written documentation of a 12 consecutive month good credit history from a utility for which the Applicant received a similar service with the 12 consecutive month period ending no earlier than 60 days prior to the date of the application for service. A deposit for service shall not exceed an amount equal to an estimated 90 days bill of the Customer. A deposit is not an advance payment or part payment of any bill for service but is security for payment of bills for service, to be applied against unpaid bills only in the event service is discontinued. A Customer's deposit for residential seivice will be credited to the Customer's account for the deposit amount plus any interest accrued thereon when bills are paid timely for a consecutive 12 month period. A Customer's deposit for small :J: commercial and commercial seivice will be credited to the Customer's account for the amount of the deposit :J: plus any interest accrued when bills are paid timely for a consecutive 36 month period. Upon discontinuance of service, the Company will apply the Customer's deposit and any interest accrued thereon against unpaid bills for service and the remaining balance of the deposit, if any, will be refunded. Interest on deposits shall be paid at a rate of not less than that shown on Tariff Sheet R5A and shall be calculated for the period elapsed from the DO NOT WRITE date of deposit to date refunded or the date the deposit is credited to the IN THIS SPACE Customer's account. Interest will be credited to the Customer's account annually Ol' upon request of the Customer. Advice Letter No. 483-530 s/Kerefl WilkesJennifer Ries Issue Date: A1:1g1:1st 5, 2Ql1June 26, 2017 Decision or Authority No. Title: Vice-President Rates & Effective Date: Septe1Hher S, 4CCR 723 4 4494 Regulatory tuut Puhlie Affairs ~July 27, 2017 Attachment JNG-5 Page 14of14 ATMOS ENERGY CORPORATION Colo. P.U.C. No. 7 Gas 1555 Blake St., Suite 400 01·iginal First Revised Sheet No. R29 Denve1·, Colorado 80202 Cancels Original Sheet No. R29 NATURAL GAS RATES (General Service Classification) OPTIONAL EXCESS FLOW VALVE ("EFV") SERVICE Customers of nevt' and l"e]'llaced residence service lines will he notified in ·.vriting of the I availaaility may request the installation of EFV valves which meet~ DOT-prescribed performance standards (Title 49 CFR Part 192.383), and related safety benefits and costs. While the Company will install the EFV at the customer's request, it is the responsibility of the customer to pay all costs associated with the installation. These costs will include fully loaded labor, equipment and material costs for the installation and removal or repair of asphalt, concrete. sod, landscaping and .Qiping,.Further, the theR c1:trreat customer is responsible for the costs associated with ]'lOteHtial re]'lair, l"esetting, replacemeHt, aael eleaetivation. These costs v:Hl be eased on the actual eost of that repair, resetting, replacemeHt, aael eleactivation. E1dsting resielential gas customers •.vho reqHest an EPV he installed on their existing line will be charged the actual cost for installation:. Typisally, the fully loadeel labor, equipffient, and material sosts fer the removal a0d repair of asphalt, so0crete, sod, laaelscaping, and pi]'lieg ·.vill be paid hy the cHstoraer ia addition to the installatiefl charge listed oa this tariff. Customers who want an EFV removed from their service line will be charged the actual cost to remove the EFV. Again, the fully loaded labor, equipment and material costs for the removal and repair of asphalt, concrete, sod, landscaping and piping will be paid by the customer. Isstallation charge: ·New Se1vice $150.00 ReplasemeHt Ser,rice Astual Gest as Eletermineel by Atffies En:ergy Cerperation End User Any person or entity that has completed a Request for Transportation Service, has executed a Transportation Service Agreement, and is receiving service under the transpo1iation rate schedule. End User may also execute a Gas Transportation Agency Agreement to assign balancing, nomination, scheduling and delivery obligations under this tariff to a third party. End User is the person or entity that ultimately uses the supply of natural gas at the Delivery Point. DO NOT WRITE IN THIS SPACE Advice Letter No. 465 Third s/KareH \\lilkesJennifer Ries Issue Date: June 9-26, 2009-11 AmeHaed530 Decision or Authority No. Title: Vice-President Effective Date: July 2.$-l, 2009-17 Rates & Regulatory aAa Public Affairs Attachment JNG-6 Page 1 of9 ATMOS ENERGY CORPORATION Colo. P.U.C. No. 7 Gas 1555 Blake St., Suite 400 Thirty-Fourth Revised Sheet No. 9 Denver, Colorndo 80202 Cancels Thirty~ Third Revised Sheet No. 9 NATURAL GAS RATES Cost Adjustment & Rate Component Summary All volumet1·ic rates at $ per CCF Class/Sheet Division 1 Division 2 No. T:y~e of Charge NE NW/C SE SW Residential 15 Facilities Charge $12.59 $12.59 $12.59 $12.59 (I,I,I,T) PrPP $0.00 $0.00 $0.00 $0.00 GasDSMCA $0.10 $0.10 $0.10 $0.10 Gas Cost Adjustment (GCA): Commodity $0.33385 $0.32796 $0.32321 $0.331 IO Upstream Pipeline 0.18200 0.19745 0.09999 0.02423 Deferred Gas Cost (0.02740) (0.01860) 0.01780 (0.02480) Total GCA $0.48845 $0.50681 $0.44100 $0.33053 Distribution System Rate 0.20494 0.20494 0.20494 0.20494 (I,I,I,I) Volumetric DSMCA 0.00156 0.00156 0.00156 0.00156 Volumetric SSIR Surcharge 0.01987 0.01987 0.01987 0.01987 Total volumetric rate for class $0.71482 $0.73318 $0.66737 $0.55690 (I,I,I,I) Small Commercial & Commercial 15 Facilities Charge $30.65 $30.65 $30.65 $30.65 (l,I,I,I PrPP $0.00 $0.00 $0.00 $0.00 GasDSMCA $0.55 $0.55 $0.55 $0.55 Gas Cost Adjustment (GCA): Commodity $0.33385 $0.32796 $0.32321 $0.33110 Upstream Pipeline 0.18200 0.19745 0.09999 0.02423 Deferred Gas Cost (0.02740) (0.01860) 0.01780 (0.02480) TotalGCA $0.48845 $0.50681 $0.44100 $0.33053 Distribution System Rate 0.12095 0.12095 0.12095 0.12095 (I,I,I,I) Volumetric DSMCA 0.00215 0.00215 0.00215 0.00215 Volumetric SSIR Surcharge 0.01173 0.01173 0.01173 0.01173 Total volumetric rate for class $0.62328 $0.64164 $0.57583 $0.46536 (I,I,I,I) Irrigation Service 17 Facilities Charge $49.02 NA $49.02 NA (1,1) PIPP $0.00 $0.00 Gas Cost Adjustment (GCA): Commodity $0.33385 NA $0.32321 NA Upstream Pipeline 0.18200 0.09999 Deferred Gas Cost (0.02740) 0.01780 TotalGCA $0.48845 $0.44100 Distribution System Rate 0.11183 0.11183 (l,I) Volumetric SSIR Surcharge 0.01084 0.01084 Total volumetric rate for class $0.61112 $0.56367 (I,I) DO NOT WRITE IN TIITS SP ACE Advice Letter No. 530 s/Jennifer Ries Issue Date: June 26, 2017 Decision or Authority No. Title: Vice-President Effective Date: July 27, 2017 Rates and Regulatory Affairs Attachment JNG-6 Page 2 of9 ATMOS ENERGY CORPORATION Colo. P.U.C. No. 7 Gas 1555 Blake St., Suite 400 Nineteenth Revised Sheet No. 11 Denver, Colorado 80202 Cancels Eighteenth Revised Sheet No. 11 NATURAL GAS RATES Cost At(justment & Rate Component Summary All volumetric rates at $ per CCF Class/Sheet Division I Division2 ___Ng,__ Tvpe of Cha1·gc ---1:!L filY& __fil',_ ____filY_ Tr11nspo1·tation Service 23,25 Facilities Charge $91.92 $91.92 $91.92 $91.92 (I,1,1,1) Gas Cost Adjustment (GCA): Commodity NA NA NA NA Upstream Pipeline NA NA NA NA Deferred Gas Cost NA NA NA NA Transportation Gas Cost Adj. $0.00601 $0.00601 $0.00601 $0.00601 Tota!GCA $0.00601 $0.00601 $0.00601 $0.00601 Max Distribution System Rate 0.09953 0.09953 0.09953 0.09953 (1,1,I,I) Volumetric SSIR Surcharge 0.00965 0.00965 0.00965 0.00965 Total volumetl'ic rate for class $0.11519 $0.11519 $0.11519 $0.11519 (I,I,I,I) DO NOT WRITE IN TIIIS SPACE Advice Letter No. 530 s/Jennifer Ries Issue Date: June 26, 2017 Title: Vice-President Decision or Authority No. Rates and Regulatory Affairs Effective Date: July 27, 2017 Attachment JNG-6 Page 3 of9 ATMOS ENERGY CORPORATION Colo. P.U.C. No. 7 Gas 1555 Blake St., Suite 400 Eighth Revised SheetNo.15 Denver, Colorado 80202 Cancels Seventh Revised SheetNo.15 NATURAL GAS RATES (General Service Classification) GENERAL SERVICE (Rate Title or Number) AVAILABILITY Available in entire service area of the Company within the state of Colorado. APPLICABILITY Applicable to residential, small commercial and commercial service. This rate is not RATE applicable to resale or standby service. The residential monthly facilities charge is applicable to all metered individual dwelling units. The commercial monthly facilities charge is applicable to all other firm services. MONTHLY RATESl1H21 Facilities Charge: Residential $ 12.59 I Small Commercial and Commercial $ 30.65 I Distribution System Rate, per CCF (Billing Pressure Base 14.65 PSIA) Residential $0.20494 I Small Commercial and Commercial $0.120951 I GAS COST ADJUSTMENT This rate schedule is subject to Gas Cost Adjustments stated in the Cost Adjustment & Rate Component Summary Schedule. GAS DEMAND-SIDE MANAGEMENT COST ADJUSTMENT This rate schedule is subject to Gas Cost Adjustments stated in the Cost Adjustment & Rate Component Summary Schedule. OTHER RIDERS This rate schedule may from time to time be subject to rider(s) as pe1mitted by the Public Utilities Commission. RULES AND REGULATIONS Service supplied under this schedule is subject to the terms and conditions set fmth in the Company's Rules and Regulations on file with The Public Utilities Commission of the State of Colorado. [1] See Sheet No. 's 3 and 4 for applicable local pressure base and Sheet No. 14 for computation of bill inf01mation. [2] See Sheet No. 19 for applicable General Rate Schedule Adjustment DO NOT WRITE Rider applying uniform percentage increase to all non-gas facilities IN THIS SPACE charges and distribution system rates to all tariff rate classes. \ Advke Letter No. 530 s/JennifeI" Ries IssueDate: June26,2017 Decision Ol' Authority No. Title: Vice-P•·esident Effective Date: July 27, 2017 Rates & Reg•d•tory Affairs Attachment JNG-6 Page 4 of9 ATMOS ENERGY CORPORATION Colo. P.U.C. No. 7 Gas 1555 Blake St., Suite 400 Sixth Revised Sheet No. 17 Denver, Colorado 80202 Cancels Fifth Revised Sheet No. 17 NATURAL GAS RATES (General Service Classification) IRRIGATION SERVICE (Rate Title or Number) AVAILABILITY Available in entire service area of the Company within the state of Colorado. The Company reserves the right to render service only where it has adequate distribution capacity. APPLICABILITY Applicable to any individually metered customer using gas engine driven RATE pumps for irrigating land. Gas service under this schedule is not available for resale or for standby service. MONTHLY RATE[11 Facilities Charge $ 49.02 I Distribution System Rate, per CCF@ 14.65 PSIA $ 0.11183 I GAS COST ADJUSTMENT This rate schedule is subject to Gas Cost Adjustments stated in the Gas Cost Adjustment & Rate Component Summary Schedule. OTHER RIDERS This rate schedule may from time to time be subject to rider(s) as permitted by the Public Utilities Commission. RULES AND REGULATIONS Service supplied under this schedule is subject to the terms and conditions set forth in the Company's Rules and Regulations on file with the Public Utilities Commission and the following special conditions: ; 1. The interruption of gas deliveries in whole or in part under this schedule shall not be the basis for claims for damages sustained by customers. 2. Customers may be required to install an adequate pulsation chamber ahead of the gas engine. 3. For service to gas engine driven hTigation pumps the point of delivery and location of the meter shall be determined by the Company. Except in unusual situations, such point and meter locations shall be at the line nearest the Company's source of natural gas. All piping beyond poh1t of delivery shall be installed, owned, and maintained by customer. ..--~~~~~~~~~~~~~~-j 4. The Company reserves the right to limit or cmiail the DO NOT WRITE quantity of gas supplied hereunder depending upon the IN THIS SPACE supply and facilities available to render services. lllsee Sheet No. 19 for applicable General Rate Schedule Adjustment Rider applying uniform percentage increase to all non-gas facilities charges and distribution system rates to all tariff rate classes. Advice Lette1· No. 530 s/Jennife1· Ries Issue Date: June 26, 2017 Decision or Authmi!y No. Title: Vice-President Effective Date: July 27, 2017 Rates & Regulatory Affairs Attachment JNG-6 Page 5 of9 ATMOS ENERGY CORPORATION Colo. P.U.C. No. 7 Gas 1555 Blake St., Suite 400 Fifth Revised Sheet No.19 Denver, Colorado 80202 Cancels Fourth Revised SheetNo.19 NATURAL GAS RATES (General Service Classification) GENERAL RATE SCHEDULE ADJUSTMENT RIDER APPLICABILITY The General Rate Schedule Adjustment ("GRSA") Rider applies to charges for gas service calculated as a percentage of base revenues. The GRSA, as approved in Proceeding No. l 5AL-0299G, will be applied evenly to all tariff rate classes and shall be implemented as the percentage(s) listed below commencing on the effective date of this tariff. I Facilities Charge: 8.52% I Volumetric Charge: 8.52% The GRSA is in addition to each class' existing base rates resulting in the following increases: Facilities GRSA Volumetric GRSA Residential $0.99 $0.01609 I Commercial $2.41 $0.00950 I Irrigation $3.85 $0.00878 I Transportation $7.22 $0.00781 I RATE CASE EXPENSE The GRSA includes Rate Case Expenses of 1.19%. The Rate Case Expense percentage will be C recovered over a one-year period. At the end of the period, Atmos Energy will malce a compliance filing removing the Rate Case Expense percentage :from the GRSA. REFUND/RECOVERY If the GRSA billed rate case expense amounts exceed or fail to recover the total approved amount from T Proceeding No. 17 AL--~Gwithin the one year period, Atmos Energy will refund or collect amounts +/ $5,000 difference from the amount approved by adding/subtracting the amount to/from the GRSA base revenue percentage. DO NOT WRITE IN THIS SPACE Advice Letter No. 530 s/Jennifer Ries Issue Date: Jun~ 26, 2017 Decision or Authority No. Title: Vice-President Effective Date: July 27, 2017 Rates & Regulatory Affairs Attachment JNG-6 Page 6 of9 ATMOS ENERGY CORPORATION Colo. P.U.C. No. 7 Gas 1555 Blake St., Suite 400 Ninth Revised Sheet No. 23 Denver, Colorado 80202 Cancels Eighth Revised Sheet No. 23 GAS TRANSPORTATION RATES (General Service Classification) FIRM TRANSPORTATION SERVICE COMPANY (Rate Title or Number) RATE CODE AVAILABILITY Transportation service is available to all Small Commercial, Commercial, and Irrigation Customers within the Company's service ten-itory where unsubscribed firm gas supply capacity exists. APPLICABILITY RATE Applicable to Company's End Users that have purchased supplies of natural gas by separate agreement (transport gas) and that have requested Company to utilize its system to transport such gas to End User's place of utilization. Service provided hereunder shall be in accordance with a Transportation Service Agreement of not less than one Year in duration between Company and End User. The Company's sole obligation hereunder is to redeliver Equivalent Volumes ofEnd User's gas from the Receipt Point to the Delivery Point. Transportation service hereunder wiJl be subject to the terms and conditions herein set forth and to the availability of adequate capacity on Company's system to perform such service without detriment to its other customers. MONTHLY RATESl1l Facility Charge $91.92 I Transportation gas cost adjustment chargelll Note 1 Transportation charge, All gas transported per CCF: All Divisions Minimum Rate, per CCF @ BPB $0.00500 All Divisions Maximum Rate, per CCF @ 14.65 PSIA $0.09953 I [lJ See Sheet No. 19 for applicable General Rate Schedule Adjustment Rider applying uniform percentage increase to all non-gas facilities charges and distribution system rates to all tariff rate classes. l•l Applicable to End Users in all service areas with no EFM device installed. UONOTWRlTE IN THIS SPACE Advice Lette1· No. 530 s/Jennifer Ries Issue Date: June 26, 2017 Decision ot' Authol'ity No. Title: Vice-P1·csidcnt Effective Date: July 27, 2017 Rates & Regulatory Affairs Attachment JNG-6 Page 7 of9 ATMOS ENERGY CORPORATION Colo. P.U.C. No. 7 Gas 1555 Blake St., Suite 400 Fifth Revised Sheet No. 2 7 Denver, Colorado 80202 Cancels Fourth Revised Sheet No. 27 NATURAL GAS RATES SYSTEM SAFETY AND INTEGRITY RIDER 1. APPLICABIUTY. Rate Schedules for natural gas service are subject to a System Safety Integrity Rider T ("SSIR") designed to collect Eligible System Safety and Integrity Costs, as defined herein. The SSIR rates will be subject to annual changes to be effective on January 1 of each year. The SSIR will be implemented begim1ing January 1, 2016 and ending December 31, 2023 and recover capital investments made between September l, 2015 and December 31, 2023. The SSIR rates to be applied to each Rate Schedule are as set forth on Sheet Nos. 9 and 11 (exclude special contracts and other revenue). 2. ANNUAL FILINGS. Each proposed revision in the SSIR rates will be accomplished by filing an advice letter on November 1 of each year to take effect on the following January I, except for the initial filing. On T November 2, 2015, the company will malce as advice letter filing to be effective January 1, 20 J 6 with the first SSIR Cost Recovery Request. On February 1, 2016, the Company will submit the SSIR 5 Year Forecast and Company's confidential DIM Plan. The Company will include in its annual SSJR filings all pertinent inf01mation and supp01ting data, including a 5 Year Forecast document, related to Eligible System Safety and Integrity Costs, including but not limited to, SSIR prioritization results, project name, project scope, project prioritization score, estimated construction start and completion dates, project cost estimate, discussion of risk modifiers, diagram of proposed replacement project, change of right-of-way, change of capacity, and status update. On or before March l 5 of each year the Company will file a true-up report with the Commission that will match final costs with revenues collected. No later than March 15 of each year beginning in 2017 and ending in 2024 unless otherwise ordered by the Commission, the Company will file the SSIR Cost Prudency Review describing the Projects completed in the prior year and their associated costs. 3. DEFINITIONS. 3 .1 "Deferred SSIR Balance" shall be equal to the balance, positive or negative, of SSIR revenues at the end of the 12-month period for the year prior to the annual SSIR filing less the Eligible System Safety and Integrity Costs as projected by the Company for that 12-month period. 3.2 "Eligible System Safety and Integrity Costs" shall mean (1) a return, at a percentage equal to the Company's weighted average cost of capital grossed up for taxes, approved in Proceeding No. l 5AL-0299G on the projected increase in the average 12 month-ending net plant in-service balances associated with the projects for the following 12-month period in which the SSIR rates will be in effect, exclusive of all plant in-service included in the determination of the revenue requirements approved in the Company's last general rate case; (2) the plant related ownership costs associated with such incremental plant investment, including depreciation, accumulated deferred income taxes (if the Company has no regulated net operation loss), and all taxes including income taxes and property taxes; and (3) no operations and maintenance expenses shall be included as an SSIR Eligible Cost DO NOT WRITE IN THIS SPACE Advice Letter No. 530- s/Jeunifer Uies Issue Date: June 26, 2017 Decision or Authority No. Title: Vice-President Effective Date: July 27, 2017 Uates & Regulalory Affairs Attachment JNG-6 Page 8of9 ATMOS ENERGY CORPORATION Colo. P.U.C. No. 7 Gas 1555 Blake St., Suite 400 Second Revised Sheet No. RS Denvei·, Coloi·ado 80202 Cancels First Revised Sheet No. RS Rules, Ree:ulations or Extension Policy RULES AND REGULATIONS NATURAL GAS SERVICE GENERAL DEPOSITS When an application for residential, small commercial or commercial service is made, the Company will apply non-discriminatory criteria with respect to the decision to require a deposit. If the Applicant for residential service has not previously received service from the Company, a deposit may be T required ifa RiskView query indicates that the Applicant has a risk analysis score of under 600 or if the risk analysis score from a different Company selected third-party credit score vendor is less than 500. If the Applicant has previously received service from the Company, a new or additional deposit will be required only if the Applicant's previous payment history includes recent or substantial delinquencies. In cases where the Applicant for new service is in default on payment of bills for any service previously rendered to Applicant by the Company, a settlement of the prior account or an arrangement satisfactory to the Company related to the settlement will be required before the new service is rendered. Settlement of the prior account will not exempt the Applicant from the need to make a deposit with respect to the current application for service. A deposit will not be required if an Applicant provides written documentation of a 12 consecutive month good credit history from a utility for which the Applicant received a similar service with the 12 consecutive month period ending no earlier than 60 days prior to the date of the application for service. A deposit for service shall not exceed an aniount equal to an estimated 90 days bill of the Customer. A deposit is not an advance payment or part payment of any bill for service but is security for payment of bills for service, to be applied against unpaid bills only in the event service is discontinued. A Customer's deposit for residential service will be credited to the Customer's account for the deposit amount plus any interest accrued thereon when bills are paid timely for aconsecutive 12 month period. A Customer's deposit for small commercial and commercial se1vice wil I be credited to the Customer's account for the amount of the deposit plus any interest accrued when bills are.paid timely for a consecutive 36 month period. Upon discontinuance of service, the Company will apply the Customer's deposit and any interest accrued thereon against unpaid bills for service and the remaining balance of the deposit, if any, will be refunded. Interest on deposits shall be paid at a rate of not less than that shown on Tariff Sheet RSA and shall be calculated for the period elapsed from the DO NOT WRITE date of deposit to date refunded or the date the deposit is credited to the IN THIS SPACE Customer's account. Interest will be credited to the Customer's account annually or upon request of the Customer. Advice Letter No. 530 s/Jennifer Ries Issue Date: June 26, 2017 Decision or Authority No. Title: Vice-President Rates & Effective Date: July 27, 2017 Regulatory Affairs Attachment JNG-6 Page 9 of9 ATMOS ENERGY CORPORATION Colo. P.U.C. No. 7 Gas 1555 Blake St., Suite 400 First Revised Sheet No. R29 Denver, Colorado 80202 Cancels Original Sheet No. R29 NATURAL GAS RATES (General Service Classification) OPTIONAL EXCESS FLOW VALVE ("EFV") SERVICE Customers may request the installation of EFV valves which meet the DOT-prescribed T performance standards (Title 49 CFR Part 192.383), and related safety benefits and costs. While the Company will install the EFV at the customer's request, it is the responsibility of the customer to pay all costs associated with the installation. These costs will include fully loaded labor, equipment and material costs for the installation and removal or repair of asphalt, concrete, sod, landscaping and piping. Customers who want an EFV removed from their service line will be charged the actual cost to remove the EFV. Again, the fully loaded labor, equipment and material costs for the removal and repair of asphalt, concrete, sod, landscaping and piping will be paid by the customer. End User Any person or entity that has completed a Request for Transportation Service, has executed a Transpmtation Service Agreement, and is receiving service under the transpo1tation rate schedule. End User may also execute a Gas Transportation Agency Agreement to assign balancing, nomination, scheduling and delivery obligations under this tariff to a third party. End User is the person or entity that ultimately uses the supply of natural gas at the Delivery Point. DONOTWRITE INTillSSPACE Advice Letter No. 530 s/Jennifer Ries Issue Date: June 26, 2017 Decision or Authority No. Title: Vice-President Effective Date: July 27, 2017 Rates & Regulatory Affairs BEFORE THE PUBLIC UTILITIES COMMISSION OF THE STATE OF COLORADO IN THE MATTER OF ADVICE LETTER ) NO. 530, FILED BY ATMOS ENERGY ) CORPORATION TO PLACE INTO ) Proceeding No. 17AL~_G EFFECT TARIFF SHEET CHANGES TO ) BE EFFECTIVE ON JULY 27, 2017 ) DIRECT TESTIMONY AND ATTACHMENTS OF ROBERT B. HEVERT June 26, 2017 SUBMITTED ON BEHALF OF ATMOS ENERGY CORPORATION TABLE OF CONTENTS I. .EXECUTIV.E SU.MMARY ...... 1 II. INTRODUCTION, PURPOSE OF TESTIMONY, AND RECOMMENDATIONS ...... 2 III. SUMMARY OF CONCLUSIONS ...... 5 IV. REGULATORY GUIDELINES AND FINANCIAL CONSlDERATIONS ...... 7 ·v.. PROXY G.ROUP S.ELECTION ...... 7 VI. COST OF EQUITY ESTIMATION ...... 11 VII. BUSINESS RISKS AND OTHER CONSIDERATIONS ...... 34 VIII. CAPITAL MARKET ENVIRONMENT ...... 39 IX. CONCLUSIONS AND RECOMMENDATION ...... 53 ATTACHMENTS: Attachment RBH-1 - Curriculum Vitae Attachment RBH-2 - Constant Growth DCF Results Attachment RBH-3 - Retention Growth Rate Attachment RBH-4 - Multi-Stage DCF Results Attachment RBH-5 - Market Risk Premium Calculations Attachment RBH-6 -Beta Coefficients Attachment RBH-7 - CAPM Results Attachment RBH-8 - Bond Yield Risk Pl'ernium Analysis Attachment RBH-9 - Small Size Analysis Attachment RBH-10 - Flotation Costs i. GLOSSARY OF ACRONYMS AND DEFINED TERMS Acronym/Defined Term Meaning Bluefield Bluefield Water Works and Improvement Co. v. Public Service Comm 'n, 262 U.S. 679 (1923) CAPM Capital Asset Pricing Model Commission; PUC Colorado Public Utilities Commission Company Atmos Energy Corporation DCF Discounted Cash Flow EPS Earnings Per Share FOMC Federal Reserve's Open Market Committee GDP Gross Domestic Product Hope Federal Power Comm 'n v. Hope Natural Gas Co., 320 U.S. 591 (1944) M/B Market/Book MRP Market Risk Premium P/E Price to Earnings Ratio PEG Price to Earnings Growth Ratio ROE Return on Equity TIPS Treasury Inflation Protected Securities ii. Q. PLEASE STATE YOUR NAME, AFFILIATION AND BUSINESS 2 ADDRESS. 3 A. My name is Robert B. Hevert. I am a Partner of ScottMadden, Inc. ("ScottMadden"). 4 My business address is 1900 West Park Drive, Suite 250, Westborough, MA 01581. 5 I. EXECUTIVE SUMMARY 6 As a Partner at ScottMadden, I advise energy and utility clients on a wide 7 range of financial and economic issues, including corporate and asset-based 8 transactions, asset and enterprise valuation, transaction due diligence, and strategic 9 matters, and provide expert testimony in regulatory proceedings on topics, such as 10 return on equity. 11 In my direct testimony, l present supporting evidence and provide the Colorado 12 Public Utilities C~mmission ("Commission") with a recommendation regarding 13 Atmos Energy Corporation's ("Atmos Energy" or the "Company") requested return 14 on equity ("ROE") for its natural gas utility operations in Colorado, and provide an 15 assessment of the reasonableness of the capital structure to be used for ratemaking 16 purposes. In order to develop my ROE recommendation, I applied the Constant 17 Growth Discounted Cash Flow ("DCF") model, the Multi-Stage DCF Model, the 18 Capital Asset Pricing Model ("CAPM"), and the Bond Yield Plus Risk Premium 19 approach using a proxy group consisting of local distribution companies ("LDCs") 20 and combination electdc and gas utilities. Based on the model results applied to 21 the proxy group, I find that the Company's cost of equity currently is in the range 22 of 10.00 percent to 10.75 percent. I conclude that a ROE of 10.50 percent is 23 reasonable and appropriate for Atmos Energy's Colorado natural gas operations. Direct Testimony of Robert B. Revert Pagel Colorado I Revert Direct Testimony 1 II. INTRODUCTION, PURPOSE OF TESTIMONY, AND 2 RECOMMENDATIONS 3 Q. ON WHOSE BEHALF ARE YOU SUBMITTING TIDS TESTIMONY? 4 A. I am submitting this testimony on behalf of Atmos Energy. 5 Q. PLEASE DESCRIBE YOUR EDUCATIONAL BACKGROUND. 6 A. I hold a Bachelor's degree in Business and Economics from the University of 7 Delaware, and an MBA with a concentration in Finance from the University of 8 Massachusetts. I also hold the Chartered Financial Analyst designation. 9 Q. PLEASE DESCRIBE YOUR EXPERIENCE IN THE ENERGY AND 10 UTILITY INDUSTRIES. 11 A. I have worked in regulated industries for over 25 years, having served as an 12 executive and manager with consulting firms, a financial officer of a publicly traded 13 natural gas utility (at the time, Bay State Gas Company), and an analyst at a 14 telecommunications utility. As a consultant, I have advised numerous energy and 15 utility clients on a wide range of financial and economic issues, including corporate 16 and asset-based transactions, asset and enterprise valuation, transaction due 17 diligence, and strategic matters. I have provided expert witness testimony in over 18 15 0 proceedings regarding various financial and regulatory matters before 19 numerous state utility regulatory agencies, the Federal Energy Regulatory 20 Commission, and the Province of Alberta, Canada. A summary of my professional 21 and educational background, including a list of my testimony in prior proceedings, 22 is provided as Attachment RBH-1. 23 Q. WHAT IS THE PURPOSE OF YOUR TESTIMONY? 24 A. The purpose of my testimony is to present evidence and provide a recommendation Direct Testimony of Robert B. Revert Page2 Colorado I Revert Direct Testimony regarding the Company's cost of equity (sometimes referred to as the "return on 2 equity" or "ROE") and to provide an assessment of the capital structure and cost of 3 debt to be used for ratemaking purposes. 4 Q. ARE YOU SPONSORING ANY OTHER ATTACHMENTS AS PART OF 5 YOUR TESTIMONY? 6 A. Yes. My analyses and conclusions are supported by the data presented in 7 Attachment RBH-2 through Attachment RBH-10, which have been prepared by me 8 or under my direction. 9 Q. WHAT ARE YOUR CONCLUSIONS REGARDING THE APPROPRIATE 10 COST OF EQUITY FOR THE COMPANY? 11 A. My analyses indicate that the Company's cost of equity currently is in the range of 12 10.00 percent to 10.75 percent. Based on the quantitative and qualitative analyses 13 discussed throughout my testimony, I conclude that an ROE of 10.50 percent is 14 reasonable and appropriate. 15 Q. PLEASE PROVIDE A BRIEF OVERVIEW OF THE ANALYSES THAT 16 LEAD TO YOUR ROE RECOMMENDATION. 17 A. I begin with the principle that in estimating the cost of equity, it is important to 18 apply the methods used, and to reflect the factors considered by, investors. Because 19 investors tend to use multiple methods in developing their return requirements, I 20 considered several analytical approaches to determine the Company's ROE, 21 including the Constant Growth and Multi-Stage forms of the DCF model, the 22 CAPM; and the Bond Yield Plus Risk Premium approach. 23 My recommendations and conclusions consider the risks associated with the Direct Testimony ofRobe1t B. Revert Page3 Colorado I Revert Direct Testimony Company's small relative size as compared to the proxy group and :flotation costs 2 associated with equity issuances. Although I did not make explicit adjustments to 3 my ROE estimates for these factors, I did take them into consideration in 4 determining the range in which the Company's cost of equity likely falls. 5 Q. HOW IS THE REMAINDER OF YOUR TESTIMONY ORGANIZED? 6 A. The remainder of my testimony is organized as follows: 7 • Section III - Provides a summary of my conclusions and recommendations; 8 • Section IV - Discusses the regulatory guidelines and financial 9 considerations pertinent to the development of the cost of capital; 10 • Section V - Explains my selection of the proxy group used to develop my 11 analytical results; 12 • Section VI - Explains my analyses and the analytical bases for my ROE 13 recommendation; 14 • Section VII - Provides a discussion of specific business risks that have a 15 direct bearing on the Company's cost of equity; 16 • Section VJU - Highlights the current capital market conditions and their 17 effect on the Company's cost of equity; and 18 • Section IX - Summarizes my conclusions and recommendations. Direct Testimony of Robert B. Revert Page4 Colorado I Revert Direct Testimony 1 III. SUMMARY OF CONCLUSIONS 2 Q. WHAT ARE THE KEY FACTORS CONSIDERED IN YOUR ANALYSES 3 AND UPON WHICH YOU BASE YOUR RECOMMENDED ROE? 4 A. My analyses and recommendations considered the following: 5 • The Hope and Bluefield decisions 1 which established the standards for 6 determining a fair and reasonable allowed ROE including: consistency of the 7 allowed return with other businesses having similar risk; adequacy of the return 8 to provide access to capital and support credit quality; and the end result must 9 lead to just and reasonable rates. 10 • The Company's business risks relative to the proxy group of comparable 11 companies and the implications of those risks in arriving at the appropriate 12 ROE. 13 • The effect of the current capital market conditions on investors' return 14 requirements. 15 Q. WHAT ARE THE RESULTS OF YOUR ANALYSES? 16 A. The results of my analyses are summarized in Table RBH-1. Bluefield Waterworks & Improvement Co. v. Public Service Comm 'n of West Virginia, 262 U.S. 679 (1923)("Bluefield''); Federal Power Comm 'n v. Hope Natural Gas Co., 320 U.S. 591 (1944} ("Hope"). Direct Testimony of Robert B. Revert Pages Colorado I Revert Direct Testimony 1 T a bl e RBH- 1 : S ummarvofA na1vt1ca I ' IResu ts Discounted Cash Flow Mean Low Mean Mean High Constant Growth DCF 30-Day Constant Growth DCF 7.36% 9.23% 11.66% 90-Day Constant Growth DCF 7.47% 9.33% 11.77% 180-Day Constant Growth DCF 7.59% 9.45% 11.89% Multi-Stage DCF (Gordon Method) 30-Day Multi-Stage DCF 8.19% 8.61% 9.23% 90-Day Multi-Stage DCF 8.30% 8.73% 9.37% 180-Day Multi-Stage DCF 8.41% 8.85% 9.52% Multi-Stage DCF (I'erminal PIE) 30-Day Multi-Stage DCF 7.92% 9.11% 10.67% 90-Day Multi-Stage DCF 8.23% 9.43% 10.99% 180-Day Multi-Stage DCF 8.55% 9.76% 11.33% Bloomberg Value Line Derived Derived Market Risi' Market Risk CAPM Results Premium Premium Average Bloomberg Beta Coefficient Current 30-Year Treasury (2.97%) 9.53% 9.99% Near Term Projected 30-Year Treasury (3.43%) 9.99% 10.45% Average Value Line Beta Coefficient Current 30-Year Treasury (2.97%) 10.83% 11.38% Near Term Projected 30-Year Treasury (3.43%) 11.29% 11.84% Low Mid High Bond Yield Risk Premium 9.93% 9.99% 10.24% Flotation Costs 0.04% 2 Based on the analytical results presented in Table RBH-1, and in light of 3 the considerations discussed throughout the balance of my testimony regarding the 4 Company's business and regulatory risks relative to the proxy group, it is my view 5 that an ROE of 10.50 percent is reasonable and appropriate. Direct Testimony of Robert B. Revert Page6 Colorado I Revert Direct Testimony IV. REGULATORY GUIDELINES AND FINANCIAL CONSIDERATIONS 2 Q. PLEASE PROVIDE A BRIEF SUMMARY OF THE GUIDELINES 3 ESTABLISHED BY THE UNITED STATES SUPREME COURT (THE 4 "COURT") FOR THE PURPOSE OF DETERMINING A UTILITY'S ROE. 5 A. The Court established the guiding principles for establishing a fair return for capital 6 in two cases: (1) Bluefield; and (2) Hope.2 In those cases, the Court recognized that 7 the fair rate of return on equity should be (1) comparable to returns investors expect 8 to earn on other investments of similar risk, (2) sufficient to assure confidence in 9 the company's financial integrity, and (3) adequate to maintain and support the 10 company's credit and to attract capital. 11 Q. DOES COLORADO PRECEDENT PROVIDE SIMILAR GUIDANCE? 12 A. Yes. In 200 l, the Commission noted: 13 In determining the authorized ROE for Public Service in this case, 14 the Commission must consider the financial integrity concerns 15 expressed by the cost of capital witnesses. Indeed, consideration of 16 such concerns is required under Federal Power Commission v. Hope 17 Natural Gas. 3 18 V. PROXY GROUP SELECTION 19 Q. AS A PRELIMINARY MATTER, WHY IS IT NECESSARY TO SELECT A 20 GROUP OF PROXY COMPANIES TO DETERMINE THE COST OF 21 EQUITY FOR ATMOS ENERGY? 22 A. First, it is important to bear in mind that the cost of equity for a given enterprise 23 depends on the risks attendant to the business in which the company is engaged. 2 Bluefield Waterworks & Improvement Co., v. Public Service Commission o/West Virginia, 262 U.S. 679 (1923); Federal Power Commission v. Hope Natural Gas Co., 320 U.S. 591 (1944). Decision No. COl-231; Docket No. OOS-422G. Direct Testimony of Robert B. Hevert Page? Colorado I Hevert Direct Testimony 1 According to financial theory, the value of a given company is equal to the 2 aggregate market value of its constituent business units. The value of the individual 3 business units reflects the risks and opportunities inherent in the business sectors in 4 which those units operate. Because the ROE is a market-based concept, and given 5 the fact that the Company's Colorado jurisdictional operations do not make up the 6 entirety of the publicly .traded parent company, it is necessary to establish a group 7 of companies that are both publicly traded and comparable to Atmos Energy to 8 serve as its "proxy" for purposes of the ROE estimation process. 9 Even if its Colorado jurisdictional assets did constitute the entirety ofAtmos 10 Energy's combined operations, it is possible that transitory events could bias its 11 market value in one way or another over a given period of time. A significant 12 benefit of using a proxy group, therefore, is to moderate the effects of anomalous, 13 temporary events that may be associated with any one company. 14 Q. DOES THE SELECTION OF A PROXY GROUP SUGGEST THAT 15 ANALYTICAL RESULTS WILL BE TIGHTLY CLUSTERED AROUND 16 AVERAGE (LE., MEAN) RESULTS? 17 A. No. The DCF approach, for example, defines the cost of equity as the sum of the 18 expected dividend yield and projected long-te1m growth. Despite the care taken to 19 ensure risk comparability, market expectations with respect to future risks and 20 growth opportunities will vary from company to company. Therefore, even within 21 a group of similarly situated companies, it is common for analytical results to reflect 22 a seemingly wide range. At issue, then, is how to estimate the cost of equity from 23 within that range. That determination necessarily must consider a wide range of Direct Testimony of Robert B. Heve1t Page 8 Colorado I Hevert Direct Testimony both empirical and qualitative information. 2 Q. PLEASE PROVIDE A SUMMARY PROFILE OF ATMOS ENERGY. 3 A. Atmos Energy operates in eight states in the West and Midwest and is engaged 4 primal'ily in the regulated natural gas distribution and pipeline businesses. In 5 Colorado, it provides natural gas distribution service to approximately 64 6 communities. 4 7 Q. HOW DID YOU SELECT THE COMPANIES INCLUDED IN YOUR 8 PROXY GROUP? 9 A. I began with the universe of companies that Value Line classifies as Electric 10 Utilities and Natural Gas Utilities and applied the following screening criteria: 11 • Because certain of the models used in my analyses assumes that earnings 12 and dividends grow over time, I excluded companies that do not 13 consistently pay quarterly cash dividends; 14 • To ensure that the growth rates used in my analyses are not biased by a 15 single analyst, all the companies in my proxy group have been covered by 16 at least two utility industry equity analysts; 17 • All the companies in my proxy group have investment grade senior 18 unsecured bond and/or corporate credit ratings from S&P; 19 • To incorporate companies that are regulated gas distribution utilities, I only 20 included companies with at least 30.00 percent of operating income derived 21 from regulated natural gas utility operations; and 4 Atmos Energy - Colorado Tariff Sheet No. 3 and 4. Direct Testimony ofRobe1t B. Heve1t Page 9 Colorado I Hevert Direct Testimony 1 • I eliminated companies that are currently known to be party to a merger, or 2 other significant transaction. 3 Q. BASED ON THOSE CRITERIA, WHAT IS THE COMPOSITION OF 4 YOUR PROXY GROUP? 5 A. The criteria discussed above results in a proxy group of the following eight 6 companies provided in Table RBH-2 below. 7 T a ble RBH- 2 : P roxv G roup Company Ticker Black Hills Corporation BKH CenterPoint Energy, Inc. CNP Chesapeake Utilities Corporation CPK Northwest Natural Gas Company NWN Sempra Energy SRE Southwest Gas Corporation swx Spire Inc. SR Vectren Corporation vvc 8 9 Q. IS IT APPROPRIATE TO INCLUDE BOTH NATURAL GAS UTILITIES 10 AND COMBINED ELECTRIC AND NATURAL GAS UTILITIES IN THE 11 PROXY GROUP? 12 A. Yes. In selecting a proxy group, a balance must be struck between the size of the 13 proxy group, and the comparability of the proxy companies to the subject company. 14 By ensuring the proxy group members derive at least 30.00 percent of their 15 operating income from regulated natural gas utility operations, I have selected Direct Testimony of Robert B. Revert Page 10 Colorado I Hevert Direct Testimony 1 proxy companies that are reasonably comparable to Atmos Energy, without 2 unnecessarily constraining the pool of potential proxy companies. 3 Q. DO YOU BELIEVE THAT EIGHT_ COMPANIES CONSTITUTE A 4 SUFFICIENTLY LARGE PROXY GROUP FOR THE PURPOSE OF 5 DETERMINING THE COST OF EQUITY FOR A UTILITY? 6 A. Yes, I do. Because all analysts use some form of screening process to develop 7 proxy groups, those groups, by definition, are not randomly drawn from a larger 8 population. Consequently, there is no reason to place more reliance on the range 9 of results derived from a larger, but potentially less comparable proxy group simply 10 by virtue of the larger number of observations. Moreover, because I am using 11 market-based data, my analytical results will not necessarily be tightly clustered 12 around a central point. Results that may be somewhat dispersed, however, do not 13 suggest that the screening approach is inappropriate or the results less meaningful. 14 Including companies whose fundamental comparability to the subject company is 15 tenuous, simply for the purpose of expanding the number of observations, does not 16 add relevant information to the analysis. 17 VI. COST OF EQUITY ESTIMATION 18 Q. PLEASE BRIEFLY DISCUSS THE ROE IN THE CONTEXT OF THE 19 REGULATED RATE OF RETURN. 20 A. Regulated utilities primarily use common stock and long-term debt to finance their 21 capital investments. The overall rate of retum ("ROR") weighs the costs of the 22 individual sources of capital by their respective book values. Whereas the costs of 23 debt and preferred stock can be directly observed, the cost of equity cannot; rather, Direct Testimony of Robert B. Revert Page 11 Colorado I Heve1t Direct Testimony 1 it must be estimated from market-based information. 2 Q. . HOW IS THE REQUIRED ROE DETERMINED? 3 A. The ROE is estimated by applying various financial models to market-based data. 4 By their very nature, those models produce a range of results, from which the 5 market-required ROE must be determined. As discussed throughout my testimony, 6 that determination must be based on a comprehensive review of relevant data and 7 information, and does not necessarHy lend itself to a strict mathematical solution. 8 The key consideration in determining the ROE is to ensure that the overall analysis 9 reasonably reflects investors' view of the financial markets in general, and the 10 subject company (in the context of the proxy companies) in particular. 11 Although several models have been developed for that purpose, all are 12 subject to limiting assumptions or other constraints. Consequently, many finance 13 texts recommend using multiple approaches to estimate the cost of equity.5 When 14 faced with the task of estimating the cost of equity, analysts and investors are 15 inclined to gather and evaluate as much relevant data as reasonably can be analyzed 16 and, therefore, rely on multiple analytical approaches. 17 Lastly, as a practical matter no individual model is more reliable than all 18 others under all market conditions. Therefore, it is both prudent and appropriate to 19 use multiple methods to mitigate the effects of assumptions and inputs associated 20 with any single approach. As such, I have considered the Constant Growth and 21 Multi-Stage forms of the DCF model, the CAPM, and the Bond Yield Plus Risk See, for example, Eugene Brigham, Louis Gapenski, Financial Management: Theory and Practice, 7th Ed., 1994, at 341; and Tom Copeland, Tim Koller and Jack Murrin, Valuation: Measuring and Managing the Value of Companies, 3rd ed., 2000, at 214. Direct Testimony of Robert B. Revert Page 12 Colorado I Revert Direct Testimony l Premium approach. 2 Constant Growth DCF Model 3 Q. ARE DCF MODELS WIDELY USED IN REGULATORY PROCEEDINGS? 4 A. Yes. In my experience, the Constant Growth DCF model is widely recognized in 5 regulatory proceedings, as well as in financial literature. Nonetheless, neither the 6 DCF nor any other model should be applied without considerable judgment in the 7 selection of data and the interpretation of results. 8 Q. PLEASE DESCRIBE THE DCF APPROACH. 9 A. The Constant Growth DCF approach is based on the theory that a stock's current 10 price represents the present value of all expected future cash flows. In its simplest 11 form, the Constant Growth DCF model expresses the cost of equity as the discount 12 rate that sets the cmTent price equal to expected cash flows: 13 EQUATION 1 14 15 where P represents the current stock price, D1 ... Dao represent expected future 16 dividends, and k is the discount rate, or required ROE. Equation 1 above is a 17 standard present value calculation that can be simplified and rearranged into the 18 familiar form: 19 EQUATION2 20 k = Do (1+g) + g p 21 Equation 2 is often referred to as the "Constant Growth DCF" model, in which the 22 first term is the expected dividend yield and the second term is the expected long~ Direct Testimony ofRobe1t B. Revert Page 13 Colorado I Revert Direct Testimony term annual growth rate. 2 Q. WHAT ASSUMPTIONS ARE REQUIRED FOR THE CONSTANT 3 GROWTH DCF MODEL? 4 A. The Constant Growth DCF model assumes: (1) a constant average annual growth 5 rate for earnings and dividends; (2) a stable dividend payout ratio; (3) a constant 6 price-to-earnings ("PIE") multiple; and (4) a discount rate greater than the expected 7 growth rate. Under those assumptions, dividends, earnings, book value, and the 8 stock price all grow at the same, constant rate. The model further assumes that the 9 current cost of equity (that is, the model's results) will remain unchanged, in IO perpetuity. 11 Q. WHAT MARKET DATA DID YOU USE TO CALCULATE THE 12 DIVIDEND YIELD COMPONENT OF YOUR DCF MODEL? 13 A. The dividend yield is based on the proxy companies' current annualized dividend, 14 and average closing stock prices over the 30-, 90-, and 180-trading day periods as 15 of April 28, 2017. 16 Q. WHY DID YOU USE THREE AVERAGING PERIODS TO CALCULATE 17 AN AVERAGE STOCK PRICE? 18 A. I did so to ensure that the model's results are not skewed by anomalous events that 19 may affect stock prices on any given trading day. At the same time, the averaging 20 period should be reasonably representative of expected capital market conditions 21 over the long term. In my view, using 30-, 90-, and 180-day averaging periods 22 reasonably balances those concerns. Direct Testimony of Robert B. Revert Page 14 Colorado I Revert Direct Testimony 1 Q. DID YOU MAKE ANY ADJUSTMENTS TO THE DIVIDEND YIELD TO 2 ACCOUNT FOR PERIODIC GROWTH IN DIVIDENDS? 3 A. Yes. Because utilities increase their quarterly dividends at different times 4 throughout the year, it is reasonable to assume that dividend increases will be 5 evenly distributed over calendar quarters. Given that assumption, it is appropriate 6 to calculate the expected dividend yield by applying one-half of the long-term 7 growth rate to the current dividend yield. See, Attachment RBH-2. That 8 adjustment ensures that the expected dividend yield is representative of the coming 9 twelve-month period, and does not overstate the dividends to be paid during that 10 time. 11 Q. IS IT IMPORTANT TO SELECT APPROPRIATE MEASURES OF LONG- 12 TERM GROWTH IN APPLYING THE DCF MODEL? 13 A. Yes. The Constant Growth DCF model (presented in Equation 2 above) assumes a 14 single growth estimate in perpetuity. To reduce the long-term growth rate to a 15 single measure, one must assume a fixed payout ratio, and the same constant growth 16 rate for earnings per share ("EPS"), dividends per share, and book value per share. 17 Because dividends are sustained by earnings growth, the model should incorporate 18 a variety of measures of long-term earnings. That can be accomplished by 19 averaging those measures of long-term growth that tend to be least influenced by 20 capital allocation decisions that companies may make in response to near-term 21 changes in the business environment. Because such decisions may directly affect 22 near-term dividend payout ratios, estimates of earnings growth are more indicative 23 of long-term investor expectations than are dividend growth estimates. Therefore, Direct Testimony ofRobe1t B. Revert Page 15 Colorado I Heve1t Direct Testimony 1 for the purposes of the Constant Growth DCF model, growth in EPS represents the 2 appropriate measure of long-term growth. 3 Q. PLEASE SUMMARIZE THE FINDINGS OF ACADEMIC RESEARCH ON 4 THE APPROPRIATE MEASURE FOR ESTIMATING EQUITY RETURNS 5 USING THE DCF MODEL. 6 A. The relationship between various growth rates and stock valuation metrics has been 7 the subject .of much academic research.6 As noted over 40 years ago by Charles 8 Phillips in The Economics of Regulation: 9 For many years, it was thought that investors bought utility stocks 10 largely on the basis of dividends. More recently, however, studies 11 indicate that the market is valuing utility stocks with reference to 12 total per share earnings, so that the earnings-price ratio has assumed 13 increased emphasis in rate cases. 7 14 Phillips' conclusion continues to hold true. Subsequent academic research 15 clearly and consistently has indicated that measures of earnings and cash flow are 16 strongly related to returns, and that analysts' forecasts of growth are superior to 17 other measures of growth in predicting stock prices.8 For example, Vander Weide 18 and Carleton state that "[our] results . . . are consistent with the hypothesis that 19 investors use analysts' forecasts, rather than historically oriented growth 6 See, Hal1'is, Robert, Using Analysts' Growth Forecasts to Estimate Shareholder Required Rate ofReturn, Financial Management (Spring 1986). Charles F. Phillips, Jr., The Economics ofRegulation, at 285 (Rev. ed. 1969). See, e.g., Christofi, Christofi, Lori and Moliver, l!,valuating Common Stocks Using Value Line's Projected Cash Flows and Implied Growth Rate, Journal oflrivesting (Spring 1999); Harris and Marston, Estimating Shareholder Risk Premia Using Analysts' Growth Forecasts, Financial Management. 21 (Summer 1992); and Vander Weide and Carleton, Investor Growth Expectations: Analysts vs. History, The Journal of Portfolio Management (Spring 1988). Direct Testimony ofRobett B. Revert Page 16 Colorado I Revert Direct Testimony 1 calculations, in making stock buy-and-sell decisions."9 Other research specifically 2 notes the importance of analysts' growth estimates in determining the cost of 3 equity, and in the valuation of equity securities. Dr. Robe1i Harris noted that "a 4 growing body of knowledge shows that analysts' earnings forecasts are indeed 5 reflected in stock prices." _Citing Cragg and Malkiel, Dr. Harris notes that those 6 authors "found that the evaluations of companies that analysts make are the sorts 7 of ones on which market valuation is based."10 Similarly, Brigham, Shame, and 8 Vinson noted that "evidence in the current literature indicates that (i) analysts' 9 forecasts are superior to forecasts based solely on time series data, and (ii) investors 10 do rely on analysts' forecasts."11 11 To that point, the research of Carleton and Vander Weide demonstrates that 12 earnings growth projections have a statistically significant relationship to stock 13 valuation levels, while dividend growth rates do not. 12 Those findings suggest that 14 investors form their investment decisions based on expectations of growth in 15 earnings, not dividends. Consequently, earnings growth, not dividend growth, is 16 the appropriate estimate for the purpose of the Constant Growth DCF model. 9 Vander Weide and Carleton, Investor Growth Expectations: Analysts vs. History, The Journal of Portfolio Management (Spring 1988). The Vander Weide and Carleton study was updated in 2004 under the direction of Dr. Vander Weide. The results of the updated study were consistent with the original study's conclusions. 10 Robert S. Harris, Using Analysts' Growth Forecasts to Estimate Shareholder Required Rate ofReturn, Financial Management (Spring 1986). 11 Eugene F. Brigham, Dilip K. Shame, and Steve R. Vinson, The Risk Premium Approach to Measuring a Utility's Cost ofEquity, Financial Management {Spring 1985). 12 See, Vander Weide and Carleton, Investor Growth Expectations: Analysts vs. History, The Journal of Portfolio Management (Spring 1988). Direct Testimony of Robert B. Hevert Page 17 Colorado I Revert Direct Testimony Q. PLEASE SUMMARIZE YOUR INPUTS TO THE CONSTANT GROWTH 2 DCFMODEL. 3 A. I used the following inputs for the price and dividend terms: 4 l. The average daily closing prices for the 30-, 90-, and 180-trading days 5 ended April 28, 2017, for the term Po; and 6 2. The annualized dividend per share as of April 28, 2017, for the term Do. 7 I then calculated my DCF results using each of the following growth terms: 8 l. The Zack's consensus long-term earnings growth estimates; 9 2. The First Call consensus long-term earnings growth estimates; 10 3. The Value Line long-term earnings growth estimates; and 11 4. The retention growth rate. 12 Q. PLEASE DESCRIBE THE RETENTION GROWTH ESTIMATE AS 13 APPLIED IN YOUR CONSTANT GROWTH DCF MODEL. 14 A. The Retention Growth model, which is a generally recognized and widely taught 15 method of estimating long-term growth, is an alternative approach to the use of 16 analysts' earnings growth estimates. In essence, the model is premised on the 17 proposition that a firm's growth is a function of its expected earnings, and the extent 18 to which it retains earnings to invest in the enterpl"ise. In its simplest form, the 19 model represents long-term growth as the product of the retention ratio (i.e., the 20 percentage of earnings not paid out as dividends, referred to below as "b" and the 21 expected retum on book equity, referred to below as "r"). Thus, the simple "bx r" 22 form of the model projects growth as a function of internally generated funds. That 23 form of the model is limiting, however, in that it does not provide for growth funded Direct Testimony of Robert B. Hevert Page 18 Colorado I Hevert Direct Testimony 1 from external equity. 2 The "br + sv" form of the Retention Growth estimate used in my DCF 3 analysis is meant to reflect growth from both internally generated funds (i.e., the 4 "br" term) and from issuances of equity (i.e., the "sv" term). The first term, which 5 is the product of the retention ratio (i.e., "b'', or the portion of net income not paid 6 in dividends) and the expected return on equity (i.e., "r") represents the portion of 7 net income that is "plowed back" into the Company as a means of funding growth. 8 The "sv" term is represented as: 9 EQUATION3 10 (7 -1) x Growth rate in Common Shares 11 where: 7is the MarkeHo-Book ratio. 12 In this form, the "sv" term reflects an element of growth as the product of 13 (a) the growth in shares outstanding, and (b) that portion of the market-to-book ratio 14 that exceeds unity. As shown in Attachment RBH-3, all of the components of the 15 Retention Growth Model can be derived from data provided by Value Line. 16 Q. HOW DID YOU CALCULATE THE HIGH AND LOW DCF RESULTS? 17 A. I calculated the proxy group mean high DCF results by using the maximum EPS 18 growth rate estimate as reported by Value Line, Zack's, and First Call, as well as 19 the retention growth rate, for each proxy company in combination with the dividend 20 yield for each of the proxy group companies. The proxy group mean high results 21 then reflect the average of the maximum DCF resu Its for the proxy group as a 22 whole. I used a similar approach to calculate the proxy group mean low results 23 using instead the minimum of the Value Line, Zack's, First Call, and retention Direct Testimony of Robe1t B. Revert Page 19 Colorado I Revert Direct Testimony 1 growth estimate for each proxy company. 2 As noted earlier, the Constant Growth DCF model is subject to several 3 assumptions that likely are not consistent with current market conditions. For 4 example, the model assumes the current payout ratio will remain constant in 5 perpetuity, even though (on average, across the proxy companies) it has fallen 6 below long-term levels. The model further assumes the return estimated today will 7 be the same return required at all times in the future, even though the Federal 8 Reserve only recently has begun its move toward monetary policy normalization. 9 That process of normalization, together with the uncertainty surrounding the 10 "unwinding" of the assets put on the Federal Reserve's balance sheet during its 11 "Quantitative Easing" initiatives, introduce a degree of risk, and a likelihood of 12 increasing interest rates not present in the current market. As also discussed later 13 in my direct testimony, other methods more directly reflect the risk premium 14 required by investors in response to such risks. On balance, it is my view that the 15 Constant Growth DCF method should be given less weight than other methods in 16 establishing the Company's ROE. 17 Q. WHAT ARE THE RESULTS OF YOUR CONSTANT GROWTH DCF 18 ANALYSIS? 19 A. My Constant Growth DCF results are summarized in Table RBH-3 (below; see 20 also, Attachment RBH-2). Direct Testimony of Robert B. Hevert Page20 Colorado I Hevert Direct Testimony Table RBH-3: Constant Growth DCF Results Mean Low Mean Mean High 30-Day Average 7.36% 9.23% 11.66% 90-Day Average 7.47% 9.33% 11.77% 180-Day Average 7.59% 9.45% 11.89% 2 3 Multi-Stage DCF Model 4 Q. WHAT OTHER FORM OF THE DCF MODEL HAVE YOU 5 CONSIDERED? 6 A. In order to address some of the limiting assumptions underlying the Constant 7 Growth form of the DCF model, I also considered the results of a Multi-Stage 8 (three-stage) DCF Model. The Multi-Stage model, which is an extension of the 9 Constant Growth form, enables the analyst to specify growth rates over three 10 discreet stages. As with the Constant Growth form of the DCF model, the Multi- 11 Stage fotm defines the cost of equity as the discount rate that sets the current price 12 equal to the discounted value of future cash flows. Unlike the Constant Growth 13 form, however, the Multi-Stage model must be solved in an iterative fashion. 14 Q. PLEASE NOW SUMMARIZE WHY YOU HAVE INCLUDED THE 15 MULTI-STAGE DCF METHOD IN YOUR COST OF EQUITY 16 ESTIMATION. 17 A. First, it is both prudent and appropriate to use multiple methodologies in order to 18 mitigate the effects of assumptions and inputs associated with any single approach. 19 Second, the Constant Growth DCF model assumes that earnings, dividends and 20 book value will grow at the same, constant rate in perpetuity; that the payout ratio 21 will remain constant in perpetuity; and that the Price/Earnings ratio will remain Direct Testimony ofRobe1t B. Revert Page21 Colorado I Hevert Direct Testimony 1 constant. In addition, the model assumes that the return required today will be the 2 same return required every year in the future. As discussed above, those 3 assumptions are not likely to hold. In particular, it is likely that over time, payout 4 ratios will increase from their cun·ent levels. In addition, to the extent that long- 5 term interest rates increase over the next few years as the Federal Reserve continues 6 its process of policy "normalization", it is likely that the cost of equity also will 7 increase. In my view, the Multi-Stage DCF model enables analysts to consider 8 those issues, and to address the limiting, but likely unrealistic assumptions 9 underlying the Constant Growth form of the model. 10 Q. PLEASE DESCRIBE THE STRUCTURE OF YOUR MULTI-STAGE DCF 11 MODEL. 12 A. As noted above, the Multi-Stage DCF model sets the subject company's stock price 13 equal to the present value of future cash flows received over three "stages." In the 14 first two stages, "cash flows" are defined as projected dividends. In the third stage, 15 "cash flows" equal both dividends and the expected price at which the stock will 16 be sold at the end of the period (i.e., the "terminal price"). The terminal price is 17 calculated based on the Gordon model, which defines the price as the expected 18 dividend divided by the difference between the cost of equity (i.e., the discount 19 rate) and the long-term expected growth rate. In essence, the terminal price is 20 defined by the present value of the remaining "cash flows" in perpetuity. In each 21 of the three stages, the dividend is the product of the projected earnings per share 22 and the expected dividend payout ratio. A summary description of the model is 23 provided in Table RBH-4 (below). Direct Testimony of Robe1t B. Revert Page22 Colorado I Hevert Direct Testimony l T a bl e RBH- 4 : M u It'1- Sta2e DCFStrue t ure Staee Component 0 First Second Terminal Cash Flow Initial Stock Expected Expected Expected Price Dividend Dividend Dividend+ Terminal Value Inputs • Stock Price •Expected •Expected •Expected •Earnings Per EPS EPS EPS Share •Expected •Expected •Expected ("BPS") DPS DPS DPS •Dividends •Terminal Per Share Value ("DPS") Assumptions • 30-, 90-, and • EPS Growth •Growth •Long-term 180-day Rate Rate Change Growth average •Payout •Payout Rate stock price Ratio Ratio •Long-term Change Payout Ratio 2 3 Q. WHAT ARE THE ANALYTICAL BENEFITS OF YOUR THREE-STAGE 4 MODEL? 5 A. The principal benefits relate to the flexibility provided by the model's structure. 6 Because the model provides the ability to specify near, intermediate, and long-term 7 growth !'ates, for example, it avoids the sometimes-limiting assumption that the 8 subject company will grow at the same, constant rate in perpetuity. In addition, by 9 calculating the dividend as the product of earnings and the payout ratio, the model I 0 accommodates assumptions regarding the timing and extent of changes in the 11 payout ratio to reflect, for example, increases or decreases in expected capital 12 spending, or transition from current payout levels to long-term expected levels. In 13 that regard, because the model relies on multiple sources of earnings growth rate Direct Testimony of Robert B. Revert Page23 Colorado I Revert Direct Testimony l assumptions, it is not limited to a single source, such as Value Line, for all inputs, 2 and therefore mitigates the potential bias associated with relying on a single source 3 of growth estimates. 13 4 The model also enables the analyst to assess the reasonableness of the inputs 5 and results by reference to certain market-based metrics. For example, the stock 6 price estimate can be divided by the expected earnings per share in the final year to 7 calculate the terminal P/E ratio. Similarly, the terminal PIE ratio can be divided by 8 the terminal growth rate to develop a Price to Earnings Growth ("PEG") ratio. To 9 the extent that the projected P/E or PEG ratios are inconsistent with either historical 10 or expected levels, it may indicate incorrect or inconsistent assumptions within the 11 balance of the model. 12 Q. PLEASE SUMMARIZE YOUR INPUTS TO THE MULTI-STAGE DCF 13 MODEL. 14 A. I applied the Multi-Stage model to the proxy group described earlier in my 15 testimony. My assumptions with respect to the various model inputs are described 16 in Table RBH-5, below. 13 See, for example, Harris and Marston, Estimating Shareholder Risk Premia Using Analysts' Growth Forecasts, Financial Management, 21 (Summer 1992). Direct Testimony of Robert B. Revert Page 24 Colorado I Revert Direct Testimony 1 T a bl e RBH- 5 : M u Iti- . Stage DCFMo d e IAssump f ions Stage Component Initial First Transition Terminal Stock Price 30-, 90-, and 180-day average stock price as of April 28, 2017 Earnings 2015 actual EPS growth Transition to Long-term Growth EPS as average of Long-term GDP growth escalated by (1) Value GDP growth Period 1 Line; (2) growth rate Zack's; (3) First Call; and (4) Retention Growth rates Payout Ratio Value Line Transition to Long-term company- long-term industry specific industry average payout ratio Terminal Expected Value dividend in final year divided by solved Cost of Equity less long-term growth rate 2 3 Q. HOW DID YOU CALCULATE THE LONG-TERM GROSS DOMESTIC 4 PRODUCT ("GDP") GROWTH RATE? 5 A. The long-term growth rate of 5.48 percent is based on the real GDP growth rate of 6 3 .22 percent from 1929 through 2016, and an inflation rate of 2. l 9 percent. The 7 GDP growth rate is calculated as the compound growth rate in the chain-weighted Direct Testimony of Robert B. Revert Page 25 Colorado I Revert Direct Testimony GDP for the period from 1929 through 2016. 14 The rate of inflation of 2.19 percent 2 is an average of two components: (1) the compound annual forward rate starting in 3 ten years (i.e., 2027, which is the beginning of the terminal period) based on the 4 30~day average spread between yields on long-term nominal Treasury Securities 5 and long~terrn Treasury Inflation Protected Securities, known as the "TIPS spread" 6 of 2.08percent; 15 ahd (2) the projected Blue Chip Financial Forecast of the CPI for 7 2023 - 2027 of 2.30 percent. 16 8 In essence, the real GDP growth rate projection is based on the assumption 9 that absent specific knowledge to the contrary, it is reasonable to assume that over 10 time, real GDP growth will revett to its long-term mean. In addition, because 11 estimating the cost of equity is a market-based exercise, it is important to reflect, to 12 the extent possible, the sentiments and expectations of investors; those expectations 13 are directly captured in the market-based measure of inflation. In that important 14 respect, the TIPS spread represents the collective views of investors regarding long- 15 term inflation expectations. Equally important, by using forward yields, we are 16 able to infer the level of long-term inflation expected by investors as of the terminal 17 period of the Multi-Stage model (that is, 10 years in the future). 18 Q. WHAT WERE YOUR SPECIFIC ASSUMPTIONS REGARDING THE 19 PAYOUT RATIO? 20 A. As noted in Table RBH-5, the first two periods rely on the first year and long-term 14 See, Bureau ofEconomic Analysis, "Current-Dollar and 'Real' Gross Domestic Product," April 28, 2017 update. 15 See, Board of Governors of the Federal Rese1ve System, "Table H.15 Selected Interest Rates." 16 Blue Chip Financial Forecasts, December 1, 2016, at 14. Direct Testimony of Robert B. Revert Page26 Colorado I Revert Direct Testimony projected payout ratios reported by Value Line for each of the proxy group 2 companies.17 Then by the end of the second period (i.e., the end of year 10), it is 3 assumed that the payout ratio will converge to the long-term industry average of 4 65.58 percent. 18 5 Q. WHAT WAS YOUR PRINCIPAL ASSUMPTION REGARDING THE 6 TERMINAL VALUE? 7 A. Although I performed a series of analyses in which the terminal value is calculated 8 based on the assumed long-term nominal GDP growth rate, 19 I also completed a 9 series of analyses in which the terminal value is based on the current P/E ratio.20 10 The results of those analyses are shown in Table RBH-6, below. 11 T a bl e RBH- 6 . M uIf 1- Staee DCFResu It s, T ermmaIP/EM l e th 0 d21 Low Mean High 30-Day Average 7.92% 9.11% 10.67% 90-Day Average 8.23% 9.43% 10.99% 180-Day Average 8.55% 9.76% 11.33% 12 13 Q. DID YOU UNDERTAKE ANY ADDITIONAL ANALYSES TO SUPPORT 14 YOUR ROE RECOMMENDATION? 15 A. Yes. As noted earlier, I also applied the CAPM and Risk Premium analyses. 17 As reported in the Value Line Investment Survey as "All Div'ds to Net Prof." 18 Source: Bloomberg Pmfessional 19 See, Attachment RBH-4, pages 1 to 10. 20 Defined as the 30-day average of the proxy group PIE ratio, calculated as an Index. 21 · See, Attachment RBH-4, pages 11 to 20. Direct Testimony ofRobertB. Revert Page 27 Colorado I Revert Direct Testimony 1 CAPM Analysis 2 Q. PLEASE BRIEFLY DESCRIBE THE GENERAL FORM OF THE CAPM 3 ANALYSIS. 4 A. The CAPM is a risk premium approach that estimates the cost of equity for a given 5 security as a function of a risk-free return plus a risk premium (to compensate 6 investors for the non-diversifiable or "systematic" risk of that security). As shown 7 in Equation 4, the CAPM is defined by four components, each of which 8 theoretically must be a forward-looking estimate: 9 EQUATION4 IO Ke= (f + j3(rm - ff) ] 1 where: 12 Ke = the required market ROE for a security; 13 ~=the Beta coefficient of that security; 14 r1= the risk-free rate of return; and 15 rm = the required return on the market as a whole. 16 In Equation 4, the te1m (rm - r1) represents the Market Risk Premium.22 17 According to the theory underlying the CAPM, since unsystematic risk can be 18 diversified away by adding securities to their investment portfolio, investors should 19 be concerned only with systematic or non-diversifiable risk. Non-diversifiable l'isk 20 is measured by the Beta coefficient, which is defined as: 21 22 The Market Risk Premium is defined as the incremental return of the market over the risk-free rate. Direct Testimony of Robert B. Revert Page28 Colorado I Hevert Direct Testimony 1 EQUATION 5 2 3 Where: 4 a1 = the standard deviation ofreturns for company''}"; 5 am = the standard deviation of returns for the broad market (as measured, 6 for example, by the S&P 500 Index); and 7 PJ.m = the correlation of returns in between company j and the broad market. 8 The Beta coefficient therefore represents both relative volatility (i.e., the 9 standard deviation) of returns, and the correlation in returns between the subject 10 company and the overall market. 11 Intuitively, higher Beta coefficients indicate that the subject company's 12 returns have been relatively volatile, and have moved in tandem with the overall 13 market. Consequently, if a company has a Beta coefficient of 1.00, it is as risky as 14 the market and does not provide any diversification benefit. 15 Q. WHAT ASSUMPTIONS REGARDING THE RISK-FREE RATE DID YOU 16 INCLUDE IN YOUR CAPM ANALYSIS? 17 A. Because utility assets represent long-term investments, I used two different 18 estimates of the risk-free rate: (1) the current 30-day average yield on 30-year 19 Treasury bonds (i.e., 2.97 percent); and (2) the near-term projected 30-year 20 Treasury yield (i.e., 3.43 percent).23 23 See, Blue Chip Financial Forecasts, Vol. 36, No. 5, May 1, 2017, at 2. Consensus projections of the 30- year Treasury yield for the six quarters ending the third quarter 2018. Direct Testimony ofRobe1t B. Hevert Page 29 Colorado I Heve1t Direct Testimony 1 Q. WHY HAVE YOU RELIED UPON THE 30-YEAR TREASURY YIELD 2 FOR YOUR CAPM ANALYSIS? 3 A. In determining the security most relevant to the application of the CAPM, it is 4 important to select the term (or maturity) that best matches the I ife of the underlying 5 investment. Natural gas utilities typically are long-duration investments and as 6 such, the 30-year Treasury yield is more suitable for the purpose of calculating the 7 cost of equity. 8 Q. PLEASE DESCRIBE YOUR EX-ANTE APPROACH TO ESTIMATING 9 THE MARKET RISK PREMIUM. 10 A. The ex-ante Market Risk Premium reflects the expected market required return, less 11 the current 30-year Treasury yield. To estimate the expected market return, I 12 calculated the average ROE based on the Constant Growth DCF model. To do so, 13 I relied on data from two sources: (1) Bloomberg, and (2) Value Line. For both 14 sources, I calculated the average expected dividend yield (using the same one-half 15 growth rate assumption described earlier) and combined that amount with the 16 average projected earnings growth rate to arrive at the average DCF result. I then 17 subtracted the current 30-year Treasury yield from that amount to an·ive at the 18 market DCF-derived ex-ante Market Risk Premium estimate. The results of those 19 two calculations are provided in Attachment RBH-5. 20 Q. WHAT BETA COEFFICIENTS DID YOU USE IN YOUR CAPM 21 ANALYSIS? 22 A. My approach includes the average reported Beta coefficient from Bloomberg and 23 Value Line for each of the proxy companies (see, Attachment RBH-6). Value Line Direct Testimony ofRobe1t B. Hevert Page 30 Colorado I Revert Direct Testimony calculates the Beta coefficient over a five-year period, whereas Bloomberg's 2 calculation is based on two years of data; both services adjust their calculated (or 3 raw) Beta coefficients to reflect the tendency of the Beta coefficient to regress to 4 the market mean of 1.00 (see, Attachment RBH-6). 5 Q. WHAT ARE THE RESULTS OF YOUR CAPM ANALYSIS? 6 A. The results of my CAP.M analysis are summarized in Table RBH-7, below (see also 7 Attachment RBH-7). 8 T a bl e RBB- 7 : S ummaryofCAPMR esu Its Bloomberg Value Line Derived Derived Market Market Risk Risk Premium Premium Average Bloomberg Beta Coefficient Current 30-Year Treasury (2.97%) 9.53% 9.99% Near Term Projected 30-Year Treasury (3.43%) 9.99% 10.45% Average Value Line Beta Coefficient Current 30-Year Treasury (2.97%) l0.83% 11.38% Near Term Projected 30-Year Treasury (3.43%) 11.29% 11.84% 9 10 Bond Yield Plus Risk Premium Approach l 1 Q. PLEASE GENERALLY DESCRIBE THE BOND YIELD PLUS RISK 12 PREMIUM APPROACH. 13 A. This approach is based on the basic financial principle that because equity investors 14 bear the residual risk associated with ownership, they require a premium over the 15 return they would have earned as a bondholder. That is, because returns to equity 16 holders are riskier than returns to bondholders, equity investors must be 17 compensated for that additional risk. Risk premium approaches therefore estimate Direct Testimony ofRobe1t B. Heve1t Page 31 Colorado I Revert Direct Testimony 1 the cost of equity as the sum of the equity risk premium and the yield on a particular 2 class of bonds. The equity risk premium typically is estimated using a variety of 3 approaches, some of which incorporate ex-ante, or forward-looking estimates of 4 the cost of equity, and others that consider historical, or ex-post, estimates. An 5 alternative approach is to use actual authorized returns for natural gas utilities to 6 estimate the Equity Risk Premium. 7 Q. PLEASE EXPLAIN HOW YOU PERFORMED YOUR BOND YIELD PLUS 8 RISK PREMIUM ANALYSIS. 9 A. I first defined the Risk Premium as the difference between the authorized ROE and 10 the then-prevailing level oflong-term (i.e., 30-year) Treasury yield. I then gathered 11 data for 1,054 natural gas rate proceedings between January, 1980 and April 28, 12 2017. In addition to the authorized ROE, I also calculated the average period 13 between the filing of the case and the date of the final order (the "lag period"). To 14 reflect the prevailing level of interest rates during the term of the proceedings, I 15 calculated the average 30-year Treasury yield over the average lag period 16 (approximately 188 days). 17 Because the data covers a number of economic cycles,24 the analysis also 18 may be used to assess the stability of the Equity Risk Premium, which is not 19 constant; prior research has shown that it is directly related to expected market 24 See, National Bureau ofEconomic Research, U.S. Business Cycle &pansion and Contractions. /Direct Testimony of Robert B. Revert Page 32 Colorado I Revert Direct Testimony volatility, and inversely related to the level of interest rates.25 That finding is 2 particularly relevant given the historically low level of current Treasury yields. 3 Q. HOW DID YOU MODEL THE RELATIONSHIP BETWEEN INTEREST 4 RATES AND THE EQUITY RISK PREMIUM? 5 A. The basic method used was regression analysis, in which the observed Equity Risk 6 Premium is the dependent variable, and the average 30-year Treasury yield is the 7 independent variable. Relative to the long-term historical average, the analytical 8 period includes interest rates and authorized ROEs that are quite high during one 9 period (i.e., the 1980s) and that are quite low during another (i.e., the post-Lehman 10 bankruptcy period). To account for that variability, I used the semi-log regression, 11 in which the Equity Risk Premium is expressed as a function of the natural log of 12 the 30-year Treasury yield: 13 EQUATION6 14 RP= a+ p(LN(T30)) 15 As shown on Chart RBH-1 (below), the semi-log form is useful when 16 measuring an absolute change in the dependent variable (in this case, the Risk 17 Premium) relative to a proportional change in the independent variable (the 30-year 18 Treasury yield). 25 See, e.g., Robe1t S. Harris and Felicia C. Marston, Estimating Shareholder Risk Premia Using Analysts' Growth Forecasts, Financial Management, Summer 1992, at 63-70; Eugene F. Brigham, Dilip K. Shome, and Steve R. Vinson, The Risk Premium Approach to Measuring a Utility's Cost qf Equity, Financial Management, Spring 1985, at 33-45; and Farris M. Maddox, Donna T. Pippert, and Rodney N. Sullivan, An Empirical Study of Ex Ante Risk Premiums for the Electric Utility Industry, Financial Management, Autumn 1995, at 89-95. Direct Testimony of Robert B. Revert Page 33 Colorado I Revert Direct Testimony 1 Chart RBH-1: E Risk Premium 1!l.CHI% .------ (}.1}(}% f------"-- Treasury Yield 2 3 As Chart RBH-1 illustrates, over time there has been a statistically 4 significant, negative relationship between the 30-year Treasury yield and the Equity 5 Risk Premium. Consequently, simply applying the long-term average Equity Risk 6 Premium of 4.57 percent would significantly understate the cost of equity and 7 produce results well below any reasonable estimate. Based on the regression 8 coefficients in Chart RBH-1, however, the implied ROE is between 9.93 percent 9 and 10.24 percent (see, Attachment RBH-8). 10 VII. BUSINESS RISKS AND OTHER CONSIDERATIONS 11 Q. WHAT ADDITIONAL INFORMATION DID YOU CONSIDER IN 12 ASSESSING THE ANALYTICAL RESULTS NOTED ABOVE? l3 A. Because the analytical methods discussed above provide a range of estimates, there 14 is an additional factor that should be taken into consideration when establishing a 15 reasonable range for the Company's cost of equity. Those factors include the 16 Company's comparatively small size, and the costs associated with the flotation of Direct Testimony ofRobert B. Revert Page 34 Colorado I Heve1t Direct Testimony common stock. 2 Small Size Premium 3 Q. PLEASE EXPLAIN THE RISK ASSOCIATED WITH SMALL SIZE. 4 A. Both the financial and academic communities have long accepted the proposition 5 that the cost of equity for small firms is subject to a "size effect" .26 Although 6 empirical evidence of the size effect often is based on studies of industries beyond 7 regulated utilities, utility analysts also have noted the risks with associated small 8 market capitalizations. Specifically, Ibbotson Associates noted: 9 For small utilities, investors face additional obstacles, such as 10 smaller customer base, limited financial resources, and a lack of 11 diversification across customers, energy sources, and geography. 12 These obstacles imply a higher investor return.27 13 Small size, therefore, leads to two categories of increased risk for investors: 14 (1) liquidity risk (i.e., the risk of not being able to sell one's shares in a timely 15 manner due to the relatively thin market for the securities); and (2) fundamental 16 business risks. 17 Q. HOW DOES ATMOS ENERGY COMPARE IN SIZE TO THE PROXY 18 COMPANIES? 19 A. Atmos Energy is significantly smaller than the average for the proxy group 20 companies, both in terms of number of customers and market capitalization. 21 Because Atmos Energy's operations in Colorado are not owned by a separately 22 traded entity, an estimated stand-alone market capitalization for Atmos Energy 26 See, Mario Levis, The record on small companies: A review of the evidence, Journal of Asset Management 2, March 2002, at 368-397, for a review of literature relating to the size effect. 27 Michael Annin, Equity and the Small-Stock Effect, Pub Iic Utilities Fortnightly, October l 5, l 995. Direct Testimony of Robert B. Revert Page 35 Colorado I Revert Direct Testimony 1 must be calculated. To do so, I applied the median market to book ratio for the 2 eight-member proxy group of 2.30 to Atmos Energy's implied equity of $78.42 3 million28 to derive an implied market capitalization of $180.63 million, which is 4 approximately 4.78 percent of the median level of the proxy group. 5 Q. HOW DID YOU EVALUATE THE RISKS ASSOCIATED WITH THE 6 COMPANY'S RELATIVELY SMALL SIZE? 7 A. In its 2017 Valuation Handbook, Duff & Phelps calculates the size premium for 8 deciles of market capitalizations relative to the S&P 500 Index. As shown on 9 Attachment RBH-9, based on recent market data, the average market capitalization 10 of the proxy group is approximately $7 .32 billion, and the median market 11 capitalization of the proxy group is $3.78 billion, which corresponds to the yct and 12 4th deciles of Duff & Phelps's market capitalization data, respectively. Using the 13 median market capitalization in the Duff & Phelps analysis, the proxy group has a 14 size premium of 0.98 percent. The implied market capitalization for Atmos Energy 15 is approximately $180.63 million, which corresponds to the 10111 decile and 16 indicates a size premium of 5.59 percent (or 559 basis points). The difference 17 between those size premiums is 461 basis points (5.59 percent - 0.98 percent). 18 However, rather than propose a specific adjustment, I considered the effect of small 19 size in determining where the Company's ROE falls within the range of results. 20 Flotation Costs 21 Q. WHAT ARE FLOTATION COSTS? 22 A. Flotation costs are the costs associated with the sale of new issues of common stock. 28 Equals requested rate base of$141.1M multiplied by the requested equity ratio of55.58 percent. Direct Testimony of Robert B. Revert Page 36 Colorado I Revert Direct Testimony 1 These include out-of-pocket expenditures for preparation, filing, underwriting, and 2 other costs of issuance. 3 Q. WHY IS IT IMPORTANT TO RECOGNIZE FLOTATION COSTS IN THE 4 ALLOWED ROE? 5 A. To attract and retain new investors, a regulated utility must have the opportunity to 6 earn a return that is both competitive and compensatory. To the extent that a 7 company is denied the opportunity to recover prudently-incurred flotation costs, 8 actual returns will fall short of expected (or required) returns, thereby diminishing 9 its ability to attract adequate capital on reasonable terms. JO Q. ARE FLOTATION COSTS PART OF THE UTILITY'S INVESTED COSTS 11 OR PART OF THE UTILITY'S EXPENSES? 12 A. Flotation costs at·e part of capital costs, which are properly reflected on the balance 13 sheet under "paid in capital" rather than current expenses on the income statement. 14 Flotation costs are incurred over time, just as investments in rate base or debt 15 issuance costs. As a result, the great majority of flotation costs is incurred prior to 16 the test year, but remains part of the cost structure during the test year and beyond. 17 Q. DO THE DCF AND CAPM MODELS ALREADY INCORPORATE 18 INVESTOR EXPECTATIONS OF A RETURN IN ORDER TO 19 COMPENSATE FOR FLOTATION COSTS? 20 A. No. The models used to estimate the appropriate ROE assume no "friction" or 21 transaction costs, as these costs are not reflected in the market price (in the case of 22 the DCF models) or risk premium (in the case of the CAPM and the Bond Yield 23 Plus Risk Premium model). Therefore, it is appropriate to consider flotation costs Direct Testimony ofRobe1t B. Revert Page 37 Colorado I Heve1t Direct Testimony 1 when determining where within the range of reasonable results Atmos Energy's 2 return should fall. 3 Q. IS THE NEED TO CONSIDER FLOTATION COSTS RECOGNIZED BY 4 THE ACADEMIC AND FINANCIAL COMMUNITIES? 5 A. Yes. The need to reimburse investors for equity issuance costs is recognized by the 6 academic and financial communities in the same spirit that investors are reimbursed 7 for the costs of issuing debt. That treatment is consistent with the philosophy of a 8 fair rate of return. As explained by Dr. Shannon Pratt: 9 Flotation costs occur when a company issues new stock. The 10 business usually incurs several kinds of flotation or transaction 11 costs, which reduce the actual proceeds received by the business. 12 Some of these are direct out-of-pocket outlays, such as fees paid to 13 underwriters, legal expenses, and prospectus preparation costs. 14 Because of this reduction in proceeds, the business's required 15 returns must be greater to compensate for the additional costs. 16 Flotation costs can be accounted for either by amortizing the cost, 17 thus reducing the net cash flow to discount, or by incorporating the 18 cost into the cost of equity capital. Since flotation costs typically 19 are not applied to operating cash flow, they must be incorporated 20 into the cost of equity capital.29 21 Q. HOW DID YOU CALCULATE THE FLOTATION COST RECOVERY 22 ADJUSTMENT? 23 A. I modified the DCF calculation to provide a dividend yield that would reimburse 24 investors for issuance costs. My flotation cost adjustment recognizes the costs of 25 issuing equity that were incurred by the Company in fiscal year 2016. As shown 26 in Attachment RBH-10, an adjustment of 0.04 percent (i.e., 4 basis points) 27 reasonably represents the actual flotation costs for the Company. 29 Shannon P. Pratt, Roger J. Grabowski, Cost of Capital: Applications and Examples, 4th ed. (John Wiley & Sons, Inc., 2010), page 586. Direct Testimony of Robert B. Revert Page 38 Colorado I Revert Direct Testimony 1 Q. ARE YOU PROPOSING TO ADJUST YOUR RECOMMENDED ROE BY 4 2 BASIS POINTS TO REFLECT THE EFFECT OF FLOTATION COSTS ON 3 ATMOS ENERGY'S ROE? 4 A. No, I am not. Rather, I have considered the effect of flotation costs, in addition to 5 the Company's other business risks, in determining where the Company's ROE 6 falls within the range of results. 7 VIII.. CAPITAL MARKET ENVIRONMENT 8 Q. DO ECONOMIC CONDITIONS INFLUENCE THE REQUIRED COST OF 9 CAPITAL AND REQUIRED RETURN ON COMMON EQUITY? 10 A. Yes. As discussed in Section VI, the models used to estimate the cost of equity are 11 meant to reflect, and therefore are influenced by, current and expected capital 12 market conditions. As such, it is important to assess the reasonableness of any 13 financial model's results in the context of observable market data. To the extent 14 that certain ROE estimates are incompatible with such data or inconsistent with 15 basic financial principles, it is appropriate to consider whether alternative 16 estimation techniques are likely to provide more meaningful and reliable results. 17 Q. DO YOU HAVE ANY GENERAL OBSERVATIONS REGARDING THE 18 RELATIONSHIP BETWEEN FEDERAL RESERVE MONETARY 19 POLICY, CAPITAL MARKET CONDITIONS, AND ATMOS ENERGY'S 20 COST OF EQUITY? 21 A. Yes, I do. Much has been reported about the Federal Reserve's Quantitative Easing 22 policy and its effect on interest rates. Although the Federal Reserve completed its 23 Quantitative Easing initiative in October 2014, it was not until December 2015 that Direct Testimony ofRobe1t B. Hevert Page 39 Colorado I Hevert Direct Testimony 1 it raised the Federal Funds rate, and began the process of rate normalization.30 2 Therefore, a significant issue is how investors will react as that process continues, 3 and eventually is completed. A viable outcome is that investors will perceive 4 greater chances for economic growth, which will increase the growth rates included 5 in the Constant Growth DCF model. At the same time, higher growth and the 6 absence of Federal market intervention could provide the opportunity for interest 7 rates to increase, thereby increasing the dividend yield portion of the DCF model. 8 In that case, both terms of the Constant Growth DCF model would increase, 9 producing increased ROE estimates. 10 More recently, interest rates have risen and become increasingly volatile. 11 In the equity markets, sectors that historically have included dividend-paying 12 companies have lost value, as increasing interest rates have provided investors with 13 other sources of current yields. Because those dynamics affect different models in 14 different ways, it would be inappropriate to rely on a single method to estimate the 15 Company's cost of equity. A more reasoned approach is to understand the 16 relationships among Federal Reserve policies, interest rates, and measures of 17 market risk, and to assess how those factors may affect different models and their 18 results. As discussed throughout my direct testimony, the current market is one in 19 which it is very important to consider a broad range of data and models when 20 determining the cost of equity. 30 See, Federal Reserve Press Release (December 16, 2015). Direct Testimony of Robert B. Revert Page40 Colorado I Revert Direct Testimony 1 Q. PLEASE SUMMARIZE THE EFFECT OF RECENT FEDERAL RESERVE 2 POLICIES ON INTEREST RATES AND THE COST OF CAPITAL. 3 A. Beginning in 2008, the Federal Reserve proceeded on a steady path of initiatives 4 intended to lower long-term Treasury yields.31 The Federal Reserve policy actions 5 "were designed to put downward pressure on longer-term interest rates by having 6 the Federal Reserve take onto its balance sheet some of the duration and 7 prepayment risks that would otherwise have been borne by private investors."32 8 Under that _policy, "Securities held outright" on the Federal Reserve's balance sheet 9 increased from approximately $489 billion at the beginning of October 2008 to 10 $4.25 trillion by April 2017.33 To _put that increase in context, the securities held 11 by the Federal Reserve represented approximately 3.29 percent of Gross Domestic 12 Product ("GDP") at the end of September 2008, and had risen to approximately 13 22.37 percent of GDP in April 2017.34 As such, the Federal Reserve policy actions 14 have represented a significant source of liquidity, and have had a substantial effect 15 on capital markets. 16 Just as market intervention by the Federal Reserve has reduced interest 17 rates, it also had the effect of reducing market volatility. As shown in Chart RBH- 18 2 (below), each time the Federal Reserve began to purchase bonds (as evidenced 19 by the increase in "Securities Held Outright" on its balance sheet), volatility 20 subsequently declined. In fact, in September 2012, when the Federal Reserve began 31 See, Federal Reserve Press Release, dated June 19, 2013. 32 Federal Reserve Bank ofNew York, Domestic Open Market Operations During 2012, April 2013, at 29. 33 Source: Federal Reserve Board Exhibit H.4.1. "Securities held outright" include U.S. Treasury securities, Federal agency debt securities, and mortgage-backed securities 34 Source: Federal Reserve Board Exhibit H.4.1; Bureau of Economic Analysis. Direct Testimony of Robert B. Hevert Page 41 Colorado I Hevert Direct Testimony 1 to purchase long-term securities at a pace of $85 billion per month, volatility (as 2 measured by the CBOE Volatility Index, known as the "VIX") fell, and through 3 October 2014 remained in a relatively narrow range. The reason is quite straight- 4 forward: investors became confident that the Federal Reserve would intervene if 5 markets were to become unstable. 6 Chart RBH-2: VIX and Federal Reserve Asset Purchases35 QE2 QE3 $4,5[1[},1}00 I'/ ... $4,l'.HlO,UOO $3,500,000 $3,0(}0,000 $2,500,000 i $2,[}(}0,000 ~ 30 l! S1 ,50-0,tlOO :! 20 H $1 ,D00,000 Ci> ie $500,0'00 .. =~ Ci> 0 O;-_,___,...._..__,...__._....-~_.,_...__.__,~~.,.__~-.-~~.~ so &..? &.J:io.i <:P~o$l &'t"" &iD-- &"'""> ...... VIX - Securities Held Outright 7 8 9 The important analytical issue is whether we can infer that risk aversion 10 among investors is at a historically low level, implying a cost of equity that is well 11 below recently authorized returns. Given the negative correlation between the 12 expansion of the Federal Reserve's balance sheet and the VIX, it is difficult to 13 conclude that fundamental risk aversion and investor return requirements have 14 fallen. If it were the case that investors believe that volatility will remain at low 15 levels (that is, that market risk and uncertainty will remain low), it is not clear why 35 Source: Federal Reserve Economic Data (FRED), Federal Reserve Bank of St. Louis; Federal Reserve Statistical Release H.4.1, Factors Affecting Reserve Balances. Direct Testimony of Robert B. Revert Page42 Colorado I Revert Direct Testimony 1 they would decrease their return requirements for defensive sectors such as utilities. 2 In that respect, it appears that the Constant Growth DCF results are at odds with 3 market conditions. 4 Q. DOES YOUR RECOMMENDATION ALSO CONSIDER THE INTEREST 5 RATE ENVIRONMENT? 6 A. Yes, it does. From an analytical perspective, it is important that the inputs and 7 assumptions used to arrive at an ROE recommendation, including assessments of 8 capital market conditions, are consistent with the recommendation itself. Although 9 I appreciate that all analyses require an element of judgment, the application of that 10 judgment must be made in the context of the quantitative and qualitative 11 information available to the analyst and the capital market environment in which 12 the analyses were undertaken. 13 The low interest rate environment associated with central bank intervention 14 may lead some analysts to conclude that current capital costs, including the cost of 15 equity, are low and will remain as such. However, that conclusion only holds true 16 under the hypothesis of Perfectly Competitive Capital Markets ("PCCM") and the 17 classical valuation framework which, under nmmal economic and capital market 18 conditions, underpin the traditional cost of equity models. PCCM's are those in 19 which no single trader, or "market-mover," would have the power to change the 20 prices of goods or services, including bond and common stock securities. In other 21 words, under the PCCM hypothesis, no single trader would have a significant effect 22 on market prices. Direct Testimony ofRobe1t B. Revert Page43 Colorado I Revert Direct Testimony Classic valuation theory assumes that investors trade securities rationally, 2 with prices reflecting their perceptions of value. Although central banks have the 3 ability to set benchmark interest rates, they have been maintaining below normal 4 rates to stimulate continued economic and capital market recovery. It therefore is 5 reasonable to conclude that the Federal Reserve and other central banks have been 6 acting as market-movers, thereby having a significant effect on the market prices 7 of both bonds and stocks. The presence of market-movers, such as the Federal 8 Reserve, runs counter to the PCCM hypothesis, which underlies traditional cost of 9 equity models. Consequently, the results of those models should be considered in 10 the context of both quantitative and qualitative information. 11 Although the Federal Reserve's market intervention policies have kept 12 interest rates historically low, since July 8, 2016 (when the 30-year Treasury yield 13 hit an all-time low of 2.11 percent), rates have risen. As the Federal Reserve 14 increased the Federal Funds target rate by 25 basis points in December 2016 (from 15 0.25 percent - 0.50 percent to 0.50 percent - 0. 75 percent) and again in March 2017 16 (to 0. 75 percent - 1.00 percent),36 short-term interest rates increased by a 17 cmTesponding amount.37 Long-term yields increased by wider margins, with the 18 10-year and 30-year Treasury yields increasing by 92 basis points and 85 basis 19 points, respectively, by April 28, 2017 (see Chart RBH-3 below). 36 On June 14, 2017, the Federal Reserve increased the Federal Funds target rate to 1.00 percent -1.25 percent. 37 Federal Reserve Board Exhibit H.15. 6-month and 1-year Treasury yields both increased by 63 and 59 basis points, respectively, from July 8, 2016 to Apri I 28, 2017. Direct Testimony ofRobe1t B. Hevert Page44 Colorado I Heve1t Direct Testimony 1 Chart RBH-3: Treasury Yield Curve: 7/8/2016, 4/28/2017 and Projected Q3 201838 4.1c~o1 r .. L . , -'•" •-'•" ·"'. ·-· . ... ,.. -· jo' ..... ~ .. +111•• .. ·-=···•a."'" •• ------.-.. ·····_~ ..... ~~~~-;;;•···· - io+...... ~ ... +-t ,,,:> .. . . ·• •- ...... F•:"·.~fo" ...... + ,.. l.5-0 ...... :·"'" .... ,_,._...... ,,. •<:"" ."'~ ...... n.. SU. 11111 Sm 5m 1v 2y Sy 5V -7lS/2016 ••••••••• Bl1eCl1lp Q3 .201S 2 3 The increase in the ten- and 30-year yields from July 2016 to April 2017 is 4 among the highest increase in at least 25 years.39 That increase in Treasury yields 5 is highly related to increasing inflation. To that point, leading up to and following 6 the November 2016 United States Presidential election expected inflation, as 7 measured by the difference between nominal Treasmy yields and Treasury Inflation 8 Protected Securities (that difference often is referred to as the "TIPS spread") also 9 increased, such that it stands somewhat above the Federal Reserve's 2.00 percent 10 inflation target (see Chart RBH-4, below). 38 Sources: Federal Reserve Board Exhibit H.15.; Blue Chip Financial Forecasts, Vol. 36, No. 5, May 1, 2017, at 2. 3-year, 7-year and 20-year projected Treasury yields interpolated. 39 Source: Federal Reserve Exhibit H.15. The increases fall in the top 98th percentiles for both the 10 and 30-year Treasury yields, respectively. Direct Testimony of Robert B. Hevert Page45 Colorado I Hevert Direct Testimony Chart RBH-4: Forward Inflation Estimates 7/8/2016- 4/28/201740 2.25 2.15 1.SS U!.S 1.75 1.fiS 1.55 ; ...... , ...; .. . . '· ...... ,, .,. ,., ... .,; ...... : ...... ······:····· Jul-15 Aug-16 Sep-15 Oct-15 Nov-16 Dec-Hi Jan-17 Fe!J.-17 Mar-17 Apr-17 2 3 The increase in both long-term interest rates and inflation, particularly 4 considering the magnitude of the changes over an abbreviated period, suggest 5 higher investor return requirements. 6 Q. DOES MARKET-BASED DATA INDICATE THAT INVESTORS SEE A 7 PROBABILITY OF INCREASING INTEREST RATES? 8 A. Yes. Forward Treasury yields implied by the slope of the yield curve and published 9 projections by sources such as Blue Chip Financial Forecasts (which provides IO consensus estimates from approximately 50 professional economists) indicate 11 investors expect long"term interest rates to increase. Similarly, investors' 12 expectations for increased long-term Treasury yields are apparent in the prices 13 investors are willing to pay today for the option to buy or sell long~term 14 Government bonds, at today's price, in the future. Because the value of bonds falls 40 Source: Federal Reserve Exhibit H.15. F01ward inflation estimates calculated as the difference between implied nominal and inflation protected 20-year Treasury yields in 10 years. Direct Testimony ofRobe1t B. I-Ievert Page46 Colorado I Revert Direct Testimony 1 as interest rates increase, the option to sell bonds at today's price becomes more 2 valuable when interest rates are expected to increase.41 Currently option prices 3 show that investors are willing to pay about 50.00 percent more for the option to 4 sell bonds in the future (at today's price) than they are willing to pay for the option 5 to buy those bonds.42 That matket-based data tells us that investors consider an 6 increase in interest rates as likely. 7 Looking to shorHerm interest rates, data compiled by CME Groups 8 indicates that investors see a high likelihood of further Federal Funds rate increases, 9 even after the December 14, 2016 and March 15, 2017 increases. As shown in 10 Table RBH-8, (below) the market is now anticipating at least one additional rate 11 hike (94.50 percent probability) and possibly two or more (59.80 percent and 18.60 12 percent probability, respectively) by January 2018. In fact, the implied probability 13 of no increase in the coming year is only 5 .5 0 percent, whereas the likelihood of at 14 least a 50-basis point increase is approximately 60.00 percent. Importantly, the 15 potential for rising rates represents risk for utility investors. 41 In other words, if there is a high probability that interest rates will increase and bond prices will fall, there is value in the option to sell those bonds in the future at today's price. Conversely, if there is a strong probability that interest rates will decrease (price of bonds will increase), there is value in the option to buy those bonds in the future at today's price. 42 The option to sell the TLT index in January 2018 attoday's price is approximately one and a halftimes the value of the option to buy the fund. Source: http://www.nasdag.com/symbol/tlt/option- chain?dateindex=7. Direct Testimony of Robert B. Revert Page 47 Colorado I Revert Direct Testimony Table RBH-8: Probability of Federal Funds Rate I ncreases43 Federal Reserve Meeting Date Target Rate (bps) 6/14/17 7/26/17 9/20/17 1111/17 12/13/17 1/31/18 75-100 16.9% 15.7% 8.8% 8.5% 5.8% 5.5% 100-125 83.1% 78.2% 50.9% 49.2% 36.6% 34.7% 125-150 6.2% 37.6% 38.1% 41.6% 41.2% 150-175 2.7% 4.1% 14.6% 16.3% 175-200 0.1% 1.3% 2.2% 200-225 0.1% 2 3 Lastly, we can view the market's expectations of future interest rates based 4 on. the current yield curve. Those expected rates, often referred to as "forward 5 yields" are derived from the "Expectations" theory, which states that (for example) 6 the current 30-year Treasury yield equals the combination of the current three-year 7 Treasury yield, and the 29-year Treasury yield expected in one year. That is, an 8 investor would be indifferent to (1) holding a 30-year Treasury to maturity, or (2) 9 holding a one-year Treasury to maturity, then a 29-year Treasury bond, also to 10 maturity.44 As Chart RBH-5 (below) indicates, since 2006 the implied forward 29- 11 and 28- year yields (one and two years hence, respectively) consistently exceeded 12 the (interpolated) spot yields. That is, just as economists' projections implied 13 increased interest rates, so did observable Treasury yields. 43 Source: http://www.cmegroup.com/trading/interest-rates/countdown-to-fomc.html, accessed May 8, 2017. I would like to note that the Federal Reserve did raise their Federal Funds target rate to 1.00 percent- 1.25 percent on June 14, 2017, which occurred after my initial analysis. 44 In addition to the Expectations theory, there are other theories regarding the term structure of interest rates including: the Liquidity Premium Theory, which asserts that investors require a premium for holding long term bonds; the Market Segmentation Theory, which states that securities of different terms are not substitutable and, as such, the supply of and demand for short-term and long-term instruments is developed independently; and the Prefened Habitat Theory, which states that in addition to interest rate expectations, certain investors have distinct investment horizons and will require a return premium for bonds with maturities outside of that preference. Direct Testimony of Robert B. Revert Page 48 Colorado I Revert Direct Testimony Chart RBH-5: Forward vs. Interpolated Treasury Yields45 Feb-'88 Feb-10 Feb-14 Feb-16 - - - - - Eiq::€,cted 2:9year YieJd in 1 Year --Eiq:ietted 2Sye,arYield in 2Years 2 3 Q. HAVE YOU ALSO REVIEWED THE RELATIONSHIP BETWEEN 4 CREDIT SPREADS FOR A-RATED UTILITY DEBT RELATIVE TO A- 5 RATED CORPORATE DEBT? 6 A. Yes, I have. Given the historical volatility in the spread between corporate and 7 utility A-rated debt, there is no reason to conclude that utility yields are different 8 than those of their corporate counterparts. That conclusion is consistent with the 9 finding that over time, there has been a nearly one-to-one relationship between 10 credit spreads on A-rated corporate and utility bonds. In fact, a regression analysis 11 in which corporate credit spreads are the explanatory variable and utility credit 12 spreads are the dependent variable shows that slope is approximately 1.00 and 13 highly significant (see Chart RBH-6, below). Because the intercept tenn is 14 statistically insignificant, we can conclude that there has been no material 15 difference between the two, and there cetiainly is no meaningful difference in the 45 Source: Federal Reserve Exhibit H.15. Spot yields are interpolated. Direct Testimony of Robert B. Revert Page49 Colorado I I-revert Direct Testimony l cun·ent market. 2 Chart RBHM6: Corporate and Utility Credit Spreads (AMRated)46 4.5·D 4.00 y:. 1.'0117>HU}Do14 3.SD . · ft•.,. -0. g.e;S2 "O. ·::r"' ·3.·l}D CI. l'l "' 2.~{) "'·~ u 2.J}-~ ,;::·==""' ;:. 1.51Ci .=> -t 1.08• 0.50 ·0:.00 !Q.1~0 0.50 4.50 ,;.~Corporate Cre dilSprear.f 3 4 Q. WHAT DO YOU CONCLUDE FROM THOSE ANALYSES? 5 A. First, it is clear that interest rates have increased from the low levels experienced in 6 early 2016. Second, it is clear that marketMbased data indicate investors' 7 expectations of rising interest rates in the nearM and longer~term. The observation 8 that interest rates have increased, in combination with the optimism in the market 9 discussed in Section II, indicates that the financial community sees the strong 10 prospect of increased growth throughout the economy. As that occurs, and as 11 interest rates continue to rise, it would be reasonable to expect lower utility 12 valuations, higher dividend yields, and higher growth rates. In the context of the 13 Discounted Cash Flow model, those variables would combine to indicate increases 14 in the Cost of Equity. 46 Source: Federal Reserve Exhibit H.15. Direct Testimony of Robert B. Revert Page 50 Colorado I Revert Direct Testimony l Although the market data discussed above indicate increasing costs of 2 capital, it is important to keep in mind that estimating the cost of equity is an 3 empirical exercise, but rote application of a specific form of an analysis, or the 4 mechanical use of specific model inputs, may well produce misleading results. The 5 methods used to estimate the cost of equity, or the weight given to any one method, 6 may change from case to case; and that the returns authorized in other jurisdictions 7 provide a relevant, observable, and verifiable benchmark for assessing the 8 reasonableness of analytical assumptions, results, and conclusions. 9 Q. HAVE THERE BEEN RECENT PERIODS WHEN UTILITY VALUATION 10 LEVELS WERE IDGH RELATIVE TO BOTH THEIR LONG-TERM 11 AVERAGE AND THE MARKET? 12 A. Yes. For example, between July and December 2016, the SNL Gas Utility Index 13 lost approximately 1.30 percent of its value. At the same time, the S&P 500 14 increased approximately by 6.60 percent, indicating that the utility sector under- 15 performed the market by about 8.00 percent. Also during that time, the 30-year 16 Treasury yield increased by approximately 95 basis points (an increase of nearly 17 45.00 percent). The point simply is that as interest rates increased, utility valuations 18 fell. Because (as noted above) investors see the strong likelihood of further interest 19 rate increases, there is a continuing risk of losses in the utility sector. 20 Q. WHAT CONCLUSIONS DO YOU DRAW FROM YOUR ANALYSES OF 21 THE CURRENT CAPITAL MARKET ENVIRONMENT, AND HOW DO 22 THOSE CONCLUSIONS AFFECT YOUR ROE RECOMMENDATION? 23 A. In my view, we cannot conclude that the recent levels of utility valuations are due Direct Testimony ofRobe1t B. Revert Page 51 Colorado I Revert Direct Testimony to a fundamental change in the risk perceptions of utility investors. There is no 2 measurable difference between credit spreads of A-rated utility debt, and A-rated 3 corporate debt. That is, based on analyses of credit spreads, there is no reason to 4 conclude that investors see utilities as less risky relative to either historical levels 5 or to their corporate counterparts. 6 From an analytical perspective, it is important that the inputs and 7 assumptions used to arrive at an ROE determination, including assessments of 8 capital market conditions, are consistent with the conclusion itself. Although all 9 analyses require an element of judgment, the application of that judgment must be 10 made in the context of the quantitative and qualitative information available to the 11 analyst and the capital market environment in which the analyses were undertaken. 12 Because the application of financial models and interpretation of their results often 13 is the subject of differences among analysts in regulatory proceedings, I believe 14 that it is important to review and consider a variety of data points; doing so enables 15 us to put in context both quantitative analyses and the associated recommendations. 16 Because not all models used to estimate the cost of equity adequately reflect 17 those changing market dynamics, it is important to give appropriate weight to the 18 methods and to their results. Moreover, because those models produce a range of 19 results, it is important to consider the type of data discussed above in determining 20 where the Companies' ROE falls within that range. On balance, I believe that the 21 DCF-based results should be viewed very carefully, and that somewhat more 22 weight should be afforded the Risk Premium-based methods. I believe that doing 23 so supports my recommended range of 10.00 percent to 10.75 percent, and my ROE Direct Testimony ofRobert B. Hevert Page 52 Colorado I Hevert Direct Testimony 1 recommendation of 10.50 percent. 2 IX. CONCLUSIONS AND RECOMMENDATION 3 Q. WHAT IS YOUR CONCLUSION REGARDING THE COMPANY'S COST 4 OF EQUITY? 5 A. As discussed throughout my testimony, it is important to consider a variety of 6 empirical and qualitative information in reviewing analytical results and arriving at 7 ROE recommendations. Here, we have a situation in which the proxy companies 8 have traded at Price/Earnings ratios in excess of their historical average, and, for a 9 time, in excess of the market. Because that condition is unlikely to persist, it 10 violates a principal assumption of the Constant Growth DCF model, i.e., that the 11 P/E ratio will not change, ever. As a practical matter, the Constant Growth DCF 12 results are well below a highly observable and relevant benchmark: the returns 13 authorized for vertically integrated electric utilities. A more balanced approach 14 therefore would be to consider multiple methods, including the CAPM approach, 15 and the Bond Yield Plus Risk Premium model. 16 I believe that a rate of return on common equity in the range of 10.00 percent 17 to 10.75 percent represents the range of equity investors' required rate of return for 18 investment in natural gas utilities similar to Atmos Energy in today's capital 19 markets. Within that range, it is my view that an ROE of l 0.50 percent is 20 reasonable and appropriate. A summary of the results of my analyses is shown in 21 Table RBH-9 below. Direct Testimony of Robert B. Revert Page 53 Colorado I Revert Direct Testimony 1 T a bl e RBH- 9 : S ummary o f A na1y I t'1ca IResu It s Discounted Cash Flow Mean Low Mean Mean High Constant Growth DCF 30-Day Constant Growth DCF 7.36% 9.23% 11.66% 90-Day Constant Growth DCF 7.47% 9.33% 11.77% 180-Day Constant Growth DCF 7.59% 9.45% 11.89% Multi-Stage DCF (Gordon Method) 30-Day Multi-Stage DCF 8.19% 8.61% 9.23% 90-Day Multi-Stage DCF 8.30% 8.73% 9.37% 180-Day Multi-Stage DCF 8.41% 8.85% 9.52% Multi-Stage DCF (Terminal PIE) 30-Day Multi-Stage DCF 7.92% 9.11% 10.67% 90-Day Multi-Stage DCF 8.23% 9.43% 10.99% 180-Day Multi-Stage DCF 8.55% 9.76% 11.33% Bloomberg Value Line Derived Derived Market Risk Market Risk CAPM Results Premium Premium Average Bloomberg Beta Coefficient Current 30-Year Treasury (2.97%) 9.53% 9.99% Near Term Projected 30-Year Treasury (3.43%) 9.99% 10.45% Average Value Line Beta Coefficient Current 30-Year Treasury (2.97%) 10.83% 11.38% Near Term Projected 30-Year Treasury (3.43%) 11.29% 11.84% Low Mid High Bond Yield Risk Premium 9.93% 9.99% 10.24% Flotation Costs 0.04% 2 3 Q. DOES THIS CONCLUDE YOUR TESTIMONY? ·4 A. Yes, it does. Direct Testimony of Robert B. Hevert Page 54 Colorado I Hevert Direct Testimony Attachment RBH-1 Page 1of14 Resume of: c;,J!!"'"'· Robert 8. Hevert Partner scottmadden MANAGEMENT CONSULTANT& Summary Bob Hevert is a financial and economic consultant with more than 30 years of broad experience in the energy and utility industries. He has an extensive background in the areas of corporate finance, mergers and acquisitions, project finance, asset and business unit valuation, rate and regulatory matters, energy market assessment, and corporate strategic planning. He has provided expert testimony on a wide range of financial, strategic, and economic matters on more than 100 occasions at the state, provincial, and federal levels. Prior to joining ScottMadden, Bob served as managing partner at Sussex Economic Advisors, LLC. Throughout the course of his career, he has worked with numerous leading energy companies and financial institutions throughout North America. He has provided expert testimony and support of litigation in various regulatory proceedings on a variety of energy and economic issues. Bob earned a B.S. in business and economics from the University of Delaware and an M.B.A. with a concentration in finance from the University of Massachusetts at Amherst. Bob also holds the Chartered Financial Analyst designation. Areas of Specialization !Ill Regulation and rates llii1I Utllities !l!l Fossil/hydro generation lllll Markets and RTOs i!ill Nuclear generation m Mergers and acquisitions i[li!I Regulatory strategy and rate case support !iP.l Capital project planning lilll Strategic and business planning Recent Expert Testimony Submission/Appearance IYil Federal Energy Regulatory Commission - Return on Equity lllll New Jersey Board of Public Utilities - Merger Approval lllll New Mexico Public Regulation Commission- Cost of Capital and Financial Integrity M United States District Court- PURPA and FERG Regulations lllil Alberta Utilities Commission - Return on Equity and Capital Structure Recent Assignments lllll Provided expert testimony on the cost of capital for ratemaking purposes before numerous state utility regulatory agencies, the Alberta Utilities Commission, and the Federal Energy Regulatory Commission ii!l For an independent electric transmission provider in Texas, prepared an expert report on the economic damages with respect to failure to meet guaranteed completion dates. The report was filed as part of an arbitration proceeding and included a review of the ratemaking implications of economic damages !Ill Advised the board of directors of a publicly traded electric and natural gas combination utllity on dividend policy issues, earnings payout trends and related capital market considerations l!il Assisted a publicly traded utility wlth a strategic buy-side evaluation of a gas utility with more than $1 billion in assets. The assignment included operational performance benchmarking, calculation of merger synergies, risk analysis, and review of the regulatory implications of the transaction fill Provided testimony before the Arkansas Public Service Commission in support of the acquisition of SourceGas LLC by Black Hills Corporation. The testimony addressed certain balance sheet capltallzation and credit rating issues ~ For the State of Maine Public Utility Commission, prepared a report that summarized the Northeast and Atlantic Canada natural gas power markets and analyzed the potential benefits and costs associated wlth natural gas pipeline expansions. The independent report was filed at the Maine Public Utllity Commission Attachment RBH-1 Page 2of14 Resume of: @ Robert B. Hevert scottmadden Partner .MANAGEMENT CONSULTANTS ENSTAR Natural Gas Company Altalink, LP., and EPCOR Distribution & Transmission, Inc. Oklahoma Gas and Electric Company 09/16 Oklahoma Gas and Electric Company Docket No. 16-052-U Return on Equity CenterPoint Energy Resources Corp. d/b/a 11/15 CenterPoint Energy Resources Corp. d/b/a Docket No. 15-098-U Return on Equity CenterPoint Energy Arkansas Gas CenterPoint Energy Arkansas Gas SourceGas Arkansas, lnc. 03/15 SourceGas Arkansas, Inc. Docket No. 15-011-U Return on Equity CenterPoint Energy Resources Corp. d/b/a 01107 CenterPoint Energy Resources Corp. d/b/a Docket No. 06-161-U Return on Equity CenterPoint Energy Arkansas Gas CenterPoint Energy Arkansas Gas Xcel Energy, Inc. 03/15 Public Service Company of Colorado Docket No. 15AL-0135G Return on Equity (gas) Xcel Energy, Inc. 06/14 Public Service Company of Colorado Docket No. 14AL-0660E Return on Equity (electric) Xcel Energy, Inc. 12/12 Public Service Company of Colorado Docket No. 12AL-1268G Return on Equity (gas) Xcel Energy, Inc. 11/11 Public Service Company of Colorado Docket No. 11AL-947E Return on Equity (electric) Xcel Energy, Inc. 12/10 Public Service Company of Colorado Docket No. 10AL-963G Return on Equity (electric) Atmos Energy Corporation 07/09 Atmos Energy Colorado-Kansas Division Docket No. 09AL-507G Return on Equity (gas) Xcel Energy, Inc. 12/06 Public Service Company of Colorado Docket No. 06S-656G Return on Equity (gas) Xcel Energy, Inc. 04/06 Public Service Company of Colorado Docket No. 06S-234EG Return on Equity (electric) Xcel Energy, Inc. 08/05 Public Service Company of Colorado Docket No. 05S-369ST Return on Equity (steam) Attachment RBH-1 Page 3of14 Resume of: r~ l:::r Robert B. Hevert scottmadden Partner MANAGEMENT CONSULTMITS SPONSOR DATE CASE/APPLICANT DOCKET NO. SUBJECT Xcel Energy, Inc. 05105 Publ1c Service Company of Colorado Docket No. 05S-246G Return on Equlty (gas) ;(-', .~;;+;l)fa. .;ii;.+1+iii+; ... ;o g:;;;,;,;,, .... ___ ft •;: "" ..... ,,,.,.. •.· ioHtY'·',{:}\·?)0;•' .•. ).:·:.:::.:..:•:•:····:/i\'·i•U·•·····o:·t·.·•'\;·····•.:o:··················.·.······················~<••·····•·\•:•.f.·',·••··· •:3;,·····················:;: ...... :.····:,:.:·•.?/.:.::•: .. .::/.i.Oi:Di'•i/':n\i/)2'//'Hi:•••·'·'::'•••:·::o:•·············································•:•.•······•i:·•··········· Connecticut Light and Power Company 06/14 Connecticut Light and Power Company Docket No. 14-05-06 Return on Equity Southern Connecticut Gas Company 09/08 Southern Connecticut Gas Company Docket No. 08-08-17 Return on Equity Southern Connecticut Gas Company 12107 Southern Connecticut Gas Company Docket No. 05-03-17PH02 Return on Equity Connecticut Natural Gas Corporation 12/07 Connecticut Natural Gas Corporation Docket No. 06-03-04PH02 Return on Equity .·•· nlii~\!Ji!:rA::Di ,i:.;·,1;.:~;;";;.i1;.;;;:r..•···•.•·.········...... ITT ·.::;·;:c·:•·.:················•·········..c.iY?·•·'i ...... /•.•••.'·'{. ...,. ·, :K•'•_;i,': .., ••.•.. •·•·• ..... ·.....•••.. ·.,;;.,...:.:•)·•·:•i)}.'i'·'>· '······: •.•••.... ···•·•••·• .· .. •,,• '·• ·.·•·•·'•.••·' ...... •.•.····•••:<•• ,:·wu·:::i·bO::·•:.:.i";•:•,.,.•{'.;\.''.'O:'········· ,.,,.,,,., '.·.·;,· ..,,, •. ....,. ;········.:};·::· ;;.J ...... : ••...•.•.•. ·.·,·,··<·•···,•... ,., ..,, •...... ,,,,·,.,·' '. ·'·:•.''.':·<''· ···'·'···················••\:i•··········•;:.:'/ •. .• ':•·•· :••'•,}•••·•'·}' ...:::... ·······•;·••••.i•\'{1 ••>•·•:.••:•.:0:•••••·,, .. ,.,, Delmarva Power & Light Company 05/16 Delmarva Power & Light Company Case No. 16-649 (Electric} Return on Equity Delmarva Power & Light Company 05/16 Delmarva Power & Light Company Case No. 16-650 (Gas} Return on Equity Delmarva Power & Light Company 03/13 Delmarva Power & Light Company Case No. 13-115 Return on Equity Delmarva Power & Light Company 12112 Delmarva Power & Light Company Case No. 12-546 Return on Equity Delmarva Power & Light Company 03/12 Delmarva Power & Light Company Case No. 11-528 Return on Equity ..... , •';' ·• ·;..;• :ni~#;1·~·•··~·'" 6~1;;,..i..; "'-if~icrlmmli ~iun;:o:·::·:·:'.•'::.·:··•u•·::}]'/'•'X(.···?··.·.:\,,. .,..,;·e:·.;'·n:·•·iu.·••···•·•s'i/:O:·/·'.',:::.;·•(i'•··X<>. O.":••······:•·.:;r·•·'rit· :•'·.:·••·r ;:• ... :·c:::.: :.;,: ·:.:.•·o.:i.'•.:' .. :.y;.. · :-:··'·,...... ······ ··· :•··•·······•:;••.•< ············ ·.. ·. ··· ···•::·•···• :i· ·:••-;.·: .. •':·.• .•••·••o::.•.•:••. Potomac Electric Power Company 07116 Potomac Electric Power Company Formal Case No. FC1139 Return on Equity Washington Gas Light Company 02/16 Washington Gas Light Co!'f1pany Formal Case No. FC1137 Return on Equity Potomac Electric Power Company 03/13 Potomac Electric Power Company Formal Case No. FC1103-2013-E Return on Equity Potomac Electric Power Company 07/11 Potomac Electric Power Company Formal Case No. FC1087 Return on Equity Sabine Pipeline, LLC 09/15 Sabine Pipeline, LLC Docket No. RP15-1322-000 Return on Equity Nextera Energy Transmisslon West, LLC 07115 Nextera Energy Transmission West, LLC Docket No. ER15-2239-000 Return on Equity Maritimes & Northeast Plpellne, LLC 05/15 Maritimes & Northeast Pipeline, LLC Docket No. RP15-1026-000 Return on Equity Public Service Company of New Mexlco 12/12 Public Service Company of New Mexico Docket No. ER13-685-000 Return on Equity Public Service Company of New Mexico 10/10 Public Service Company of New Mexico Docket No. ER11-1915-000 Return on Equity Portland Natural Gas Transmission System 05/10 Portland Natural Gas Transmission System Docket No. RPi0-729-000 Return on Equity Florida Gas Transmission Company, LLC 10/09 Florida Gas Transmission Company, LLC Docket No. RP10-21-000 Return on Equity Maritimes and Northeast Plpellne, LLC 07/09 Marilimes and Northeast Pipeline, LLC Docket No. RP09-809-000 Return on Equity Spectra Energy 02108 Saltville Gas Storage Docket No. RP08-257-000 Return on Equity -·- ·:-.. ·--.··· Attachment RBH-1 Page 4of14 Resume of: OJ["':~ Robert B. Hevert scottmadden Partner ·~1ANAGEMENT CONSULT.O.NTS SPONSOR DATE CASE/APPLICANT DOCKET NO. SUBJECT Panhandle Energy Pipelines 08/07 Panhandle Energy Pipelines Docket No. PL07-2-000 Response to draft policy statement regarding inclusion of MLPs in proxy groups for determination of gas pipellne ROEs Southwest Gas Storage Company 08/07 Southwest Gas Storage Company Docket No. RP07-541-000 Return on Equity Southwest Gas Storage Company 06/07 Southwest Gas Storage Company Docket No. RP07-34-000 Return on Equity Sea Robin Pipeline LLC 06/07 Sea Robin Pipeline LLC Docket No. RP07-513-000 Return on Equity Transwestern Pipeline Company 09/06 Transwestern Pipeline Company Docket No. RP06-614-000 Return on Equity GPU International and Aquila 11/00 GPU International Docket No. EC01-24-000 Market Power Study Hawaiian Electric Company, Inc. 12/16 Hawaiian Electric Company, Inc. Docket No. 2016-0328 Return on Equity Hawai'i Electric Light Company, Inc. 09/16 Hawai'i Electric Light Company, Inc. Docket No. 2015-0170 Return on Equity Maui Electric Company, Limited 12/14 Maui Electric Company, Limited Docket No. 2014-0318 Return on Equity Hawaiian Electric Company, Inc. 06/14 Hawaiian Electric Company, Inc. Docket No. 2013-0373 Return on Equity Hawai'i Electric Light Company, Inc. 08/12 Hawai'i Electric Light Company, Inc. Docket No. 2012-0099 Return on Equity Ameren Illinois Company d/b/a Ameren 01/15 Ameren Illinois Company d/b/a Ameren Illinois Docket No. 15-0142 Return on Equity Illinois Liberty Utilities {Midstates Natural Gas) 03/14 Liberty Utilities {Midstates Natural Gas) Corp. Docket No. 14-0371 Return on Equity Corp. d/b/a Liberty Utilities d/b/a Liberty Utilities Ameren Illinois Company 01/13 Ameren Illinois Company Docket No. 13-0192 Return on Equity d/b/a Ameren Illinois d/b/a Ameren Illinois Attachment RBH-1 Page 5of14 Resume of.· Robert B. Hevert scottmadden Partner MANACloMENT CONSUl.TANTS SPONSOR DATE CASE/APPLICANT DOCKET NO. SUBJECT Ameren Illinois Company 02/11 Ameren Illinois Company Docket No. 11-0279 Return on Equity (electric) d/b/a Ameren Illinois d/b/a Ameren Illinois Ameren Illinois Company 02111 Ameren Illinois Company Docket No. 11-0282 Return on Equity (gas) d/b/a Ameren Illinois d/b/a Ameren Illinois Duke Energy Indiana, Inc. 12/15 Duke Energy Indiana, Inc. Cause No. 44720 Return on Equity Duke Energy Indiana, Inc. 12/14 Duke Energy Indiana, Inc. Cause No. 44526 Return on Equity Northern Indiana Public Service Company 05/09 Northern Indiana Public Service Company Cause No. 43894 Assessment of Valuation Approaches Potomac Electric Power Company 03/17 Potomac Electric Power Company Case No. 9443 Return on Equity Potomac Electric Power Company 06/16 Potomac Electric Power Company Case No. 9424 Return on Equity Potomac Electric Power Company 06/16 Potomac Electric Power Company Case No. 9418 Return on Equity Potomac Electric Power Company 12/13 Potomac Electric Power Company Case No. 9336 Return on Equity Delmarva Power & Light Company 03/13 Delmarva Power & Light Company Case No. 9317 Return on Equity Potomac Electric Power Company 11/12 Potomac Electric Power Company Case No. 9311 Return on Equity Potomac Electric Power Company 12/11 Potomac Electric Power Company Case No. 9286 Return on Equity Delmarva Power & Light Company 12/11 Delmarva Power & Light Company Case No. 9285 Return on Equity Delmarva Power & Light Company 12/10 Delmarva Power & Light Company Case No. 9249 Return on Equity Attachment RBH-1 Page6of14 Resume of: ,+:'J Robert B. Hevert Y" scottmadden Partner MANAGEMENT CONSULTANTS SPONSOR I DATE CASE/APPLICANT DOCKET No. SUBJECT ... ,.. .,, ...... ~ ,.,, .. ''' "Di;i:;;i;;;.:,., ;~ ...... ·.· · ....· /:Y.·:·;N·(t>:::o·.'>:·.:;:).··Vi''\·'/:.;•.·::··x:::·.:·.i'::::·.··nt··. ~"'% Resume of: 01 Robert B. Hevert scottmadden Partner MA!>t4GEMENT CONSULTANTS SPONSOR DATE CASE/APPLICANT DOCKET NO. SUBJECT Unitil Corporation 01/04 Fltchburg Gas and Electric DTE 03-52 Integrated Resource Plan; Gas Demand Forecast Bay State Gas Company 01/93 Bay State Gas Company DPU 93-14 Divestiture of Shelf Registration Bay State Gas Company 01/91 Bay State Gas Company DPU 91-25 Divestiture of Shelf Registration ALLETE, Inc., d/b/a Minnesota Power Inc. 11/16 ALLETE, Inc., d/b/a Minnesota Power Inc. Docket No. E015/GR-16-664 Return on Equlty Otter Tail Power Corporation 02/16 Otter Tail Power Company Docket No. E017/GR-15-1033 Return on Equity Minnesota Energy Resources Corporation 09/15 Minnesota Energy Resources Corporation Docket No. G-011/GR-15-736 Return on Equity CenterPoint Energy Resources Corp. d/b/a 08/15 CenterPoint Energy Resources Corp. d/b/a Docket No. G-008/GR-15-424 Return on Equity CenterPoint Energy Mlnnesota Gas CenterPoint Energy Minnesota Gas Xcel Energy, Inc. 11/13 Northern States Power Company Docket No. E002/GR-13-868 Return on Equity CenterPoint Energy Resources Corp. d/b/a 08/13 CenterPoint Energy Resources Corp. d/b/a Docket No. G-008/GR-13-316 Return on Equity CenterPoint Energy Minnesota Gas CenterPoint Energy Minnesota Gas Xcel Energy, Inc. 11/12 Northern States Power Company Docket No. E002/GR-12-961 Return on Equity Otter Tail Power Corporation 04/10 Otter Tail Power Company Docket No. E-017/GR-10-239 Return on Equity Minnesota Power a division of ALLETE, Inc. 11/09 Minnesota Power Docket No. E-015/GR-09-1151 Return on Equity CenterPoint Energy Resources Corp. d/b/a 11/08 CenterPoint Energy Minnesota Gas Docket No. G-008/GR-08-1075 Return on Equity CenterPoint Energy Minnesota Gas Otter Tail Power Corporation 10/07 Otter Tail Power Company Docket No. E-017/GR-07-1178 Return on Equity Xcel Energy, Inc. 11/05 Northern States Power Company -Minnesota Docket No. E-002/GR-05-1428 Return on Equity (electric} 09/04 Northern States Power Company- Mlnnesota Docket No. G-002/GR-04-1511 Return on Equity (gas) CenterPoint Energy Resources, Corp. d/b/a 07109 CenterPoint Energy Mississippi Gas Docket No. 09-UN-334 Return on Equity CenterPoint Energy Entex and CenterPoint Energy Mississippi Gas Attachment RBH-1 Page 8of14 Resume of: @ Robert 8. Hevert scottmadden Partner MANAGoMoNT CONS\Jt.TANTS Union Electric Company d/b/a Ameren 07116 Union Electric Company d/b/a Ameren Case No. ER-2016-0179 Return on Equity (electric) Missouri Missouri Kansas City Power & Light Company 07116 Kansas City Power & Light Company Case No. ER-2016-0285 Return on Equity (electric) Kansas City Power & Light Company 02116 Kansas City Power & Light Company Case No. ER-2016-0156 Return on Equity (electric) Kansas City Power & Light Company 10/14 Kansas City Power & Light Company Case No. ER-2014-0370 Return on Equity (electric) Union Electric Company d/b/a Ameren 07/14 Union Electric Company d/b/a Ameren Case No. ER-2014-0258 Return on Equity (electric) Missouri Missouri Union Electric Company d/b/a Ameren 06/14 Union Electric Company d/b/a Ameren Case No. EC-2014-0223 Return on Equity (electric) Missouri Missouri Liberty Utilities (Midstates Natural Gas) 02114 Liberty Utilities (Midstates Natural Gas) Corp. Case No. GR-2014-0152 Return on Equity Corp. d/b/a Liberty Utilities d/b/a Liberty Utilities Laclede Gas Company 12112 Laclede Gas Company Case No. GR-2013-0171 Return on Equity Union Electric Company d/b/a Ameren 02/12 Union Electric Company d/b/a Ameren Case No. ER-2012-0166 Return on Equity (electric} Missouri Missouri Union Electric Company d/b/a AmerenUE 09/10 Union Electric Company d/b/a Ameren UE Case No. ER-2011-0028 Return on Equity (electric) Union Electric Company d/b/a AmerenUE 06/10 Union Electric Company d/b/a AmerenUE Case No. GR-2010-0363 Unitil Energy Systems, Inc. 04/16 Unit!I Energy Systems, Inc. Docket No. DE 16-384 Return on Equity Liberty Utilities d/b/a Granite State Electric 04/16 Liberty Utilities d/b/a Granite State Electric Docket No. DE 16-383 Return on Equity Company Company Liberty Utilities d/b/a EnergyNorth Natural 08/14 Liberty Utilities d/b/a EnergyNorth Natural Gas Docket No. DG 14-180 Return on Equity Gas Attachment RBH-1 Page 9of14 J:'"'r. Resume of: OJ Robert B. Hevert scottmadden Partner MANAGEMENT CONSUL1:".NTS SPONSOR DATE CASE!APPLICANT DOCKET No. SUBJECT Liberty Utilities d/b/a Granite State Electric 03/13 Liberty Utilities d/b/a Granite State Electric Docket No. DE 13-063 Return on Equity Company Company EnergyNorth Natural Gas d/b/a National Grid 02/10 EnergyNorth Natural Gas d/b/a National Grid Docket No. DG 10-017 Return on Equity NH NH Unitil Energy Systems, lnc., EnergyNorth 08/08 Unitll Energy Systems, Inc., EnergyNorth Docket No. DG 07-072 Carrying Charge Rate on Cash Natural Gas, Inc. d/b/a National Grid NH, Natural Gas, Inc. d/b/a National Grid NH, Working Capital Granite State Electric Company d/b/a Granite State Electric Company d/b/a National National Grid, and Northern Utilities, Inc. - Grid, and Northern Utilities, Inc. - New New Hampshire Division Hampshire Division ...••• , ..> ···~,, .. ~··· .. · ;;~<~"''·~/'' ''''''1,ti~~x: .. ?''H?·; ·J)\:.•::•·•····.:\'.@•'·::.''!··········; 0 ·~·-·.-...,.-.- ·:_.·:.···· -_. ... _• ; ··'h)d.:ff:·•;::~?•'•'',i;.'/'~UCJ:;;.::.·:u·:.:c·.:·\.•:: .. ·;;;,r:;.··•·• .•\'l/••·;)}'·' '.. SPONSOR DATE CASE/APPLICANT DOCKET No. SUBJECT Public Service Company of New Mexico 12/14 Public Service Company of New Mexico Case No. 13-00390-UT Cost of Capital and Financial Integrity Southwestern Public Service Company 02/11 Southwestern Public Service Company Case No. 10-00395-UT Return on Equity (electric) Public Service Company of New Mexico 06/10 Public Service Company of New Mexico Case No. 10-00086-UT Return on Equity (electric) Public Service Company of New Mexico 09/08 Public Service Company of New Mexico Case No. 08-00273-UT Return on Equity (electric} Xcel Energy, Inc. 07/07 Southwestern Public Service Company Case No. 07-00319-UT Return on Equity (electric} ·.Ne.f/;i)':i)... .,...... "' ~·c>;iL••i'e~.···· ~~··'"'··· .~·····~····.•;··_ 1 , ....•i ·.• ....•::''\./.::•(. :•····•·•••<> .....···.···.· .. ·...... :;.::/'} >·····•::t•.i'::/• ;.::::.:.:•n:•;:::•:::•Y•':...... , • •• '·· •.. .,•;::·:•.··:s::f · :·••:r·•··•···· :/:Yi'··kL•.•:.i:+;:;.•·::...... · .f J·:.., ·· ···•· ····•·· ....•.•.••··· ..... • ·:::•.· ·: /:-:),: •.·· i.i; • (? Consolidated Edison Company of New York, 01/15 Consolidated Edison Company of New York, Case No. 15-E-0050 Return on Equity (electric) Inc. Inc. Orange and Rockland Utilities, Inc. 11/14 Orange and Rockland Utilities, Inc. Case Nos. 14-E-0493 and 14-G- Return on Equity (electric and 0494 gas) Consolidated Edison Company of New York, 01/13 Consolidated Edison Company of New York, Case No. 13-E-0030 Return on Equity (electric) lnc. lnc. Niagara Mohawk Corporation d/b/a National 04/12 Niagara Mohawk Corporation d/b/a National Case No. 12-E-0201 Return on Equity Grid for Electric Service Grid for Electric Service (electric) Niagara Mohawk Corporation d/b/a National 04/12 Niagara Mohawk Corporation d/b/a National Case No. 12-G-0202 Return on Equity Grid for Gas Service Grid for Gas Service (gas) Orange and Rockland Utilities, Inc. 07/11 Orange and Rockland Utilities, Inc. Case No. 11-E-0408 Return on Equity {electric) Orange and Rockland Utilities, Inc. 07/10 Orange and Rockland Utilities, Inc. Case No. 1O-E-0362 Return on Equity {electric) Consolidated Edison Company of New 11/09 Consolidated Edison Company of New York, Case No. 09-G-0795 Return on Equity (gas} York, Inc. Inc. Consolidated Edison Company of New York, 11/09 Consolidated Edison Company of New York, Case No. 09-S-0794 Return on Equity (steam) Inc. Inc. Niagara Mohawk Power Corporation 07/01 Niagara Mohawk Power Corporation Case No. 01-E-1046 Power Purchase and Sale Agreement; Standard Offer Service Agreement •...., ···:·;•••••••;;;.:•>'•"". liriif...... ,·.••.:·:····~·L:iL'io:'··""·· .·.··• ... ,.,., . ., ... 111 -AP!l' ••fr•';::.• :·•O.Uh\:··•.::..r·:L:.:·:.. ·\' ···~h.•§.•.i?::..;:·•;:•·•••~i.'.:: .: ,.:·····.·::\<):·:.:.::/ ...... ·:••.·.:: ...'.;.",·;: :.;.;.;·.::;:•,:·/:·:,:u.:. .. :.::· .•.• •...;.::: ••.:..•.... •.::···<•••·:•·••:·:.·.•.···:/•:::•.:,.·:.···•• i ?>• ·:.o ::,.:TL•• ::;: ... <.•••••·.·•:·.• :::•:·:•·.·.•.•:i••·:- •/•:·::·? ./: :·•·-'·••·: ··,•:· ···•:·:"~)::·::·.>::'/.:•. ·.· ···· ······ ··c .., •.•. i ·•···:·?··: . Public Service Company of North Carolina, 03/16 Public Service Company of North Carolina, Docket No. G-5, Sub 565 Return on Equity Inc. Inc. Dominion North Carolina Power 03/16 Dominion North Carolina Power Docket No. E-22, Sub 532 Return on Equity Attachment RBH-1 Page 11of14 Resume of: @ Robert B. Hevert scottmadden Partner MANAGEMENT CONSUlTANTS SPONSOR DATE CASE/APPLICANT DOCKET NO. SUBJECT Duke Energy Carolinas, LLC 02/13 Duke Energy Carolinas, LLC Docket No. E-7, Sub 1026 Return on Equity Carolina Power & Light Company d/b/a 10/12 Carolina Power & Light Company d/b/a Docket No. E-2, Sub 1023 Return on Equity Progress Energy Carolinas, Inc. Progress Energy Carolinas, Inc. Virginia Electric and Power Company d/b/a 03/12 Vlrginia Electric and Power Company d/b/a Docket No. E-22, Sub 479 Return on Equity (electric) Dominion North Carolina Power Dominion North Carolina Power Duke Energy Carolinas, LLC 07/11 Duke Energy Carolinas, LLC Docket No. E-7, Sub 989 CenterPoint Energy Resources Corp., d/b/a 03/16 CenterPoint Energy Resources Corp., d/b/a Cause No. PUD201600094 Return on Equity CenterPoint Energy Oklahoma Gas CenterPoint Energy Oklahoma Gas Oklahoma Gas & Electric Company ·12/15 Oklahoma Gas & Electric Company Cause No. PUD201500273 Return on Equity Public Service Company of Oklahoma 07115 Public Service Company of Oklahoma Cause No. PUD201500208 Return on Equity Oklahoma Gas & Electric Company 07/11 Oklahoma Gas & Electric Company Cause No. PUD201100087 Return on Equity CenterPoint Energy Resources Corp., d/b/a 03/09 CenterPoint Energy Oklahoma Cause No. PUD200900055 Return on Equity CenterPoint Energy Oklahoma Gas Gas Duke Energy Progress, LLC 07/16 Duke Energy Progress, LLC Docket No. 2016-227-E Return on Equity Duke Energy Carolinas, LLC 03/13 Duke Energy Carolinas, LLC Docket No. 2013-59-E Return on Equity South Carolina Electric & Gas 06/12 South Carolina Electric & Gas Docket No. 2012-218-E Return on Equity Attachment RBH-1 Page 12of14 Resume of: '-· ... OJ"""""' Robert B. Hevert scottmadden Partner MANAGEMENT CONSULTANTS SPONSOR DATE CASE/APPLICANT DOCKET No. SUBJECT Duke Energy Carolinas, LLC 08/11 Duke Energy Carolinas, LLC Docket No. 2011-271-E Return on Equity South Carolina Electric & Gas 03/10 South Carolina Electric & Gas Docket No. 2009-489-E Return on Equity ., .. /·•;:;; ...... : ... ·;', ·······-"·· ····••<·:·'·"''."''''''··>.·'•>'-"• .. ...,,.,.,,:.o .• \i~~ICl'hW ;.'~9Ull '" ···• Ill" ...... , ·•••·•:·;;.: ..:: .• :.•·.:.·::·; .. i>?•• .... :.• :·.·."s•.•·•.•••·: ..•··•··•····•:.:V/::'.·••·••••· ... '•:·····•••·o.·••·•·•:•,•.'.·••··••·;:(.".·::-..:; i'.~ .. ••·······•······················•·•·<·c:•·o.·.::-\::•·>"·:::···:····./:·········,: :"' .·' ·.· .· ... ·.··· :_'.:·/~·;:::-/,~':· ········. .-:.-.:.: ...... ·.:·· ·..······· •.·:·.:_::: .. •.:.::.·:•·•··•.·•·.•••·••··.•:·• - >·r•···•·.·::::· ...... -:·•·.•:..Yi•'i'\.·····•'·••i···:•···•••••• '····· ···•. Otter Tail Power Company 08/10 Otter Tail Power Company Docket No. EL 10-011 Return on Equity {electric) Northern States Power Company 06/09 South Dakota Division of Northern States Docket No. EL09-009 Return on Equity {electric) Power Otter Tail Power Company 10/08 Otter Tail Power Company Docket No. EL08-030 Return on Equity (electric) ..... "'·' ,...... ,,,. /?.•;·""' ~UIJllC'.'LITl~::-u· ~ :::n.··•·•rn:e ...... •·•·•'/·•·•·'•i';; .":;·::::.'.:::-,·:;· ·::·: ·.::: :• .. ·::·,:;·/.::,-,~_:;:.:· :;::. o-::; :".: ·- ... :.:;...•.;.;; •: ...... ,, ...... ,.. ;.' ...... ,..,,...... Atmos Pipeline- Texas 01/17 Atmos Pipeline- Texas Docket No. 10580 Return on Equity Attachment RBH-1 Page 13of14 Resume of: r5J ' Robert B. Hevert scottmadden Partner MAN!\G!:MENT CONSULTANTS SPONSOR DATE CASE/APPLICANT DOCKET NO. SUBJECT Centerpoint Energy Resources Corp. D/B/A 12/16 Centerpoint Energy Resources Corp. D/B/A D-GUD-10567 Return on Equity Centerpoint Energy Entex And Centerpoint Centerpoint Energy Entex And Centerpoint Energy Texas Gas Energy Texas Gas Centerpoint Energy Resources Corp. d/b/a 03/15 Centerpoint Energy Resources Corp. d/b/a GUD 10432 Return on Equity Centerpoint Energy Entex and Centerpofnt Centerpoint Energy Entex and Centerpoint Energy Texas Gas Energy Texas Gas CenterPoint Energy Resources Corp. d/b/a 07/12 CenterPoint Energy Resources Corp. d/b/a GUD 10182 Return on Equity CenterPoint Energy Entex and CenterPoint CenterPoint Energy Entex and CenterPoint Energy Texas Gas Energy Texas Gas Atmos Energy Corporation-West Texas 06/12 Atmos Energy Corporation -West Texas GUD 10175 Return on Equity Division Division Atmos Energy Corporation - Mid-Texas 06/12 Atmos Energy Corporation - Mid-Texas GUD 10171 Return on Equity Division Division CenterPoint Energy Resources Corp. d/b/a 12/10 CenterPoint Energy Resources Corp. d/b/a GUD 10038 Return on Equity CenterPoint Energy Entex and CenterPoint CenterPoint Energy Entex and CenterPoint Energy Texas Gas Energy Texas Gas Atmos Pipeline - Texas 09/10 Atmos Pipeline - Texas GUO 10000 Return on Equity CenterPoint Energy Resources Corp. d/b/a 07/09 CenterPoint Energy Resources Corp. d/b/a GUO 9902 Return on Equity CenterPoint Energy Entex and CenterPoint CenterPoint Energy Entex and CenterPoint Energy Texas Gas Energy Texas Gas CenterPoint Energy Resources Corp. d/b/a 03/08 CenterPoint Energy Resources Corp. d/b/a GUD9791 Return on Equity CenterPoint Energy Texas Gas CenterPoint Energy Texas Gas Central Vermont Public Service Corporation; 02/12 Central Vermont Public Service Corporation; Docket No. 7770 Merger Policy Green Mountain Power Green Mountain Power Central Vermont Public Service Corporation 12/10 Central Vermont Public Service Corporation Docket No. 7627 Return on Equity (electric) Green Mountain Power 04106 Green Mountain Power Docket Nos. 7175 and 7176 Return on Equity (electric) Vermont Gas Systems, Inc. 12105 Vermont Gas Systems Docket Nos. 7109 and 7160 Return on Equity (gas) Attachment RBH-1 Page 14of14 Resume of: @ Robert B. Hevert scottmadden Partner .MANAGEMENT CONSULT.'5;NTS SPONSOR DATE CASE/APPLICANT DOCKET NO. SUBJECT ·...... ;: : . .. :.; .:-: :.: :·:.··_.· ;,,:":~·. ;·:.:. : .-.:-.·::.:·.· : ···.· ,.. ,.,,.,,, i···~·ll·!ol!.I. "" ;:.}:.>i''·:...:<.L< n:.'·i' :';:\:: :\ <:::::; F .Y,:c:·y,.··-c- .. · :.. , :.·,..; .· , 'l:''/''' ,.:: .. :.::./'~,:::.-.,....,, .. ,;::;:: ::·· : ·.::, ···::: :::·<::::>,. ':· .. : :.,. -.i''.: · .... , Virginia Natural Gas, Inc. 03/17 Virginia Natural Gas, Inc. Case No. PUE-2016-00143 Return on Equity Virginia Electric and Power Company 10/16 Virginia Electric and Power Company Case No. PUE-2016-00112; PUE- Return on Equity 2016-00113; PUE-2016-00136 Washington Gas Light Company 07/16 Washington Gas Light Company Case No. PUE-2016-00001 Return on Equity Virginia Electric and Power Company 06/16 Virginia Electric and Power Company Case Nos. PUE-2016-00063; Return on Equity PUE-2016-00062; PUE-2016- 00061; PUE-2016-00060; PUE- 2016-00059 Virginia Electric and Power Company 12/15 Virginia Electric and Power Company Case Nos. PUE-2015-0058; PUE- Return on Equity 2015-0059; PUE-2015-0060; PUE- 2015-0061; PUE-2015-0075; PUE- 2015-0089; PUE-2015-0102; PUE- 2015-0104 Virginia Electric and Power Company 03/15 Virginia Electric and Power Company Case No. PUE-2015-00027 Return on Equity Virginia Electric and Power Company 03/13 Virginia Electric and Power Company Case No. PUE-2013-00020 Return on Equity Virginia Natural Gas, Inc. 02/11 Virginia Natural Gas, Inc. Case No. PUE-2010-00142 Capital Structure Columbia Gas of Virginia, Inc. 06/06 Columbia Gas of Virginia, Inc. Case No. PUE-2005-00098 Merger Synergies Dominion Resources 10/01 Virginia Electric and Power Company Case No. PUE000584 Corporate Structure and Electric Generation Strategy Exoert Reoort Xt.fn•it~~·§~~!~!':Pi~trlGt.:q9µa;,,,y~~!~r6'.pj~#i!?t··Pf·'·T•~~~~~.;,:A;µ~tJgip.iy!~l9i#!::}@}.' .. DYk'C::F:'•'·····';::.J _.•...•..•••.•.••.•.••..•. '.'.·.··.········:········;··\···········-·····················'·••:·,•,·,···'·•·········.. ················'·>·••'.·':•.'·'···········:·,,••·•········'·... ·.·.. ·.· .... Southwestern Public Service Company I 02/12 I Southwestern Public Service Company I C.A. No. A-09-CA-917-SS I PURPA and FERG regulations Attachment RBH-2 Page 1 of3 Constant Growth Discounted Cash Flow Model with Half Year Growth Adjustment 30 Day Average Stock Price [1] [2] [3) [4) [5] [6] [7] [8] [9] [10] [11] [12] Average Expected Zacks First Call value [me Average Annualized Stock Dividend Dividend Earnings Earnings Earnings Retention Earnings Low Mean High Company Ticker Dividend Price Yield Yield Growth Growth Growth Growth Growth ROE ROE ROE Black Hills Corporation BKH $1.78 $67.07 2.65% 2.75% 5.00% 10.38% 7.50% 5.41% 7.07% 7,72.% 9.82% 13.17% CenterPoint Energy, Inc. CNP $1.07 $27.94 3.83% 3.94% 5.00% 6.06% 6.00% 4.98% 5.51% 8,90% 9.44% 10.01% Chesapeake Utilities Corporation CPK $1.22 $70.37 1.73% 1.81% 6.00% 6.00% 8.00% 14.38% 8.60% 7.79% 10.40% 16.24% Northwest Natural Gas Company NWN $1.88 $59.56 3.16% 3.23% 4.30% 4.50% 6.00% 3.46% 4.57% 6.68% 7.79% 9.25% Sempra Energy SRE $3.29 $111.49 2.95% 3.06% 8.70% 9.87% 8.00% 2.73% 7.32% 5.72% 10.38% 12.97% Southwest Gas Corporation swx. $1.98 $83.71 2.37% 2.43% 5.00% 4.00% 6.50% 8.02% 5.88% 6.41% 8.31% 10.48% Spire Inc SR $2.10 $68.14 3.08% 3.16% 4.10% 4.05% 8.00% 5.24% 5.35% 7.19% 8.51% 11.21% Vectren Corporation WC $1.68 $58.79 2.86% 2.95% 5.70% 5.57% 7.00% 6.46% 6.18% 8.51% 9.13% 9.96% Proxy Group Mean 2.83% 2.92% 5.48% 6.30% 7.13% 6.34% 6.31% 7.36% 9.23% 11.66% Proxy Group Median 2.90% 3.00% 5.00% 5.79% 7.25% 5.32% 6.03% 7.46% 9.29% 10.84% Notes; [1] Source: Bloomberg Professional #REF! [3] Equals [1] / [2] [4] Equals [3] x (1 + 0.5 x [9]) [5] Source: Zacks [6] Source: Yahoo I Finance [7] Source: Value Line [8] Source; Value Line, see Attaehment RBH-3 [9] Equals Average([5], [6], !7], [B]) [10] Equals [3] x (1 + 0.5 x Minimum(!5], [6], [7], [8])) + Minimum([5], [6], [7], [8]) [11] Equals [4] + [9] [12] Equals [3] x (1 + 0.5 x Maximum([5J, [6], [7], [BJ))+ Maximum([5J, J6], [7], [8]) Attachment RBH-2 Page2 of3 Constant Growth Discounted Cash Flow Model with Half Year Growth Adjustment 90 Day Average Stock Plice [1] [2] [3] [4] [5] [6] [7] [8] [9] [10] [11] [12] Average EXpec!ed Zacks F1rS! call valuetme Average Annualized Stock Dividend Dividend Earnings Earnings Earnings Retention Earnings Low Mean High Company Ticker Dividend Plice Yield Yield Growth Growth Growth Growth Growth ROE ROE ROE Black Hills Corporation BKH $1.78 $64.03 2.78% 2.88% 5,00% 10.38% 7,50% 5.41% 7.07% 7.85% 9.95% 13.30% CenterPoint Energy, Inc. CNP $1.07 $26.72 4.00% 4.12% 5.00% 6.06% 6.00% 4.98% 5.51% 9.08% 9.62% 10.19% Chesapeake Utilities Corporation CPK $1.22 $67.73 1.80% 1.88% 6.00% 6.00% 8.00% 14.38% 8.60% 7.86% 10.47% 16.32% Northwest Natural Gas Company NWN $1.88 $59.31 3.17% 3.24% 4.30% 4.50% 6.00% 3.46% 4.57% 6.69% 7.81% 9.26% Sempra Energy SRE $3.29 $106.86 3.08% 3.19% 8.70% 9.87% 8.00% 2.73% 7.32% 5.85% 10.52% 13.10% Southwest Gas Corporation swx $1.98 $81.56 2.43% 2.50% 5.00% 4.00% 6.50% 8.02% 5.88% 6.48% 8.38% 10.55% Spire Inc SR $2.10 $65.81 3.19% 3.28% 4.10% 4.05% 8.00% 5.24% 5.35% 7.31% 8.62% 11.32% Vectren Corporation WC $1.68 $55.95 3.00% 3.10% 5.70% 5.57% 7.00% 6.46% 6.18% 8.66% 9.28% 10.11% Proxy Group Mean 2.93% 3.02% 5.48% 6.30% 7.13% 6.34% 6.31% 7.47% 9.33% 11.77% Proxy Group Median 3.04% 3.14% 5.00% 5.79% 7.25% 5.32% 6.03% 7.58% 9.45% 10.93% Notes: [11 Source: Bloomberg Professional #REF! [3] Equals [1] I [2] [4] Equals [3] x (1 + 0.5 x [9]) [5] Source: Zacks [6] Source: Yahoo! Finance [7] Source: Value Line [8] Source: Value Line, see Attachment RBH-3 [9] Equals Average([5], [6], [7], [8] [10] Equals [3] x (1 + 0.5 x Minimum([5J, [6], [7], [B])) + Minimum([5], [6], [7], [8]) [11] Equals [4] + [9] [12] Equals [3] x (1 + 0.5 x Maximum([5], [6], [7], [8])) + Maximum([5], [6], [7], [8]) Attachment RBH-2 Page 3 of3 Constant Growth Discounted Cash Flow Model with Half Year Growth Adjustment 1 BO Day Average Stock Price [1] [2] [3] [4] [5] [6] [7] [8] [8] [9J (10] [11] Average EXpected lacks First Call value Line Average Annualized Stock Dividend Dividend Earnings Earnings Earnings Retention Earnings Low Mean High Company Ticker Dividend Price Yield Yield Growth Growth Growth Growth Growth ROE ROE ROE Blaok Hills Corporation BKH $1.78 $61.79 2.88% 2.98% 5.00% 10.38% 7.50% 5.41% 7.07% 7.95% 10.05% 13.41% CenterPoint Energy, Inc. CNP $1.07 $24.91 4.30% 4.41% 5.00% 6.06% 6.00% 4.98% 5.51% 9.38% 9.92% 10.49% Chesapeake Utilities Corporation CPK $1.22 $65.49 1.86% 1.94% 6.00% 6.00% 8.00% 14.38% 8.60% 7.92% 10.54% 16.38% Northwest Natural Gas Company NWN $1.88 $59.19 3,18% 3.25% 4.30% 4.50% 6.00% 3.46% 4.57% 6.70% 7.81% 9.27% Sempra Energy SRE $3.29 $105.28 3.12% 3.24% 8.70% 9.87% 8.00% 2.73% 7.32% 5.90% 10.56% 13.15% Southwest Gas Corporation swx $1.98 $76.46 2.59% 2.67% 5.00% 4.00% 6.50% 8.02% 5.88% 6.64% 8.55% 10.71% Spire Inc SR $2.10 $64.75 3.24% 3.33% 4.10% 4.05% 8.00% 5.24% 5.35% 7.36% 8.68% 11.37% Vectren Corporation WC $1.68 $52.69 3.19% 3.29% 5.70% 5.57% 7.00% 6.46% 6.18% 8.85% 9.47% 10.30% Proxy Group Mean 3.05% 3.14% 5.48% 6.30% 7.13% 6.34% 6.31% 7.59% 9.45% 11.89% Proxy Group Median 3.15% 3.24% 5.00% 5.79% 7.25% 5.32% 6.03% 7.64% 9.70% 11.04% Notes: [1] Source: Bloomberg Professional #REF! [3J Equals [1] I [2] [4J Equals [3] x (1 + 0.5 x [9]) [5] Source: Zacks [6] Source: Yahoo! Finance [7] Source: Value Line [BJ Source: Value Line, see Attachment RBH-.3 [SJ Equals Average([5j, [6J, [7], [8]) [1 OJ Equals [3] x (1 + 0.5 x Minimum([5], [6], [7j, [8])) + Minimum([5J, [6], [7j, [8]) [11 J Equals [4] + [9! [12J Equals [3] x (1 + 0.5 x Maximum([5J, [6J, [7], [8])) + Maximum([5]. [B], [7], [8]) Attachment RBH-3 Page 1of1 Retentton Gro\Nl:h Estimate [1] [2] [3) [4l [5] [6] (7] [B~ [9] [10] [11( [12] [13] [141 [15l [16] [17] [181 ProJ&C.ted ProJ&cted ProJ&ed Projected DMdend Projected Common Common Common Projected Earnings Declared Book Value Return on Shares Shares Shares Book Value. per share per share Reteniion perShaire Book Value Outstanding Outstanding Growth 2017 High 2017 Low 2017 Price per Shan: Market/ Company Ticker 2020-22 2020-22 Ratio(B) 2020-22 (R) B>rR 2018 2020-22 Rate- Price Price M!dpoin1 2017 Sook Ratio "S" 'V' SxV BR+SV Black Hills Corporation BKH 4.25 2.W 48.24% 41.00 10.37% 5.00% 60.25 61.00 0.41% $ 68.60 $ 60,00 $ 64.30 32.25 1.99 0.82% 49.84% 0.41% 5.41% CenterPofnt Energy, Inc. CNP 1.65 1.23 25.45% 9.75 15.92% 4.31% 431.00 435.00 0.31% $ 28.10 $ 24.50 $ 26.30 B.25 3.19 0.97% 68.63% 0.67% 4.98% Chesapeake Uttlitfes Corporation CPK 4.20 1.55 63.10% 32.90 12.77% B.05% 17.50 20.00 4.51% s 68.BO s 63,00 $ 65.90 27.40 2.41 10.84% 58.42% 6.33% 14.38% Northwest Natural Gas Company NWN 3.15 2.05 34.92% 31.75 9.92% 3.46% 30.00 30.00 0.00% s 60.70 $ 57.10 $ 58.90 28.45 2.07 0.00% 51.70% 0.00% 3.46% Sempra Energy SRE 7.50 4.55 39.33% 57.70 12.99% 5,11% 254.00 236.00 -2.40% s 113.10 99.70 $ 106.40 53.40 1.99 -4.77% 49.81% -2.38% 2.73% Souihwest Gas Corporation SIM< 4.75 2.50 47.37% 39.60 11.99% 5,58% 50.00 53.00 1.94% $ 84.00 75.60 s 79.80 36.20 2.20 4.28% 54.64% 2.34% 8.02% Spire lnc SR 4.65 2.50 46.24% 48.30 9.63% 4.45% 48.00 50.00 1.36% $ 66.10 62.30 s 64.ZO 40.65 1.58 2.14% 36.68% 0.79% 5.24% Vectren Corporafion WC 3.45 2.00 42.03% 27.05 12.75% S,36% 84.00 86.00 0.78% $ 57.10 51.50 54.30 22.50 2.41 1,88% 58.56% 1.10% 6.46% Average~ 6.34% Notes: [1] Source: Value line [2] Source: Value Line [3] Equals 1 - [2] I ]1] [4] Source: Value Line [5] Equals [1] I [4( [6( Equals [3] x [5] [7] Source: Value Line [BJ Source: Value Line i9] Equals ([BJ I [7l) • 0.33 -1 (10] Source: Value Line [11] Source: Value Une [12] Equals Average ([10], [11D [13] Source: Value Line [14) Equals [12] I [13( ]15) Equals [9] x (14] !16] Equals 1 - (1 I [14J) [17] Equals [15l x [16] [18] Equals [6] + !17] Attachment RBH-4 Page 1 of20 Multi-Stage Growth Discounted Cash Flo.w Model 30 Day Average S1ock Prh::e Ave.ra,ge EP'S Growth Rate Estimate fn First stage: ln~uts [1) !2) [31 [4] [5] [6l m [SJ [9J [10] [11) [12] [13] [14J stock ~PS Gro'll'lth Rate E:stim~tes Lcng-Tel'rT Payo1JtRatio tterative S(ltution Terminal Terminal Val:ue Reoier.ilion Ci.imp any ifcker Prioeo Zac:ks First Call Line Growth Average Growth 2017 2021 2027 Proof IRR PIE Ralia PEG Ratio Bra.;;k Hill& C(lrpor~:tioii BKH $67.07 5.00% 10.38% 7.50% 5.41% 7.07% 5.48% oc.00% 52.00% 65.58% QiD.00 8.87% 20.39 3.72 Cl!lnterPoint Energy, Inc. CNP $27.94 5.(10% 6;06% 6.00% 4.98% 5.51% 5.48% 82.00% 74.00% 65.58% f$0.00) 8.46% 23.23 4.24 Chesapeake Utilities Corporati.on CPK $70.37 6.00% 6.00% 8.00% 14.38% 8.Sfl% 5,4S.% 45,00% 37.00% 65,58% $0,00 B.79% 20.90 3.81 N.orthwl!!!St N21tural Gas Campany NWN $59.56 4.30% 4.50% 6.DO% 3,46% 4.57% 5.48% 80.00% 65.00% 6"fi.5Bo/o 7.78% 30.10 5.49 sempt.a Energy SRE $111,49 8.70% 9.87% 8.00% 2.73% 7.32% 5.48% 65.00% 61,1}0% S5,58% (GO.~)"""" .9.47% 17.36 3.17 SDuttiwest Gas Corporatton swx S83.71 S.00% 4.CIC% 6.50% 8.02% 5.68% 5.48% 53.00% 52.00% 156.58% ($0.00~ B.D6"% 26.80 4.89 Spire Inc SR 568.14 4.10% 4.05% .e1.00% 5.24% 5.35% 5.48% 60,00% 54.00% 65.58% (SO.CO) B.81% 20.77 3.79 Vaetre11 Car12oration WC 558.79 5.70% 5.57'% 7,[]0% 6.46% 6,18% 5.48% 63.00% 58.00% 65.58% 50.00 8.62% 22.02 4.02 Mean 8.61% 22.70 Ma< 9.47% Min 7.78% Pc-ojei:ited Anr.iuat Eaminias per Share: 11s1 [16] [1!] !181 [19] [20] [211 ra:gJ J23! ~4] ~5] [26l [27] [26] 129] [30] J31] Compa:ny Ticker 2015 2015 2017 2016 2019 20:!0 2021 2022 2023 2024 2025 2026 2027 2028 2029 2030 2031 Bla-ak Hills Corporation BKH S2.83··: · $3.03 $3.24 $3.47 $3.72 $3.98 $4.26 $4.55 $4.85 $5.16 $5.47 55.78 SS.10 $6.43 $6.78 $7.16 $7.55 CenterP.oint Ertergy, Inc. CNP Sl.08. $1.14 $1.20 $1.27 $1.34 $1.41 $1.49 $1.57 $1.66 St.75 $1.65 51.95 52.05 $2.17 $2.2.8 $2.41 $2.54 Chesapeake Utilltiet; Col"pQr.atlon CPK 52.68.: 52.91 $3.16 $3.43 $3.73 $4.05 $4.40 $4.75 $5.11 $5.47 $5.83 56.16 56.51 $6.87 $7.25 $7.65 $8.06 Northwest Natural Gas. Company NWN 51.96. 52.05 $2.14 $2.24 $2.34 $2.45 $2.56 $2.68 $2.81 S2.9B $3.11 $3.27 53.45 $3.64 $3,84 $4.05 $4.27 Sempra Energy SRE ss.23·· SS.61 $ti.02 $6.47 $6.94 $7.45 $7.99 $6.SS $9.13 59.71 $10.30 $!Cl.90 $11.50 S12.13 512.79 $13.49 514.23 Southwest Gas Ci:il'pcration swx $2.92: 53.09 $3.27 $3.47 53.67 $3.89 $4.11 $4.35 $4,60 54.66 $5.14 $5.42 55.7:1. $6.03 $6.36 $5.71 $7.08 Spira: Inc SR 53.16.. 53.33 53.51 $3.69 S3.89 $4.10 $4.32 $4.55 $4.80 55.06 $5.33 $5.62 $5.93 $6.26 $6.60 $6.96 $7.34 Veel:ren Co~o:ration WC 52.39 52.54 S2.69 $2.86 53.04 $3.23 $3.43 $3.63 $3.85 S4.07 $4.31 $4.55 54.BO $5.06 $5.34 $5.63 $5.94 P'rcjected Annual Dividend Paymll RafiD 1321 [33] [34] 1351 [36] 1371 [38] [39] 1401 [41] !421 143] [44] 145] [46] Cl)lfl2illln:!! Tii:;;ker 2017 201.B 2019 2020 2021 2022 2023 2024 2025 2026 '1.027 2028 2029 2030 2031 Black Hills Corpctation BKH 50.00% 50.50% :51.00% 51.50% 52.00% 54.26% 56.53% 58,79% 61.05% 63.32% 65.58% 65.58% 65.58% 65.58% 65.58% CenterFlotnt Energy, Irie. CNP 82.00% 80.COo/o 7B.CD% 76.0(]% 74.00% 72.60% 71.19% 69.79% 68.39% 66.98% 65.58o/a 155.58% 65.58% 65.5&% 65.58% Chesapeake Uillffil!!!!!I Corporatfcn CPK 45.00% 43,0D% 41,00% 39.0Q% 37.00% 41.76% 46.53% 51.29% 56.05% Bill.:!1.2:% 65,58% 65.5&% 65.58% 65.58% 65.58% Northwest Na'ltlr:aI Ga:& Company NWN SD.00% 76.25% 7:!.50% 63.75% 6"5.0D% 65.10% 65.19% 65.29% 65.39% 65.48% 65.58% 65.58% 65.58% 65.58% 65.58% Sempra Energy SRE 65.00% S4.QLl% 63.0()% 62.00% S1.0D% 61.76% 152.53% 63.29% 64.05% 64.82% 65JiB% 65.58.% 65.58% 65.58% 65.58% Southwest Gas Corporatio-n swx 53.00% 52..75% 52..50% 52..25% s2.oa% 54.2S% 56.53% 58.79% 61.05% 63.32% 65.58% es.5a% 155.58% es.5a% 65.58% S;p[relnc SR 6D.0(1% 58.50% 57.00% 55.50% 54.00% :55.93% 57.86% 59.79% 61.n% Ei3,65% 65.58% 65.56% 65.56% 65.58% 65.58% Vectnm Corpota1f on WC 63.00% 61.75% 60.50% 59.2.5% 58.00o/c. 59.26% S0.53% 61.7:9% 63.05% 64.32% 65.58% 65.58% 65.58% 65.58% 155.58% P:rojei::t:ed Ann1.1illl Ca5b Flews. [47) [48] 149] [50] [51] [52] [53] [54] [55] [56] [57] [581 [59] (601 [61] [62] Terminal ComE!an::t Ticker 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026 2027 2028 2029 2030 2031 Value Black Hills Corporation BKH $1.62 $1.75 $1.90 52.05 S2.22 52.47 $2.74 ;3.03 S3.34 $3.66 $4.00 S4.22 $4.45 S4.69 $4.95 $153.95 r:::en.terPolnt Energy, ln-o. CNP S0.99 $1.01 $1.04 S1.07 S1.10 S1.14 $1.18 $1.22 Sl.26 $1.30 $1.35 51.42 $1.50 51.58 $1.67 $59.04 Chesapeake Utilitres Corporation CPK 51.42 $1.48 $1.53 51.58 S1.63 51.98 $2,38 $2,81 53.27 83.76 $4.2.7 $4.51 $4.75 $5.01 $5.29 5168.54 Narthwest Natural Gas Compan-y NWN Sl.71 $1.71 $1.70 $1.68 S1.67 51.75 $1.83 $1.93 S2.D3 S2.14 $2.25 $2.39 $2,52 S2.66 $2.80 Sl2U7 .Sempra Energy SRE $3.92 $4,14 $4.37 S4.62 $4.88 SS.28 $5.71 $6.15 $6.60 $7,07 $7.54 $7.95 $8.39 $8.85 $9.33 $247.16 Seot.rthWlll'&t Ga.$ Cofpol'4iltfon swx Sl.73 $1.83 $1.93 S2.03 S2.14 S2.36 $2.60 $2.86 53.14 53.43 $3.75 $3.96 $4.17 $4.40 $4,94 5189,77 Spire Inc SR 52.10 S2.16 $2.22 $2.28 52.33 S2.55 $2.78 $3.02 53.29 S3.58 $3.89 $4.10 $4.33 $4.56 $4.81 S152.47 Ve=Gtreri Cori:i.oration WC $1.70 31.77 $1.84 51.91 S1.99 $2.15 $2.33 $2.52 S2.72 S2.93 $3.15 $3.32 $3.50 $3,69 $3.89 $130.78 P:rojecl:e.d Annual Data lnve<$l:cir Cl!l$h Flows [63] 164] [65] [66] [67] [68] [691 [70] (71] [72] [73] [74l [75] [76] [77] [78] [79] [BO] nitiaJ Companx Tio.k:e:r Outflow 4128117 12131117 6130118 6130119 6130120 6130121 6130122 6130123 6130124 6130125 6130126 6130127 6130128 6130129 6130130 6130131 6130132 Bia.cf< HITT5, Corporation BKH ($67.07] $0.00 $1.10 Sl.66 $1.90 52.05 $2.22 $2.47 $2.74 $3.03 S3.34 SJ.66 S4.00 $4.22 $4A5 $4.69 $4.95 $158.90 CenterPoint :E:ner.gy, Jnc.. CNP (S27.94) $0,00 $0.67 $1.01 $1.04 51.07 51.10 $1.14 $1.18 $1.22 $1.26 51.30 $1.35 $1.42 $1.50 $1.58 $1.57 $60.71 Chesapeake Utilities Corporation CPK ($70.36) $0.00 $0.96 51.48 $1.53 51.56 $1.63 $1.98 $2.38 $2.81 $3.27 53.76 $4.27 $4.51 $4.75 $5.01 $5.29 $173.83 NOrth'W'e$t Na'b.lf-1!1 Gas Cornparty NWN (559.56) $0.00 $1.16 Sl.75 $1.70 SUS $1.67 $1.75 $1.63 $1.93 $2.03 $2.14 $2.26 $:!.39 $2.52 $2.66 $2.80 $131.48 Sempra E:nergy SRE [$111.49) $0.00 52.65 54.06 $4.37 54.62 S4.B8 $5.28 $5.71 $6.15 $6.60 57.07 57.54 $7.95 $6.39 $8.85 $9.33 $256.49 Southwest Gas Corporation swx [583.71) $0.00 51.17 $1.79 $1.93 $2.03 $2.14 $2.36 $2.60 $2.86 $3.14 $3.43 $3.75 $3.96 S4.17 $4.40 $4.64 $194.41 Spire lno SR [S68.14] $0.00 $1.42 $2.16 $2.22 '52.28 $2.33 $2.55 $2.78 $3.02 S3.29 53.58 53.89 $4.10 $4.33 $4.56 $4.81 $157.28 Vectren Coeporation WC [$58.79) $0.00 $1.15 $1.15 $1.84 $1.91 $1.99 $2.15 $2.33 $2.52 52.72 $2.93 $3.15 $3.32 S3.50 $3.69 $3.89 $134.68 Attachment RBH-4 Page 2 of20 MultT·Stage Gr0\1111.h Dlsccm1.1ted Cash Flow Model 30 Day Average SJoc:k Price High EPS Growth Rate Estimate In Flrat Stage Inputs [1] [2] [3] [4] [5] (6] Fl [BJ [91 [10] [11) [12] (13] 114] Stook ____...:E::P..:S:..;G::;rc::;owt:;:v"'~,:.l~=:=t•'"i~;;:~:;:~~"'n":;;l~D="~=-----=Long-Tam Payout Ratio Iterative- Solutlo" Te-rminal Terminal Company Ticker Z:acks FirstCa!I Line Growth High Growth Growth 2017 2021 2027 Proof IRR PIE Rotio PEG Ratio Black Hms Corporation BKH $67,07 5,00% 10,38% 7,50% 5,41% 10.38% 5.48% 50.00% 52.00% 65.58% $0 ..00 9.77% 16.14 2.94 CenterPoint !;nergy, Inc. CNP $27.94 5.00% 6.06% 6.00% 4.98% 6.06% 5.48% 82.00% 74.00% 65.58% (IO.OD) 8.59% 22.26 4.06 Chesapeake- Utlllties Corporation CPK $70.37 6.00% 6.00% 8.00% 14.38% 14.38% 5.48% 45.00% 37.00% 65.58% (ID.OD) 10.35% 14.20 2.59 Northwest Natural Gas Company NWN $59.56 4.30% 4.50% 6.00% 3.46% 6.00% 5.48% 80.00% 65.00% 65.58% SO.OD 8.05% 26.93 4.91 :Se-mpra Energy SRE $111.49 B,70% 9,87% 8.00% 2.7:3% 9.87% 5.48% 6.5.00% 61.00o/c. 6.5.58% S0.00 10.26% 14.48 2.64 SouthWest Gas Corporatlnn swx. $83.71 S.00% 4.00% 6.50% 8.02% 8.02% 5.48% 53.00% 52.00% 65.58% (lliO.-DO) 8.51 % 22.87 4.17 Spire Inc SR $68.14 4.10% 4.05% 8.00% 5.24% 8.00% 5.48% 60.00% 54.00% 65.58% (ID.OD) 9.53% 17.11 3.12 Vectren Coporation WC $58.79 5.70% 5.57% 7.00% 6.46% 7.00% 5.48% 6'3.00% 58.00% 65.58% sa.aa B.82% 20.72 3.78 Meao 9.23% Max 10.35% Min 8.05% Projected Annual Earnings per Share [15] [16] [17] . [18] [19] [20] [21] [22] [231 [24] [25] [26] 127] [28l [29] [30] [31] Company Ticker 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026 2027 2028 2029 2030 2031 61ack Hills Corporation BKH ·.· .. $2.83::· $3.12 53.45 $3.81 $4.20 $4.64 $6.12 $5.61 56.10 $6.58 $7.05 $7.49 $7.91 $8.34 SS.SO $9.28 $9.79 CenterPoint En:ergy, Inc. CNP $1.08 $1.15 $1.21 $1.29 $1.37 $1.45 $1.54 $1.63 51.72. $1.82 $1.93 $2.03 $2.15 $2.26 52.39 $2.52 $2.66 Chesapeake Utiltties Corporation CPK ··' .. $2.68'': $3.07 $3.51 $4.01 $4,59 $5.25 $6.00 66.78 $7.55 $8.30 $9.00 $9.63 $10.16 $10~71 511.30 $11.92 S12.57 Northwest Natural Gas Company NWN '>$Us.::. $2,08 S2.20 $2.33 $2.47 $2.62 $2.78 62.94 53.12 $3.30 $3.48 $3.68 $3.88 $4.09 $4.31 $4,SS $4.80 Sompra Energy SRI: ·:>.$5,23:: $5.75 $6.31 $6.94 $7.62 S8.37 $9.20 $10.04 SI0.88 $11.72 $12.53 $13.31 $14.04 $14.81 515.62 $16.48 S17.38 Souttiwest Gas Corpora1km swx. ,, $2.92° $3.15 $3.41 $3.68 $3.98 $4.29 $4.64 $4,99 $6.35 $5.71 $6.07 $6.43 $6.78 $7.15 $7.55 $7.96 $8.40 Spire Inc SR $3.16 $3.41 $3.69 $3.98 $4.30 54.64 $5.01 $5.39 $5.78 SS.17 $6.56 $6.95 $7.33 $7.73 58.15 $6.60 S9.07 Vectren Corporation WC $2.39 $2.56 $2.74 $2.93 $3.13 $3.35 $3.59 $3,83 $4.0B 64.33 $4.59 64.85 $5.12 $5.40 $6.70 $6.01 $6.34 Projected Annual Dividend Payout Ratio [32] [33] [34] [35] [36] [37J [38] [39] (40] [41] [42] [43] j44l [45) [46] Company Ticker 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026 2027 2028 2029 2030 2031 Black Hill• Corporatlon BKH 50.00% 50.50% 51.00% 51.50% 52,00% 54.26% 56.53% 58.79% 61.05% 63,32% 65,58% 65,58% 65.58% 65.58% 65.56% C::ent.er?oint Ene:rgy, ln.r:i.. CNP 82.00% 80.00% 78.00% 76.00% 74.00% 72.60% 71.19% 69.79% 68.39% 66.98% 65.58% 65.58% 65.58% 65.58% 65.58% Chesapeake: Utilities Corporation CF>K 45.00% 43.00% 41.00% 39.00% 37.00% 41.76% 46.53% 51.29% 56.05% 60.82% 65.58% 65.58% 65.58% 65.58% 65.58% N"orthwest Natural Gas Company NWN 80.00% 76.25% 72.50% 68.75% 65.00% 65.10% 65.19% 65.29% 65.39% 65.48% 65.58% 65.56% 65.58% 65.58% 65.58% Sempra Energy SRE 65.00% 64.00% 63.00% 62.00% 61.00% B1.76% 82.53% 63.29% 64.05% 84.82% 65.58% 55.58% 85.58% 65.58% 65.58% Southwest Gas Corporation swx. 53.00% 52.75% 52.50% 52.:25% 52.00% 54.26% 56.53% 58.79% 61.05% 63.32% 65.58% 65.58% 65.58% 65.58% 65.58% Spire l~c SR 60.00% 58.50% 57.00% 55.50% 54.00% 55.93% 57.66% 59.79% 61.72% 63.65% 65.58% 65.58% 65.58% 65.58% 65.58% Vectren Ccrporatlort vvc 63.00% 61.75% 60.50% 59.25% 58.00% 59.26% 60.53% 61.79% 63.05% 64.32% 65.58% 65.58% 85.58% 65.58% 85.58% Projeate-d Anm..1al Cash Flows [47J 148] [49] 150] !51l [52] [53] [54] [55] 156] [57! [58] [59] [60] 161] 162] Terminal Company Ticker 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026 2027 2028 2029 2030 2031 Value Slack Hills Corporation BKH S1.72 $1.92 $2.14 $2.39 52.66 $3.04 $3,45 $3.87 $4,30 $4.75 $5.18 $5.47 $5,77 SS.OS $6.42 $157.90 CenterPoint Energy, Inc. CNP $1,00 $1.03 $1.07 $1.10 S1.14 $1.18 $1.23 $1.27 $1.32 $1.36 $1.41 $1.48 $1.57 $1.65 $1.74 $59.14 Chesapeake Utilities Corporatiori CPK S1.58 $1.72 S1.88 $2.05 S2.22 $2.83 $3.51 $4.26 $5.05 $5.86 SB.66 57.03 $7.41 57.82 $8.25 $178.54 Ncirthwest Natural Gas Company NWN S1.76 $1.78 $1.79 $1.80 Sl.81 $1.92 $2.03 $2.15 $2..28 $2.41 $2.54 $2.68 $2.83 $2.98 $3.15 $129.23 Se-rnpra l::nergy SRE $4.10 $4.44 $4.80 $5.19 55.81 $6.20 $6.81 $7.42 $6.03 $8.63 $9.21 59.71 $10.25 $10.81 811.40 $251.71 Sauthwest Gas Corporafion swx. 51.81 $1.94 $2.09 $2.24 $2.41 $2.71 $3.02 $3.36 $3.71 $4.07 $4.45 $4,69 $4.95 $5.22 $5.51 $192.03 Spire Inc SR $2,21 $2.33 $2,45 $2.58 $2.71 $3.02 $3.34 $3.69 $4.05 $4.42 $4.81 $5.07 $5.35 $5.64 $5.95 $155.19 Ve-cr:ren Corporation WC $1,72 $1.81 $1.90 $1.99 $2.08 $2.27 $2.47 $2.68 $2.89 $3.12 $3.36 $3.54 $3.74 $3.94 $4.16 $131.37 Projected Annual Data Investor Cash Flows [63] [64] [65] [66] [67] [68] [69] (70] 1711 [72] [731 174] 175] (76] 1711 (78] 179] !80] Initial Company Ticker O"lflow 4128117 12131117 6130/18 6130119 6130120 81301:!1 6130122 6130/23 6130124 8130125 6130128 8130127 6130128 61301:!9 6130130 6130131 6130132 Black HUis Corporation Bl Mutti..stage Growth Dfscounted Cash Flow Model 30 Day Averag:e- Stoc5c Price Low EPS Growth Rate Estimate in :First Stage Inputs [1] ~ 13! 141 [5] 161 [TI [SJ I~ [10l [11l [12) [13! [14] Stock: EPS Growth Rate Estlmales Lon~·Terrr Payout Ratio lte rative Solution Ts:rminal Terminal Value Retention PEG Company Ticker Price Zacks First Call Line Growth Low Growth Growth 2017 2021 2027 Proof IRR PIE Ratio Ratio Bl.eiek Hille; Corporatior.i BKH $67.07 5,00% 10.38% 7.50% 5.41% 5.00%• 5,48% :50.00% 52.00% 65,58:% SO.OD B.39% 23.78 4.34 CenterPoint Energy, Inc. CNP $27.94 5.00% 6.06% 6.00% 4.98% 4.96% 5.48% 82.00% 74.00% 65.58% (SO.OOf S.34% 24.21 4.42 Chesapeake Utilities Corporation CPK $70.37 6,00% 6.00% 8,00% 14.38% 6.00% 5.48% 45.00% 37.00% 65.58% (SO.OOf 8.23% 25.19 4.59 Northwest Natural Gas Company NWN $59.56 4.30% 4.50% 6.00% 3.413% 3.46% 5.48% 80.00% 55.00% £5.58% S0.00 7.59% 32.84 5,99 Seompra Eoergy SRE $111,49 B,70% 9.87% 8.00% 2.73% 2.73% 5,48% 65.00% 51,00% 65,58% S0.00 8.29% 24.61 4.49 Southw&St Gas Corporation swx S83.71 5.00% 4.00% 6.50% B.02% 4.00% 5.48% 53.00% 52.00% 65.58% (S0,00~ 7.72% 30.93 5.64 Spire Inc SR $68.14 4.10% 4.05% 6.00% 5.24% 4.05% 5.48% 60.00% 54.00% 65.58% (SO.OOf 8.50% 22.91 4.18 VB!c:l:ren CDrporation WC 558.79 5.70% 5.57% 7.00% 6.46% 5.57% 5.48% 63.00% 58.00% 55.58% (50.00) 8.48% 23.06 4.21 Mean 8.19% Mar 8.50% Min 7.59% P~ojected Ahnual Eamings per Share [1§1 [161 !1!:1 [18! [19! [20] @1! ~I [23] @4! [2!!] 1!6] f2ZJ 1281 [29l [301 [31] Company licker 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026 2027 2028 2029 2030 2031 Blaok Hilts Corparaticn BKH $2.83. $2.97 $3.12 $3.28 $3.44 S3.81 $3.79 $3.99 $4.19 $4.41 $4.65 $4.90 $5.16 $5.45 $5.75 $6.06 So.39 ConterP0!11t Energy, Inc.. CNP s1.os: $1.13 $1.19 $1.25 $1.31 $1.38 S1.45 $1.52 $1.00 $1.68 $1.77 $1.88 $1.97 $2.07 $2.19 $2.31 $2.44 Chesapeake Utiliiie$ Corporation CPK $2.68·· 02.84 $3.01 $3.19 $3.38 $3.59 S3.80 $4.03 $4.26 $4.51 $4.78 $5.03 $5.30 $5.59 $5.90 $6.22 $8.56 Northwest Natural Gas Company NWN $1.96: 52.03 $2.10 $2.17 $2.25 $2.32 $2.40 $2.50 $2.60 52.72 $2.85 $2.99 $3.16 $3.33 $3.51 $3.70 $3.91 Sempra En&rgy SRE : $5.23.: 05.37 $5.52 $5.67 $5.82 $5.98 $6.15 $6.34 $6.57 56.84 $7.16 $7.52 $7.93 $8.36 $8.82 $9.30 $9.81 Southwes.t Gas Corporation: swx $2.92·. 53.04 $3.16 $3.28 $3.42 $3.55 $3.69 $3.85 $4.02 54.22 $4.43 $4.66 $4.91 $5.18 $5.47 $5.77 $8.08 Spire Inc SR $3.16 $3.29 $3.42 $3.56 $3.70 $3.85 $4.01 $4.18 $4.37 54.58 $4.81 $5.0B $5.34 $5.63 $5.94 $6.27 $D.61 Vectren Corporation WC $2.39 S2.52 $2.6'5 $2.81 $2.97 $3.13 $3.31 $3.49 $3.69 53.69 $4.10 $4.33 $4.57 $4.82 $5.08 $5.36 $5.65 Projeoted Annual Dlvlde-nd Payout Ratio- [32[ [331 [34l [35) [361 [37} 1381 [39] [40l [411 [42) [43) [44) [45) [46] Come!nx licker 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026 2027 2028 2029 :rnao 2031 Black Htlls Corporation BKH 50.00% 50.50% 51.00% 51.50% 52.00% 54.28% 56.53% 58.79% 61.05% 63.32% 65.58% 65.58% 65.58% 65.58% 65.58% Center?o1nt Energy, Inc::. CNP 62.00% 80.00% 78.00% 76.00% 74.00% 72.60% 71.19% 89.79% 68.39% 66.98% 65.58% 65.58% 65.58% as.ss% 65.58'% Ch1!!sapeake Utiltties Corporation CPK 45.00% 43.00% 41.00% 39.00% 37.00% 41.76% 46.53% 51.29% 56.05% 50.8:2% 65.56% 65,58% 65,58% 55,58% 65.58% Northwest Natural Gas Company NWN 80,00% 75.25% 72.50% BB.75% 65.00% 65.10% 65.19% 65.29% 65.39% 65.48% 65.58% 65.58% 65.58% 65.58% 65.58% Sempra Energy SRE 65.00% 64.00% 63.00% 82.00% 61.00% 61.76% 62.53% 63.29% 64.05% 64.82% S5.58% 65.58% 65.58% 65.58% 65.58% Soutllwest Gas Corporation swx 53.00% 52.75% 52.50% 52.25% 52.00% 54.20% 56.53% 58.79% 61.05% 63.32% 65.58% 65.58% 55.58% 65.58% 65.58% Spire Inc SR 60.00% 58.50% 57.00% 55.50% 54.00% 55.93% 57.85% 59.79% 51.72% 63.55% 55.58% 65,58% 65.56% 65.58% 65.58% Veetr~n Corporation WC 63.00% 51,75% 60.50% 59.25% 58.00% 59.26% 60.53% 61.79% 63.05% 64.32% 65.58% 65.58% 65.5B% 65.58% 65.5B% Projected Annual Cash Flows [47} [481 [491 [50] 1511 [52) [53] [54l [55] [56l [57} [581 [591 [60l [61] [621 Terminal Company Tic:ker 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026 2027 2028 2029 2030 2031 V:atus Bleiok Hills Corporation BKH $1.58 $1.65 S1.75 $1.86 $1.87 $2.18 $2.37 $2.59 $2.84 $3,10 $3.39 $3.57 53.77 $3.97 54.19 $152.01 CenterPoint Energy, Inc. CNP $0.98 $1.00 >1.02 $1.05 $1.07 $1.10 $1.14 $1.17 $1.21 $1.25 $1.29 S1.36 S1.44 $1.51 S1.60 $58.96 Chesapeake Utillties Corporation CPK $1.36 $1.37 $1.39 $1.40 $1.41 $1.68 $1.98 $2.31 $2.67 $3,06 $3.48 S3.67 53.87 $4.08 54.30 $165.28 Northw&&t Natural Gas Company NWN $1.68 $1.66 $1.63 $1.60 $1.56 $1.62 $1.59 s1.n $1.86 $1.98 $2.07 S2.1B $2.30 $2.43 52.58 $128.32 Sempra Energy SF!E $3,59 $3.63 $3.67 $3.71 $3.75 $3.92 $4.11 $4.33 $4.58 $4,87 55.20 $5.48 S5.7B $8.10 56.44 $241.51 Southwest Gas Corpo.tation swx $1.67 $1.73 $1.79 $1.86 $1.92 S2.09 $2.28 $2.48 $2.70 S2.95 53.22 S3.40 $3.56 $3.78 53.99 $188.14 Spiretn:c SR $2.05 52.08 $2.11 $2.14 $2.17 52.34 $2.53 $2.74 $2.97 $3.22 $3.50 $3.69 53.90 $4.11 54.33 $151.38 Vectren Co-!]ora.ticn: we $1.68 $1.74 $1.80 S1.86 $1.92 $2.07 $2.23 $2.40 $2.59 $2,78 $2.99 $3.16 S3.33 $3.51 53.71 $130.38 Projected Annt1al D:a1a !ttvestor cash Flows [631 1641 [65l [66} [67} [68l [691 [701 [71l [72] [731 [74l [751 [76} [77] [78] [79] [!ID] r.utia Company Ticker OUUIO\V 4128117 12131117 6130118 6130119 6130120 6130121 6130122 6130123 6130124 6130125 6130126 6130127 6130128 6130129 6130130 6130131 6130132 Black:: Hills Corporatloll BKH ($67.07) $0.00 $1.06 51.60 $1.75 $1.86 $1.97 $2.16 $2.37 $2.59 52.84 53.10 $3.39 $3.57 $3.77 $3.87 S4.19 $156.20 CenterPotnt Energv, lno. CNP ($27.94) $0.00 S0.66 61.00 $1.02 $1.05 $1.07 $1.10" $1.14 $1.17 61.21 $1.25 $1.29 $1.36 $1.44 $1.51 51.BO $60.55 Chesapeake Utllil[es Corporation CPK ($70.37) $0.00 50.92 $1.40 $1.39 $1.40 $1.41 $1.68 $1.98 $2.31 52.67 $3.06 $3.48 $3.87 S3.87 $4.08 $4.30 $169.58 Northwest Natural Gas Company NWN ($59.56) $0.00 $1.14 $1.71 $1.63 $1.60 $1.56 $1.62 $1.69 $1.77 $1.86 $1.96 $2.07 $2.18 $2.30 52.43 52.06 $130.88 Sempra Energy SRE ($111.49) $0.00 $2.43 $3.64 $3.67 $3.71 $3.75 $3.92 $4.11 $4.33 $4.58 $4.87 $5.20 $5.48 $5.78 $8.10 $6.44 $247.95 Southwest Ga5 Corpo-ratlon swx ($83.71) $0.00 $1.13 $1.71 $1.79 $1.86 $1.92 $2.09 $2.28 $2.48 52.70 $2.95 $3.22 $3.40 $3.58 $3.78 $3.99 $192.13 Spire Inc SR ($68.14) $0.00 $1.39 $2.09 $2.11 $2.14 $2.17 $2.34 $2.53 $2.74 52.97 $3.22 $3.50 $3.69 $3.90 $4.11 $4.33 $155.72 Veotrer- Corporation we ($58.79) $0.00 $1.14 $1.72 $1.80 $1.86 $1.92 $2.07 $2.23 $2.40 52.59 $2.76 $2.99 $3.16 $3.33 $3.51 $3.71 $134.09 ·.· ... ·.. :•.: ·.·.·.·.--·. Attachment RBH-4 Page 4 of20 Multl-stag-e G.ro'llllth Discounted Cash Flow Model :90 Cay Average Ste.ck ?rice Average EPS Growth Rate- Estimate- Jn First Stage ln~uls 11] @I [3] [4] !51 [61 m 18] [9] 110] 1111 [12] [13J [14] 81ock EPS Growth Rate Estimates LongaTem Payout Ratio. lteraiive Sol111lo~ Termin:a! Terminal Value Retentic>n Company Tiok-er :Pr[c:eo Zaoks. Fi<0tColl L[ne Gromh Average Growth 2017 2021 2027 P:ro-of IRR PllE Rotto PEG Ratio Sl:ii..:;k Hills Corporatiari BKH $64.03 5.00% 10.38% 7.50-% 5.41% 7,07% 5,48% SO.OD% 52,00% 65,58% 00.00 9.03% 19.49 3.&6 C1mter?cirtrt Ehergy, Inc. CNP $26.72 5.00% 6.06% 15.00-% 4.98% 5.51% 5.48% 82.00% 74.00% 65.58% (00.00) 8.60% 22.15 4.04 Chesapeake- Ui11itie:s Corporation CPK $67.73 6.00% 6.0(J% B.CICI•% 14.38% B.60% 5.48% 45,CD% 37.DC% 65.58o/a $0.00 8.91% 20.16 3.68 Northwest Natural Gas Campany NWN $58.31 4.30o/a 4.50% 6.00-% 3.46% 4.57% 5.48% 80.00% 155.00% 65.58% (00.00) 7.79% 29.97 5.47 Sempra Energy SRIE 5106.86 B.70% 9.87% 8,00% 2.73% 7.32% 5.48% 6"5.01)% 61.00% 65.58% {.SO.OO> 9.64% 16.63 3.03 Southwest Gas Corpcraticn 5WX $81.56 5.00% 4.00% 15.1$1)% 8.02% :5.88% 5.48% 53.00% :52.00% 65.58% C00.00) 8.13% 26.12 4.76 Spire lnc SR $65.81 4.10% 4.05% B.00% 5.24% 5.35% 5.48% 60.00-% 54.00% 65.58% c.so.oo• 8.93% 20.05 3.66 Vectren Corearatiort WC $55.95 5.70% 5.57% 7.00% 6.45% Ei.18% 5.48% 63.00-% 58.00% 65.58% &0.00 S.7.S% 2(],95 3,82 Meal'!; 8.73% Ma> 9.64% Min 7.79% Prajected Annual Earning$ pe-:r Share- 11s1 [16) [17] (18] [191 ra0J ra1J 1221 ra2i (24] (25) (26] (27] (28] (29) [30] 1311 Company ltcker 2015 2016 2017 2018 2019 :2.D20 2D21 2022. 2023 2024 2025 2026 2027 2028 2029 2030 2031 Bleiek Hill$ Carporatiol'I BKH . $2.83 .. $3,03 $3.24 $3.47 $3.72 $3.98 $4,26 $4,55 $4.85 $5,15 $5,47 $5.78 $6.10 $6.43 $CHS $7.16 $7.55 CentetPoln1 energy, Inc. C~P $1.08 .... $1.14 $1.20 $1.27 $1.34 51.41 51.49 $1.57 51.66 $1.75 $1.85 $1.95 $2.05 $2.17 $2.28 $2.41 $2.54 Chesapeake Utilities Corporatian CPK $2.6F 52.91 $3.16 $3.43 53.73 $4.05 54.40 $4.75 55.11 $5.47 $5.83 $6.18 $6.51 $6.87 $7.25 $7.65 $8.06 Northwe.!lit Naiural Gas Com1-':21ny r.lll\IN $1.96:. 52.05 $2.14 $2.24 52.34 52.45 52.56 $2.68 52.81 $2.96 $3.11 $3.27 $3.45 $3.64 $3.84 $4.05 $4.27 Sempra Energy SRE $5.23 .. $5.51 $6.02 $6.47 $6.94 57.45 57.99 $8.55 S9.13 $9.71 $10.30 $10.90 $11.50 $12.13 $12.79 $13.49 514.23 Southwest Gas Co-rporation swx .. $2.92. $3.09 $3.27 $3.47 $3.67 $3.89 $4.11 $4.35 S4.60 $4.BS $5.14 $5.42 $5.72 S6.D3 $6.36 $6.71 $7.08 Spire Inc SR ,· $3.16.. $3.33 $3.51 $3.89 $3.89 S4.10 S4.32 $4.55 $4.80 $5.06 $5.33 $5.62 $5.93 $6.26 $6.60 $6,96 $7.34 Vectren Ccirporation WC . $2.39 $2.54 $2.69 $2.86 $3.04 53.23 53.43 $3.63 $3.85 $4.07 $4.31 $4.55 $4.80 S5.06 $5.34 $5.63 $5.94 Pc'ofecled Atlriuai OMdend Payout Ratio [32) 133] l34l !35] [36] 137( [38] (39] (401 !41J (42[ [43] 1441 145] (461 Comj:!:any Ticker 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026 2027 202• 2D29 2030 2.031 Black Hills Corporation BKH 50.00% 50.50% 51.00% 51.50% 52.00o/a 54.26% 56. .53% 58.79% 61.05% 63.32% 65.58% 65.58% 65.58% 65,58% 55.53% Cen~erPoint t:n-ergy, Inc. CNP 82.00% SO.OD% 7B.OD% 76,00% 74.00% 72.61}% 71.19% 69,79% 6S.3e% 66jl8% 65,5!l% 65.58% 65.58% 65.58% 65.58% Chesapeake Utilities Co.rpota1ion CPK 45.00% 43.00% 41.00% 39.00% 37.00% 41.76% 46.53% 51.29% 56.05% 60.82% 65,58% 65.58% 65,58% 65.58% 65.58% Northwest Natural Gas Company NWN B0.00% 76.25% 72.50% 68.75% 65.00% 65.10% 65.19% 65.29o/o 65.39% 65.48% 65.58% -65.58% 65.58% 65.58% 65,58% Sempra Energy SRE 65,00% 64,.[]0% 63,00% 52.00% 61.00% 61.76% 1!52.53% 63.29% 64,05% 64.82% 65.58% 65.58% 1$5.58% S5.5B% 65.58% Southwelii-t Gas. Corporation l'JWX 5;l.00o/o 52.75% 52.50% 52.2&% 52.00% 54.26% :56.5:3% Slt79% 61.05% 63.32% 65.58% 65.58% 65.58% 65.5811/a. 65,58% Spire Irie SR 60.00% 58,50% 57.00% 55.50% 54.00% 55.93% 57.86% 5.9.79% 61.72% 63.-65% 65.58% 65.58% s5.5a% 65..58% 155.58% Ve:ctten Corporation we S3.00% 61.75% 60.50% 59.2S% 58.0D% 59.26% 60.53% 151.79% 63.05% 64.32% 65.58% 65.58% 65.58% 65.58% 65.5.8% Projected Annual Cash Fl.ows [47] [48] (49] [50] [51( [52] [531 f54J [55] [56] [57] [SS! [59J rs or [61] [62] Terminal Com1=1any Ticker 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026 2027 2028 2028 :2Cl30 2031 Value- Bloo:k: Hms Corporatton BKH $1.62 $1.75 $1.90 $2.05 $2.22 $2.47 $2.74 $3.03 $3.34 $3.86 $4.00 $4.22 $4.45 54.69 $4.95 $147.12 Center~oint Energy, lr.ie. CNP $0.99 $1.01 $1.04 $1.07 $1.10 S1.14 $1.18 51.22 $1.26 $1.30 $1.35 S1.42 $1.50 S1.58 $1.67 $56.32 Chesapeake Utilities Corpo.ratiiJon CPK $1.42 $1.48 Sl.53 $1.58 $1.63 $1.98 $2.38 52.81 $3.27 $3.76 $4.27 $4.51 54.75 $5.01 $5.29 $162.57 Northwes.t Natural Ga!Si Company NWN $1.71 $1.71 $1-70 $1-88 $1-67 51.75 $1.83 $1.93 $2.03 $2.14 $2.26 $2.39 S2.o2 $2.66 $2.BO $128.11 Sempra Energy SRE $3.92 $4.14 $4.37 $4.62 $4.88 $5.28 $5.71 $6.15 $6.60 $7.07 $7.54 $7.95 $8.39 SS.85 $9.33 $236.78 SoJJthwest Gas Corparatian swx $1.73 $1.83 $1.93 $2.03 $2.14 $2.36 $2.60 $2.86 $3.14 $3.43 $3.75 53.96 $4.17 $4.40 $4.64 5184.95 Splre ln.c SR $2.IO $2.16 $2.22 $2.28 $2.33 $2.55 $2.78 53.02 $3.29 $3,58 $3,89 $4.10 $4.33 $4.56 $4.B1 5147.23 Veirlreh CorE!ctiltion WC $1.70 $1.77 $1.84 $1.91 $1.99 $2,15 $2.33 $2.52 $2.72 $2.93 $3.15 $3.32 S3.50 S3.69 $3.89 5124.42 Projected Annual Data Investor Ca-sh F'lows [63] [64] (65] [66] [67] [68J [69] [70] [71) [72l [73] (741 [75] [76l [77] [78( [791 [80] lnltial Com pan}'. Ticker OlJUIDW 4128117 12131117 6/30/18 6130/19 5131lJ20 613D/21 6/30/22 6130/23 6130/24 6/30125 6130126 6/30127 6130/28 6130/29 6130/30 6130/31 6J:l0132 Blac.k Hlll& Cor!Jooration BKH ($64.03) $0,00 $1.10 $1.68 SUD $2,05 $2.22 52.47 $2,74 $3.03 $3,34 $3,Sfi S4.DD $4.22 S4.45 $4.69 $4.95 5152.07 CenterPoint Energy, Inc. CNP ($26.72) $0.00 $0.67 St.01 St.04 $1.07 $1.10 S1.14 $1.18 $1.22 S1.26 $1.30 $1.35 $1.42 $1.50 St.SS $1.67 $57.99 Chesapeake Utilities C.cirporatian CPK {$67.73) $0,00 $0.95 St.48 $1.53 $1.58 $1.63 St.88 $2.38 $2.81 $3.27 $3.7fi S4.27 $4.51 S4.75 55.01 $5.29 5167.86 Northwest. Natural Gas Compan-y NWN ($59.31) $0.00 $1.16 51.75 $1.70 $1.68 $1.67 $1.75 $1.83 $1.93 $2.03 $2.14 $2.28 $2.39 52.52 $2.66 $2.BO $130.92 Sempra Energy SRc {$106.86) $0.00 $2.65 $4.06 $4.37 $4.62 $4.88 $5.28 $5.71 $6.15 $6.60 $7.07 $7.54 $7.95 S8.39 $8.85 $9.33 5246.11 Sc-uthwest Gas Corporation = ($81.56) $0.00 $1.17 $1.79 $1.93 $2.03 $2.14 $2.36 $2.60 $2.86 $3.14 $3.43 $3.75 53.96 $4.17 54.40 $4.64 $189.59 Sp-irelnci SR ($85.81) $0.00 $1.42 $2.16 $2.22 $2.28 $2.33 $2.55 $2.78 $3.02 $3.29 $3.58 $3.89 $4.10 $4.33 $4.56 54.BI $152.04 Vec:tren Co~oratiein WC [$55.95) $0.00 $1.15 $1.75 $1.84 $1.91 $1.99 $2.15 $2.33 $2.52 $2.72 $2.93 $3.15 $3.32 $3.50 $3.69 S3.89 $128.32 Attachment RBH-4 Page 5 of 20 M11lti·Sti1geo Growth Disc:ounted Ceieh Flo-w MGdel 90 Daiy Average Stock Pcice High i=~s Growth Rate Es:tlmate 111 First Stage Inputs [1] 1;2] 131 [4] [5] [6] l7J [8] [9] !101 [11] !12] (13] 114] Stocik ---~E=P~S~G=r~owth"-'v Componv Tlok•r 2015 2016 2017 2018 2D19 2020 2021 2022 2023 2024 2025 2026 2027 2028 2029 2030 2031 Block Hil!s Corporation BKH .:· $2.83.-_·.. 53.12 $3.45 $3.81 $4.20 $4.64 $5.12 S5.61 $6.1D $6.58 $7.05 $7.49 $7.91 $8.34 $8.80 $9.28 $9.79 Center?obtt Energy. Inc. CNP ·.. $1.08:..- $1.15 $1.21 $1.29 $1 .37 $1.45 $1-54 $1.63 $1.72 $1.82 Sl.93 $2.D3 $2.15 $2.26 $2.39 $2.52 $2.66 Chesapeake Utilltios Corporation CPK · ;. n.ss.:.: 53.07 $3.51 $4.01 $4.59 $5.25 $6.DO S6.78 $7.55 S8.30 SS.OD $9.63 $10.16 510.11 $11.30 $11.92 $12.57 NorthwestNoturalGosCompany NWN ··:$1.9S·>· S2.D8 $2.20 $2.33 $2.47 $2.62 $2.78 S2.94 $3.12 S3.30 $3.48 $3.68 $3.88 $4.DB $4.31 S4.55 S4.SO Semp"' Energy SRE .:$5.23:.-.'. $5.75 $6.31 $6.94 $7.62 SB.37 $9.20 $10.04 $10.88 $11.72 $12.53 613.31 $14.04 $14.81 $15.62 $16'18 $17.38 Southwest Gas CorporoUon S'w. :: $2.92-'.°.· $3.15 $3.41 $3.68 $3.98 S4.29 $4.64 $4.99 $5.35 $5.71 S6.D7 $6.43 $6.78 $7.15 $7.55 57.96 $8.40 Spirelno SR ··.-$3.1s:•.:· $3.41 $3.69 $3.98 64.30 $4.S4 $5.01 $5.39 $5.78 S6.17 $6.58 $6.95 $7.33 $7.73 $8.15 $8.60 S9.07 ~V~•otr=•~n... c~o"'~o"'~"""·o~"------~w~c~·:: $2.39:. · · ~S"2'"'.s... s_~$2".7~4 __ $~2~.9~3---=-$3".~13~--'S"3~.3.._5_~$"3~.5 ... 9_"'S3'-'.~83~-$~•~·o~8-~$4=-3.._3 _ _,S..,4."'59~--=-$4"".B"'5~-"S"'5."'12,..__--'$"'5'-'.4""0---=-$5,..,.7'"'0~--'S"6"'.o-'-1---=-s6"'.3'"'4'-- Projected Annual Dividend Payout Ratio 132J [33J [34] [35] (36] [37) [38] (39] [401 [41] [42] [43] [44] [45] [46] Com'Pany Ticker 2017 2018 2019 2020 2021 2022 ;m2a 2024 2025 2D26 2027 2028 2029 :!!030 2031 Slac.k Hllls Cl)rporation BKH 50.00% :50.50% :51.00% 51.50% 52.00-% 54.26% 56.53% 58.79% 61.05% 63.32% 65.58% 65.58% 65.58% 65.58% 65.58% CenterPDint Energy, Inc. CNP 82.00.% 8.0.00% 78.00% 7EUJO% 74.CO-% 72.60% 71 .19% 69.79% BS.39% 56.98% 65,58% 65.:58% 65,5,8% 155.58% 55.58% Chi!!:sapeak.er Utilflfes Corporation CPK 45.00% 43.00% 41,00% 39,00% 37.0D% 41.76% 46.53% 51.29% 56".(15% Ei0.B2% 65.58% 65.58% 65.58% 65.58% 65.58% Northwe$l: Natura.I G:i!I$ Company NWN · SO.OD% 76.25% 72.50% 68.75% 85.00% 65.10% 65.19% 65.29% 65,39% 65.43% D!S.58% 65.58% 155.58% 65.58% 65.58% Sempra Energy SRE 65.00% :64.00% 63.00% 62.00% 61.00% 61.76% 62.53% 63.29% 64.05% 64,82% 65,58% 65.58% SS,5.6% 65.58% SS.58% Southwe:St Gas Corpora1ion swx 53.00% 52.75% 52.50% 52..25% 52..00% 54.25% 56,53% 58.79% 61.05% 63,32% 65.58% 65.58% 65.58% 65.58% 65.58% Spirelno SR 60,00% 58,50% 57.D0% 55,50% 54.00% 55.93% 57.815% 59.79-% 61.72% 63.65% 65.58% 65.58% 155.58.% 65.58% 65.56% Vectren Corr:io~ation WC 63.00% 61.75% 60.50% 59.25% 58.00% 59.26% 60.53% 6:1.79-% 153.0:5% 64.32% 65.58% 65.58% 65.58% 65.56% 65.56% ?rejected Anllui!I Cash FIO'W'S [47] [48] 149) [50] [51] [52] [53] (54] [55] (561 [57] [58( [59] [SD] [61] [62) Termirial Company licker 2018 2019 2020 2021 2022 2023 2024 2025 2026 2027 2028 2029 2030 2D31 Valu-e Slack Hills Carporation BKH $1.72 $1.92 $2.14 $2.39 $2.66 $3.04 $3.45 $3.87 $4.30 $4.75 $5.18 $5.47 S5.77 $6.08 Sa.42 5151.05 CeriterPorrit Et1ergy, fno. CNP $1.00 $1.03 $1.07 $1.10 $1.14 $1.18 $1.23 $1.27 $1.32 $1.36 $1.41 51.48 S1.57 $1.65 $1.74 $56.42 Chesapeake Utilities CorporatiQn OPK $1.58 $1.72 $1.88 $2.05 $2.22 $2.83 $3.51 $4.26 $5.05 $5.86 $6.66 S7.03 $7.41 $7.82 SS.25 $172.50 Northwel!lt Naturaf Gas Company NWN $1.76 $1.78 $1.79 $1.BO $1.81 $U2 $2.D3 S2.15 $2.28 $2.4f $2.54 $2.68 S2.83 $2.98 $3.15 5128.S7 Sempra Energy SRE $4.10 $4.44 $4.80 $5.19 $5.61 $6.20 $6.81 S7.42 $8.03 $8.63 $9.21 $9.71 $10.25 $10.81 $11.40 5241.32 Southwest Gas Corpora:tt1m swx $1.81 $1.94 $2.09 $2.24 $2.41 $2.71 $3.02 S3.36 $3.71 $4.07 $4.45 54.69 S4.95 $5.22 $5.51 $187,21 Spire Inc SR $2.21 $2.33 $2.45 $2.58 $2.71 $3.02 $3.34 $3.69 $4.05 $4.42 $4.81 S5.D7 $5.35 $5.64 $5.95 $149.94 Vectren Corporation WC $1.72 $1.81 $1.SD $1.99 $2.08 $2.27 $2.47 $2.68 $2.89 $3.12 $3.36 $3.54 S3.74 $3.94 $4.16 $125.01 Prajeoted Anrtual Data lnve:$.tOr C;;i$h Flows [63] [64] [65] [66) (671 [68] [69] [70] 171] [72] [73] [741 [75] [761 [77] 178] [79] [80] fnitiaf Company 11c:r Multi-Stage: Growth Ol&counted Cash Flew Model 90 Day Average Stock Price Low EPS Growth. Rate Ee.timate in Fif$t Stage Input; {1] [31 [4] {5] )6] i7l [8] [9] 110) [11] [12] [13) [14] sto.ak _____EP_S_G_r_o_wth"va~~u-"•te-E~rf-~W~:n~tb~:n~-a;~w...... -Long: .. Terrr ?ayo-ut Ratio lte rative solution Terminal TermlnaJ Company Ticker Pfice Z21c:.k:s Flr$t Call Line Gr(lwth iG:ro'liVlh Growth 2017 2021 2027 Proof lRR PIE Rolio PEG Ratio BJack Hills Carporation BKH $64.03 5,DO% 10.38% 7.50% 5.41% 5,00% 5.48% 50.00% :52.00% 65.58%. $(l,00 8.53% 2.2.71 4.14 Cente:r.Poin.t Energy, l.ni;l:. CNP $26.72 5.00% 6.06% 6.00% 4.98% 4.98% 5.48% 82.,00% 74.00% 65.58% (!i0.00) 8.48% 23.09 4.21 Chesapeake LJfiflties Corporatic.n CPK $67.73 Ei.00% 6.1)0% 8.00% 14.38% 6.00% 5.48% 45.00% 37.00% 65.58% $0,00 8,33% 24.28 4.43 Northwest Natural Gas Company NWN $59.31 4.30% 4.50% 6.00% 3.4-6% 3,46% 5.48% 80,00% 6:5.00% 65.58% ($0.00l 7.60% 32.70 5.97 Sempra Ef"l;ergy SRE $106.86 B,70% U7% S.0{]% 2.73% 2.73% .S.48% 65.00% 61.00% 65.58% (SD.00,. 8.4:2% 23.55 4.30 Southwest Gas Cotporation swx. $81.56 5.00% 4.00% 6.50% 8.02% 4.00% 5.48% 53.00% 52.0fl% 65.58% (lj;0.00) 7.78% 30.14 5.50 Spire Inc SR $65.81 4.1D% 4.05% 8.00% 5.2:4% 4.05% 5.48% 60.QD% 54.00% -65,58% [$0,00) 8.61 % 2.2.11 4.03 Vectren Corpo:raticn WC $55.95 5,7D% 5.57% 7.00% 6,46% 5,57% 5.48% 63,00% 56.00% 6:5.56% $0.00 8.133% 21.94 4.00 Mean 8.30% Max 8.63% Min 7.6D% Projecte:d Annual Eaminns 1=1er Share [15] 116! [17) [18) (191 [?OJ [21] 1221 [23] [24] 125) [26] ]271 (2BJ [29] [30] [311 Company Ticker 2015 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026 2021 2028 2029 2030 2031 Black HiU& Corporation BKH $2.83,·. $2.S7 $3.12 $3.26 $3.44 $3.B1 $3.79 $3.99 $4.19 $4.41 $4.65 $4.90 $5.16 SS.45 SS.75 SS.06 56.39 Ce-nterPoint Energv. lnc:. CNP $1.08• $1.13 $1.19 $1.25 $1.31 $1.38 $1.45 $1.52 $1.60 SI.GS $1.77 $1.86 $1.97 52.07 52.19 $2.31 $2.44 Chesapeake Utilities Cc.rp-ora1:fon CPK $2.68. $2.84 $3.01 $3.19 $3.38 $3.59 $3.BO $4.03 $4.26 $4.51 $4.76 $5.03 $5.30 $5.59 S5J!O $6.22 S6.S6 Northwest Natural Gas Company NWN $1.96 .. $2.03 $2.10 $2.17 $2.25 $2.32 $2.40 $2.50 $2.60 $2.72 $2.BS $2.99 $3.16 53.33 $3.51 $3.70 $3.91 Semp!f'a Energv SRE $5.23• $5.37 $5.52 $5.67 $5.82 $5.98 $6.15 $6.34 $6.57 $6.84 $7.16 $7.52 $7.93 SB.36 oB.B2 $9.30 59.81 Southwest Gas Corpnraifon &N.<. . $2.92 .. $3.04 $3.16 $3.28 $3.42 $3.55 $3.69 $3.B5 $4.02 $4.22 $4.43 $4.66 $U1 SS.18 SS.47 $5.77 $6.08 Spire Inc: SR $3.16.:. $3.29 $3.42 $3.56 $3.70 $3.85 $4.01 $4.18 $4.37 $4.58 $4.81 $5.06 $5.34 $5.63 $5.94 $6.27 So.61 V-eetreri Corporation WC $2.39. $2.52 $2.66 $2.61 $2.97 $3.13 $3.31 $3.49 $3.69 $3.89 $4.10 $4.33 $4.57 $4.B2 SS.OB $5.36 $5.65 F':roJe.c:ted Anri~al Diivld&nd Payout R.aUo [32] [33) [34] [35) [36] )37[ [38] [39) )401 [41) 1421 [43) [44) (45] [46) Company licker 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026 2027 202B 2029 2113[] 2031 Bla:ck Hiiis Corpora"tion BKH .50.00% 50.50% 51 .OQ% 51.50% 52.DO% 54,2.6% 56.53% 58,79% 61,05% 63,:32% 65.58% 65.58% 65.58% 65.58% 65.58% CenterPoint Erte:rgy, lric, CNP 82.110% 811.00% 7B.D0% 76.00% 74.00% 72.60% 71.19% 69.79% 68,39% 66.98% 65.58% 85.58% 65.58% B5.5B% 65.58% Chesapeake LJtlilties. Cor~oratic.n CPK 45.00% 43.00% 41.00% l9.0Q% 37.1)0% 41.76% 46.53% 51.29% 56.05% 60.82% 65,5S% 65,58% 65,58% 65.58% 65.:58% Northwest Natural ~as CGmpany NWN 80.00% 76.25% 72.50% 68.75% 65.00% 65,10% 65.1:9% 65,29% 65,39% 65.4.8% 65.58% 65.58% 65.58% BS.SB% 65.58% Sempra EnerGY SRE 65.00% 64,00% 63.00% 6.2,011% 61.00-% 61.76% 62.53% 63.29% 64.05% 64.82% 65.58% 65.58% 65.58% 65.58% 65.58% So\Jthwest Gas Corporation swx. 53.00% 52.75% 52.50% 52.25% 52.00% :54,26% SEi,53% 5.El,7S% 6t.D5% 63.32% 65.58% BS.SB% SS.SB% 65.58% 65.58% Spire lnci SR 60.00% 58.50% 57.00% 55.5()% 54.CID% 55 ..93% 57.86% 59.79% 61.72% 63.65% 65.58% 65.58% 65.58% 135.58% 65.58% Ve-ctren Corr;:ioration we 63.00% 151 .75% EI0.50% 59.25% 58.00% 59.26% 60.53% 61.79% 63.05% 64.32% 55.58% 65.:58% 65.58% 65.58% 65.58% Projected Annua! Cash F!CIW$ [471 [48] [49] [50] [51) [52] [53] !54) [55) [56] [571 )SS! [59] )BO) (61[ [62] Te:rmlnal Ticker 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026 2027 2028 2029 2030 2031 Value- .Blac.k Hins Corporatic.n BKH S!.56 Sl.65 $1.75 $1.86 $1.97 $2.16 $2.37 $2.59 $2.84 $3.10 $3.39 $3.57 $3.77 $3.97 $4.19 $145.18 CerderPoint Energy, Inc. CNP so.es $1.00 $1.02 $1.05 $1.07 $1.10 $1.14 $1.17 $1.21 $1.25 $1.29 $1.36 $1.44 $1.51 $1.BO $56.23 Che$ai;i-eake Utilitie$ Corpo!f'a:tion CPK $1.36 $1.37 $1.39 $1.40 $1.41 $1.68 $1.98 $2.31 $2.67 $J.06 $3.46 $3.67 $3.87 $4.0B $4.30 $159.32 NQrtnwest Natural Gas Company NWN $1.68 $1.06 $1.63 $1.60 $1.56 $1.62 $1.69 $1.77 $1.86 $1.96 $2.07 $2.18 $2.30 $2.43 $2.56 $127.76 Ss-mpr:a Energy SRE 03.59 $3.63 $3.67 $3.71 $3.75 $3.92 $4.11 $4.33 $4.58 $4.87 $5.20 $5.48 $5.78 $6.10 $6.44 $231.14 Southwe$t Gu; Co:rpor.qtio~ $1.67 $1.73 $1.79 $1.86 $1.92 $2.09 $2.28 $2.48 $2.70 $2.95 $3.22 $3.40 $3.58 $3.78 $3.99 $1S3.32 Spire Inc =SR $2.05 $2.08 $2.11 $2.14 $2.17 $2.34 $2.53 $2.74 $2.97 $3.22 $3.50 $3.B9 $3.90 $4.11 $4.33 $146.14 Vectren Carpora:1ion we S1.6B $1.74 $1.BO $1.86 $1.92 $2.07 $2.23 $2.40 $2.59 $2.78 $2.99 $3.16 $3.33 $3.51 $3.71 $124.02 Projec.t&d Annu:a! Data l~vest~r Casb Flows [63] (64] [65) [66] [67] (68] [69) [70] [71] [721 [73] )74] [75) )76[ (77) (78[ [79] [BO] Initial Company TI-oker Outftow 4128117 12131117 6130118 6130119 6130120 6130121 6130122 6130123 6130124 6130125 6130126 6130127 6/J0/28 6/30129 6130130 6130131 6130132 131.aek Hilts Carpo-ration BKH ($64.03) $0.00 $1.06 $1.60 $1.75 $1.86 $1.97 $2.16 $2.37 S2.59 $2.84 $3.10 $3.39 $3.57 $3.77 $3.97 $4.19 $149.37 CenterPaint Energy, !nc. CNP ($26.72) $0.00 SD.56 $1.00 $1.02 $1.05 $1.07 $1.10 $1.14 S1.17 $1.21 $1.25 $1.29 $1.36 $1.44 $1.51 $1.60 $57.63 Che$apeake Utilitie:!!i Co.-poration CPK ($67.73) $0.00 $0Jl2 $1.40 $1.39 $1.40 $1.41 $1.66 $1.98 $2.31 $2.67 $3.06 $3.48 $3.67 $3.B7 $4.0B $4.30 $163.63 NQrthwest Nirtural Gas C-ornpany NWN (559.31) $0.00 $1.14 $1.71 $1.63 $1.60 $1.56 $1.62 $1.69 $1.77 $1.86 $1.96 $2.07 $2.!B $2.30 $2.43 $2.56 $130.32 Sempr.a Erlergy SRE ($106.86) $0.00 $2.43 $3.64 $3.67 $3.71 $3.75 $3.92 $4.11 $4.33 $4.58 $4.B7 $5.20 $5.48 $5.78 $6.10 $B.44 $237.57 Southwest Ga& Corpo:ratio:n swx [681.56) $0.00 $1.13 $1.71 $1.79 $1.86 $1.92 $2.09 $2.28 $2.48 $2.70 $2.95 $3.22 $3.40 $3.58 $3.78 $3.99 $187.31 Sp.Ire IM SR (665.81] $0.00 $1.39 $2.09 $2.11 $2.14 $2.17 $2.34 $2.53 $2.74 $2.97 $3.22 $3.50 $3.69 $3.90 $4.11 $4.33 $150.48 Vfl:ctrell Cnrporaticlll WC ($55.95) $0.00 $1.14 $1.72 $1.80 $1.86 $1.92 $2.07 $2.23 52.40 $2.59 $2.78 $2.99 $3.1B $3.33 $3.51 $3.71 $127.73 Attachment RBH-4 Page 7 of20 Mul~-Stago Grow1h Disoountod Cash Flow Model 180 Day Average :Stoek Ptlce Average EPS Growth Rate Estimate in First Stage Inputs 111 !!:I ~ [4] !51 [6] [7) 16] ~ [10j [11] [12) [13] [14] stock: EPS Growth Rafa Estimates LonguTem Payout Ratio tterative Solutfan Terrmn:al Terminal Value Retenf1on PEG C:om~any 11-cker Price Z..cks Fi :ProJac:ted Annual Dividend Payout Ratio (32] [33] [34] (35] [36] [37] [38] [39( [40] 1411 142] [431 [44] [45] [46] comeany Ticker 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026 2027 2028 2029 2030 2031 Btaek HUI$ Corporation BKH 50.00% 50.50% 51.00% 51.50% 52.00% 54.26% 56.53% 58.79% 61.05% 63.32% 65.58% 65.58% 65.58% 65.:58% 65.58% CenterPolnt Energy, Inc. CNP 82.00% 80.00% 78.00% 76.00% 74.00% 72.60% 71.19% 59.79% 68.M% 66.98% ·5s.58% S5.58% 85.58% 65.58% 65.58% Chesapeake UtiUtie:s Corporation CPK 45.00% 43.00% 41.00% 39,00% 37,00% 41.78% 46.53% 51.29% 56.05% 60.82% 65.56% 65.58% 65.58% 65.58% 65.58% Nofth'Ni!$t Natural Gas Compar.iy NWN B0.00% 76.25% 72.50% 68.75% 65.00% SS.10% 65.19% 65.29% 65,39% 65.48% BS.58% 65.58% 65.56% 85.58% 65.56% Sempra Energy SRE 65.00% 64.00% 63.00% 62.00% 61.00% 61.7S% 62.53% 03.29% 64.05'% 64.82% 65.58% 6"5.58% 65.58% -65.58% 65.58% Southwest Gas Corporation swx 53.00% 52.75% 52.50% 52.25% 52.00% 54.26% 56.53% SB.79% 81.05% 63.32% 65.56% 05.58% 65.58% 65.58% 65.58% Spire Inc SR 60.00% 58.50% 57.00% 55,50% 54.00% 55.93"/o 57.86% 59.79% 61.7:1.% 63.55% 65.58% aS.58% 65.58% 65.58% 65.58% Vectren Corporation WC 64.00% 61.75% 60.50% 59.25% 58.00% 59.26% 60.53% 61.79% 63.05% 64.32% 65.56% 65.58% 65.56% 65.58% 65.56% Projeded Annual Cash Flows [47] 148] [49] [50] [51] 152] [53] [54] (55] [56l [57) [58] 1591 [60] 161] [621 Terminal Company Ticker 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026 2027 2028 2029 2030 2031 Vafue Black Hills Corpor.afian BKH S1.62 $1.75 $1.90 52.05 $;1..22 $2.47 $2.74 $3.03 $3.34 $3.66 $4.00 $4.22 $4.45 $4.69 $4.95 $142.06 CenterPoint Ene:rgy, Inc. CNf> S0.99 $1.01 $1.04 $1.07 $1.10 $1.14 S1.18 $1.22 $1.26 $1.30 $1.35 $1.42 $1.50 $1.58 $1.67 $52.29 Chesapeake Uiilities Corporation CPK 51.42 $1.48 $1.53 $1.58 $1.63 $1.98 $2.38 $2.81 $3.;1.7 $3.76 $427 $4,51 $4.75 $5.01 $5.29 $157.51 Northwest Natural Gas Company NWN $1.71 $1.71 $1.70 $1.68 $1,67 $1.75 S1.83 $1.93 $2.03 $2.14 $2.26 $2.39 $2.52 $2.66 $2,80 $127.84 Sempra Energy SRE $3.92 $4.14 $4.37 $4.62 $4.86 $5.28 SS.71 $6.15 S6.60 $7.07 $7.54 $7.95 $8.39 $8.85 $9.33 $233.25 Southwest Gas. Corporation SWX 51.73 $1.63 $1.93 S2.03 $2.14 $2.36 $2.60 $2.86 $3.14 $3.43 $3.75 $3.96 $4.17 $4.40 $4.64 5173.46 Spire Inc SR $2.10 $2.16 $2.22 $2.28 $2.33 $2.55 $2.78 $3,02 $3.29 $3.58 $3.89 $4.10 $4.33 $4.56 $4.81 5144.86 Vectren Coreora1fon WC S1.70 $1.77 $1.84 $1.91 $1,99 $2.15 $2.33 $2.52 52.72 $2.93 $3.15 $3.32 $3,50 $3.69 $3.89 $117.11 PfDjeded An~ual Data Investor- Cash Flows 163] [64] [65] 166] [67( [68] [69] [701 [71] [72] [73] [74] 175] [76] (77) (78] [791 [SOJ n1t1a Company Tickel' Outflow 4128117 12131117 6130116 6130119 6130120 6130121 6!30122 6130123 6130124 6!30125 6/30126 6130127 6130128 6130129 6130130 6!30/31 6130132 Black Hills Corporaiion BKH ($61.79) $0.00 S1.10 $1.66 $1.90 $2.05 $2.22 $2.47 $2.74 $3,03 $3.34 $3.66 $4.00 $4.22 $-1.45 $4.69 $4.95 $147.02 CenterPoint Energy, lne. CNP ($24.91) S0.00 S0.67 $1.01 $1.04 $1.07 $1.10 $1.14 $1.16 $1.22 $1.2S $1.30 $1.35 $1.42 $1.50 $1.58 $1.67 $53.95 Chesapeake Uiflitles Corpomtron CPK ($65.49) S0.00 S0.96 $1.48 $1.53 $1.58 $1.63 $1.96 $2.38 $2.81 $3.27 $3.76 $4.27 $4.51 $4.75 $5.01 $5.29 $162.80 Northwest Natural Gas Company NWN ($59.19) SO.DO $1.16 $1.75 $1.70 $1.BS $1.67 $1.75 $1.83 $1.93 $2.03 $2.14 $2.26 $2.39 $2.52. $2.66 52.80 5130.65 Sempra Energy SRE ($105.28) SO.DO $2.65 $4.06 $4.37 $4.62 $4.88 $5.28 $5.71 $6.15 $6.60 $7.07 $7.54 $7.95 $8.39 $6.85 $9.33 5242.58 SouthWest Gas Col'pot.aUon swx ($76.46) S0.00 $1.17 $1.79 51.93 $2.03 $2.14 $2.36 $2.60 $2.86 $3.14 $3.43 $3.75 $3.96 $4.17 $4.40 $4.64 $178.12 Sptre Inc SR ($64.75) SO.DO $1.42 s2.1a $2.22 $2.28 $2.33 $2.55 $2.78 $3.02 $3.29 $3.58 $3.89 $4.10 $4.33 $4.56 $4.81 5149.67 Vectren Corponrtfon WC !S52.69l so.oo $1.15 $1.75 51.84 $1.91 $1.99 $2.15 $2.33 $2.52 $2.72 $2.93 $3.15 $3.32 $3.50 $3.69 $3.89 5121.00 Attachment RBH-4 Page 8of20 M:Lllti-stage Growth Di.scounted Ca:sh :Flo-w Model 180 Day Avera.ge Siock Pr[Qe High EPS Growth Rate Estimate in Fl«! Stage tn~uts 111 ~] [3] 141 !51 [6] [7! 18] [9] [10] 1111 [121 [131 [14] stock EPS Grawth R21te Estimate!!i Long-Tern PayotJtFta.tieo Iterative Solution Terminal rerminal Value Rete.ntion Company Tfc:k"&t F'~lee- .Zaoks Fir.s,tCall Une Grcwth Hig:h Growth Growth 2017 2021 2027 Proof IRR PIE Ratio PEG Ra1io Black Hille. C'°rpl)ration BKH $61.79 5.00% 1t>.33% 7.50% 5.41% 10.38% 5.48% 50.00% 52.00% 65.58% 1').00 10.12% 14.92 2.72 CentetPoirit Energy, Inc. CNP $24.91 5.00% 6.06% 6.00% 4.9a% 6".06% 5.48% 82.00% 74.00% 65.58% (S0,00) 8.99% 19.71 3,60 Chesapeake Utilities Corporation CPK $65.49 s.ooo/a 6.00% B.00% 14.38% 14.38% 5.48% 45.0D% 37,00% 65,58% C'°"OO) 10.68% 13.31 2.43 Northwest Natural Gas Campany NWN $59.19 4,30% 4.50% 6,00% 3,46% 6".00% 5.48% 80.00% 65.00% 65.58% (.SC.OQ) 8.07% 26.75 4.88 Sempra En-ergy SRE $105.26 8.70% 9.87% B.00% 2.73% 9.87% 5.48% 65.00% 61.00% 65.58% 1'0.CO 10.54% 13.68 2.50 SDuthwest Gas Corporillion swx $76.46 5.00% 4.00% 6.50% 8.02% 8.02% 5.48% 53.00% 52,00% 65.58% (S0.00) a.79% 20.93 3.82 Spire Inc SR $64.75 4.10% 4.05% 8.DO% 5.24% 8,00% 5,48% SD.00% 54,(]0% 65.58% (:SO.OO> 9.73% 16.26 2.97 Vectren Ca~oration WC 552.69 5.70% 5,57% 7.DD% 6.46% 7.00% 5.48% 153.00% 58.00% 65.56% r•o.oo> 9.21% 18.57 3.39 Mean e.52% Max 10.68% M[n 8.07% Praijec:.te-d Annuar Earnln.g$ per Sh are [15J [16] [17) [18] [19] [20] [21] 1221 [231 [24J ~5] [26] (27] [28) J29J !3°1 JM[ Company Licker 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026 20%1 2028 2029 2030 2031 Black Hills Corporation BKfl .. $2.83.... : $3,12 53.45 S3.B1 $4.20 $4.64 $5.12 $6.61 56.10 $6.S8 $7.05 $7.49 $7.91 $8.34 $8.80 $9.28 $9.79 CenterF'olnt Erie:rgy, Inc. CNP ... $1.08.... · $1.15 $1.21 $!.29 $1.37 $1.45 $1.54 $1.63 51.72 $1.82 $1.93 52.03 $2.15 $2.26 $2.39 $2.52 $2.66 Chesapeake Utilities CorporatiDn CPK · · s2.sa··.. $3.07 $3.51 $4.01 $4.59 $5.25 $6.0D $6.78 $7.55 $8.30 $9.00 $9.63 $10.16 $10.71 511.30 $11.92 512.57 Northwest Natural Gas Company NWN ... $1.96· .... $2.08 52.20 $2.33 $2A7 $2.82 $2.78 $2.94 $3.12 $3.30 S3.4B $3.BB $3.88 $4.09 $4.31 $4.55 $4.80 Sempra Energy SRE .. S5.23 ... $5.75 SB.31 SB.94 $7.62 $8.37 $9.20 $1D.04 $10.68 S11.72 $12.53 $13.31 $14.04 $14.81 515.62 $16.48 $17.38 Southwest Gas Corparatian swx :·... 52.92:.. ·: $3.15 $3.41 S3.68 $3.98 $4.29 $4.64 $4.99 $5.35 $5.71 ss.07 $6.43 $6.78 $7.15 $7.55 $7.96 $S.4D Splrel11c SR $3.16...... $3.41 $3.69 SJ.SS $4.30 $4.64 $5.01 $5.39 $5.78 $6.17 SB.56 $6.95 $7.33 $7.73 $8.15 $8.60 $9.07 Veotre-n Cor~0oratit1on WC $2.39. $2.56 52.74 $2.93 $3.13 $3.35 $3.59 $3.83 $4.08 $4.33 $4.59 $4.85 $5.12 $5.40 $5.70 $6.01 $6.34 ?tQ.jected Annual Olvidend ?ayD1.1t Ra:tio [321 [33] ·(34] [35] [36] ran [38) [39] [40] [41] [42] [43) )44] [4'i) )46] camE!:anx licker 2017 2018 2Q19 2020 2021 2022 2023 2024 2025 2026 2027 2028 2029 2030 2031 Bl:ack Hills Corporation BKH 50,ill0% 50,50% 51,00% 51.50% 52,00% 54.26% 56,53% :56.79% 61.05% 63.32% 65.58% 65.58% 65.58% 65.5.8.% Ei5.5a.% CenterPoint Energy, !no. CNP 82.00% 80.00% 78.00% 76.00% 74.00% 72.60% 71.19% 69.7.9% 6.8.3.9% 66.98% 65.58% 65.58% 65.58% 65.58% 65,58.% Chesapeake 1.Jlillties CorpQration; CPK 45.00% 43.00% 41.00% 39.00% 37.00o/o 41.'76% 46.53% 51.29% 56,05% 60,82% 65,58% 155.58% 65.51!1-% 65.58% 65.58% Northwut Natural Gas Company NWN !O.OQ% 76.25% 72,50% 68,75% 65,00% 65.10% 65,19% 65.29% 65.39% 65.48% 65.58% 65.58% 65.58% 65.53% 65.58% Se:mpra Energy SRE 65.00% 64.00% 6:S.00% 62.00% 61.00% 61.76% 62.53% 63.29% 64.05% 64.82% 65.56% 65.58% 65.58% 65.58% 65,58% Southwest Gas Corpe.ration swx 53.00% 52.75% 52.50% 52.25% 52.00% fi4..26:% 56.53% 58.78% 61.05% 63.32% 65.5S.% 65,56% 65,Sa.% 65,58% 65.58% Spire Inc SR 60.00% 56.50% 57.00% 55.5Do/o 54.00% 55.93% 57.86% 59,79% 61.72% 63,65% 65.56% 65.58% 65.58% 65.58% 65.58% Vec:1ren Corpor.atlon WC 63.0Q% 61.75% 60.50% 59.25% 5&.00% 59.2.6% em.53% 61.79% 15'3.05% 64.32% 65.58% 65.58% 65.58% 65.58% 65.68% Projected Annual C-ash Flow& [47] {481 [49] [50] [51] [52] [53] [54] [551 [56] [571 [58] . [59] [60] [61] [52) lerminal Co mean:! Ticker 2017 .2018 2019 2020 2021 2022 2023 2024 2025 2026 2027 2028 2029 2030 2031 Value Black Hills Corporation BKH $1.72 S1.92 $2.14 $2.39 $2.06 S3.04 $3.45 $3.87 S4.30 S4.75 $5.18 $5.47 $5.77 SS.OS $6.42 $145.98 CenterPoint Energy, Inc. CNP $1.00 $1.03 $1.07 $1.10 $1.14 51.18 $1.23 $1.27 S1.32 S1.36 $1.41 $1.48 $1.57 $1.65 $1.74 $52.39 Chesapeake Uttl[fies Ccrporatiorm CPK $1.58 S1.72 $1.88 $2.05 $2.22 S2.83 $3.51 $4.26 S5.05 $5.86 $6.66 $7.03 $7.41 $7.82 $8.25 $167.38 Northwest NatLlraf Gas Company NWN $1.76 S1.78 $1.79 $1.BO $1.81 S1.92 $2.03 $2.15 S2.28 $2.41 $2.54 $2.68 $2.83 $2.98 $3.15 $128.40 Sempra Energy Sl'tE $4.10 $4.44 $4.80 $5.19 $5.61 56.20 $6.81 $7.42 56.03 $8.63 $9.21 $9.71 $10.25 $10.81 $11.40 $237.78 Southwest Gas Carporatfon swx $1.81 S1.94 $2.09 $2.24 $2.41 52.71 $3.02 $3.36 S3.71 $4.07 $4.45 $4.69 $4.95 $5.22 $5.51 $175.72 S~l:re Jr.ii::. SR $2.21 $2.33 $2.45 $2.58 $2.71 53.02 $3.34 $3.69 54.05 $4.42 $4.81 $5.07 $5.35 SS.64 $5.95 $147.56 Vec1ren Cor~Dration WC $1.72 SUI $1.90 $1.99 $2.0B S2.27 $2.47 $2.68 S2.89 S3.12 $3.36 $3.54 $3.74 $3.94 $4.16 $117.69 Proje.cte.d Annual Data Investor C:ash f"lows. [63) [64] [65) [65) [67] [68) )69] [70] [71] (72] [73) [74] [75] [76] [77] [78] [79] [80] lm:tial Company Ticker Outflow 4128117 12131117 6130118 6130119 6130120 8/30121 6130122 6/30123 6130124 6130/25 S/30.126 6/30127 6130(28 6130129 6130130 6130131 6130/32 B!ac:k Hiiis Corporationi BKH ($61.79) $0.00 $1.17 $1.81 $2.14 $2.39 $2.66 S3.04 $3.45 $3.87 54.30 $4.75 S5.18 $5.47 $5.77 $6.08 $6.42 $152.40 CenterPotnt Eni::rgy, Inc. CNP ($24.91) $0.00 $0.67 $1.03 $1.07 $1.10 $1.14 $1.18 $1.23 $1.27 51.32 $1.36 51.41 $1.48 $1.57 S1.65 51.74 554.13 Ches-apeake- Utellties Corporaiion CPK ($65.49) $0.00 $1.07 $1.59 $1.88 $2.05 $2.22 52.83 $3.51 $4.26 S5.05 $5.86 $6.66 $7.03 $7.41 $7.82 $8.25 $175.63 No.rthwee;1 Natura[ Gas Company NWN ($59.19) $0.00 S1.19 51.BI $1.79 $UO $1.81 51.92 $2.03 $2.15 52.28 $2.41 $2.54 $2.68 $2.83 $2.98 $3.15 $131.55 Sempra Energy Sl'tE ($105.28) $0.00 52.78 $4.31 $4.80 $5.19 $5.61 $6.20 $6.81 $7.42 SB.03 $8.63 $9.21 $9.71 $10.25 $10.81 $11.40 $249.18 Southwest G~s Corporetlcm swx ($76.46) $0.0D $1.22 S1.88 $2.09 $2.24 $2.41 52.71 $3.02 $3.36 53.71 $4.07 $4.45 $4.89 $4.95 SS.22 $5.51 $181.23 Spire Inc:: SR ($64.75) $0.00 $1.50 52.30 $2.45 $2.58 $2.71 S3.02 $3.34 $3.69 $4.05 $4.42 $4.81 $5.07 $5.35 SS.64 $5.95 $153.51 Vectren Ccrpondfon WC ($52.69l $0.00 51.17 51.78 $1.90 $1.99 $2.08 S2.27 $2.47 $2.68 S2.S9 $3.12 $3.36 S3.54 $3.74 $3.94 $4.16 $121.84 Attachment RBH-4 Page 9of20 Multi-Stag& Growth Oiscoun1ed C-ash Flew Mode[ 180 Day Average Stock Price Low EPS Gri:iwth R:ate Estim:ate in Fir.$t stage lnE!uts [1] ~l !3] !4] [5] l6J IZl [8] !91 1101 [111 [12] [13] [141 Stoek EPS Growth Riitle .E~timfiles Lor.ig-Ter11 Payout Ratio Iterative Solution Terminal Terminal Value- Retention Low Company Ticker Prioe Zaol C.ompan:i Ttck:er 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026 2.02.7 2028 2029 2030 2031 Bfack Kiiis Corporation BKH $2.83 $2.97 $3.12 $3.28 $3.44 $3.61 $3.79 $3.99 $4.19 $4.41 $4.65 $4.90 S5.16 $5.45 SS.75 $6.06 $6.39 Cerite-rPQlnt Energy, lnr::. CNP $1.08: $1.13 $1.19 $1.25 $1.31 $1.38 $1.45 $1.52 $1.SD $1.68 $1.77 $1.86 $1.87 $2.07 $2.19 $2.31 $2.44 Chesapeake Utilities Carpotatian CPK .. $2.68 $2.84 $3.01 $3.19 $3.38 $3.58 $3.80 54.03 $4.26 $4.51 54.76 $5.03 $5.30 $5.59 55.90 $6.22 $6.56 Northwa-st Natural G.as Compal"iy NV\IN .. $1.96. $2.03 $2.10 $2.17 $2.25 $2.32 $2AO S2.50 $2.SO $2.72 S2.85 $2.99 $3.16 $3.33 $3.51 $3.70 $3.91 Sempra Energy SRc . $5.23. $5.37 $5.52 $5.67 $5.82 $5.98 $6.15 S6.34 $6.57 SS.84 $7.16 $7.52 $7.93 $8.36 SB.82 $9.30 $9.81 SouttiwestGas CC1rpora1ion swx $2.92· $3.04 $3.16 $3.26 $3.42 $3.55 $3.69 $3.85 $4.02 $4.22 $4.43 $4.66 $4.61 $5.18 55.47 S5.77 $6.08 Sp!re Inc SR $3.16 $3.29 $3.42 $3.56 $3.70 $3.85 $4.01 S4.18 $4.37 $4.58 $4.81 $5.06 $5.34 $5.63 $5,94 SS.27 $6.61 V!!!.ctre-n Corporatian WC: $2.39 $2.52 $2.66 $2.81 $2.97 $3.13 $3.31 $3.49 $3.69 $3.88 $4.10 $4.33 $4.57 $4.82 SS.OB $5.36 $5.65 Projected Annual Oivldend :Payout Ratio [32] [33] [34] [35] [36] [37] 138] [39] [40] [411 [42] [43] [44] [45] [461 Cl)m:e;ariJ: lie:ker 2017 2018 2019 2020 2021 2022 2Cl23 2024 2025 2026 2027 2028 2029 :11030 2f'.131 Black Hills CDtpara1ian BKH 50.00% OD.50% 51.0i0% st.50% 52.00% 54.26% 56.53% sa.7e% 61.05% 63.32% 65.58% 65.58% 65.58% 65.58% 65.58% CenterPoint l::nergy, Inc. CNP 82.00% 80.00% 78.00% 76,0C% 74.00% 72.,60% 71.19% 69.79% 68.39% 66.98% 65.58% 65.52% 65.58% 65.58% 65.58% Chesapeake utiliti~ Corporation CPK 45.00% 43.00% 41.00% 39.00%. 37.00% 41.76% 46.53% 51.29% 56.05% 60.82% 65.58% 65.58% 65.58% 65.58% 65,58% Nol'Ehwest Natur.al Gas Comp.any NWN BD.00% 76.2.5% 72,50% 68.75% 65.00% 65.10% 65.19% 65.29% 65.39% 55,46% 65,58% 65.58% 65. .58% 65.58% 65.58% Sempra Ener,gy SRE 65.00% 64.00% 63.00% 62.00% 61.QCJ.% 61.76% 62.53% 63.29% 64.05% 64.82% 65.58% 65.58% 65.58% S5.5S.% 65. .58% Southwest Gas Corpe ration &NX 53.00% 52.75% 5:2.5()% 52..25% 52.00% 54.26% 56.53% 56.79% 61.05% 63.32% 65.58% 65.58% ISS.5:EI% 65.58% 65.58% Sp[re Jn~ SR 60.00% 58.5D% 57.QO% 55.50% 54.00% 55.93% 57,86% 59.79-% 61.72% 63.65% 65.58% 65.58% 65.5!% 65.58% S5.S.S% Vec:tren Corporation WC 63.00% 61,75% 60,50% 59.25% 58.0Do/o 59.26% 60.53% 61.79% 63.05% 64,32% 65,52% EiS.5B.% 65.58% 65.58% 65.56% Pro]er::te-d Annual Cash Flaws [47l [48] [49] [501 [51] [52] [53] [541 [551 [56] [57] [581 [59] [601 [61] [62] Terminal Comp:&1ny Tioker 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026 2027 2028 2029 2ll3D 2031 Vatue Black Hi!l!!I Ceirpo-ratio-n BKH S1.56 S1.65 $1.75 $1.86 S1.97 $2.16 $2.37 S2.59 $2.84 $3.10 $3.39 $3.57 $3.77 $3.87 $4.19 $140.14 CentetPoirit 5riergy, Inc. CNP S0.98 $1.00 $1.02 S1.05 $1.07 $1.10 $1.14 $1.17 $1.21 $1.25 $1.29 $1.36 $1.44 St.51 $1.60 $52.20 Chesapeake Utili:lies Corporation CPK 51.35 $1.37 $1.39 $1.40 $1.41 $1.68 $1.98 52.31 $2.67 $3.06 $3.48 53.67 $3.87 S4.D8 $4.30 5154.27 N.orlbwest Naiural Gas Company NWN $1.68 $1.66 $1.63 $1.60 $1.56 $1.62 $1.69 $1.77 $1.86 $1.96 $2.07 $2.18 $2.30 $2.43 52.56 $127.49 Se:mpra Erietgy SRE $3.59 $3.63 $3.67 $3.71 $3.75 $3.92 $4.11 $4.33 $4.58 $4.87 $5.20 $5.48 SS.78 $6.10 56.44 $227.61 Scn1thWe&t Ga& Ccrpot"ati1.m swx $1.67 $1.73 $1.79 $1.86 51.92 $2.09 $2.2/l 52.48 $2.70 $2.95 $3.22 $3.40 $3.58 $3.78 S3.99 $171.86 Spire Inc SR S2.05 $2.08 $2.11 $2.14 $2.17 $2.34 $2.53 $2.74 $2.97 $3.22 $3.50 $3.69 $3,80 $4.11 $4.33 5143.77 Vectren Corporation WC $1.68 $1.74 $1.80 $1.86 $1.92 $2.07 $2.23 S2.40 $2.59 $2.78 $2.99 $3,16 $3.33 $3.51 $3.71 $116.70 Projei:ited Arinual Data tnV&$tor Cae.h FIOW$ [63] [64] [65l [66] [67] [68] [69] [70] [71] 1n1 [73] [74] [75] [761 [77] 178] [79] [aD] Initial Compa.nx Tkill:el' OtltftGW 4128117 12131117 6130118 6130119 6130120 6130121 6130122 6130123 6130124 6/30125 6130126 6/30127 6130128 6130129 6130130 6/30/31 6130/32 Black Hflls Corporation BKH ($61.79) $0.00 $1.06 51.60 $1.75 S1.86 $1.97 $2.16 $2.37 $2.59 $2.84 $3.10 $3.39 $3.57 $3.77 $3.97 $4.19 $144.33 CenterPoint Energy, !rm. CNP ($24.91) $0.00 S0.66 $1.00 $1.02 S1.05 $1.07 $1.10 $1.14 $1.17 $1.21 $1.25 $1.29 S1.3fi $1.44 $1.51 $1.60 $53.80 Chesapeake Utilities Cc>i·porati:on CPK ($65.49) $0.00 $0.92 $1.40 $1.39 $1.40 $1.41 $1.68 $1.98 $2.31 $2.67 $3.06 $3.48 $3.67 $3.87 $4.08 $4.30 $158.58 No-rthw.est Natural Gas Company NWN ($59,19) $0.00 $1.14 51.71 $1.63 51.60 S1.56 $1.62 $1.69 $1.77 $1.86 $1.96 $2.07 $2.18 $2.30 $2.43 $2.56 $130.05 Sempra Energy SRE {$105.28) $0.00 $2.43 $3.54 $3.57 $3.71 S3.75 $3.S2 $4.11 $4.33 $4.58 $4.87 $5.20 $5.48 $5.78 $6.10 $6.44 $234.05 Southwe-.st Gas Corporation swx ($76.46) $0.00 $1.13 S1.71 $1.79 $1.86 S1.92 $2.09 $2.28 $2.48 $2.70 $2,95 $3.22 $3.40 $3.58 $3.78 $3.98 $175.84 Spire Inc: SFt ($64.75) $0.00 S1.39 S2.09 $2.11 S2.14 S2.17 $2.34 S2.53 $2.74 $2.97 $3.22 $3.50 $3.69 $3.90 $4.11 $4.33 $148.11 Vectren Co~ol'atian WC ($52.89) $0.00 S1.14 $1.72 $1.80 $1.86 $1.92 $2.07 $2.23 $2.40 $2.59 $2.78 $2.99 $3.16 $3.33 $3.51 $3.7\ $120.41 Attachment RBH-4 Page 10 of20 Multi-Stage DCF Notes: [1] Source: Bloomberg; based on 30-, 90-, and 180-day historical average as of April 28, 2011 [2] Source: lacks [3] Source: Yahool Finance [4] Source: Value line [5] Source: Attachment RBH-3, Value Line [6] Equals indicated value (average, minimum, maximum) from Columns [2], [3], [4], [5] [7] Source: Federal Reserve, Bureau of Economic Analysis, Blue Chip Financial Forecas· [BJ Source: Value Line [9] Source: Value Line [1 OJ Source: Bloomberg Professional [11] Equals Column [1] +Column [63] [12] Equals result of Excel Solver function; goal: Column [11] equals $0.0C [13] Equals Column [62) I Column [31] [14] Equals Column [13] I (Column [7] x 100) [15) Source: Value Line [16) Equals Column [15] x (1 +Column [BJ) [17] Equals Column [16] x (1 +Column [BJ) [18] Equals Column [17] x (1 +Column [6]) [19] Equals Column [18] x (1 +Column [6]) [20] Equals Column [19] x (1 +Column [BJ) [21] Equals Column [20] x (1 +Column [6]) [22] Equals (1 +(Column [6] +(((Column [7]- Column [6]) I (2027-2022+1))x(2022-2021)))) xColumn [21] [23] Equals (1 +(Column [6] +(((Column [7]- Column [6]) I (2027 - 2022 + 1)) x (2023 - 2021)))) x Column [22] [24] Equals (1 +(Column [SJ+ (((Column [7]- Column [SJ) I (2027 - 2022 + 1)) x (2024 - 2021)))) x Column [23] [25] Equals (1 +(Column [SJ+ (((Column [7]- Column [6]) I (2027 - 2022 + 1)) x (2025 - 2021)))) x Column [24] [26] Equals (1 +(Column [SJ+ (((Column [7]- Column [61) I (2027 - 2022 + 1)) x (2026 - 2021)))) x Column [25] [27] Equals Column [2B] x (1 +Column [7]) [28] Equals Column [27] x (1 +Column [71) [29] Equals Column [28] x (1 +Column [7]) [30] Equals Column [29] x (1 + Column [7]) [31] Equals Column [30] x (1 + Column [7]) [32] Equals Column [6] [33] Equals Column [32] + ((Column [36] - Column [32]) I 4) [34] Equals Column [33] + ((Column [3B] - Column [32]) I 4) [35] Equals Column [34] + ((Column [3B] - Column [32]) I 4) [3B] Equals Column [9] [37] Equals Column [3B] + ((Column [42] - Column [36]) I B) [38] Equals Column [37] + ((Column [42] - Column [36]) I B) [39) Equals Column [38] + ((Column [42] - Column [36]) / 6) [40] Equals Column [39] + ((Column [42] - Column [36]) / B) [41] Equals Column [40] +((Column [42]- Column [3B]) / B) [42] Equals Column [10] [43] Equals Column [10] [44] Equals Column [10] [45] Equals Column [10] [46] Equals Column [10] [47] Equals Column [17] x Column [32] [48] Equals Column [18] x Column [33] [49] Equals Column [19] x Column [34] [50] Equals Column [20] x Column [35] [51] Equals Column [21] x Column [36] [52] Equals Column [22] x Column [37] [53] Equals Column [23] x Column [36] [54] Equals Column [24] x Column [39] [55] Equals Column [25] x Column [40] [56] Equals Column [26]x Column [41] [57] Equals Column [27] x Column [42] [58] Equals Column [28] x Column [43] [59] Equals Column [29] x Column [44] [60] Equals Column [30] x Column [45] [61] Equals Column [31] x Column [46] [62] Equals (Column [61] x (1 +Column [7])) I (Column [12]- Column [7]) [B3] Equals negative net present value; discount rate equals Column [12], cash flows equal Column [64] through Column [60 [64] Equals $0.00 [65] Equals Column [47] x (12/31/2017 - 412812017) / 36E [66] Equals Column [47] x (1 + (0.5 x Column [6])) [67] Equals Column [49] [68] Equals Column [50] [69] Equals Column [51] [70] Equals Column [52] [71] Equals Column [53] [72] Equals Column [54] [73] Equals Column [55] [74] Equals Column [5B] [75] Equals Column [57] [76] Equals Column [58] [77] Equals Column [59] [78] Equals Column [60] [79] Equals Column [B1] [BO] Equals Column [B1] + [62] Attachment RBH-4 Page 11 of20 Multi-Stag& Gra.wlh Discouniec:I C:esh Flow McdeI 30 Day Average Sto.ck :Piice: Avera,ge E?s Growth fi:a1e Estimate In First Stage Input. [1] [21 [3] 141 [51 [6J [7] [BJ [9! [10] 1111 [12] (13] [14] Stoc:.k ----~CP~S~G~ro~wth=R~•~t•~•,.Rs<.;;;e~m;;;0~o;;,C':o----~Long-Terrr Payout R:afio Iterative Solution Te:rmlnal Terminal Tii::.lcer Price fft'$t Calf Value Line G"owth Aveira:ge Growth 2017 2021 2027 Proof IRR PIE Ratio PEG Ratio BJa.tk Hills Carporation Bl Ticker 2015 2016 2017 201B 2019 2020 2021 2022 2023 2024 2025 2026 2027 2028 2029 2030 2D31 Blaek Hms Corporation l!KH : $2.83: $3.03 $3.24 $3.47 S3.72 $3.98 $4.26 $4.55 $4.85 $5.16 S5.47 $5.78 S6.10 S6.43 $6.78 57.16 $7.55 CenterPoint Ener'1!f, Inc. CNP .. SI.OB· $1.14 $1,20 $1.27 61.34 $1.41 $1.49 $1.57 $1.66 $1.75 S1.B5 $1.95 $2.05 52.17 52.28 $2.41 $2.54 CE'llll:Sapearr:e Utllitle$ Corp°'ratlon CPK ·· s2.eB: $2.91 $3.16 $3.43 $3.73 $4.05 $4.40 $4.75 $5.11 $5.47 $5.83 $6.18 $6,51 $6.87 $7.25 87.65 SB.06 North.west Natural Gas CDmpany NWN ... S1.96· $2.05 $2.14 $2.24 S2.34 $2.45 S2.56 $2.68 $2.81 $2.96 S3.ll $3.27 63.45 $3.64 $3.B4 $4.05 54.27 Sempra Eneri;w SRE 55.23: $5.61 $6,02 $6.47 SB.94 $7,45 57.99 $B.55 $9.13 $9.71 $10.30 .$10.90 $11.SO $12.13 $12.79 $13.49 $14.23 Southwe$t Ga:e Corpor.ation swx: $2.92 $3.09 $3.27 $3.47 $3.67 $3.89 $4.11 $4.35 $4.60 $4.86 $5.14 $5.42 SS.72 $6.03 $6.36 $6.71 57.08 Splre Inc SR $3.16· $3.33 $3.51 $3.69 S3.89 $4.10 S4.32 $4.55 $4.80 $5.06 55.33 $5.62 65.93 S6.26 $6.60 $6.96 57.34 Vectren Corporation we $2.39 $2.54 $2.69 $2.B6 63.04 $3.23 $3.43 $3.63 $3.B5 $4.07 64.31 $4.55 $4.90 SS.06 $5.34 $5.63 $5.94 ProJec.ted Annuat Divfdend Payout Ratio [32] (33] [34] [35] [36] [37] [3B] (39! [40] [41] [42] [43] [44] [45) [46] Ticlcer 2017 201B 2019 2020 2021 2022 2023 2024 2025 2026 2027 2028 202• 2030 2031 Black Hill::;. Corporatlon BKH ·. ·· 50.00% 50.50% 51.00% 51.50% .52..00% :64.2.6% 56.53% 58.79% S1.D5% 63.32% 65.58% 65.5:8% 55.58% 65.58% 65,58% CenterPoint Energy, tm~. CNP ... S:Z.00% 80.00% 78.00o/a 76.00% 74.00% 72.60% 71.19% 69.79% 68.39% S6 ..9&% S5.fi0% 65.58% 65.5B% 65.58% 65.58% Chesapeake Utilities Corporation ~: :·:•·: ..... ·... ··· 45.00% 43.00% 41,1}0% 39,00% 37,DO% 41.76% 46.53% 51.29% 56.05% 60.82% -65.58% 65.58% 65.58% 65,58% -65.58% Northwe Proje ote d Annual Cash:Fio.ws [47] [48] [49] [50] [51] [52] !53( [54] 155] [56] 1571 [58] [59( [60] [611 [52] Termin~I Company Tieker 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026 2027 2029 2030 2031 Value Blacik" HUis Corparatici11 BKH $1.62 $1.75 $1.90 $2.05 S2.22 $2.47 52.74 $3.03 $3.34 $3.66 $4.00 $4.22 $4.45 S4.69 $4.95 $185.33 CenterPoint Ener,mr, Inc. CNP $0.99 $1.01 $1.04 $1.07 $1.10 $1.14 51.18 $1.22 $1.26 $1.30 $1.35 $1.42 SI.SO S1.58 $1.67 $62.41 Chesapeake Utiltties Corporation CPK $1.42 $1.48 $1.53 $1.58 S1.63 $1.9B S2.3B $2.81 $3.27 $3.76 $4.27 $4.51 54.75 $5.01 $5.29 $1S7.97 Northwest Naturat Gas Company NWN:.:: $1.71 $1.71 $1.70 $1.BB $1.67 $1.75 $1.83 $1.93 $2.03 $2.14 $2.26 $2.39 $2.52 $2.66 $2.BO $104.95 Sempf" Energy SRI; $3.92 $4.14 $4.37 $4.52 $4.BB $5.2B S5.7! $6.15 $6.60 $7.07 $7.54 $7.95 $8.39 SB.BS $0.33 $349.46 Southwest Ga~ Co(poratleon swx .. $1.73 $1.83 $1.93 $2.03 $2.14 $2.36 S2.60 $2.86 $3.14 $3.43 $3.75 $3.96 $4.17 $4.40 $4.64 $173.85 Spire Inc SR $2.10 $2.16 $2.22 $2.2B 52.33 $2.55 52.78 $3.02 $3.29 $3.5B $3.89 $4.10 $4.33 $4.56 $4.81 $180.24 Veo:tfE!fl Corpora1i1m WC $1.70 $1.77 $1.84 $1.91 SU9 $2.15 S2.33 $2.52 $2.72 $2.93 $3.15 $3.32 $3.50 $3.69 $3.89 $145.80 Proje-Ql:l!!d Annual Data fnvestor Caeih Flo'INS [63] [64] 165] [66] [67] [68) [70] [71) [72] [73] [74] [75( [76] [77) [78] )791 (BO] Jnitial Cctnpanv Tloker Ootllow 412Bl17 12131117 6130118 6/30119 6130120 6130121 6130122 6130123 6130124 6130125 6130126 6130127 6/30128 6130/29 6/30130 6130131 6130132 $lack Hibs Corporation BKH ($67.07) $0.00 $1.10 $1.68 51.90 $2.05 $2.22 $2.47 $2.74 $3.03 53.34 $3.66 $4.00 $4.22 $4.45 $4.69 $4.95 $190.28 Cenier?o!nt Energy, Inc. CNP ($27,94) $0.00 $0.67 $1.01 51.04 $1.07 $1.10 $1.14 51.1B $1.22 51.26 $1.30 51.l5 $1.42 $1.SO $1.58 $1.67 $64.08 Chesapeake Utilffiei$ Co-rpofeti:on CPK ($70.37) $0.00 $0.96 $1.48 S1.53 $1.58 $1.63 $1.9B 52.3B $2.81 $3.27 $3.76 54.27 $4.51 S4.75 $5.01 $5.29 $203.26 Northwest Naturat Gas Company NWN ($59,56) $0.00 $1.16 $1.75 S1.70 $1.BB S1.67 $1.75 $U3 $1.93 52.03 $2.14 52.26 $2.39 52.52 $2,66 $2.80 $107.75 Semp:ra Energy SRE ($111.49) $0.00 $2.65 $4.06 54.37 $4.62 S4.B8 $5.26 55.71 $6.15 $6.60 $7.07 $7.54 $7.95 58.39 $B.85 $9.33 $358.79 S-outhw&$t Gas Cori:io-ra1ion swx ($83.71) $0.00 $1.17 $1.79 51.93 $2.03 $2.14 $2.36 $2.60 $2.86 $3.14 $3.43 53.75 $l.96 S4.17 $4.40 $4.64 $17B.50 Spire lne SR ($68.14) $0.00 $1.42 $2.16 $2.22 $2.28 $2.33 $2.55 S2.78 $3.02 $3.29 $3.58 53.89 64.10 54.33 $4.56 $4.81 S1B5.05 Vectren Cor~oraiion WC ($58.79) $0.00 $1.15 $1.75 51.84 $1.91 $1.99 $2.15 52.33 $2.52 52.72 $2.93 $3.15 $3.32 $3.50 $3.69 $3.B9 $149.69 Attachment RBH-4 Page 12 of 20 Murti-Sti!lgei Growth Otscaunted Cash Fio-w Ma.del 30 Day Average Stock Pric:e High E!='S Growth Ratlil: 55timate In First Stage Inputs [1J [2] !3J [4J [5J !BJ 171 [BJ IS] [101 [11J 1121 [13] !141 Stock EPS Growth Rate Es.tlmates Lon9-Terrr PaycutRatio Iterative Solution Termlnal Terminal Retention kigli Company Ticker Ptice Zaoks First Call Value line Growth Growth Growth 2017 2021 2027 Proof IRFl PJE Ratio PEG Ratia Blac.k Hills Corporatio:n BKH 567.07 5.00% 10.38% 7.50% 5.41% 10.38% 5.48% 50.0Do/o 5:2.00% s5.5s% {SO.OD) 12.07% 24.55 4.48 Ci1!111terPl)int Energy, Inc. Cr.IP S27.e4 5.00% 6:.06% s.ooo/a 4.96% 6.06% 5.48% 82.00% 74.00% 65,58% ... ,, 9.14% 24.55 4.48 CE'le-sa~eake WtDltieEi Corporatlcm CPK $70.37 6.00% 6.00% a.co% 14.38% 14.38% 5.4i!!i% 45.00% 37.00% 65.:58% f.SO,CO> 13.36% 24.55 4.48 Northwest Nab.lral Gai!!I Co-mpainy NIJ\JN $59.55 4.30% 4.50% 6.00% 3.46% 6.00% 5.48% 80.00% 65.00% 65.58% (.S0.00) 7.52% 24.55 4.48 Sempra Ene.rgy SRE $111.49 8.70% 9.&7% 8.00% 2.7:3.% 9.87% 5.48% 65.00o/o 61.00% 65.58% ;SO.CC 13.07% 24.55 4.48 Southwe&t Gas Corporatian swx $63.71 5.00% 4.00% 6.50% 8.02% !1:.02% 5.46% 53.00% 52.00% 65.58% 8.91% 24.55 4.48 Spire ln.c: SR 566.14 4.10% 4.05% S.00% 5.24% 6.0(1% 5.46% 60.0{1% 54.GO% 65.58% ""·"'r:SLl.CID'J 11.51% 24.55 4.48 Vectren Corporation WC S5B.7S 5.70% 5.57% 7.00% 5.46% 7.00% 5.48% 53.0(1% 5.S.1)0% 65,55% (:!iG.ODJ 9.77% 24.55 4.48 Mei!n 10.67% Max 13.36% Min 7.$2.% PraJected .Annual Ea.mlngs per Share- [16] [16) [17] (16] (19] [20] [21] (22[ [23) [241 125] 126] 127] [28] [29( [30] [31( C::om~:an~ Ticker 2015 '2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026 2027 202.8 2.029 2030 20M Black: Him;; Cot~cratleon BKH $3.12 $3.45 $3.81 $4.20 $4.64 SS.12 $5.61 S6.10 $6.58 $7.05 $7.48 $7.91 $8.34 SS.SO $9.28 $9.79 CenterPoint Er.iergy1 Inc:. CNP ..•.. :~:~:· S1.15 $1.21 $1.29 $1.37 $1.45 Sl.54 $1.63 $1.72 $1.82 $1.93 $2.03 $2.15 $2.26 52.39 $2.52 $2.66 Chesapeake Utilitfes Catporation CPK •: ... s2.68·• ... $3.07 $3.51 $4.01 $4.59 $5.25 $6.00 $6.78 S7.55 $6.30 $9.00 $9.63 $10.16 $10.71 $11.30 $11.92 $12.57 Northwest Natu:tal Gas Company NWN $2.08 $2.20 $2.33 $2.47 $2.82 $2.76 $2.94 $3.12 $3.30 $3.48 $3.68 $3.86 $4.09 $4.31 S4.55 $4.80 Sempra Energy SRE :•.•. · ~~~~< S5.75 $6.31 $6.94 $7.62 $8.37 $9.20 $10.04 $10.86 $11.72 $12.53 $13.31 $14.04 $14.61 $15.52 $16.48 $17.36 Southwest Gas Ccri;:iaratian ~ ...... $2. .92 .... $3.15 $3.41 $3.68 $3.98 $4.29 $4.64 $4.99 $5.35 $5.71 $6.07 $6.43 56.78 57.15 $7.55 S7.96 $8.40 Spire: Irie SR •-$3.15.-· $3.41 $3.69 $3.98 $4.30 $4.54 $5.01 $5.39 $5.78 $6.17 SS.56 $6.95 S7.33 $7.73 $6.15 $8.60 $9.07 Vectren Corporation WC $2.39 $2.56 $2.74 $2.93 $3.13 $3.35 $3.59 $3.83 $4.08 $4.33 $4.59 $4.85 $5.12 55.40 S5.70 $6.01 $6.34 Projected Annual Dividend Payo~t t;tatio )321 [33] [34] [35] {38) [37] [36] (39! [40] [41] [42] "[43] [44] [45] (46] ComE;l!l:ny Ticker 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026 2027 2028 2D29 2030 2031 Bla:ck Hill$ Corpora1lon BKH ::: 50.00% 50.50% 51.00% 51.50% 52.00% 54.:26% :56.53% 58,79% 61.05% 63.32% 65.58o/a 65.58% 65.58% 65.58% 65.58% CenterPoint Energyt Inc, CNP .· 82.00% 80.00% 78.00% 76.00% 74.00% 72.60% 71.19% BS.79% 68.39% 66" ..98% 65.58% 55.58% 65.58% 65.58% 65.58% · Chesape-ake- Utilitia.s Corporatii>n CPK • 45.00% 43.00% 41.00% 39.1)0% 37,00% 41.78% 48,53% 51.29% 56.05% 60.S.2% 65.58% 65.56% 65.58% 6:5,58% B5.58% l\torthwi!!isl Natural Gas Company NIJ\JN' &0.00% 7S.~% 72.5a% 68.75%. 6:5.00% 85.10% 65.19% 65.29% 65.39% 65.48% 65,58% 65.S8% 65.58% -15:5.58% 65.58% Setnpra EnerfW' SRE 65.00% 64.00% 63.00% 62,DO% 61.00% 61.76% 62,53% 63.2.9% 64.05% 64.82% 65.58% 65.58% 65.58% a5.58"'/a 65.58% Saathwest Gas Corpo.ratiori swx ... :53.00% 02.75% 52.>0% 52.25% 52.00% 54.26% 56.53% 58.79% E:it,05% 63.3:.1.% 65.58% 65.5B% 65.58% 65.58% 65,58% sprre-lm:: SR 60.00% SB.50% 57.00% 55.50% 54.00% 55,93% 57.86% 59.79% 61.72% 63.65% 65.58% 65.56% 65.58% 65,58% 65.58% V.e:otrer.i Cori:ior.atiori WC 63.00% 61.75% 60.51}% 59.25% 58.00% 59.26% 60.53% 61.79% 63.05% 54.32% 65.58% 65.58% 65.58% 65.56% 65.58% Projected AnnaaJ Cash FJows [471 [48] [49] f50( (51] [52] [53] [54] [55] [561 [57] f58( [591 160] [61] 1621 Terminal Comp:ariy Ticker 2017 2018 2019 2020 2021 2022 2023 2024 2025 2025 2027 2028 2029 2030 2031 V:a!ue Blaek Hi[ls Corporatio-n 6KH $1.72 $1.92 $2.14 $2.39 $2.56 $3.04 $3.45 $3.87 $4.30 $4.75 $5.18 $5.47 $5.77 $6.08 $6.42 $240.25 CerrterPoint Energy, [nci. CNP $1.00 $1.03 $1.07 $1.10 S1.14 $1.16 61.23 $1.27 $1.32 $1.36 $1.41 $1.48 $1.57 $1.65 $1.74 SB5.24 Chesapeake Utilities Corporation CPK •· $1.58 $1.72 $1.68 $2.05 $2.22 $2.63 53.51 $4.26 55.05 $5.86 Sti.55 $7.03 $7.41 $7.82 $8.25 $308.69 Northwest Natura:I Gas Campany NWN $\.76 $1.78 $1.78 $1.80 $1.81 $1.92 $2.03 $2.15 62.26 $2.41 $2.54 $2.88 S2.B3 $2.98 $3.15 $117.82 Sempra Energy SRE .... $4.10 $4.44 $4.80 $5.18 $5.51 $8.20 $6.81 $7.42 SB.03 $8.63 $9.21 $9.71 $10.25 $10.81 611.40 $426.77 So-uthW\!!$t Gas Ca.rparatian ~-· 61.61 $1.94 $2.09 $2.24 $2.41 $2.71 $3.02 $3.35 $3.71 $4.07 $4.45 $4.69 $4.95 $5.22 $5.51 $205.14 Spire tnc SR $2.21 $2.33 $2.45 $2.58 $2.71 $3.02 S3.34 $3.69 54.05 $4.42 $4.81 55.07 $5.35 $5.64 $5.95 $222.73 Vectren Corporation WC $1.72 $1.61 $1.90 $1.SB $2.08 $2.27 $2.47 $2.B8 52.89 $3.12 63.36 $3.54 $3.74 $3.94 $4.16 $155.62 Projl!cted Annual Data !nvesfor Cash Flaws [63] [64] (65] [66] [67] [68( (691 [70] [711 [72] [73] [74! [75] )76( [77] [781 [79] taoJ lnffial Company Tieker Outflaw 4126117 12131117 6130118 6130119 6130120 6/30121 5130122 5130123 6130124 6130125 6130126 6130127 6130/28 6130!29 6130!30 6130131 6130132 Black HH~ Corporation BKH ($67.07) $0.00 $1.17 $1.81 $2.14 S2.39 $2.66 $3.04 $3.45 $3.67 $4.30 $4.75 55.18 $5.47 $5.77 SB.OB $5.42 $246.57 Cehtet:Point E:ner.gy, Inc.. CNP ($27.94) $0.00 $0.67 $1.03 $1.07 $1.10 $1.14 $1.16 $1.23 $1.27 $1.32 51.36 S1.41 51.46 $1.57 51.65 $1.74 $66.QB Chesapeake Utilities Cl)rporatic:in CPK ($70.37) $0.00 $1.07 $1.69 $1.88 52.05 $2.22 $2.83 $3.51 $4.26 $5.05 $5.86 $6.56 57.03 $7.41 $7.82 $8.25 5316.94 Na.rthwest Natural Gas Ccmpany NWN ($59.55) $0.00 $1.19 $1.81 $1.79 51.80 $1.81 $1.92 $2.03 $2.15 $2.28 52.41 52.54 $2.66 $2.83 $2.98 63.15 $120.97 Sempra energy SRE {$111.49) $0.00 $2.76 $4.31 $4.80 55.19 $5.61 $6.20 $6.81 $7.42 5B.03 58.63 $9.21 $9.71 $10.25 $10.61 $11.40 $438.17 Southwest Gas Corporatiol"J ~ ($83.71) SO.OD $1.22 $1.BB $2.09 52.24 $2.41 $2.71 $3.02 $3.36 53.71 S4.07 54.45 $4.59 $4.95 $5.22 SS.51 $211.65 Spire Inc SR ($68.14) 50.00 $1.50 $2.30 $2.45 $2.58 $2.71 53.02 $3.34 $3.69 54.05 54.42 54.81 55.07 $5.35 $5.54 $5.95 $228.68 Vectren Corporation we ($58.79) so.co $1.17 $1.76 $1.90 $1.99 $2.08 $2.27 $2.47 $2.58 $2.89 $3.12 53.36 53.54 $3.74 53.94 $4.15 $159.76 Attachment RBH-4 Page 13 of 20 Multi-siage Growth Oiscc.unted Cash Ficw Model 30 Day Av~rage Steck. Priee L0\'11' EPS Growth Rate Estfmate 111; F"irat Stage Inputs [1] 12] [31 [41 [5] [6] [71 [B] [91 [1 OJ [11) [12] [13] [14] 81001< _____E~P_S_G_ro~wth=R~•-1•-E,.~-.::-~-.: .... ~~--~Lo:ng-Tem Payout Ratio ltetative Sc-ll.rlion Terminal Termirial Company TI(lker Price Zac.lcs First Call Value Line Growth Low Growth Growth 2D17 2021 2027 Proof IRR Black Hills Corporation BKH S67.07 5.oo% 10.38% 7.50% 5.41% 5.00% 5.48% 50,00% 52.D0% 65,58% SQ.DO B.57% 24.55 MB Ce=nterPciirit Energy, !nc, CNP $27.94 5,00% 6.06% S.00% 4.98% 4,98% 5.48% .82,00% 74.00% 65.:58% .S0.00 8 .. 42% 24.55 MB Che5apeake Utilitfes Corpor~tion CPK $70.37 6.00% 6.00% e.00% 14.38% e:.00% 5.48% 45.00% 37.00% 65.:SS.% .S0.1'.10 8.08% 24.55 4.48 Northwest Natural Gas Company NWN $59.56 4.30% 4.50% 0.00% 3.4Ei% 3.46% 5.48% 80.00% 65.00% 65.58% .so.co 5.90% 24.55 4.48 Sempra Energy SRE $111.49 8.70% 9.87% B.00% 2.73% 2.73% 5.48% 65.00% 61.00% 65.56% (-5'1".00~ B,.2B% 24.55 4.48 Southw~t Gas Co.rporatior.i swx $83.71 5,00% 4.0D% 6.50% a.02% 4.00% 5.48% 53.00% 52.00% 65.:58% (.SCI.DO~ 6.37% 24.55 4.48 S!Jilte Inc SR $68.14 4.10% 4.05% B.00% 5.24% 4.05% 5.48% 60.00% 54.00% 65.:58% (:SL'.l,00) B.S9% 24.55 4.48 Vectren Carporation WC $58.79 5.7()% 5.57% 7.DO% 6.46% 5.57% 5.48% 63.00% 58.00% 65.56% $0.00 B.83% 24.55 4.48 Me.an 7.92% Max 8.89% Min 5.90% .Projei::.ted Annuat Earnings per Share (15) [16) [17] [18] [19] [20) 1:211 [22] [23] (24( [25] [26] [27] [28] [29] POI P1J Company Tlc:l::l!lr 2015 2016 2017 2018 2019 2020 2022 2026 2027 2028 2030 2031 Black Hllls Corporation BKH : · .$2.83:. $2.97 $3.12: $328 53.44 $3.61 $3.79 $3.99 $4.19 $4.41 54.65 $4.90 55.16 55.45 $5.75 $6.06 56.39 CenterPoint Energy, Inc. CNP . i51.D8. $1.13 $1.19 $125 51.31 $1.38 $1.45 $1.52 Sl.60 $1.68 51.77 $1.86 $1.97 52.07 $2.19 $2.31 52.44 Chii!!mpany NWN : : 51.eo: $2.03 $2.10 $2.17 5225 $2.32 52.40 $2.50 $2.60 $2.72 $2.85 62.99 $3.16 $3.33 53.51 $3.70 53.91 Sempra Energy SRE .·: 55,23·· $5.37 $5.52 $5.07 55.82 $5.98 56.15 $6.34 $6.57 $6.84 $7.16 57.52 $7.93 $8.36 58.82 $9.30 $9.81 Southwest Gas Corpciration swx ·· 52.02· $3,04 $3.16 $328 53.42 $3.55 $3,69 $3.85 54.02 $4.22 $4.43 54.66 $4.91 $5.18 $5.47 $5.77 SB.OS Splre tnc SR . 53.10· $3.29 $3.42 $3.56 53.70 $3.SS S4.01 $4.16 54.37 $4.58 54.81 $5.06 $5.34 $5.63 55.94 $6.27 $6.61 Vectren Corporation WC $2.39 $2.52 $2.66 $2.81 52.97 $3.13 $3.31 $3.49 53.69 $3.89 $4.10 $4.33 $4.57 54.82 $5.08 $5.36 55.65 ?rojec.ted Annual Dividend Payout Ratio [321 [33] [341 [35] P6l [37] PB] (39J [40] [41] [42] [43] [44] [45) [46] Company Ticker 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026 2027 2028 2029 2030 2031 Blaok Hill$ Corpo.ration BKH ·.·::< .. ::·. · 50.00% 5.C.50% 51,00% 51.50% $2,00% 54.26% 56.53% 513.79% 61.05% 63.32% 6:5.58% 65.58% 85.58% 65.58% 65.58% CenterPoint Energy, !n c. 82.00% 80.00% 78.00% 76.00% 74.00% 72.60% 71.19'% 69.79% SS.39% 66.83% 65.58%. 65.5:8% 65.58% 65.58% 6:5.58% Chesapeake 'Utilities CorpQration 45.00% 43.00% 41.00% 39,0Do/a J7.00% 41.76% 46.53% 51.29% 56.05%. 60.82% 65.:58% 65.58% 65,58% 65,58% 85,58% NorthWEl:st Natural Gas CDmpany NWN :·:::·· ;f!O.OD% 76.25% 72.50·%. 68.75% 65.00% 65,10% 65,19% 65,29% 65.39% 65,48% 65.58% 65.58% 6:5.58% 65.58% 65.58% SRE ...·•······•:•·•·······:··· · 65.0D% 64.0D% s:to0%- Sl!llmpri! En.ermr swx~~~ .... 62.0D% 61.00% 61.76% 62.53% 63.29% 64.05% 64.82% 65.58% 65.58% Ei:5.5S% 1$5.53% 65.58% Seiuthwelit Ga& Cmpcratich 53.00% 52.75% 52.50% 52.25% 52.00% 54.2-6% 56.53.% 58.79% B1.05% 63.32% 65.58% 165.58% 65.58% 65.58% 65,58% Spire lnc SR 60.00% 58.50% 57.M% 55.50% 54.00% 55.93% 57.86% 59.79% 61.72% 63.65% 65.58% S5.58% Ei5.S8% 65.56% 65.58% Vec.trl!!n Corporati-on WC 63.00% 61.75% 60.50% 59.25% ss.00% ssi.2s% so.:53% st.79% ea.as% es4.a2% 65.158% 65.5$% 65.58% 65.56% S:fi.5S.% Proje-cte-d Annual Cash Flc.ws: [47] [48] (49] [50] [51] [52] [53) [54] [55] [56] (57] [58] [59( [60] 161( [62) Terminal CotntJii!lhY Tielr:e:r 2017 2018 2019 2020 2021 2022 2023 2024 2026 2027 202/l 2029 2030 2031 Value Black HiUs Corporation 8.KH $1.56 $1.65 $1.75 $1.86 51.97 $2.16 52.37 $2.59 $2.84 $3.10 $3.39 $3.57 $3.77 $3.97 $4.19 $156.95 CenterPoint Energy, Inc. CNP $0.98 $1.00 $1.02 $1.05 $1.07 $1.10 51.14 $1.17 $121 $1.25 $129 51.36 $1.44 S1.51 $1.60 $59.78 Chee.a:peak'e UtHWe$ CQ-rporation CPK $1.36 $1.37 $1.39 $1.40 51.41 $1.68 51.98 $2.31 $2.67 $3.06 $3.48 $3.67 $3.87 54.08 $4.30 $161.11 Northwest Natura! Gas Company NWN $1.68 $1.66 $1.63 $1.60 51.56 $1.62 $1.69 $1.77 $1.86 $1.96 $2.07 $2.18 $2.30 $2.43 52.56 $95.93 SE!mpra Energy SRE $3.59 $3.63 $3.67 $3.71 53.75 $3.92 54.11 $4.33 $4.58 $4.87 $520 $5.48 $5.78 $6.10 $6.44 $240.96 Southwe$.t Ga:s Corpor«tion swx $1.87 $1.73 $1.79 $1.86 51.92 $2.09 52.28 $2.48 $2.70 $2.95 $322 $3.40 53.58 53.78 $3.99 $149.31 Spire Inc SR $2.05 $2.08 $2.11 $2.!4 $2.17 $2.34 52.53 $2.74 $2.97 $3.22 $3.50 $3.tiS $3.90 54.11 $4.33 $162.24 Vectren Corpora'lfon WC $1$8 $1.74 $1.80 $1.86 $1.92 $2.07 $2.23 $2.40 $2.59 $2.78 $2.99 $3.16 $3.33 $3.51 $3.71 $136.79 ~rojecte-d Annual Oata lnvestc.r Cash Flc.ws [63] [64] (65] [66] [67] [68] [69] [70] [71] [721 [73] [74] 175( [76] [78] [79) [BO] Initial Campany Ticker Outtlaw 4128/17 12131117 6130118 6130/'[9 6/30120 6130/21 6/30122 6130123 6130/24 6130125 6/30il2S 61301.(:7 6130128 Ell30/29 6130130 6130131 6130132 Black Hrus Corpor:atlor:i BKK ($67.07) $0.00 $1.06 $1.60 $1.75 $1.86 $1.97 $2.16 $2.37 $2.59 52.84 $3.10 53.39 53.57 $3.77 $3.97 $4.19 $161.15 CenterPoint Energy, lnc. CNP ($27.94) $0.00 $0.66 $1.00 $1.02 $1.05 $!.07 $1.10 $1.14 $1.17 5121 $1.25 5129 $1.36 $1.44 $1.51 $1,60 $61.38 Chesapeake: Utilitles Corporatioll CPK ($70.36) $0.DO $0.92 $1.40 $1.39 $1.40 $1.41 $1.68 $1.98 $2.31 l;2.67 $3,06 $3.48 $3.67 $3.87 $4.08 $4.30 $165.41 Northwest Natural Ga'& Company NWN ($59.56) $0.00 $1.14 $1.71 $1.63 $1.60 $1.56 $1.62 $1.69 $1.77 S1.86 $1.96 S2.D7 $2.18 $2.30 $2.43 $2.56 $98.49 Sempra Energy SRE ($111.49) $0.00 $2.43 $3.64 U.67 $3.71 $3.75 $3.92 $4.11 $4.33 $4.58 $4.87 55.20 55.48 $5.78 $6.10 $6.44 $247.39 Southwest Gas Corporation swx ($83.71) $0.00 $1.13 $1.71 $1.79 $1.86 $1.92 $2.09 $228 $2.48 $2.70 $2,95 $322 $3.40 $3.58 $3.78 $3.99 $153.30 Spire Inc SR ($68.14) $0.00 $1.39 $2.09 $2.11 $2.14 $2.17 $2.34 $2.53 $2.74 $2.97 $3.22 l;3.50 $3.69 $3.90 $4.11 $4.33 $166.57 Vectren Corporation WC ($58.79) $0.00 $1.14 $1.72 $1.80 $1.86 $1.92 $2.07 $223 $2.40 $2.59 $2.78 52.99 $3.16 $3.33 $3.51 $3.71 $142.50 Attachment RBH-4 Page 14 of 20 Multi-Stage Growfh Oisemmte.d Cash Flow Model 90 Day Average Stock Plic!!! Average EPS Growth Rate .e&tlmate in Flrst Stage lnpu1o [11 [2] f31 141 [&] [6] l?J 18] [9] [10] [11] [1~ [13] ]14j Stock EPS Growth Raie Estimates Long-Te-:rrr Payout Ratio lbm:rti11e Sotutton ienninal Te:rmlnal Ret.!ntion Co.mpany Ticker Price Zlioks First Call V:atu-e Lini;1: Growth Average Growth 2017 2021 2027 Proof IRR P/5 Ratio PEG Ratio B[atk Hills. Corporation BKH $64.03 .5.00% 10.38% 7.50% $.41% 7.07% 5.48% 50,00% 52.Ll0% 6:5.5EI.% (SD.OCIJ 10.32% 24.55 4.48 CenterPaint Energy, lno. CNP $26.72 5.00% 6.06"% 6.00% 4.98% fi.51% 5,48% 82.00% 74.liO"'/a- 65.58% :!ill.CO 9.17% 24.55 4.48 Chesapeake Utilities CorpotatiQn OPK $67.73 6.DO% 6.CCI% 8.00% 14.38% B.60% 5.48% 45.00% 37.r:J.0% 65,56% 1$0-.00) 10.04% 24,55 4,48 Northweet Natural Gas Campany NWN $59.31 4.30% 4.50% 6,00% 3,46% -4,57% 5.48% 80.00% 55.00% 65.58% $L'l.QQ S.84% 24.55 4.48 Sempra Energy SRE $106.86 8.10% 9.87% B.00% 2.73% 7.32% 5.4!1.% 65.00% 61.00% 65.:58% (:50.0DJ 11.75% 24.55 4.48 Southwest Gas Co-rporatron swx $81.56 5.DO% 4.00% 6.50% 8,02% 5.88% 5.48% 53.00% 5:2.00% 65.58% [$0.1)1)) 7.77% 24.55 4.48 Spire ll'lc SR $65.81 4.10% 4.05% 8.00% 5.24% 5.35% 5.48% 60.00% 54.00% 65.58% ($0.(ID] 10.Q6% 24.55 4.48 Vectren Corporation WO $55.95 5.70% 5.57% 7.00% 6.45% 6.~8% 5.4S% E!i3.00% 58.00% Ei5.5Bo/a $0.00 9.67% 24.55 4.48 Mean 9.43~ Max 11.75% Min 6.64% ~ro]ei::ted Annu:al c:arrirn~s per snar111: [15] !16] [171 [18] [19] [20] [21] [22] ]23) [24] 1251 [26] 1271 128] (29] [30) [31] Company Tic::k:e.r 2015 2016 2017 2018 2orn 2020 2021 2022 2023 2024 2025 2026 2027 2028 2029 2030 2031 Black Hills CDr:poratiol'L BKH $3.03 $3.24 $3.47 $3.n $3.98 $4.25 $4.55 $4,85 $5.16 $5.47 $5.78 $6.IO $6.43 $6.78 $7.16 $7.55 Cente:r?ci[nt Energy, Inc. CNP ;.:~:~;; $1.14 $1.20 $1.27 $1,34 $1,41 $1.49 S1.57 $1.66 $1.75 $1.85 $1.95 $2.05 $2.17 $2.2B $2.41 $2.54 Chesape.ake-1Jtiltfies Corp.oration OPK . .:.C$2.6F $2.91 $3.16 $3.43 $3.73 $4.05 $4.40 $4,75 $5.11 $5.47 $5.63 $6.18 $6.51 $6.87 $7.aS $7.65 $8.06 Northwest Natural Gas Company NWN >:·$1.05< $2,05 $2.14 $2.24 $2.34 $2.45 $2.56 52.68 $2.BI $2.96 $3.11 $3.27 $3.45 $3.64 $3.84 $4.05 $4.27 Sl!llmpra Enil!!rgy SRE ·.'..$5~23i· $6.61 $6.02 $6.47 $6.94 $7,45 $7.99 SB.55 $9.13 $9.71 $10.30 $10.90 $11.50 S12.13 $12.79 $13.49 $14.23 Southwest Gas 0Drporation swx ·::: $2.!li: $3.09 $3.27 $3.47 $3.67 $3.69 $4,11 $4.35 $4.60 54.86 $5.14 $5.42 $5.72 $6.03 $6.36 $6.71 $7,0B Splre ln.c SR ·:: $3.16:: $3.33 $3.51 $3.69 $3.Ba $4.10 $4.32 S4.S5 $4.80 $5.06 $5,33 $5.62 $5.93 $6.26 $6.60 $6.96 $7.34 Ved:ren Core:oratial'I WO · · $2.a9:: $2.54 $2.69 $2.86 $3.04 $3.23 $3.43 S3.63 $3.85 $4.07 $4.31 $4.55 $4.80 $5.06 $5.34 $5.63 $5.94 Projee1ed Ann1.1al OMdend Payout Ratio [32] (33] (34] [35] [36] 1371 [38] [39] [40] (41) [42] [43] [44] [45] [46] Com~any Ticiker ZD17 2018 2019 2020 2021 2022 2023 ZD24 2025 2026 2027 2028 2029 2030 2031 Blac.k Hills CDrporation BKH .. OD.0.[]% 50.50% 51.00% 51.50% 52.00% 54.26% 56.53% 5.B.79% 61.05% S3.J2.% 65.5Cl% 65.5B% 65.58% 66.58%. 65.56% CenterPo-int Energy, lne. Cr.IP 62.00% 80.00% 78.DO% 76.D0% 74.00% 72.5D% 71.19% 69.79% 68.39% 66.98% 65.58% 65.58% 65.58% 65.58% 65.58% Chesapt::ake- UtUWes Corporation OPK 45.0C% 43.00% 41.00% 39.00% :37.00% 41.7-8% 46.:53% 51.29% 56.1)5% 60.82% 155.58% 65.56% 65.:58% 65.58% 65.58% Northwest Natural G.a:11; Company NWN 80.00% 76.25% 72.50% SS..75% 65.00% 65.tOo/o 65.19% 65.29% 65.39% 65.48% 65.58% 65.58% 65.58% 65.58% 65.Sa.% Semprn En&r,gy SRE 65.00% 64.00% 63.00% 62.00% 61.00% 61.76% 62.53% 63,29% 64.05% 64.82% 65.58% 65,58% 65.58% SS.58% 65.:58% $(11.1thw~!'ilt G:i!I$ Corporation swx ·.::· 53.00% 52,75% 52,50% 52,25% 52.00% 54.26% 56.:53% 58.79% 61.05% 63,32% SS.SB% 65.58% 65.58% 65,58% 65.58% Sp[~e-lm;: SR 6:0,0D% 58.50% 57.00% :SS.SO% 54.00% 55.93% 57.86:% 59.79% 61:72% 63.55% 65.58% 65.58% 65.58% 65.5S% 65.58% Vectren Carparaiian WO 63.QD% 61.75% 6Ll.50% 59.25% 51!t.00% 59.26% 60.53% 61.79% 63.05% 64.32% 65.58% 65.58% 65.5B% 65.58% 65,5B% E=lrcject:ed Annual Cash Flows [47] 148] [49] [50] [51] [52] f53J [54] !551 [56] f57J [SB] [59J 160] [611 [62] Terminal C:amp:any Ticker 2011 2018 2019 2020 2021 2022 2023 2024 2025 2026 2027 202B 2029 2030 2031 Vall.le Black Hi[ls CorpaiqtiDn BKH $1.62 $1.75 $1.90 $2.05 52.22 $2.47 $2.74 $3.03 $3.34 $3.66 S4.00 $4.22 S4.45 $4.69 S4.95 $1•5.33 CehtetPoint Ene(gy, fnc. $0.99 $1.01 $1.04 S1.07 51.10 $1.14 $1.18 $1.22 $1.26 $1.30 S1.35 $1.42 S!.50 $1.SB S1.67 $62.41 Chesape~ke Utili:ti'es: Ccir.Porath:in g~~ ··:· .. ·· $1.42 $1.46 $1.53 SUB 51.63 $1.9S $2.38 $2.B1 S3.27 $3.76 $4.27 $4.51 S4.75 SS.01 $5.29 $1W.97 Northwest N1!tural Gas Company NWN · $1.71 $1.71 $1.70 Sl.66 51.67 $1.75 S!.63 $1.93 52.03 $2.14 $2.26 $2.39 $2.52 $2.66 $2.BO $104.95 sempra E:;nergy SRE $3.92 $4.14 $4.37 $4.62 54.68 $5.2B $5.71 $6.15 $6.60 $7.07 $7.54 $7.95 $8.39 $8.85 $9.33 $349.46 Southwest Gas Carp oration swx :: .... $1.73 $1.83 $1.93 S2.03 52.14 $2.36 52.60 $2.B6 $3.14 $3.43 $3.75 $3.96 $4.17 $4.40 $4.64 $173.B5 Spire Inc SR $2.10 $2.16 $2.22 S2.28 52.33 $2.55 $2.78 $3.02 $3.29 $3.58 $3.B9 $4.10 $4.33 $4.56 $4.61 $180.24 Vectren Cotp(loratlon WO $1.70 $1.77 $1.64 $1.91 51.99 $2.15 S2.33 $2.52 $2.72 $2.93 $3.15 $3.32 $3.50 $3.69 $3.89 $145.BO Pl"oje-cted Ah:nual Data Investor C:as.h Flaws [63] f64) [65) [68] [67] 166) [69] [70] ]71] [72] !73) [74] ]751 [781 (77] [78] [79] [BO) Initial Company Tlclca:r Outflow 4128117 12131117 6130118 6130119 6130/20 6/3012.1 6130122 6/30/23 6130124 6/30/25 6130/26 6130127 6J31l/'28 6130/29 6130130 6130131 6130132 Black Hills Corparati.cin BKH ($64.03) $0.00 51.10 $1.68 $1.90 $2.05 $2.22 $2.47 $2.74 $3.03 $3.34 53.66 $4.00 $4.22 $4.45 $4.69 $4.95 S!90.2B Ce:n!erPo!nt Energy, ln;c. CNP (S26.n) $0,00 S0.67 $1.01 $1.04 $1.07 $1.10 $1.14 $1.1B $1.22 $1,28 $1.30 $1.35 $1.42 $1.50 $1.58 $1.67 $64,0S Che$.i!peake. Lltilffie~ Carp-oration OPK (S67.73) SO.DO S0.96 $1.48 $1.53 $1,58 $1.63 $1.98 $2.3B $2.81 $3.27 53.76 $4.27 $4,51 $4.75 $5.01 $5.29 $203.26 Northwest Natl.Ir.a[ G~s Company NWN (559.31) so.co 51.16 $1.75 $1.70 $1.68 $1.67 $1,75 $1.83 $1.93 $2.03 $2.14 $2.26 $2.39 $2.52 $2,66 $2.BO $107.75 Sempra Ene:rgy SRE ($1061!6) $0,00 52.65 $4.06 $4.37 $4.62 $41!S $5.28 $5.71 $6.15 $6,60 $7.07 $7.54 $7.55 $8.39 $81!5 $9,33 $356,79 Southwest Gas Corporaticm swx [581.58) $0.00 51.17 $1.79 $1.93 $2.03 $2.14 $2.36 $2.60 $2,85 $3.14 53.43 $3.75 $3.96 $4.17 $4.40 $4.64 5178.50 si:iltefne SR ($65.81) $0.00 $1.42 $2.16 $2.22 $2.28 $2.33 $2.55 $2.78 $3.02 $3.29 $3.58 $3.89 $4.10 $4.33 $4.56 $4.81 5185.05 Vectren Car!!oratlon WO [$55.95) $0.00 51.15 $1.75 $1.84 $1.91 $1.99 $2.15 $2.33 $2.52 $2.72 52.93 $3.15 $3.32 $3.50 $3.69 $3.89 5149.69 .·· -._. Attachment RBH-4 Page 15 0120 Mtliti-stage Growth Oi:eoounted Ca$h Flo-w Model 90 Day Avera.ge Stock ?rCce Hlgh EPS Growth Rate l::stlmate In Flr&t Stage l~e;uts [1! [2] [3] 14] [5J [6] IZl [BJ [91 1101 [111 [12] [13] [14] Stock E?S Growfh Rate Estim~tea Longni'ern Payout Ratio Iterative Solution Terminal Terminal Rete-ntion Hig:h Company TCcker Pri.ce Zack$ flr Projeat:ed Annual Dividend Payout Ratio [32] [33l [34l [35] [36J [37] (361 [39] (40) [41] 1421 [43J [44] [45] [46] Company TiQker 2017 2018 :l019 2020 2021 2022 2023 2024 2025 2026 2027 2028 2029 2030 2031 Blaek Hills Corpo.ration BKH 50.00% 50.50% 51.00% 51-50% 52.00% .54.2.6% 56.53% 5B.79% 61.05% 153.32% 65.58% 65.58% 65.58% 65.53% 65.58% c~nter?oint Energy I Inc. CNP::·.<:.:.::··;:.::.·: ... :.: :. 82.00% 80.00% 7B.00% 76.00% 74.0'1:1% 72.60% 71.19% 69.79% 68,39% 66.9&% 65.68% El:S.58% 65.58% 65.58% 65.58% Chesapeake Utilities Corporation CPK :·:·.. :::.:::.·.:::•:•: .. : 45.00% 43.00% 41.00% 39.00% 37.00% 41.76% 48.53% 51.29% 56.05% 60.82% 65.58% 65.58% SS.58% 65.58% 155.58% Northwe:s.t N:a:tura! l3a5 Cotnpany NWN .:.··: >•.:·.· .. ·... 80.DCI% 76.25% 72.50% 68.75% 65.CIG% 65.10% 65.1.9% 65.29% 85,39% 65.43% 65.56% 65.56% 65.5&% 65.58% 65.58% Sempra Eniergy SRE :.'.':···:>• 65.00% 64.00% 63,00% 62.0(J% 61.0()% 61.78% 62.53% Ei:3.29% 64.05% 64,.82% 55,58% 65,5::1.% 65.58% 65.58-% 65.5&% Southwest Gas C:arporatian SIJ\/X: .·. 53..00% 52.75% 52.50% :52.:25% 52.00% 54.26% 56.53% 5S.79% 61.05% 6;,,32% 65.58% 65.58% 55.58% 65,:5EI:% 66.58% Splre Inc SR 60.00% 58.50% 57.00% 55.5(]% 54,00.% :55,.93% 57.B6% 59.79% 61-72% 63.65% 65.58% 65.58% 65.58% 65.58% 65.58% Vectren Cor~oration WC 63.00% 61.75% 60.fi.Oo/o 59.2:5% 5B.00% 59.26% 60.53% 61.79% 63,C5% 64.32% 65.58o/a 65.56% 65.5&% a5.5a% 65,58% Projected Annual Casb Flows [47] (4BJ (49] [50] [511 [52] [53] 1541 [55] [56J [57] [58] [59] [60l [61] [62] Terminal Ccm~any Ticker 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026 2027 202.B 2029 2030 2031 Vall.le Bleck Hills Corporation BKH $1.72 Sl.92 52.14 52.39 $2.66 $3.04 $3.45 $3.87 $4.30 $4.75 $5.16 $5.47 $5.77 SS.OB $6.42 $240.25 CenterPoint Energy, Inc. CNP $1.00 Sl.03 S1.D7 51.10 $1.14 $1.1B $1.23 61.27 $1.32 $1.36 $1.41 $1.46 $1.57 $1.65 $1.74 $65.24 Ch-e.sapeake- utUitie:& Corporation CPK $1.5B 81.72 SI.BS $2.05 $2.22 $2.83 $3.51 S4.26 $5.05 $5.B6 $6.66 $7.03 $7.41 S7.B2 SB.25 $30B.69 Northwest Nab.lraI Gas Comparw NWN $1.76 S!.7& Sl.79 SUD $1.61 $1.92 $2.03 $2.15 $2.28 $2.41 $2.54 $2.68 $2.B3 $2.9& $3.15 $117.62 Sempra Energy SRE $4.10 64.44 $4.80 55.19 $5,61 $6.20 $6.81 $7.42 $6.03 $8.63 $9.21 $9.71 $\0.25 SW.Bl $11.40 $426.77 Southwe!!lt G;a$ Corparation swx ·.· $1.81 Sl.94 $2.09 02.24 $2.41 $2.71 $3.02 $3.36 $3.71 $4.07 $4.45 $4.69 $4.95 $5.22 $5.51 $206.14 Spire lnc SR $2.21 52.33 $2.45 52.58 $2.71 $3.02 $3.34 $3.69 $4.05 $4.42 $4.81 $5.07 $5.35 S5.64 $5.95 $222.73 Vec:tren Corporation WC $1.72 $1.81 Sl.90 $1.99 $2.0& $2.27 $2.47 s2.as $2.89 $3.12 $3.36 $3.54 $3.74 S3.94 $4.16 $155.62 Projected Armual Dabil Investor Cash Flows [63] [64] [65] 166J 167[ [68] [691 [70] [71] [721 [73] [74] [75] [76] [77] 178) [79] [BO) lnltial Com~an}'. Ticker Outf[ow 4128117 12131117 6130118 6130/1:9 6J3Cl/20 6130121 6/30122 6130123 6130124 6130125 6130126 6130127 6130128 5130129 5130130 6130131 6130132 Blac:k Hil!s CLlrpora1ion BKH [564.03) $0.00 S1.17 $1.61 $2.14 $2.39 S2.66 $3.04 53.45 $3.87 $4.30 $4.75 $5.18 $5.47 $5.77 SS.OB $6.42 $248.67 CenterPcint Ene-rgy, Inc. ONP [$26.72] $0.00 SD.67 $1.03 $1.07 $1.10 51.14 $1.18 S1.23 $1.27 $1,32 $1.36 $1.41 $1.48 $1.57 51.65 $1.74 $86.98 Che&apeake- LJtfiltiiNa- Corporation CPK ($67.73) $0.00 $1.07 $1.69 $1.88 $2.05 $2.22 $2.83 S3.51 $4.28 $5.05 $5.86 $6.66 $7.03 $7.41 57.62 $8.20 $316.94 Northwest Natural Gas Co.mpany f-IV\IN [$59.31) $0.00 $1.19 $1.61 $1.79 $1.&0 $1.BI $1.92 $2.03 $2.15 $2.28 $2.41 $2.54 $2.68 $2.83 S2.98 $3.15 $120.97 Sempfa Energy SRE [$106.86) $0.00 $2.78 $4.31 $4.80 $5.19 55.fil $6.20 $6.81 $7.42 $8.03 $8$3 $9.21 SB.71 $10.25 $10.81 $11.40 $438.17 Southwest Gae Corparaticn swx (SB1.56) $0.00 51.22 $1.&8 $2.09 $2.24 $2.41 $2.71 $3.02 $3.36 $3.71 $4.07 $4.45 $4.69 $4.95 S5.22 $5.51 $211.65 Spfre lnc SR (S65.B1) $0.00 $1.50 $2.30 $2.45 $2.58 $2.71 $3.02 53.34 $3.69 $4.05 $4.42 $4.81 $5.07 $5.35 55.64 $5.95 $228.68 Vec.tren Core.oration WC ($55.95) $0.00 $1.17 $1.78 $1.90 $1.99 $2.0S $2.27 52.47 $2.6B $2.89 $3.12 $3.36 S3.54 $3.74 $3.94 $4.16 $159.7B Attachmen1 RBH.4 Page 16 of 20 Multi~Stage Growth DlsG01..mted Cash Flow Model 90 D:ay Average S1ock Price Low EPS Growth Rat~ E-stimat~ iri Fin~t stage Inputs [1] 12] Pl [4] [5] [61 171 [SJ 19] [1 OJ [11] [12] [131 (141 Stm::k _____E,,P_,S'--G"'r"'owth='-'R"'ot"-•-=Esl=;R;ci~'-"~"'1:7.-~o~o-~L~o~w,---'Long-Tem P~")IOLit Ra1io lterattve Solution Termirial lermtnal Company Tl~ker Price Zac!:.s First Call Value- Linf! Growth Grc-wt:h Growth 2:0'!7 2021 2027 Proof tRR PlE Ratlo PEG Ratio Bla~k Hill$ Co-rpora1,on BKH S64.03 5.00% l0.38% 7.50% 5,41% 5,0(l% 5.48% 50-.00% 52.00% 65.58% $0.00 8.97% 24.55 4.48 CenterPoint Energy, Inc. CNP $26.72 5.00% 6.06% 6JJ0% 4.98% 4.98% 5.48% 82.00% 74.00% 65.58% $0.00 8.62% 24.55 4.4• Ches.apeak:e Utllitle:S Corp-o-ratio-n CPK $67.73 6.00% -6.00% 8.00% 14.38% 6.0(J% 5.4B% 45.00% 37.00% 65.58% $n00 8.40% 24.55 4.48 Northwest Na:tural Ge:s Campany NWN $59.31 4.30% 4.5o% 6.00% 3.46% 3.46% 5.48% .SO.OD% 65.00% 65,58% ($0,00) 5,93% 24.55 4.48 Sempra Ertergy SRE $106.86 B.70% .9.87% 8.00% 2.73% 2.73% 5.48% 65.CD% 61.00% 65.58% (&l.00) 8.65% 24.55 4.48 Southwest Gas Corporation swx $61.56 5.00% 4.00% 6.50% 6.D-2% 4.00% 5.48% 53.00% 52.00% 65.58% (SO.OD) 6.55% 24.55 4.48 Spiti! Inc SR $55.81 4.10% 4.05% 8.DO% 5.24% 4.05% 5,48% 60.00% 54.0(J% 65.58% (.SO.OD) 9.20% 24.55 4.48 Vectren Cci-rporation we $55.95 5.70% 5.57% 7.DO% S.46% 5.57% 5.48% 63.0D% 58.00% 65.58% ($1ic'li'.l) 9.27% 24.55 4.48 Mean B..23% Max 9.27% Mrn 5.93% ProJeci:ed Amiuat E~mi~gs par Sliare (15] [16] [17] [18] [19] [20] [21] !221 [23] [241 [25] [261 [27] [28] [29] (30] [31] Company Tickf!r 2015 2016 2017 201a 2019 2021 2022 2023 2024 2025 2026 2027 2028 2029 2030 2031 Black H][[s Corpor:iltion BXH .. · $2.83: 52.97 $3.12 53.28 53.44 53.61 $3.79 $3.99 $4.19 S4.41 $4.65 H.90 $5.16 $5.45 $5.75 $6.06 $6.39 CenterPnil'1t Energy, Inc. CNP ·: . 51.D8: $1.13 $1.19 $1.25 $1.31 51.38 S1.45 $1.52 $1.60 $1.68 $1.77 $1.86 $1.97 $2.07 52.19 S2.31 $2.44 Chesapeake Utmtles Corpornilcm CPK .. 52.68 ·: S2.84 $3.01 53.19 53.38 $3.59 $3.30 $4.03 5426 $4.51 $4.75 $5.03 $5.30 $5.59 SS.90 $6.22 56.56 Northwest Natl.Jr.el Gas Cornpa!"1")1 NWN ...... sus·. 52.03 $2.10 $2.17 $2.25 S2.32 S2.40 $2.50 $2.60 $2.72 $2.85 $2.99 $3.16 $3.33 53.51 $3.70 $3.91 Sempra Energy SRE ·: · 55.23. $5.37 $5.52 $5.67 $5.82 $5.98 $6.15 $6.34 56.57 $6.84 $7.16 $7.52 $7.93 $8.36 $6.82 S9.30 $9.81 Southwest Gas Corporatioti swx : : 52.n· · S3.04 53.16 53.28 $3.42 $3.55 53.69 $3.85 S4.02 $4.22 $4.43 $4.66 $4.91 $5.18 55.47 $5.77 $6.06 Sptrelric SR $3.16 $3.29 $3.42 $3.56 53.70 S3.85 $4.01 $4.18 $4.37 $4.58 H.81 $5.06 $5.34 $5.63 S5.94 $6.27 $6.61 Vectren Corporation WC 52.39 $2.52 $2.66 $2.81 52.97 53.13 $3.31 $3.49 S3.69 $3.89 $4.10 $4.33 54.57 S4.82 SS.OB $5.35 $5.65 PmJ~ct@d Annual Dividend Payout Ratio [32] [331 !341 [35] [361 (37] [38] [391 [40] [41] (42] [43] [44] [45] [46] Company Ticker 2017 20\8 20\9 2020 2021 2022 2023 2024 2025 2026 2027 2028 2029 2030 2031 Black Hms Corporatton SKH 50.00% 50.50% 51.00% 51.50% 52.DC% 54.26% 56.53% 58.79% 61.05% 63.32% 66.58% 65.58% 65.58% 65.58% 65.58% CenterPoint Eriergy1 Irie:. CNP. aa.00% SO.DO% 78.00% 76.00% 74.00% 72.60% 71.19% 69.79% SS.39% 66 ..98% 65.58% 65.58% 65.56% 65.56% 65.58% Chesapeake Utilities Corporation CPK 45.DO% 43.00% 41.00% 39.00% 37.00% 41.76% 46.53% 51.29% 56,05% 60.82% 65.58% 65.58% 65.58% 65.58% 65.58% Northwest Natural Gas Company NWN SO.DO% 76..25% 72.5D% 68.75% 65.00% 65.10% 65.19% 65.29% 65.39% 65.48% S5,58% 55.58% 65.58%- 65.58% 65.58%. Sempra Energy SRE 65.00% S4.00% 63.00% 62.00% 61.00% 61,76% 62,53% 63.2.9% 64.05% 64.82% 65.58% 65.58% 65,58% £5.58% 65.58% Southwest Gois Corporation swx 53Jl0% 52.75% 52.50% 52..25% 52.00% 54.26% S6.53% 58.79% 61,05% 63-.32.% 65.58% 65.58% 65.58% 65.58% 65.58% Splre Inc SR 60.00% 5S..50% 57.00% 55.50% 54.00% 55.93% 57.88% 59<79% 61.7::2:% 63.65% 65.58% 65.58% 65.58% 65.58% 65.58% Ve.ctren Corparatlan WC 63.00% 61.75% 80,50% 59,25% 58.00% 59.26% 60.53% 61.79% 63.05% 64.32% 65,58-% 65)58% 65.58% 65.58% 65.58% Projected Annual Cash Fl.cws [47] [49] [49] [501 [511 [52] [53] [54] [55] (56] [57] [581 (59] [60] [61] [62( Term Ireal Compa11y 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026 2027 2028 2029 2030 2031 Value Bl ?rojected Ann1Jal Data lnvestor Cas.h Flews [63] (64] [65] [66] [67[ [681 [691 [70] [71] [72] [73] [74] [75] [76] [77] [78] [79) [80] Company Ticker Outtlow 4/28/17 12131117 6130/18 6130119 6/30/2D 6130121 6130122 6130123 6130124 6130125 6130126 6130127 6130128 6/30/29 6130130 6130/31 6130132 Blai::k Hllls Corporation BKH (S64.03) $0.00 $1.06 $1.60 $1.75 $1.86 $\.97 $2.16 $2.37 $2.59 $2.B4 $3.10 S3.39 $3.57 $3.77 $3.97 $4.19 $\61.15 CenterPoint Energy, Inc. CNP ($26.72) $0.00 $0.66 $1.00 $1.02 $1.05 $\.07 $1.10 $1.14 $1.17 $1.2\ 61.25 S1.29 $1.36 $1.44 $1.51 $1.60 $61.38 Chesapeake Utilities Corporation CPK ($67.73) $0.00 50.92 $1.40 $1.39 $1.40 $1.41 $1.68 $1.98 $2.31 $2.67 $3.08 $3.48 $3.67 $3.87 $4.0S $4.30 $165.4\ Nmthwa:st ~aturnl Gao;: Company NWN ($59.31) $0.00 $1.14 $1.71 $1.63 $1.60 $1.56 $1.62 $1.69 $1.77 $1.B6 $1.96 $2.07 $2.18 $2.30 $2,43 $2.56 $98.49 Sempra Energy SRE 1$106.86) $0.00 $2.43 $3.64 $3.67 $3.71 $3.75 $3.92 $4.11 $4.33 $4.58 $4.87 55.20 $5.48 $5.78 $6.10 $6.44 $247.39 Southwest Gas Corporation swx ($81 .56) so.oa S1.13 $1.71 $1.79 $U6 $1.92 $2.09 $2.28 $2.48 Si.70 $2.95 $3.22 $3.40 $3.58 $3.78 $3.99 $153.30 Spire lnc SR ($65.81) SO.DO 6\.39 $2.09 $2.11 $2.14 $2.17 $2.34 $2.53 $2.74 S2.97 $3.22 $3.50 $3M $3.90 $4.11 $4.33 $166.57 Vectren Corparation WC ($55.95) $0.00 $1.14 $1.72 $1.80 $1.86 $1.92 $2.07 62.23 $2.40 S2.59 $2.78 S2.99 $3.16 $3.33 $3.51 $3.71 $142.50 Attachmont RBH-4 Page 17 of20 Multi-Stage Growth Discoun.ted Cash Flow Model 180 Day Average Stciek Prlce Average EPS Growth Rate Eslirrui.te iri flrst Stage lnpu~ 11] [21 [3] !4] (5] [6( [?] [B( [9] [10] [111 [12] [13] [14] Stock ----~E~PS~G~ro~w1~h~R=a1e=E=;~<;i:;i't:c;;,'t";.-;io'°n ______;LDn.g-Tem Payout Ratio lterat[ve Sol1.1tion Terminal Te.rminal Ticket :Prtca: Zacks :First Call Value Line Growth Average GroC1wth 2017 · ::!.021 2027 Proof [RR PJE Ratio PEG Ratio Bl.eek HOJ$ Corpo-ration BKH $61.79 5.00% 10.36% 7.50% 5.41% 7.07% 5.46% 50.00% 52,00% 65.56% l•O.OO) 10.64% 24.55 4.48 Ce11terF'oint Energy, Inc:. CNP $24.91 5.00% 6.06% S.CIO% 4.9S.% 5.51% :5.4Bo/o 82.00% 74.00% 65.5;8% SD.OD 9,82% 24.55 4.48 Che.sa:p-eake Utllitfes Corporation CPK $65.49 15.00% fJ.00% B.00% 14.38% 8.60% 5,46% -45,1}0% 37 ,CID% S5.5il!i% $0.00 10.32% 24.55 4.48 Northwest N:qtu:ra.I G21s Compaiiy f>IWN $59.19 4.30% 4.50% 6.0D% 3.46% 4.57% 5.48% 80.1)0% 6"5,01)% 65.58% (lli0.00) 6.66% 24.55 4.48 Se-nipra Eri~rgy SRE $105.26 B.70% 9.67% 8.00% 2.73% 7.32% :5.4S% a5.D0% 6"1,0Do/o 65.58% (50.00) 11.B.9% 24.55 4.48 Southwest Gas Corporaticin swx $76.46 5.00% 4.00% 6.5Do/o B.02% 5.88% :5.48% 53.0-0% 52.0D% 65.58% {.$0,00) 8.32% 24.55 4.48 Spire fnc SR $64.75 4.10% 4.05% 8.0D% 5.24% 5.35% 5.48% 60.00% 54.01)% 65.58% (.SO.DO) 10.21% 24.55 4.48 Ve-etren Corpo-ration WC $52.69 5.70% 5.57% 7.01)% 6.4El% 6.16% 5.4.8% 63.00% 58.00% 65.5:8% (.$0.00) 10.21% 24.55 4.46 Mean 9.76% Max 11.69% Min 13.66% ProjeC"ted An.ri1.1i!!il Earnings pet Share [15] [16] [17] (18) (191 [20] [21] [22] [23] [24] 1251 [26] [27J [28) [28] [30] [31] Company Tioker 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026 2027 2028 2029 2030 2031 Blac:k Hills Ccrporaiion BKH $2.83. $3,03 $3,24 $3.47 $3.72 $3,98 $4.26 $4.55 $4.85 $5.16 $5.47 $5.78 $6.10 $6.43 $6.76 $7.16 $7.55 Ce:nter.Poln.t Energy, IM. CNP . $1.oa:. $1.14 $1.20 $1.27 $1.34 $1.41 $1.49 $1.57 $1.66 $1.75 $1.85 $1.95 52.05 $2.17 $2.28 52.41 $2.54 Chesapeake Utilities CDrparatfo.11 OPK ' S2.66: $2.91 $3.16 $3.43 $3.73 $4.05 $4.40 $4.75 $5.11 $5.47 $5,83 $6,18 $6.51 $6.87 $7.25 $7.65 $8.06 Northw&st Natural Gas Company NWN ·. $1.96· $2,05 $2,14 $2.24 $2.34 $2,45 $2.56 $2.68 $2.81 $2.96 $3.11 $3.27 $3.45 $3.64 $3.84 $4.05 $4.27 Sempra En.ergy SRE '· $5.23: $5.61 $6.02 $6.47 $6.94 $7.45 $7.99 $8.55 $9.13 $9.71 $10.30 $10.90 $11.50 512.13 $12.79 $13.49 $14.23 Southwest Gas Corporation SllllX :· $2.92' $3.09 $3.27 $3.47 $3.67 $3.89 $4.11 $4.35 $4.60 $4.86 $5.14 $5,42 $5.72 $6,03 $6.36 SS.71 $7.08 Spire Inc SR .· $3.16: $3.33 $3.51 $3.69 $3.89 $4.10 $4.32 $4.55 $4.80 $5.06 $5.33 $5.62 55.93 $6.26 $6.60 $8.96 $7.34 Vedre-n C0irpo:ration WC · $2.39· $2.54 $2.69 $2.86 $3.04 $3.23 $3.43 $3.63 $3.85 $4.07 $4.31 $4.55 $4.BD $5.06 $5.34 S5.63 S5.94 Pro-jeeted Anri1.1al Dividend Payout Ratio. [32] (33] [34] [35] [36] [37] [38] !39] [401 [41] [42] [43) [44] [45] [46] _9~mp21ny Tfck"er 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026 2027 2028 2029 2030 2031 Black Hills Corporation BKH 5D.00% 50.51}% 51.00% 51.50% 52.0Q% 54.2.6% 56.53% 58.79% 61.05% ea.a2% 65.58% SS.SS% 65.58% 65.58% 65.58% Cen.tefPoir-t Er-e-rgy, Irie. Cr-IP 62.00% 60.00% 78.00% 76.00% 74.00% 72.60% 71.19% 69.79% 68.39% 66.98% 65.58% 1$5.58% 65.58% 65.5:8% -65.58% Che$;;i.peake Utilitiesi. r::arpi:.r.ation CPK 45.00% 43.00% 41.00% 39.00% 37.00% 41.76% 4B.53% :St ,:£!9% 56.05.% 60.82% 65.58% 65.58% 65.58% 65.5;8% 65.58% Northwest: Natural Gas Campan)I NWN ..'.· 80.00% 76.25% 72.50% .68.75% 65.00% 65.10% 65.19% 65.29% 55.39% 65.48% 65,58% 65,58% 65.56% 155.5.8% SS.58% Sempra Energy SRE . 65.00% 64.00% 63.00% 82.00% 61.00% 61,76% 62,53% 63.29% 64.05% 64.82% 65.56% 65.58% 65.58% 65.58% SS.SS% Southwi!! ?rojected Ann.ual Cash Ftows. (47] [48] [49] (50] [51) [52] [53) [54] [55] [56] [57] [58] [59] [60] !61( [62] Terminal Company Ticker 2017 2018 2019 2020 2D2.1 2023 2024 2025 2026 2027 2028 2.029 2030 2031 Value Bhlliek Hills Corpl)ra.tll)n BKH >:>. .<:..· .. :.:· $1.62 $1.75 $1.90 $2.05 $2.22 $2.47 $2.74 $3.03 $3.34 $3.66 $4.00 $4.22 $4.45 $4.69 $4.95 $185.33 CenterPoi11tEnergy, Inc. $0.99 $1.01 $1.04 $1.07 $1.10 $1.14 $1.18 $1.22 $1.26 $1.30 $1.35 $1.42 $1.50 $1.SS $1.67 $62.41 Chesapeake Utilittes Corporation g~~ ..• . /<••·· .·· $1.42 $1.48 $1.53 $1.58 $1.63 $1.98 $2.38 $2.81 $3.27 $3.76 $4.27 $4.51 $4.75 $5.01 $5.29 $197.97 N-orthwe Projected Ann.ual O.ata tnvestDr Cash FIDws [63( [64] (65] [66] [67] (681 (69] [70] 1711 [72) [73] (74] [75] [76] !771 [78) ]79( [BO] Initial Campany Ticke1· Outdow 4128117 12131117 6130/18 6130/19 6.130(20 6130121 8/30122 6130/23 6/30124 6130125 8130126 6130/27 6130128 6130129 6130130 6130131 6130/32 Blaok HUI& Corporation BKH {$61.79) SO.DO $1.10 $1.68 $1.90 $2.05 $2,2;1 $2.47 $2.74 $3.03 $3.34 $3.66 54.00 $4.22 $4.45 $4.69 SUS $190.28 CeriterPolnt 5nergy, Inc. CNP {$24.91) $0.00 $0.67 $1.01 $1.04 $1.07 $1.10 $1.14 $1.18 $1.22 $1.26 $1.30 $1.35 $1.42 $1.50 $1.58 $1.67 $64,0B Chesapeake Utili1fes Corporation CPK ($65.49) $0.0D $0.9B $1.48 $1.53 $1.58 SU3 $1.98 $2.38 $2.61 $3.27 $3.76 54.27 $4.51 54.75 $5.01 $5.29 $203.26 Northwest Natural Gas. Com:pan!f NWN {$59.19) so.oo $1.16 $1.75 $1.70 $1.68 $1.67 $1.75 $1.83 $1.93 $2.03 $2.14 $2.26 $2.39 S2.52 $2.66 $2.BO $107.75 Sempr:a 5riergy SRE ($105.26) $0.00 $2.55 $4.06 $4.37 $4.62 $4.BS $5.28 $5.71 $6.15 SB.60 $7.07 $7.54 S7.95 $8.39 $8.65 $9.33 $358.79 Southwest Ga:s Corporation &I-IX ($76.46) $0.00 $1.17 $1.79 $1.93 $2.03 $2.14 $2.36 $2.50 $2.85 53.14 $3.43 $3.75 $3.96 $4.17 $4.40 $4.64 $178.50 Spire lri.c SR {$54.75) $0.00 $1.42 $2.16 $2.22 $2.28 $2.33 $2.55 $2.78 $3.02 S3.29 $3.58 S3.89 $4.10 $4.33 $4.55 $4.81 $185.05 Vectren Corporatiori WC ($52.59) $0.00 $1.15 $1.75 $1.84 $1.91 Sl.99 $2.15 $2.33 $2.52 $2.72 $2.93 $3.15 $3.32 $3.50 $3.69 $3.89 $149.69 At1achment RBH-4 Page 18 of20 Multi-stage GrQwth Diseounted Cash Flow Model 180 Day Average Stock Price High EPS Growth Rate Estimate in Fil'&t stage l11puts [1) [2] [3] (4] [5J [8! [?] (BJ [9] [10] [11] 112] [13] [14] Sta.ck ----~S'~S_G~'-""'"-~R_•,.,~E"'~R,_i:.-t~tes~ntt""·o-n-~H-lg-h~Long-Tern Payot.1t Ratic Iterative Sol'Ution Terminal Terminal Company Ttcli:er Price Zacks First Calf Valu!!! Lir.ie Growth Grawth Growfh 2017 202:1 2027 Proof IRR PIE Ratco ~5.G RafiD BlacJc Hills CDrporation BKH 561-79 :5.00% 10.38% 7.50% 5.41% 10.38% 5.48% 50.00% 52.,00% 65,58% ($0,00) 12.a.2% 24.05 4.48 Ce11terPciint Eoergy, lric, CNP 524,91 5.00% 6.06% 6.0C% 4.9B% M6% 5.46% 82.00% 74.00% 65.5B% $Cl.CC 10.19% 24.55 4.48 Che:eapei!!ike Utnltl.e.s Corr;io-rati0in CPK 565.49 6.00% 6.00% 8.00% 14.38% 14.38% 5.48% 45.00% 37.00% 65.58% ($0.00) 14.01o/o 24.55 4-48 Northwest Natural Ga:s Company NllllN 559.19 4.30% 4.50% 6.00% 3.46% 6.00% 5.48% 80.00% 65,00% 65.58% ($0,0D) 7.58% 24.55 4.48 Sempra Energy SRE $105-2B B.70% 9.87% 8.00% 2.73% 9.87% 5,4B% EiEi,OC% 61.00% 65.58% $0.00 13.152% 24.55 4.48 So:uthwee.t-Gas Corporation SINX $76.46- 5.00% 4.00% 6.50% 8.02% B.02% S.48% 53.DO% S2.0D% 65,58% (00.00) 9.69% 24.55 4.48 Spire Inc SR $64.75 4.10% 4.05% 8.00% 5.24% a.oao/o 5.48% 60.00% 54.QO% SS.58% ($0.DD) 11.98% 24_55 4.48 Vectren CDreoration we $52.69 5.70% 5.57% 7.00% 6.46% 7.00% 5.48% 63.1}0% 58.00% 65.58% [$D,OO) 10.75% 24.55 4.48 Mean 11.33% Max 14.01% Min 7.58% Projected Annual E:amings. per Share [15] [16] [17] [18] [19] {20] [21] [22] (23J [24] j25( [26] 127( [28] (29) [30] (31) Company Ticker 2015 2016 2017 2018 2019 2.02.0 2021 2022 2023 2024 2025 2D26 2027 2D26 2029 2030 2031 Black. HJ[[-5 Col'por:atiori BKH · · S2.B3·· $3.12 $3.45 $3.81 $4-20 $4.64 $5.12 $5.61 $6.10 $6.58 $7.05 $7.49 $7.91 $8.34 $8,80 $9,28 $9.79 CenterPoint .Energy, lnc. CNP :.:_·_st.0a-··_ $1.15 $1-21 S1-29 SU7 $1-45 $1.54 $1-63 $1-72 $1-82 $1-93 S2,03 $2,15 $2,26 $2.39 $2.52 $2.66 Chesapeakl!! UtilltJes Cc-rporatfon CPK -<.s2.6{: $3,07 $3,51 $4,01 $4,59 $5,25 sa.oo $6.7B $7.55 $8.30 $9.00 $9.63 $10.16 510.71 $11.30 $11.92 512.57 No-rthwe$t Na.turP:I Gia$ Company NWN --:·.sus···· $2.0S $2.20 S2.33 $2.47 $2.62 $2.78 $2.94 $3.12 $3.30 $3.48 $3.66 $3.88 $4.09 $4.31 $4.55 $4-80 Sempra Snergy SRE :: Projected Annual Dividend Payout Ratio [32] [33] [34] [35] {36] [37] (38J [39] [40) [41] [42( [43] [44) [45) !46] Compa:ny Ticker 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026 2027 2028 2029 2030 2031 Bla:ct HUI& Corpora1fon BKH S0.00% 50.50% 51.00% 51.50% 52.00% 54.215% 515.53% 5S..7S% 61.05% 63.:32% 6"5.5fl.% 65.58% 65.5S% 65.56% 65.58% OenteirPctnt Energy, l:ne. CNP 8:2:.00% 80.00% 78.00% 7S.00% 74.0D% 72.60% 71.19% 69.7:9% 68.39% 66.98% 6"5.58% 65,58% 65.56-% 65.58% 65.:513-% Chesapeake Uthitles Corporatlon CPK 45.00% 43.00% 41.00% 39.00% 37,00% -41,76% 46,53% 51.29% 56,05% 60.82% 65.58% 65.58% 65.56% 65.58% 65,5&% Northw!!!st Natural Gas Compan'J NllllN 8ll.00% 76.,25% 72,50% 68.75% 65,(10% Ei5.10% 65.19% 6S.C!:9% 65.39% 65.48% 85,58% 65.58% D5.5S% 65.5S% 65.5a.% Semr;.ra Energy SRE 65.00% 64.00% 63.00% 62.00% 61.00% 61.76.% 62..:153% 63.2&% 64.05% 64.82o/a 65.58% 65.58% 65.58% 65,58% 65,58% Solllhwest Gas Corporatk1n SINX 53.0(Jo/ii 52.75% 52:.50% 52.25o/a :62.00o/a 5426% 56.53% 58.78% 61.oll5% 63.32% 65,58% 65,58% 65,58% 66.58% 65.58% Splre Inc SR 60.00% 58.50% 57.00% 55.50% 54.00% 55.93% 57,86% 59,79% 61.72% S;l.65% 65.58% 65.58% 65.58% 65.58% 65.58% Vectren C:ari:ic.rntion WC 1!53.00% 61.75% 60.50% 59,25% 58.DO% 5.9..26% 60.53% 61.79% 63.0:5% 64.3211/a. 65,58% 65.58% 65.58% 65.58o/a 65.58% Projected AnnuaI Cash F[ows [47] [48( [49( (50( [51] [52( [53] [54] [55] [56] [57] (581 [59] [60] [61] [62] Termlnal Company Ticker 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026 2027 2028 2029 2030 2031 Value. Black HUis Corpcra:lfon $1.72 $1.92 $2.14 $2.39 $2.66 53.04 $3.45 $3.87 S4.30 $4-75 $5.18 $5.47 $5.n $6.0B $6.42 $240-25 CenterPoint Energy, tnc. $1-00 $1-03 $1-07 suo $1.14 $1-18 $1.23 $1.27 St.32 $1.36 $1.41 $1.48 $1.57 $1.65 $1.74 $65.24 Che$apeah Utilitfe$ Corporation i·•---•·•:•.•>••·-:··_·_ $1.58 $1.72 $1.88 $2.05 $2.22 S2.83 $3.51 $4.26 $5.05 $5.86 $6.66 $7.03 $7.41 $7.82 $8.25 $308.69 Not1bWe5t Natura:I Ga;:; Comi;iany ~~ $1.76 $1.78 $1.79 SI.BO $1.81 St.92 $2.03 $2.15 $2.28 $2.41 $2.54 $2.68 $2.B3 $2.96 $3.15 $117.82 Sempra Energy ~~~ >·:> $4.10 $4-44 $4.80 S5.19 $5.61 $6-20 $6.81 $7-42 $8.03 $8.63 $9.21 S9.71 $10.25 S10.B1 $11.40 $426.77 SINX .:_-:_-:···· Southwe-.$t Ga.s Carporatiori $1.B1 $1,94 $2.09 $2.24 $2.41 $2.71 $3.02 $3.36 $3.71 $4.07 $4.45 $4.69 $4.95 $5.22 $5-51 5206.14 SR .··· Spire Inc $2.21 $2.33 $2.45 S2.58 $2.71 $3.02 $3.34 $3.69 $4.05 $4.42 $4.B1 S5.07 $5.35 $5.64 $5,95 $222.73 Vectren Corporation we $1.72 $1-81 $1-90 51-99 $2.08 52.27 $2.47 $2.6B $2.69 $3.12 $3.36 $3.54 $3.74 $3.94 $4.16 S155.62 Prajec:ted .Annua[ Data Investor C:a:ah Flows [63) [64] [65] J66( [67J (68) [69] [70( [71] [72] [73] 174( [75] !76] [77l [78] [79l [801 lnflial C.ompany TiokE=r Outllo.w 412Bl17 12131117 6130118 613Cl/t9 6/30/2:0 6130121 6130122 6130123 6130124 6130125 6130126 6130127 6130128 6130129 6130130 6130131 6130132 Black Hifls CorporafiDn BKH ($61.79) $0.00 $1.17 SI.Bl $2.14 $2-39 $2.66 S3.D4 $3.45 $3.87 $4-3D $4-75 $5.1B $5.47 $5.77 SS.OB $6.42 $246,67 CenterPoint Energy, tnc. CNP ($24.91) $0.00 $0.67 51-03 51-07 $1-10 $1-14 ;us $1.23 $1-27 $1,32 $1.36 $1.41 $1.48 $1.57 $1.65 51.74 $66.98 Chesapeake Utilities Corpcratian CPK ($65,49) $0,00 $1,07 $1.69 SI.BB $2.05 $2,22 $2,83 $3,51 $4-26 $5.05 $5.86 $6.66 $7.03 $7.41 $7.82 $8-25 $31B.a4 Northwest Natural Gas Cotnpahy NWN ($59.19) $0,00 $1.19 S1.B1 S1.79 $1.80 $1.81 $1.92 $2.03 $2.15 $2.28 $2.41 $2.54 $2.68 52.83 $2,9B 53,15 $120,97 Sempra ~ergy SRE ($1 05.28) $0.00 $2.78 $4.31 $4.80 $5.19 $5.61 $6.20 $6.B1 $7-42 $8.03 5B.63 $9.21 $9,71 $10.25 $10.81 $11.40 $438.17 Southwest Gas Carporation SINX ($76,46) $0,00 $1,22 51.86 $2,09 $2-24 $2,41 $2.71 $3,02 $3,36 $3.71 $4.07 $4.45 $4.69 S4.95 $5-22 $5,51 $211.65 Spire Inc: SR ($64.75) $0.00 $1.50 $2.30 $2.45 52.58 $2.71 $3.02 $3.34 $3.69 $4.05 $4.42 $4.B1 $5.07 $5.35 $5.64 55_95 $228.68 Vectren Corporation WO ($52.69) SD.OP $1.17 $1.78 $1.90 $1.99 $2.08 $2-27 $2.47 $2.6B $2.B9 $3.12 $3.36 $3.54 $3.74 $3,94 $4.16 $159.78 Attachment RBH-4 Page 19 of 20 MtJlti-stage Growth Dfsc;ounted Cash .Flew MDdel 1BO Day Average S1oclc Prfce Law E:PS Growth Rate E$tlmate in Flr$t Stage Inputs [1] f21 [3) [4) [5] [6] [7] [8] [9] [1 O] (11! [12] 113] [!<] Stock _____E_P_S_G_ro_wlh __ Ra_t_• _Es~~~:~:-~;~,-.-~c-ow__ Lorig·Terrr P21yi:i1,1t Rat[o lteratrve Se>lution Te:rmlnal Termln:a! Company Tioker ?rice 2ae:ks First Call Va[ue Line Growth Growth Growth 2017 2021 2027 Proof IRR PIE Ratio PEG Ri!ltiO Black Hm~ Cctporation BKH $61.79 5.00% 10.38% 7.50% S.41% 5.00% 5..48% :SOJ}Oo/a 52.0[}% 65.58% lfjll.00 9.2.6% 24.55 4.48 CenterPoint Energy1 Inc.. CNP $24.91 5.00% 6.06% 6.00% 4.9"6% 4.98% 5.48% 82.1}0% 74.01}% 65,58% .$Q,OO 9.46% 24.55 MB Chesapeake Utilities Corpcraticm CPK $65.49 6.00% 6.00% .S,DO% 14,38% 6.0.C% 5.4:1!i% 45.00o/o 37.00% 65.58% .so.co 8.67% 24.55 4.48 Northwo&$t Natural Ga'Ei Company NWN $59.19 4.30% 4.50% e.00% 3.46% 3.46% 5,48% S0.00% GS.00% 65.58% (.S0.00~ 5.95% 24.55 4.48 Sempra Energy' SRE $105.28 8.70% 9.87% a.DO% 2.73% 2.73% 5.48% 65.00o/o 61.00% 65.58% (.$0.CC~ 8.79% 24.55 4.49 Southw&St Gas Corporation swx $76.46 5.00% 4.00% S.50'°/o- 8.02% 4.0.C% 5.48% 53.00% 52.0C% 65,5S% C"'-OO> 7.11% 24.55 4.48 Spire Inc SR $64.75 4.10% 4,05% 8.00% 5.24% 4.0:5% 5.48% 60.00% 54.00% 65.58% {$0.DC> 9.34% 24.55 4.48 Vecite:n Corpotafon WC $52.69 5.70% 5.57% 7.00% 6.46% 5.57% 5.48% 63.00% 58.()0% 65.56% l.$0.CO> 9.80% 24.55 4.46 Mean 8.55% Max 9.BO% Min 5.95% Pl"o]e-et&d Annual Earnings per Sbate [15) [16) [17l [19) [19) f20) !21) [22) [23] 1241 [25] [26] [27] [28] [29] [30! [31] Company Tle:ke-r 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2026 2028 2029 2030 2031 Blaok Hills Corpor;e!ltiiQn: S2.97 53.12 $3.28 $3.44 $3.61 $3.79 $3.99 $4.19 $4.41 S4.65 $4.90 S5.16 $5,45 $5.75 56.06 $6.39 CenterPaint :Energy, 1111:. ~~~ ~f:~; S1.13 $1.19 $1.25 $1.31 Sl.38 $1.45 $1.52 $1.60 $1.68 S1.77 $1.86 S1.97 $2.07 $2.19 $2.31 $2.44 Chesapeake- U:ttlities Corporation CPI< :·: ·: $2,68:.. : $2.64 53.01 $3.19 $3.38 $3.59 $3.80 $4.03 $4.26 $4.51 S4.7S $5.03 $5,30 SS.59 $5.90 $6.22 $6.56 Nortlwite$t Na'b.lr21[ Gas Comparw NWN :: · $1.96·:.. $2.03 S2.10 $2.17 lla.25 $2.32 $2.40 $2.50 $2.50 $2.72 S2.85 $2.99 S3.16 $3.33 $3.51 $3.70 $3.91 Sempra Energy · SR<. ::.·. $5,23;.'. 55.37 $5.52 $5,67 $5,82 $5.98 $6.15 $6.34 SS.57 $6.84 S7.16 $7.52 57.93 $8.36 $8,82 $9.30 $9,61 Southwest Gas Corporation S3.04 53.16 $3.28 $3.42 $3.55 $3.69 $3.85 $4.02 $4.:!2 S4.43 $4.66 S4.91 SS.18 $5.47 $5.77 $6.08 Sp[rell'".lc s: :.•:··· :;:~~ • 53.29 $3.42 $3.56 $3.70 $3.85 $4.01 $4.18 $4.37 $4.58 S4.81 $5.06 $5.34 55.63 $5.94 $6.27 $6.61 Vectren Cotpot.atit1n WC $2.39 52.52 52.66 $2.81 $2.97 $3.13 $3.31 $3.49 $3.69 $3.89 S4.IO $4.33 S4.57 S4.82 $5.08 $5.36 $5.65 Pro]ecte-d Annual Oividehd ?ayalJt Ratcc [32) [33) [34] [35) {36) [37] [38] 1391 [40] [41] [42] [43] [44] [45) [45] Company Ticker 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026 2027 2028 2029 2030 2031 Black HLll:s Corpor.atlon BKK : ... ·.· .. 50.00% 50.50% :51.00% 51.50% 52..00% 54,26% 5S,53% 58,79% 61,1)5% 63.32°/o 65.58% 65.58% 65.fi8% 65.58% 65.58% CenterPolnt Energy, lnc:. CNP :.··.·ic 82.00% 80.00% 7S.OD% 76.00% 74.00% 72.60% 71.19% 69.79% 68.39% 6U8% 65.58% 65.58% 65.58% 65.58% 65.58% Chesai;ieake Utilities Corporation CPK: 45.00% 43.0-0% 41.00% 39.00% 37,00% 41.76% 46.53% 51.29% 56.05% S0.82% 65.58% 65.5.8% 65,58% 65.58% 65.58% Northwest Natural Gas Campany NWN 80.00% 76.25% 72.50% 68.75% 65.00% 6:5.10% 65.19% 65,29% 65.39%. 65.48% 65.58% 65.58% Ei:S.58·%. 65.58% 85.58% Sempra Energy SRE 65,00% 64.DO% 53,00% 62.00% St,00% 61.76% 62.5~% 63.29% 64.05% 64.82% 65.58% 65.5.8% 65.58% 65.58% 65.56% Southwe5t Gas C-orpori!l:tion swx 53.00% 52.75% 52.50% 52.25% 52.00% 54.2.6% 56.:53% 58.79% Ei1.05% 63.32% 65.56% 85.58% 65.58% 65.5.8% 65,58% Spire Inc SR 60.00% 56.50% 57.00% 55.50% 54.00% :65.93o/a 57.86% 59.79% 61.72% 53.65% 65.:58% 65.58% 65.58% BS.SS% 65.58% Vectren Corporation we 63.00% 61.75% 60.50% 59.25% 56.00% 59.2.6% 60.53% 61.79% 63.05% e:4.3;2% 155.58% 65.5$% 65.58% 65.58% 65.58% Pro-jected Annual Cash Flows [47) )48] 149) [50] [51) [52] [53) [54] [551 [56] [571 [58) 159) [60] 161) [62} Termin:al Company Tti:iker 2017 2018 2019 2020 2021 2022 2023 2024 2025 202S 2027 2028 2029 2030 2031 Value Black Hills CDrp-1mrifcn BKH .... ·.. ::: : .. ·. $1.56 $1.65 $1.75 $1.86 S1.97 $2.16 52.37 $2.59 $2.84 $3.10 $3.39 $3.57 $3.77 $3.97 S4.19 $156.90 CenterPoint Energy, lne. Cl ::.·:···· $0.98 51.00 $1.02 $1.05 S1.07 $1.10 S1.14 $1.17 $1.21 $1.25 $1.29 $1.36 51.44 S1.51 Sl.60 $59.78 Chasapeake Utmties Corporation $1.36 S1.37 $1.39 $1.40 $1.41 $1.69 S1.96 $2.31 $2.67 $3.06 $3.48 $3.57 S3.87 S4.0S $4.30 $151.11 Northwea.t N:i!!tural Ga::; CGrnpany ~: / :: . $1.68 51.66 $1.63 $1.60 S1.56 $1.62 51.69 $1.77 $1.86 $1.96 $2.07 $2.18 52.30 $2.43 S2.56 $95.93 Sempra Energy SRE .··.:·.: ... · $3.59 53.63 $3.67 $3.71 SJ.75 $3.92 $4.11 $4.33 $4.58 $4.87 $5.20 $5.48 $5.79 S5.10 $6.44 $240.96 Souihwest Ga:s Corporaticirt swx ·:· ... :· $1.67 S1.73 $1.79 $1.96 Si.92 $2.09 S2.26 $2.48 $2.70 $2.95 $3.22 $3.40 $3.58 $3.78 $3.99 $149.31 Spirie Inc SR $2.05 S2.08 $2.11 $2.14 $2.17 $2.34 S2.53 $2.74 $2.97 $3.22 $3.50 $3.69 $3.90 $4.11 $4.33 $162.24 Vectren Corporation WC $1.66 $1.74 $1.80 $1.86 S1.92 $2.07 $2.23 $2.40 $2.59 $2.78 $2.99 $3.16 S3.33 $3.51 $3.71 $138.79 Prnjected AllhUal Data lnvesmr Cash Flows [63) [64) [65] 166} 1671 [68] [Ba] [70] [71) [72] [731 [74] 175) [76] 178) 1791 [BO] Initial Company ltcker Out'flow 4128117 12131117 6130118 6130118 6130/20 6130121 6130122 6130123 6130124 6130125 6130126 6130127 Sl3D.12.B 6130/29 6130130 6130131 6130132 Blao.k Hills Corpo.-atfon BKH [S61.79) $0,00 51.06 $1.60 $1.75 $1.86 $1.97 $2.16 $2.37 $2.59 52.84 $3.10 $3.39 S3.57 $3.77 $3.97 $4.19 $161.15 Center?c.int Energy, Inc. CNP (S24.91) $0.00 S0.66 $1.DO $1.02 51.05 $1.07 $1.10 $1.14 $1.17 51.21 $1.25 51.29 $1.36 $1.44 $1.51 $1.60 $61,38 Chesapeake Utilities. Carporatlon CPK (565.411) $0.00 S0.92 $1.40 $1.39 51.40 $1.41 $1.68 $1.98 $2.31 52.67 $3,06 $3.49 $3.67 $3.97 $4.08 $4.30 $165.41 Northwe$t Natural G;eis Compa:ny l>IWN (559.19) $0,00 $1.14 $1.71 $1.63 S1.60 $!.56 $1.62 $1.69 $1.77 51.86 $1.96 52.07 S2.IB $2.30 $2.43 $2.56 $98.49 .Sempta Energy SRc ($105.28) $0,00 $2.43 $3.64 $3.67 $3.71 $3.75 $3.92 $4.11 $4.33 54.58 $4.87 55.20 55.48 $5.78 $6,10 $6.44 $247.39 Southwe:st Gas Corporation swx ($76.40) $0.00 51.13 $1.71 $1.79 S1.86 $1.92 $2.09 $2.28 $2.48 S2.70 $2.95 S3.22 $3.40 $3.58 $3.78 $3.99 Sl53.30 Spire [no SR (554.75) $0.00 51.39 $2.09 $2.11 52.14 $2.17 $2.34 $2.53 $2.74 S2.97 $3.22 53.50 $3.69 $3.90 $4.11 $4.33 5166.57 Vectren Corporation WC (552.69) $0.00 $1.14 $1.72 $1.80 $1.86 $!.92 $2.07 52.23 $2.40 52.59 $2.78 52.99 S3.16 $3.33 $3.51 $3.71 5142.50 Attachment RBH-4 Page 20 of20 Multi-Stage DCF Notes: [1] Source: Bloomberg; based on 30-, 90-, and 1 BO-day historical average as of April 2B, 2017 [2] Source: Zacks [3] Source: Yahoo! Finance [4] Source: Value Line [5] Source: Attachment RBH-3, Value Line [6] Equals indicated value (average, minimum, maximum) from Columns [2], [3], [4], [5] [7] Source: Federal Reserve, Bureau of Economic Analysis, Blue Chip Financial Forecast [6] Source: Value Line [9] Source: Value Line [10] Source: Bloomberg Professional [11] Equals Column [1] +Column [63] [12] Equals result of Excel Solver function; goal: Column [11] equals $0.DD [13] Equals Proxy Group 30-day average PE ratio. Source: SNL Financial [14] Equals Column [13] I (Column [7]x 100) [15] Source: Value Line [16] Equals Column [15] x (1 +Column [6]) [17] Equals Column [16] x (1 +Column [61) [18] Equals Column [17] x (1 +Column [6]) [19] Equals Column [18] x (1 +Column [6)) [20] Equals Column [19] x (1 +Column [6]) [21] Equals Column [20] x (1 +Column [6]) [22] Equals (1 +(Column (6] +(((Column [7] - Column [6]) I (2027- 2022 + 1)) x (2022-2021)))) x Column [21] [23] Equals (1 +(Column [6] +(((Column [7] - Column [6]) I (2027- 2022 + 1)) x (2023-2021)))) x Column [22] [24] Equals (1 +(Column [6] +(((Column [7] - Column [6]) I (2027 - 2022 + 1)) x (2024 - 2021)))) x Column [23] [25] Equals (1 +(Column [6] +(((Column [7] - Column [6]) I (2027 - 2022 + 1)) x (2025 - 2021 )))) x Column [24] [26] Equals (1 + (Column [6] +(((Column [7] - Column {6]) I (2027 - 2022 + 1)) x (2026 - 2021 )))) x Column [25] [27] Equals Column [26] x (1 +Column [7]) · [2B] Equals Column [27] x (1 +Column [7]) [29] Equals Column [28] x (1 +Column [7]) [30] Equals Column [29] x (1 +Column [7]) [31] Equals Column [30] x (1 +Column [7]) [32] Equals Column [BJ [33] Equals Column [32] +((Column [36] - Column [321) 14) [34] Equals Column [33] +((Column [36] - Column [32]) 14) [35] Equals Column [34] +((Column [36] - Column [32]) 14) [36] Equals Column [9] [37] Equals Column [36] +((Column [42] - Column [36]) / 6) [38] Equals Column [37] +((Column [42] - Column [36]) / 6) [39] Equals Column [36] +((Column [42] - Column [36]) 16) [40] Equals Column [39] +((Column [42] - Column [36]) I 6) [41] Equals Column [40] +((Column (42] - Column [361) I 6) [42] Equals Column [1 DJ [43] Equals Column [1 D) [44] Equals Column [10] [45] Equals Column [10] [46] Equals Column [10] [47] Equals Column [17] x Column [32] [48] Equals Column [16] x Column [33] [49] Equals Column [19] x Column [34] [50] Equals Column [20] x Column [35] [51] Equals Column [21] x Column [36] [52] Equals Column [22] x Column [37] [53] Equals Column [23] x Column [38] [54] Equals Column [24] x Column [39] [55] Equals Column [25] x Column [40] [56] Equals Column [26] x Column [41] [57] Equals Column [27] x Column [42] [58] Equals Column [28] x Column [43] [59] Equals Column [29] x Column [44] [60] Equals Column [30] x Column [45] [61] Equals Column [31] x Column [46] [62] Equals Column [31] x Column [13] [63] Equals negative net present value; discount rate equals Column [12], cash flows equal Column [64] through Column [BO] [64] Equals $0.00 [65] Equals Column [47] x (1213112017 - 4128/2017) 1365 [66] Equals Column [47] x (1 + (0.5 x Column [6])) [67] Equals Column [49] [68] Equals Column [50] [69] Equals Column [51] [70] Equals Column [52] [71] Equals Column [53] [72] Equals Column (54] [73] Equals Column [55] [74] Equals Column [56] [75] Equals Column [57] [76] Equals Column [58] [77] Equals Column [59] [78] Equals Column [60] [79] Equals Column [61] [80] Equals Column [61] + [62] Attachment RBH-5 Page 1 of 12 Ex-Ante Market Risk Premium Market DCF Method Based - Bloomberg 111 [2] [3] S&P 500 Current 30-Year Est. Required Treasury (30-day Implied Ma!kel Riok Markel Return average) Premium 13.37% 2.97% 10.39% [41 [5] (6] [7] !BJ [9] Markel EsUmated Dividend Long-Term Growth Weighted Company Ticker Capltallzation Weight In Index Yield Est. DCF Result DCFResult AGILENT TECHNOLOGIES INC A 17,742.66 O.OB% 0.93% 8.66% 9.84% 0.0082% AMERICAN AIRLINES GROUP INC ML 20,994.14 0.10% 1,00% -2.71% -1.73% -0.0017% ADVANCE AUTO PARTS INC MP 10,492.60 0.05% 0.17% 13.58% 13.74% 0.0068% APPLE INC MPL 753,665.47 3.55% 1.59% 10.64% 12.32% 0.4377% ABBVIEINC ABBY 105,0B0.45 0.50% 3,90% 9,27% 13.35% 0.0661% AMERISOURCEBERGEN CORP ABC 17,827.BO 0.08% 1.78% 9.46% 11.33% 0.0095% ABBOTT LABORATORIES ABT 75,409.82 0.36% 2.49% 10.70% 13.32% 0.0474% ACCENTURE PLC-CL A ACN 78,616.83 0.37% 2,00% 10,07% 12.17% 0.0451% ADOBE SYSTEMS INC ADBE 66,160.91 0.31% 0.00% 17.48% 17.48% 0.0545% ANALOG DEVICES INC ADI 27,819.91 0.13% 2.16% 10.96% 13.24% 0.0174% ARCHER-DANIELS-MIDLAND CO ADM 26,107.99 0.12% 2.81% 11.86% 14.84% 0.0183% AUTOMATIC DATA PROCESSING ADP 46,905.83 D.22% 2.14% 11.02% 13.27% 0.0294% ALLIANCE DATA SYSTEMS CORP ADS 13,948.55 0.07% 0,84% 14.50% 15.40% 0.0101% AUTODESK INC ADSK 19,891.89 0.09% 0.00-0-1~ 24.33% 24.33% 0.0226% AMEREN CORPORATION AEE 13,269.70 0.06% 3.28% 6.00% 9.37% 0.0059% AMERICAN ELECTRIC POWER AEP 33,352.83 0.16% 3.51% 4.75% 8.34% 0.0131% AES CORP AES 7,456.84 0.04% 4.27% 4.37% B.73% 0.0031% AETNA INC AET 44,805.97 0.21% 1.48% 11.72% 13.29% 0.0281% AFLAC INC AFL 30,040.15 0.14% 2.34% 3.30% 5.67% 0.0080% ALLERGAN PLC AGN 81,814.13 0.39% 1.16% 12.73% 13.96% 0.0538% AMERICAN INTERNATIONAL GROUP AIG 59,665.00 0.28% 2.22% 11.00% 13.34% 0.0375% APARTMENT INVT & MGMT CO -A AIV 6,867.94 0.03% 3.33% 25.40% 29.14% 0.0094% ASSURANT INC AIZ 5,329.22 0.03% 2.25% 21.41% 23.90% 0.0060% ARTHUR J GALLAGHER & CO AJG 10,016.53 0.05% 2.80% 9.95% 12.88% 0.0061% AKAMAI TECHNOLOGIES INC AKAM 10,537.62 0.05% 0.00% 14.18% 14.16% 0.0070% ALBEMARLE CORP ALB 12,061.90 0.06% 1.17% 11.60% 12.84% 0.0073% ALASKA AIR GROUP INC ALK 10,525.35 0.05% 1.42% 10.66% 12.16% 0.0060% ALLSTATE CORP ALL 29,687.40 0.14% 1.73% 9.70% 11.52% 0.0161% ALLEGION PLC ALLE 7,493.36 0.04% 0.78% 13.02% 13.85% 0.0049% ALEXION PHARMACEUTICALS INC ALXN 28,693.83 0.14% 0.00% 21.77% 21.77% 0.0294% APPLIED MATERIALS INC AMAT 43,651.94 0.21% 1.02% 15.72% 16.82% 0.0348% ADVANCED MICRO DEVICES AMO 12,520.60 0.06% 0.00% 8.33% 8.33% 0.0049% AMETEK INC AME 13,156.82 0.06% 0.68% 10.29% 11.01% 0.0068% AFFILIATED MANAGERS GROUP AMG 9,369.81 0.04% 0.48% 13.98% 14.50% 0.0064% AMGEN INC AMGN 120,105.39 0.57% 2.82% 6.81% 9.73% 0.0551% AMERIPRISE FINANCIAL INC AMP 19,671.48 0.09% 2.53% 10.40% 13.07% 0.0121% AMERICAN TOWER CORP AMT 53,525.69 0.25% 2.06% 17.96% 20.23% 0.0510% AMAZON.COM INC AM2N 442,122.56 2.08% 0.00% 35.49% 35.49% 0.7398% AUTONATION INC AN 4,252.98 0.02% 0,00% 7.92% 7.92% 0.0016% ANTHEM INC ANTM 47,138.40 0.22% 1.46% 8.15% 9.87% 0.0215% AON PLC AON 31.470.08 0.15% 1.15% 9.77% 10.97% 0.0163% APACHE CORP APA 18,501.20 0,09% 2.06% -14,70% -12.80% -0.0112% ANADARKO PETROLEUM CORP APC 31,657.16 0.15% 0.35% -0.49% -0.14% -0.0002% AIR PRODUCTS & CHEMICALS INC APD 30,590.29 0.14% 2.57% 8.19% 10.86% 0.0157% AMPHENOL CORP-CL A APH 22,082,65 0.10% 0.89% 10.03% 10.95% 0.0114% ALEXANDRIA REAL ESTATE EQUIT ARE 10,246.67 0.05% 2.98% 6.97% 10.05% 0.0049% ARCONICINC ARNC 12,042.81 0,06% 0.97% 13.10% 14.13% 0,0080% ACTIVISION BLIZZARD INC ATVI 39,373.86 0.19% 0.29% 9.46% 9.76% 0.0181% AVALONBAY COMMUNITIES INC AVB 26,099.26 0.12% 3.00% 6.96% 10.06% 0.0124% BROADCOM LTD AVGO 88,624.85 0.42% 1.65% 15.42% 17.41% 0,0728% AVERY DENNISON CORP AVY 7,332.77 0.03% 2.03% 7.10% 9.20% 0.0032% AMERICAN WATER WORKS CO INC AWK 14,175.49 0.07% 2.05% 7.00% 9.12% 0.0061% AMERICAN EXPRESS CO AX.P 70,832,00 0.33% 1.67% 8.20% 9.94% 0.0332% ACUITY BRANDS INC AYI 7.764.69 0.04% 0.30% 20.00% 20.33% 0.0074% AUTOZONE INC AZO 19,663.15 0.09% 0.00% 13.66% 13,66% 0,0127% BOEING COfrHE BA 111,559.87 0.53% 3.07% 14.33% 17.62% 0.0927% BANK OF AMERICA CORP BAC 233,676.75 1.10% 1.62% 13.94% 15.67% 0.1727% BAXTER INTERNATIONAL INC BAX 30,176,19 0.14% 0.97% 12.68% 13.71% 0.0195% BED BATH & BEYOND INC BBBY 5.624.71 0.03% 1.02% 5.53% 6.58% 0.0017% BB&T CORP BBT 35,034.97 0.17% 2..94% 8.41% 11.47% 0.0189% BEST BUY CO INC BBY 16,015.03 0.08% 2.52% 11.44% 14.11% 0.0107% CR BARD INC BCR 22,266.83 0.10% 0,35% 9,30% 9.66% 0.0101% BECTON DICKINSON AND CO BOX 39,791.91 0.19% 1.57% 10.19% 11.84% 0.0222% FRANKLIN RESOURCES INC BEN 24,198.35 0.11% 1.86% 10.00o/o 11.96% 0.0136% BROWN-FORMAN CORP-CLASS B BFIB 18,291.27 0.09% 1.51% 1.53% 3.04% 0.0026% BAKER HUGHES INC BHI 25,259.78 0.12% 1.15% 20.50% 21.76% 0.0259% BIOGEN INC BUB 57,527.76 0.27% 0,00% 7.70% 7.70% 0.0209% BANK OF NEW YORK MELLON CORP BK 48,737.00 0.23% 1.76% 12.31% 14.17% 0.0326% BLACKROCK INC BLK 62,833.27 0.30% 2.61% 13.87% 16.66% 0.0494% BALL CORP BLL 13,460.89 0.06% 0.67% 5.50% 6.19% 0.0039% BRISTOL-MYERS SQUIBB CO BMY 92,338.70 0.44% 2.83% 13.26% 16.26% 0.0709% BERKSHIRE HATHAWAY INC-CL B BRKIB 407,512.26 NIA 0,00% NIA NIA NIA BOSTON SCIENTIFIC CORP BSX 36,113.47 0.17% 0.00% 9.80% 9.80% 0.0167% 60RGWARNER INC 6WA 8,972.64 0.04% 1.32% 6.13% 7.49% 0.0032% BOSTON PROPERTIES INC BXP 19,477.31 0.09% 2.38% 5.33% 7.78% 0.0071% CITIGROUP INC c 163,458.84 0.77% 1.34% 4.43% 5.60% 0.0447% CAINC CA 13,722.09 0.06% 3.12% 6.05% 9.26% 0.0060% CONAGRA BRANDS INC CAG 16,500.95 0.08% 2.18% 6.55% 10.92% 0.0085% CARDINAL HEALTH INC CAH 22,696.86 0.11% 2.39% 8.33% 10.81% 0.0117% Attachment RBH-5 Page 2of12 !41 [SJ [6] [7] {B] [9) Market Estimated Dividend Long-Term Growth Weighted Company Ticker Capllalization Weight in Index Yield Est, DCFResult DCFResult CATERPILIAR ING CAT 60,247.20 0.26% 3.03% 7.64% 10.76% 0.0306% CHUBB LTD GB 63,928.46 0.30% 2.03% 10.63% 12.77% 0.0385% GBRE GROUP INC -A GBG 12,099.29 0.06% 0.00% 10.23% 10.23% 0.0058% GBOE HOLDINGS ING CBOE 9,228.64 NIA 1.24% N/A NIA NIA CBS CORP-CIASS B NON VOTING CBS 27,154.66 0.13% 1.09% 12.64% 13.60% 0,0177% CROWN CASTLE INTL GORP CCI 34,633.89 0.16% 4.07% 19.97% 24.44% 0.0399% CARNIVAL CORP CCL 44,711.68 D.21% 2.38% 13.55% 16.09% 0.0339% CELGENE CORP CELG 96,661.26 0.46% 0,00% 20.68% 20.68% 0,0944% GERNER CORP CERN 21,369.07 0.10% 0.00% 12.62% 12.62% 0.0129% CF INDUSTRIES HOLDINGS INC CF 6,235.36 0.03% 4.49% -0.05% 4.44% 0.0013% CITIZENS FINANCIAL GROUP CFG 16,697.26 0.09% 1.65% 19.13% 20,93% 0,0184% CHURCH & DWIGHT CO INC CHO 12,582.40 0.06% 1.53% !l.02% 10.62% 0.0063% CHESAPEAKE ENERGY CORP CHK 4,776.26 0.02% 0.00% -0.57% -0.57% --0.0001% C.H. ROBINSON WORLDWIDE ING CHRW 10,307.46 0.05% 2.50% 9.28% 11.89% 0.0056% CHARTER COMMUNICATIONS INC-A CHTR 106.729.90 0.50% 0.00% 22.33% 22.33% 0.1124% CIGNA CORP Cl 40,135.44 0.19% 0.03% 11.98% 12.01% 0.0227% CINCINNATI FINANCIAL CORP CINF 11,872.37 NIA 2.77% NIA N/A NIA COLGATE-PALMOLIVE CO CL 63,632.42 0.30% 2.26% 9.26% 11.62% 0.0349% CLOROX COMPANY CLX 17,147.86 0.06% 2,40% 7.01% 9.50% 0.0077% COMERICA INC CMA 12.465.74 0.06% 1.41% 10.97% 12.46% 0.0073% COMCAST CORP-CIASS A CM CSA 185.876.46 0.88% 1.54% 10.31% 11.93% 0.1046% CME GROUP INC CME 39,460.81 0.19% 5,02% 9,84% 15,10% 0,0281% CHIPOTLE MEXICAN GRILL INC CMG 13,599.75 0.06% 0.00% 20.00% 20.00% 0.0128% CUMMINS INC CMI 25,353.56 0.12% 2.75% 6.00% 8.83% 0.0100% CMS ENERGY CORP CMS 12,712.60 0,06% 2.93% 6.33% 9.36% 0.0056% CENTENE CORP CNC 12,817.46 0.06% O.OOo/o 13.22% 13.22% 0.0080% CENTERPOINT ENERGY INC CNP 12,295.23 0.00% 3.77% 6,00% 9.88% 0,0057% CAPITAL ONE FINANCIAL CORP COF 38,800,02 0.18% 2.11% 4.52% 6.66% 0.0122% CABOT OIL & GAS CORP COG 10,818.76 0.05% 0.34% 41.29% 41.70% 0.0213% COACH INC COH 11,053.47 0,05% 3,44% 10,89% 14.51% 0.0076% ROCKWELL COLLINS INC COL 16,902.49 0.08% 1.27% 9.57% 10.90% 0.0087% COOPER COS INC/THE coo 9,803.39 0.05% 0.04% 11.64% 11.66% 0.0054% CONOCOPHILLIPS COP 59,267.09 0.28% 2.23% 7.00% 9.31% 0.0260% COSTCO WHOLESALE GORP COST 77,920.84 0.37% 1.02% 10.40% 11.47% 0.0421% COTY INC-CLA COTY 13,336.05 0.06% 2.97% 1.69% 4.89% 0.0031% CAMPBELL SOUP CO CPB 17,513.96 0.06% 2.45% 4.98% 7.49% 0.0002% SALESFORCE.COM INC CRM 61,260.46 0.29% 0.00% 25.53% 25.53% 0.0737% CISCO SYSTEMS INC csco 170,617.66 0,80% 3.21% 7.44% 10.77% 0.0866% CSRAINC CSRA 4,743.24 0.02% 1.3S% 6.20% 7.63o/o 0.0017% CSX CORP CSX 46,906.06 0.22% 1.52% 9.90% 11.50% 0.0254% CINTAS CORP CTAS 12,896,85 0.06% 1.09% 11.15% 12.30% 0.0075% CENTURYLINK INC CTL 14,089.33 0.07% 8.41% -4.08% 4.16% 0.0028% COGNIZANT TECH SOLUTIONS-A CTSH 35,475.16 0.17% 0.78% 13.78% 14.61% 0.0244% CITRIX SYSTEMS INC CTXS 12,236.75 0.06% 0.00% 10.34% 10.34% 0.0000% CVS HEALTH CORP CVS 85,390.62 0.40% 2.37% 11.89% 14.40% 0.0580% CHEVRON CORP cvx 202,149.72 0.95% 4.07% 29.90% 34.57% 0.3295% CONCHO RESOURCES INC cxo 18,767.33 0.09% 0.00% 3.24% 3.24% 0.0029% DOMINION RESOURCES INCNA D 48,643.96 0.23% 3.88% 5.68% 9.67% 0.0222% DELTA AIR LINES INC DAL 33,422.50 0.16% 1.99% 11.44% 13.55% 0.0214% DU PONT (E.1.) DE NEMOURS DD 69,145.80 0.33% 1.86% 6.72% 8.64% 0.0282% DEERE&CO DE 35,523.58 0.17% 2.18% 7.70% 9.96% 0.0167% DISCOVER FINANCIAL SERVICES DFS 24,026.33 0.11% 1.S9% 6.91% 8.97% 0.0102% DOLIAR GENERAL CORP DG 19,987.41 0.09% 1.43% 9,65% 11.16% 0,0105% QUEST DIAGNOSTICS INC DGX 14,436.46 0.07% 1.66% 6.51% 10.27% 0.0070% DR HORTON INC DHI 12,352.74 0.06% 1.20% 11.77% 13.04% 0.0076% DANAHER CORP OHR 57,841.05 0.27% 0,68% 10.41% 11.13% 0.0303% WALT DISNEY CO/THE DIS 182,792.30 0.66% 1.36% 7.75% 9.16% 0.0790% DISCOVERY COMMUNICATIONS-A DISCA 16,512.38 0.06% 0.00% 14.07% 14.07% 0.0110% DISH NETWORK CORP-A DISH 29,989.41 0,14% 0.00% 2.99% 2.99% 0.0042% DELPHI AUTOMOTIVE PLC DLPH 21,650.70 0.10% 1.51% 11.76% 13.35% 0.0136% DIGITAL REALTY TRUST INC DLR 18,601.69 0.09% 3.25% 5,10% 8.42% 0,0074% DOLLAR TREE INC DLTR 19,556.38 0.09% 0.00% 15.23% 15.23% 0.0140% DOVER CORP DOV 12,279.23 0.06% 2.29% 13.63% 16.08% 0.0093% DOW CHEMICAL COfTHE DOW 76,722.93 0,36% 3.17% 6.58% 9.86% 0.0357% DR PEPPER SNAPPLE GROUP INC DPS 16,846.60 0.08% 2.46% 6.56% 11.17% 0.0069% DARDEN RESTAURANTS INC DRI 10,592.41 0.05% 2.63% 9.69% 12.44% 0,0062% DTE ENERGY COMPANY DTE 18,762.22 0,09% 3.17% 5.50% 8.75% 0.0077% DUKE ENERGY CORP DUK 57,740.37 0.27% 4.26% 5.05% 9.42% 0.0257% DAVITA INC DVA 13,429.35 0.06% 0.00% 8.84% 8.64% 0.0056% DEVON ENERGY CORP DVN 20,758,47 0.10% 0.61% 16.53% 19.19% 0.0188% DXC TECHNOLOGY CO DXC 21,367.56 NIA 0.00% NIA NIA NJA ELECTRONIC ARTS INC EA 29,229,64 0.14% 0.00% 11.27% 11.27% 0.0155% EBAY INC EBAY 36,180.91 0.17% 0.00% 9.52% 9.52% 0.0162% ECOLAB INC ECL 37,443.50 0,18% 1.15% 13.00% 14.22% 0.0251% CONSOLIDATED EDISON INC ED 24,202.16 0.11% 3.47% 3.27% 6.60% 0.0076% EQUIFAX INC EFX 16,265.86 0.06% 1.10% 8.90% 10.05% 0.0077% EDISON INTERNATIONAL EIX 26,055.12 0.12% 2.74% 4.76% 7.56% 0.0093% ESTEE IAUDER COMPANIES-CL A EL 31,928.60 0.15% 1.49% 10.82% 12.39% 0.0187% EASTMAN CHEMICAL CO EMN 11,629.53 0,05% 2.55% 6.40% 9.03% 0.0050% EMERSON ELECTRIC CO EMR 38,884.50 0.18% 3.20% 7.08% 10.39% 0.0191% EOG RESOURCES INC EOG 53,387.27 0.25% 0.73% -8.06% ..S.37% -0.0135% EQUINIXINC EQIX 32,543.78 0.15% 1.92% 21.38% 23.50% 0.0361% EQUITY RESIDENTIAL EQR 23,709.76 0.11% 3.17% 9.07% 12.38% 0.0136% EQT CORP EQT 10,076.59 0.05% 0,21% 15,00% 15.22% 0.0072% EVERSOURCEENERGY ES 18,823.02 0.09% 3.21% 6.00% 9.31% 0.0083% EXPRESS SCRIPTS HOLDING CO ESRX 36.406.95 0.17% 0.00% 11.99% 11.99% 0.0206% ESSEX PROPERTY TRUST INC ESS 16,026.97 0.08% 2.62% 6.95% 9.67% 0.0075% E"TRADE FINANCIAL CORP ETFC 9,490.91 0.04% 0.00% 16.17% 16.17% 0.0072% EATON CORP PLC ETN 33,926.62 0.16% 3,16% 9,20% 12.50% 0.0200% ENTERGY CORP ETR 13,738.64 0.06% 4.62% -2.70% 1.B6% 0.0012% Attachment RBH-5 Page 3of12 [4l [5] 61 fll [8] [9 Market Estimated Dividend Long-Term Growth Weighted Company Ticker Capitalization Weightin lndox Yield Est. DCFRes"ll DCF Result ENVISION HEALTHCARE CORP EVHC 6,584.77 0.03% 0.00% 9.99% 9.99% 0.0031% EDWARDS LIFESCIENCES CORP EW 23,160.76 0.11% 0.00% 16.68% 16.68% 0.0182% EXELON CORP EXC 32,059.18 0.15% 3.76% 4.33% 8.18% 0.0124% EXPEDITORS INTL WASH INC EXPO 10,135.25 0.05% 1.46% 7.85% 9.39% 0.0045% EXPEDIA INC EXPE 20,184.46 0.10% 0.84% 19.18% 20.10% 0.0191% EXTRA SPACE STORAGE INC EXR 9,510.16 0.04% 4.44% 7.54% 12.15% 0.0054% FORD MOTOR CO F 45,673.38 0.22% 5.32% 3.62% 9.24% 0.0199% FASTENAL CO FAST 12,924.31 0.06% 2.84% 14.37% 17.41% 0.0106% FACEBOOK INC-A FB 435,328.93 2.05% 0.00% 25.04% 25.04% 0.5140% FORTUNE BRANDS HOME & SECURI FBHS 9,784.37 0.05% 1.12% 12.53% 13.72% 0.0063% FREEPORT-MCMORAN INC FCX 18,444.74 0.09% 0.00% 12.55% 12.55% 0.0109% FEDEXCORP FDX 50,721.03 0.24% 0.88% 13.67% 14.61% 0.0349% FIRSTENERGY CORP FE 13,285.58 0.06% 4.81% -0.30% 4.51% 0.0028% F5 NETWORKS INC FFIV 8,366.03 0.04% 0.00% 12.21% 12.21% 0.0048% FIDELITY NATIONAL INFO SERV FIS 27,758.72 0.13% 1.39% 11.10% 12.56% 0.0164% FISERV INC FISV 25,302.71 0.12% 0.00% 10.13% 10.13% 0.0121% FIFTH THIRD BANCORP FITB 18,337.68 0.09% 2.41% 3.30% 5.75% 0.0050% FOOT LOCKER INC - Fl 10,149.56 0.05% 1.59% 10.12% 11.80% 0.0056% FLIR SYSTEMS INC FLIR 5,008.88 N/A 1.49% N/A N/A N/A FLUOR CORP FLR 7,171.29 0.03% 1.66% 16.85% 18.65% 0.0063% FLOWSERVE CORP FLS 6,637.97 0.03% 1.51% 11.74% 13.34% 0.0042% FMC CORP FMC 9,800.12 0.05% 0.94% 12.00% 13.00% 0.0060% TWENTY-FIRST CENTURY FOX-A FOXA 55,981.50 0.26% 1.26% 9.84% 11.16% 0.0295% FEDERAL REAL TY INVS TRUST FRT 9,446.68 0.04% 3.08% 6.26% 9.44% 0.0042% TECHNIPFMC PLC FTI 14,058.42 0.07% 1.66% -6.95% -5.35% -0.0035% FORTIVE CORP FTV 21,924.93 0.10% 0.39% 7.65% 8.06% 0.0083% GENERAL DYNAMICS CORP GD 58,463.62 0.26% 1.70% 8.55% 10.32% 0.0285% GENERAL ELECTRIC CO GE 252.465.61 1.19% 3.29% 10.03% 13.48% 0.1604% GGPINC GGP 19,091.31 0.09% 4.27% 5.90% 10.30% 0.0093% GILEAD SCIENCES INC GILD 69,611.07 0.42% 3.12% 0.34% 3.47% 0.0146% GENERAL MILLS INC GIS 33,133.55 0.16% 3.34% 8.10% 11.57% 0.0181% CORNING INC GLW 26,548.68 0.13% 2.13% 9.19% 11.41% 0.0143% GENERAL MOTORS CO GM 52,275.62 0.25% 4.46% 10.14% 14.63% 0.0365% ALPHABET INC-CL A GOOGL 632,353.25 2.98% 0.00% 16.26% 16.26% 0.4847% GENUINE PARTS CO GPC 13,563.20 0.06% 2.95% 10.32% 13.41% 0.0086% GLOBAL PAYMENTS INC GPN 12,467.74 0.06% 0.05% 12.00% 12.05% 0.0071% GAPINCfrHE GPS 10,485.78 0.05% 3.51% 5.46% 9.06% 0.0045% GARMIN LTD GRMN 9,561.62 0.05% 3.93% 2.45% 6.42% 0.0029% GOLDMAN SACHS GROUP INC GS 93,458.61 0.44% 1.30% 7.16% 8.50% 0.0375% GOODYEAR TIRE & RUBBER CO GT 9,122.51 NIA 1.14% N/A NIA NIA WW GRAINGER INC GWW 11,254.78 0.05% 2.61% 12.28% 15.04% 0.0080% HALLIBURTON CO HAL 39.817.80 NIA 1.57% NIA NIA NIA HASBRO INC HAS 12,369.42 0.06% 2.29% 9.45% 11.85% 0.0069% HUNTINGTON BANCSHARES INC HBAN 14,019.71 0.07% 2.58% 10.35% 13.07% 0.0066% HANESBRANDS INC HSI 8,124.18 0.04% 2.68% 13.86% 16.75% 0.0064% HCA HOLDINGS INC HCA 31,194.82 0.15% 0.00% 11.18% 11.18% 0.0164% WELLTOWER INC HCN 25,947.43 0.12% 4.90% 4.59% 9.61% 0.0118% HCP INC HCP 14,684.81 0.07% 4.96% -1.90% 3.01% 0.0021'1'· HOME DEPOT INC HD 187,502.48 0.88% 2.25% 12.56% 14.95% 0.1321% HESS CORP HES 15.455.83 0.07% 2.07% -9.60% -7.63% -0.0056% HARTFORD FINANCIAL SVCS GRP HIG 17,765.57 0.08% 1.99% 9.50% 11.58% 0.0097% HARLEY-DAVIDSON INC HOG 9,977.39 0.05% 2.59% B.80% 11.50% 0.0054% HOLOGICINC HOLX 12,610.23 0.06% 0.00% 10.22% 10.22% 0.0061% HONEYWELL INTERNATIONAL INC HON 99,973.03 0.47% 2.05% 9.29% 11.43% 0.0539% HELMERICH & PAYNE HP 6,583.26 0.03% 4.63% 4.10% 8.82% 0.0027% HEWLETT PACKARD ENTERPRIS HPE 30,683.04 NIA 1.40% N/A N/A NIA HPINC HPQ 31,820.52 0.15% 2.84% 1.75% 4.61% 0.0069% H&R BLOCK INC HRB 5,135.68 0.02% 3.54% 11.00% 14.74% 0.0036% HORMEL FOODS CORP HRL 18,554.28 0.09% 1.87% 4.07% 5.98% 0.0052% HARRIS CORP HRS 13,926.02 NIA 1.89% NIA NIA NIA HENRY SCHEIN INC HSIC 13,856.01 0.07% 0.00% 10.09% 10.09% 0.0066% HOST HOTELS & RESORTS INC HST 13,245.74 0.06% 4.57% 3.40% 6.05% 0.0050% HERSHEY corrHE HSY 23,023.52 0.11% 2.33% 10.30% 12.75% 0.0138% HUMANA INC HUM 32,026.27 0.15% 0.71% 12.53% 13.28% 0.0201% INTl BUSINESS MACHINES CORP IBM 150,591.96 0.71% 3.60% 6.64% 10.36% 0.0736% INTERCONTINENTAL EXCHANGE IN ICE 35,725.91 0.17% 1.33% 11.30% 12.71% 0.0214% IDEXX LABORATORIES INC IDXX 14,780.95 0.07% 0.00% 12.32% 12.32% 0.0086% INTL FLAVORS & FRAGRANCES IFF 10,944.85 0.05% 1.85% 6.55% 8.46% 0.0044% ILLUMINA INC llMN 26,990.36 0.13% 0,00% 14.61% 14.61% 0.0186% INCYTECORP INCY 25,425.94 0.12% 0.00% 42.38% 42.36% 0.11508% INTELCORP INTC 170,230.35 0.80% 3.00% 7.79% 10.90% 0.0875% INTUIT INC INTU 32,02-6.88 0.15% 1.06% 14.76% 15.94% 0.0241% INTERNATIONAL PAPER CO IP 22,284.02 0.11% 3.43% 6.86% 10.41% 0.0109% INTERPUBUC GROUP OF COS INC IPG 9,312.75 0.04% 3.03% 9.21% 12.38% 0.0054% INGERSOLL-RAND PLC IR 22,721.98 0.11% 1.83% 10.30% 12.23% 0.0131% IRON MOUNTAIN INC IRM 9,180.69 0.04% 6.00% 11.45% 17.80% 0.0077% INTUITIVE SURGICAL INC ISRG 30,794.09 0.15% 0.00% 9.73% 9.73% 0.0141% GARTNER INC IT 10,320.17 0.05% 0.00% 14.83% 14.83% 0.0072% ILLINOIS TOOL WORKS ITW 47,733.33 0.23% 1.88% 8.40% 10.36% 0.0233% INVESCOLTD IVZ 13,401.86 0.06% 3.55% 10.79% 14.53% 0.0092'/o HUNT (JB) TRANSPRT SVCS INC JBHT 9,861.09 0.05% 1.02% 13.43% 14.51% 0.0067% JOHNSON CONTROLS INTERNATION JCI 39,022.18 0.18% 2.42% 10.50% 13.04%" 0.0240% JACOBS ENGINEERING GROUP INC JEC 6,649.24 0.03°/o 0.56% 8.49% 9.07% 0.0028% JOHNSON & JOHNSON JNJ 334,713.83 1.58% 2.72% 6,45% 9'.26% 0.1462% JUNIPER NETWORKS INC JNPR 11,500.78 0.05% 1.40% 9.32% 10.78% 0.0058% JPMORGAN CHASE & CO JPM 309.533.68 1.46% 2.39% 7.80% 10.28% 0.1500% NORDSTROM INC JWN 8,053.91 0.04% 3.21% 7.63% 10.96% 0.0042% KELLOGG CO K 24,853.60 0.12% 3.03% 6.82% 9.95% 0.0117% KEYCORP KEY 19,735.97 0.09% 2.06% 7.42% 9.55% 0.0089% KRAFT HEINZ corrHE KHC 110,016.93 0.52% 2.60% 10.03% 12.76% 0.0662% Attachment RBH-5 Page 4of12 !41 [5l (6] !7J [BJ 9 Market Estlm•ted Dividend Long-Term Growth Weighted Comeany Ticker Capitalization Weight in Index Yield Est. DCF Result DCF Result KIMCO REALTY CORP KIM B,636.54 OJJ4% 5.36% 7.66% 13.22% 0.0054% KLA-TENCOR CORP KLAC 15,397.22 0.07% 2,16% 4.20% 6,40% 0.0046% KIMBERLY-CLARK CORP KMB 46,051.92 0.22% 2.9B% 6.99% 10.06% 0.0219% KINDER MORGAN INC KMI 46,055.29 0.22% 2.42% 10.00% 12.54% 0.0272% CARMAXINC KMX 10,863.55 0.05% 0.00% 12.32% 12,32% 0.0063% COCA-COLA COFTHE KO 184,360.93 0.61% 3.43% 5.16% B.67% 0.0754% MICHAEL KORS HOLDINGS LTD KORS 6,064.07 0.03% 0.00% 0.74% 0.74% 0.0002% KROGER CO KR 27,107.23 0.13% 1.72% 6.66% B.44% 0.0108% KOHLS CORP KSS 6,727.07 0.03% 5.64% 5.42% 11.21% 0.0036% KANSAS CITY SOUTHERN KSU 9,554.96 0.05% 1.53% 12.56% 14.19% 0.0064% LOEWS CORP L 15,696.22 NIA 0.54% NIA NIA NIA LBRANDSINC LB 15,040.77 0.07% 4.72% 6.73% 13.66% 0.0097% LEGGETT & PLATT INC LEG 6,986.77 0.03% 2.70% 19.00% 21.96% 0.0072% LENNAR CORP-A LEN 11,593.40 0.05% 0.32% 10.09% 10.42% 0.0057% LABORATORY CRP OF AMER HLDGS LH 14,337.35 0.07% 0.00% 10.03% 10.03% 0.0068% LKQ CORP LKQ 9,628.63 0.05% 0.00% 15.00% 15.00% 0.0068% L3 TECHNOLOGIES INC LLL 13,376.99 0.06% 1.76% 9.77% 11.61% 0.0073% ELI LILLY & CO LLY 90,541.26 0.43% 2.54% 12.63% 15.34% 0.0655% LOCKHEED MARTIN CORP LMT 77,990.43 0.37% 2.76% 7.35% 10.21% 0.0375% LINCOLN NATIONAL CORP LNC 14,868.55 0.07% 1.77% 9.79% 11.65% 0.0082% ALLIANT ENERGY CORP LNT 8,958.01 0.04% 3,19% 6.40% 9.70% 0.0041% LOWE'S COS INC LOW 72,770.42 0.34% 1.82% 14.79% 16.75% 0.0575% LAM RESEARCH CORP LRCX 23,366.03 0.11% 1.10% 11.74% 12.91% 0.0142% LEUCADIA NATIONAL CORP LUK 9,135.18 0.04% 0.98% 18.00% 19.07% 0.0082% SOUTHWEST AIRLINES CO LUV 34,538.82 0.16% 0.79% 10.10% 10.93% 0.0178% LEVEL3 COMMUNICATIONS INC LVLT 21,955.33 0.10% 0.00% 7.50% 7.50% 0.0078% LYONDELLBASELL INDU-CL A LYB 34,139.30 0.16% 4.10% 6.50% 10.73% 0.0173% MACY'SlNC M B,917.56 0.04% 5.36% 2.63% 8.08% 0.0034% MASTERCARD INC· A MA 125,363.63 0.59% 0.75% 15,87% 16.68% 0.0986% MID-AMERICA APARTMENT COMM MM 11,267.83 N/A 3.53% NIA NIA NIA MACERICH COITHE MAC B,886.90 0.04% 4.66% 8.51% 13.59% 0.0057% MARRIOTT INTERNATIONAL-CL A MAR 36,106.06 0.17% 1.31% 13.19% 14.58% 0.0248% MASCO CORP MAS 11,822.81 0.06% 1.10% 13.68% 14.85% 0.0083% MATTEL INC MAT 7,680.11 0.04% 6.78% 25.65% 33.30% 0.0121% MCDONALD'S CORP MCD 114,268.26 0.54% 2.72% 9.77% 12.62% 0.0660% MICROCHIP TECHNOLOGY INC MCHP 16,357.94 0.08% 1.89% 17.52% 19.57% 0.0151% MCKESSON CORP MCK 29,324.74 0.14% 0.81% 7.18% 8.03% 0.0111% MOODY'S CORP MCO 22,601.43 0.11% 1.32% 8.00% 9.37% 0.0100% MONDELEZ INTERNATIONAL INC-A MOLZ 68,646.46 0.32% 1.75% 11.04% 12.86% 0.0417% MEDTRONIC PLC MDT 113,740.65 0.54% 2.05% 6.64% 8.75% 0.0469% METLIFE INC MET 55,978.03 0.26% 3.12% 7.04% 10.27% 0.0271% MOHAWK INDUSTRIES JNC MHK 17.445.36 0.08% 0,0041"/a 7.01% 7.01o/o 0.0058% MEAD JOHNSON NUTRITION CO MJN 16,292.54 0.08% 1.92% 6.27% 8.25% 0.0063% MCCORMICK & CO-NON VTG SHRS MKC 12.451.26 0.06% 1.87% 7.86% 9.80% 0.0058% MARTIN MARIETTA MATERIALS MLM 13,790.82 0.07% 0.78% 22.91% 23.77% 0.0155% MARSH & MCLENNAN COS MMC 38,201.73 0.18% 1.92% 11.76% 13.82% 0.0249% 3MCO MMM 117,027.39 0.55% 2.41% 8.40% 10.91% 0.0602% MALLINCKRODT PLC MNK 4,912.27 0.02% 0.00% 6.33% 6.33% 0.0015% MONSTER BEVERAGE CORP MNST 25,713.19 0.12% 0.00% 19.30% 19.30% 0.0234% AlTRIA GROUP INC MO 138,946.01 0.66% 3.60% 7.64% 11.38% 0.0745% MONSANTO CO MON 51,169.36 0.24% 1.96% 10.10% 12.16% 0.0293% MOSAIC corrHE MOS 9,452.59 0.04% 2.27% 17.50% 19.97% 0.0089% MARATHON PETROLEUM CORP MPC 26,889.96 0.13% 2.93% 16.55% 19.72% 0.0250% MERCK & CO. INC. MRK 170,879.55 O.B1% 3.02% 5.36% 8.46% 0.0682% MARATHON OlL CORP MRO 12,642.00 0.06% 1.34% 8.60% 10.00% 0.0060% MORGAN STANLEY MS 80,337.42 0.38% 2.06% 14.87% 17.!18% 0.0647% MICROSOFT CORP MSFT 528,546.44 2.49% 2.25% 9.57% 11.93% 0.2973% MOTOROLA SOLUTIONS INC MSI 14,089.86 0.07% 2.11% 4.65% 6.81% 0.0045% M & T BANK CORP MTB 23,896.12 0.11% 1.95% 6.26% 8.27% 0.0093% METTLER-TOLEDO INTERNATIONAL MTD 13,300.45 0.06% 0.00% 11.76% 11.78% 0.0074% MICRON TECHNOLOGY INC MU 30,611.52 0,14% 0.00% 10.00% 10.00% 0.0144% MURPHY OIL CORP MUR 4,517.23 NIA 4.00% NIA N/A NIA MYLAN NV MYL 20,000.81 0.09% 0.00% 6.47% 6.47% 0.0061% NAVIENT CORP NAVI 4,331,10 0.02% 4.26% B.00% 12.43% 0.0025% NOBLE ENERGY INC NBL 14,079.13 0.07% 1.24% 10.62% 11.92% 0.0079% NASDAQ INC NDAQ 11,442.31 0,05% 2.10% 8.35% 10.54% 0.0057% NEXTERA ENERGY INC NEE 62,527.81 0.29% 2.93% 6.75% 9.78% 0.0288% NEWMONT MINING CORP NEM 18,028.62 0.09% 0.66% -12.95% -12.33% -0.0105% NETFUXINC NFLX 65,598,88 0.31% 0.00% 36.35% 36.35% 0.1124% NEWFIELD EXPLORATION CO NFX 6,888.22 0.03% 0.00% 20.39% 20.39% 0.0066% NiSOURCE INC NI 7,849.82 0,04% 2.90% 6.38% 9.37% 0.0035% NIKE INC ·CL B NKE 91,468.97 0.43% 1.26% 12.13% 13.47% 0.05(!1% NIELSEN HOLDINGS PLC NLSN 14,695.64 0.07% 3.21% 10.67% 14.05% 0,0097% NORTHROP GRUMMAN CORP NOC 42,937,92 0.20% 1.56% 5.96% 7.56% 0.0153% NATIONAL OILWELL VARCO INC NOV 13,290.05 NIA 0.57% NIA NIA NIA NRG ENERGY INC NRG 5,341.76 NIA 0.71% N/A NIA NIA NORFOLK SOUTHERN CORP NSC 34,046.56 0.16% 2.08% 11.67% 13.87% 0.0223% NETAPP INC NTAP 10,797.41 0.05% 1.91% 10.16% 12.17% 0,0062% NORTHERN TRUST CORP NTRS 20,653,64 0.10% 1.76% 13.15% 15.02% 0.0146% NUCOR CORP NUE 19,557.53 0.09% 2.46% 6.63% 9.16% 0.0085% NVIDIA CORP NVDA 62,010.21 0.29% 0.51% 9.40% 9.94% 0.0291% NEWELL BRANDS INC NWL 23,062.71 0.11% 1.69% 11.60% 13.59% 0.0146% NEWS CORP-CLASSA NWSA 7,452.46 0.04% 1.69% 10.73% 12.51% 0,0044% REALTY INCOME CORP 0 15,933,01 0.08% 4.28% 4.91% 9.29% 0.0070% ONEOK INC OKE 11,095.73 0.05% 5.20% 25.10% 30.95% 0.0162% OMNICOM GROUP OMC 19,127.51 0.09% 2.76% 7.48% 10.35% 0.0093% ORACLE CORP ORCL 184,996.19 0.87% 1.41% 9.22% 10.69% 0.0933% O'REILLY AUTOMOTIVE INC ORLY 22,741.98 0.11% 0.00% 15.50% 15,50% 0,0166% OCCIDENTAL PETROLEUM CORP OXY 47,052.22 0.22% 4.96% -1.99% 2.92% 0.0065% PAYCHEX INC PAYX 21,296.24 0.10% 3.09% 6.60% 11.82% 0.0119% Attachment RBH-5 Page 5of12 [4) [5] [6] [7] {6) [9] Market Estimated Dividend Long-Term Growth Weighted Company Ticker Capllallzation Weight in Index Yield Est DCFResult DCF Result PEOPLE'S UNITED FINANCIAL PBCT 6,001.09 0.03% 3.94% 2.00% 5.98% 0.0017% PACCAR INC PCAR 23,439.24 0.11% 2.58% 6.73% 9.40% 0.0104% PG&ECORP PCG 34,236.42 0.16% 3.12% 6,50% 9.72% 0.0157% PRICEUNE GROUP INCfTHE PCLN 90,776.21 0.43% 0.00% 16.83% 16,83% 0.0720% PATTERSON COS INC PDCO 4,321.49 0.02% 2.22% 4.76% 7.03% 0.0014% PUBLIC SERVICE ENTERPRISE GP PEG 22,298.87 0.11% 3,90% 2.05% 5.99% 0.0063% PEPSICO INC PEP 161,820.62 0,76% 2.79% 6.40% 9.27% 0.0707% PFIZER INC PFE 201,997.87 0.95% 3.77% 5.08% 6.95% 0.0652% PRINCIPAL FINANCIAL GROUP PFG 16,777.96 0.09% 2,83% 9.53% 12.50% 0.0111% PROCTER & GAMBLE CO/THE PG 223,356.46 1.05% 3.11% 7.56% 10.79% 0.1136% PROGRESSIVE CORP PGR 23,069.50 0.11% 2.56% 10.26% 12.95% 0.0141% PARKER HANNIFIN CORP PH 21,433.63 0.10% 1.61% 9,81% 11.50% 0.0116% PULTEGROUP INC PHM 7,152.47 0.03% 1.63% 17.05% 18.82% 0.0063% PERKINELMER INC PKI 6,522.45 0.03% 0.47% 9.57% 10.06% 0.0031% PROLOGIS INC PLO 28,813.35 0.14% 3.20% 5,09% 8.37% 0.0114% PHILIP MORRIS INTERNATIONAL PM 172,150.39 0.81% 3.84% 9.47% 13.49% 0.1095% PNC FINANCIAL SERVICES GROUP PNC 58,217.21 0.27% 1.95% 6.65% 6.66% 0.0238% PENTAIR PLC PNR 11,756.63 0.06% 2.19% 5.96% 8.21% 0.0046% PINNACLE WEST CAPITAL PNW 9,492.27 0.04% 3.12% 5.05% 6.25% 0.0037% PPG INDUSTRIES INC PPG 28,191.44 0.13% 1.50% 7.71% 9.26% 0.0123% PPL CORP PPL 25,944.95 0.12% 4.15% 1.70% 5.88% 0.0072% PERRIGO CO PLC PRGO 10,601.11 0.05% 0.77% 5.20% 5.99% 0.0030% PRUDENTIAL FINANCIAL!NC PRU 46,062.51 0.22% 2.87% 9,70% 12.71% 0.0276% PUBLIC STORAGE PSA 36,328.93 0.17% 3.91% 6.06% 10.10% 0.0173% PHILLIPS66 PSX 41,130.17 0.19% 3.34% -12.61% -9.48% -0.0184% PVHCORP PVH 7,900.87 0.04% 0.16% 8.31% 8.48% 0.0032% QUANTA SERVICES INC PWR 5,508.76 0.03% 0.00% 16.80% 16.80% 0.0044% PRAXAIR INC PX 35,663.54 0.17% 2,53% 9.97% 12.62% 0.0212% PIONEER NATURAL RESOURCES CO PXD 29,438.84 0.14% 0.05% 20.00% 20.05% 0.0278% PAYPAL HOLDINGS INC PYPL 57,324.05 0.27% 0.00% 17.70% 17.70% 0.0478% QUALCOMM INC QCOM 79,397.44 0,37% 4.07% 8.72% 12.97% 0.0485% QORVOINC QRVO 8,602.57 0.04% 0.00% 14.07% 14.07% 0.0057% RYDER SYSTEM INC R 3,637.27 0.02% 2.69% 15.00% 17.90% 0.0031% REYNOLDS AMERICAN INC RA! 91,972.76 0.43% 3.17% 8.09% 11.39% 0.0494% ROYAL CARIBBEAN CRUISES LTD RCL 22,910.71 0.11% 1.86% 18.57% 20.60% 0.0223% REGENCY CENTERS CORP REG 10,740.82 0.05% 3,26% 8.57% 11.97% 0.0061% REGENERON PHARMACEUTICALS REGN 41,292.84 0.19% 0.00% 19.27% 19.27% 0.0375% REGIONS FINANCIAL CORP RF 16,572.31 0.08% 2.19% 8.95% 11.24% 0.0088% ROBERT HALF INTL INC RHI 5,858.58 0.03% 2.09% 8.00% 10.17% 0,0028% RED HAT INC RHT 15,658.59 0.07% 0.00% 14.90% 14.90% O.D110o/o TRANSOCEAN LTD RIG 4,311.86 0.02% 0.00% -25.60% -25.60% -0.0052% RAYMOND JAMES FINANCIAL INC RJF 10,707.48 0,05% 1.16% 13.50% 14.74% 0.0074% RALPH lAUREN CORP RL 6,636.20 0.03% 2.52% 1.46% 3.99% 0.0012% ROCKWELL AUTOMATION INC ROK 20,235.18 0.10% 2.05% 10.99% 13,15% 0,0125% ROPER TECHNOLOGIES INC ROP 22,279.89 0.11% 0.62% 12.53% 13.19% 0.0139% ROSS STORES INC ROST 25,479.97 0.12% 0.98% 12.62% 13.ll8% 0.0164% RANGE RESOURCES CORP RRC 6,558.67 0.03% 0.33% -10.13% -9.81% -0.0030% REPUBLIC SERVICES INC RSG 21,295.77 0.10% 2.11% 9.23% 11.44% 0.0115% RAYTHEON COMPANY RTN 45,177.60 0.21% 2.04% 7.82% 9,94% 0,0212% STARBUCKS CORP SBUX 87,531.44 0.41% 1.70% 17.13% 18.97% 0.0783% SCANA CORP SCG 9,476.62 0.04% 3.69% 5.30% 9.09% 0.0041% SCHWAB(CHARLES)CORP SCHW 51,934.37 0.24% 0.80% 18.17% 19.04% 0.0466% SEALED AIR CORP SEE 8,598.22 0.04% 1.49% 3.47% 4.98% 0.0020% SHERWIN-WILLIAMS CO/THE SHW 31,168.18 0.15% 1.02% 13.65% 14.74% 0,0217% SIGNET JEWELERS LTD SIG 4,496.90 0.02% 1.88% 5.63% 7.57% 0.0016% JM SMUCKER CO/THE SJM 14,755.42 0.07% 2.31% 5.90% 8.28% 0.0058% SCHLUMBERGER LTD SLB 100,862.12 0.48% 2.79% 36.05% 39.35% 0.1871% SL GREEN REALTY CORP SLG 10,842.32 0.05% 2.99% 0.58% 3.58% 0.0018% SNAP-ON INC SNA 9,708.21 0.05% 2.04% 9.80% 11.94% 0.0055% SCRIPPS NETWORKS INTER-CL A SNI 9,691.83 0,05% 1.58% 7.56% 9.19% 0.0042% SYNOPSYS INC SNPS 11,091.68 0.05% 0.00% 9.36% 9.36% 0.0049% SOUTHERN CO/THE so 49,562.22 0.23% 4.63% 4.40% 9,13% 0.0213% SIMON PROPERTY GROUP INC SPG 51,617.54 0.24% 4.27% 7.87% 12.31% 0.0300% S&P GLOBAL INC SPGI 34,594.18 0.16% 1.22% 11.00% 12.28% 0.0200% STAPLES INC SPLS 6,380.66 0,03% 4.97% 5.94% 11.06% 0.0033% STERICYCLE INC SRCL 7,276.22 0.03% 0.00% 9.95% 9.95% 0.0034% SEMPRA ENERGY SRE 28,323.39 0.13% 2.90% 7.3Zo/o 10.32% 0,0138% SUNTRUST BANKS INC STI 27,917.17 0.13% 1.98% 8.50% 10.56% 0.0139% STATE STREET CORP STT 32,021.07 0.15% 1.89% 9.70% 11.68% 0.0176% SEAGATE TECHNOLOGY STX 12,512.61 0,06% 5.47% 12.45% 18,26% 0.0108% CONSTELlATION BRANDS INC-A STZ 33,589.81 0.16% 1.20% 17.83% 19.13% 0.0303% STANLEY BlACK & DECKER INC SWK 20,827.30 0.10% 1.74% 11.00% 12.63% 0.0126% SKYWORKS SOLUTIONS INC SWKS 18,401.19 0.09% 1.13% 14.22% 15.43% 0.0134% SYNCHRONY FINANCIAL SYF 22,540.37 0.11% 2.08% 10.35% 12.53% 0.0133% STRYKER CORP SYK 50,970.34 0.24% 1,23% 8.04% 9,32% 0,0224% SYMANTEC CORP SYMC 19,573.73 0.09% 1.01% 11.63% 12.70% 0.0117% SYSCO CORP SYY 28,561.01 0.13% 2.46% !l.11% 11.68% 0.0157% AT&T INC T 243,605,61 1.15% 4.97% 4.83% !l.92% 0.1139% MOLSON COORS BREWING CO -B TAP 20,636.BS 0.10% 1.73% 16.88% 18.75% 0.0182% TERADATA CORP TDC 3,819.30 0.02% 0.00% 4.76% 4.76% 0.0009% TRANSDIGM GROUP INC TDG 13,038.33 0.06% 0.00% 9.39% 9.39% 0.0058% TE CONNECTIVITY LTD TEL 27,468.46 0.13% 1.96% 6.75% 8.76% 0.0114% TEGNAINC TGNA 5,472.56 0.03% 2.25% 5.50% 7.81% 0.0020% TARGET CORP TGT 30,866.92 0.15% 4.39% -1.11% 3.26% 0.0047% TIFFANY&CO TIF 11,435.63 0,05% 2.05% 8.73% 10,87% 0.0059% TJX COMPANIES INC TJX 50,687.65 0.24% 1.56% 9.62'%1 11.26% 0.0269% TORCHMARK CORP TMK 9,043.91 0.04% 0.78% 7.57% 8.38% 0.0036% THERMO FISHER SCIENTIFIC INC TMO 64,679.61 0.30% 0.36% 11.98% 12.37% 0.0377% TRIPADVISOR INC TRIP 6,355.91 0.03% 0.00% 15.53% 15.53% 0.0047% T ROWE PRICE GROUP INC TROW 17,103.51 0,08% 3,19% 12.15% 15,53% 0.0125% Attachment RBH-5 Page 6of12 [4] [5l [6] Markel Estimated Dividend Company Ticker Capitalization Weight in Index Yield DCF Result TRAVELERS COS INCfTHE TRV 33,993.73 0.16% 2.32% 6.68% 9.28% 0.0149% TRACTOR SUPPLY COMPANY TSCO 6,042.77 0.04% 1.66% 13.60% 15.58% 0.0059% TYSON FOODS INC-CL A TSN 24,988.06 0.12% 1.41% 6.30% 7.75% 0.0091% TESORO CORP TSO 9,356.35 0.04% 2.85% 10.00% 12.99% 0.0057% TOTAL SYSTEM SERVICES INC TSS 10,508.05 0.05% 0.70% 11.00% 11.74% 0.0058% TIME WARNER INC TWX 76,868.16 0.36% 1.69% 9,30% 11.06% 0.0401% TEXAS INSTRUMENTS INC TXN 79,151.47 0.37% 2.42% 10.34% 12.89% 0.0481% TEXTRON ING TXT 12,490.38 0.06% 0.18% 9.66% 9.85% 0.0058% UNDER ARMOUR INC·CLASS A UAA 8,947.92 0.04% 0.00% 17.98% 17.98% 0.0076% UNITED CONTINENTAL HOLDINGS UAL 22,062.37 0.10% 0.00% 1.90% 1.90% 0.0020% UDR INC UDR 9,984.41 0.05% 3.32% 6.41% 9.83% 0.0046% UNIVERSAL HEALTH SERVICES·B UHS 11,670.02 0,06% 0.26% 9.49% 9,76% 0.0054% ULTA BEAUTY ING ULTA 17,468.06 0.06% 0.00% 22.30% 22.30% 0.0184% UNITEDHEALTH GROUP INC UNH 168,603.59 0.79% 1.50% 12.98% 14.58% 0.1159% UNUM GROUP UNM 10,573.15 0.05% 1.81% 6.53% 8.40% 0.0042% UNION PACIFIC CORP UNP 90,400.90 0.43% 2.20% 9.62% 12.12% 0.0517% UNITED PARCEL SERVICE·CL B UPS 93.493.39 0.44% 3,07% 8.50% 11.70% 0.0516% UNITED RENTALS INC URI 9,267.74 0.04% 0.00% 15.17% 15.17% 0.0066% US BANCORP USB 86,828.50 0.41% 2.29% B.78% 11.18% 0.0458% UNITED TECHNOLOGIES CORP UTX 95,338.06 0.45% 2,30% 7.92% 10.31% 0.0464% VISA INC.CLASS A SHARES v 210,322.97 0.99% 0.72% 17.43% 18.22% 0.1806% VARIAN MEDICAL SYSTEMS INC VAR B,479.69 N/A 0.00% NIA NIA NIA VF CORP VFC 22,645.41 0.11% 3.13o/o 6.68% 9.92% 0.0106% VIACOM INC·CLASS B VIAB 16,992.74 0.08% 1.93% 1.59% 3.54% 0.0028% VALERO ENERGY CORP VLO 28,992.50 0.14% 4.34% 13.15% 17.78% 0.0243% VULCAN MATERIALS CO VMC 16,033.14 0.08% 0.72% 28.41% 29.23% 0.0221% VORNADO REALTY TRUST VNO 1 B,217.45 0.09% 2.81% 4.32% 7.19% 0.0062% VERISK ANALYTICS INC VRSK 13,777.59 0,06% 0.00% 10.55% 10.55% 0.0069% VERISIGN INC VRSN 9,023.21 0.04% 0.00% 9.30% 9.30% 0.0040% VERTEX PHARMACEUTICALS INC VRTX 29,461.80 0.14% 0.00% 74.91% 74.91% 0.1041% VENTAS INC VTR 22,714.14 0.11% 4.89% 4.17% 9.16% 0.0098% VERIZON COMMUNICATIONS ING vz 187,283.85 0.88% 5.07% 2.72% 7.86% 0.0694% WATERS CORP WAT 13,604.03 0.06% 0,0041'/a 7.51% 7.51% 0.0048% WALGREEN$ BOOTS ALLIANCE INC WBA 93,545.49 0.44% 1.74% 10.65% 12.49% 0.0551% WESTERN DIGITAL CORP WDC 25,658.43 0.12% 2.25% 9.87% 12.23% 0.0148% WEC ENERGY GROUP INC WEC 19,098.92 0.09% 3.45% 6.23% 9,78% 0.0088% WELLS FARGO & CO WFC 269,408.48 1.27% 2.91% 11.03% 14.10% 0.1791% WHOLE FOODS MARKET INC WFM 11,586.19 0.05% 1.53% 3.17% 4.73% 0.0026% WHIRLPOOL CORP WHR 13,734.81 0.06% 2.25% 15,88% 18.31% 0.0119% WlLLIS TOWERS WATSON PLC WLTW 17,962.56 0.08% 1.51% 11.90% 13.50% 0.0114% WASTE MANAGEMENT INC WM 32,164.45 0.15% 2,34% 10.77% 13.24% 0.0201% WILLIAMS COS ING WMB 25,307.25 0.12% 3.92% 10.00% 14.11% 0.0168% WAL·MART STORES INC WMT 227,912.40 1.07% 2.71% 4.84% 7.61% 0.0818% WESTROCKCO WRK 13,411.61 0.06% 2.99% 7.31% 10.40% 0.0066% WESTERN UNION GO WU 9,456.00 0.04% 3.52% 5.70% 9.33% 0.0042% WEYERHAEUSER CO WY 25,446.35 0.12% 3.81% 7.50% 11.45% 0.0137% WYNDHAM WORLDWIDE CORP WYN 9,945,96 0,05% 2.32% 12.90% 15.36% 0.0072% WYNN RESORTS LTD WYNN 12,536.92 0.06% 1.70% 17.20% 19.04% 0.0113% CIMAREX ENERGY CO XEC 11,097.87 0.05% 0.30% 77.89% 78.31% 0.0410% XCEL ENERGY INC XEL 22,874.72 0.11% 3.20% 6.00% 9.29% 0.0100% XL GROUP LTD XL 11,036.93 0.05% 1.83% 9.00% 10.91% 0.0057% XILINX INC XLNX 15,710.28 0,07% 2.18% 9.10% 11.38% 0.0064% EXXON MOBILCORP XOM 346,174.09 1.63% 3.76% 13.80% 17.82% 0.2909% DENTSPLY SIRONA INC XRAY 14,557.31 0.07% 0.54% 9.47% 10.04% 0.0069% XEROX CORP XRX 7,309.24 0.03% 3.73% 1.80% 5.56% 0.0019% XYLEM INC XYL 9,237.74 0.04% 1.40% 15.00% 16.51% 0.0072% YAHOOllNC YHOO 46,191.51 0,22% 0.00% 10.37% 10.37% 0.0226% YUMI BRANDS INC YUM 23,161.74 0.11% 2.29% 12.56% 14.99% 0.0164% ZIMMER BIOMET HOLDINGS INC ZBH 24,076.39 0.11% 0.83% 8.74% 9.61% 0.0109% ZIONS BANCORPORATION ZION 8,103.01 0.04% 1.01% 9.00% 10.06% 0.0038% ZOETIS INC ZTS 27,585.24 0.13% 0.74% 12.25% 13.04% 0.0170% Tolal Market Capilalization: 21,209,328.43 13.37% Notes: [1] Equals sum of Col. [9] [2] Source: Bloomberg Professional [3] Equals [1] - (21 [4] Source: Bloomberg Professional [5] Equals weight in S&P 500 based on market capitalization [6] Sour Ex-Ante Markel Risk Premium Market DCF Melhod Based - Value Line [1J (2] [3J S&P 500 Current 30-Year Esl Required Treasury (30-day Implied Market Markel Relum average) Risk Premium 14.09% 2.97% 11.12% [4J (5] [6] [7] !8l {9l Market Estimated Long-Term Weighted Company Ticker Capitalization Weight in Index Dividend Yield Growth Est DCF Result DCFResull AGILENT TECHNOLOGIES INC A 17,107.86 0.09% 1.00% 6.50% 7.53% 0.0067% AMERICAN Al RUNES GROUP ING AAL 22,939.84 NIA 0.89% NIA NIA NIA ADVANCE AUTO PARTS INC AAP 10,808.65 0.06% 0.16% 9,50% 9.67% 0.0054% APPLE ING AAPL 748,582,40 3.88% 1.71% 10.00% 11.80% 0.4574% ABBVIEINC ABBV 101,570.50 0.53% 4.01% 11.50% 15.74% 0.0828% AMERISOURCEBERGEN GORP ABC 17,873.05 0.09% 1.77% 10.00% 11.86% 0,0110% ABBOTT LABORATORIES ABT 64,752,20 0.34% 2.41% 7.50% 10.00% 0.0335% ACCENTURE PLC-CL A AGN 76,552.49 0.40% 2.10% 8.00% 10.18% 0.0404% ADOBE SYSTEMS INC ADBE 65,069.99 0,34% 0.00% 29.50% 29.50% 0,0994% ANALOG DEVICES INC ADI 24,322.22 0.13% 2.29% 16.00% 18.47% 0.0233% ARCHER-DANIELS-MIDLAND CO ADM 25,727.70 0.13% 2.85% 5.00% 7.92% 0.0106% AUTOMATIC DATA PROCESSING ADP 46,254.65 0.24% 2.31% 10.00% 12.43% 0.0298% ALLIANCE DATA SYSTEMS CORP ADS 15,063.84 0.08% 0.80% 10.00% 10.84% 0.0085% AUTODESK INC ADSK 19,476.72 NIA 0,00% NIA NIA N/A AMEREN CORPORATION AEE 13,233,26 0.07% 3.28% 6.00% 9.38% 0.0064% AMERICAN ELECTRIC POWER AEP 33,160.99 0.17% 3.59% 4.00% 7.66% 0.0132% AES CORP AES 7,527.79 0,04% 4.20% 7.00% 11.35% 0.0044% AETNA INC AET 46,399.78 0.24% 1.52% 8.00% 9.58% 0.0230% AFLAC INC AFL 30,098.93 0.16% 2.37% 4.00% 6,42% 0,0100% ALLERGAN PLC AGN 79,686.11 0.41% 0.12% 10.00% 10.13% 0.0416% AMERICAN INTERNATIONAL GROUP AIG 62,229.18 0.32% 2.15% 10.00% 12.26% 0.0395% APARTMENT INVT & MGMT CO -A AIV NIA 3.27% NIA NIA NIA ASSURANT ING AIZ 5,517.43 0.03% 2.23% 7.00% 9.31% 0.0027% ARTHUR J GALLAGHER & CO AJG 10,029.38 0.05% 2.77% 13.50% 16.46% 0,0085% AKAMAI TECHNOLOGIES INC AKAM 10,429.95 0,05% 0.00% 12.50% 12.50% 0.0068% ALBEMARLE CORP ALB 11,873.53 0.06% 1.21% 11.00% 12.28% 0.0076% ALASKA AIR GROUP INC ALK 10,898.50 0.06% 1,36% 13,00% 14.45% 0,0082% ALLSTATE CORP ALL 29,334.90 0.15% 1.85% 5.50% 7.40% 0.0112% ALLEGION PLC ALLE 7,404.70 0.04% 0.82% 10.00% 10.86% 0.0042% ALEXION PHARMACEUTICALS INC ALXN 26,702.62 0.14% 0.00% 20.00% 20,00% 0,0277% APPLIED MATERIALS ING AMAT 43,074.46 0.22% 1.00% 23.50% 24.62% 0.0549% ADVANCED MICRO DEVICES AMD 12,257.85 NIA 0.00% N/A N/A NIA AMETEK INC AME 12,563,09 0,07% 0.66% 5.50% 6.18% 0.0040% AFFILIATED MANAGERS GROUP AMG 9,331.69 0.05% 0.49% 8.50% 9.01% 0.0044% AMGEN INC AMGN 1111,617.90 0.62% 2.90% 7.50% 10.51% 0.0651% AMERIPRISE FINANCIAL INC AMP 20,052,25 0.10% 2.32% 10.50% 12.94% 0.0134% AMERICAN TOWER CORP AMT 52,904.62 0.27% 2.11% 11.00% 13.23% 0,0362% AMAZON.COM INC AMZN 430,282.70 2,23% 0.00% 91.00% 91.00% 2.0282% AUTONATION INC AN 4,393.46 0.02% 0.00% 7.00% 7.00% 0.0016% ANTHEM INC ANTM 44,327.96 0.23% 1.55% 9.00% 10.62% 0.0244% AON PLC AON 31,586,72 0.16% 1.19% 12.00% 13.26% 0.0217% APACHE CORP APA 16,599.61 0.10% 2.04% 7.00% 9.11% 0.0088% ANADARKO PETROLEUM CORP APC 32,520.60 NIA 0.34% N/A N/A N/A AIR PRODUCTS & CHEMICALS INC APO 29,788.07 0.15% 2.78% 10.50% 13.43% 0.0207% AMPHENOL CORP-CL A APH 21,862.14 0.11% 0,90% 8,00% 8,94% 0,0101% ALEXANDRIA REAL ESTATE EQUIT ARE NIA N/A 0.00% NIA NIA N/A ARCONICINC ARNC 11,449.76 N/A 0.92% NIA NIA NIA ACTIVISION BUZZARD INC ATVI 37,237.02 0.19% 0.60% 7.00% 7.62% 0.0147% AVALONBAY COMMUNITIES INC AVB NIA 3.13% NIA NIA NIA BROADCOM LTD AVGO 87,347.71 0.45% 1.87% 19.50% 21.55% 0.0975% AVERY DENNISON CORP AVY 7,331.83 0.04% 2.19% 9.00% 11.29% 0.0043% AMERICAN WATER WORKS CO ING AWK 14,099.86 0.07% 2.07% 8.50% 10.66% 0.0078% AMERICAN EXPRESS CO AXP 72,338.09 0.37% 1,68% 4,50% 6.22% 0.0233% ACUITY BRANDS INC AYI 7,821.48 0.04% 0.29% 19.00% 19.32% 0.0078% AUTOZONE INC l\Z.O 20,111.89 0.10% 0.00% 12.00% 12.00% 0.0125% BOEING CO/THE BA 110,655.30 0.57% 3,29% 7,00% 10,41% 0.0596% BANK OF AMERICA CORP BAC 233,557.10 1.21% 1.39% 17.00% 18.51% 0.2239% BAXTER INTERNATIONAL INC BAX 28,767.56 0.15% 0,98% -2.50% -1.53% -0,0023% BED BATH & BEYOND INC BBBY 6,002.08 0,03% 1.50% -1.00% 0.49% 0.0002% BB&T CORP BBT 35,349.77 0.18% 2.79% 7.50% 10.39% 0.0190% BEST BUY CO INC BBY 15,720.29 0,08% 2,69% 6.00% 8,77% 0.0071% GR BARDING BCR 18,732.22 0.10% 0.42% 10.50% 10.94% 0.0106% BECTON DICKINSON AND CO BOX 39,596.09 0.21% 1.65% 9.00% 10.72% 0,0220% FRANKLIN RESOURCES INC BEN 23,543.77 0,12% 1.97% 6.00% 8.03% 0.0098% BROWN-FORMAN CORP-CLASS B BFIB 17,705.52 0.09% 1.61% 8.50% 10.18% 0.0093% BAKER HUGHES ING SHI 25,226.00 0.13% 1.14% 29.00% 30.31% 0.0396% BIOGEN ING BllB 59,280.22 0.31% 0.00% 9.50% 9.50% 0.0292% BANK OF NEW YORK MELLON CORP BK 48,865.32 0.25% 1.63% 10,50% 12.22% 0,0309% BLACKROCK INC BLK 61,639.76 0,32% 2.62% 7.50% 10.22% 0.0326% BALL CORP BLL 12,812.36 0.07% 0.71% 14.50% 15.26% 0.0101% BRISTOL-MYERS SQUIBB CO BMY 88,924.16 0.46% 2.92% 14.50% 17.63% 0.0012% BERKSHIRE HATHAWAY INC.Cl B BRK/B NIA 0.00% NIA NIA NIA BOSTON SCIENTIFIC CORP BSX 34,063.33 0.18% 0.00% 18.00% 16.00% 0,0318% BORGWARNER INC BWA 8,540.74 0.04% 1.40% 6.00% 7.44% 0.0033% BOSTON PROPERTIES INC BXP NIA 2.23% NIA NIA NIA CITIGROUP INC c 166,452.70 0,86% 1.10% 11.50% 12.66% 0,1092% GAING CA 13.433.65 0.07% 3.17% 6.50% 9.77% 0.0066% CONAGRA BRANDS INC GAG 17,326.44 0.09% 1,97% 1.00% 2.98% 0.0027% CARDINAL HEALTH JNC CAH 23,165.96 0.12% 2.66% 13.00% 15.83% 0.0190% Attachment RBH-5 Page 8 of12 [4) [Sl [6] Market Eotimated long-Term Company Ticker Capitalization Weight in Index Dividend Yield Growlll Est. DCFResult CATERPILlAR INC CAT 55,363.01 0.29% 3.25% 4.50% 7.82% 0.0224% CHUBB LTD CB 63,641.82 0.33% 2.,02'% 7,50% 9,60% 0.0316% CBRE GROUP INC -A CBG 11,524.82 0.06% 0.00% 8.50% 8.50% 0.0051% CBOE HOLDINGS INC CBOE 6,746.66 0.03% 1.21% 12.50% 13.79% 0.0048% CBS CORP-CLASS B NON VOTING CBS 28,292.04 0,15% 1.05% 13,00% 14.12% 0.0207% CROWN CASTLE INTL CORP CCI 32,420.22 0.17% 4.10% 8.50% 12.77% 0.0215% CARNIVAL CORP CCL 42,986.46 0.22% 2.70% 15.50% 18.41% 0.0410% CELGENE CORP CELG 95,583.56 0,50% 0.00% 26,00% 26,00% 0.1287% CERNERCORP CERN 19,564.19 0.10% 0.00% 11.50% 11.50% 0.0117% CF INDUSTRIES HOLDINGS INC CF 6,196.17 0.03% 4,63% 10.00% 14.86% 0.0048% CITIZENS FINANCIAL GROUP CFG 18,275,08 N/A 1.59% N/A NIA N/A CHURCH & DWIGHT CO INC CHO 12,987.71 0.07% 1.51% 7.00% 8.56% 0.0058% CHESAPEAKE ENERGY CORP CHK 4,313.07 NIA 0,00% NIA NIA N/A C.H. ROBINSON WORLDWIDE INC CHRW 10,848.10 0.06% 2.35% 6.50% B.93% 0.0050% CHARTER COMMUNICATIONS INC-A CHTR 90,239.15 0.47% 0.00%' 26.00% 26.00% 0.1215% CIGNA CORP Cl 39,940.74 0,21% 0.03% 11,50% 11,53% 0.0239% CINCINNATI FINANCIAL CORP CINF 11,603.11 0.06% 2.84% 6.00% 8.93% 0.0054% COLGATE-PALMOLIVE CO Cl 66,353.18 0.34% 2.21% 12.00% 14.34% 0.0493% CLOROX COMPANY CLX 17,387.21 0,09% 2.40% 7,50% 9,99% 0,0090% COMERICA INC CMA 11,908.83 0.06% 1.33% 10.50% 11.90% 0.0073% COMCAST CORP-CLASS A CM CSA 180,561.00 0.94% 1.45% 11.00% 12.53% 0.1172% CME GROUP INC CME 40,287.77 0.21% 2.22% 7.50% 9.80% 0.0205% CHIPOTLE MEXICAN GRILL INC CMG 13,864.70 0.07% 0.00% 6.50% 8.50% 0.0061% CUMMINS INC CMI 24,595.36 0.13% 2.81% 5.50% 8.39% 0.0107% CMS ENERGY CORP CMS 12,514.01 0.06% 3.01% 6.50% 9.61% 0.0062% CENTENE CORP CNC 12,196.11 0.06% 0.00% 17.00% 17.00% 0.0107% CENTERPOINT ENERGY INC CNP 12,016.03 0.06% 3.87% 6.00% 9.99% 0.0062% CAPITAL ONE FINANCIAL CORP COF 40,957.50 0.21% 1.91% 2.50% 4.43% 0.0094% CABOT OIL & GAS CORP COG 11,382.20 0.06% 0,33% 32,50% 32.88% 0.0194% COACHING COH 11,162,27 0.06% 3.39% 9.00% 12.54% 0.0073% ROCKWELL COLLINS INC COL 13,026.37 0.07% 1.33% 6.50% 7.87% 0.0053% COOPER COS INCfTHE coo 9,804.45 0.05% 0.03% 16.50% 16.53% 0.0084% CONOCOPHILLIPS COP 59,327.05 0.31% 2.21% 9.50% 11.81% 0.0363% COSTCO WHOLESALE CORP COST 74,685.80 0.39% 1.18% 9.00% 10.23% 0.0396% COTY INC-CL A COTY 13,371.30 0.07% 2.79% B.00% 10.90% 0.0076% CAMPBELL SOUP CO CPB 18,572.50 0.10% 2.44% 5.00% 7.50% 0.0072% SALESFORCE.COM INC CRM 59,462.02 NIA 0.00% NIA NIA NIA CISCO SYSTEMS INC csco 164,379.80 0.65% 3.53% 7.00% 10.65% OJJ907% CSRAINC CSRA 4,713.61 NIA 1.38% NIA N/A NIA CSX CORP CSX 45,728.36 0,24% 1.45% 6.50% 8.00% 0.0189% CINTAS CORP CTAS 12,949.01 0.07% 1.08% 8.00% 9.12% 0.0061% CENTURYLINK INC CTL 13,931.43 0.07% 8.47% 10.50% 19.41% 0.0140% COGNIZANT TECH SOLUTIONS-A CTSH 35,130.24 0.18% 1.04% 12.00% 13.10% 0.0238% CITRIX SYSTEMS INC CTXS 13,077.54 0.07% 0.00% 8.50% 8.50% 0.0058% CVS HEAL TH CORP CVS 84,672.38 0.44% 2.52% 9.50% 12.14% 0.0532% CHEVRON CORP cvx 198,381.20 1.03% 4.12% 3.00% 7.18% 0.0738% CONCHO RESOURCES INC cxo 18,116.27 0.09% 0.00% 14.00% 14.00% 0.0131% DOMINION RESOURCES INCNA D 48,566.61 0.25% 3.90% 5.50% 9.51% 0.0239% DELTA AIR LINES INC DAL 33,782.89 0.17% 1.76% 11.50% 13.36% 0.0234% DU PONT (E.I.) DE NEMOURS DD 67,564.50 0,35% 2,07% 8.00% 10.15% 0.0355% DEERE&CO DE 34,629.19 0.18% 2.21% 5.00% 7.27% 0.0130% DISCOVER FINANCIAL SERVICES DFS 26,438.38 0.14% 1.80% 5.00% 6.65% 0.0094% DOLLAR GENERAL CORP DG 19,523.58 0,10% 1.59% 11.00% 12.68% 0.0128% QUEST DIAGNOSTICS INC DGX 14,252.11 0.07% 1.73% 9.00% 10.81% 0.0080% DR HORTON INC DH! 12,357.45 0,06% 1,24% 11.00% 12,31% 0,0079% DANAHER CORP DHR 57,533,95 0.30% D.68% 9.00% 9.71% 0.0289% WALT DISNEY COfTHE DIS 183,664.00 0.95% 1.38% 8.50% 9.92% 0.0944% DISCOVERY COMMUNICATIONS-A DISCA 15,920.76 0.08% 0.00% 15.50% 15.50% 0,0128% DISH NETWORK CORP-A DISH 27,840.38 0.14% 0.00% 7.00% 7.00% 0.0101% DELPHI AUTOMOTIVE PLC DLPH 21,016.56 0.11% 1.59% 14.00% 15.70% 0.0171% DIGITAL REALTY TRUST INC DLR NIA 3.36% NIA NIA N/A DOLLAR TREE INC DLTR 18.778.52 0.10% 0.00% 16.50% 16.50% 0.0160% DOVER CORP DOV 12,408.46 0.06% 2.21% 1.50% 3,73% 0,0024% DOW CHEMICAL CO/THE DOW 75,017,58 0.39% 3.29% 8.00% 11.42% 0.0444% DR PEPPER SNAPPLE GROUP INC DPS 17,962.24 0.09% 2.39% 7.00% 9.47% 0.0088% DARDEN RESTAURANTS INC DRI 10,450.69 0.05% 2.69% 14.50% 17.39% 0.0094% DTE ENERGY COMPANY DTE 18,560.45 0.10% 3.31% 5.00% B.'39% 0.0081% DUKE ENERGY CORP DUK 56,518.67 0.29% 4.24% 4.50% 8.84% 0,0259% DAVITAJNC DVA 13,313.33 0.07% 0.00% 11.00% 11.00% 0.0076% DEVON ENERGY CORP DVN 20,802.80 0.11% 0.61% 4.50% 5.12% 0.0055% DXC TECHNOLOGY CO DXC 10,642.96 0.06% 0.74% 4.00% 4.75% 0.0026% ELECTRONIC ARTS INC EA 28,001.47 0.15% 0.00% 13.50% 13.50% 0.0196% EBAY INC EBAY 35,067.34 0.18% 0,00% 1.50% 1.50% 0.0027% ECOLAB INC ECL 36,837.60 0.19% 1.17% 8.0Do/o 9.22% 0.0176% CONSOLIDATED EDISON INC ED 23,875.40 0.12% 3.55% 3.00% 6.60% 0.0082% EQUIFAX INC EFX 16,422.28 0.09% 1.14% 10.50% 11.70% 0.0100% EDISON INTERNATIONAL EIX 26,165.86 0.14% 2.80% 3.00% 5.84% 0.0079% ESTEE LAUDER COMPANIES-CL A EL 31,498.59 0.16% 1,58% 8,50% 10.15% 0.0166% EASTMAN CHEMICAL CO EMN 11,662.32 0.06% 2.56% B.00% 10.66% 0.0064% EMERSON ELECTRIC CO EMR 36,146.60 0.20% 3.26% 5.00% 8.34% 0.0165% EOG RESOURCES INC EOG 51,429.67 0.27% 0.80% 7,50% 8.33% 0.0222% EQUINIXINC EQ!X 26,929.93 0.15% 1.98% 23.00% 25.21% 0.0378% EQUITY RESIDENTIAL EQR N/A 3.15% NIA NIA NIA EQT CORP EQT 10,935.46 0.06% 0.19% 22.00% 22.21% 0.0126% EVERSOURCE ENERGY ES 18,835.64 0.10% 3.20% 7.00% 10.31% 0.0101% EXPRESS SCRIPTS HOLDING CO ESRX 41,343.03 0.21% 0,00% 14.50% 14.50% 0.0311% ESSEX PROPERTY TRUST INC ESS NIA 2.99% NIA NIA NIA E•TRADE FINANCIAL CORP ETFC 9,4!14.60 0.05% 0.00% 14.00% 14.00% 0.0069% EATON CORP PLC ETN 33,439,35 0.17% 3.24% 5.50% 8.83% 0.0153% ENTERGY CORP ETR 13,577.96 0.07% 4.64% -2.50% 2.08% 0.0015% Attachment RBH-5 Page 9 of12 [4] [5] [6] [7] [BJ [9] Market Eslimated Long-Term Weighted Company Ticker Capitalization Weighlln Index Dividend Yleld Growth Est. DCFResult DCFResult ENVISION HEALTHCARE CORP EVHC NIA 0.00% NIA NIA NIA EDWARDS LIFESCIENCES CORP EW 21,051.59 0.11% 0.00% 15.00% 15.00% 0.0104% EXELON CORP EXC 32,360.62 0.17% 3.74% 6.00% 9.65% 0.0165% EXPEDITORS INTL WASH INC EXPD 10,133.43 0.05% 1.42% 8.50% 9.98% 0.0052% EXPEDIA INC EXPE 19,793.72 0.10% 0,85% 21.50% 22.44% 0.0230% EXTRA SPACE STORAGE INC EXR NIA 4.02% NIA NIA NIA FORD MOTOR CO F 44,765.84 0.23% 5.23% 3.00% 8.31% 0.0193% FASTENAL CO FAST 13,152.83 0.07% 2.82% 6.50% 9.41% 0.0064% FACEBOOK INC-A FB 415,869.60 2.15% 0.00% 37.50% 37.50% 0.8078% FORTUNE BRANDS HOME & SECURI FBHS 9,616.41 0.05% 1.16% 13.50% 14.74% 0.0073% FREEPORT-MCMORAN INC FCX 18,076.95 NIA 0,00% NIA NIA NIA FEDEXCORP FOX 49,860.09 0.26% 0.86% 11.00% 11.91% 0.0308% FIRSTENERGY CORP FE 13,053.28 0.07% 4.70% 5.00% 9.82% 0.0066% F5 NETWORKS INC FFIV 8,667.53 0,05% 0.00% 7.50% 7.50% 0,0034% FIDELITY NATIONAL INFO SERV FIS 26,754.96 G.14% 1.42% 14.50% 16.02% 0.0222% FISERV INC FISV 25,654.66 Cl.13% 0.00% 9.50% 9.50% 0.0126% FIFTH THIRD BANCORP FITB 18,724.45 O.Hl% 2.29% 3.00% 5.32% 0.0052% FOOT LOCKER INC FL 10,066.02 0.05% 1.62% 9.50% 11.20% 0.0058% FUR SYSTEMS INC FUR 4,966.65 0.03% 1.73% 7.50% 9,29% 0.0024% FLUOR CORP FLR 7,031.14 0.04% 1.66% 4.50% 6.20% 0.0023% FLOWSERVE CORP FLS 6,382.91 0.03% 1.55% 2.50% 4.07% 0.0013% FMC CORP FMC 9,614.18 0.05% 0,91% 8,50% 9.45% 0,0048% TWENTY-FIRST CENTURY FOX-A FOXA 57,505,44 0.30% 1.16% 12.00% 13.23% 0.0394% FEDERAL REALTY INVS TRUST FRT NIA 2.96% NIA NIA NIA TECHNIPFMC PLC FTI NIA NIA 0,00% NIA NIA NIA FORTIVE CORP FTV 20,952.BB NIA 0.46% NIA NIA NIA GENERAL DYNAMICS CORP GD 56,894.09 0.29% 1.79% 5,50% 7,34% 0,0216% GENERAL ELECTRIC CO GE 264,638.90 1.37% 3.17% 13.50% 16.88% 0.2314% GGPINC GGP NIA 3.95% NIA NIA NIA GILEAD SCIENCES INC GILD 87,115.00 0.45% 3.13% -3,50% -0.42% -0,0019% GENERAL MILLS INC GIS 33,344,66 0.17% 3.35% 5.00% 8.43% 0.0146% CORNING INC GLW 25,103.86 0.13% 2.29% 10.50% 12.91% 0.0168% GENERAL MOTORS CO GM 51,150.00 0,26% 4.46% 9.00% 13.66% 0.0362% ALPHABET INC-CL A GOOGL NIA NIA 0.00% NIA NIA NIA GENUINE PARTS CO GPC 13,817.67 0.07% 2.91% 6.50% 9.50% 0,0068% GLOBAL PAYMENTS INC GPN 12,332.11 0.06% 0.05% 14.50% 14.55% 0.0093% GAPING/THE GPS 10,142.58 0.05% 3.62% 0.50% 4.13% 0.0022% GARMIN LTD GRMN 9,424.48 0,05% 4.08% 5.00% 9,18% 0,0045% GOLDMAN SACHS GROUP INC GS 86,870,09 0.45% 1.38% 9.50% 10.95% 0.0493% GOODYEAR TIRE & RUBBER CO GT 8,992.08 0.05% 1.18% 10.00% 11.24% 0.0052% WW GRAINGER INC GWW 11,523.23 0,06% 2.49% 6.00% 8.56% 0.0051% HALLIBURTON CO HAL 41,299.54 0.21% 1.51% 8.00% 9.57% 0.0205% HASBRO INC HAS 11,952.00 0.06% 2.38% 12.00% 14.52% 0,0090% HUNTINGTON BANCSHARES INC HBAN 13,809,96 0.07% 2.59% 8.00% 10.69% 0.0076% HANESBRANDS INC HBI 6,384.13 0.04% 2.71% 9.50% 12.34% 0.0054% HCA HOLDINGS INC HCA 31,137.27 0,16% 0.00% 10.00% 10.00% 0.0161% WELL TOWER INC HCN NIA 4.71% N/A NIA NIA HCP INC HCP NIA 4.58% NIA NIA NIA HOME DEPOT INC HD 181 ,438.40 0.94% 2.39% 11.50% 14.03% 0.1318% HESS CORP HES 14,846.36 0.08% 2.13% -1.00% 1.12% 0.0009% HARTFORD FINANCIAL SVCS GRP HIG 18,082.63 0.09% 1.93% 11.50% 13.54% 0.0127% HARLEY-DAVIDSON INC HOG 9,935.78 0.05% 2.59% 9.00% 11.71% 0.0060% HOLOGICINC HOl.X 12,014.43 0.06% 0.00% 25,00% 25.00% 0,0156% HONEYWELL INTERNATIONAL INC HON 94,164.22 0.49% 2.15% 8.00% 10.24% 0.0499% HELMERICH & PAYNE HP 7,038.14 0.04% 4.32% 4.50% 8.92% 0.0033% HEWLETT PACKARD ENTERPRIS HPE 30,482.79 0.16% 1.42% 1.50% 2,93% 0,0046% HPINC HPQ 31,361.40 NIA 2.97% NIA NIA NIA H&R BLOCK INC HRB 4,897.40 0.03% 3.72% 10.00% 13.91% 0.0035% HORMEL FOODS CORP HRL 18,259.60 0.09% 2.00% 10.50% 12,61% 0.0119% HARRIS CORP HRS 13,664.26 0.07% 1.98% 6.50% 8.54% 0.0060% HENRY SCHEIN INC HSIC 13,661.09 0.07% 0,00% 8,50% B.50% 0,0060% HOST HOTELS & RESORTS INC HST NIA 4.20% NIA NIA NIA HERSHEY CO/THE HSY 23,093.78 0.12% 2.27% 6.50% 8.64% 0.0106% HUMANA INC HUM 31,943.40 0.17% 0,75% 9,00% 9,78% 0,0162% !NTL BUSINESS MACHINES CORP IBM 153,514.20 NIA 3.70% N/A NIA NIA INTERCONTINENTAL EXCHANGE IN ICE 36,074.85 0.19% 1.32% 12.00% 13.40% 0.0250% IDEXX LABORATORIES INC IDXX 14,310.06 0,07% 0.00% 12.50% 12,50% 0.0093% INTL FLAVORS & FRAGRANCES JFF 10,792.98 0.06% 2.02% 7.50% 9.60% 0.0054% ILLUMINA INC ILMN 26,024.80 0.13% 0,00% 19.00% 19.00% 0.0256% lNCYTECORP INCY 23,318,02 0.12% 0.00% 69.50% 69.50% 0.0839% INTELCORP INTC 171,131.40 0.89% 3.01% 8.00% 11.13% 0.0987% INTUIT INC INTU 30,277.36 0,16% 1.15% 13.50% 14.73% 0.0231% INTERNATIONAL PAPER CO IP 21,803.36 0.11% 3.49% 17.50% 21.30% 0.0241% INTERPUBLIC GROUP OF COS INC IPG 10,327.25 0.05% 2,86% 13.00% 16,05% 0.0086% INGERSOLL-RAND PLC IR 21,432,75 0,11% 1.93% 8,00% 10.01% 0.0111% IRON MOUNTAIN INC IRM 9,620.28 0.05% 6.02% 10.00% 16.32% 0,0081% INTUITIVE SURGICAL INC ISRG 29,971.76 0,16% 0.00% 11.50% 11.50% 0.0179% GARTNER INC IT 9,337.16 0.05% 0.00% 11.50% 11.50% 0.0056% ILLINOJS TOOL WORKS lTW 47,238.25 0.24% 1,93% 10.00% 12,03% 0.0294% INVESCOLTD IVZ 12,877.02 0.07% 3.55% 4.50% 8.13% 0.0054% HUNT (JB) TRANSPRT SVCS INC JBHT 9,991.85 0.05% 1.03% 9.00% 10.08% 0,0052% JOHNSON CONTROLS INTERNATION JCI 39,171.33 0.20% 2.68% 2.00% 4.71% 0.0096% JACOBS ENGINEERING GROUP INC JEC 6,504.19 0.03% 1.16% 8.00% 9.21% 0.0031% JOHNSON & JOHNSON JNJ 331,801.30 1.72% 2.75% 8,50% 11.37% 0,1954% JUNIPER NETWORKS INC JNPR 10,594.58 0.05% 1.51% 8.00% 9.57% 0.0053% JPMORGAN CHASE & CO JPM 306,120.50 1.59% 2.34% 6.00% 8.41% 0.1334% NORDSTROM INC JWN 8,137.90 0.04% 3,09% 2.00% 5,12% 0.0022% KELLOGG CO K 25,554.31 0.13% 2.89% 6.50% 9.48% 0.0126% KEYCORP KEY 19,654.29 0.10% 2.03% 9,00% 11.12% 0,0113% KRAFT HEINZ CO/THE KHC 111,964.40 NIA 2.67% NIA NIA NIA Attachment RBH-5 Page 10of12 [7] [8] [9l Long-Term Weighted Company Tici KIMCO REALTY CORP KIM NIA 4.91% NIA NIA NIA KLA-TENCOR CORP KLAC 15,439.37 0.08% 2.19% 13.50% 15.84% 0.0127% KIMBERLY-CLARK CORP KM8 46,796.62 0.24% 2.96% 10.00% 13.11% 0.0318% KINDER MORGAN !NC KMI 46,207.71 0.24% 2.41% 24.00% 26.70% 0.0639% CARMAXINC KMX 11,016.24 0.06% 0.00% 10.50% 10.50% 0.0060% COCA-COLA CD!THE KO 164,769.90 0,96% 3.48% 4.50% 8.06% 0.0771% MICHAEL KORS HOLDINGS LTD KORS 6,104.35 0.03% 0.00% 4.50% 4.50% 0.0014% KROGER CO KR 27,452.04 0.14% 1.78% B.50% 10.36% 0.0147% KOHLS CORP KSS 7,092.24 0,04% 5.40% 7.00% 12.59% 0.0046% KANSAS CITY SOUTHERN KSU 9,655.31 0.05% 1.46% 9.50% 11.03% 0.0055% LOEWS CORP L 15,504.76 0.08% 0.54% 13.00% 13.58% 0.0109% LBRANDS INC LB 14,202.76 0.07% 4.83% 2.50% 7.39% 0.0054% LEGGETT & PLATT INC LEG 6,971.37 0.04% 2.60% 7.50% 10.20% 0.0037% LENNAR CORP-A LEN 12., 166.39 0,06% 0.31% 10.00% 10.33% 0.0065% LABORATORY CRP OF AMER HLDGS LH 14.959.28 0.08% 0.00% 9.00% 9-.00% 0.0070% LKQ CORP LKQ 8,910.97 0.05% 0.00% 12.50% 12.50% 0.0058% L3 TECHNOLOGIES INC LLL 12,985.79 0,07% 1.78% 10.00% 11.87% 0.0080% ELI LILLY & CO LLY 90,205.70 0.47% 2.54% 11.00% 13.68% 0.0639% LOCKHEED MARTIN CORP LMT 78,564.64 0.41% 2.74% 8.50% 11.36% 0.0462% LINCOLN NATIONAL CORP LNG 14,725.36 0.08% 1.84% 7.00% 8.90% 0.0068% ALLIANT ENERGY CORP LNT 9,043.21 0.05% 3.17% 6.50% 9.77% 0.0046% LOWE'S COS INC LOW 72,712.16 0.38% 1.86% 14.50% 16.49% 0.0621% LAM RESEARCH CORP LRCX 22,626.07 0.12% 1.36% 19.50% 20.99% 0.0246% LEUCADIA NATIONAL CORP LUK 9,273.17 0.05% 0.97% 31.00% 32.12% 0.0154% SOUTHWEST AIRLINES CO LUV 34,418.26 0,18% 0,72% 14.50% 15.27% 0.0272% LEVEL 3 COMMUNICATIONS INC LVLT 21,667.60 0.11% 0.00% 29.50% 29.50% 0.0331% LYONDELLBASELL INDU.CL A LYB 34,987.78 0.18% 3.98% 5.00% 9,08% 0.0165% MACY'S INC M 9,124.93 0.05% 5.03% 2.50% 7.59% 0.0036% MASTERCARD INC -A MA 123,871.80 0.64% 0.77% 12.00% 12.82% 0.0822% MID-AMERICA APARTMENT COMM MAA NIA NIA 0,00% NIA NIA NIA MACERICH CO!THE MAC NIA 4.39% NIA NIA NIA MARRIOTT INTERNATIONAL.CLA MAR 35,582.96 0.18% 1.29% 13.00% 14.37% 0.0265% MASCO CORP MAS 10,789.74 0,06% 1.18% 11.50% 12.75% 0.0071% MATTELINC MAT 8,631.90 0.04% 6.03% 4.50% 10.67% 0.0048% MCDONALD'S CORP MCD 110,667.40 0.57% 2.85% 6.50% 9.44% 0.0541% MICROCHIP TECHNOLOGY INC MCHP 16,368,60 0,08% 1.90% 12.00% 14.01% 0.0119% MCKESSON CORP MCK 29,191.22 0.15% 0.61% 11.00% 11.85% 0.0179% MOODY'S CORP MCO 22,053.49 0.11% 1.32% 6.50% 7.86% 0.0000% MONDELEZ INTERNATIONAL INC-A MOLZ 68,745.86 0.36% 1.82% 10.00% 11.91% 0.0424% MEDTRONIC PLC MDT 110,907.10 0.57% 2.17% 6.00% 8.24% 0.0473% METLJFE INC MET 56,725.97 0,29% 3.32% 7.00% 10.44% 0.0307% MOHAWK INDUSTRIES INC MHK 17,525.16 0.09% 0.00% 7.50% 7.50% 0.0068% MEAD JOHNSON NUTRITION CO MJN 16,262.25 0.08% 1.86% 5.50% 7.41% 0.0063% MCCORMICK & CO-NON VTG SHRS MKC 12,522,66 0.06% 1.87% 6.50%· 8.43% 0.0055% MARTIN MARIETTA MATERIALS MLM 13,727.51 0.07% 0.77% 17.50% 18.34% 0.0130% MARSH & MCLENNAN COS MMC 37,855.97 0,20% 1.86% 9.00% 10.94% 0.0215% 3MCO MMM 114,976.20 0.60% 2.46% 8.00%. 10.56% 0.0629% MALLINCKRODT PLC MNK 4,615.01 0.02% 0,00% 53.00% 53.00% 0,0132% MONSTER BEVERAGE CORP MNST 25,914.73 0.13% 0.00% 12.00% 12.00% 0.0161% ALTRIA GROUP INC MD 138,769.10 0.72% 3.42% 9.50% 13.08% 0.0940% MONSANTO CO MON 50,767.64 0.26% 1.87% 9.50% 11.46% 0.0301% MOSAIC CO!THE MOS 9,491.45 0.05% 2.21% 3.50% 5.75% 0.0028% MARATHON PETROLEUM CORP MPG 25,532.04 0.13% 3.21% 3.50% 6,77% 0,0089% MERCK & CO. INC. MRK 171,933.10 0.89% 3.01% 5.50% 8.59% 0.0765% MARATHON OIL CORP MRO 12,781.23 0.07% 1.33% 14.50% 15.93% 0.0105% MORGAN STANLEY MS 79,749.BO 0.41% 1.88% 12.00% 13,99% 0,0578% MICROSOFT CORP MSFT 506,315,00 2.62% 2.38% 8.00% 10.48% 0.2747% MOTOROLA SOLUTIONS INC MSI 13,851.27 0.07% 2.24% 10.50% 12.86% 0,0092% M & T BANK CORP MTB 23,906.15 0.12% 1.95% 6.50% 8.51% 0.0105% METTLER-TOLEDO INTERNATIONAL MTD 12,744.33 0.07% 0.00% 10.50% 10.50% 0.0069% MICRON TECHNOLOGY INC MU 30,923.76 0.16% 0.00% 18.00% 18.00% 0,0288% MURPHY OIL CORP MUR 4,609,79 NIA 3.74% NIA NIA NIA MYLAN NV MYL 19,849.96 0.10% 0.00% 16.50% 16.50% 0.0170% NAVIENT CORP NAVI 4,851.03 NIA 4.00% NIA NIA NIA NOBLE ENERGY INC NBL 14,813.58 NIA 1.17% NIA NIA NIA NASDAQ INC NDAQ 11,660.52 0.06% 1.83% 8.50% 10.41% 0,0063% NEXTERA ENERGY INC NEE 61,247.16 0.32% 3.00% 6.00% 9.09% 0.0268% NEWMONT MINING CORP NEM 17,860.76 0.09% o.59% 0.50% 1.09% 0.0010% NETFLIXINC NFLX 60.847.59 0.32% 0.00% 42.00% 42.00% 0.1324% NEWFIELD EXPLORATION CO NFX 6,940.77 0.04% 0.00% 12.50% 12.50% 0.0045% NiSOURCE INC NI 7.760.24 0.04% 2.90% 2.00% 4.93% 0.0020% NIKE INC -CL B NKE 93,172.80 0,48% 1.28% 15.00% 16.38% 0.0790% NIELSEN HOLDINGS PLC NLSN 14,701.09 0.08% 3.02% -2.50% 0.48% 0.0004% NORTHROP GRUMMAN CORP NOC 42,865.40 0.22% 1.47% 8,00% 9.53% 0.0212% NATIONAL OILWELL VARCO INC NOV 13,456,52 0.07% 0.56% -9.50% -8.97% -0.0062% NRG ENERGY INC NRG 5,438.24 NIA 0.70% NIA NIA NIA NORFOLK SOUTHERN CORP NSC 33,809.80 0.18% 2.11% 6.50% 8.68% 0.0152% NETAPPJNC NTAP 10.924.01 0.06% 1.89% 9.00% 10.96% 0.0062% NORTHERN TRUST CORP NTRS 19,801.39 0.10% 1.74% 8.00% 9.81% 0.0101% NUCOR CORP NUE 19,220,57 0.10% 2.50% 20.50% 23.26% 0.0232% NVIDIA CORP NVDA 59,237.10 0.31% 0.55% 14.50% 15.09% 0.0463% NEWELL BRANDS INC NWL 22,725.75 0.12% 1.61% 18.00% 19.75% 0.0233% NEWS CORP - CLASS A NWSA 7.523.38 0.04% 1.55% 59.00% 61.01% 0.0238% REAL TY INCOME CORP 0 NIA 4.11% NIA NIA NIA ONEOK INC OKE 11,323.76 0.06% 4.69% 11.00% 15.95% 0.0094% OMNICOM GROUP OMC 19.832.BB 0.10% 2.74% 9.00% 11.86% 0.0122% ORACLE CORP DRCL 183,240.90 0.95% 1.71% 5.00% 6.75% 0.0641% O'REILLY AUTOMOTIVE INC ORLY 24.420.08 0.13% 0.00% 11.00% 11.00% 0.0139% OCCIDENTAL PETROLEUM CORP OXY 47,326.16 0.25% 4.94% 3,50% 8.53% 0,0209% PAYCHEX INC PAYX 21.067,08 0.11% 3.29% 9.00% 12.44% 0.0136% Attachment RBH-5 Page 11of12 4] [5] (6 !7l [8] {9l Market Estlmared Long-Tenn Weighted Company Ticker Capitalization Weight in Index Dividend Yield Growth Est. DCF Result DCFRosull PEOPLE'S UNITED FINANCIAL PBCT 5,550.36 0.03% 3.93% 10.50% 14.64% 0.0042% PACCAR INC PCAR 23,097.53 0.12% 2.49% 5.00% 7.55% 0.0090% PG&E CORP PCG 34,037.73 0.18% 3.16% 9.50% 12.81% 0.0226% PRICELINE GROUP INCFTHE PCLN 86,610.23 0.45% 0.00% 15.00% 15.00% 0.0673% PATTERSON COS INC PDCO 4,300.12 0.02% 2.35% 10.50% 12.97% 0.0029% PUBLIC SERVICE ENTERPRISE GP PEG 22,406.85 0.12% 3.88% 2.50% 6.43% 0.0075% PEPSICO INC PEP 162,206.50 0.84% 2.71% 7.00% 9.80% 0.0824% PFIZER INC PFE 204,801.80 1.06% 3.79% 11.00% 15.00% 0.1591% PRINCIPAL FINANCIAL GROUP PFG 18,102.08 0.09% 2.86% 5.00% 7.93% 0.0074% PROCTER & GAMBLE COFTHE PG 228,370.10 1.18% 3.09% 7.50% 10.71% 0.1266% PROGRESSIVE CORP PGR 22,853.86 0.12% 1.73% 7.50% 9.29% 0.0110% PARKER HANNIFIN CORP PH 20,936.49 0.11% 1.68% 7.50% 9.24% 0.0100% PULTEGROUP INC PHM 7,447.54 0.04% 1.59% 16.50% 18.22% 0.0070% PERKINELMER INC PKI 6,268.41 0.03% 0.49% 8.00% 8.51% 0.0028% PROLOGIS INC PLO N/A 3.23% NIA NIA NIA PHILIP MORRIS INTERNATIONAL PM 170,621.40 0.88% 3.78% 7.50% 11.42% 0.1009% PNC FINANCIAL SERVICES GROUP PNC 57,989.04 0.30% 1.85% 3.00% 4,88% 0.0147% PENTAIR PLC PNR 11,417.04 0.06% 2.20% 11.00% 13.32% 0.0079% PINNACLE WEST CAPITAL PNW 9,499.19 0.05% 3.18% 5.50% 8.77% 0.0043% PPG INDUSTRIES INC PPG 27,372.19 0.14% 1.50% 9.50% 11.07% 0.0157% PPL CORP PPL 25,676.33 0.13% 4.18% 2.00% 6.22% 0.0083% PERRIGO CO PLC PRGO 9,571.65 NIA 0.96% NIA NIA NIA PRUDENTIAL FINANCIAL INC PRU 45,466.11 0.24% 2.83% 5.50% 8.41% 0.0198% PUBLIC STORAGE PSA N/A 3.55% NIA NIA NIA PHILLIPS 66 PSX 39,454.39 0.20% 3.70% 2,00% 5.74% 0,0117% PVHCORP PVH 7,965,86 0.04% 0.15% 7.00% 7.16% 0.0030% QUANTA SERVICES INC PWR 5,089.71 0.0~% 0.00% 10.50% 10.50% 0.0028% PRAXAIR INC PX 34,169.63 0.18% 2.68% 6.00% 8.76% 0.0155% PIONEER NATURAL RESOURCES CO PXD 29,605.43 0.15% 0.05% 20.00% 20.06% 0.0308% PAYPAL HOLDINGS INC PYPL 52,733.83 NIA O.Ooo/o NIA NIA NIA QUALCOMM INC QCOM 77,778,83 0.40% 4.41% 6.00% 10.54% 0.0425% QORVOINC QRVO 8,973.29 NIA 0.00% NIA NIA NIA RYDER SYSTEM INC R 4,097.25 0.02% 2.30% 7,50% 9.89% 0.0021% REYNOLDS AMERICAN INC RAI 90,953.38 0.47% 3.20% 13.50% 16.92% 0.0797% ROYAL CARIBBEAN CRUISES LTD RCL 20,860.68 0.11% 1.98% 16.50% 18.64% 0.0201% REGENCY CENTERS CORP REG NIA NIA 0.00% NIA NIA NIA REGENERON PHARMACEUTICALS REGN 39,901.41 0.21% 0.00% 22.00% 22.00% 0.0455% REGIONS FINANCIALCORP RF 16,566.88 0.09% 2.05% 7.50% 9.63% 0.0083% ROBERT HALF INTL INC RHI 5,917.16 0.03% 2.09% 6.00% 8.15% 0.0025% REDHATINC RHT 15,623.26 0.08% 0.00% 16.50% 16.50% 0.0134% TRANSOCEAN LTD RIG 4,430.99 0,02% 0.00% -19.00% -19.00% -0.0044% RAYMOND JAMES FINANCIAL INC RJF 10,599.69 0.05% 1.19% 10.50% 11.75% 0.0065% RALPH LAUREN CORP RL 6,552.98 0.03% 2.51% 1.00% 3.52% 0.0012% ROCKWELL AUTOMATION INC ROK 19,781.25 0.10% 1.98% 4.00% 6.02% 0.0062% ROPER TECHNOLOGIES INC ROP 21,233.18 0.11% 0.67% 6.50% 7.19% 0.0079% ROSS STORES INC ROST 25,483.80 0.13% 1.01% 9.00% 10,06% 0.0133% RANGE RESOURCES CORP RRC 6,822.43 0.04% 0.29% 14.00% 14.31% 0,0051o/o REPUBLIC SERVICES INC RSG 21,473.81 0.11% 2.10% 8.00% 10.18% 0.0113% RAYTHEON COMPANY RTN 45,122.00 0.23% 2.07% 8.00% 10.15% 0.0237% STARBUCKS CORP SBUX 87,548.58 0.45% 1.83% 15.00% 16.97% 0.0769% SCANA CORP SCG 9,437.12 0.05% 3.71% 4.50% 8.29% 0.0041% SCHWAB (CHARLES) CORP SCHW 51,213.36 0.27% 0.83% 14.50% 15.39% 0.0408% SEALED AJR CORP SEE B,511.27 0,04% 1.46% 12.00% 13.55% 0.0060% SHERWIN-WILLIAMS CO/fHE SHW 30,138.07 0,16% 1.05% 8.50% 9.59% 0.0150% SIGNET JEWELERS LTD SIG 4,604.10 0,02% 1.84% 7.00% 8.90% 0,0021% JM SMUCKER COffHE SJM 14,841.83 0.08% 2.35% 7.00% 9.43% 0.0073% SCHLUMBERGER LTD SLB 106,461.80 0.55% 2.61% 10.00% 12.74% 0.0703% SL GREEN REAL TY CORP SLG NIA 2.90% NIA N/A NIA SNAP-ON INC SNA 10,045.87 0.05% 1.64% 9.50% 11.22% 0,0058% SCRIPPS NETWORKS INTER-CL A SNI 9,778.26 0.05% 1.59% 9.00% 10.66% 0,0054% SYNOPSYS INC SNPS 10,915,05 0.06% 0.00% 9.00% 9.00% 0.0051% SOUTHERN COFTHE so 48,774.55 0.25% 4.66% 4.50% 9.26% 0.0234% SIMON PROPERTY GROUP INC SPG NIA 4.01% NIA NIA NIA S&P GLOBAL INC SPGI 34,167.52 0.18% 1.24% 11.00% 12.31% 0,0218% STAPLES INC SPLS 6,289.34 0.03% 4.93% 1.50% 6.47% 0.0021% STERICYCLE INC SRCL 7.240.39 0.04% 0.00% 5.50% 5.50% 0.0021% SEMPRA ENERGY SRE 28,089.57 0.15% 2.99% B.00% 11,11% 0.0162% SUNTRUST BANKS INC STJ 27.519.49 0.14% 1.sao/o 7.00% 9.05% 0.0129% STATE STREET CORP STT 29.913.46 0.15% 2.04% 5.50% 7.60% 0.0118% SEAGATE TECHNOLOGY STX 14,329,63 0.07% 5.19% 4.50% 9.81% 0.0073% CONSTELLATION BRANDS INC-A STZ 34.421.89 0.18% 1.22% 14.50% 15.81% 0.0282% STANLEY BLACK & DECKER ING SWK 19,997.94 0.10% 1.75% 9.00% 10,83% 0.0112% SKYWORKS SOLUTIONS INC SWKS 18.781,22 0.10% 1.10% 12.50% 13,67% 0.0133% SYNCHRONY FINANCIAL SYF 27.941.96 NIA 1.54% NIA NIA NIA STRYKER CORP SYK 49,652.24 0.26% 1.28% 14.50% 15.87% 0.0408% SYMANTEC CORP SYMC 18,865.32 0.10% 0.98% 5.00% 6.00% 0.0059% SYSCO CORP SYY 28,343.09 0.15% 2.59% 11.50% 14.24% 0.0209% AT&T INC T 247.769.80 1.28% 4,88% 5,50% 10.51% 0.1349% MOLSON COORS BREWING CO -B TAP 21,329.22 0.11% 1.84% 3,50% 5.37% 0.0059% TERADATA CORP TDC 4,145.81 0.02% 0.00% 0.50% 0.50% 0.0001% TRANSDIGM GROUP INC TOG 12.814.77 0.07% 0.00% 12.00% 12.00% 0.0080% TE CONNECTIVITY LTD TEL 26,349.73 0.14% 2.00% 7.50% 9.58% 0.0131% TEGNAINC TGNA 5,596.43 0.03% 2.15% 1.00% 3.16% 0.0009% TARGET CORP TGT 30,388.36 0.16% 4.39% 4,50% 8.99% 0.0141% TIFFANY& CO TIF 11,471.43 0.06% 2.13% 8.00% 10.22% D.0061% TJX COMPANIES INC TJX 50,959.10 0.26% 1.60% 10.00% 11.66% 0.0308% TORCHMARK CORP TMK 8,970.36 0.05% 0.79% 7.50% 8.32% 0.0039% THERMO FISHER SCIENTIFIC INC TMO 61,371.08 0.32% 0.39% 9.50% 9.91% 0.0315% TRIPADVISOR INC TRIP 6,154.94 0.03% 0.00% 10,50% 10.50% 0.0033% T ROWE PRICE GROUP INC TROW 17,697.8.8 0.09% 3.15% 7.50% 10.77% 0.0099% Attachment RBH-5 Page 12of12 [4] [5] [6] !7l [8] [9l Market Estimated Long-Term Weigh led Company Tici TRAVELERS COS INCfTHE TRV 33,238.85 0.17% 2.25% 1.50% 3.77% 0.0065% TRACTOR SUPPLY COMPANY TSCO 8,489,90 0.04% 1.66% 10.50% 12.25% 0.0054% TYSON FOODS INC-CL A TSN 23,216.61 0.12% 1.46% 9.00% 10.55% 0.0127% TESORO CORP TSO 8,935.11 0,05% 2.88% 7.50% 10.49% 0.0049% TOTAL SYSTEM SERVICES INC TSS 9,640,31 0.05% 0.75% 10.50% 11.29% 0.0058% TIME WARNER INC TWX 77,200.00 0.40% 1.61% 11.00% 12.70% 0.0508% TEXAS INSTRUMENTS INC TXN 80,435.66 0.42% 2.46% 6.00% 10.58% 0.0441% TEXTRON INC TXT 12,408.68 0.06% 0.17% 12.00% 12.18% 0.0078% UNDER ARMOUR INC-CLASS A UAA 8,495.79 0.04% 0.00% 15.50% 15.50% 0.0068% UNITED CONTINENTAL HOLDINGS UAL 21,716.88 0.11% 0.00% 6.00% 6,00% 0.0067% UDR INC UDR NIA 3.42% NIA NIA NIA UNIVERSAL HEALTH SERVICES-B UHS 11,511.53 0.06% 0.34% 10.50% 10.86% 0.0065% ULTA BEAUTY INC ULTA 17,369,34 0.09% 0.00% 22.00% 22.00% 0.0198% UNITEDHEALTH GROUP INC UNH 163,306.10 0.85% 1.46% 12.50% 14.05% 0.1189% UNUM GROUP UNM 10,516.70 0,05% 1.75% 10.50% 12.34% 0.0067% UNION PACIFIC CORP UNP 88,027.41 0.46% 2.24% 8.00% 10.33% 0.0471% UNITED PARCEL SERVICE-CL B UPS 92,127.69 0.48% 3.15% 9.50% 12.80% 0.0611% UNITED RENTALS INC URI 9,569.57 0.05% 0.00% 8.00% 8,00% 0.0040% US BANCORP USB 85,999.50 0.45% 2.25% 4.00% 6.30% 0.0280% UNITED TECHNOLOGIES CORP UTX 92,143.39 0.48% 2.32% 7.50% 9.91% 0.0473% VISA INC-CLASS A SHARES v 192,782.20 1.00% 0.76% 13.50% 14.31% 0,1429% VARIAN MEDICAL SYSTEMS INC VAR 8,351.42 0.04% 0.00% 7.00% 7.00% O.OD30% VF CORP VFC 23,366.84 0.12% 2.98% 8.50% 11.61% 0.0140% VIACOM INC-CLASS B VIAB 17,599.01 0.09% 1.81% 1.00% 2.82% 0.0026% VALERO ENERGY CORP VLO 28,941.28 0.15% 4.37% 4.50% 8.97% 0.0134% VULCAN MATERIALS CO VMC 15,858.18 0.08% 0.84% 20.50% 21.43% 0.0176% VORNADO REALTY TRUST VNO 19,196.12 0.10% 2.80% 19.50% 22.57% 0.0224% VERISK ANALYTICS INC VRSK 13,697.91 0.07% 0,00% 10.00% 10,00% 0.0071% VERISIGN INC VRSN 9,145,20 0.05% 0.00% 12.00% 12.00% 0.0057% VERTEX PHARMACEUTICALS INC VRTX 29,083.88 NIA 0.00% N/A NIA NIA VENTAS INC VTR NIA 4.85% N/A NIA N/A VERIZON COMMUNICATIONS INC vz 197,349.80 1.02% 4.77% 3.00% 7.84% 0.0802% WATERS CORP WAT 12,808.39 0.07% 0.00% 6.00% 6.00% 0.0040% WALGREEN$ BOOTS ALLIANCE INC WBA 90,929.88 0.47% 1.78% 11.00% 12.88% 0.0607% WESTERN DIGITAL CORP woe 24,310.08 0.13% 2.37% 7.50% 9.96% 0.0125% WEC ENERGY GROUP INC WEC 18,864.25 0.10% 3.53% 6.00% 9.64% 0.0094% WELLS FARGO & CO WFC 268,776.10 1.39% 2.90% 4.50% 7.47% 0.1039% WHOLE FOODS MARKET INC WFM 11,306.75 0.06% 1.61% 3.50% 5.14% 0.0030% WHIRLPOOL CORP WHR 12,873.00 0.07% 2.56% 9.50% 12,18% 0,0081% WILLIS TOWERS WATSON PLC WL1W 17,697.19 NIA 1.57% NIA NIA NIA WASTE MANAGEMENT INC WM 32,195.06 0.17% 2.33% 7.50% 9.92% 0.0165% WILLIAMS COS INC WMB 22,664.74 0.12% 3.97% 14.00% 18.25% 0.0214% WAL-MART STORES INC WMT 227,991}.40 1.16% 2.73% 4.00% 6.78% 0.0801% WESTROCKCO WRK 13,275.31 NIA 3.01% NIA N/A NIA WESTERN UNION CO WU 9,625.19 0.05% 3.50% 8.00% 11.64% 0.0058% WEYERHAEUSER CO WY 26,033.80 0.13% 3.57% 12.50% 16.29% 0.0220% WYNDHAM WORLDWIDE CORP WYN 9,664,55 0.05% 2.59% 8.00% 10.69% 0,0054% WYNN RESORTS LTD WYNN 11,823.95 0.06% 1.72% 5.00% 6.76% 0.0041% CIMAREX ENERGY CO XEC 11,104.14 0.06% 0.27% 16.00% 16.29% 0.0094% XCEL ENERGY INC XEL 22,647.46 0.12% 3.27% 4.50% 7.84% 0.0092% XL GROUP LTD XL 11,895.91 0.06% 2.18% 8.00% 10.27% 0.0063% XILINX INC XLNX 14,366.04 0.07% 2.29% 6.50% 8.86% 0.0066% EXXON MOBIL CORP XOM 336,029.50 1.74% 3.73% 11.50% 15.44% 0.2688% DENTSPLY SIRONA INC XRAY 14,471.58 0.07% 0.56% 8.50% 9.06% 0.0068% XEROX CORP XRX 7,066.03 0.04% 3.59% 0.50% 4.10% 0.0015% XYLEM INC XYL 9,014.49 0.05% 1.43% 12.00% 13.52% 0.0063% YAHOOllNC YHOO 45,451.77 N/A 0.00% NIA NIA NIA YUMl8RANDSINC YUM 24,455.04 0.13% 1.89% 4.00% 5.93% 0.0075% ZIMMER BIOMET HOLDINGS INC ZBH 24,394.37 0.13% 0.65% 12.50% 13.40% 0.0169% ZIONS BANCORPORATION ZION 8,342.73 0,04% 0.83% 11.00% 11.88% 0.0051% ZOETISINC ZTS 26,757.10 0.14% 0.77% 11.50% 12.31% 0.0171% Total Markel Capitalization: 19,305,717.66 14.09% Notes: [1] Equals sum of Col. [9] [2] Source: Value Line [3] Equals [1) - [2l [4] Source: Value Line [5] Equals weight in S&P 500 based on market capitalization [6] Source: Value Line [7] Source: Value Line [8] Equals ([6] x (1 + (0.5 x [7l))) + [7] [9] Equals Col. [SJ x Col. [BJ Attachment RBH-6 Page 1 ofl Bloomberg and Value Line Bela Coemcients [1] [2] Company licker Bloomberg Value Line #REFI #REF! 0.504 0.850 #REFI #REF! 0.696 0.850 #REF! #REF! 0.665 0.700 #REF! #REF! 0.549 0.650 #REF! #REF! 0.734 0.800 #REF! #REF! 0.588 0.750 #REF! #REF! 0.636 0.700 #REF! #REF! 0.675 0.750 Mean 0,631 0.7!;6 Notes: [1] Source: Bloomberg Professional [2) Source: Value Line AttachmentRBH-7 Page 1 ofl Capital Asset Pricing Model Results Bloomberg, and Value Line Derived Market Rlsk Premium [1] [2] [3] [4] [5] [6] CAPM Average Bloomberg Value Lme Risk-Free Beta Market DCF Market DCF Bloomberg Value Line Rate Coefficient Derived Derived MRP MRP PROXY GROUP AVERAGE BLOOMBERG BETA COEFFICIENT Current 30-Year Treasury [7] 2.97% 0.631 10.39% 11.12% 9.53% 9.99% Near-Term Projected 30-Year Treasury [8] 3.43% 0.631 10.39% 11.12% 9.99% 10.45% Mean 9.76% 10.22% -Average Bloomberg Value Line Risk-Free Beta Market DCF Market DCF Bloomberg Value Line Rate Coefficient Derived Derived MRP MRP PROXY GROUP AVERAGE VALUE LINE AVERAGE BETA COEFFICIENT Current 30-Year Treasury [7] 2.97% 0.756 10.39% 11.12% 10.83% 11.38% Near-Term Projected 30-Year Treasury [8] 3.43% 0.756 10.39% 11.12% 11.29% 11.84% Mean 11.06% 11.61% Notes: [1] See Notes [7} and [8] [2] Source: Attachment RBH-6 [3] Source: Attachment RBH-5 [4] Source: Attachment RBH-5 [5] Equals Col. [1] +(Col. [2] x Col. [3]) [6] Equals Col. [1] +(Col. [2] x Col. [4]) [7] Source: Bloomberg Professional [8] Source: Blue Chip Financial Forecasts, Vol. 36, No. 5, May 1, 2017, at 2. Attachment RBH-8 Page 1 of17 Bond Yield Plus Risk Premium [1] [2] [3] [4] [5] 30-Year Treasury Risk Return on Constant Slope Yield Premium Equity -2.85% -2.79% Current 30-Year Treasury 2.97% 6.96% 9.93% Near-Term Projected 30-Year Treasury 3.43% 6.55% 9.99% Long-Term Projected 30-Year Treasury 4.35% 5.89% 10.24% 10.00% ~------ § l i 2.00% ~ 0.00% f------~"---.!l>"0'---- " 0.0 % 2.00% 4.00% 6.00% 8.00% 10.00% 12.00% 14.00% 16.00% ill" -2.00% ,______ -4.00% ~------.. ------Treasury Yield Notes: [1] Constant of regression equation [2] Slope of regression equation [3] Source: Current= Bloomberg Professional, Near Term Projected = Blue Chip Financial Forecasts, Vol. 36, No. 5, May 1, 2017, at 2, Long Term Projected= Blue Chip Financial Forecasts, Vol. 35, No. 12, December 1, 2016, at 14. [4] Equals [1] + ln([3]) x [2] [5] Equals [3] + [4] [6] Source: SNL Financial [7] Source: SNL Financial [8] Source: Bloomberg Professional, equals 188-trading day average (i.e. lag period) [9] Equals [7] - [8] Attachment RBH-8 Page 2 of17 Bond Yield Plus Risk Premium [6] [7] [8] [9] .:iu-rear Date of Gas Return on Treasury Risk Rate Case Equity Yield Premium 1/3/1980 12.55% 9.39% 3.16% 1/4/1980 13.75% 9.40% 4.35% 1/14/1980 13.20% 9.44% 3.76% 1/18/1980 14.00% 9.47% 4.53% 1/31/1980 12.61% 9.56% 3.05% 2/8/1980 14.50% 9.63% 4.87% 2114/1980 13.00% 9.67% 3.33% 2115/1980 13.00% 9.69% 3.31% 2129/1980 14.00% 9.85% 4.15% 3/5/1980 14.00% 9.90% 4.10% 3/7/1980 13.50% 9.94% 3.56% 3/14/1980 14.00% 10.03% 3.97% 3/27/1980 12.69% 10.19% 2.50% 4/1/1980 14.75% 10.25% 4.50% 4/29/1980 12.50% 10.50% 2.00% 5/7/1980 14.27% 10.55% 3.72% 5/8/1980 13.75% 10.55% 3.20% 5/19/1980 15.50% 10.61% 4.89% 5/27/1980 14.60% 10.64% 3.96% 5/29/1980 16.00% 10.66% 5.34% 6/10/1980 13.78% 10.70% 3.08% 6/25/1980 14.25% 10.73% 3.52% 7/9/1980 14.51% 10.77% 3.74% 7/17/1980 12.90% 10.78% 2.12% 7/18/1980 13.80% 10.79% 3.01% 7/22/1980 14.10% 10.79% 3.31% 7/23/1980 14.19% 10.79% 3.40% 8/1/1980 12.50% 10.80% 1.70% 8/11/1980 14.85% 10.81% 4.04% 8/21/1980 13.03% 10.84% 2.19% 8/28/1980 13.61% 10.87% 2.74% 8/28/1980 14.00% 10.87% 3.13% 9/4/1980 14.00% 10.89% 3.11% 9/24/1980 15.00% 10.98% 4.02% 10/9/1980 14.50% 11.05% 3.45% 10/9/1980 14.50% 11.05% 3.45% 10/24/1980 14.00% 11.09% 2.91% 10/27/1980 15.20% 11.10% 4.10% 10/27/1980 15.20% 11.10% 4.10% 10/28/1980 12.00% 11.10% 0.90% 10/28/1980 13.00% 11.10% 1.90% 10/31/1980 14.50% 11.12% 3.38% 11/4/1980 15.00% 11.13% 3.87% 11/611980 14.35% 11.13% 3.22% 11/10/1980 13.25% 11.14% 2.11% 11/17/1980 15.50% 11.15% 4.35% 11/19/1980 13.50% 11.15% 2.35% 12/5/1980 14.60% 11.14% 3.46% 12/811980 16.40% 11.14% 5.26% 1211211980 15.45% 11.15% 4.30% 12/17/1980 14.20% 11.16% 3.04% 12/17/1980 14.40% 11.16% 3.24% 12/18/1980 14.00% 11.17% 2.83% 12/2211980 13.45% 11.16% 2.29% 12/26/1980 14.00% 11.15% 2.85% 12/30/1980 14.50% 11.15% 3.35% 12/3111980 14.56% 11.15% 3.41% 11711981 14.30% 11.14% 3.16% 1/1211981 14.95% 11.14% 3.81% 1/26/1981 15.25% 11.20% 4.05% 1/30/1981 13.25% 11.23% 2.02% 2/11/1981 14.50% 11.33% 3.17% 2120/1981 14.50% 11.39% 3.11% 3/12/1981 15.65% 11.59% 4.06% 3/25/1981 15.30% 11.73% 3.57% 4/1/1981 15.30% 11.81% 3.49% 4/9/1981 15.00% 11.90% 3.10% 4/29/1981 13.50% 12.11% 1.39% 4/29/1981 14.25% 12.11% 2.14% 4/30/1981 13.60% 12.13% 1.47% Attachment RBH-8 Page 3 of17 Bond Yield Plus Risk Premium [6] [7] [8] [9] ,jU-Year Date of Gas Return on Treasury Risk Rate Case Equity Yield Premium 4/30/1981 15.00% 12.13% 2.87% 5/21/1981 14.00"/o 12.37% 1.63% 6/3/1981 14.67% 12.45% 2.22% 6/2211981 16.00% 12.57% 3.43% 6/25/1981 14.75% 12.59% 2.16% 7/2/1981 14.00% 12.64% 1.36% 7/10/1981 16.00% 12.68% 3.32% 7/14/1981 16.90% 12.71% 4.19% 7/2111981 15.78% 12.77% 3.01% 7/27/1981 13.77% 12.82% 0.95% 7/27/1981 15.50% 12.82% 2.68% 7/31/1981 13.50% 12.86% 0.64% 7/31/1981 14.20% 12.86% 1.34% 8/1211981 13.72% 12.93% 0.79% 8/1211981 13.72% 12.93% 0.79% 8/12/1981 14.41% 12.93% 1.48% 8/25/1981 15.45% 13.01% 2.44% 8/27/1981 14.43% 13.04% 1.39% 8/28/1981 15.00% 13.05% 1.95% 9/23/1981 14.34% 13.23% 1.11% 9/24/1981 16.25% 13.25% 3.00% 9/29/1981 14.50% 13.30% 1.20% 9/30/1981 15.94% 13.32% 2.62% 10/211981 14.80% 13.35% 1.45% 10/1211981 16.25% 13.42% 2.83% 10/2011981 15.25% 13.49% 1.76% 10/2011981 16.50% 13.49% 3.01% 10/2011981 17.00% 13.49% 3.51% 1012311981 15.50% 13.53% 1.97% 10/26/1981 13.50% 13.55% -0.05% 10/29/1981 16.50% 13.59% 2.91% 11/4/1981 15.33% 13.62% 1.71% 1116/1981 15.17% 13.63% 1.54% 11/1211981 15.00% 13.64% 1.36% 11125/1981 15.25% 13.66% 1.59% 11/25/1981 16.10% 13.66% 2.44% 11125/1981 16.10% 13.66% 2.44% 11130/1981 16.75% 13.65% 3.10% 12/111981 15.70% 13.65% 2.05% 12/111981 16.00% 13.65% 2.35% 12115/1981 15.81% 13.68% 2.13% 12117/1981 14.75% 13.70% 1.05% 1212211981 15.70% 13.71% 1.99% 1212211981 16.00% 13.71% 2.29% 1213011981 16.00% 13.74% 2.26% 1213011981 16.25% 13.74% 2.51% 114/1982 15.50% 13.74% 1.76% 111411982 11.95% 13.80% -1.85% 1/25/1982 16.25% 13.84% 2.41% 112711982 16.84% 13.85% 2.99% 1/31/1982 14.00% 13.85% 0.15% 2/211982 16.24% 13.86% 2.38% 2/811982 15.50% 13.87% 1.63% 2/911982 14.95% 13.88% 1.07% 2/911982 15.75% 13.88% 1.87% 2/11/1982 16.00% 13.89% 2.11% 3/1/1982 15.96% 13.91% 2.05% 313/1982 15.00% 13.91% 1.09% 318/1982 17.10% 13.91% 3.19% 3/2611982 16.00% 13.96% 2.04% 3/3111982 16.25% 13.97% 2.28% 4/1/1982 16.50% 13.98% 2.52% 4/611982 15.00% 13.98% 1.02% 4/911982 16.50% 13.99% 2.51% 411211982 15.10% 13.98% 1.12% 411211982 16.70% 13.98% 2.72% 4118/1982 14.70% 13.98% 0.72% 4/27/1982 15.00% 13.97% 1.03% 511011982 14.57% 13.94% 0.63% 511411982 15.80% 13.92% 1.88% Attachment RBH-8 Page 4 ofl7 Bond Yield Plus Risk Premium [6] [7] [8] [9] 6U-Year Date of Gas Return on Treasury Risk Rate Case Equity Yield Premium 5/20/1982 15.82% 13.91% 1.91% 512111982 15.50% 13.90% 1.60% 512511982 16.25% 13.90% 2.35% 6/211982 14.50% 13.87% 0.63% 61711982 16.00% 13.86% 2.14% 6123/1982 15.50% 13.81% 1.69% 6/25/1982 16.50% 13.81% 2.69% 7/111982 15.55% 13.80% 1.75% 7/1/1982 16.00% 13.80% 2.20% 7/2/1982 15.10% 13.79% 1.31% 7113/1982 16.80% 13.76% 3.04% 7/22/1982 14.50% 13.72% 0.78% 7/28/1982 16.10% 13.69% 2.41% 7/30/1982 14.82% 13.67% 1.15% 8/4/1982 15.58% 13.65% 1.93% 8/6/1982 16.50% 13.63% 2.87% 8/11/1982 17.11% 13.62% 3.49% 8/25/1982 16.00% 13.58% 2.42% 8/30/1982 16.25% 13.58% 2.67% 9/3/1982 15.50% 13.56% 1.94% 9/9/1982 16.04% 13.55% 2.49% 9/15/1982 16.04% 13.52% 2.52% 9/17/1982 15.25% 13.51% 1.74% 9/29/1982 14.50% 13.43% 1.07% 9/30/1982 14.74% 13.42% 1.32% 9/30/1982 15.50% 13.42% 2.08% 9/30/1982 16.50% 13.42% 3.08% 9/30/1982 16.70% 13.42% 3.28% 10/1/1982 16.50% 13.41% 3.09% 10/8/1982 15.00% 13.34% 1.66% 10/15/1982 15.90% 13.26% 2.64% 10/19/1982 15.90% 13.23% 2.67% 10/27/1982 17.00% 13.13% 3.87% 10/28/1982 14.75% 13.11% 1.64% 11/2/1982 16.25% 13.08% 3.17% 11/4/1982 15.75% 13.04% 2.71% 11/5/1982 14.73% 13.02% 1.71% 11/17/1982 16.00% 12.87% 3.13% 11/23/1982 15.50% 12.79% 2.71% 11/24/1982 14.50% 12.78% 1.72% 11/24/1982 16.02% 12.78% 3.24% 11/30/1982 12.98% 12.73% 0.25% 11/30/1982 15.50% 12.73% 2.77% 11/30/1982 15.50% 12.73% 2.77% 11/30/1982 15.65% 12.73% 2.92% 11/30/1982 16.00% 12.73% 3.27% 11/30/1982 16.10% 12.73% 3.37% 12/3/1982 15.33% 12.68% 2.65% 12/8/1982 15.75% 12.64% 3.11% 12113/1982 16.00% 12.59% 3.41% 12114/1982 16.40% 12.57% 3.83% 1211711982 16.25% 12.53% 3.72% 12120/1982 15.00% 12.51% 2.49% 12121/1982 15.70% 12.50% 3.20% 12/28/1982 15.25% 12.43% 2.82% 12/28/1982 15.25% 12.43% 2.82% 12/29/1982 16.25% 12.41% 3.84% 12/29/1982 16.25% 12.41% 3.84% 1/11/1983 15.90% 12.26% 3.64% 1/1211983 15.50% 12.25% 3.25% 1/18/1983 15.00% 12.19% 2.81% 1/24/1983 15.50% 12.14% 3.36% 1/24/1983 16.00% 12.14% 3.86% 1/28/1983 14.90% 12.09% 2.81% 1/31/1983 15.00% 12.07% 2.93% 2/10/1983 15.00% 11.98% 3.02% 2125/1983 15.70% 11.85% 3.85% 312/1983 15.25% 11.80% 3.45% 3/16/1983 16.00% 11.64% 4.36% 3/21/1983 14.96% 11.58% 3.38% Attachment RBH-8 Page 5of17 Bond Yield Plus Risk Premium [6] [7] [BJ [9] Ju-rear Date of Gas Return on Treasury Risk Rate Case Equity Yield Premium 3/23/1983 15.40% 11.54% 3.86% 3/2311983 16.10% 11.54% 4.56% 3/24/1983 15.00% 11.53% 3.47% 4/12/1983 13.25% 11.31% 1.94% 4/29/1983 15.05% 11.11% 3.94% 5/3/1983 15.40% 11.08% 4.32% 5/911983 15.50% 11.01% 4.49% 5/19/1983 14.85% 10.90% 3.95% 5/31/1983 14.00% 10.85% 3.15% 6/2/1983 14.50% 10.83% 3.67% 6/7/1983 14.50% 10.81% 3.69% 6/9/1983 14.85% 10.80% 4.05% 6/20/1983 14.15% 10.74% 3.41% 6/20/1983 16.50% 10.74% 5.76% 6/27/1983 14.50% 10.72% 3.78% 6/30/1983 14.80% 10.71% 4.09% 6/30/1983 15.90% 10.71% 5.19% 7/1/1983 14.80% 10.70% 4.10% 7/5/1983 15.00% 10.70% 4.30% 7/8/1983 15.50% 10.69% 4.81% 7/19/1983 15.00% 10.71% 4.29% 7/19/1983 15.10% 10.71% 4.39% 8/18/1983 15.30% 10.81% 4.49% 8/19/1983 15.79% 10.82% 4.97% 8/29/1983 16.00% 10.85% 5.15% 8/31/1983 14.75% 10.86% 3.89% 8/31/1983 15.25% 10.86% 4.39% 9/8/1983 14.75% 10.89% 3.86% 9/16/1983 15.51% 10.93% 4.58% 9/26/1983 14.50% 10.96% 3.54% 9/28/1983 14.25% 10.97% 3.28% 9/30/1983 16.15% 10.98% 5.17% 9/30/1983 16.25% 10.98% 5.27% 10/1/1983 16.25% 10.98% 5.27% 10/13/1983 15.52% 11.02% 4.50% 10/19/1983 15.20% 11.04% 4.16% 10/26/1983 14.75% 11.06% 3.69% 10/27/1983 14.88% 11.07% 3.81% 10/27/1983 15.33% 11.07% 4.26% 11/9/1983 14.82% 11.10% 3.72% 11/9/1983 16.51% 11.10% 5.41% 11/9/1983 16.51% 11.10% 5.41% 12/1/1983 14.50% 11.17% 3.33% 12/8/1983 15.90% 11.20% 4.70% 12/9/1983 15.30% 11.21% 4.09% 12/1211983 14.50% 11.21% 3.29% 12/1211983 15.50% 11.21% 4.29% 12/20/1983 15.40% 11.26% 4.14% 12120/1983 16.00% 11.26% 4.74% 12/2211983 15.75% 11.27% 4.48% 12/29/1983 15.00% 11.29% 3.71% 12130/1983 15.00% 11.30% 3.70% 1/10/1984 15.90% 11.34% 4.56% 1/13/1984 15.50% 11.36% 4.14% 1/18/1984 1'5.53% 11.38% 4.15% 1/26/1984 15.90% 11.41% 4.49% 2114/1984 14.25% 11.50% 2.75% 2128/1984 14.50% 11.58% 2.92% 3/20/1984 16.00% 11.69% 4.31% 3/23/1984 15.50% 11.72% 3.78% 4/9/1984 15.20% 11.81% 3.39% 4/18/1984 16.20% 11.85% 4.35% 4/27/1984 15.85% 11.90% 3.95% 5/15/1984 13.35% 11.99% 1.36% 5/16/1984 15.00% 12.00% 3.00% 5/2211984 14.40% 12.03% 2.37% 6/13/1984 15.50% 12.18% 3.32% 7/10/1984 16.00% 12.36% 3.64% 81711984 16.69% 12.50% 4.19% 8/9/1984 15.33% 12.51% 2.82% Attachment RBH-8 Page 6 ofl7 Bond Yield Plus Risk Premium [6] [7] [8] [9] .:iu-Tear Date of Gas Return on Treasury Risk Rate Case Equity Yield Premium 8/17/1984 14.82% 12.53% 2.29% 8/2111984 14.64% 12.54% 2.10% 8/27/1984 14.52% 12.56% 1.96% 8/28/1984 14.75% 12.56% 2.19% 8/30/1984 15.60% 12.57% 3.03% 9/12/1984 15.60% 12.60% 3.00% 9/1211984 15.90% 12.60% 3.30% 9/25/1984 16.25%. 12.61% 3.64% 1012/1984 14.80% 12.62% 2.18% 10/9/1984 14.75% 12.63% 2.12% 10/10/1984 15.50% 12.63% 2.87% 10/18/1984 15.00% 12.64% 2.36% 10/24/1984 15.50% 12.64% 2.86% 11/7/1984 15.00% 12.64% 2.36% 11/20/1984 15.92% 12.62% 3.30% 11/30/1984 15.50% 12.60% 2.90% 12/18/1984 15.00% 12.55% 2.45% 12120/1984 15.00% 12.53% 2.47% 12/28/1984 15.75% 12.51% 3.24% 12/28/1984 16.25% 12.51% 3.74% 1/2/1985 16.00% 12.50% 3.50% 1/31/1985 14.75% 12.37% 2.38% 2/7/1985 14.85% 12.33% 2.52% 2115/1985 15.00% 12.28% 2.72% 2120/1985 14.50% 12.26% 2.24% 212211985 14.86% 12.26% 2.60% 3/14/1985 15.50% 12.17% 3.33% 3/28/1985 14.80% 12.09% 2.71% 4/9/1985 15.50% 12.03% 3.47% 4/16/1985 15.70% 11.97% 3.73% 6/10/1985 15.75% 11.59% 4.16% 6/26/1985 14.82% 11.47% 3.35% 7/9/1985 15.00% 11.39% 3.61% 7/26/1985 14.50% 11.27% 3.23% 8/29/1985 14.50% 11.12% 3.38% 8/30/1985 14.38% 11.11% 3.27% 9/12/1985 15.25% 11.07% 4.18% 9/23/1985 15.30% 11.04% 4.26% 9/25/1985 14.50% 11.03% 3.47% 9/26/1985 13.80% 11.02% 2.78% 9/26/1985 14.50% 11.02% 3.48% 10/25/1985 15.25% 10.92% 4.33% 11/8/1985 12.94% 10.86% 2.08% 11/20/1985 14.90% 10.81% 4.09% 11/25/1985 13.30% 10.79% 2.51% 12/6/1985 12.00% 10.72% 1.28% 12/11/1985 14.90% 10.69% 4.21% 12/20/1985 14.88% 10.60% 4.28% 12/20/1985 15.00% 10.60% 4.40% 12/20/1985 15.00% 10.60% 4.40% 12/30/1985 15.75% 10.53% 5.22% 12/3111985 14.00% 10.52% 3.48% 12/31/1985 14.50% 10.52% 3.98% 1/17/1986 14.50% 10.38% 4.12% 2/11/1986 12.50% 10.21% 2.29% 2/12/1986 15.20% 10.20% 5.00% 3111/1986 14.00% 9.98% 4.02% 41211986 12.90% 9.77% 3.13% 412811986 13.01% 9.47% 3.54% 5/21/1986 13.25% 9.19% 4.06% 5/28/1986 14.00% 9.12% 4.88% 5/29/1986 13.90% 9.11% 4.79% 612/1986 13.00% 9.08% 3.92% 6/1111986 14.00% 8.98% 5.02% 6/1311986 13.55% 8.95% 4.60% 6/2711986 11.88% 8.78% 3.10% 7/1411986 12.60% 8.60% 4.00% 7/30/1986 13.30% 8.39% 4.91% 8/1411986 13.50% 8.23% 5.27% 9/5/1986 13.30% 8.03% 5.27% Attachment RBH-8 Page 7of17 Bond Yield Plus Risk Premium [6] [7] [8] [9] .jU-r ear Date of Gas Return on Treasury Risk Rate Case Equity Yield Premium 9/23/1986 12.75% 7.91% 4.84% 10/30/1986 13.00% 7.68% 5.32% 10/31/1986 13.75% 7.67% 6.08% 11/10/1986 14.00% 7.62% 6.38% 11/19/1986 13.75% 7.57% 6.18% 11/25/1986 13.15% 7.54% 5.61% 12122/1986 13.80% 7.48% 6.32% 12130/1986 13.90% 7.47% 6.43% 1/20/1987 12.75% 7.47% 5.28% 1/23/1987 13.55% 7.47% 6.08% 1/27/1987 12.16% 7.47% 4.69% 2113/1987 12.60% 7.47% 5.13% 2/24/1987 12.00% 7.47% 4.53% 3/30/1987 12.20% 7.46% 4.74% 3/31/1987 13.00% 7.46% 5.54% 5/511987 12.85% 7.60% 5.25% 5/28/1987 13.50% 7.72% 5.78% 6/15/1987 13.20% 7.80% 5.40% 6/30/1987 12.60% 7.85% 4.75% 7/10/1987 12.90% 7.88% 5.02% 7/27/1987 13.50% 7.93% 5.57% 8/25/1987 11.40% 8.08% 3.32% 9/18/1987 13.00% 8.27% 4.73% 10/20/1987 12.60% 8.54% 4.06% 10/20/1987 12.98% 8.54% 4.44% 11/1211987 12.75% 8.67% 4.08% 11/13/1987 12.75% 8.68% 4.07% 11/24/1987 12.50% 8.73% 3.77% 1218/1987 12.50% 8.81% 3.69% 12/2211987 12.00% 8.90% 3.10% 12/31/1987 12.85% 8.93% 3.92% 12/3111987 13.25% 8.93% 4.32% 1/15/1988 13.15% 8.98% 4.17% 1/20/1988 12.75% 8.99% 3.76% 1/29/1988 13.20% 8.99% 4.21% 2/4/1988 12.60% 8.99% 3.61% 3/23/1988 13.00% 8.94% 4.06% 5/27/1988 13.18% 9.02% 4.16% 6/14/1988 13.50% 9.00% 4.50% 6/17/1988 11.72% 8.99% 2.73% 6/24/1988 11.50% 8.97% 2.53% 711/1988 12.75% 8.95% 3.80% 7/8/1988 12.00% 8.94% 3.06% 7/18/1988 12.00% 8.91% 3.09% 7/20/1988 13.40% 8.90% 4.50% 8/8/1988 12.74% 8.90% 3.84% 9/20/1988 12.90% 8.93% 3.97% 9/26/1988 12.40% 8.93% 3.47% 9/27/1988 13.65% 8.93% 4.72% 9/30/1988 13.25% 8.94% 4.31% 10/13/1988 13.10% 8.93% 4.17% 10/21/1988 12.80% 8.93% 3.87% 10/25/1988 13.25% 8.94% 4.31% 10/26/1988 13.50% 8.94% 4.56% 10/27/1988 12.95% 8.94% 4.01% 10/28/1988 13.00% 8.94% 4.06% 11/15/1988 12.00% 8.97% 3.03% 11/29/1988 12.75% 9.01% 3.74% 12/19/1988 13.00% 9.05% 3.95% 12/21/1988 12.90% 9.05% 3.85% 12/22/1988 13.50% 9.05% 4.45% 1/26/1989 12.60% 9.06% 3.54% 1/27/1989 13.00% 9.06% 3.94% 2/8/1989 13.37% 9.05% 4.32% 3/8/1989 13.00% 9.04% 3.96% 5/4/1989 13.00% 9.04% 3.96% 6/8/1989 13.50% 8.96% 4.54% 7/19/1989 11.80% 8.84% 2.96% 7/25/1989 12.80% 8.82% 3.98% 7/31/1989 13.00% 8.80% 4.20% Attachment RBH-8 Page 8 of17 Bond Yield Plus Risk Premium [6] [7] [8] [9] -'V·Tear Date of Gas Return on Treasury Risk Rate Case Equity Yield Premium 8/14/1989 12.50% 8.76% 3.74% 8/22/1989 12.80% 8.73% 4.07% 8/23/1989 12.90% 8.73% 4.17% 9/21/1989 12.10% 8.63% 3.47% 1016/1989 13.00% 8.58% 4.42% 10/17/1989 12.41% 8.54% 3.87% 10/18/1989 13.25% 8.54% 4.71% 10/20/1989 12.90% 8.53% 4.37% 10/31/1989 13.60% 8.50% 5.10% 11/3/1989 12.93% 8.48% 4.45% 1115/1989 13.20% 8.48% 4.72% 11/9/1989 12.60% 8.46% 4.14% 1119/1989 13.00% 8.46% 4.54% 11/28/1989 12.75% 8.37% 4.38% 1217/1989 13.25% 8.33% 4.92% 12115/1989 13.00% 8.28% 4.72% 12120/1989 12.90% 8.26% 4.64% 12/21/1989 12.80% 8.26% 4.54% 12121/1989 12.90% 8.26% 4.64% 12/27/1989 12.50% 8.24% 4.26% 1/9/1990 13.00% 8.19% 4.81% 1/18/1990 12.50% 8.17% 4.33% 1/26/1990 12.10% 8.15% 3.95% 3/21/1990 12.80% 8.15% 4.65% 3/28/1990 13.00% 8.16% 4.84% 4/5/1990 12.20% 8.17% 4.03% 4/12/1990 13.25% 8.19% 5.06% 4/30/1990 12.45% 8.24% 4.21% 5/31/1990 12.40% 8.31% 4.09% 6/15/1990 13.20% 8.33% 4.87% 6/27/1990 12.90% 8.34% 4.56% 6/29/1990 13.25% 8.34% 4.91% 7/6/1990 12.10% 8.35% 3.75% 7/19/1990 11.70% 8.38% 3.32% 8/31/1990 12.50% 8.52% 3.98% 8/31/1990 12.50% 8.52% 3.98% 9/13/1990 12.50% 8.58% 3.92% 9/18/1990 12.75% 8.60% 4.15% 9/20/1990 12.50% 8.61% 3.89% 10/2/1990 13.00% 8.65% 4.35% 10/1711990 11.90% 8.68% 3.22% 10/31/1990 12.95% 8.70% 4.25% 11/9/1990 13.25% 8.70% 4.55% 11/19/1990 13.00% 8.70% 4.30% 11/21/1990 12.10% 8.70% 3.40% 11/21/1990 12.50% 8.70% 3.80% 11128/1990 12.75% 8.70% 4.05% 11129/1990 12.75% 8.70% 4.05% 12118/1990 13.10% 8.68% 4.42% 12/20/1990 12.50% 8.67% 3.83% 12121/1990 12.50% B.67% 3.83% 12(21/1990 13.00% 8.67% 4.33% 12121/1990 13.60% 8.67% 4.93% 1/3/1991 13.02% 8.66% 4.36% 1/16/1991 13.25% B.64% 4.61% 1/25/1991 11.70% 8.61% 3.09% 2115/1991 12.70% 8.56% 4.14% 2115/1991 12.80% 8.56% 4.24% 4/3/1991 13.00% 8.51% 4.49% 4/30/1991 12.45% 8.48% 3.97% 4/30/1991 13.00% 8.48% 4.52% 6/25/1991 11.70% 8.35% 3.35% 6/28/1991 12.50% 8.34% 4.16% 7/111991 11.70% 8.34% 3.36% 7/19/1991 12.10% 8.31% 3.79% 7/19/1991 12.30% 8.31% 3.99% 7/22/1991 12.90% 8.31% 4.59% 8/15/1991 12.25% 8.28% 3.97% 8/29/1991 13.30% 8.26% 5.04% 9/27/1991 12.50% 8.23% 4.27% Attachment RBH-8 Page 9 of17 Bond Yield Plus Risk Premium [6] [7] [8] [9] .1U-Year Date of Gas Return on Treasury Risk Rate Case Equity Yield Premium 9/30/1991 12.40% 8.23% 4.17% 10/3/1991 11.30% 8.22% 3.08% 10/9/1991 11.70% 8.21% 3.49% 10/15/1991 13.40% 8.20% 5.20% 11/1/1991 12.90% 8.20% 4.70% 11/8/1991 12.75% 8.20% 4.55% 11/26/1991 11.60% 8.18% 3.42% 11/26/1991 12.00% 8.18% 3.82% 11/27/1991 12.70% 8.18% 4.52% 12/6/1991 12.70% 8.16% 4.54% 12110/1991 11.75% 8.16% 3.59% 12/19/1991 12.60% 8.14% 4.46% 12/19/1991 12.80% 8.14% 4.66% 12130/1991 12.10% 8.11% 3.99% 1/22/1992 12.84% 8.05% 4.79% 1/31/1992 12.00% 8.03% 3.97% 2/20/1992 13.00% 8.00% 5.00% 2/27/1992 11.75% 7.99% 3.76% 3/18/1992 12.50% 7.95% 4.55% 5/15/1992 12.75% 7.87% 4.88% 6/24/1992 12.20% 7.85% 4.35% 6/29/1992 11.00% 7.85% 3.15% 7/14/1992 12.00% 7.83% 4.17% 7/22/1992 11.20% 7.82% 3.38% 8/10/1992 12.10% 7.79% 4.31% 8/26/1992 12.43% 7.75% 4.68% 9/30/1992 11.60% 7.72% 3.88% 10/6/1992 12.25% 7.72% 4.53% 10/13/1992 12.75% 7.71% 5.04% 10/23/1992 11.65% 7.71% 3.94% 10/28/1992 12.25% 7.71% 4.54% 10/29/1992 12.75% 7.71% 5.04% 10/30/1992 11.40% 7.70% 3.70% 11/9/1992 10.60% 7.70% 2.90% 11/25/1992 11.00% 7.68% 3.32% 11/25/1992 12.00% 7.68% 4.32% 12/3/1992 11.85% 7.67% 4.18% 12/16/1992 11.90% 7.64% 4.26% 12/2211992 12.30% 7.63% 4.67% 12/22/1992 12.40% 7.63% 4.77% 12/30/1992 12.00% 7.61% 4.39% 12/31/1992 12.00% 7.61% 4.39% 1/12/1993 12.00% 7.59% 4.41% 1/12/1993 12.00% 7.59% 4.41% 2/2/1993 11.40% 7.53% 3.87% 2/22/1993 11.60% 7.48% 4.12% 4/23/1993 11.75% 7.27% 4.48% 5/3/1993 11.50% 7.25% 4.25% 5/3/1993 11.75% 7.25% 4.50% 6/3/1993 12.00% 7.20% 4.80% 6/7/1993 11.50% 7.20% 4.30% 6/22/1993 11.75% 7.16% 4.59% 7/21/1993 11.78% 7.07% 4.71% 7121/1993 11.90% 7.07% 4.83% 7/23/1993 11.50% 7.06% 4.44% 7/29/1993 11.50% 7.03% 4.47% 8/12/1993 10.75% 6.98% 3.77% B/24/1993 11.50% 6.92% 4.58% 8131/1993 11.90% 6.88% 5.02% 9/111993 11.25% 6.88% 4.37% 9/1/1993 11.47% 6.88% 4.59% 9/27/1993 10.50% 6.74% 3.76% 9/29/1993 11.00% 6.73% 4.27% 9/30/1993 11.60% 6.72% 4.88% 10/811993 11.50% 6.68% 4.82% 10114/1993 11.20% 6.65% 4.55% 10/15/1993 11.75% 6.65% 5.10% 10125/1993 11.55% 6.60% 4.95% 10128/1993 11.50% 6.58% 4.92% 10/29/1993 10.10% 6.58% 3.52% Attachment RBH-8 Page 10 of17 Bond Yield Plus Risk Premium [6] [7] [8] [9] .;)V-rear Date of Gas Return on Treasury Risk Rate Case Equity Yield Premium 10129/1993 10.20% 6.58% 3.62% 1012911993 11.25% 6.58% 4.67% 11/2/1993 10.80% 6.56% 4.24% 11/1211993 11.80% 6.53% 5.27% 11123/1993 12.50% 6.51% 5.99% 1112611993 11.00% 6.50% 4.50% 12/111993 11.45% 6.49% 4.96% 12/16/1993 10.60% 6.46% 4.14% 12116/1993 11.20% 6.46% 4.74% 12121/1993 11.30% 6.45% 4.85% 12/2211993 11.00% 6.44% 4.56% 12/23/1993 10.10% 6.44% 3.66% 1/5/1994 11.50% 6.41% 5.09% 1/10/1994 11.00% 6.40% 4.60% 112511994 12.00% 6.37% 5.63% 21211994 10.40% 6.35% 4.05% 2/9/1994 10.70% 6.34% 4.36% 4/6/1994 11.24% 6.35% 4.89% 4/25/1994 11.00% 6.39% 4.61% 6/1611994 10.50% 6.63% 3.87% 6/23/1994 10.60% 6.67% 3.93% 7/1911994 10.70% 6.83% 3.87% 9/29/1994 10.90% 7.20% 3.70% 9/29/1994 11.00% 7.20% 3.80% 101711994 11.87% 7.25% 4.62% 10118/1994 11.50% 7.31% 4.19% 10118/1994 11.50% 7.31% 4.19% 10124/1994 11.00% 7.35% 3.65% 11/2211994 12.12% 7.52% 4.60% 11/29/1994 11.30% 7.55% 3.75% 12/1/1994 11.00% 7.56% 3.44% 12/8/1994 11.50% 7.59% 3.91% 1218/1994 11.70% 7.59% 4.11% 1211211994 11.82% 7.60% 4.22% 12/14/1994 11.50% 7.61% 3.89% 1211911994 11.50% 7.62% 3.88% 4/19/1995 11.00% 7.71% 3.29% 9/11/1995 11.30% 7.16% 4.14% 9/15/1995 10.40% 7.13% 3.27% 9/29/1995 11.50% 7.06% 4.44% 10/13/1995 10.76% 6.99% 3.77% 111711995 12.50% 6.87% 5.63% 11/811995 11.10% 6.86% 4.24% 11/8/1995 11.30% 6.86% 4.44% 1111711995 10.90% 6.81% 4.09% 1112011995 11.40% 6.80% 4.60% 11/27/1995 13.60% 6.77% 6.83% 12/1411995 11.30% 6.68% 4.62% 12/20/1995 11.60% 6.65% 4.95% 113111996 11.30% 6.46% 4.84% 311111996 11.60% 6.40% 5.20% 4/3/1996 11.13% 6.41% 4.72% 4/1511996 10.50% 6.41% 4.09% 411711996 10.77% 6.41% 4.36% 4/2611996 10.60% 6.40% 4.20% 5/10/1996 11.00% 6.41% 4.59% 5/13/1996 11.25% 6.41% 4.84% 713/1996 11.25% 6.49% 4.76% 7122/1996 11.25% 6.54% 4.71% 1013/1996 10.00% 6.77% 3.23% 10/29/1996 11.30% 6.84% 4.46% 11/26/1996 11.30% 6.86% 4.44% 11/27/1996 11.30% 6.86% 4.44% 11/29/1996 11.00% 6.85% 4.15% 1211211996 11.96% 6.85% 5.11% 1211711996 11.50% 6.85% 4.65% 1/2211997 11.30% 6.83% 4.47% 1/27/1997 11.25% 6.83% 4.42% 1/31/1997 11.25% 6.83% 4.42% 2113/1997 11.00% 6.82% 4.18% Attachment RBH-8 Page 11 of17 Bond Yield Plus Risk Premium [6] [7] [8] [9] .ju-rear Date of Gas Return on Treasury Risk Rate Case Equity Yield Premium 2/13/1997 11.80% 6.82% 4.98% 2/20/1997 11.80% 6.81% 4.99% 3/27/1997 10.75% 6.79% 3.96% 4/29/1997 11.70% 6.80% 4.90% 7/17/1997 12.00% 6.77% 5.23% 10/2911997 10.75% 6.70% 4.05% 10/3111997 11.25% 6.70% 4.55% 12/24/1997 10.75% 6.53% 4.22% 4/28/1998 10.90% 6.11% 4.79% 4/30/1998 12.20% 6.10% 6.10% 6/30/1998 11.00% 5.94% 5.06% 8/26/1998 10.93% 5.82% 5.11% 9/3/1998 11.40% 5.80% 5.60% 9/15/1998 11.90% 5.77% 6.13% 10/7/1998 11.06% 5.70% 5.36% 10/30/1998 11.40% 5.63% 5.77% 12/1011998 12.20% 5.52% 6.68% 12/1711998 12.10% 5.49% 6.61% 2119/1999 11.15% 5.32% 5.83% 311/1999 10.65% 5.31% 5.34% 3/1/1999 10.65% 5.31% 5.34% 618/1999 11.25% 5.35% 5.90% 11112/1999 10.25% 5.92% 4.33% 12/14/1999 10.50% 5.99% 4.51% 1/28/2000 10.71% 6.16% 4.55% 2/17/2000 10.60% 6.20% 4.40% 5/25/2000 10.80% 6.19% 4.61% 6/19/2000 11.05% 6.18% 4.87% 6/22/2000 11.25% 6.18% 5.07% 7/17/2000 11.06% 6.15% 4.91% 712012000 12.20% 6.14% 6.06% 811112000 11.00% 6.11% 4.89% 912712000 11.25% 6.01% 5.24% 9/29/2000 11.16% 6.00% 5.16% 10/5/2000 11.30% 5.98% 5.32% 11/28/2000 12.90% 5.87% 7.03% 11/30/2000 12.10% 5.87% 6.23% 2/5/2001 11.50% 5.76% 5.74% 3/15/2001 11.25% 5.67% 5.58% 5/8/2001 10.75% 5.61% 5.14% 10/2412001 10.30% 5.54% 4.76% 10/2412001 11.00% 5.54% 5.46% 11912002 10.00% 5.50% 4.50% 1/30/2002 11.00% 5.47% 5.53% 1/31/2002 11.00% 5.47% 5.53% 4/17/2002 11.50% 5.44% 6.06% 412912002 11.00% 5.45% 5.55% 6/11/2002 11.77% 5.48% 6.29% 6/20/2002 12.30% 5.47% 6.83% 8/28/2002 11.00% 5.49% 5.51% 9/11/2002 11.20% 5.45% 5.75% 9/1212002 12.30% 5.45% 6.85% 10/28/2002 11.30% 5.35% 5.95% 10130/2002 10.60% 5.34% 5.26% 11/112002 12.60% 5.34% 7.26% 11/712002 11.40% 5.33% 6.07% 11/8/2002 10.75% 5.33% 5.42% 11/20/2002 10.00% 5.30% 4.70% 11/20/2002 10.50% 5.30% 5.20% 1214/2002 10.75% 5.27% 5.48% 12/30/2002 11.20% 5.19% 6.01% 1/6/2003 11.25% 5.17% 6.08% 2/28/2003 12.30% 5.01% 7.29% 3/7/2003 9.96% 4.99% 4.97% 311212003 11.40% 4.97% 6.43% 3/20/2003 12.00% 4.95% 7.05% 4/312003 12.00% 4.93% 7.07% 5/212003 11.40% 4.88% 6.52% 5/15/2003 11.05% 4.87% 6.18% 6/26/2003 11.00% 4.80% 6.20% Attachment RBH-8 Page 12 of17 Bond Yield Plus Risk Premium [6] [7] [8] [9] 6u-rear Date of Gas Return on Treasury Risk Rate Case Equity Yield Premium 7/1/2003 11.00% 4.80% 6.20% 712912003 11.71% 4.78% 6.93% 8/2212003 10.20% 4.82% 5.38% 9/17(2003 9.90% 4.84% 5.06% 9/25/2003 10.25% 4.85% 5.40% 10/17/2003 10.54% 4.87% 5.67% 1012212003 10.46% 4.87% 5.59% 10/2212003 10.71% 4.87% 5.84% 10130(2003 11.00% 4.88% 6.12% 10(31/2003 10.20% 4.88% 5.32% 10/31/2003 10.75% 4.88% 5.87% 11/10/2003 10.60% 4.89% 5.71% 12/9/2003 10.50% 4.93% 5.57% 12/18/2003 10.50% 4.94% 5.56% 12/19/2003 12.00% 4.94% 7.06% 12/19/2003 12.00% 4.94% 7.06% 1/1312004 10.25% 4.95% 5.30% 111312004 12.00% 4.95% 7.05% 2/9/2004 11.25% 4.98% 6.27% 3/16/2004 10.90% 5.05% 5.85% 3/1612004 10.90% 5.05% 5.85% 5/25/2004 10.00% 5.06% 4.94% 6/212004 11.22% 5.07% 6.15% 6/3012004 10.50% 5.10% 5.40% 7/812004 10.00% 5.10% 4.90% 7/2212004 10.25% 5.10% 5.15% 8/26/2004 10.50% 5.10% 5.40% 8/26/2004 10.50% 5.10% 5.40% 9/9/2004 10.40% 5.10% 5.30% 9/2112004 10.50% 5.09% 5.41% 9/27/2004 10.30% 5.09% 5.21% 9/27/2004 10.50% 5.09% 5.41% 10/20/2004 10.20% 5.08% 5.12% 11/30/2004 10.60% 5.08% 5.52% 12/8/2004 9.90% 5.09% 4.81% 1212112004 11.50% 5.09% 6.41% 1212212004 11.50% 5.09% 6.41% 12/28/2004 10.25% 5.09% 5.16% 2118/2005 10.30% 4.95% 5.35% 3/29/2005 11.00% 4.86% 6.14% 411312005 10.60% 4.84% 5.76% 4/2812005 11.00% 4.80% 6.20% 511712005 10.00% 4.77% 5.23% 61812005 10.18% 4.71% 5.47% 6/10/2005 10.90% 4.71% 6.19% 7/6/2005 10.50% 4.65% 5.85% 711912005 11.50% 4.63% 6.87% 811112005 10.40% 4.60% 5.80% 9/19/2005 9.45% 4.53% 4.92% 913012005 10.51% 4.52% 5.99% 10/412005 9.90% 4.52% 5.38% 10/412005 10.75% 4.52% 6.23% 10114/2005 10.40% 4.52% 5.88% 10131/2005 10.25% 4.53% 5.72% 111212005 9.70% 4.53% 5.17% 11/30/2005 10.00% 4.54% 5.46% 12/912005 9.70% 4.53% 5.17% 12/1212005 11.00% 4.53% 6.47% 1212012005 10.13% 4.53% 5.60% 1212112005 10.40% 4.53% 5.87% 1212112005 11.00% 4.53% 6.47% 12/2212005 10.20% 4.53% 5.67% 1212212005 11.00% 4.53% 6.47% 12/28/2005 10.00% 4.52% 5.48% 1/512006 11.00% 4.52% 6.48% 112512006 11.20% 4.52% 6.68% 112512006 11.20% 4.52% 6.68% 2/312006 10.50% 4.52% 5.98% 2115/2006 9.50% 4.53% 4.97% 4/26/2006 10.60% 4.65% 5.95% Attachment RBH-8 Page 13 of17 Bond Yield Plus Risk Premium [6] [7] [8] [9] .;iu-rear Date of Gas Return on Treasury Risk Rate Case Equity Yield Premium 7/24/2006 9.60% 4.86% 4.74% 712412006 10.00% 4.86% 5.14% 9/20/2006 11.00% 4.93% 6.07% 9/26/2006 10.75% 4.93% 5.82% 10/20/2006 9.80% 4.96% 4.84% 11/2/2006 9.71% 4.96% 4.75% 11/9/2006 10.00% 4.97% 5.03% 11/21/2006 11.00% 4.98% 6.02% 12/5/2006 10.20% 4.97% 5.23% 1/5/2007 10.40% 4.95% 5.45% 1/9/2007 11.00% 4.94% 6.06% 1/11/2007 10.90% 4.94% 5.96% 1/19/2007 10.80% 4.93% 5.87% 1/26/2007 10.00% 4.92% 5.08% 2/8/2007 10.40% 4.91% 5.49% 3/14/2007 10.10% 4.86% 5.24% 3/20/2007 10.25% 4.85% 5.40% 3/21/2007 11.35% 4.84% 6.51% 3/22/2007 10.50% 4.84% 5.66% 3/29/2007 10.00% 4.83% 5.17% 6/13/2007 10.75% 4.81% 5.94% 6/29/2007 9.53% 4.84% 4.69% 6/29/2007 10.10% 4.84% 5.26% 7/3/2007 10.25% 4.85% 5.40% 7/13/2007 9.50% 4.86% 4.64% 7/24/2007 10.40% 4.87% 5.53% 8/1/2007 10.15% 4.88% 5.27% 8/29/2007 10.50% 4.91% 5.59% 9/10/2007 9.71% 4.91% 4.80% 9/19/2007 10.00% 4.91% 5.09% 9/25/2007 9.70% 4.91% 4.79% 10/8/2007 10.48% 4.92% 5.56% 10/19/2007 10.50% 4.91% 5.59% 10/25/2007 9.65% 4.91% 4.74% 11/15/2007 10.00% 4.89% 5.11% 11/20/2007 9.90% 4.89% 5.01% 11/27/2007 10.00% 4.88% 5.12% 11/29/2007 10.90% 4.88% 6.02% 12/14/2007 10.80% 4.87% 5.93% 12118/2007 10.40% 4.86% 5.54% 12/19/2007 9.80% 4.86% 4.94% 12/19/2007 9.80% 4.86% 4.94% 12/19/2007 10.20% 4.86% 5.34% 12/21/2007 9.10% 4.86% 4.24% 1/812008 10.75% 4.83% 5.92% 1117/2008 10.75% 4.81% 5.94% 1/17/2008 10.75% 4.81% 5.94% 2/512008 9.99% 4.78% 5.21% 2/5/2008 10.19% 4.78% 5.41% 2/13/2008 10.20% 4.76% 5.44% 3/31/2008 10.00% 4.63% 5.37% 5/28/2008 10.50% 4.53% 5.97% 6/24/2008 10.00% 4.52% 5.48% 612712008 10.00% 4.52% 5.48% 7/31/2008 10.70% 4.50% 6.20% 7/31/2008 10.82% 4.50% 6.32% 8/27/2008 10.25% 4.50% 5.75% 9/2/2008 10.25% 4.50% 5.75% 9/19/2008 10.70% 4.48% 6.22% 9/24/2008 10.68% 4.48% 6.20% 9/24/2008 10.68% 4.48% 6.20% 9/24/2008 10.68% 4.48% 6.20% 9/30/2008 10.20% 4.48% 5.72% 10/3/2008 10.30% 4.47% 5.83% 10/8/2008 10.15% 4.47% 5.68% 10/20/2008 10.06% 4.47% 5.59% 10/24/2008 10.60% 4.46% 6.14% 10/24/2008 10.60% 4.46% 6.14% 1112112008 10.50% 4.42% 6.08% 11f21f2008 10.50% 4.42% 6.08% Attachment RBH-8 Page 14of17 Bond Yield Plus Risk Premium [6] [7] [8] [9) .lU-Year Date of Gas Return on Treasury Risk Rate Case Equity Yield Premium 11/21/2008 10.50% 4.42% 6.08% 11/24/2008 10.50% 4.42% 6.08% 12/3/2008 10.39% 4.37% 6.02% 12/24/2008 10.00% 4.26% 5.74% 12126/2008 10.10% 4.24% 5.86% 12/29/2008 10.20% 4.23% 5.97% 1/13/2009 10.45% 4.14% 6.31% 2/2/2009 10.05% 4.04% 6.01% 3/9/2009 10.30% 3.90% 6.40% 3/25/2009 10.17% 3.84% 6.33% 4/2/2009 10.75% 3.81% 6.94% 5/5/2009 10.75% 3.71% 7.04% 5/15/2009 10.20% 3.70% 6.50% 5/29/2009 9.54% 3.70% 5.84% 6/3/2009 10.10% 3.71% 6.39% 6/22/2009 10.00% 3.73% 6.27% 6/29/2009 10.21% 3.74% 6.47% 6/30/2009 9.31% 3.74% 5.57% 7/17/2009 9.26% 3.75% 5.51% 7/17/2009 10.50% 3.75% 6.75% 10/16/2009 10.40% 4.09% 6.31% 10/26/2009 10.10% 4.11% 5.99% 10/28/2009 10.15% 4.11% 6.04% 10/28/2009 10.15% 4.11% 6.04% 10/30/2009 9.95% 4.12% 5.83% 11/20/2009 9.45% 4.18% 5.27% 12/14/2009 10.50% 4.24% 6.26% 12/16/2009 10.75% 4.25% 6.50% 12/1712009 10.30% 4.25% 6.05% 12/18/2009 10.40% 4.26% 6.14% 12/1812009 10.40% 4.26% 6.14% 12/18/2009 10.50% 4.26% 6.24% 12/22/2009 10.20% 4.27% 5.93% 12122/2009 10.40% 4.27% 6.13% 12/28/2009 10.85% 4.29% 6.56% 12/29/2009 10.38% 4.29% 6.09% 1111/2010 10.24% 4.34% 5.90% 1/21/2010 10.23% 4.37% 5.86% 1/21/2010 10.33% 4.37% 5.96% 112612010 10.40% 4.37% 6.03% 2/10/2010 10.00% 4.39% 5.61% 2/23/2010 10.50% 4.40% 6.10% 3(9/2010 9.60% 4.40% 5.20% 3/24/2010 10.13% 4.42% 5.71% 3/31/2010 10.70% 4.43% 6.27% 4/1/2010 9.50% 4.43% 5.07% 4/2/2010 10.10% 4.44% 5.66% 4/8/2010 10.35% 4.44% 5.91% 4/29/2010 9.19% 4.46% 4.73% 4/29/2010 9.40% 4.46% 4.94% 4/29/2010 9.40% 4.46% 4.94% 5/17/2010 10.55% 4.46% 6.09% 5/24/2010 10.05% 4.46% 5.59% 6/3/2010 11.00% 4.46% 6.54% 6/16/2010 10.00% 4.45% 5.55% 6/18/2010 10.30% 4.45% 5.85% 8/9/2010 12.55% 4.41% 8.14% 8/17/2010 10.10% 4.40% 5.70% 9/16/2010 9.60% 4.31% 5.29% 9/16/2010 10.00% 4.31% 5.69% 9/16/2010 10.00% 4.31% 5.69% 9/16/2010 10.30% 4.31% 5.99% 10/21/2010 10.40% 4.20% 6.20% 11/2/2010 9.75% 4.18% 5.57% 11/2/2010 9.75% 4.18% 5.57% 11/3/2010 10.75% 4.17% 6.58% 11/19/2010 10.20% 4.15% 6.05% 12/1/2010 10.00% 4.13% 5.87% 1216/2010 9.56% 4.12% 5.44% 1216/2010 10.09% 4.12% 5.97% Attachment RBH-8 Page 15 of17 Bond Yield Plus Risk Premium [6] [7] [8] [9] 6U-Year Date of Gas Return on Treasury Risk Rate Case Equity Yield Premium 121912010 10.25% 4.12% 6.13% 12/14/2010 10.33% 4.12% 6.21% 12/17/2010 10.10% 4.11% 5.99% 12120/2010 10.10% 4.11% 5.99% 12123/2010 9.92% 4.11% 5.81% 1/6/2011 10.35% 4.09% 6.26% 1/12/2011 10.30% 4.09% 6.21% 1/13/2011 10.30% 4.09% 6.21% 3/10/2011 10.10% 4.16% 5.94% 3/31/2011 9.45% 4.20% 5.25% 4/18/2011 10.05% 4.23% 5.82% 5/26/2011 10.50% 4.31% 6.19% 6/21/2011 10.00% 4.36% 5.64% 6/29/2011 8.83% 4.37% 4.46% 8/1/2011 9.20% 4.41% 4.79% 9/1/2011 10.10% 4.33% 5.77% 11/14/2011 9.60% 3.93% 5.67% 12113/2011 9.50% 3.76% 5.74% 12/20/2011 10.00% 3.72% 6.28% 12122/2011 10.40% 3.70% 6.70% 1/10/2012 9.06% 3.60% 5.46% 1/10/2012 9.45% 3.60% 5.85% 1/10/2012 9.45% 3.60% 5.85% 1/23/2012 10.20% 3.53% 6.67% 1/31/2012 10.00% 3.49% 6.51% 4/24/2012 9.50% 3.16% 6.34% 412412012 9.75% 3.16% 6.59% 5/712012 9.80% 3.13% 6.67% 5/22/2012 9.60% 3.10% 6.50% 5/24/2012 9.70% 3.09% 6.61% 6/712012 10.30% 3.06% 7.24% 6/15/2012 10.40% 3.05% 7.35% 611812012 9.60% 3.05% 6.55% 7/2/2012 9.75% 3.04% 6.71% 10/24/2012 10.30% 2.92% 7.38% 10/26/2012 9.50% 2.92% 6.58% 10/3112012 9.30% 2.92% 6.38% 10/31/2012 9.90% 2.92% 6.98% 10/31/2012 10.00% 2.92% 7.08% 11/112012 9.45% 2.92% 6.53% 11/8/2012 10.10% 2.91% 7.19% 11/9/2012 10.30% 2.91% 7.39% 11/26/2012 10.00% 2.89% 7.11% 11/28/2012 10.40% 2.88% 7.52% 11/28/2012 10.50% 2.88% 7.62% 12/4/2012 10.00% 2.87% 7.13% 121412012 10.50% 2.87% 7.63% 1212012012 9.50% 2.84% 6.66% 1212012012 10.10% 2.84% 7.26% 12/2012012 10.25% 2.84% 7.41% 12120/2012 10.30% 2.84% 7.46% 12120/2012 10.40% 2.84% 7.56% 12/2012012 10.50% 2.84% 7.66% 12126/2012 9.80% 2.83% 6.97% 2/22/2013 9.60% 2.86% 6.74% 311412013 9.30% 2.89% 6.41% 3/27/2013 9.80% 2.91% 6.89% 4/23/2013 9.80% 2.95% 6.85% 511012013 9.25% 2.96% 6.29% 6/13/2013 9.40% 3.01% 6.39% 6/18/2013 9.28% 3.02% 6.26% 611812013 9.28% 3.02% 6.26% 612512013 9.80% 3.04% 6.76% 9/2312013 9.60% 3.32% 6.28% 11/612013 10.20% 3.42% 6.78% 11/13/2013 9.84% 3.44% 6.40% 11/14/2013 10.25% 3.44% 6.81% 11(2212013 9.50% 3.47% 6.03% 12/5/2013 10.20% 3.50% 6.70% 12/13/2013 9.60% 3.52% 6.08% Attachment RBH-8 Page 16 ofl7 Bond Yield Plus Risk Premium [6] [7] [8] [9] .;1v-rear Date of Gas Return on Treasury Risk Rate Case Equity Yield Premium 12/16/2013 9.73% 3.52% 6.21% 12117/2013 10.00% 3.53% 6.47% 12/18/2013 9.08% 3.53% 5.55% 12/23/2013 9.72% 3.54% 6.18% 12130/2013 10.00% 3.57% 6.43% 1/21/2014 9.65% 3.65% 6.00% 1/22/2014 9.18% 3.66% 5.52% 2120/2014 9.30% 3.71% 5.59% 2121/2014 9.85% 3.71% 6.14% 212812014 9.55% 3.72% 5.83% 3/16(2014 9.72% 3.73% 5.99% 4/2112014 9.50% 3.73% 5.77% 4/22(2014 9.80% 3.73% 6.07% 5/8/2014 9.10% 3.71% 5.39% 5/B/2014 9.59% 3.71% 5.88% 6/6/2014 10.40% 3.66% 6.74% 6/1212014 10.10% 3.66% 6.44% 6/1212014 10.10% 3.66% 6.44% 6/12/2014 10.10% 3.66% 6.44% 7/7/2014 9.30% 3.63% 5.67% 7/25/2014 9.30% 3.60% 5.70% 7/31/2014 9.90% 3.59% 6.31% 9/4/2014 9.10% 3.51% 5.59% 9/24/2014 9.35% 3.46% 5.89% 9/30/2014 9.75% 3.45% 6.30% 10/29/2014 10.80% 3.37% 7.43% 11/6/2014 10.20% 3.35% 6.85% 11/14/2014 10.20% 3.33% 6.87% 11/14/2014 10.30% 3.33% 6.97% 11/26/2014 10.20% 3.31% 6.89% 12/3/2014 10.00% 3.29% 6.71% 1/13/2015 10.30% 3.16% 7.14% 1/21/2015 9.05% 3.13% 5.92% 1/21/2015 9.05% 3.13% 5.92% 4/9/2015 9.50% 2.88% 6.62% 5/11/2015 9.80% 2.82% 6.98% 6/17/2015 9.00% 2.79% 6.21% 8/21/2015 9.75% 2.78% 6.97% 10/7/2015 9.55% 2.82% 6.73% 10/13/2015 9.75% 2.83% 6.92% 10/15/2015 9.00% 2.83% 6.17% 10/30/2015 9.80% 2.86% 6.94% 11/19/2015 10.00% 2.89% 7.11% 12/3/2015 10.00% 2.91% 7.09% 12/9/2015 9.60% 2.92% 6.68% 1211112015 9.90% 2.92% 6.98% 12118/2015 9.50% 2.93% 6.57% 1/6/2016 9.50% 2.96% 6.54% 1/6/2016 9.50% 2.96% 6.54% 1/2812016 9.40% 2.97% 6.43% 2110/2016 9.60% 2.95% 6.65% 2116/2016 9.50% 2.94% 6.56% 212912016 9.40% 2.92% 6.48% 4/29/2016 9.80% 2.83% 6.97% 5/5/2016 9.49% 2.82% 6.67% 611/2016 9.55% 2.80% 6.75% 6/3/2016 9.65% 2.79% 6.86% 6/15/2016 9.00% 2.77% 6.23% 6/15/2016 9.00% 2.77% 6.23% 9/2/2016 9.50% 2.57% 6.93% 9/23/2016 9.75% 2.52% 7.23% 9/27/2016 9.50% 2.51% 6.99% 9/29/2016 9.11% 2.50% 6,61% 10/28/2016 9.70% 2.47% 7.23% 11/9/2016 9.80% 2.47% 7.33% 11/18/2016 10.00% 2.49% 7.51% 12/9/2016 10.10% 2.52% 7.58% 12115/2016 9.00% 2.53% 6.47% 12115/2016 9.00% 2.53% 6.47% 12/2212016 9.50% 2.54% 6.96% Attachment RBH-8 Page 17 of17 Bond Yield Plus Risk Premium [6] [7] [BJ [9] .ju-rear Date of Gas Return on Treasury Risk Rate Case Equity Yield Premium 1124/2017 9.00% 2.59% 6.41% 3/1/2017 9.25% 2.65% 6.60% 4/11/2017 9.50% 2.77% 6.73% 4/20/2017 8.70% 2.79% 5.91% #ofCases: 1,054 Average: 4.57% Attachment RBH-9 Page 1 of 1 Small Size Premium [1] [2] Customers (Mil) ($Mil) Atmos Energy Colorado Equity 0.1 $78.42 Median Market to Book for Comp Group 2.30 Atmos Energy Colorado Implied Market Cap $180.63 [3] [4] [5] Customers Market Cap Market to Company Name Ticker (Mil) ($Mil) Book Ratio Black Hills Corporation BKH 1.2 $3,584.90 2.22 CenterPoint Energy, Inc. CNP 5.8 $12,039.71 3.48 Chesapeake Utilitles Corporation CPK 8.2 $27,969.17 2.15 Northwest Natural Gas Company NWN 1.2 $4,878.36 2.76 Sempra Energy SRE 0.2 $1,145.08 2.56 Southwest Gas Corporation swx 0.7 $1,705.73 2.00 Spire Inc SR 2.0 $3,980.14 2.39 Vectren Corporation WC 1.6 $3,225.77 1.73 MEDIAN 1.4 $3,782.52 2.30 MEAN 2.6 $7,316.11 2.41 Average Market Capitalization ($Mil) [6] Decile Size Premium 2 $ 15,053.355 0.61% 3 $ 7,968.196 0.89% 4 $ 4,573.990 0.98% 5 $ 2,982.908 1.51% 6 $ 2,088.950 1.66% 7 $ 1,357.347 1.72% 8 $ 823.172 2.08% 9 $ 436.570 2.68% 10 $ 117.572 5.59% Proxy Group Median $ 3,782.517 0.98% 1oth Decile Size Premium $ 180.635 5.59% Difference from Proxy Group Median 4.61% Notes: [1] Atmos Energy Corporation. SEC Form 10-K for the fiscal year ended September 30, 2016, at 5 [2] Atmos Energy CO ratebase of $141.1 M mutiplied by the recommended equity ratio of 55.58% [3] Source: SNL Financial [4] Source: SNL Financial, 30-day average [5] Source: SNL Financial, 30-day average [6] Source: Duff & Phelps, 2017 Valuation Handbook U.S. Guide to Cost of Capital ···-·.-:-.-:·:-: Attachment RBH-10 Flotation Cost Adjustment Page 1 of 1 Two most recent open market common stock issuances per company, if available ross Equity otat1on Total Flotation Issue Before Cost Company Date Costs Costs Net Proceeds Percentage Atmos Energy Corporation At-the-Market $1,400,000 $100,000,000 $98,600,000 1.400% Constant Growth Discounted Cash Flow Model Adjusted for Flotation Costs - 30 Day Average Stoel< Price [1] [2l [3] [4] [5] [6] [7] [BJ [9] [10] [11] [12] Average Expected Dividend Yield Zacks First Call Value Line Value Line Average Flotation Annualized Stock Dividend Adjusted for Earnings Earnings Earnings Retention Earnings Adjusted Company Ticker Dividend Plice Yield Current Flot. Costs Growth Growth Growth Growth Growth DCF k(e) DCF k(e) Black Hills Corporation BKH $1.78 $67,07 2,65% 2.75% 2.79% 5.00% 10.38% 7.50% 5.41% 7.07% 9.82% 9.86% CenterPoint Energy, Inc. CNP $1.07 $27.94 3.83% 3.94% 3.99% S.00% 6.06% 6.00% 4.98% 5.51% 9.44% 9.50% Chesapeake Utilities Corporation CPK $1.22 $70.37 1.73% 1.61% 1.83% 6.00% 6.00% 8.00% 14.38% 8,60% 10.40% 10.43% Northwest Natural Gas Company NWN $1.68 $59.56 3.16% 3.23% 3.27% 4.30% 4.50% 6.00% 3.46% 4.57% 7.79% 7.64% Sempra Energy SRE $3.29 $111.49 2.95% 3.06% 3.10% 8.70% 9.87% 8.00% 2.73% 7.32% 10.38% 10.43% Southwest Gas Corpora~on swx $1.98 $83.71 2.37% 2.43% 2.47% 5.00% 4.00% 6.50% 6.02% 5.86% 8.31% 8.35% Spire Inc SR $2.10 $68.14 3.06% 3.16% 3.21% 4.10% 4.05% 6.00% 5.24% 5.35% 8.51% 6.56% Vectren Corporation WC $1.68 $58.79 2.86% 2.95% 2.99% 5.70% 5.57% 7.00% 6.46% 6.18% 9.13% 9.17% PROXY GROUP MEAN 9.23% 9.27% Notes: DCF Result Adjusted For FlotaUon Costs: 9.27% The proxy group DCF result is adjusted forflotaUon costs by dividing each company's expected dividend yield by (1 ·flotation cost). The flotation cost DCF Result Unadjusted For Flotation Costs: 9.23% adjustment is derived as the difference between the unadjusted DCF result and the DCF result adjusted for flotation costs. Difference (Flotation Cost Adjustment):! 0.04%j(13] [1] Source: Bloomberg Professional [21 Source: Bloomberg Professional (3] Equals [1] / [21 [4] Equals (3] x (1 + 0.5 x (10]) [5] Equals [4] / (1 - 1.4%) [6] Source: Zacks [7] Source: Yahoo! Finance [8] Source: Value Line [9] Source: Attachment RBH- 3, Value Line [1 O] Equals Averege([6J, [7], [8], [9]) [11] Equals [4] + [10] [12] Equals [5] + [10] [13] Equals average (12]- average [11J (") "':::c z m mc .?J c.. r BEFORE THE PUBLIC UTILITIES COMMISSION OFTHESTATEOFCOLORADO IN THE MATTER OF ADVICE LETTER ) NO. 530, FILED BY ATMOS ENERGY ) CORPORATION TO PLACE INTO ) Proceeding No. 17AL-_G EFFECT TARIFF SHEET CHANGES TO ) BE EFFECTIVE ON JULY 27, 2017 ) DIRECT TESTIMONY AND ATTACHMENTS OF JASON L. SCHNEIDER June 26, 2017 SUBMITTED ON BEHALF OF ATMOS ENERGY CORPORATION TABLE OF CONTENTS I. EXECUTIV.E SUMMARY ...... 1 II. INTRODUCTION AND PURPOSE OF TESTIMONY ...... 2 III. BOOKS AND RECORDS ...... 4 IV. COSTASSIGNMENTANDALLOCATIONMANUAL ...... 14 V. ATMOS ENERGY'S CORPORATE STRUCTURE ...... 15 ATTACHMENT: Attachment .TLS-1 - Cost Assignment and Allocation Manual and Fully Distributed Cost Study I Q. PLEASE STATE YOUR NAME AND BUSINESS ADDRESS. 2 A. My name is Jason L. Schneider. My business address is 5430 LBJ Freeway, Suite 3 600, Dallas, Texas, 75240. 4 I. EXECUTIVE SUMMARY 5 As a natural gas distribution utility with regulated operations in eight states, 6 Atmos Energy has implemented processes to ensure its Books and Records are 7 accurately maintained in accordance with the Federal Energy Regulatory 8 Commission's Uniform System of Accounts and Generally Accepted Accounting 9 Principles. These processes include integrated, computerized business systems to 10 efficiently process, record, and maintain transactions; requiring a level of personal 11 knowledge and supporting documentation to record transactions; maintaining 12 controls to ensure the accuracy of the Books and Records; and third-party audits 13 and reviews of the controls. These controls and processes are also reviewed 14 internally on an annual basis to ensure the Company's Books and Records are being 15 accurately maintained, and the controls and processes are also reviewed by an 16 independent public accounting firm. 17 Atmos Energy also maintains and uses a Cost Assignment and Allocation 18 Manual to make allocations within the Company's Books and Records, including 19 allocations of various common expenses incurred for the benefit of one or more of Direct Testimony of Jason L. Schneider ; Page 1 Colorado I Schneider Direct Testimony 1 Atmos Energy's rate divisions. The Cost Assignment and Allocation Manual also 2 directs allocations between Atmos Energy and its affiliates, or between affiliates. 3 II. INTRODUCTION AND PURPOSE OF TESTIMONY 4 Q. BY WHOM ARE YOU EMPLOYED AND IN WHAT CAPACITY? 5 A. I am the Director of Accounting Services for Atmos Energy Corporation ("Atmos 6 Energy" or the "Company"), Shared Services ("SSU"). 7 Q. WHATISSSU? 8 A. SSU is a group of Company employees who collectively serve multiple rate 9 divisions. These employees provide various services including, for example, legal, 10 billing, call center, accounting, information technology, human resources, gas 11 supply, and rates administration. SSU is comprised of two separate parts, "Shared 12 Services - General Office" and "Shared Services - Customer Support." 13 Q. PLEASE OUTLINE YOUR EDUCATIONAL AND PROFESSIONAL 14 QUALIFICATIONS. 15 A. I earned a Bachelor of Science degree in Accounting Control Systems from the 16 University of North Texas in 2000. I also eamed a Master of Business 17 Administration degree in Accounting from the University of North Texas in 2003. 18 I have worked in various industries for over twenty years in a variety of accounting 19 and finance staff and management roles. In 2004, I joined Atmos Energy's Plant 20 Accounting group and became the Manager of Plant Accounting in 2005. In that Direct Testimony of Jason L. Schneider Page2 Colorado I Schneider Direct Testimony I capacity, I worked closely with the prior Director of Accounting Services in 2 ensuring the Company's Cost Assignment and Allocation Manual remained 3 consistently aligned with Atmos Energy's recordkeeping practices. I assumed my 4 current role as Director of Accounting Services in March 2011. 5 Q. ARE YOU A MEMBER OF ANY PROFESSIONAL ORGANIZATIONS? 6 A. Yes. I am licensed as a Certified Public Accountant ("CPA") in the State of Texas. 7 Q. HAVE YOU PREVIOUSLY TESTIFIED BEFORE THE COLORADO 8 PUBLIC UTILITIES COMMISSION OR OTHER REGULATORY 9 ENTITIES? 10 A. I previously submitted testimony to the Colorado Public Utilities Commission 11 ("Commission") in Proceeding Nos. BAL-04960, 14AL-0300G, and 15AL- 12 0299G. Additionally, -I submitted testimony to the Kansas Corporation 13 Commission in Docket Nos. 12-ATMG-564-RTS and 14-ATMG-320-RTS, to the 14 Tennessee Regulatory Authority in Docket Nos. 12-00064 and 14-00146, to the 15 Mississippi Public Service Commission in Docket No. 2015-UN-049, to the 16 Virginia State Corporation Commission in Case No. PUE-2015-00119, and to the 17 Kentucky Public Service Commission in Case Nos. 2015-00343 and 2013-00148. 18 I testified before the Kentucky Public Service Commission in Case No. 2013- . 19 00148. Direct Testimony ofJason L. Schneider Page3 Colorado I Schneider Direct Testimony 1 Q. WHAT IS THE PURPOSE OF YOUR TESTIMONY? 2 A. The purpose of my testimony is to (a) support the historic Books and Records of 3 Atmos Energy; (b) discuss the Company's methodology for cost allocations, as set 4 forth in the Company's Cost Assignment and Allocation Manual; and ( c) discuss 5 the SSU cost allocations. 6 Q. ARE YOU SPONSORING ANY ATTACHMENTS WITH YOUR 7 TESTIMONY? 8 A. Yes. I am sponsoringAttachrnentJLS-1, a copy of the Company's Cost Assignment 9 and Allocation Manual. 10 III. BOOKS AND RECORDS 11 Q. PLEASE SUMMARIZE HOW ATMOS ENERGY MAINTAINS AND 12 UTILIZES ITS BOOKS AND RECORDS IN THE REGULAR COURSE OF 13 BUSINESS. 14 A. Atmos Energy maintains its Books and Records in accordance with the Federal 15 Energy Regulatory Commission's ("FERC") Uniform System of Accounts 16 ("USOA'') and Generally Accepted Accounting Principles ("GAAP"). The USOA 17 is the prescribed methodology for maintaining records in all of the state 18 jurisdictions which regulate Atmos Energy's natural gas distribution operations. 19 Currently, Atmos Energy's provision of service is subject to regulatory oversight in Direct Testimony of Jason L. Schneider Page4 Colorado I Schneider Direct Testimony l Colorado, Kansas, Kentucky, Louisiana, Mississippi, Tennessee, Texas and 2 Virginia. 3 Atmos Energy's accounting organization utilizes integrated, computerized 4 business systems to efficiently process, record and maintain transactions that are 5 generated in the regular course of business. Financial transactions are created and 6 entered into the system at or near the time of the transaction by (a) personnel having 7 personal knowledge, or (b) personnel acting in reliance on information transmitted 8 by persons having personal knowledge of the transactions. In addition to the 9 personal knowledge of the transactions, these personnel are also familiar with the 10 applicable accounting procedures and requirements. 11 Q. HOW DO YOU KNOW THAT TRANSACTIONS ARE PROPERLY 12 RECORDED? 13 A. In my capacity as Director ofAccounting Services, and as part of the Controllership 14 function, I have and maintain personal knowledge of the organizational business 15 processes and associated staffing. The Controller's organization is staffed with 16 highly qualified accounting managers and personnel, many of whom are CPAs. The 17 managers in the organization are charged with the responsibility to inspect, review 18 and if appropriate, revise the work of the accountants they supervise. Atmos Energy 19 has established and maintains controls that ensure the accuracy of its Books and 20 Records. These controls identify any necessary adjustments to accounting entries, Direct Testimony of Jason L. Schneider Page5 Colorado I Schneider Direct Testimony l which are then recorded to the original Books and Records. Additionally, Atmos 2 Energy contracts with KPMG LLP ("KPMG") for internal audit services, and 3 KPMG periodically performs reviews of those controls as well. 4 Q. ARE THE COSTS THAT ARE RECORDED ON THE COMPANY'S BOOKS 5 AND RECORDS SUPPORTED BY UNDERLYING INVOICES OR OTHER 6 RECORDS? 7 A. Yes. In order for an item to be recorded in the Company's general ledger, there 8 must be supporting documentation. By way of example, the supporting 9 documentation may be in the form of a billing invoice received from a vendor or 10 an employee's timesheet. The designated manager of a specific cost center or 11 project is responsible for reviewing, coding and approving invoices or other 12 underlying supporting documentation that are charged to that respective cost center 13' or project. 14 Q. WHAT DO YOU MEAN BY COST CENTERS? 15 A. As described in the Company's Cost Assignment and Allocation Manual, a cost 16 center is a designation generally utilized for the assignment of departmental cost 17 responsibility and internal management reporting. The employees responsible for 18 oversight of these functional areas are delegated with a certain level of authority to 19 conduct the business of the Company. Direct Testimony of Jason L. Schneider Page6 Colorado I Schneider Direct Testimony l Q. HOW ARE THESE AUTHORITY LEVELS DETERMINED OR 2 DELEGATED WITHIN THE COMPANY? 3 A. The Board of Directors initially delegates authority to the Chief Executive Officer 4 ("CEO") of the Company. The CEO then authorizes the Vice President and 5 Controller to further delegate authority to others throughout the Company as 6 necessary. The Controller's approval of authority limits is generally based on a 7 review of the needs and recommendations from those who request authority limit 8 changes. Controller~approved authority limits are maintained in a secure table 9 within the Company's accounting system. 10 Q. DOES THE COMPANY HAVE L~ PLACE ANY PROCESS OR SYSTEM 11 FOR THE REVIEW AND VALIDATION OF INVOICES? 12 A. Yes. Invoices are generally scanned into Markview, an accounts payable processing 13 system, when they are received by the Company. Once scanned, an image of the 14 invoice is routed electronically to the appropriate cost center owner. The cost center 15 owner reviews, electronically codes, and approves or escalates, as appropriate, the 16 invoice within the established approval hierarchy. As a part of this process, the cost 17 center owner is responsible for ensuring that the cost is valid, just and reasonable. 18 If the amount of the invoice exceeds the authority limit of the initial approver, an 19 automatic escalation process is initiated through the system's approval hierarchy to 20 the appropriate person. A similar review process is performed at each level within Direct Testimony of Jason L. Schneider Page 7 Colorado I Schneider Direct Testimony 1 the approval hierarchy. Once final approval of payment for an invoice has been 2 obtained, the invoice is submitted to the accounts payable depaitrnent for payment. 3 Q. DOES THE COMPANY HAVE IN PLACE ANY PROCESS OR SYSTEM 4 FOR THE REVIEW AND VALIDATION OF COSTS THAT ARE NOT 5 PROCESSED THROUGH MARKVIEW? 6 A. Yes. Certain invoices and other requests for payment that are not presented as an 7 invoice are processed outside of Markview. These types of requests include, but 8 are not limited to, tax returns, contracts for certain third party services, or certain 9 wire transfers. The process for the review, coding and approval of these types of 10 costs is the same as the process within Markview, except that the process may be 11 manual for these types of requests rather than electronic. The Company employee 12 in charge of documentation is responsible for ensuring that the cost is valid, just 13 and reasonable. Coding and approvals are performed within the approval hierarchy. 14 Once final approval for payment has been obtained, the request, along with 15 supporting documentation, is submitted to the accounts payable department for 16 payment. Direct Testimony of Jason L. Schneider Pages Colorado I Schneider Direct Testimony Q. ARE THERE ANY OTHER ACCOUNTING CONTROLS OR PROCESSES 2 IN PLACE TO ENSURE THE ACCURACY OF THE COMPANY'S BOOKS 3 AND RECORDS? 4 A. Yes, the Company executes a series of detective and monitoring controls designed 5 to identify and explain material and/or unusual costs that have been recorded in the 6 general ledger. If errors are found, they are typicalJy corrected in the following 7 month's reporting period, unless the errors are material. If an error is material, it is 8 corrected in the current month. 9 Additionally, the CEO and Chief Financial Officer must certify the 10 Company's annual and quarterly financial statements and must attest to and report 11 on the Company's system of internal control. To facilitate this effort, the Company 12 outsources its internal audit function to the accounting firm KPMG to conduct tests 13 of the Company's system of internal control. These tests are developed to ensure 14 that the system of internal control has been designed effectively and that the 15 controls are functioning as designed as of the end of the Company's fiscal year. 16 Q. PLEASE DESCRIBE THE PROCESS USED TO TEST INTERNAL 17 CONTROLS. 18 A. The Company maintains a Sarbanes~Oxley ("SOX") steering committee. The SOX 19 steering committee is responsible for the oversight and monitoring of SOX 20 compliance. This committee is comprised of myself, the Vice President and Direct Testimony of Jason L. Schneider Page9 Colorado I Schneider Direct Testimony l Controller, the Director of Financial Reporting, the Director of Infonnation 2 Security, and the Director of Gas Accounting and Rate Administration. 3 During the first quarter of the fiscal year, the Director of Financial 4 Reporting and I meet with the internal auditors to review the Company's listing of 5 key controls and to assess whether revisions should be made to that list based upon 6 changes in the risk profile or organization of the Company. A key control is defined 7 as a control necessary to mitigate risks and ensure that the financial reporting is 8 reasonable and materially correct. 9 The internal audit group will then develop a testing plan based upon key 10 controls. The plan is reviewed and approved by the SOX steering committee. The 11 key controls are tested throughout the year, and if an issue arises, it is individually 12 addressed by a steering committee member who has knowledge of the affected area. 13 The SOX steering committee meets regularly to assess the progress and review the 14 results of the testing. During this process, the SOX steering committee discusses 15 all the findings and determines whether a finding should be considered a control 16 deficiency, a significant deficiency or a material weakness. A control deficiency 17 exists where the design or operation of a control does not allow management or 18 employees to timely prevent or detect misstatements in financial reporting. A 19 significant deficiency is a control deficiency that adversely affects the Company's 20 ability to report external financial data reliably, with more than a remote likelihood Direct Testimony of Jason L. Schneider Page 10 Colorado I Schneider Direct Testimony l that an inconsequential misstatement of the Company's financial statements will 2 not be prevented or detected. A material weakness is a significant deficiency that 3 results in more than a remote likelihood that a material misstatement of the financial 4 statements will not be prevented or detected. 5 At the end of the fiscal year, the SOX steering committee makes 6 recommendations regarding the effectiveness of the Company's internal control 7 structure to be included in the internal auditor's final report to the audit committee. 8 Q. PLEASE SUMMARIZE THE RESULTS OF TESTING FOR THE MOST 9 RECENTLY COMPLETED FISCAL YEAR. 10 A. The most recent fiscal year available is fiscal 2016. A total of 223 key controls 11 related to the Company's regulated natural gas distribution operations were tested. 12 Five (5) deficiencies were identified as a result of this testing. No significant 13 deficiencies or material weaknesses were identified. All five (5) deficiencies have 14 been remediated. 15 Q. ARE THE COMPANY'S TESTS OF INTERNAL CONTROL SUBJECT TO 16 EXAMINATION BY AN INDEPENDENT REGISTERED PUBLIC 17 ACCOUNTING FIRM? 18 A. Yes. As a publicly traded company, Atmos Energy is required to have an 19 independent registered public accounting firm audit management's public 20 assertions regarding the Company's system of internal control. Ernst & Young, Direct Testimony of Jason L. Schneider Page 11 Colorado I Schneider Direct Testimony l LLP ("EY") serves as the Company's independent registered public accounting 2 firm. 3 Q. CAN YOU SUMMARIZE THE PROCESS USED BY EY TO PERFORM ITS 4 AUDIT FUNCTION? 5 A. Yes. EY performs independent tests regarding the design of the Company's internal 6 control function and the effectiveness of the controls as of the end of the fiscal year. 7 They rely, in part, on the work performed by the internal auditors in completing 8 their audit procedures. Upon completion of their work, EY issues an audit rep01i 9 summarizing their findings. This report is included in the Company's Form IO"K 10 annual report. 11 Q. DID EY'S MOST RECENT REPORT DIFFER FROM THE FINDINGS OF 12 MANAGEMENT? 13 A. No. EY issued an unqualified audit report for fiscal 2016. This means that EY 14 agrees with management's assertions. 15 Q. ARE THERE OTHER TYPES OF REGULAR AUDITS AND REVIEWS 16 THAT ARE CONDUCTED OF ATMOS ENERGY'S BOOKS AND 17 RECORDS? 18 A. In addition to the audit of internal controls, EY conducts an annual audit of Atmos 19 Energy's Books and Records, and performs reviews of Atmos Energy's quarterly Direct Testimony of Jason L. Schneider Page 12 Colorado I Schneider Direct Testimony 1 financial statements. These audits and reviews are conducted in accordance with 2 the standards of the Public Company Accounting Oversight Board (United States). 3 Q. HOW DOES THE ACCOUNTING SYSTEM ALLOW FOR THE 4 SEPARATE RECORDING AND TRACKING OF COSTS FOR ATMOS 5 ENERGY'S UTILITY DIVISIONS? 6 A. Direct costs are charged directly to the natural gas distribution division that incurs 7 these costs. Technical and support services are provided to the distribution 8 divisions by centralized shared services departments primarily located at the Atmos 9 Energy headquarters in Dallas. These centralized functions include, but are not 10 limited to, accounting, human resources, legal, treasury, and risk management. The 11 costs for these shared services are allocated to the operating divisions. 12 Q. WERE THE BOOKS AND RECORDS OF THE COMPANY UTILIZED IN 13 THE PREPARATION OF THE RATE FILING FOR RATEMAKING 14 PURPOSES? 15 A. Yes. 16 Q. ARE ATMOS ENERGY'S BOOKS AND RECORDS AVAILABLE FOR 17 REVIEW? 18 A. Yes. Atmos Energy's general ledger is maintained in an electronic format that 19 allows authorized users access to the financial data. As part of this proceeding, Direct Testimony of Jason L. Schneider Page 13 Colorado I Schneider Direct Testimony 1 Atmos Energy will make its Books and Records available for review, upon request, 2 at its offices in Denver, Colorado or Dallas, Texas. 3 IV. COST ASSIGNMENT AND ALLOCATION MANUAL 4 Q. WHAT IS THE COST ASSIGNMENT AND ALLOCATION MANUAL 5 ("CAAM")? 6 A. The CAAM describes and documents the process whereby allocations are made 7 within Atmos Energy's Books and Records. These include allocations of various 8 common expenses which are incurred for the benefit of one or more of Atmos 9 Energy's rate divisions and which expenses are therefore allocated to those rate 10 divisions. Additionally, the CAAM describes and documents the processes 11 whereby allocations are made between Atmos Energy and its affiliates and between 12 affiliates. : 13 Q. PLEASE DESCRIBE THE HISTORY OF THE CAAM. 14 A. The CAAM was first developed in response to Kentucky regulation 807 KAR 5:080 15 and was first filed with the Kentucky Public Service Commission in April of 2001. 16 Atmos Energy is required to update the CAAM each year. Atmos Energy has used 17 the CAAM to document its allocation processes in the regular course of business 18 since it was first filed in Kentucky. Atmos Energy filed its first CAAM in Colorado 19 in Docket No. 07A-106G. Atmos Energy is filing the CAAM in this docket in 20 accordance with the Code of Colorado Regulations ("CCR"), specifically 4 CCR Direct Testimony of Jason L. Schneider Page 14 Colorado I Schneider Direct Testimony 1 723-4-4502 and 4503. The Company's CAAM also includes a Fully Distributed 2 Cost Study in accordance with 4 CCR 723-4-4504. 3 Q. ARE THE ALLOCATIONS DESCRIBED IN THE CAAM USED IN EVERY 4 JURISDICTION IN WHICH ATMOS ENERGY OPERATES? 5 A. Yes. The CAAM is applicable in all states in which Atmos Energy has regulated 6 utility divisions for those allocations that involve both utility divisions and 7 affiliates. 8 Q. DOES THE CAAM DESCRIBE ALLOCATIONS OF BALANCE SHEET 9 AMOUNTS USED IN TIDS RATE FILING? 10 A. No. Allocations of balance sheet amounts are not described in the CAAM and, 11 rather, are made only for ratemaking purposes in the context of a rate filing or for 12 certain regulatory reports. I discuss the allocations of rate base amounts for this 13 rate filing later in my testimony. 14 V. ATMOS ENERGY'S CORPORATE STRUCTURE 15 Q. ARE YOU FAMILIAR WITH THE COMPANY'S CORPORATE 16 STRUCTURE? 17 A. Yes. The Company consists of the utility and its various subsidiaries. The utility 18 is part of the parent company. The Company conducts other operations through its 19 subsidiaries. A chart showing the corporate structure is included in Appendix A as 20 Attachment 1 to the CAAM attached as Attachment JLS-1. Direct Testimony of Jason L. Schneider Page 15 Colorado I Schneider Direct Testimony 1 Q. IN THE TOP BOX OF THE REFERENCED CHART REPRESENTING 2 ATMOS ENERGY, WHAT DO THE VARIOUS DIVISIONS REPRESENT? 3 A. The various divisions are a part of the Company's management control structure 4 which is utilized in the Company's shared cost allocation processes. Section 5 4503(b)(I) of the CAAM describes the corporate structure in detail. There are 6 cun-ently seven divisions - six are regulated gas local distribution operations and 7 one is a regulated intrastate pipeline operation. We commonly refer to these 8 divisions as "Operating Divisions" or "Business Units." The Operating 9 Division/Business Unit that serves customers in Colorado and is the subject of this 10 rate filing is referred to as the Colorado-Kansas Division. 11 Q. DO THESE OPERATING DIVISIONS CONSTITUTE SEPARATE LEGAL 12 ENTITIES? 13 A. No. They are merely unincorporated operating divisions within the Company's 14 organizational structure. None of the operating divisions have a legal existence 15 separate and apart from the Company, nor do they have separate equity or debt, nor 16 keep separate Books and Records. Direct Testimony of Jason L. Schneider Page 16 Colorado I Schneider Direct Testimony VI. COST ALLOCATION PROCESS FOR COMMON COSTS 2 Q. WHAT IS COST ALLOCATION WITH REGARD TO COMMON COSTS? 3 A. Cost allocation is the process of allocating various common costs that are incurred 4 for the benefit of one or more of the Company's rate divisions. Those costs· are 5 then allocated to the respective rate division(s) that receives the benefit. 6 Q. WHAT DO YOU MEAN WHEN YOU REFER TO "RATE DIVISION"? 7 A. The CAAM defines "Rate Division" as the primary source for regulatory reporting 8 and rate activity of an accumulation of accounting data. 9 Q. ARE THERE DIFFERENT TYPES OF DIVISIONS? 10 A. Yes, there are rate divisions and operating division general offices. A rate division 11 represents an area in which rates have been set by a regulatory authority such as the 12 Commission. For GCA purposes, the Company's Colorado operations are currently 13 comprised of rate divisions designated as 33 Northeast, 34 Northwest/Central, 35 14 Southeast, and 36 Southwest. An operating division general office provides 15 common services to rate divisions. If an operating division general office 16 encompasses more than one jurisdiction, then the costs from the operating division 17 general office are allocated to the separate rate divisions to which it provides 18 services. An example of this airnngement is the Colorado-Kansas Division that 19 provides services to the Company's utility operations in Colorado and Kansas. As 20 described further below, and provided in Attachment JLS-1, the costs of the Direct Testimony of Jason L. Schneider Page 17 Colorado I Schneider Direct Testimony 1 operating division general office are allocated to the rate divisions in accordance 2 with the methodology described by the CAAM. 3 Q. WHAT IMPACT WILL CONSOLIDATION OF THE FOUR GCA RATE 4 AREAS INTO TWO GCA RATE AREAS HAVE ON THE COMPANY'S 5 BOOKS AND RECORDS AND OPERATIONS? 6 A. The impact of the consolidation of the gas cost adjustment rate divisions will not 7 impact Colorado's books and records as the treatment will be consistent with the 8 process described in the CAAM. The impact to the company's operations is 9 addressed in the Consolidated GCA section of the Company's witness Jared N. 10 Geiger's direct testimony. 11 Q. WHICH SHARED SERVICES DIVISIONS PROVIDE SERVICES TO THE 12 COMPANY'S COLORADO RATE DIVISIONS? 13 A. The Colorado rate divisions receive allocations from SSU. As I mentioned earlier, 14 SSU is comprised of two divisions: the Shared Services - General Office ("SSGO") 15 (designated as division 2) and Shared Services - Customer Support ("SSCS") 16 (designated as division 12). 17 Q. WHICH OPERATING DIVISION GENERAL OFFICES PROVIDE 18 SERVICES TO THE COMPANY'S COLORADO RATE DIVISIONS? 19 A. The Company's Colorado utility operations receive allocations from the Colorado- 20 Kansas operating division general office (designated as division 30) and also a Direct Testimony of Jason L. Schneider Page 18 Colorado I Schneider Direct Testimony 1 small allocation from the Company's Colorado division general office (designated 2 as division 31 ). 3 Q. WHAT ARE THE COMMON COSTS TO WHICH YOU REFER? 4 A. Common costs include costs related to services that are provided to the Company's 5 rate divisions by SSU. SSGO includes, for example, accounting, human resources, 6 legal, rates, risk management and numerous others. SSCS includes billing, 7 customer call center functions and customer support related services. The costs for 8 these shared services are allocated to the Company's rate divisions that utilize those 9 services. Common costs are also those from the operating division general offices 10 that provide services to the rate divisions. These costs include costs related to rent 11 for office facilities, labor related to technical services personnel that provide 12 engineering and mapping services and management and operations personnel that 13 operate the division. 14 Q. HOW DOES THE ACCOUNTING SYSTEM ALLOW FOR THE 15 SEPARATE RECORDING AND TRACKING OF COSTS FOR ATMOS 16 ENERGY'S RATE DIVISIONS? 17 A. Direct costs are charged directly to the rate division which has incurred the costs. 18 For example, if an outside contractor is hired in Colorado to perform leak survey 19 services, then those costs are charged directly, and only, to Colorado because the 20 work is done only for Colorado. Costs for the shared services, by contrast, are Direct Testimony of Jason L. Schneider Page 19 Colorado I Schneider Direct Testimony L allocated to the rate divisions that receive the benefit of those services. Detailed 2 transactions are recorded by rate division in the general ledger for all utility 3 divisions of Atmos Energy. The rate division designation is incorporated into the 4 Company's account coding, and costs are accumulated for various rate divisions or 5 operating division general offices within the Company's general ledger. 6 Q. ARE COMMON COST ALLOCATIONS NECESSARY IN THE CONTEXT 7 OF THE COMPANY'S RATE FILINGS? 8 A. Yes, it is appropriate and necessary to allocate the common costs incurred for the 9 benefit of ratepayers in multiple regulatory jurisdictions to the various jurisdictions 10 that receive those services. For example, the Company's SSGO provides the 11 various support services discussed above to its utility operations in eight states. 12 Similarly, the SSCS provides customer service functions exclusively to the 13 Company's utility operations and is the utility customer's point of contact with the 14 Company for service activations, billing issues, emergency reporting, etc. Because 15 Colorado customers receive the benefits of SSGO and SSCS services, it is fair to 16 allocate the appropriate portion of the services to Colorado. 17 Q. PLEASE DESCRIBE THE COMPANY'S COMMON COST ALLOCATION 18 METHODOLOGY. 19 A. The Company allocates certain types of common costs to its rate divisions for 20 management purposes, as well as for reporting and ratemaking purposes. Direct Testimony of Jason L. Schneider Page 20 Colorado I Schneider Direct Testimony 1 Operations and Maintenance expense ("O&M"), depreciation expense, and taxes, 2 other than income taxes, that comprise common costs are allocated on the books of 3 the Company, as described in the CAAM. Other common costs, such as commonly 4 utilized plant in service and other rate base items, are not allocated on the books of 5 the Company. Instead, those costs are allocated for ratemaking purposes based on 6 similar methodologies from above. 7 Q. YOU DIFFERENTIATE BETWEEN COMMON COSTS WHICH ARE 8 ALLOCATED ON THE BOOKS OF THE COMPANY AND THOSE THAT 9 ARE ALLOCATED FOR RATEMAKING PURPOSES. CAN YOU 10 EXPLAIN THE DIFFERENCE? .. 11 A. Yes. O&M, depreciation, and taxes (other than income taxes) related to shared 12 services are allocated on the Company's general ledger utilizing the· allocation 13 methodologies described in detail in the CAAM. The Company allocates these 14 expenses within its general ledger as a part of its normal accounting cycle. The 15 allocation factors used are generally updated annually and effective as of October 16 1, the beginning of the Company's fiscal year. The updated factors are used for the 17 entire fiscal year, absent the occurrence of a material event that significantly 18 changes the factors. 19 Composite factors or customer factors are used to allocate costs that are not 20 allocated on the Company's general ledger. For example, Shared Services costs, Direct Testimony of Jason L. Schneider Page 21 Colorado I Schneider Direct Testimony I for which composite or customer factors are used for ratemaldng purposes, include 2 plant in service and accumulated deferred income taxes, among other rate base 3 items. 4 Q. HOW WERE THE COMPOSITE AND CUSTOMER ALLOCATION 5 FACTORS DERIVED FOR THIS RATE FILING? 6 A. The Composite Factor used in the rate filing is derived from a three-factor formula 7 comprised of the simple average of the relative percentage of: 8 l . Gross plant in service for each of the Company's operating divisions to the 9 total gross plant in service for all of Atmos Energy's operating divisions 10 (excluding Shared Services); 11 2. The average number of customers in each of the Company's operating 12 divisions to the total number of customers for the Company; and 13 3. The direct O&M expense for each of the Company's operating divisions to 14 the total direct O&M expenses of all Atmos Energy's operating divisions 15 (excluding Shared Services). 16 The Customer Factor is derived based on the average number of customers of the 17 Company's operating divisions that receive allocable costs for the services 18 provided. Direct Testimony of Jason L. Schneider Page 22 Colorado I Schneider Direct Testimony Q. WHAT FACTOR IS USED FOR ALL SSGO ALLOCATIONS NOT 2 RECORDED ON THE COMPANY'S GENERAL LEDGER (FOR RATE 3 BASE)? 4 A. SSGO, division 2, costs are generally allocated utilizing the Composite Factor. This 5 factor is calculated utilizing the three-factor formula described above. 6 Q. WHAT FACTOR IS USED FOR ALL SSCS ALLOCATIONS NOT 7 RECORDED ON THE COMPANY'S GENERAL LEDGER (FOR RATE 8 BASE)? 9 A. SSCS, division 12, costs are generally allocated utilizing the Customer Factor. 10 Q. WHAT FACTORS ARE USED TO ALLOCATE THE COLORADO- 11 KANSAS OPERATING DIVISION GENERAL OFFICE COSTS? 12 A. The operating division general office costs for the Colorado-Kansas Division are 13 allocated to the applicable rate divisions utilizing a composite factor based on the 14 calculation of the above-mentioned three factors (i.e., gross plant in service, 15 customers and O&M). However, they are calculated at a division level. 16 Q. DOES THIS CONCLUDE YOUR DIRECT TESTIMONY? 17 A. Yes. Direct Testimony of Jason L. Schneider Page 23 Colorado I Schneider Direct Testimony Attachment JLS-1 Page 1of72 Atmos Energy Corporation Cost Assignment and Allocation Manual As required by 4CCR 7234-4500 Table of Contents Section Introduction (I.) 1 Definitions and Glossary of Terms 1-3 Cost Assignment and Allocation Principles (//.) 4502 -Overview 4502 3 -Tariffed Services 4502(a) 3 -Direct Assignment 4502(b) 4 -Common Costs 4502(c) 4-5 -Value of Transactions - CO utility to non-regulated activity 4502(d) 5-6 -Value of Transactions - Non-regulated activity to utility 4502(e) 6-7 -Inability to establish a market price 4502{f) 7 -Non-jurisdictional regulated services 4502(g) 7 -Value of transactions between regulated divisions within a utility 4502{h) 7 -Bundled Services 4502(i) 7 -Incidental activities 45020) 7 -Audit Trail 4502(k) 8 Cost Assignment and Allocation Manuals (Ill.) 4503 8 -Information to be included in the CAAM (I-VI) 4503{b) 8-10 -Description of the basis of the assignment/allocation (VI I) 4503(b) 11-41 -Statement (VI 11) 4503(b) 42 Fully Distributed Cost Study (IV.) 4504 42-43 Disclosure of Non-regulated Goods and Services (V.) 4505 43-44 Appendix A: Attachment 1 - Organization Structure Attachment 2 -Word document "Colorado CAAM - Section 4504(d) (11).doc" Attachment 3 - Excel file - Fully Distributed Cost Study- "FDCS - Inc Stmts Mar17 as filed.xis" Attachment JLS-1 Page 2 of 72 I. INTRODUCTION: This Cost Assignment and Allocation Manual ("CAAM") describes and explains the cost assignments and allocation processes which are utilized by Atmos Energy Corporation ("Atmos") in accordance to 4 Code of Colorado Regulations ("CCR") 723-4-4502 and 4503. The CAAM describes and explains the calculation methods used to segregate and account for costs between and among jurisdictions, between regulated and non-regulated activities and between and among utility divisions DEFINITIONS: The following abbreviations or acronyms are used within the CAAM document. Atmos (the Company) ...... Atmos Energy Corporation CAAM ...... Cost Assignment and Allocation Manual CCR ...... Code of Colorado Regulations FERG ...... Federal Energy Regulatory Commission FDCS ...... Fully Distributed Cost Study O&M ...... Operations & Maintenance Expense GLOSSARY OF TERMS: The following terms defined below are defined for purposes of this document only: Affiliate - One or more of Atmos' subsidiaries. Below the Line - Amounts which are generally not included in an analysis of costs from which gas service rates are derived. Company - In general terms, it refers to Atmos Energy Corporation. Within the context of the account coding string, this term represents an operating division, wholly-owned subsidiary or other legal entity controlled by Atmos. Composite Factor - The Company's general allocation factor which is derived for each applicable area based upon the simple average of the ratio of gross plant in service, average number of customers and direct operation and maintenance expenses for each applicable area to the total for each of these items. Corporate Headquarters - The headquarters of Atmos Energy Corporation located in Dallas, Texas. Cost Centers - Account coding which denotes an area of cost responsibility. This coding is used primarily for management purposes. Customer Factor - The Company's general allocation factor which is derived based on the average number of customers of the Operating Divisions that receive allocable costs for the services provided. 1 Attachment JLS-1 Page 3 of72 Direct Charges - Those charges which may originate in a shared services department or operating division general office division or a rate division which are booked directly to the applicable rate division. FERC USOA - The Uniform System of Accounts as prescribed by the Federal Energy Regulatory Commission. Municipal Jurisdiction - For Atmos' operations in Texas, each municipality which it serves has original jurisdiction over rates. Operating Division - An unincorporated division of Atmos Energy Corporation that contains at least one rate division that is responsible for the management of the Company's Regulated Operations. Operating divisions are not subsidiaries or separate legal entities. As such, they do not have separate equity or debt structures. Additionally, the divisions do not keep separate books and records. Operating divisions with multiple rate divisions have one operating division general office rate division in addition to rate divisions corresponding to regulatory jurisdictional areas. Operating Division General Office - Administrative offices that are located outside of shared service offices which serve as the base of operations and central office for each "operating division." Rate Division - Often referred to as an operating rate division, it denotes Atmos' regulatory jurisdictions that are defined by state and geographic boundaries. The term also denotes Atmos' various shared services and operating division general office divisions. These divisions are the primary source for regulatory reporting and rate activity for an area in which rates have been set by a regulatory authority such as the Colorado Public Utilities Commission. Rate divisions are identifiable in the Company's account coding string. As such, costs are accumulated within the general ledger and represent the sum of direct costs plus costs allocated to the rate division. Regulated Operations - Represents the Company's six regulated natural gas distribution operating divisions operating in 8 states and the Company's regulated intrastate pipeline operations in the State of Texas. Service Area - The portion of the Company's account coding structure of which the first three digits denote rate division. The last three digits of this code denote "town" which is used only in certain instances. Atmos Pipeline-Texas uses the final three digits of the service area to represent the actual storage or compressor facility; however, this is used for O&M expenses only. Shared Services - The Company's functions that serve multiple rate divisions. These services include departments such as legal, billing, call center, accounting, information technology, human resources, gas supply, rates administration among others. Shared Services is comprised of Shared Services - General Office and Shared Services - Customer Support. Shared Services - Customer Support - Shared Services functions that include billing, c.ustomer call center functions and customer support related services. 2 Attachment JLS-1 Page 4 of72 Shared Services - General Office - Shared Services functions that include all other functions not encompassed by Shared Services - Customer Support. 11. (4502) COST ASSIGNMENT AND ALLOCATION PRINCIPLES Overview Atmos Energy Corporation is comprised of seven operating divisions (Atmos Energy Corporation, (Unconsolidated)) and various wholly-owned subsidiaries, most of which are wholly-owned by Atmos Energy Holdings, Inc. A chart showing the current corporate structure is included in Appendix A, Attachment 1. The following briefly describes the Company's operating divisions: Division Service Area Atmos Energy Colorado-Kansas Division Colorado, Kansas Atmos Energy Kentucky/Mid-States Kentucky, Tennessee, Virginia Division Atmos Energy Louisiana Division Louisiana Atmos Energy Mid-Tex Division Texas, including the Dallas/Fort Worth metropolitan area Atmos Energy Mississippi Division Mississippi Atmos Energy West Texas Division West Texas Atmos Pipeline -Texas Division Intrastate pipeline business in Texas The operating divisions are a part of the Company's management control structure that is utilized in the Company's shared costs allocation processes. Section 4503(b) (I) of the CAAM describes the corporate structure in detail. There are currently seven operating divisions - six regulated local gas distribution operations and one regulated intrastate pipeline operation. We also refer to these divisions as "Business Units." The Company's Colorado operation is contained within the Colorado-Kansas Operating Division/Business Unit. Also, Operating Divisions or Business Units are comprised of rate divisions (defined in the glossary above). Within an operating division, there are operating rate divisions and office rate divisions. An operating rate division represents a regulated operation such as the Company's utility operations in Colorado. An office rate division is one that provides common services to operating rate divisions. The costs of the office rate divisions are allocated to the operating rate divisions in accordance with the methodology described by the CAAM, as will be explained more in detail in section 4503. 4502(a) Tariffed Services If a tariffed service is provided to or from Colorado, the charge for that service is at the tariffed rate. Currently, there are no tariffed services provided to or from another state or subsidiary to Colorado. 3 Attachment JLS-1 Page 5 of72 4502(b) Direct Assignment Direct costs are charged directly to the operating rate division that has incurred the costs. For example, if Colorado hires an outside contractor to perform leak survey services, then those costs are charged directly, and only, to Colorado because the work is done only for Colorado. 4502(c) Common Costs Common costs such as Shared Services cost or operating division costs are allocated to the operating rate divisions that receive the benefit of those services. If an office rate division encompasses more than one jurisdiction, such as the Company's Colorado rate division, which provides services to the Company's utility operations in Colorado and Kansas, then the costs from that office rate division are allocated to the separate rate divisions to which it provides services. Detailed transactions are recorded by rate division in the general ledger for all utility divisions of Atmos Energy. The rate division designation is incorporated into the Company's account coding string. As such, costs are accumulated for various operating areas or office rate divisions within the Company's general ledger. This could represent the Company's operations in a particular state or a particular area within a state and/or various office rate divisions, which would appropriately allocate costs to operating rate divisions. Each category is fairly and equitably allocated between regulated and non-regulated activities or jurisdictions in accordance with the following principles: 4502(c) (I) Cost Causation The Company's Shared ·Services - General Office provides various support services discussed above to its natural gas distribution operations in the nine states in which the Company operates. Some of these shared services are also provided to the Company's nonregulated subsidiaries. Similarly, the Shared Services - Customer Support group provides customer service functions to the Company's natural gas distribution operations and is the utility customer's point of contact with the Company for service activations, billing issues, emergency reporting, etc. Colorado rate division customers receive the benefits of these services, and the allocations of these costs are apportioned to the Colorado rate division on the basis of cost causation (or benefit received). In addition to the Shared Services function, the Colorado-Kansas Division headquarters office in Denver provides services to Colorado and Kansas. Accordingly, costs from this office are allocated to the Company's Colorado rate division as well as other jurisdictions that it supported on the basis of cost causation (or benefit received). 4502(c) (II) Variability Overall, the Company's allocation methodologies are generally based upon the relative size and nature of operations of each operating division or subsidiary. The allocation percentages to be applied to costs are reviewed and changed at least annually. If there is a dramatic change in the relative size or operations during the fiscal year, the Company will review and determine the impact of the change and determine if it is necessary to update the allocation percentages at that time. 4502(c) (Ill) Traceability Operations and Maintenance (O&M) expense, depreciation expense and taxes other than income taxes related to Shared Services and the Colorado-Kansas division's headquarters office are allocated on the Company's books and records utilizing the allocation methodologies 4 Attachment JLS-1 Page 6 of72 described in detail in section 4503 of this CMM. The Company allocates these expenses within its books and records as a part of its normal accounting cycle. The allocation factor used has a logical or observable correlation to the activity and generally is calculated once per year at the beginning of the Company's fiscal year (October 1) and utilized for the entire year unless a material event occurs that would significantly change the factors. For those Shared Services costs that are not allocated on the Company's books and records, either a composite factor for Shared Service - General Office or a customer factor for Shared Service - Customer Support is used to allocate costs. Some examples of Shared Services costs for which composite factors or the customer factor, as appropriate, are used for allocating such expenses for ratemaking purposes would include plant in service and accumulated deferred income taxes, as well as other rate base items. Composite factors are derived based upon a three-factor formula comprised of the simple average of: 1. The relative percentage of gross plant in service for each of the Company's business units to the total gross plant in service for all of Atmos' business units (excluding Shared Services}; 2. The ratio of the number of customers in each of the Company's business units to the total number of the Company's customers; and 3. The ratio of direct O&M expense for each of the Company's business units to the total direct operation and maintenance expenses of all Atmos business units (excluding Shared Services}. The Customer Factor is derived based on the average number of customers of the Operating Divisions that receive allocable costs for the services provided. 4502( c) (IV) Benefit Common costs include costs related to technical and support services that are provided to the Company's operating rate divisions by centralized shared services ("Shared Services" or "SSU"}. Shared Services - General Office includes, for example, accounting, human resources, legal, rates, information technology and numerous other functions. Shared Services - Customer Support includes customer call center services, billing, collections and other customer support related functions. The costs for these Shared Services are allocated to the Company's rate divisions that benefits from these services. 4502(c) (V) Residual Any residual costs left after direct assignments or indirect assignments, i.e., allocations, are allocated using the same allocation methodologies as used in the original allocation. 4502(d) Value of transactions -Colorado Utility to non-regulated activities For cost assignment and a/location purposes, the value of all transactions from the Colorado utility to a non-regulated activity shall be determined as follows: I. Atmos provides regulated natural gas distribution service to its customers in Colorado at tariffed rates. Atmos does not provide non-regulated services to its customers within Colorado. However, if the Colorado utility provided a product or 5 Attachment JLS-1 Page 7 of72 service that is not regulated in Colorado, the value of the transaction would be at a tariffed rate. II. As stated in 4502{d) (I), Atmos does not provide non-regulated activities to its customers within Colorado. However, if the Company provided a nonutility service or product that was not pursuant to tariff, the cost charged would be at the higher of market price or the utility's fully distributed cost in accordance with these rules. Ill. If the transaction involves the sale of an asset, the value of the transaction shall be the higher of net-book cost or market price. If the transaction involves the use of an asset, the value of the transaction shall be the higher of fully distributed cost or market price. The Company does not have these types of transactions within Colorado. 4502(e) Value of transactions -Non-regulated activities to the Utility For cost assignment and a/location purposes, the value of all transactions from a non regulated activity to the utility shall be determined as follows: I. Pursuant to the rules as defined in section 4502(e) (I) of the CCR, if the transaction involves a product or service that is not provided pursuant to a tariff, the value of the transaction shall be the lower of the fully distributed cost or the market price except if the transaction results from a competitive solicitation process then the value of the transaction shall be the winning bid price. Fully distributed cost in this circumstance, shall be the cost that would be incurred by the utility to provide the service internally. Market price shall be either the price charged for the non-regulated activity or if that condition is not met, the lowest price charged by other persons in the market for a comparable product or service, when such prices are publicly available. Charges for services from the Company's captive property insurance subsidiary, Blueflame Insurance Services, LTD, are billed at cost to the Company's Colorado rate divisions. Periodic surveys are made in the commercial marketplace by our broker to determine the cost of property coverage for Atmos. Historically these surveys have proven Blueflame Insurance Services, LTD provides better coverage at a lower price than is available in the commercial marketplace. II. Pursuant to the rules as defined in section 4502(e) {II) of the CCR, if the transaction involves the sale of an asset, the value of the transaction shall be the lower of net-book cost or market price. If the transaction involves the use of an asset, the value of the transaction shall be the lower of fully distributed cost or market price. Market price shall be either the price charged by the non-regulated activity or, if this condition cannot be met, the lowest price charged by another person in the market for the sale or use of a comparable asset, where such prices are publicly available. 6 Attachment JLS-1 Page 8 of72 Currently the transactions occurring between Atmos' Colorado Operations and Atmos' non-regulated subsidiaries do not involve either the sale or use of assets. If, at some future date, these types of transactions occur, the value of the transaction would be valued at the lower of net-book cost or market price. 4502(f) Inability to establish a market price Pursuant to the rules as defined in section 4502{f) of the CCR, if it is impracticable for the utility to establish a market price pursuant to paragraphs (d) or (e}, the utility shall provide a statement to that effect, including its reasons in its fully distributed cost study as well as its proposed method and amount for valuing the transaction. Parties in a Commission proceeding retain the right to advocate alternative market prices pursuant to paragraphs (d) and (e). Please see 4502{e) {I). 4502(g) Non-jurisdictional regulated services. Pursuant to the rules as defined in section 4502{g) of the CCR, a utility may classify nonjurisdictional services as regulated if the services are rate-regulated by another agency (i.e., another state utility commission or the FERG) and where there are agency-accepted principles or methods for the development of rates associated with such services. This rule may apply, for example, to a provider's wholesale sales of electric power and energy. For such services, the utility shall identify the services in its manual, and account for the revenues, expenses, assets, liabilities and ratebase associated with these services as if these services are regulated. The Company has classified certain non-Colorado jurisdictional natural gas distribution operations in other states as regulated since the services are rate regulated by the state commissions in Kansas, Texas, Louisiana, Mississippi, Tennessee, Virginia and Kentucky. The Company has identified the services in this CAAM, and accounted for the revenues, expenses, assets, liabilities and ratebase associated with these services as if they are regulated. 4502(h) Value of transactions between regulated divisions within a utility Atmos provides only regulated natural gas delivery services to its customers in Colorado. Unlike other utilities in Colorado, the Company is not involved and has no plans to be involved in any non-regulated activities such as new product development, lighting solutions, water service, appliance repair services, heating and air conditioning services, etc. 4502(i) Bundled Services The Company does not sell bundled services; therefore, this section does not apply. Please see section 4502(h). 4502(j) Incidental activities Incidental activities as defined in section 4501 (h) are not provided in Colorado. If these services were provided in Colorado, any amount of these activities would be classified as regulated activities and booked as part of the Company's utility records. 7 Attachment JLS-1 Page 9 of72 4502(k) Audit Trail Atmos' account coding structure enables it to capture the costs for allocable activities. Expenses, assets and liabilities for Atmos' shared service divisions and other operating division general office divisions are coded to applicable location codes and cost centers which are then allocated to the appropriate rate divisions based upon the methodologies described herein. Allocations recorded in the books and records of the Company are primarily for management control purposes and may not be reflective of the allocation methodology used for rate making purposes. Atmos account coding structure is as follows: XXX. xxxx. XXXX. xxxxx. XXXXXX. xxxx Company Cost FERG Sub- Service Future Center Account Account Area Use 3 digit 4 digit 4 digits 5 digits 6 digits 4 digits Within the above coding structure, "Company" and "Cost Center" are primarily utilized for internal management responsibility reporting purposes for Atmos' operating divisions. The terms "Company" and "Cost Center" are defined in the glossary beginning on page 2. Utilization of the "Company" or "cost center" fields is not suitable for meaningful financial or regulatory reporting purposes. The FERG account field contains the three-digit FERG USOA account plus one extension digit which in some cases is utilized by the FERG USOA. The first three digits of the Service Area field are the primary coding utilized for cost allocations within Atmos and is generally referred to as "rate division number". This portion of the field denotes Atmos' various rate divisions as well as the Company's various shared service divisions, and operating division general office. These codes are the primary source of information for regulatory reporting and rate activity. The remaining three digits represent "town" location which is utilized only for some accounts. Atmos Pipeline-Texas uses the final three digits of the service area to represent the actual storage or compressor facility; however, this is used for O&M expenses only. Ill. 4503(b) COST ASSIGNMENT AND ALLOCATION MANUALS Each utility shall include the following information in its CAAM: I. A listing of all regulated or non-regulated divisions of the Colorado utility together with an identification of the regulated or non-regulated activities conducted by each. 8 Attachment JLS-1 Page 10 of72 Total Company Atmos Energy Corporation (Atmos or the Company) operates its Regulated Operations through seven operating divisions in 8 states. The seven operating divisions and their service areas are: Division Service Area Atmos Energy Colorado-Kansas Division Colorado, Kansas Atmos Energy Kentucky/Mid-States Division Kentucky, Tennessee, Virginia Atmos Energy Louisiana Division Louisiana Atmos Energy Mid-Tex Division Texas, including the Dallas/Fort Worth metropolitan area Atmos Energy Mississippi Division Mississippi Atmos Energy West Texas Division West Texas Atmos Pipeline - Texas Division Intrastate pipeline business in Texas These operating divisions are not subsidiaries or separate legal entities. Therefore, by definition, they cannot be considered affiliates of Atmos. Technical and support services are provided to the operating divisions by centralized shared services departments primarily located at the Atmos headquarters in Dallas. These centralized functions currently include, but are not limited to, accounting, gas supply, human resources, information technology, legal, rates and customer support. The costs for these shared services are allocated to the operating divisions. In addition, for operating divisions that operate in more than one rate jurisdiction, costs from an operating division's general office are allocated to separate rate divisions within the operating division. ' Atmos Energy Holdings, Inc. is a wholly owned subsidiary of Atmos. Atmos Energy Holdings and its various wholly owned subsidiaries are separate legal entities and are considered affiliates of Atmos. The Company's current legal entity organization chart is contained in Appendix A. Note that the descriptions contained herein do not address tariffed services. II. A listing of all regulated or non-regulated affiliates of the Colorado utility together with an identification of which affiliates allocate or assign costs to and from the Colorado utility. The Colorado-Kansas division as stated in 4503(b) {I) is not a separate legal entity and therefore is not an affiliate of Atmos. Our Colorado utility does not provide nonregulated services to its customers. lhe Colorado-Kansas division receives nonregulated services from Blueflame Insurance Services, LTD. Blueflame provides captive insurance policies. This is allocated to the Colorado-Kansas Division as described in detail in section 4503(b) (VII). Ill. A listing and description of each regulated and non-regulated activity offered by the Colorado utility. The Colorado utility shall provide a description in sufficient 9 Attachment JLS-1 Page 11 of72 detail to identify the types of costs associated with the activity and shall identify how the activity is offered to the public and identify whether the Colorado utility provides the activity in more than one state. If an activity is offered subject to tariff, the Colorado utility may identify the tariff and the tariff section that describes the service offering in lieu of providing a service description. Colorado provides only regulated natural gas service to its customers in Colorado. The service is defined in their approved tariffed rate as filed with CPUC and is detailed in the Atmos Energy Corporation website www.atmosenergy.com. IV. A listing of the revenues, expenses, assets, liabilities and ratebase items by Uniform System of Accounts (USDA) account number that the utility proposes to include in its revenue requirement for Colorado jurisdictional activities including those items that are partially allocated to Colorado as well as those items that are exclusively assigned to Colorado. See Appendix A, Attachment 2 V. A detailed description showing how the revenues, expenses, assets, liabilities and ratebase items by account and sub-account are assigned and/or allocated to the Colorado utility's non-regulated activities, along with a description of the methods used to perform the assignment and a/locations. See 4503(b) (IV) above. VI. A description of each transaction between the Colorado utility and a non regulated activity which occurred since the Colorado utility's prior CAAM' was filed and, for each transaction, a statement as to whether, for this Commission's jurisdictional cost assignment and allocation purposes, the value of the transactions is at cost or market as applicable. Atmos only provides regulated natural gas delivery services to its customers in Colorado. There have been no changes in the nature of these services since the filing of the last CAAM. VII. A description of the basis for how the assignment or a/location is made 10 Attachment JLS-1 Page 12 of72 Service: Capitalized overhead (general) Description: Overhead related to capital expenditures Current Provider Shared Services of Service Atmos Pipeline-Texas Division Louisiana Division operating division general office Kentucky/Mid-States Division operating division general office Colorado-Kansas Division operating division general office Mid-Tex Division Mississippi Division West Texas Division Current Use of Rate divisions Service Basis for Capitalized overhead costs are accumulated by operating division (and state level for allocation multiple state divisions). Each operating division (and state) sets an application rate at the beginning of the year based on projected expenditures. As expenditures for CWIP and RWIP are recorded overhead is applied at the application rate. Periodically, the application rate is reviewed. Shared services overhead is allocated to operating divisions based on operating division capital expenditures. At the end of each quarter, the amount that has accumulated in the OH project is cleared to all eligible projects that incurred charges during that quarter, on a pro rata basis Genera E Ledger E::ntrles: E:xample Only ssU BU 010 SSU BU D10 Administrative Office Supply Expenses SSU BU 010 SSU BU 010 and Expenses Transferred Cash Accounts Payable Acct. 921 Acct. 922 Acct.131 Acct. 232 Co.st Center XXXX-. Cost Center XXXX $1.000'(1) • (1) $1,000'(1) • (1) $600~3) $1,0001 $1,0001 I I $400 (3a) SSU BU 010 Admini:strative SSU BU 010 I General Of!iae - Div 091 I Expenses Administrative SSU BU 010 Administrative Transferred & General Constri.iction Work :l::xpenses Acct. 922 Acct. 920 in Progress Transferred Cost Center 1910 "' Cost Center 1910 Acct. 107 Acc.t. 922 (3b) $200'(2) • (2) • (3) $600 $150 (4) $2001 (3b) $180$201 $450 (4a) I r (5) $10 $20 (3b) General Office Rate Oiv Office Rate Div Office Remaining Mid States Div 009 .,.., Mfd St.ates Div ..Remain in Administrative Administr.ative Admlnf strative Expenses Expenses Expenses Transferred. Tra nsrerre d Transferred Ac.ct. 922 Aect. 922 Acct. 922 (3a) $180 (3b) r (4) $10'(5) (4a) $4001 $1501 $4501 ... Cap rate = 20% ..... Many rate dhAsion offices exist within Mld-States in addition to Div 009. Flow of Activity • (1) Purchase Office Supplies .. (2) Capitalize Overhead is calculated based on cost center capitalization percentage ~ (3) Allocatrng Shared Sen.foes Expenses to General Officas - 60% Allocation rate for Hlustration purposes only (3a) Allocation to remaining general offices (3b) AHocate capitalization credits to bt.1siness unlts r- (4) AHoc:ating Shared SeNces E)(penses to Rate Di'\lisfon Office - 25% Allocation rate for illustration purposes only (4a) Allocation to remaining dil.islon offices ,. (5) AHocatlng Shared SeNce.s Capitalization Credit to Rate DhAsion Office - 50% AILocaUon rate for illustration purposes only Note: Please see the allocation of expenses from General Office to State Regional Office to Rate DiVision on the fallowing pages: West Texas - 20, Colorado/Kansas - 22, Louisiana - 26 11 Attachment JLS-1 Page 13 of72 Service: Stores overhead Description: Overhead related to inventory warehousing is allocated to materials as issued. Current Provider Shared Services of Service Operating division general office Current Use of Atmos Pipeline-Texas Divislon Service West Texas Division rate divisions Louisiana Division rate divisions Kentucky/Mid-States Division rate divisions Mid-Tex Division rate division Colorado-Kansas Division rate divisions Mississippi Division rate division Basis for Overhead costs associated with inventory items, including rent, labor and allocation supervision are accumulated by operating divlsion. Each operating division sets an application rate at the beginning of the year based on projected overhead and materials activity. As materials are issued from the warehouse, the overhead assigned is also allocated to the same account. Periodically, the balance in the undistributed stores overhead account is compared to the materlals on hand balance and a new rate is determined. Shared Services stores overhead is allocated monthly to the operating divlsions based on number of meters. General Ledger Entries: Example Only Rate Div Office Mid States Div 009 ** SSU BU 010 SSU BU 010 Construction Work Cash Inventory in Progress Acct. 131 Acct. 107 $100 (1) ,.. (1) $100 $100 (2) ,.. (2) $100 $2 {3a) (3b) $2 SSU BU 010 SSU BU 010 Stores Expense Accounts Undistributed Payable Acct. 163 Acct. 232 (3a) $2 $2 (3b) (3a) $2 $2 (3a) ** Many rate dhlision offices exist within Mid-States in addition to Div 009. Flow of Activi~ 1 Purchase Inventory - Material 2 Issue ln\ientory to Capltal Project 3a Incurring ln\ientory Expense 3b Apply ln\ientory Storage Rate Assume 2% 12 Attachment JLS-1 Page 14 of72 Service: O&M Expenses in Shared Services - Customer Support cost centers Description: Includes all expenses for Customer Support. (Division 012) Current Provider Shared Services Of Service Current Use of Service West Texas Rate Divisions Mid-Tex Division Louisiana Rate Divisions Kentucky/Mid-States Rate Divisions Colorado-Kansas Rate Divisions Mississippi Division Basis for Costs are allocated to the applicable operating division general office in total allocation based on the average number of customers in each operating division as a percentage of the total number of customers in all of the operating divisions. From the operating division general office Divisions Customer Support charges are allocated to rate divisions using the average number of customers in each rate division. General Ledger Entries: Exam!!le OnlJl SSU BU 010 Office Supply SSU BU 010 SSU BU 010 SSU BU 010 and Expeni;es • Administrative Cash Accounts Payable Acct 921 Expeni;es Acct 131 Acct 232 Cost Center XXXX Transferred ,. (1) ,. (1) $1,000~1) $1,0001 $1,000~1) $1,0001 Acct 922 400 ~2) I I: 600 (2a) General Office General Office Rate Div Office Rate Div Office Remainin Mid States - Div 091 Mid States Div 009 ** Mid States -Remainin Administrative Administrative Administrative Administrative Expenses Expenses Expenses Expeni;es Transferred Transferred Transferred Transferred Acct 922 Acct 922 Acct. 922 Acct. 922 (2a) $ ,. (2) $400 $100 (3) ... (3) (3a) 600 $1001 $3001 I $300 (3a) • Many O&M expense accounts exist in addition to 921 that get cleared out of account 922. •• Many rate di\ision offices exist within Mid-States in addition to Div 009. Flow of Activity ,. (1) Purchase Office Supplies - Shared Sernces ,. (2) Allocating Shared Sernces Expenses to General Offices - 40% Allocation rate for illustration purposes only (2a) Allocation to remaining general offices ,. (3) Allocating Shared Sernces Expenses to Rate Dillision Office - 25% Allocation rate for illustration purposes only (3a) Allocation to remaining dilision offices Note: Please see the allocation of expenses from General Office to State Regional Office to Rate Divislon on the following pages: West Texas - 20, Colorado/Kansas - 22, Louisiana - 26 13 Attachment JLS-1 Page 15 of72 Service: O&M Expenses in Shared Services - General Office cost centers Description: Includes O&M expenses in Shared Services - General Office. (Division 002) Current Shared Services Provider Of Service Current Use Atmos Energy Louisiana Industrial Gas, LLC of Service Trans Louisiana Gas Plpeline WKG Storage, Inc. West Texas Division Mid-Tex Division Atmos Pipeline-Texas Division Louisiana Division Kentucky/Mid-States Division Colorado-Kansas Division Mississippi Division Trans Louisiana Gas Storage Atmos Power Systems, Inc UCG Storage, Inc. Atmos Energy Holdings, Inc. Basis for Costs are allocated to affiliates and operating divisions based on a composite factor applied allocation to the Shared Services departments. Shared Services departments which provide services to the Company's affiliates utilize a composite factor which includes the affiliates. Shared Service departments that do not provide services to the Company's affiliates utilize a composite factor which does not include the Company's affiliates. Other allocation methods used as appropriate include, but are not limited to, composite not including affiliates or Atmos Pipeline -Texas and an Overhead rate. From each operating division general office charges are allocated to rate divisions using the composite rate for each rate division. See page 15 for General Ledger Entries: Example Only. 14 Attachment JLS-1 Page 16 of72 General Ledger Entries: Examgle Onll". SSU BU 010 SSU BU010 Office Supply Administrative SSU BU 010 SSU BU 010 and Expenses• Expenses Cash Accounts Payable Acct. 921 Transferred Acct. 131 Acct 232 Cost Center XXXX Acct 922 $1,000~1) "(1) $1,0001 $1,000~1) "(1) $1,0001 300 ~2) I I: 700 (2a) General Office General Office Rate Div Office Rate Div Office Remainin Mid States - Div 091 Mid States Div 009 •• Mid States -Remainin Administrative Administrative Administrative Administrative Expenses Expenses Expenses Expenses Transferred Transferred Transferred Transferred Acct 922 Acct. 922 Acct. 922 Acct. 922 (2a) $ "(2) $150~3) "(3) (3a) 700 $3001 $1501 $1501 I $150 (3a) • Many O&M expense accounts exist in addition to 921 that get cleared out of account 922. ~ Many rate division offices exist within Mid-States in addition to Div 009. Flow of Activity ' (1) Purchase Office Supplies - Shared Services " (2) Allocating Shared Services Expenses to General Offices - 30% Allocation rate for illustration purposes only (2a) Allocation to remaining general offices ,. (3) Allocating Shared Services Expenses to Rate Diliision Office - 50% Allocation rate for illustration purposes only (3a) Allocation to remaining di\Asion offices Note: Operating Divisions Mississippi, Mid-Tex and Atmos Pipeline- Texas have 1 rate division. There is no allocation to remaining division offices (3a). Note: Please see the allocation of expenses from General Office to State Regional Office to Rate Division on the following pages: West Texas - 20, Colorado/Kansas - 22, Louisiana - 26 15 Attachment JLS-1 Page 17 of72 Service: SSU - Customer Support taxes other than income taxes Description: Includes all taxes other than income tax charged in Shared Services - Customer Support. Current Provider Shared Services Of Services Current Use of West Texas Rate Divisions Service Louisiana Rate Divisions Kentucky/Mid-States Rate Divisions Mid-Tex Division Colorado-Kansas Rate Divisions Mississippi Division Basis for allocation Costs are allocated to the applicable rate division level in total based on the average number of customers in each operating division as a percentage of the total number of customers in all of the operating divisions. If needed number of customers in the rate divisions is used to allocated from the operating division general office to the rate divisions. General Ledger Entries: Example Only General Office SSU BU 010 Remainin SSU BU 010 SSU BU 010 Taxes Other than Taxes Other than Cash Accounts Payable Income Taxes Income Taxes Acct. 131 Acct. 232 Acct. 408.1 Acct. 408.1 I $1,000'(1) ,. (1) $1,0001 $1,000'(1) ,. (1) $1,000 $400 (2) (2a) $600 (2a) General Office Rate Div Office Rate Div Office Mid States -Div 091 Mid States -Div 009•• Mid States - Remainin Taxes Other than Taxes Other than Taxes Other than Income Taxes Income Taxes Income Taxes Acct. 408.1 Acct. 408.1 Acct. 408.1 ,. (2) $400 $100 (3) ,. (3) {3a) $300 (3a) •• Many rate dii.ision offices exist in addtion to Div 009. Flow of Activity " (1) Taxes Other than Income Taxes incurred " (2) Allocating Shared SeriAces Expenses to General Offices -40% to Mid States BU - for illustration purposes (2a) Allocating to remaining dii.ision offices ,. (3) Allocating Shared Sernces Expenses to Rate Division Office - 25% for Kentucky Rate Di\ision Office - for illustration purposes only (3a) Allocating Shared Sernces Expenses to remaining Rate Dii.ision Offices Note: Please see the allocation of expenses from General Office to State Regional Office to Rate Division on the following pages: West Texas - 20, Colorado/Kansas - 22, Louisiana - 26 16 Attachment JLS-1 Page 18 of72 Service: SSU - General Office taxes other than income taxes Description: Includes all taxes other than Income tax charged in Shared Services - General Office. Current Provider Shared Services Of Services Current Use of Atmos Energy Louisiana Industrial Gas, LLC Service Atmos Power Systems, Inc. WKG Storage, Inc. Trans Louisiana Gas Pipeline, Inc. West Texas Division Mid-Tex Dlvision Atmos Pipeline- Texas Division Louisiana Division Kentucky/Mid-States Division Colorado-Kansas Division Mississippi Division UCG Storage, Inc. Atmos Energy Holdings, Inc. Basis for Costs are allocated to the applicable operating divisions in total based on the allocation Composite Factor. The Composite Factor is the simple average of three percentages: The percentage of Gross Direct Property Plant and Equipment ln each operating division unit as a percentage of the total Direct Property Plant and Equipment in all of the operating divisions. ' The number of customers in each operating division as a percentage of the total number of customers in all of the operating divisions. The total direct O&M expense in each operating division as a percentage of the total direct O&M expense in all operating divisions. If needed, allocation from operating division general offices to rate division uses the composite rate. See page 16 for General Ledger Entry- Example Only. 17 Attachment JLS-1 Page 19 of72 Service: SSU - Customer Support depreciation Description: Includes all depreciation charged in Shared Services - Customer Support. Current Provider Shared Services Of Services Current Use of West Texas Rate Divisions Service Louisiana Rate Divisions Kentucky/Mid-States Rate Divisions Mid-Tex Division Colorado-Kansas Rate Divisions Mississippi Division Basis for allocation Costs are allocated to the applicable rate division level in total based on the average number of customers in each operating division as a percentage of the total number of customers in all of the operating divisions. If needed number of customers in the rate divisions is used to allocated from the operating division general office to the rate divisions. General Ledger Entries: Example Only Rate Div Office SSU BU 010 SSU BU 010 Mid States -Div 009"* Depreciation Exp Depreciation Exp Depreciation Exp Acct. 403 Acct. 108 Acct. 403 ,. (1) $5,000 $200 (2) ; $6.ooo· (1) ,. (2) $4,800 (2a) (2a) "* Many rate division offices exist in addtion to Div 009. Flow of Activity ,. (1) Monthly Depreciation Expense is booked through Powerplant and interfaces with the Oracle general ledger. ,. (2) Current Month Depreciation Expense is allocated to the various utility rate divisions using the following allocation factors: i. For SSU division 002 - General -Allocated using the composite factor ii. For SSU division 012 - Call Center - Allocated using the customer factor. (2a) Allocation to remaining Rate Divisions Note: Please see the allocation of expenses from General Office to State Regional Office to Rate Division on the following pages: West Texas - 20, Colorado/Kansas - 22, Louisiana - 26 18 Attachment JLS-1 Page 20 of72 Service: SSU - General Office depreciation Description: Includes all depreciation charged in Shared Services - General Office. Current Provider Shared Services Of Services Current Use of Atmos Energy Louisiana Industrial Gas, LLC Service WKG Storage, Inc. Trans Louisiana Gas Pipeline, Inc. West Texas Division Mid-Tex Division Atmos Pipeline-Texas Division Louisiana Division Kentucky/Mid-States Division Colorado-Kansas Division Mississippl Division UCG Storage, Inc. Atmos Energy Holdings, Inc. Basis for Costs are allocated to the applicable operating divisions in total based on the allocation Composite Factor. The Composite Factor is the simple average of three percentages: (1) The percentage of Gross Direct Property Plant and Equipment in each operating division unit as a percentage of the total Direct Property Plant and Equipment in all of the operating divisions. (2) The number of customers in each operatlng division as a percentage of the total number of customers in all of the operating divisions. (3) The total direct O&M expense in each operating division as a percentage of the total dlrect O&M expense in all operating divisions. If needed, allocation from operating division general offices to rate division uses the composite rate. See page 18 for General Ledger Entry - Example Only. 19 Attachment JLS-1 Page 21 of72 Service: West Texas Division operating division general office O&M, depreciation and taxes other than income taxes, to rate division level Description: Allocation of operating division general office expenses to rate division levels Current Provider of West Texas Division operating division general office Service Current Use of West Texas Division rate divisions Service Basis for allocation Costs are allocated to the applicable operating divisions in total based on the Composite Factor. The Composite Factor is the simple average of three percentages: (1) The percentage of Gross Direct Property Plant and Equipment in each division as a percentage of the total Direct Property Plant and Equipment in the West Texas Division rate divisions. (2) The number of customers in each rate division as a percentage of the total number of customers in the West Texas Division rate divisions. (3) The total direct O&M expense ln each municipal rate division as a percentage of the total direct O&M expense in the West Texas Division rate divisions. See Page 21 for General Ledger Entries: Example Only. 20 Attachment JLS-1 Page 22 of72 General Ledger Entries: Example Only General Office General Office General Office West Texas - Div 010 SSU-Div002 SSU-Div 002 Office Supply Cash Accounts Payable and Expenses * Acct. 131 Acct. 232 Acct. 921 $500~1) ,.. (1) $500 $500 {1} ,.. (1} $400~5) ,.. (5) $400 $400~5) '1 General Office Rate Div Office Rate Div Office West Texas - Div 010 West Texas Div 020•• West Texas -Remaining Administrative Administrative Administrative Expenses Expenses Expenses Transferred Transferred Transferred Acct. 922 Acct. 922 Acct. 922 $200"(2) ,. (2) (2a) $300 (2a) "'I General Office Rate Div Office West Texas - Div 01 O West Texas - Div 010 West Texas Div 020•• Depreciation Exp Accumulated Depreciation Depreciation Exp Acct. 403 Acct.108 Acct. 403 ,.. (3) $15 ..(4) $100~3) ,. (4) "1 $85 (4a) General Office Rate Div Office Rate Div Office West Texas - Div 010 West Texas Div 020•• West Texas -Remaining Taxes Other than Taxes Other than Taxes Other and Income Taxes Income Taxes Depreciation Acct. 408.1 Acct. 408.1 Acct. 408.1 and 403 ,. (5) $400 $100 (6) ,.. (6) $ (4a) $851 $300 (6a) "'I (6a) $300 • Many O&M expense accounts exist in addition to 921 that get cleared out of account 922. •• Many rate division offices exist in addition to Div 020. Flow of Activity ,. (1) Purchase Office Supplies - West Texas Division General Office ,. (2) Allocating General Office Expenses to Rate Division Office - 40% Allocation rate for illustration purposes only (2a) Allocation to remaining division offices ,. (3) Monthly Depreciation Expense is booked through Powerplant and interfaces with the Oracle general ledger. ,. (4) Allocation from Division 010 -West Texas General Office to West Texas Rate Divisions (4a) Allocation to remaining division offices ,. (5) Taxes Other than Income Taxes incurred ,. (6) Allocating General Office Expenses to Rate Division Office - 25% to West Texas Rate Division Office - for illustration purposes only (6a) Allocation to remaining division offices 21 Attachment JLS-1 Page 23 of72 Service: Colorado-Kansas Division operating division general office expenses to state regional office division level. Description: Allocation of division general office expenses to state regional office division levels. Current Provider Colorado-Kansas Division operating division general office of Service Current Use of Colorado-Kansas Operating Division state office divisions. Service Basis for allocation Costs are allocated to the applicable state regional office divisions in total based on the Composite Factor. The Composite Factor is the simple average of three percentages: (1) The percentage of Gross Direct Property Plant and Equipment in each state as a percentage of the total Direct Property Plant and Equipment in Colorado Kansas Division. (2) The number of customers in each state as a percentage of the total number of customers ln Colorado-Kansas Division. (3) The total direct O&M expense in each state as a percentage of the total dlrect O&M expense in Colorado-Kansas Division. General Ledger Entries: Example Only General Office General Office General Office CO/KS BU 060 SSU-Div002 SSU-Div 002 Office Supply Cash Accounts Payable and Expenses * Acct. 131 Acct. 232 Acct. 921 $50011) ,. (1) $50011) ,. (1) $50, General Office State Div Office Rate Div Office CO/KS BU 060 CO/KS Div 031 CO/KS Div 080 Administrative Administrative Administrative Expenses Expenses Expenses Transferred Transferred Transferred Acct. 922 Acct. 922 Acct. 922 $25012) ,. (2} (2a) $25, $250(2a) * Many O&M expense accounts exist in addition to 921 that get cleared out of account 922. Flow of Activity ,. (1) Purchase Office Supplies - Colorado/Kansas Divlsion General Office ,. (2} Allocating General Office Expenses to State Division Office - 50% Allocation rate for illustration purposes only (2a)Altocation to remainlng state office 22 Attachment JLS-1 Page24 of72 Service: Colorado-Kansas Division state regional office division level expenses to rate division level Description: Allocation of state regional office division level expenses to rate division levels. Current Provider Colorado-Kansas Division regional division office of Service Current Use of Colorado-Kansas Division rate divisions Service Basis for allocation Costs are allocated to the applicable rate divisions in total based on the Composite Factor. The Composite Factor is the simple average of three percentages: (1) The percentage of Gross Direct Property Plant and Equipment in each state rate division as a percentage of the total Direct Property Plant and Equipment in each state. (2) The number of customers in each state rate division as a percentage of the total number of customers in each state. (3) The total direct O&M expense in each state rate division as a percentage of the total direct O&M expense in each state. General Ledger Entries: Example Only State Div Office General Office General Office CO/KS BU 060 SSU-Div002 SSU-Div 002 Office Supply Cash Accounts Payable and Expenses * Acct.131 Acct. 232 Acct. 921 $500~1) ,. (1) $500~1) ,. (1) $50, State Div Office Rate Div Office Rate Div Office CO/KS BU 060 CO/KS Div 033 ** CO/KS - Remaining Administrative Administrative Administrative Expenses Expenses Expenses Transferred Transferred Transferred Acct. 922 Acct. 922 Acct. 922 $200~2) ,. (2) (2a) $30, $300 (2a) *Many O&M expense accounts exist in addition to 921 that get cleared out of account 922. ** Many rate division offices exist within the state in addition to Div 033. Flow of Activity ' (1) Purchase Office Supplies - Colorado/Kansas State Division Office ,. (2) Allocating State Divisoin Office Expenses to Rate Division Office - 40% Allocation rate for illustration purposes only (2a) Allocation to remaining division offices 23 Attachment JLS-1 Page 25 of72 Service: Kentucky/Mid-States Division operating division general office O&M, depreciation and taxes other than income taxes, to rate division level Description: Allocation of operating division general office expenses to rate division levels Current Provider Kentucky/Mid-States Division operating division general office Of Service Current Use of Kentucky/Mid-States Division rate divisions Service Basis for Costs are allocated to the applicable rate divisions In total based on the Composite allocation Factor. The Composite Factor is the slmple average of three percentages: (1) The percentage of Gross Direct Property Plant and Equipment in each rate division as a percentage of the total Direct Property Plant and Equipment in Kentucky/Mid-States Division. (2) The number of customers in each rate division as a percentage of the total number of customers in Kentucky/Mid-States Division. (3) The total direct O&M expense In each rate division as a percentage of the total direct O&M expense in Kentucky/Mid-States Division. See Page 25 for General Ledger Entries: Example Only. 24 Attachment JLS-1 Page26 of72 General Ledger Entries: Example Only General Office General Office General Office Mid States - Div 091 SSU-Div002 SSU-Div 002 Office Supply Cash Accounts Payable and Expenses • Acct. 131 Acct. 232 Acct. 921 $500~1) ,. (1) $500 $500 (1) ,. (1) $400~5) ,. (5) $400 $400~5) $501 General Office Rate Div Office Rate Div Office Mid States - Div 091 Mid States Div 009 •• Mid States -Remaining Administrative Administrative Administrative Expenses Expenses Expenses Transferred Transferred Transferred Acct. 922 Acct. 922 Acct. 922 $200r(2) ,. (2) (2a) $300 (2a) i General Office Rate Div Office Mid States - Div 091 Mid States - Div 091 Mid States Div 009 •• Depreciation Exp Accumulated Depreciation Depreciation Exp Acct. 403 Acct.108 Acct. 403 ,. (3) $15~4) $100~3) ,. (4) $85 (4a) $151 General Office Rate Div Office Rate Div Office Mid States - Div 091 Mid States Div 009 •• Mid States -Remaining Taxes Other than Taxes Other than Taxes Other and Income Taxes Income Taxes Depreciation Acct. 408.1 Acct. 408.1 Acct. 408.1 and 403 ,. (5) $400 $100 (6) ,. (6) $ (4a) $851 $300 (6a) 1001 (6a) $300 • Many O&M expense accounts exist in addition to 921 that get cleared out of account 922. •• Many rate division offices exist in addition to Div 009. Flow of Activity ' {1) Purchase Office Supplies - Mid States Division General Office ,. (2) Allocating General Office Expenses to Rate Division Office - 40% Allocation rate for illustration purposes only {2a) Allocation to remaining division offices " (3) Monthly Depreciation Expense is booked through Powerplant and interfaces with the Oracle general ledger. ,. (4) Allocation from Division 091 - Mid States General Office to Mid States Rate Divisions - Allocated using the composite factor. (4a) Allocation to remaining division offices " (5) Taxes Other than Income Taxes incurred ,. (6) Allocating General Office Expenses to Rate Division Office - 25% to Mid States Rate Division Office - for illustration purposes only (6a} Allocation to remaining division offices 25 Attachment JLS-1 Page 27 of72 Service: Louisiana Division operating division general office O&M, deprecation and taxes other than income taxes, to rate division level Description: Allocation of operating division general office expenses to rate division levels Current Provider Louisiana Division operating division general office of Service Current Use of Louisiana Division rate divisions Service Basis for Costs are allocated to the applicable rate divisions in total based on the allocation Composite Factor. The Composite Factor is the simple average of three percentages: (1) The percentage of Gross Direct Property Plant and Equipment in each rate division as a percentage of the total Direct Property Plant and Equipment in Louisiana Division. (2) The number of customers in each rate division as a percentage of the total number of customers in Louisiana Division. (3) The total direct O&M expense in each rate division as a percentage of the total direct O&M expense in Louisiana Division. See Page 27 for General Ledger Entries: Example Only. 26 Attachment JLS-1 Page 28 of72 General Ledger Entries: Example Onl}". General Office General Office General Office LA- Div 107 SSU-Div 002 SSU-Div 002 Office Supply Cash Accounts Payable and Expenses* Acct. 131 Acct. 232 Acct. 921 $500 ~1) ,. (1) $500 $500 (1) ,. {1) $400~5) ,. (5) $400 $400~5) $5001 General Office Rate Div Office Rate Div Office LA- Div 107 LA Div007 LA Div007 Administrative Administrative Administrative Expenses Expenses Expenses Transferred Transferred Transferred Acct. 922 Acct. 922 Acct. 922 $200\2) ,. (2) $2001 (2a) $300 (2a) ~1 General Office Rate Div Office LA- Div 107 LA- Div 107 LADiv007 Depreciation Exp Accumulated Depreciation Depreciation Exp Acct. 403 Acct. 108 Acct. 403 ,. (3) $1001 $15\4) $100\3) ,. (4) $85 (4a) (4a) '"I$85 General Office Rate Div Office Rate Div Office LA- Div 107 LA Div 007 LA Div 007 Taxes Other than Taxes Other than Taxes Other and Income Taxes Income Taxes Depreciation Acct. 408.1 Acct. 408.1 Acct. 408.1 and 403 ,. (5) $400.00 $100 (6) ,. (6) $ (4a) $300 (6a) 1001 (6a) $300$851 *Many O&M expense accounts exist in addition to 921 that get cleared out of account 922. Flow of Activity "' (1) Purchase Office Supplies - LA Division General Office ,. (2) Allocating General Office Expenses to Rate Division Office - 40% Allocation rate for illustration purposes only (2a) Allocation to remaining division offices ,. {3) Monthly Depreciation Expense is booked through Powerplant and interfaces with the Oracle general ledger. ,. (4) Allocation from Division 107 - LA General Office to LA Rate Divisions -Allocated using the composite factor. (4a) Allocation to remaining division offices ,. (5) Taxes Other than Income Taxes incurred ,. (6) Allocating General Office Expenses to Rate Division Office - 25% to LA Rate Division Office - for illustration purposes only (6a) Allocation to remaining division offices 27 Attachment JLS-1 Page 29 of72 Description of Relationship between Mid-Tex and Atmos Pipeline - Texas: Mld-Tex performs operations and maintenance and capital services for the Atmos Pipeline - Texas ("APT') Divlsion. Services are provided on an ongolng basis throughout the Mid-Tex and APT service areas. The field operations include, but are not limited to, services related to pipeline integrity, measurement, compliance work, painting, right of way mowing and reclamation, leak surveys, patrolling, regulator maintenance, fence replacements, line repairs and line replacements. Additionally, Technical and Support Services are provided to APT by centralized departments primarily located at the Mid-Tex headquarters in Dallas. These centrallzed functions include, but are not limited to, compliance monitoring and reporting, gas measurement, finance and human resources. APT employs outside contractor labor services and purchases materials and supplies for field operations and construction in addition to the services provided by Mid-Tex. These services and materials are direct charged to APT and are not allocated from Mld-Tex. APT employs some pipeline only personnel. This labor and the related benefit cost is primarily charged directly to APT and not allocated from Mid-Tex. Service: Mid-Tex/Atmos Pipeline-Texas Division - lntracompany Labor Description: Mid-Tex employees' labor supporting APT operations Current Provider Mid-Tex Of Service Current Use of Service Atmos Pipeline - Texas Basis for The Operational Split is calculated each fiscal year based upon budgeted allocation non-supervisory employee labor and contract labor for the Mid-Tex and APT divisions. Mid-Tex supervisory and support employees (finance, human resources, etc) who charge time to APT generally use the operational split. Mid-Tex non-supervisory employees who charge time to APT generally record their time through the time reporting system. 28 Attachment JLS-1 Page 30 of72 General Ledger Entrv: Supervisorv employee !Example Only) Mid-Tex BU 080 SSU-Div002 SSU-Dlv 002 O&M Labor Acct. 853 Cash Accounts Payable Cost Center 4XXX Acct. 131 Acct. 232 (2) $200 I$1.000 (1) (1) $1,000 $1,000 (2) APT BU 180 Mid-Tex BU 080 APT BU 180 Construction work O&M Labor Construction work In Progress Acct. 853 In Progress Acct. 107 Cost Center 9XXX Acct. 107 Cost Center 9XXX (2) $ 250 (2) $150 Flow of Activitv: (1) Pay Mid-Tex Supervisory employee (2) Allocate labor to Mid-Tex and APT-for illustration purposes, this employee's time is charged 60% to Mid-Tex and 40% to APT. The APT portion is 63% capital. General Ledger Entry: Non Supervisory emplovee SSU-Div002 SSU-Div002 O&M Labor Acct. 853 Cash Accounts Payable Cost Center 4XXX Acct. 131 Acct. 232 (2) $400 I$800 (1) (1} $800 $800 (2) APT BU 180 APT BU 180 Construction work O&M Labor In Progress Acct. 853 Acct. 107 Cost Center 9XXX Cost Center 9XXX (2) $ 100 (2) $300 Flow of Activity: (1) Pay Mid-Tex employee labor (2) Direct charge labor to Mid-Tex and APT - for illustration purposes, this employee's time for this payroll cycle was 50% Mid-Tex and 50% APT. The APT portion was 25% capital and 75% expense. 29 Attachment JLS-1 Page 31 of72 Service: Mid-Tex/Atmos Pipeline - Texas Division - Non Labor Expenses Description: Allocation includes but is not limited to rents, heavy equipment, utilities, telecom, transportation (vehicles), uniforms, insurance, printing and postage. Current Mid-Tex Provider Of Service Current Use of Atmos Pipeline - Texas Division Service Basis for Factors are primarily based on direct employee labor and contractor labor. The vehicle allocation allocation is based on Company labor only. Allocations vary based on the cost center and sub account. General Ledger Entries: Transportation Expense (Example Only) Mid Tex BU 080 SSU-Div002 SSU-Div002 O&M Transportation Cash Accounts Payable Acct. 853 Acct.131 Acct. 232 Cost Center 4XXX I $1.000 ,, ) ,.. (1) $1,000 $1,000 (1) "(1) $1,000 $780 (2) APT BU 180 I APT BU 180 CWIP O&M Transportation Acct.107 Acct. 853 Cost Center 9XXX Cost Center 4XXX ,.. (3) ,.. (2) $220 ~3) Flow of Activity ,. (1) $1000 in transportation expense " (2) $780 is allocated from Mid-Tex O&M to APT O&M "" (3) A portion of the cost is capitalized, for illustration purposes only (22%) 30 Attachment JLS-1 Page 32 of72 Service: lntercompany labor Descrlptlon: To the extent operating division employees provide labor services to an affiliate, the labor costs for the services will be charged to the appropriate affiliate. Current Provider Atmos Pipeline -Texas Division of Service Louisiana Division Colorado-Kansas Division Kentucky/Mid-States Division Mid-Tex Division Mississippi Division West Texas Division Current Use of UCG Storage, Inc. Service Atmos Energy Louisiana Industrial Gas, LLC WKG Storage, Inc. Trans Louisiana Gas Pipellne, Inc. Trans Louisiana Gas Storage, Inc. Basis for Labor charges are captured through direct time sheet entries and transferred allocation to the appropriate subsidiary receiving the labor services. General Ledger Entries: Example Onlv SSU BU010 SSU BU010 SSU BU 010 Cash AIR from Assoc Co. Accounts Payable Acct. 131 Acct.146 Acct. 232 $500 (2a) (2b) (2a) $5001 $500 (2b) Atmos Energy Services AES BU 301 IMid States BU 050-Div 002 I Mid States BU 050-Div 091 Mains & Services Exp AIR from Assoc Co. Accounts Payable Acct. 8740 Acct.146 Acct. 232 {1) $5001 $500 (2b) (2b) $5001 $500 (1) I Flow of Activity (1) Employee X is a Kentucky Employee. He worked on a special project in March for Atmos subsidiary, AES {Atmos Energy Seivices). Time is captured through a direct time sheet entry. (2a) Salary is paid to employee x (2b) JE is made to relieve payable in operating division. lntercompany Entry generated by Oracle to keep Operating Divisions in sync. 31 Attachment JLS-1 Page 33 of72 Service: Adjustments to Uncollectible Accounts Expense Description: Allocation of additional expense amounts booked to adjust the Provlsion for Uncollectibles (Account 144) Current Provider West Texas Division rate divisions of Service Louisiana Divlsion rate divisions Kentucky/Mid-States Division rate divisions Colorado-Kansas Division rate divisions Mid-Tex Division rate division Mississippi Division rate division Current Use of West Texas Division rate divisions Service Louisiana Division rate divisions Kentucky/Mid-States Division rate divisions Colorado-Kansas Division rate divisions Mid-Tex Division rate division Mississippi Division rate division Basis of Intra Costs are allocated to the rate divisions in total based on Sales Revenue. company Allocations General Ledger Entries: Example Onlv Rate Division • Rate Division Rate Division Accumulated Provision Customer Accounts - Cistpmer Accpimts for Uncollectible Accounts Uncollectible Accounts Receivable Acct. 144 sub aaaaa Acct. 904 Acct. 142 sub bbbbb (2) $ 250 r 1.000 111 (1) $ 250 {2) • Each rate division has a different allocation rate. Flow of Activity (1) Monthly allocated costs. (2) Write off of uncollectible accounts as needed. 32 Attachment JLS-1 Page 34 of72 Service: Intra-company labor allocation - other than operating division general office labor Description: Certain employee activities cross multiple rate dlvislons wlthin an operating division. The costs associated with such activities include labor, benefits and associated taxes. Current Provider Atmos Pipeline- Texas Division of Service West Texas Division Louisiana Division Kentucky/Mid-States Division Mld-Tex Division Colorado-Kansas Division Mississippi Division Current Use of Atmos Pipeline - Texas Division Service West Texas Division Louisiana Division Kentucky/Mid-States Division Mid-Tex Division Colorado-Kansas Division Mississippi Division Basis of Intra Labor associated with cross-jurisdictional activities is charged to each company jurisdiction based on the level of employee activity. The costs are captured Allocations either through direct time sheet entries or fixed labor distribution percentages. General Ledger Entries: Example Only SSU BU 010 SSU BU010 SSU BU 010 Cash AIR from Assoc Co. Accounts Payable Acct.131 Acct.146 Acct. 232 $500 (2a) (2b} 1 (2a) 1 $500 (2b) Kentucky Division Tennessee Division Mid-States BU 050-Div 009 Mid-States BU 050-Div 093 I Mid-States BU 050-0iv 002 I I Mid-States BU 050-Div 091 I Mains & Services Exp Mains & Services Exp AIR from Assoc co. Accounts Payable Acct. 8740 Acct. 8740 Acct. 146 Acct. 232 r (1) r (1) ~, $500 (2b) (2b) $500r (1) 1 I 1 Flow of ActMt,y r (1) Employee x li1i0s in Kentucky and works 50% in Kentucky and 50% in Tennessee e1i0ry month. Time is captured through fixed labor distribution (2a} Salary is paid to employee x (2b) JE is made to relie1i0 payable in operating dilAsion. lntercompany Entry generated by Oracle to keep Operating DilAsions in sync 33 Attachment JLS-1 Page 35 of 72 Service: Other income and interest expense (All below the line accounts) Descrlption: Allocation of Shared Services' other Income and interest expense (All below the line accounts) Current Provider Shared Services of Service Current Use of West Texas Division Service Louisiana Division Kentucky/Mid-States Division Mid-Tex Division Colorado-Kansas Division Mississippi Division Atmos Pipeline - Texas Division Basis for Interest Expense, Interest Income and Other Non-Operating Income in shared allocation services are allocated to each utility division based on the budget allocatlon percentages. The budget allocation is based on projected average net investment by rate division for the budget year. For this purpose, 'net investment' is defined as regulatory rate base + goodwill. These allocation factors are the same throughout the fiscal year. The allocation stays in the account the charge was originally booked in. Headquarter allocation of below the line accounts to rate divisions follows the same process as described above. See page 36 for General Ledger Entries: Example Only. 34 Attachment JLS-1 Page 36 of72 General Ledger Entries: Example Only SSU BU 010 Div 033 SSU BU010 SSU 8U010 Interest and Interest and Cash Account'S Receivable Dividend Income Dividend Income Acct 131 Acct 143 Acct 419 Acct 419 .. (1) $1,000'(1) '(2) $1,000'(11 $20 1 $1,0001 $1,0001 $201 I SSU BU 010 SSU BU 010 SSU BU010 Div033 Cash Account'S Receivable Other Deductions• Other Deductions Acct 131 Acct 143 Acct 426.5 Acct 426.5 $2,000'(3) .. (3) $2,000'(3) '(3) $40.(4) '(4) I $2,0001 $2,0001 $401 SSU 8U010 SSU 8U010 SSU BU 010 Div033 Cash Accounts Receivable Interest Expense Interest Expense Acct 431 Acct 431 Acct 131 Acct 143 {Short Term) .. (5) $3,000'(5) $3,0001 $3,000'(5) '(5) $12'(6) '(s) $ ...~,.r·ml I $0001 SSU BU010 Div 033 Interest Expense Interest Expense Acct 431 Acct. 431 Lon Tenn Lon Term '(s) $2,400 $48 (6) '(e) $ 48 • Includes 1oarious accounts but cleared out of account 426.5 Flow of Activity r (1) Interest and Di'vidend Income generated r (2) Allocating Shared Serlices Income and Di'vidend Income to Div 33 only - Assume 2% allocation rate .. (3) Other Income and Expenses generated r (4) Allocating Shared Serlices Other Deductions to Div 33 only - Assume 2% allocation rate r (5) Interest Expense generated r (6) Allocating Shared Ser\ices Interest Expense to Div 33 only - Assume 2% allocation rate 35 Attachment JLS-1 Page 37 of72 Service: Gas cost between state jurisdictions for contiguous systems Description: Gas costs that apply to contiguous systems that cross state jurisdictional boundarles are allocated between those rate jurisdictions. Current Provlder West Texas Division of Service Colorado-Kansas Division Kentucky/Mid-States Division Current Use of West Texas Division Service Colorado-Kansas Division Kentucky/Mid-States Division Basis of Allocations are based upon throughput for the West Texas Division and the Allocations Colorado-Kansas Division's Southeast Colorado/Southwest Kansas operations. For the Colorado-Kansas Division's Kansas system and for the Kentucky/Mid-States Division, demand costs are allocated based on peak-day requirements. Commodity costs are allocated based upon throughput. Atmos Energy Corporation General Ledger Entries: Gas Costs between state jurisdictions for contiguous systems (Example Only) SSU BU 010 SSU BU 010 Cash Accounts Payable Acct.131 Acct. 232 $1,000 (1) (1) $1,0001 $1,000 (2) Various BU's & Svc Areas Natural Gas City Gate Purchase Acct. 804 (2) $1,0001 (1) Gas cost incurred (2) Gas cost paid 36 Attachment JLS-1 Page 38 of 72 Service: Gas storage services between an operating division and an affiliate Description: To the extent an operating division stores gas in a storage field owned by an affiliate, a rental fee for the use of the storage field shall be charged by the affiliate. Current Provider UCG Storage, Inc. of Service WKG Storage, Inc. Current Use of Kentucky/Mid-States Division Service Basis for The annual demand charge between UCG Storage, Inc. and Atmos Energy allocation Corporation (Tennessee operations only) is calculated based on fiscal year plant in service, gas inventory, actual operational costs incurred, and application of revenue and cost of capital conversion factors based on prior regulatory approval. In the calculatlon of the demand charge, costs not specifically related to a designated area are allocated to each affiliate based on the percentage of total plant servicing that affiliate. The annual demand charge between WKG Storage, Inc. and Atmos Energy Corporation (Kentucky operation only) is based on services provided at actual cost, market rate or as otherwise provided under tariff or contract. General Ledger Entries: Example Only WKG Storage BU 233 KY/Mid-State BU 050, Div 009 Other Gas Revenues Transportation to City Gate Acct. 495 Acct. 8580 I $100 (1) (1) $100 I WKG Storage BU 233, Div 002 KY/Mid-State BU 050, Div 002 AIR from Assoc Co. AIR from Assoc Co. Acct.146 Acct. 146 (2) $100 I I $100 (2) Flow of Activity - East Diamond Storage Facility 1 Monthly demand charge for the East Diamond Storage Facility 2 lntercompany Entry generated by Oracle to keep Operating Divisions in sync UCG Storage BU 232 KY/Mid-State BU 050, Div 009 Other Gas Revenues Other gas supply expenses Acct. 495 Acct. 813 I $100 (1) (1) $100 I WKG Storage BU 232, Div 002 KY/Mid-State BU 050, Div 002 AIR from Assoc Co. A/R from Assoc Co. Acct.146 Acct.146 (2) $100 I $100 (2) Flow of Activity - Barnsley Storage Facility 1 Monthly demand charge for the Barnsley Storage Facility 2 lntercompany Entry generated by Oracle to keep Operating Divisions in sync 37 Attachment JLS-1 Page 39 of72 Service: Working capital funds management (lntercompany account) Description: Funds are invested on behalf of or provided to affiliates based on operations. Current Provider of Atmos Energy Atmos Energy Service: Corporation Holdings, Inc. ' Atmos Energy Atmos Energy Current Use of Service: Holdinqs, Inc. Corporation Interest Income/Expense Calculation (See Below) A B Basis for Interest income or expense is recognized each month at the subsidiaries' allocation level based on the total average outstanding balance of all intercompany receivable/payable balances using the following rates: A (AEH is the borrower) Expense - One month LIBOR (last day of the month) plus 300 basis points Income - One month LIBOR (last day of the month) B (AEC is the borrower) Expense - The lowest outstanding CP rate or the Eurodollar rate under the AEC Credit Facility (RBS), which is LIBOR plus 100 Income - One month LIBOR (last day of the month) Atmos Energy Corporation General Ledger Entries: Working Capital Funds Management (Example Only) SSU BU 010 Interest and Dividend Income Acct. 419 $1,000 (1) AEH BU 312 Other Interest Expense Acct. 431 (1) $1.000 I (1) Interest Income and/or expense is recognized each month at the subsidiaries' level 38 Attachment JLS-1 Page 40 of72 Service: Gas storage services provided between affiliates Description: To the extent an affiliate stores gas in a storage field owned by another affiliate, a fee for the use of the storage field shall be charged. Current Provider Trans Louisiana Gas Storage, Inc. of Service Current Use of Trans Louisiana Gas Pipeline, Inc. Service Basis for The fee to the affiliate utilizing the storage service is based on services allocation provided at actual cost, market rate or as otherwise provided under tariff. General Ledger Entries: Example Only BU 234 BU234 Accounts Receivable from Revenue Transportation ~ Associated Company Industrial Acct.146 Acct. 4896 $10~ $100 BU 303 BU303 Accounts Receivable from Associated Company Other Gas Supply Expense Acct.146 Acct. 813 $100 $1001 39 Attachment JLS-1 Page41 of72 Service: Property Insurance Description: Blueflame Insurance Services, LTD provides a direct property lnsurance policy. The policy covers the property against all risks of direct physical loss or damage. Current Provider Blueflame Insurance Services, LTD of Service Current Use of Kentucky/Mid-States Division Service Colorado-Kansas Division Shared Services Louisiana Division Mississippi Division Mid-Tex Division West Texas Division Atmos Pipeline - Texas Division Atmos Energy Louisiana Industrial Gas, LLC Atmos Exploration & Production, Inc. Atmos Energy Services, LLC Atmos Power Systems, Inc. Trans Louisiana Gas Pipeline, Inc. Trans Louisiana Gas Storage, Inc. UCG Storage, Inc. WKG Storage, Inc. Atmos Gathering Company, LLC Basis for Atmos Energy Corporation is invoiced by Blueflame Insurance Services. allocation Costs are allocated based on the gross property, plant and equipment and gas stored underground balances of each affiliate at a rate division level. Genpml I pdner Entries• Fxamnlp Only SSU BU 010 ssu au 010 SSU BU010 Cash A.::i:::ounb Pav-i!!bl Generae Offico COIKS BU 060 Propertv lns-uranco Acct 924 (2) (3) Flow of Activity (1 ) Purchase of propecty insurance (3) Amounts remain!ng in S:SU -cost cenlers are:altocated to the dlvl~onsuslng the method described on pages 14and15. 40 Attachment JLS-1 Page 42 of 72 Service: lntercompany Interest on Notes Payable Description: lntercompany Interest on Notes Payable Current Provider Shared Services Of Services Current Use of Atmos Energy Holdings, Inc. Service Current Provider of Atmos Energy Atmos Energy Service: Corporation HoldinQs, Inc. Atmos Energy Atmos Energy Current Use of Service: Holdings, Inc. Corporation Interest Ince.me/Expense Calculation (See Below) A B Basis for Interest income and expense is recognized each month at the subsidiaries' allocation level using the following rates: A (AEH is the borrower) Expense- One month LIBOR (last day of the month) plus 300 basis points Income - One month LIBOR (last day of the month) B (AEC is the borrower) Expense - The lowest outstanding CP rate or the Eurodollar rate under the AEC Credit Facility (RBS), which is LIBOR plus 100 Income- One month LIBOR (last day of the month) General Ledger Entries: Example Only Shared Services Shared Services Accounts Receivable from Interest on Debt to Associated Associated Company Companies Acct. 146 Acct. 431 I $1.000 (1) (1) $1.000 I Atmos Energy Holdings, Inc. Atmos Energy Holdings, Inc. Accounts Receivable from Associated Company Interest and Dividend Income Acct.146 Acct. 419 (1) $1.000 I I $1.000 (1) Flow of Activity (1) lntercompany Interest on Notes Payable is recognized each month at the subsidiary level. 41 Attachment JLS-1 Page 43 of 72 VIII. If the utility believes that specific cost assignments or allocations are under the jurisdiction of another authority, the utility shall so state in its CAAM and give a written description of the prescribed methods. Nothing herein shall be construed to be a delegation of the Commission's ratemaking authority related to those assignments or allocations. Cost allocations and assignments of shared services cost are subject to the regulations of 8 state commissions, as well as city officials in Texas. As such, the Company's allocation methodologies are designed to meet the ratemaking requirements of each of those states. It is not the Company's intent to assign or allocate costs in such a manner that would cause any of the state regulatory jurisdictions to delegate ratemaking authority related to cost assignment or allocation. IV. (4504) FULLY DISTRIBUTED COST STUDY a. The utility shall submit its fully distributed cost study in both electronic and paper format simultaneously with filing its CAAM for all Colorado divisions and activities. Please see the electronic copy of the Excel file titled "FDCS - Inc Stmts Mar17 as filed.xis" (Appendix A, Attachment 3) and also the submission of the paper copy entitled "ATMOS ENERGY CORP Fully Distributed Cost Study". The paper copy includes all of the workpapers along with cross referencing for each page within the FDCS and a cross reference of the workpapers to the applicable CAAM sections. b. The utility shall prepare a FDC study that identifies all the non-regulated activities provided by each division in Colorado. Please reference the index in the fully distributed cost study for Page Nos. 2 and 5-6. The FDC study shall show the revenues, expenses, assets, liabilities and ratebase items assigned and allocated to each non-regulated activity. Atmos provides only regulated natural gas delivery services to its customers in Colorado. If the utility has more than one division (e.g., gas, electric, thermal or non-utility) in Colorado, the FDC study shall include a summary of all assigned and allocated costs by division. Please reference the index in the fully distributed cost study for Page No. 13 by rate division. c. In preparation of its FDC study, the utility shall complete an analysis of each Non-regulated activity to identify the costs that are associated with and/or should be charged to each non-regulated activity to ensure each non-regulated activity is assigned and allocated the appropriate amount of revenues, expenses, assets, liabilities and ratebase items. 42 Attachment JLS-1 Page 44 of72 As stated in section 4504(b), the Company only provides regulated natural gas delivery services to its customers in Colorado and does not provide any nonregulated services. d. If the CAAM is filed in connection with a rate case, the FOG study shall be based on the same test year used in the utility's rate case filing. The utility's FOG study shall include revenues, expenses, assets, liabilities and ratebase items in order for the Commission to determine if all appropriate revenues, expenses, assets, liabilities and ratebase items have been appropriately assigned and allocated, and to determine the utility's compliance with the principles established in rule 4502. For each assignment and allocation the utility shall: (I) Identify the revenues, expenses, assets, liabilities and ratebase items by account number, sub-account number and account description; and Please reference the index in the fully distributed cost study for Page Nos. 16-18. (II) For each account in (/) above, identify the assignment and a/location method used to assign and allocate costs in sufficient detail to verify the assignment and a/location method used to assign and allocate costs to Colorado divisions and activities is accurate and consistent with the utility's CAAM methodology and reference the CAAM section that describes the a/location. Please reference the CAAM, Appendix A, Attachment 2, Word document "Colorado CAAM Section 4504(d)(ll).doc" (Ill) Provide the test year dollar itemized amounts of revenues, expenses, assets, liabilities and ratebase assigned and allocated to each Colorado division and non regulated activity; the itemized amounts assigned and allocated to the Colorado utility for regulated activities; the itemized amounts assigned and allocated to the Colorado utility for Colorado non-regulated activities; and the itemized amounts assigned and allocated to other jurisdictions. Please reference the index in the fully distributed cost study for Page Nos. 1-3. e. Each utility shall maintain all records and supporting documentation concerning its FOG study for so long as such study is in effect or are subject to a complaint or a proceeding before the Commission. Records are maintained at Atmos Energy Corporation headquarters located at 5430 LBJ Freeway, Dallas, TX 75240. V. (4505) DISCLOSURE OF NONwREGULATED GOODS AND SERVICES Whenever a Colorado utility engages in the provision or marketing of non-regulated goods or services in Colorado that are not subject to Commission regulation, and the Colorado utility's name or logo is used in connection with the provision of such non-regulated goods and services in Colorado, there must be conspicuous, clear and concise disclosure to prospective customers that such non-regulated goods and services are not regulated by the Commission. 43 Attachment JLS-1 Page 45 of72 Such disclosure to prospective customers in Colorado shall be included in all Colorado advertising or marketing materials, proposals, contracts and bills for non-regulated goods and services, regardless of whether the Colorado utility provides such non-regulated goods or services in Colorado directly or through a division or affiliate. Please reference section 4502{h). 44 Attachment JLS-1 Page 46 of72 Appendix A 45 Attachment JLS-1 ATTACHMENT 1 Page47 of72 ATMOS:· energyj ATMOS ENERGY CORPORATION -January 1, 2017 .... __ L _____ L ______L__[ _____ , __, ...... [______:, ,...... J...... ~------[ __L__ ___ r------J ______; ! Atmos Pipelirie- i : Colorad.o-Kaosas. : K~nluc~~d-State=i; l l !..oUl$jana i ! Mid-Tex DM&ian j ! fvlsefs:slpp Dhlfeion fr, --~:I;~:::---!:.· ~ Texas Divis.tan : -I Di'llislon !· D1"1ounon l : Dit.rision l l ~ : Diiision :------~------".'J :______:--~----~-..--.! - -- •MY -MMMM ~-M~MM_: : _MM MM MY -M --- YMJ :.------: -----~ ~------..... ~----~ -~. •------;------~. Almos EnergyHoldings, lne.(DelaWBre) r::,,.. -""-A~meimi Louisiana hi::l'uslrlal Gas,LLC (O/Maware) lEGEJ\ID: C"orpvr21tionzi: D EnlilyDiu'l!!!l.anled!f-orfedtm11Ta:ic PUi"poses,,butTreal!edas!t!p.;ira!lt!! En lily for Uability Purposes;; CJ ; Attachment JLS-1 ATTACHMENT 3 Page 48 of72 ATMOS ENERGY CORP. Fully Distributed Cost Study Index Twelve Months Ended March 31, 2017 Page Number Description 1 FDCS 2017 p1 2 FDCS 2017 p2 3 FDCS 2017 p3 4 Other Income Detail 5 Blue Flame Billed 6 Blue Flame CO Allocation 7 Acct 9220 Summary 8 Acct 4081 Taxes Other 9 4030 Depreciation Summary 10 Income Tax Summary 11 Atmos RUT (Utility and APT) IS FERC Fin Reporting 12 Net Plant in Service 13 Colorado Income Statement 12 months ended Mar 17 14 RUT Income Statement (Utility and APT) 12 months ended Mar 17 15 Total Company Income Statement 12 months ended Mar 17 16-18 Total Company Income Statement Detail Attachment JLS-1 ATTACHMENT 3 Page 49of72 Atmos Energy Corporation Fully Distributed Cost Study Twelve Months ended March 31, 2017 (a) (b) (c) (d) (•) rn (g) Colorado Colorado Colorado Non-Colorado Total Atmos Atmos NonulilUy Consolidated Atmos UH!ity Affiliate and Total Atmos Utility RUT Utility RUT and Consolidating Corp&Subs Jurisdicllonal NonUtility Subs (a+b=c) (a-o=dl (FERC form 2) Eliminations (•+f=g) Operating Revenues Operating Revenue 78,866,220 $ $ 78,866,220 2,285,556, 177 2,364,422,397 848,104,125 3,212,526,523 Transportation 2,570,375 2,570,375 180,974,101 183,544,476 (1,070,897) 182,473,579 Other Revenue 376,951 376,951 27,768,293 28,145,244 13,770,399 41,915,643 Realized Gas Trading Margin 1,599,797 1,599,797 Unrealized Gas Trading Margin (7,483,612) (7,483,612) lnlerseg:ment Elimination !93,280, 143! (93,280,143) Total Operating Revenues 81,813,546 81,813,546 2,494,298,571 2,576, 112, 117 761,639,669 3,337,751,786 Purchased gas cost 40,500,864 40,500,864 774,052,995 814,553,859 777,680,218 1,592,234,078 lntersegment EliminaUon - Gas Costs (93,280, 143) (93,280, 143) Total Purchased Gas Costs 40,500,864 40,500,864 774,052,995 814,553,859 684,400,075 1,498, 953,935 Gross profit 41,312,682 41,312,682 1,720,245,576 1, 761,558,258 77,239,594 1,838,797,852 Operating Expenses Operalion & Maintenance 15,485,316 176,495 15,661,811 531,708,378 547,370, 189 19,118,462 586,488,650 Depreciation a11d Amortization 9,286,980 9,286,980 292, 103,679 301,390,659 3,304,014 304,694,673 Taxes~ other than income laxes 2,506,746 2,506,746 227,641,646 230, 148,392 2,532,890 232,681,282 Total Operating Expenses 27,279,042 176,495 27,455,537 1,051,453,703 1,078,909,240 24,955,365 1, 103,864,605 Operating Income (Loss} 14,033,840 (176,495) 13,857,145 668, 791,873 682,649,018 52,284,229 734,933,247 Other Income (expenses) Interest Expenses (3, 127,816) (26,606) (3, 154,422) (113,845,620) (117,000,042) 1,110,655 (115,889,388) l11terest lncome 21,772 21,772 1,220,359 1,242,131 (436,720) 805,411 Other Nonoperating Income (•XP<>nse) !387,678! (387,678l (588,041! (955,719) 13,020,920 12,065,201 Total Other Income (Loss) (3,493,722) (28,606) (3,520,328) (113, 193,303) (116,713,631) 13,694,855 (103,018,776) Income (Loss) before Income Taxes 10,539,918 (203,101) 10,338,817 555,598,571 565,935,388 65,979,083 631,914,471 Provision {Bene-flt} for income taxes 3,555,183 3,555,183 201,348,329 204,903,512 31,818,258 236, 721, 770 Net Income (Loss) $ 6,984,736 $ (203,101) $ 6,781,634 $ 354,250,241 $ 361,031,876 $ 34,160,826 $ 395, 192, 701 Net Property Plant and Equip- bal 3131/17 $ 156,333,828 $ $ 156,333,828 $ 8,045, 178,404 $ 8,201,512,232 $ 37,460,385 $ 8,238,972,617 Atlachment JLS-1 ATTACHMENT3 Page 50 of72 Atmos Energy Corporation Colorado Affiliate and NonUtility Income/Expense Twelve Months ended March 31, 2017 Total Atmos BLUE FLAME PROPERTY INSURANCE Premium billed to Total Atmos $ 7,590,048 -$,---1""'7"'"6,-,-49""'5,.... Colorado - BlueFlame Insurance Allocation Attachment JLS-1 ATTACHMENT 3 Page 51 of72 A."1los EMrgy Cil!rpor.rlicn - Utility ~location lo Cala-rada Twolve M.onfus e11dei:f Mlilrdl 31. 2017 Al~c1i16on of U1ility :Stiared .Sl!l:l'\OOeo& O&M exp tic- Color~oJKiiln~5 General Offire Divl:sfm SO COIKSSO TolalSS ADr-S1m 2!a; Nciv·Dec Jaf!-Mar ~ !l!ll No:l/':,PBc ~ ~ !l!ll N1;1-v-Dei;i .Jan-M:ar Cot.t Cenler Cost C•.ntar Do&er5(!fian oer SSU 9220.40002 ··-- 1001 SS Oallas Preside-11t & GOO (•5.551) (5,504} (11,El10) (20,645) (1,"'6,240) (8'2,276~ (173,163) (397,419} Ei.81% 6.69'6. 6.82% 1tea% 1101 SS- Dlldla5- Chfef Flnan~al Officer ( Atmos Ene-rgy C-orPQr.i!liQr.i - Ul51ify Mlacadon to Calcrado Twelve M(]'nths ended Mllll'l:lh 31, 21l17 All.ocalia11 cf Utility Shared :SeNices. O&M exp 1c C~cf"ilclQ,IKq.n:sa-e GoMeml Omc:e DIYl!Sf.on 30 GOJKS30 TolalSS Faclor ~ QI!!; iNo!f-Dec JiilncMlilr ~ ~ ~ J\!N'"•:S!IQ .QI;! ~ ~ Cc:s~ Centar C:::ost CooOO.r [J&Qf!tiDn u ssu 9220..40002 ™ 1407 SS Callas Facllitie:s (65.<90] (8,474} (18,4"3) (24,560) [001,670) (126,654) !270,500) (361:,170) 6.81% 6.68%- 6.B2% a•O% 1'00 SS Oiiillae; Employee- De-v.e-lr;ipmeri.1 (n,654) [7,210) [26.27'l) (45.520) {1,069,956) [11J1.m) l'''"""'l (669,-486) 6..81% Ei.69'%. G.82% 6.lSo% 1414 SS Tech Training. DeliveJY [B8,387] [12,183] (25,581) ('7,004) {1,2!5-7,2·1M) {178,CIOFJ} !'""·""") c~o-.er;u) 7.03'JL 6.65$ 6,84$ 6.84'14. 1415 SST~ Ttalfllni;, Prog & CuITTculum (9,201) [1,509) (3,018) (4,400) (130,&85) (22,032} {44,123J tB4,322) 7.0391! 6.85%- 6.84'% 1l84% 1"11.fi SS Dallas Compa~sa~cn ancl HRMS (48,643) [M49] (12.876) (20,917) (714,2"8) {1!J:l,""3) (1"8,802) (907,600) 6.81% 6.69'%- 6.B'2% 6.80% 1420 SS DaUas EAPC [2,071) [211) (1.,426> ("'l ('3,6'1) (0.153) (20,010) (9<7) 6,81"Jli 6.69"J& s,a2"M!. 6.8o% 14"3 SS HR Benefit Varia11ce 25,610 (3,733) 10,728. (5,334) 376,065 (55,Bll5) 157,31l8 (71'448) 6.81% 6.69'%- 8.82'Jli, 0.80% 1501 SS Corporal& Legal (1:D8,ii37) [25,935] (59,213) (221,\Bll) ~2,913,002) ("87.... ) (S ..,226) (3,252,202) 6.81% 6.69'%- 6.82% 6.00% 1502 SS Co~porare. Seieretasy (27,{lSt) (20,620) [3.244) ,-44.887) (397,375) (!:IOB,W> (47,561) (66C,102) 6..1~1% 6.69'% 6.82% 6.80% 1500 SS Corpor:abt Governmanlal AO'ah (>9,008) (S,163) (S,as7) (12,<'6) (421,100) !'"."'l Cl>S,255) (181,814) 7.03% El.S5"Jli 6.S4"Jli. '6.8tj% 1504 SS Co~porallt :fl.oocrds flllanagemar;t (2..... ) (5.278) (B,355) ~12,082) (354,162) (77,047) !122,155) (176,SilQ) 7.Q3% 6.85'% 6.84'% 'fi.84% 1506 .SS CQrporabt Ga$ Connet Admlni5.tration [7,00S) (1,131) [2.330) (3.3'4) [100.... ) (tB,504) f34,H6J 149. [5,606,774] (617,820) :(1,666.-00SJ (2.935.176} (75,642:,8<18~ t11.21 a.a!i!Q) {22.55'2,853~ [-40,682,94~ Attachment JLS-1 ATTACHMENT 3 Page 53 of72 MTIO$ Enlllr:gy CQrpora1ia.n - UfilEty A51ooalian lo Colorado Twelve Mon01$ t-nded Mwch 31, 2017 Alk1cation of Utility Shared Se:rvk:es O&M exp ID Coloradon C:OJKS30 Total SS ~ Qm; Nov-Dec CG"S.t Center Cost Center O:escrip!ion « SSU 9Z!0..40002 C:Ol~S Tola! O&M - SSU and CSC A!Eacafion of O&M EirDBPlSB'S lo Colorado 12 mo Mar17 1'2moMad7 Ulllity ssurc.sc O&M exp alfocial!ed 'o CoKs Div 30 ~922] ~from aw .S 11,025,m ssu & csc $ 1.fi0.107,5"14 7.$!;i% Dinict CoKs Oiv3DO&M•xp :5,9oe.oas Tolal0hr300&Mvdlh:S:SU:andCSC $ 16,93l..Sf35 43.64% O&M illKp fmm Cfli GOJKS Ti:i181Ta:i:Other -S.SUqndCSC A!localicin cifTaJCes Other than lm::omct Ta'll:.es 12 rno fu'lar17 t2m(]'Mar17 Utility SSU/CSC Taxes Other allccated ta CoK;'S IJjv 30 (-4£J;!J1.41Xl02] $ i!iSO, 102" ssu & csc $ 7;524,248 7.31% Ol'ect Co!W ~Y30 T:aJCes Olher e:xp- 2Cl8,494 758,596 44.lB'OO Ta'X.'&s Other from Co Ks OivaOISSUIC:::SC::) aHoca.b;lo!!I to Colomdo (itoe $ ::a.35, 179 {aoc:t:4061,0931"ll09J.'451-4112Qf.rl1130) GOil(& rota! Oepr SSU and CSC AU0(21ian -of [Jepr·11.ciation Exp 12m(]'Mar17 ~ Uti6fy SSUICSC Depre-c &p alloc:a'b:ld to CerKS ~ol!Q30..t0002) $ 1.257,076 s 21.657 .732 5.8Q% Direiirt CuKs Di\/!SO Oepreclelicn E:lcp U!l3.607 $ 1.440,"383 -49.17% Depree exp from C(]'f<& (Div:i!O & SSUICSC) albeab9d to Colo~.ado (4t $- 708,362 (:aC>Ct41l3'1l.00:34'1 /41124/41129/i11130) ---- A!lcc.ll!lbl'I af Nat ProD!!!rty Plant and Equ1pml!lnf Nat:Plant Al!cc1aCakJ r ct.iii Net Plan! ro be alloeatacl 91'31t2017 ~ Utiitf SSUICSC net plantaRo-cared iCI Gerlorado s 9,002,599 ssu & csc :!; 33-0.000,.024 3.01'% CaKs CNVSO net plant albcaled 1a Calorada 443,2-40 COIKS Dlv30 1.042,735' "12.51% Ta!al UQ1it:y NetPtantAl~i::aWd'lo Cokirado $. 10."4Cl5,839 .$ 331,873,.559 Attachment JLS-1 ATTACHMENT 3 Page 54 of72 Atmo& Enorgy Coqmra!:lm Fully Dfstributed" C05-t S!l.ldy rwelve Mcmtf.is ended Mar.:h 31, 2017 (•l (bl (c) (d) (•) (ij i•l Coli:irado Ci:i!cirado Colorado Non-C"Olorado Total Almos Atmo$ Nanutilify Conoondatei:I Atmoo l.Jtiily Amli•O!ni:I Tatel Abnoa Ulilily RUT Ulillty'RUT ahd Consolld"a6ng C.ctp &Subs Jurlsdfc:IE-ona! NonUlilit:y Subs (a+b""C) (El-<:=d) (FERCfarm'2) Eliminations f.er1-f:>:g) Operating Revenues Opoer.iting ~eveQue 78,666,220 7e,s-ea,220 2,285,556,177 2,364,42:2;397 848,104,1215 :3,212,526,52:3 TranspCt'lation :2,570,375 2,~70,375 180,974,101 1"83,544,476 (1,070,897} 132,473,579 rnher Revenue 378,951 3-76,951 27.768,293 28,14~.24"1 1:3.770,398- 41,915,"'13 Re:aliil:ed G<1$ l'rai:li;ng Margin 1,59-9,797 1,599,797 Unreall%ed Gas Tra"'ing Mar.gin (7,483,812) (7,483,612.] lnteroegment Elimln:e:li-on {:51J,2i!I0,11'1JJ (OJ.<'0, 143) Tola! Oj:i-eraflng Revenues 81,813,546 B1,B1J,5.rl6 2,"1!M,29B,571 2,576, 112, 117 761 ,63"9,669 3,33-7,751,786 Pun::ha:s.ed g;;rF.; co~t 40,500,BS4 4a,5.00,884 774,052,995 814,5153,.859 777,63-0,21B 1,592,234,078 ~rrleraeament Elitrilnalf.oh - Gas Costs (93,200,143> (93,28D,143] Grossprolit 41,312,BEl2 41,J1:i!,li82 l.720,245, S70 i,761,SS.8,253 77,23'9,59'4 1,838,797,352 Oper.allng Exp.enses Operation & Malntensncia- 15,48-5,316 176,495 15,661,611 !5-31,701!1,376 547,:m~,169 19,11.U:,.rl-62 SEiB,4$8,sSCJ O~prv-r;;ialio:n ;;in~ Amcf.l~~Qfl 9,286,960 9,236,980 292, 103,679 301,390,659 3,304,014 304,694,673 Ta:ices - ra-th.e-r th.an inocime taxes 2,506,74a 2,506,746 127 ,641,646 230,14&,392. 2,532,890 232,681,2..82 Tot;;il Op1;1r;;1;tin91$:J;p1;111"Ees 27,279,042 17M9S 27,4:55,537 1,C-51,453,703 1,078,009,241'.) 24,955,:S-&5 1,103,864,605 Opera1ing lnm1me il055) 14,033,64D (176,49S) 13,857,14:5 668.791,873- 682,649,0HJ :5i2,'2!J.4,l29 734,933,247 Other Income (expenses) Regula~ry Detiibl- (407.3] 032,217) [1:32,217} (1"',217) (l.lllllilli} Regi,daito:ry C:ro!lldml (407..4) 23 23 247,260 247,303 0 247,303 Revenues from Nonutiltiy Operetions (-417) 34,797 34,797 5,419 40,2.17 Ml:sc:ellane'DUS Ni:inop-eratlng lnoome (42.1) 5,432 5,432 10,670,.812. 10,67Fl,244 11!19,:987 10,866,251 G:;;iin-on Oi!llposi'li~ of !Jraperty (421.1) 13,43-0;963 l3,..j30,963 L.oas on Disl)Osilion of Proper1y (421.2) (284,39\) (284,8:91) 0Dna1fons (426.1) (234,668) {234,6681 [3,103,36!5] {3,3:;1FJ,05J] r,.o;,01ei {l,384,B71) Po11=r:iahiflle{4W,JJ POOJ (\53) (1,350,363) (\,350,521) (\,'50,521) Expendilures for Certain Civic, PoliBcal and Re,.aterl Actil/ities (4~6.4) (48,392) (<0,392} (1,452,405) (1,500,797) {1,500,797] Other Derltrotiom;; (426.5) ~109,:91!5} [1CJ.1J,91!5t [5. 482.22!i1J :[.fi.592.144J (:?93,$41] {S,88El,Li85J [JS7,6'fa] '3:1!.7,676~ '567,710t [95:5,:.lBB] 13,020,:9'20 12,065,531 Provision {Bfnefi!) for income taxes 3555183 :;l,5~.1BJ ~01,34.S,3~ 2L'.t4,90351~ 31 81.8258 236,721,770 Revam.1as fram Merchandising, Jabbing and Conuatl W.ork ~416] (L.ess) CosW and Bxpen:se o~ Merohandfsing Job & C'Dntract Wcirk {415} 331 331 ~331J 331 331 ~a:n~ Interest and DiYEdeI1d Income (419) 21,m 21,n2 1,.22.0,359 1,242,131' [4'6,720) 805,411 lntere-:st on long-Term Debt {42.7) (2,081,646) [2.001,045) (1;0,1'37,719) (141.019,,.5) (141,619,365) Arncl'ti:;::alfon of Oebt l:Jis.c, a11d C;pense- (4ia) (>3,00J) ,33,053) [1,599,79B) {1,632,351) (1,632,35\) Amo1tEz:ation of las"B o-n Reacquired Debt (428.1 J (52,0S3) (52,053) (>,505,846) {2,557,902) {2,5S7,!il'C2) lnt.erest on llebt to Ass.aciated Campanl-es i43C] j26,BOO) (>0.006) (1,2B<.4BO) {1,311.0136) 1,3t1,0S6 (0) Otherlnteres• Eicpepse (431) (191,757] (101,757) 27,976,917 27,785,160 [2i::J:D,002] 27,584,498 (less) Allo-wance for BOl/DV'/i!l:d Funds. Ust:d Du1!ng Constr-1.!Cltlon-Credit ("132) 30,693 :.m,693 2,305,308 2,336,001 231 2,3:;16.232 [.3,127,316J f2B.B06~ [311 i:i4.422~ {11:;1,S4;:,62fJ] [117.0001042] 1,11:D,6S5 (115 .SB9,33B~ Atlachment JLS-1 ATTACHMENT 3 Page55 of72 Atmos Energy Corporalloo Fully Distributed C0&ot :Sltldy Twelve Mcmlhs ended Mereh 31, 2017 C•l (0) (c) (d) (•) (Q (g) Cola-1.adi:i Colorado Coloni1dc. Nl!lf1-C:clr;iradc lot.ii AtmQ$ Atmr;ie Nonu!ility C-c;neo!idat111:d Atmos UlllY AffiUateand Tole! Atmos Utility RUT Utility RUT and ConsoEidating Cotp& Subs Jurisdfc.lficinal NonUIRlity.Subs (a+b=c:) (<>=d) (FERCform2) E~mlnatf-ons (e~f=g) SUMMARY OTHER INCJEXP Operating Income (l.o&-s) 14,033,640 !176,405) 13,857,145 El88,791,B73 682,649,018 52,284,229 734,'933,247 lnt;eresi ~pel']ses ~3,127,61:ti) (;16,606) (3,154,4'2) (113,845,62(1} (1:17,00ll,t\42) 1,110,655 (115,389,3'88) Merchar.idiss (331) [3"1) (331) Interest looome 21,772 21,772 1,'22-0.3551 1.2'12.131 (436,7>0) aOS,411 Othollir Nr:inoperating Jpcomie (367,'67ol!l) (337,878] (567,710) {955,3-68] 1.3,020,9'20 12,065,531 Total Olher Income- (loss) (3,493,722) (20,896) (3,52.'D, 32-B) {113,193,303] (11ti.71J,Wl1) •.J.:t;i9<'l,6SS (103,011,776) Income (loss) be-r«e Income Ta:.:es 10,539,913 (203,101) 10,336,817 5S5,55HS,571 565;!ilJS,:3.6S 65,97£1.,IJ".U:J ••1.•1~.471 Proi.oisicn (Benoefil) for'" Income ta:i:es J,5:55,183 3,5155,183 201,343,329 2'1-4,903,512 31,31a,2:l)B '236,721,770 Net 1nccrne (L05 Net Propert)' Platit and Cqulpmet1t , 56,JJJ, ais 1.56,333,.823 8,201,512,232 $ 8,236,972,617 Net Plant Nlilt:Plmt WP FDCS 2017 p1 WP F[ICS 2017 p1 Compu1a1lon r:ir Ne! Properly Pl:a.nt & Eqt.ilp ~ Colorado Ju~sdtdiDnal e:rad of period balance- at 03J31t2a17 Gl'0$1l:fl!ant ~ CWIP 1010 10.BO Sh:rSo!!fV,Al!ac 9,98:2,599 f3,945,9:3:9) JS1,:9e7 :t;i,3""1,60?7 Div.30,Al!ix: il"l::J.240 (147,160) 27Q,47() 566,550 co.orrect. 245,993,31-1 cse,1ot1,232) 2,493,5n 14'9,aB2:,651 CQIO JL1risdic:flon:al.~='25"'6"',3".."''-"15;,;;0~='("'10'°3,"°1""'7,_,33;;,;1,,) _ __.3.., 1=32.,,,0=0=0~~~...:1.=56.,.,,=33=>,0=<=iB Notoe: The plant halari.-ces roar Co t:lir"llct are r:iet of .SSIR balances. Attachment JLS-1 ATIACHMENT3 Page56 of72 BlueFfame Account 9240 Sub Account 04069 fl:luefla;me P.rope1ty Insurance Amortl!aUon Companyrcost Center DescrlpUon Company APR-16 MAV-16 JUN~16 JUL-16 AUG-16 :S~P·16 ocr-16 NOV-16 DEC-15 JAN-17 FEB-17 MAR-17 Total SS Dallas Insurance • Cast Ce:n!e:r 1915 010 23,149 23,149 23,149 23,149 23,149 23,149 23,149 23,149 23,149 23,326 23,32.6 19,532 274,530 Almos Energy-Loufislana 020 50,324 50,324 50,324 50,324 50,324 50,324 50,324 50,324 50,324 50,706 50,706 51,662 606,100 AtmO$ En-ergy-West Texas 030 41,013 41,013 41,013 41;013 41,013 41,013 41,013 41,013 41,013 41,326 41,326 42,356 494,129 Atmos Energy-KY/Mk:l-States 050 67,240 67,240 67,240 67,240 67,240 67,240 67,240 67,240 67,240 67,991 67,991 67,944 609,009 Aimos Energy-Colorado-K:ansa:s 060 36,188 36,188 36,186 36,188 36,186 36,188 36,188 36,188 36,1BB 36,464 3S,4B4 35,674 434,293 Atmos Energy-Mississippi 070 30,310 35,::310 35,310 35,310 35,310 35,310 35,310 35,310 35,310 35,579 35,579 35,543 424,492 Atmos Energy-Mid-Tex 080 '2:a0,239 230,239 230,239 230.239 230.239 200.239 230.239 230.239 230,239 231,99.5 '2:31,995 2.34,657 2,770,695 A!mos. Pipeline~ Texas 180 138,782 136,762 136,782 138,782 138,782. 138,782 138,782 UB,782 136,782 139,841 139,841 151,262 1,660,003 Atmos Energy Marketing LLC 212 5.321 5,321 5,321 5,321 o,321 5,321 5,321 5,321 5,321 47,690 Attrl-0$ E"netg!{ LQ1Jl$lana lru:l'u<lal GM {ACUG) 220 305 305 268 697 Atmos Pipeline & Storage LLC 231 17 17 17 17 17 17 17 17 17 18 18 192 UCG Storage - Barnsley 232 563 583 563 58.'l 583 583 583 583 583 568 568 588 7,013 WKG Storage - E:a$t Diamond 233 931 931 931 931 931 "31 931 931 931 93a 938 a63 11,141 Trans Louisiana Gas Storage (ILGS) 234 507 507 507 507 507 507 507 507 507 510 510 480 6,060 Trans Loulsfana Gas Plpenna (TLGP] 303 1,984 1,964 1,964 1,984 1,984 1,984 1,984 1,984 1,984 1,9.El9 1,999 1,585 23,435 631.568 631,588 631,588 631,586 631,586 631,586 631,588 631,588 631,588 631,568 631,568 642,577 7,590,046 Allocatlon or Shared Servlcas Cost Conter 1915 .SS Dallas Insurance Company/Cast Center Description Company APR-16 MAY~16 JUN-16 JUL-16 Al/G-16 SEP-16 OCT-16 NOV-16 DEC-16 JAN-17 FEB-17 MAR-17 Total S:S Dallas lrn>Urance-Co-st Center 1915 010 23,149 23,149 23,149 23,149 23,149 23,149 23.149 23.149 23,149 23.328 23,326 19,532 274,530 AHocation Percentage to Atmos Erie:rgy-Color~o·KaliEla$ 6.81% 6.81% 0.81% 6.81% 6.81% G.81% 6.69% 6.82% 6.62% 6.60% 6.60% 6.60% AHoea1lo-n P.ereen1:age to Rem;ainlng Companl~ 93.19% 93.19% 93.19% 93.19% 93.19-% 93.19% 93.31% 93.18% 93.18% 9'3.20% 93.20% 93.20% 100.00% 100.00% 100.00% 100.00% 100.00% 100.00% 100.00% 100.00% 100.00% 100.00% 100.00% 100.00% Total Amo-unt Alloealed to A1mO$ Ene~gy.Colorado-Kansas 1,576 1,576 1.076 1,576 1,576 1,576 1,649 1,679 1,579 1,566 1,586 1,328 18,600 Total Amount Allocated to Remaining Companies 21,573 21,573 21.573 21.573 21.573 21.673 21.601 21.571 21.571 21.740 21.740 18,204 255,864 23,149 23,149 23,149 23,149 23,149 23,149 23,149 23.149 23.149 23.326 23.326 19.532 274.530 ElluoF1i!lma PJoperty lns.L!r1111nee After SSU Allocation Company/Cost Center Descrlptlon Company APR-16 MAY-16 JUN46 JUL-16 AUG-16 SEP-15 OCT-16 NOV-16 OCC-16 JAN-17 FE!l-17 MAR-17 Tota.I Atmos Energy·Col.orado·Kans.as. 060 37,764 37,764 37,764 37,764 37.764 37,764 37,7'".R 37,767 37,767 38,050 38,050 37,002 452.956 other Remainlng Companl~ Various 593,824 693,824 593,824 593,824 593,824 593,824 593,852 593,622 593,822 593,538 593,538 605,574 7,137,090 631.566 1!331,588 631,588 631,568 631,568 631,566 631,586 631,586 631,588 631,568 631,568 642,577 7,590,048 Percentage BlueFlame Property lnsuranceAfte1 SSU Alloeatlon C(lmpany/Cos.t Center De.scrlptf¢ri Company APR-16 MAY-16 JUN-16 JUL-16 .A,UG-16 SEP-16 OCT-16 NOV-16 DEC-16 JAN-17 FEB-17 MAR-17 Atm(I$ Energy-C-olor.ado·Ka.na:ae. 060 5.98% 5.96% S.98% 5.98% 5.98% 5.98% 5,97% 5.96% 5.96% 6-02% 6.02% S.76% other Remaining Companies Varioug 94.02% 94.02% 94.02% 94.02% 94.02.% 94.02% 94.03% 94.02% 94.02% 93.98% 93.96% 94.24% 100.00% 100.00% 100.00% 100.00% 100.00% 100.00% 100.00% 100.00% 100.00% 100.00% 100.00% 100.00% AttachmentJLS-1 ATTACHMENT 3 Page 57 of72 131ueFlame Property lnsur.;ince Amortl~atiion Colorado Rate Divisjons Company 60 Total APR-16 MAY-16 JUN-16 JUL-16 AUG-16 SEP-16 OCT-16 NOV-16 DEC-16 JAN-17 FEB-17 MAR-17 Total 37,764 37,764 37,764 37,764. 37,764 37,764 37,767 37,767 37,767 38,050 38,050 37,002 452,989 Division APR-16 MAY-16 JUN-16 JUL-16 AUG-16 SEP-16 OCT-16 NOV-16 DEC-16 JAN-17 FEB-17 MAR-17 Total GGCIDenvor Company Division -030DIV 88 88 88 88 88 88 88 88 88 89 89 76 1,047 Colorado ADM Division ~ 031 DIV 1 1 1 1 1 1 1 1 1 1 1 1 12 Northeast Colorado Dlvislon - 033DIV 6,050 6,050 6,050 6,050 6,050 6,050 6,050 6,050 6,050 6,000 6,096 5,990 72,634 Northwest & Central Colorado Division -034DIV 2,946 2,946 2,946 2,946 2,946 2,946 2,946 2,946 2,946 2,968 2,968 2,918 35,367 Solltheast Colorado Division· 035DIV 3,115 3,115 3,115 3,115 3,115 3,115 3,115 3,115 3,115 3,139 3,139 2,973 37,285 Southwest Colorado Division - 036DIV 2,531 2,531 2,531 2,531 2,531 2,531 2,531 2,531 2,531 2,550 2,550 2,868 30,747 14,731 14,731 14,731 14,731 14731 14,731 14,731 14,731 14 731 14,843 14,843 14,826 177,092 Division APR-16 MAY-16 JUN-16 JUL-16 AUG-16 SEP-16 OCT-16 NOV-16 DEC-16 JAN-17 FEB-17 MAR-17 Total GGC/Denver company Division -030DIV ea 68 88 BB 88 88 BB BB BB 89 89 76 1,047 Allocation rate -of Division 030 to Div 031 43.54% 43.54% 43.54% 43.54% 43.54% 43.54% 42.51% 42.51% 42.51% 42.51% 42.51% 42.51% Amount allocated from DMsion 030 to Div 031 38 38 38 38 36 36 37 37 37 36 36 32 451 Total Blueflame Insurance in Division 031 39 39 39 39 39 39 38 38 38 39 39 33 463 Allocatron Rates of Divisjon 031 to co OlvisiOn$ Division APR-16 MAY-16 JUN-16 JUL-16 AUG-16 SEP-16 OCT-16 NOV-16 DEC-16 JAN-17 FEB-17 MAR-17 Northeast Colorado Division - 033DIV 41.77% 41.77% 41.77% 41.77% 41.77% 41.77% 43.77% 43.77% 43.77% 43.77% 43.77% 43.77% Northwest & Can1ral Colorado Division - 034DIV 23.19% 23.19% 23.19% 23.19% 23.19% 23.19% 21.64% 21.64% 21.64% 21.64% 21.64% 21.64% Soulheast Colorado Division - 035DIV 20.18% 20.18% 20.18% 20.18% 20.18% 20.18% 19.44% 19.44% 19.44% 19.44% 19.44% 19.44% Soufhwest Colorado Division • 036DiV 14.86% 14.86% 14.86% 14.86% 14.86% 14.B6% 15.15% 15.15% 1ti.15% 15.15% 15.15% 15.15% 100.00% 100.00% 100.00% 100.00% 100.00% 100.00% 100.00% 100.00% 100.00% 100.00% 100.00% 100.00% Amount allocated from Division 031 to co Divlsfon~ Dlvisfon APR-16 MAY-16 JUN-16 JUL-16 AUG-16 SEP-16 OCT-16 NOV-16 DEC-18 JAN-17 FEB-17 MAR-17 Total Northeasl Colorado Division - 033DIV 16 16 16 16 16 16 17 17 17 17 17 15 198 Northwest & central Colorado Division - 034DIV 9 9 9 9 8 8 8 8 8 7 104 Southeast Colorado Division - 035DIV 8 8 8 8 7 7 7 8 8 6 92 Southwest Colorado Division· 036DIV 6 6 6 6 6 6 6 6 6 6 6 5 69 39 39 39 39 39 39 38 38 38 39 39 33 463 Blueflame Property lns1..1ranee after allo-oation of Div 30 & 31 Division APR-16 MAY-16 JUN-16 JUL-16 AUG-16 SEP-16 OCT-16 NOV-16 DEC-16 JAN-17 FEB-17 MAR-17 T<>tal Northeast Colorado Division - 033DIV 6,067 6,067 6,067 6,067 6,067 6,067 6,067 6,067 6,067 6,113 6,113 6,004 72,B32 Northwest & Central Colorado Division - 034DIV 2,955 2,955 2,955 2,955 2,955 2,955 2,954 2,954 2,954 2,977 2,977 2,925 35,471 Southeast Colorado Division - 035DIV 3,123 3,123 3,123 3,123 3,123 3,123 3,122 3,122 3,122 3,146 3,146 2,980 37,376 Southwest Colorado Division - 036DIV 2,537 2,537 2,537 2,537 2537 2 537 2537 2537 2 537 2556 2,556 2,873 30,816 14,661 14,661 14,681 14,681 14,681 14,681 14,680 14,680 14,6BO 14 792 14.792 14,782 176,495 Attachment JLS-1 ATTACHMENT 3 Page58of72 Almos l::neruy Corporation Acoounl 922 Twelw ManlhsEnded Match 31, 2017 Division Cotorado DivisFan 'Total Account Sub A-e:count Sub Account Desiel'iption 002 012 030 031 033 034 035 036 Div31-36 9220 09341 Admtn & General Expenses (5,908,088) 532,390 855,626 453,337 399,459 300,958 2,541,771 9220 40001 Silled to Wesl lex Div (8, 122,638) (5, 154,256) 9220 40002 Billed to COJKS Div (6,764,934) (4,250,843) 9220 40003 Billed to LA Div (9,204,759) (5,974,245) 9220 40004 Billed to Mid SI Div (10,313,365) (5,777,597) 9220 40007 Bllfed to Nonutmties (1,283,802) 9220 40008 Biiied to Mid-Tex Div (37 ,439,582) ('27,509,910) 92<0 40009 Billed ta MS Div (7,087,376) (4,<59,372) 92:10 40010 Billed ta Atmos Pipeline Div (16,723,729) 9220 40011 !lilied ta AELIG {94,898) 9220 40012 BllledtaWKGS 7,904 9220 40013 Biiied ta AEH {19,678) 9220 40014 Billed to UCGS (14,189) 9220 40015 Billed to TLGP (110,275) 9220 41101 Billed from Accounllng & Tax 1,384,045 9220 41103 Billed trom Customer SeMce Cenler 3,714,370 9220 41105 Billed from Gas Control 807,675 9220 41106 Billed from Govt Affairs 73,711 9220 41107 Biiied from HR 389,067 9220 41108 Biiied from HR other 1,669,167 9220 41109 Billed from IT 2,482,125 9220 41112 Billed from lnv-e$tO-r Relations 87,141 9220 41113 Billed from Legal & Goll'! Affilira 1,068,780 9220 41114 Biiied from Carp Secretary 42,985 9220 41115 Biiied From Planning & Rale:s 299,768 9220 41116 l:l;illed from Rales 48,620 9220 41117 lliilled from Purchasing 38,499 9220 41119 Bined from Treasury 156,314 9220 41120 Billed from Risk Mgmt 1,391,085 9220 41121 Biiied from Management Committee 446,796 9220 41123 BIH!ng for overhead Capitalized (4,809,129) 9220 41126 Billed from Ulility Operations Co-uncu 4,540 9220 41131 Billing 1nr CSC O&M (3,714,370) (0) 778,768 383,304 315,285 260,379 1,737,736 9220 41132 Billing for SS O&M (7,311,407) (2,541,771) 2,432,398 1,274,452 1,126,418 853,307 3,144,803 9220 41138 BUled from Safe1y & Ente.rprise Svc 1,550,219 !97,171,3211 ,52,936,222) (5,908,0BB) !2,009,380) 4,066,791 2,111,093 1,841,161 1,414,645 7,424,310 Attachment JLS-1 ATTACHMENT 3 Page 59 of72 Almos !Enaf!llir eo,pq,lijlt.;Q.n AocoulZl408.1 Twol'llO M.:inllis. E;ndo>d M:11rii" :S.1, 2017 Dilrisian A.. oou~L 511:bAtoiooLElil SubAr:icountCeserTi;:tion APR-11> MA'l'-16 JU.N411 JIJL·1$ AIJ(;·1$ :s.1:1J•~1e 'O(;'t-11!1 NOV·111- bl:ic-1111 .JA~M1 FE"B41 MAR-11 T°"I :012:10 F~Llllad ::154,::144 2aa.m 233,4'!Mi :!::W,!i.72 :i!OS.~ 3(151,674 212.1S1 a.12S 237,SSG 3-tG,76Ei 317,ST"" 3~0'.199 3.~6.$09 ""002 ....."'" 0;211 Ful:aL'llild '11 .,, so 500 18,558 6,B!M- 2,'688 31,177 "l'J21:1: i!i-'!~1; L11<11d 3,3!51 ""' ,,."' " ... .,. ,.."" J,613'" "' 35,ooe ;llll,778 10,'281!1 ~.1!26 ""002 ...."'" 01213 FtcaLoa'llAOCf'Uat (106,479} 42,065"' 4,371 S-.1!53 'IS,753 (82,lil43J 1'2,2<12 1i561.,4f2 ['104,322]"" ....1 13,616 (126,2.1~ 1,119,787) 002 .... OJ214 fWllJ;ladA«iru:il {1,460} (<4) I''" !1l 10 25 ., 05) 11,01!!1 CS,!!1111&] ~.""') (ME14) 002 .... 0'!21.5 s.dilllMldAGoel'llBI C3,945J (325} (.. ) (37) 17 .. .. " l74} 21'."'4 (3,1-&e.) (16J5:i!) [2.785) ,,.,.... P.a~-11!Te~Pfo;ei:its '"to {10. 1,787 1,7117 ""002 "'''"30101 J\id vali:iNim -Actru~ 71,000 71.000 71,000 nooo 71,000 "44,000 44,QOO ....coo :90102 Tmr-as Proparl:jr Ami! Oilier 295 25,526"""' '"'""·l!ii!,691 "·""" (16,Hla'"""" "·""" "" "" B1111kl:IOWs~t'tell:Div 120,532] {j;!:,443) (24,!!113) l,2S,03S} ~26,080) (24,100) (2'"8,"41) lEi2,!!i14) ~N.QW) (41,4:!:111,1"' ~:.io1MO) l,24,i;l!;j1~ t,:ilS1,Z!!lrJ"'·"" 002 .o!IOIU "'"'"<0002 Elil~loCOlitSDIY {21,657J (27,41i) tZ1;!M8) l21,152J "2.035) t2D,31Cll (2:3.,611) l5'2,057J i12,151) f.34,411;2J ti!.6.201, 1.::m,!S17} ,,,,""' ""'' [28,!!111] {411,504J c;!7,349} {,ol12,49l!J .o!IOIU Elillfctd-lot.ADlv 119.••m (37.414) (2:-&.rm 1:31l,1:!:5,I t:!:T.~7) (.:i.::l,1!il!) {10,834.1 116,5-IBJ '"''""'' 002 .111:11n '"''<0004 Bij)~loMld5tO!v {32,565) (41,211) (3~,fl::il) f,:11,&0l!lJ {3j.1;W) (j!),ilSl (~.$99) {1S,-15SJ {1&.~ (52:,4&3-) """"'(SS-•.&79) (31'.22&) (4SEl,1514J 002 <1011.1 a.il~lo~~ilmc!ll ($.... ) (12,5911-J t;!l',575) l'9.12:i!) ~10.128) (9,.,,, [8.;29.11) (2,290) !53~ (1,n4J {14,2B2J {203,137) {l.Ti'4,IS05) 002 '"'' BiilJeod.loMici-TelfDW (125,999) {159,4i7til (1Zi!,46J) (123,000J C'l2UOO) (11~;ii' (1::Ji9.833) f,m1,152J ~11.7:5$J ~ Cti!0.870) 002 '"' "''" B.ille-dlo~Dilr ~.16SJ (:ti,~ {2:1,fi.4.11) l.21,649J !(22,553-) (2.'lJo,&18) (2:4,705) {54,729] {12,765) f.36,206-J (3"7,·ntJ.. (21,5.113) (:3~4,294) 002 "" """"«lll1• Billed lo A1mm= Pipeline Ciir 150,'1Jlij '63,lml (4$.Vi2) {49,2$1] (51,31:91,1 (4T.A3S) (~.9!!19) {134.:i!eol!] (31,3$&) (90,818-) (<0.009)- (54,0:31!1} (7S0~12:] 002 "" Ballct.dloAE.UG [1!i4) {121~ ~275) 002 "".!!OM ""'" BillladloVllKG5 (1!i4) (i21} ~275,1 002 ""'"<001' mlla-dloAEH (231) [l81) {412) "" 40014 EMll~.11 loUOGS {UD) 1.151) -(344] ""' "" 4001'5 8illl!'lllo'ILGP 1.CJ31 ""' "" ~ ~ !Ql !!!~ ~I ~49'J "'0 ~49l 111'1210 Flea Load 270,189 2D7,1'1Mi' 161,133 11111,712 155,CS7 2;Ni:,IP!i&I 155,487 4C6,i!l21 145,411 170,210 15'2.1U4 ,..,,. 2,5cl6,161il ,,., 1a,s59 .rl,H7 1,738 18,7BB .,,"' "" 01211 fYl:lll.OQd 71 .. ,,. '111212 5!11:Ei l.;oad 2,555"' ,,."" 1.. " '" ..."" '" '" 20.1.30 1111.045 6,651 50,756 ...'" "" Cl1213 ficql,11o11dAeoeJU11I (El1,67"1,I ;!:1,411.7 '"(9) 8,348 19,931"' (62,975)"" 8.838 116,019 (90,DZS)"" 29,451 13.87a {73,83SJ ~84.69TJ lil1214 FuleLOll!dAo;rm~el l28) ., (60) B.32:4 l3.M9) o(2..217J "'" {1,li!.'OJ (OJ 10 .. ($<~ '"012 ""408.1 01215 Sutal:oadAtcrldi!il (J,02SJ ,,,.,"''' ~1) (24) .. "•• 132 (93) 11,117» (~.254) 'IS,7lfl) (2,344) 012 ,,., 3011)1 AdV;11l111im1-Ar:o;n&I 55.llOO SS.COO S!!i,000 55,-000 -41:,000"' -11,000 41,000 -44,000 -44,000 Billc'll 1o Wosl Tox CW (Zl.005) (23,'336) (i!'l,135}'"·"" "2.00llJ"·""' (22,"93) (2t,-IS2) (2Cl,003> (54.1122l ~s.Jan t2.fl...::Ji9'.llJ"·""' (25,$71) {21.32~] li99.a51)""""' '"012 "" """" Bl91cd1':iCOJK:SOlv (19.4&6) (2;3.,i!;&9) cn,::im ~18,088) (18,lilrT,I [17,61!14) (1S,S41!> ~'4§,610) (1.813' t:!::l-,62:3) [:2.1.807) {17,742] 1.2-47~) ''" """" Biilled1ot.Amv {21,394) (S.2,773) (24.4451' i25,'454J f.Z6i,C16) (24...1157) (23,241} {63,6S5J (1C,9Cill-J (Jr:'.1,17"1) {24.:ri)J lj46.1ZJ.) "'012 ...."" """" BPleoil'laMKll!ltlJiv (2El,o!l24) (31,613) [:2::1,580) {24,55S) (25,0!!5J £23,977) (.:22.540} .(61,714) (10,577) '""""(:J;l,9!15) £29,254) {24,D29J 1.335,-121) 012 .... """'' amed"ta MPd-Tex Oh' {125,800) ~1ro;s12) (111.::1-41'.l) {11&.975) (119.55-i') (114.2:?14) (1(1-7,2SS> {:i!93.94&) (50.33:.2) (152..:2.46) (139.252) {114,343) {1,6Se,e.1!14} 012 """'' BliledtoMSCIP.r i19.5s:!oJ ,25,4tli5i ,11,458t [i8,~7EIJ ~115,51:!1~ ~17,TI>2J ,~6,539t f-45,32!! !;!.761J ~:J.,47ti-l ~l,473~ :!!7,63!,! !247.1~ "" """"' ll 0 a . 0 a ,_,,,. .... CJ1~10 FICBl,i!Sd 10.21ii4 ..... il.:128 ..... 10,M11 4,249 10,850 5,436 7-6,13-7 ~1,379 li52,CE-0 "' ...1 01211 Fu1aload .. .,. '·"° 1,051 • • • 1• .., "' Cl1212 SutaLoa-d " • • " •' ' 2 ' '" 318" "' "" Almos EnaJgy C".P:rpore.61Jfl Ac.«i1,1m40l!J.t lWlllveMonlh!l.EmladMari:h:31,2017 DMskin A-ccoun1 SubAOCOU:IEL s~~A~~mtO~C>r"~j?li>:>n APR·H MA.Y-16 JUN-HI JUL-111 AUG-11 i!lEP-18 OCT-18,,.. i'i!OV-16 DEC-18 JAN-17 FEB-17 MAR~H T1;1l;ill .... CH210 Flc:11.Ucad 12,875 ..,.. 4.520 ..... 3.373 10.900 10.117 ,... , S,716,,. 5.449 1i:uno El2,S15 ""'033 .... 01211 Fulai..oad 10 • 4 17 • s 2 25 .llC81 (11-21'2 !!i;uta l.0:11.;I "' ' 1 ,., "' ... .,."" 01213 Frc:;aLll'lldAGtnJal •• • ,,.• ""' 4 Atmc=-EnergyC::o~f.lltiein Account-4030 Twd!v ACIC'IMl.n.I :S.1EbAc:01J11Fnt :S1EbAcco1mt01!$Cripti"o11 ... 031 ...... °"F & Taxes OlhNE11J1ens111 '" "' [183,601) ~) =33.746 "'1:1,'62 15.ssz 11,i!1511 "" Depr Ex,p-Dislributfo11- Plant S,280,17D 1,623,963 1,581,200 1,589,6!!15 '"" """"' C!!opr Ex,p-Gam1;.il Plillll 13,533,"160 8,087,61i14 175,924 3-13.9-47 9o.G28 1S5,01:!: 100.~9 '""40:30 '""'"""1 V~iclaPepirec:ialiDB 5,2BB 2,860 257 Vahlitli!i OV111111ch11bn. C;ipit~liz:ad ''"" (2,9'113J <1Jl(l4) DIYlsEa-n AC:CDlilllt Sub.Accounl .Sub .Acccill~f Desciptron AP.R-1.J MAY-16 JUN-16 JUL·16 AUG•16 DCT-1& No\l'-16 DEC.HI JAN--11 Fl:!b-11 MAR·1'1' row 002 30007 DeprEllp.GeOBralPla.nl 1,111,a49 1,122,825 1,12:3,153 1,lJ!il,93.2 1,132,757 924,7~6 1,11:91,933 1,123,°"4 1,17S.81.$ 1,lBlll.26$ 1,1fllll.4:!16 U'l'6.e45 13,53l,46(1 002 """4000 V-oiile;ll)[)ll',PIOCl!itlo:n 1,f?a.7 1,ln7 1.137 1,637 106 105 105 104 102 102 7,315i 002 4000 ''"'" Tools. & ShG!p O.proada.lfon ..... ,_ ... >1-43 4,026 2,20\ii"" 2,119 1.491!1 1,.!199' 1.495 1,.!11!17 Me& 1.48&"' 2:6,406 ""'"' L.abDoproc~lion ,,. 1'" 196 ,.. ""' ....""" ""'"411001 Billll!ldlaWoei;.1TexCiv (34.SJ.4) ( ...204) @1$,:il:Z4J (.$S.1!114) (e$,l.'illo~) !>-"") (13,641) (1~.100) ~e,1,101,1 (81,oll3BJ '81.441) ,(8D,3BDJ... '900.l!i-2)''" (-85-.001:) {65.768) 1:65,795] t66=,2l!Y!) (66,lOl!I) t3,98-4) (56,23S) (56,Q Depr& Taxes OU1ieriE'J1pense l\11 0 (0) (01 {O) [O) • 330,'IMS ""' ,AimM;:EnergyCorpe-r.alloo Airmum.403tl T'Yfl!ll'a'llo Manlhs Ended March !U, ~IU7 ..,,. ,,.... O&ipr&T'ilX11osOilmEllP'!ns.a 2,81-S 2,879 ,... , Z'"l 3,722 3,Q56 3,058 2,375 ,, .. ,,,.. 2,393 33,MB "'' .... 091!" EMp..bldL11hih Pt;i;~ 2&3,78"1 2&4.5&5 :!.'GS,090'·""' 274,19:!! :j!i!I0,9$1 272,7.ila 27El.~ ·:m,2s:1 :m.421 '2:71M90 27!11,467 3.2&0.170 '" JOOIJ7"""' OeJlf"Sxp-Gorwralfllanl 21i,3!i!3 28,826 2i!l •.flo20 ""'·""'28.8.28 25.118 27,358 23,7'4S 2::1,~B 23,762 24,348 :313,947 "'"' ,..., Ti:iols. & .$hll'p 0eP!'.ciCl~llon 3.1~ 3,15:1. .fl,<152 4,452: ~031 "'·"'il,52:! '"'"'4,1"7 4,147 .rl,1'17 .rl,M7 5~13 "' ,.,.""" '''"" Tool5- & 5h11p Depr-e'llia6ar. Cepitlbd (1,142l (tBt.S) [2,<50) (2,51-4) (2,914) <> ..~ (2,370>~·"' (2,354) (:i!.210) lU4:!1) l2..212> l:i!,734) {:i!B.001)"°'"' '" lsb Pe!P*~t'joJI 80 ... '" ,.,.'°" ,..,,''"' LisbOepm;iatiaii-Capi:ilbll ( Atmos Energy Corporation Account409.1 and410.1 Twelve Months Ended March 31, 2017 Allocated to CO rate divisions Total Account Sub Account Sub Account Description Div 031 033 034 035 036 Colorado 4091 30201 Federal Income Taxes 631,847 290,060 204,465 60,362 76,960 631,847 4091 30202 State Income Taxes 68,779 31,574 22,257 6,571 8,377 68,779 4101 30201 Federal Income Taxes 2,674,656 1,227,846 865,515 255,519 325,777 2,674,656 4101 30202 State Income Taxes 179,901 82,587 58,216 17,187 21,912 179,901 3,555,183 1,632,067 1,150,452 339,638 433,026 3,555,183 Attachment JLS-1 ATTACHMENT 3 Page64of72 A'lnlCl!I uumy and llPT Oper.1lklns tAC:11i11¥=Slillh!.JP1!!11: 11!monlhs.-efllllng~h'31,M17 .,. FERO ...... <• .. ... GramiTatll Gai;.Oparalir'llJR"~i400!I l~lil.11117,ttll:I .. 221i,lffi.962 234~<14 i!10.021.6DS 1,316.Elll.31'11 431,:260,9'111-'" 81.813.546 lH.036.00U "" ,,1.ioo.m"' 27'.751J,lllii1 l327.500.200)o 2.516,112.117 Opera~Ellpa!l5DC-4D1) !,005,1117 (121,d&!l,71:1.) t1~.:!1$),n1$,1 i1~:u.m 1:$43,$il:t.!i.1d) (1211=,6!!8,309) 156,02.'l,735.J (J"i,71i!l,IU1) C65,ll00,45JJ- {7Q7411,9281 t19,554,15'f,I 327,!i00,;20!l :(117,115&) £20,7Bl) m.1>< {~.3-'M.8§4.08:1!1 Mainlenacii;i;iElljlllrll!'lltltl2Ji (346.414] ,...... f3$8.1:!11) ti,7.QQ.241) l.11.341,"°41 (11..1111-2.~51,I C13T,i4:1.J 1441.S'ill) f.!211-.112~ iSll.e41;11 t16,..j4Jj {142) tU.009.9651 Pepr:l1daliooEllpensel.tD:!I] ., ~11-.:m.m:i 121F.14~J ~1:5,SJ:il~ U2:3.1!ir..\J.17J !9J..OU$,4$:),) C!l,:;:as,!)l!IC!J 110.i:i;e,,212) Cll!l,1191,92"71 [1i1,!500,SD:!I) £2,.38-\8'11) "-"'' (jl;J$,1.si!.$U:tJ Amortlzallonlll'UlilityPlanlAC!l.Adjlslmen " •• ,.,., t;25.fl:ll!.J (16.406) 7.17ll783 1,1!105,500 ~.472] l!.11-,55$) ~·U.~I ~Ei.tt-11) ll:l!;iZ,721J ReQule!DryDe!Jils.{«11.!IJ la!l,D46J ~1.9111J C~0.27(1) . cm.:i:m ~RllaUl;)'IC1YCl«l11i{.jl;J~.4J ti:!l.:<114 $S;.$¢;1 1am "' 247~ T.a11e&Olhl!!r1haDl11C11m11Ta!!:l!S'[G.1) .. [1d,t~,d(laj (;l1.41~T.I•• '(1-ll.1:$Q.ll:f~) j'j;~l$.IXD..'23~) ~.M7,S7Clj (2.500,7.115.)" {1,5!:t,607) f5,5411,9J.71 (1,704.1'!121 (BllJ.:191]1 -(2'!0,1411.3!131 looomeTaxes-R!lior.!!1(400.1] C~12.B5.:ll!ii!Qi 7,966,3# 9',013.'.!;78 6,4ili9;9:Jll 8S,IU6;!11'5. fi7,407,332 {i'OO.G2G,I 1ero.s1.:r;i 9,4!;9,134!il 1.~.424 2.623.49;! 1.liOJ..M7 2..:500".tlU 1.51SSl.S111 m.2~ 14;000,tl'IS Pmo.Jsi11ndPeferr-edTaies(410.~I m1,$$;t.1!?$ [~.210,o.J:loj ~1~400.-'l~j ri5i5.~12J1 Q.$54,$67) (4,12a,41!11j Cll!l,97-ll',l'.IS:i!I c.e.539,191) {-1,313..2!2) (1,73-t,IU:!l l:l!,1i!l1.:M7} (2:,.W,fl!IDI"'""' [t,99!l,'lll!i!I) [&18,1!12~ {2:!9;-111!11,00l!I] t;ZZ..!9SS.4241 ~115'.18$'.~} ""'·""" " lrJR!slmenrTaicCr£111itAd~-N-et [411,4J ..,, '·"' llll$&JOil:!-tl;;lilkJBJ:jlll;fttetJ/ MerohandisingJClb&O:mlract'l'llllckC~t!GJ (120) !211] Re Hairr. Tbaabcr.'ltiSICOlllB &tatement:lorlhe- l~ moolMeOOlrt; I.lard! :!11, 2QUwas piepared in 1be&amamanllll':I as 1111' annual !'ERC F'111m2 ~rt. The fERCf'cmilisprE!pa;edaneea1emlar:re;irbi3sls. Attachment JLS-1 ATTACHMENT 3 Page 65 of72 Atmos Energy Corporation Plant In :SeNice For the Thlrteen Monlh$ Eni:I~ Mareh:31, 2017 E.Jne SSU Oivision 002 ~ S.SU DMsion 002- SSU 01Vl5ion002:- SSU Dlv!Eilon 002- SSU Division 012- SSU DMston 012 - Colorado Servi-ce Area No_ Date GO Grt:e:nville AEAM Aligne CS CKV Division 030 (1) !•) (b) (g) (h) (i) 03/J1116 165,973,519 9,196,755 21,720,201 148,987,856 12,955,069 1,306,636 236,579,511 04130116 166,017,096 9,196,755 21,720,201 148,981,307 12,955,069 1,308,636 236,658,419 05131116 166,700,605 9,196,755 21,720,201 149,321,871 12,9:55,099 1,33'3,931 236,360,35:9 05130116 166,749,207 9,196,755 21.no.201 149,400,613 12,955,099 1,332,945 235,509,074 07131116 167,413,171 9,196,7.55 21,720,201 149,406,119 12,955,069 1,336,363 235,20:1,822 OBJ31J16 165,513,146 9,196,700 21,694,056 149,325,218 15,0:56,078 1,340,433 235,434,352 09130{16 133,411,906 9, 196,755 21,970,034 17,637,660 125,095,393 15,067,448 1,392,130 234,942, 193 10/31116 136,534,428 9,196,765 21,970,034 17,713,576 125,312,693 15,067,448 1,392,130 236,063, 765 9 11130116 138,700,739 9,196,765 21,970,034 17,840,215 1.25,312,554 15,067,446 1,392,130 243,082,592 10 12131116 143,947,579 9,196,755 22,527,307 18,093,299 124,480,648 15,067,448 1,C:l37,905 243,653,619 11 01/31117 145,492,015 9,196,755 22,527,007 16,115,631 124,588,243 15,229,806 1,047,904 244,279,509 12 02/28117 145,505.267 9,1.913,755 22,527,307 18,157,511 124,606,630 15,244,500 1,047,904 244,:976,666 13 03/31117 140,984,161 9,196,755 22,627,307 1H,i60,101 124,711,811 15,250,669 1,042,735 245,993,311 14 13 Month Average 152,536.450 9,196,755 22,024, 184 9,B7o,sao 136, 117.766 14,294.335 1.254,906 239, 133.555 15 16 Allocation Peri:;ent.:ages 2.89% 1.17% 3.29% O.OOV.i& 3.79% 2Jl 28 Tota.I Average Net Plant in s~rvf¢e (Lt1 24 + Ln 26) 149.050,714 29 30 Attachment JLS-1 ATIACHMENT3 Page66of 72 Atmos E11ergy Carporallon Plant In Servt-ce F'o:rthe Thirteen Mor.:h Ended M;,'!iri:;ti 31, 2017 Line SSU DM$iOn 002 - SSU DivisjoQ 002 - SSU Division 002- SSU OMslon 002 - SSU DMslon 012 - ssu Dlvlslon 012 ~ Colorado Service Area No_ Dare GO Gre-envilte AE:AM Aligne CS CKV DMsion030 (1) (a) (g) (h) (I) 31 32 Plant in Service At March 31, 2017 (Ln 13] 140,984,181 $ 9,196,755 $ 22,527,307 $ 18,150,101 :s 124,711,811 $ 15,250,689 $ 1.D42,7J5 $ 245,993,311 33 34 Alloo0atkm PerGentag-es 2.89% 1_17% 3.29% 0.00% 3.79% 42.51% 100.00% .35 Al!cucatjo~ of S~ared Service:!!l OM$iol'i 002- GO {Ln 32, Col (b) ~ 2.89%) 4,076,159 36 Allocation of Shared Sflrvices Division 002 - GreenvDle (Ln 32, Cot (c) • 1.17%) 107,167 37 A!locatkm of Shared Services Division 002 - AEAM (Ln 32, Col (d} .. 3.29%] 740,209 38 AUoeaUcm of Shared Services DMsion 002 - Aligne (Ln 32. Coi (-e) •o.00%) 39 Allocation of Shared Servlce:sDEvlslon 012- CSiLn 32, Col (fJ "'3-79%) 4.726.169 40 AHo'l'.;atfon of Shared Services Division 012 - CKV (Ln 32, Col {g}"' 2.06%) 313,895 41 AUocaUon ofDivisio~ 030 'Lil 32, Co[ [h) ... 42.51%) 443,240 42 Total Ptant In Servloe atMarc:h 31, 2017 {ln32+(Sumoflns 35- 41] 25"1.399.150 43 44 Aci::umulated Deprec!atioll ~WP f.1-'2. Ln 36, C¢1 (fl] (103,197,331) 45 46 Total Not PlantlnSorvloo at Ma0;h 31, 2017 (l.n42+ Ln 44) 153,201,819 47 48 NDte 49 1. The Pl.ant ln Setvlce ba!;;mces are net of the S:SIJ=i balance. Attachment JLS-1 ATTACHMENT 3 Page67of72 Atmos Energy Corporation Income Statement - Colorado Twelve Months Ended March 31, 2017 (Col A) (Col B) (ColC) (Col D) (ColE) (ColF) Utility 034DIV (Northwest & 031DIV (Colorado 033DIV (Northeast Central Colorado 035DIV (Southeast 036DIV (Southwest Total Colorado ADM Division) Colorado Division) Division) Colorado Division) Colorado Division) Jurisdictional Operating Revenues Operating Revenue 33,350,396 23,272,178 11,941,243 10,302,403 78,666,220 Transportation 1,520,545 21,198 944,139 84,493 2,570,375 Other Revenue 195,512 81,130 54,221 46,088 376,951 Realized Gas Trading M argln Unrealized Gas Trading Margin lntersegment Elimination Total Operating Revenues 35,066,453 23,374,506 12,939,603 10,432,984 81,813,546 Purchased gas cost 17,066,497 13,294,704 5,834,206 4,305,457 40,500,864 lntersegment Elimination -Gas Costs Total Purchased Gas Costs 17,066,497 13,294,704 5,834,206 4,305,457 40,500,864 Gross profit 17,999,956 10,079,802 7,105,397 6,127,527 41,312,682 Operating Expenses Operation & Maintenance 6,751,519 3,495,888 3,053,787 2,360,617 15,661,811 Depreciation and Amortization 3,926,392 1,889,735 1,865,678 1,605,175 9,286,980 Taxes - other than income taxes 1,073 476 563,627 491,658 377,985 2,506,746 Total Operating Expenses 11,751,387 5,949,250 5,411,123 4,343,777 27,455,537 Operating Income (Loss) 6,248,569 4,130,552 1,694,274 1,783,750 13,857,145 Other Income (expenses) Interest Expenses (1,350, 769) (710,458) (632,289) (460,906) (3, 154,422) Interest Income 9,367 4,827 4,314 3,264 21,772 Other Nonoperating Income (161,877) (79,942) !78,789) (67,070) (387,678) Total Other Income (Loss) (1,503,279) (785,573) (706,764) (524,712) (3,520,328) Income (Loss) before Income Taxes 4,745,290 3,344,979 987,510 1,259,038 10,336,817 Provisjon (Benefit] for income taxes 1,632,067 1,150,452 339,638 433,026 3,555,183 Net Income (Loss) 3,113,223 2,194,527 647,872 826,012 6,761,834 Attachment JLS-1 ATTACHMENT 3 Page6a of72 lllmC1SE1181"gj1Carpc1raeian lneorno Slalclmenl- RUT (Ulili!J plus APTk:s.s Bleollama) TwehrsM1mlhs.EndfldMa1>Ch31,2017 [CMA) (O:ILB> (O>IMl) UlillyRlIT Api:-~16" Ma1"16 Jun-1111 Jlil-18 Auit-18 Sup-UI OtMl!i Nav-16 ,,.,_,. Jaq.17 Feb-17 Mar-17 UBDlyRUf Ta-talCaiarail'o ... .,,.,,. ""~' 11~1u&1 .... AGliual Actual Aciual Aciuill TalalAtmos Jllrisdk:tlanal Nan-Colam1fo Opcr111in9Rove11~!i- "'"'' "'"'' """'' """" opat.111ln:gRavonui:i 140.]'$9'.tll 1:!:3 •..i73.211 i2fi,24i,087 1'2'2,0B8,6DD 124,062:,D55 12Cl.7C9.~ ~::JB.414..Slie 196,236.790 S.74,Eie3,3e0 411"'16~.-m :m.-641,001 2CISM4.eliil!i 2.364.4i.2,Sc9-7 1.a.ue.220 2.i8S.S!il!l,1t1 -· 10,i:175,B33 UIO,W.11,101 Tr.a11s~rtali:111 14,922,432 14,837,613 16,:W:,965 15,291,622 15,0711",107 1-S:Jl-78,123 i3,663.,ll2EI 1-l,&-11,556 15.933.i:M 1S,1.J'.i!.17a 15,(P.$4.653 183,544,iffii 2.p10,J75 OlherRevenue 1,979',020 1-,899,32.-4 2,4n,m2 1,121!1,1.fl.4 2,139,797 1.{109,391 1,7P6,T.!5 ?;DiB,345 5,1.66,12a Z,432,125 i!,566,727 2,921,asa: 28,145,'ZM -376,951 27,7156,293 R.aaHz:.adG:asTr.adl1'111Mar:11ln Unraailii!edGa:&T1adingMilrgin lntcl'llegm11=n~EfimiRBtill'1 r.at1il OpG;ia~l'llll Ravonuos. ist.660..574 1«1,.::111:1,1611- '144,95-1,004 1-3S,li08,400 l41~.11199 137,fliJ7,3619' 153.811.Zi!:!I 212.M,691 :SSS,78$,334 43'7,326,33,4 21119-.271,:!17'0 :t2SJ\41!1,564 2.67Q.11:2.117 IU.613,$4$ 2,4!i14,298,!!i71 Pl.lclwisdgasoosl 25_!!i:!Cl-.Hi9 15,i!115,3SJ 1fi;,'&'4S,7El7 nne.010 1!jl,1111S,121 116",41d,285- 27.5&9".619 661,6153,152 205,829,109 22B.SOO.i566 108-.-844,2.13 66,-481,466 3'14,55l,e59 40.,600,864 774,002,995 lnber&egman~ E;iQ;ljBil!i~ -Gas C.o:sls Toca:I Puricha~d G11:11 Clll!ib 2.S.53(1.169 15,61:$,361 la,945,787 17,n8,tl11J 151,51151,127 1111.414.2ei5 27,581!1.619 l;ifi;~162' i!os.e:tli',1'!1S 22e.~.i!i6til 108.~.21~ l!IQ.4S1,4fi;ll ;t!-J~,553.,,.859 40,600,864 774,{152,9515 G~o~~fil 132,l:acJ,415 12"4,494,81111 1211:,005,317 1:2.1,3BD,3!HI- 121,SIU,.fl62 1:2.1,283,004 126,267,&14 loili=.,2'13,5351 189,954,Z25 21'11,~Z,76111 1-lllJ,-421,152. 159,467,0&3 1,161,$11..iSB 4t.312.&:IZ 1,72D.2:45.576 orra.1ing;Eii1H11J58S 011'1Jr:wllon & Ma'ln~Mne .Nel!l'M:Ol!l&tLv:i;s) 2$,2-44.435 17,016,130 '20.,201,724 l3,Q615-,!j;26 1:a.,732,on 5.474.an 23.210.6El6 .sG-224,923 Eie.2&4..573 6'7.770,1!!0 61,(!03.,229 SQ.e+i.sis 361,031,;&7G El,7'3,1,Ei3.:I ~,;il5Q,241 Attachment JLS-1 ATTACHMENT3 Page69of72 Atm111.z; Enl!!rgy Corporatlon lnCOl'llll! Sla1ement - Tot.al C111mp•m.:ir Tmlve McnU1$ ~cled Marcil 31, 2017 Apr-16 May-16 Jun-16 Jut-16 Aug-16 Sttp·H OieM-6 NOY•16 Oa:c--16 Jal\--17 fob-17 Mu-17 12MoTotal Mtual ..... , A""81 AC'!Uiill Ad;ual ..... A.11;!1.1i!ll Aol111;aj Ai:it1,1al Ac.'11.lilll Actual OpuraBng.RO"Vel]UEt!I. '"""' Ope-ra'linsr Revenue 208,318,100 '192,283.163 200.011;•.~1: 2.19,687,746 22a,918,9~ 213, 12e.075 '232,404,4tD 288, 191,344 507,472,431 43o,187,'97B 281,644,1 B7 214,714.aCJS :3,212,526,523 T1a:r1.tpiodaHl)n 14,3D3,54l 24,825,484 1.S,000,747-· 15,204.220 14,99S,gsa '15,Sa-4,503 13,61Q,480 14;552,834 ~5.675)331 15,682,345 1'1,'9138,745 16,028,141 182,473,S'nil OUisrRt1'11on1.m 2,990,7CJ.2 :3,131,209 3,Ctt,001 2,2.41,714 2,650,3:22 1,59-1,465 2,494,681 2,1Me,143 Ei,016,540 5,416,706 5;987,1.82 3,475,913 41,.:91S,Ei4'3 Realized Ga.s Tradil§lil Margin Hl1,419 55,955 10-3,671 122,Q48 ~45,242 18-1.762 291,05& 2ozg:ea 395,1573 0 0 0 1."9.797 UrirealW!d G;as T!adifJ.g Margin (10,<101.131) 5,948,:960 8,704.435 (3.441,010 (lll,Wl,e66J (1,879,420) (4,::197,554) 13,793,720 5,444,.319 (14,255,436> (247,195) (542,003) (1,483,EH2) lnleraegm1mt Eliminalion Q'.J75,135] ~602.469~ [r.3a9,593J ~10,584,531!1~ {10,075,61i3J [U1,1JB,031~ '11,'76~,6"415J ~.454.459) ~ 1,200,684~ D 0 0 193,'2BO, M~~ 'f'~I Operating f;:evenuea 209,Hf1,497 2.07,742,252 220,5'14,059 22::1,230,258 225,427, f78 2~3.780,354 '232,1541,430 313,134,600 51'1,003,'911 437,il31,593 302,372,919 233,735,757 3,337,751 ,7i!l6 Purchased gas eoosl 87,661:1,031 i!IG,815,495 84,674,791 106,541,598 110,51-8,44~ ~05,162.132 , 17,238,954 156.436.5-71 3:30,1315.525 221.732,049 117.560,'lliBl!I 73,1138,824 t592.:?3~.07S ID11!!JS!l!9me.r.it ElimJnation- Gas Costs '1:,175.135-J iS.502.489~ !l.389.593~ {10.584,539l ,,o,01s.eeaJ {iD,136,.(]31~ [11,76'1,646] ~6.454,459] f2.1,200,:5B4~ D D D ~.2BCJ,143~ Total Pinche:s-ed Gas- Costs eo,484.ase 72,313,QDG 77.285.196 S6.9S7,0Ei0 100,442,713 915,026,101 !05,477~00 149,'982.'112 309,535,941 221,732,049 117,55o,668 73,166,824 1- ,498,-953,93$ GIOS$Pfi!lfil 126,652,600 1::15,429,246 1'13,228,861 127,213,17-B 124,1)84,406 123,754,'254 '27,16"4,122. 163,152,4:88. 204,467,91551 215,'25151,543 184,822,251 16D,fi68,:9i!L3 1,838,79'7,852 Ope:ralingElCpenses Ope1ailion & M1Eintammce .. 3.477.542 49,527.345 44,4:39,366 5i.011,717 lj!jl,941,093 63,855,427 40,176,479' 45,5HJ,'HIO 4Ei,a10,111 44,:312,7~a 42,791,-465 45,1:55.2D7 566.4BB.Eii50 Depreciation 11nd Amcrtlzalioci 24.~6Ei,3S9 2:•1,3 ..1."868 2"4,s60.1ae 25,106,840 25,161!1,3CJ6 26,155,527 25,459',8o4 2s,bl,a55 26,152,517 25,.fl1'2,139 25,.S49,9M '2G,1l05,472 .304,694,IS-?:a fa)(ea-oliherthanlneomet.xe:s 19,5'61,89~ '$3,241,044 21,44G,815 16,719,050 16,721.Q93 tG,704,.915 15,975,0Si!I 19,5:01,161 22,203,'271 2"1,;244,6'25 20,944,413 20,4'23,745 232,681,28.2 Tora! Op@raling Eii11:11nso:ii 67,205,792 92,110,245 90,8:3D,a89 92,.fl37,6'1l7 '91,B25,493 106,715,969 31,6,1,341 510,541,917 94,1565,:965 94,369,677 89,~5.737 91,564,424 1,103,1164.EKl5 Op!l=ratlnig; ln®mie (LO$~) 41.-<146,BCI& 43,319,001 S2,39a,472. 34,435,512 33,15'-S,912 t7.03Fl,;2BS 4!ii,552;,7Bt 72,6Hl.571 109.802,005 120,S29,86e 95,236,-165 69,(J04,S09 7J4,933,2.47 othe~ lneotne (e:iipe111:Se$) lnten1slE:Jcpe-.nGoD:s (.fl,7'26,03"4) (8,610,452) ~I0,362,551) (10,00,8$1) ('9,i901,769-) ~10,360,1-65) (:9,536,&49] (51,294,3S7) (12,208,663] (9,'223,186} (8,&:91,9'32) (B,629,567) C115,689.3S&J 111,erestlnocome 11,969 10,246 16111,725 11,&62 14,7(1-:3 167.l!i95 15,833 1:2.8:31 184,'695 tl,173 4.800 1:97,697 ao5.411 Other Nom:1per.a.1r1119 lni:xi-mie 235.147 4.c9,140 ~39,38-4~ 481.200 ~-33.952] ~· .o7"1.431J~ 61,769 (1.607.293) 37,2e7 14,-496,0$@ [H1.'12&J [499,G21~ 1'2,Cl65,2(11 Tc!al ottser ir.1001110 (Loss) (.0,47i,89fJ) ~8.151,064} ~10,235.200) (9,060.7'9) (ill,S-'21,0'lB) (11,266,701) !,9,fil.,241] (10,7611,8-19) (11,9116,001) 5,279,CIE-I (9,321!1,5'01) (9,fi:I0,11191) c1 OJ,m-B,776] lil\oeome f!As.s) 'bll!foro lncomQ TaJCQS .32,9e7,91D 35-,167,91117 42,163.263 24,884,862 '23,237,894 5,771,-51!14 ::W,093,534 151,621,752 97,815,204 126,208,947 85,S07,964 59,373,EUB -631,914.471 Prnvbit111n (Bll!nel'il} l'o' Income- tRKes. 10.9-24,116 13,195,01-C 14,9137,404 9,29.9,473 .B,Ell94,001 1,1370.$93 i:3,45S,,670 23.l'Jo47.1"19 3"1.194,"401 62,713,0$7 32,206,8dl6 22,284,2.01 '236,721,770 Ne; lnocme- {LO$$~ 22,Cl-43,794 2'1,972,927 27,175,859 15,61!i5,J39 14,5~,893 4,101,192 22,637,t!iGS 38,774,603 63,"320,003 73,435,i!IOO 53,701,1'.168 37,589,417 395J92.701 Attachment JLS·1 ATTACHMENT3 Page70of72 AhrmsEn1191J1"Clll]Jlll!illlbn l:n¢9mi;i.$llltol=r!'lllft~·'to~ICtln!Pfl~~ TIWMI Mor:ilhs lft1di!Jd Merdl oi, '2011 Dts~'~dlll Am:1f M!l!:::ir Al:!9•11il Sfl!:1.S F~l!.-1'7 i!lHHU!5 ,.., Rlilsidc;onliaiuloas HS.-4BEl,7BU 83,4211,19!!1 BB,1fl9.2B:l B1.4.li~.P!!6 i'5-J11.11,6157 79,.1;82,!Mo7 :113,2&::;,513 9'T,114a,009 2117.63&5.965- :lll4.,5J3.i56" 2ltRlll.621 163,153,854 1.590.186,110 U1'1bl"ladR1tSlden~al:A!ivN1U1!1 m.;i.i.i:.4w (1.!j;~,!P14} l~;i149JIQ1J l2.~B1,•U!l-j 9,6!!1,.47§ ~l.31 l.7JO) !!i,:91t,!!il3 :i.t,920,7-67 .§!i..'117.4,:ro& (9,-13:1!,~ (:!S,Jl!i7,7!i-ll (211.l'di!i,a~ lt,2.t!l,71!iSj '"'41l11D C9mnll!R:i~l:j1ncjlndu;!:riat&!kl i8Jl511,ll'l'B lil!l,609..944 73.17.4..1'04 97.500.MS :st.~.m ~."11lll,u:illl ~.~.!j:ll~ !lll,t~.~ 1J:i',111*.0l5 17,119 51.!iillll ;ill!;l.~!;87 41!111 Commllrti~I !b:n111nu1J ~.a!lll'.~ag :i:!J,e.e,O!ld. !111,SOll,.Silo 3':,012,4114 311,35B,1lll -l!D,:917,8'9 45,~511.511 n.'99:3,1!14 1'9.+13)!<51 1!9,99'4,21!!i 87,810,2'·U"' '8T!!l,&211,!lo7!i 4B~2 lniluij.'lsi:jilR~wn~& 9.lfili.t.958 3.121.!HS 3.1G4.l!ii'2 3.SS2.li'2 3,.:illl',4Clll ~.T.W.7~ J.T.l•.IJ~ -1!,4TUllJ. 5.-nl.:m MJ2.J~ 1ill.10ll,H2 14,ilS!i!,445 74,8$11.11112 "'"""" 2!0,5911 ,,.,,. 6Cl,7114 .li,5:Z:Z,5,;J .lilH:J. lrrip!lllooREM!mHi. 504,905 '538,232 GOO,:Z..1111 '8117,13~ 53U7r t55.6S4 '1'11,5,4 211l9:D. 41ns Ur.at111edCdirl1W1Rl!W1~LJIJ '18.551,w.IJ- 1.323..540"'"' 11 •.flllo7.131>) i;974.Z<.lj 4,lQl!l,B.311 (!,S11t.nt1 !,&l!l!l,i.s 1:!1.~91.1:m!1 51t0 1S1,~.4 (1,l!i11,llOll]o ~15,tT.ol,l!iS1J (d,a~:r.m11 l:Z.4154,41BI 41Ull- Ur.ibllledlllilu!l.lrialRl!Ye- (:!U,500} ~!llW.112) ,20,&t.3 13.m> !l:l,3i!l!i iit.'650) t41!1,M4 1n.at2) i'li2.:1-12 tD.D.156 {t,6'8.BH} (t...11~7.o!OO) 1!1,934.2~5 Cl:hafSa!l!osmPutlhll.Alllhoot J,11J2.11!S5 1..ll'll.!Mt 1,llllo7,0J4 1.•311..7-ST 1,ttZ,1H !,600,.599; l,87d,71:!1 2.4711-,212 .4,'686,17.S 1,4Ut,§a3 6,~511,:!l:ll!i 4,6!i1;325 99,37-11,100 Ur.ibilledPublil:AuthoriryRe'l'll [841!1;11511]. ~..118.sl'll 7,994 43,7..119 ~67,1169} t511...fl3.1j 46$.815 §ll;2,CIJ5- 1.'236,11.5 :int.Zn Q00,802J !004.11'4'1 ~1.:llm ,.,.""' l!a;,d.41 "" Sa1Eislim'lls<1la 4'.1111-J i;3,S;i15j !il.:m n1,e!;l!I 1.00.1 '8,:1.tll- .... ~:2.1.5 ..,, !l'l,199 Forfdi;iddiKOllnt. 2115,309 254,3"10 211!1,1!03 25~m ,,.,,, ~12.~ ~7.Slllll 14~.:zillll llll:S..!111-7 4.Bill...45:! 31!;1,4D1 ::t!D,m.t '·"" "" ....""' Mi&caHi11l1Jgll5&al'l'iilanr.t1nlH!5 2,D5!:i;ll~ i.'1117,W 1,a.l'!l,Tiill 1.51!;8..1!1 1,957,1:911 1,11111.-112!3"'"' i,SB:z;m1 :l!,339,,004 2',412,9.liB 4,21113,21.5 <11,1131.768 2.ClBll111.5 .2!i'.'lll1,8BD R'l'1'911H•Trara~pOOil"liooTFilmmis:;P:in B.5!12,51tl D.11~.6'o!lll 0.3114,:zf;ol t.Z!-t.4311 B.!lt!lli,llQ8 :9.722.41..11 U~2."lm' 7.2Q8.7.:;.s S.7111.6~ u.n:u~ 7,Q4Vii:ll1i -11,:u;;i.m 'llll-A4T,!i'11 '"" Rl!t'l!ll1IG·Tial'!S191l211i1111-IJIWlilrlf1;1n §,!!192.-81!1!1 ~Bd;S.113.1 5,;006,11&' 5.nil.128 !),-852,ll'Jll .,,.,,, tl.DBB.OOt T,1.119,:!;84 U!lll,B7.4 B.1-51,BBil T.1:00,60 1.50.11,005 B1.403.6156= ""' R1!!••l:fl:llG-.!l'lill'iil!l=G~$Qlt.i11t.;; 2~&.3oli '2117.163 2llil,l!Ei1 230.~ :m1,511.s ~J5,.8'1!1 1!i14,181 214!,~ 2:1:.S..:!i:r& 251.W ...... ,,.'"" lr-c:klcri~~solillo ar1d O~&I 10,t>all 2l...1171 "'·""SB,fill3 5..750 R6951 ll!Z.~55 neml'mr:ngasplDjll!ny 16,Hl 11ll,9Gll 1!;1,SQ~ 1B,13~ •s.nt ~5.13t 16,UI 1e,1:11i !G,132 16,7.31 Ht.73-1 :20'-1,61.S "" Odler~sl'l!lll!nues 531!;""'• .tOO G16,541 9111!1,!164 319,3.1'!1 391.5Sll -657.lllllt 41U51 1,:826.16& -191>,5]0 li-'21.512 1.m428 Ati\ omergi;isrfo\ll!'JWes(lJlllll!ei;ll!lll) tHl.~l.13t> 5.94:S.5!3Q &71M.4il5 f,l,...1141,011) {ll,::;i1a,11Eill;i (l,1!170.~"''" tA,:l;lll,.5!1.41 13,P~721!o S,..U.t;,!1:9 tt4,25!5,il:!lA~ :12o1.r.1:!l!i-J"'"" 1§42;1!1~1 {1.-483,61'2) ..., OlflarG;ssR9¥ell'll95'1ReoifizadJ 1411,~19 Hl3,IJ.T! ~~2.00 t45.2£! li1.71iZ 291.IJ5l9 391;,lti'.3 1,li!le.P.11 - PnMsioraflll'Ri!daF!aliMlii (!1;7!),0001 !:l.'ll~&t-11. ~217.475) 1,359;111:9 ~" "·"' "'"' ,.,, lnl!!l"&!lljl!lllMlt'illiniooilkllll ~.175.1:!.51 i&!!ill'.i!4B~ Q;38B.69~ iio.'5&4.5311l ,i!Hl1566B! jl'lll~00.11 [l'i 7'61.646~ ji>~54 459! &;:12005"4~ !~.2lW1<3l Total.Rl'HMIH 2(1i,Ul,4!11 20711.t"Z,:ESZ Z2ll',~141,• ttl,,23(1~1 il:25,.C21,178 :111,711l,Sli4 232,MM:W :113;,1M,GDll tiH,003;,!111 431,001,5:!13 :30:1,:t12,!1!JI""" Zl3,JJ5,1iio7 s,iU,751,Till Purii:hil&rtdOH'CllSt bl!l!llbl!lll!lpH1~G1!1'fil(ill~i;IP~l'C:l>;l$!!4 2.1,101 [~lj!.~'5] 1:i.a1&) (•1 •.4111 l:!l,SEiS) ~·VM Cfl!l'.'11:11] (2,dca,,:lo!I&) ,.., =~.;31aJn ... 4.·llrl~.~49 21.174 .... 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Oe~tilllcl)~ll:lo!! 2..,,%4,244 ]5,1129.74~ 25,lli T;r.w;&;;vlh:arilhil'll ieo;:om& tin~ utility Df'IRillEl!il lnoome 19,561,891 1.S,241.-114.., 2U4l1B15 1v.n11o.050 16.T.!1.00-3. [email protected].!;11!S 11ii.tT~,Q5lll 1!il,!!ilt1.1ii;'I Zl.Nl-.'211 2'1.1-4-4.'25 11>J1+1.41a ;rD.4~,7•!? :r.;12,l!ill1,~~ OUm·lno;ivm• ..,, Rl!QUlalcll'fCrltib 11~.olidlD (~1.4al (~1 •..W91 (,1,-1491 {t1,449J !1lMlf,I 'i..5(Jli.J (~1.AOOI rt~.-lll;ij lH,MIJ.] {11,41:13) {U,.cll;l.J 1132.2171 ..,. ~lllltitV''Cl Atmos Energy Corporation - Colorado Service Areas Test Year Ended March 31, 2017 Table of Contents Line Number Schedule/WP Description 35 WP6-4 Division 012 Depreciation Adjustment 36 WP6-5 System Safety and Integrity Rider (SSIR) Depreciation 37 Schedule? State and Federal Taxes 38 WP 7-1 Allocation of Taxable SPAS 106 Trust Contributions Over PAYGO 39 WP 7-1-1 Computation of SFAS 106 Expense Over PAYGO 40 Schedule 8 Colorado Rate Base 41 WP 8-1 Plant In Service 42 'NP 8-1-1 SSIR Plant In Service 43 WP8-2 Accumulated Depreciation & Amortization Acct 108 44 WP 8-2-l SSIR Accumulated Depreciation & Amortization 45 WP8-3 Construction Work in Progress (CWIP) 107 46 WP 8-3-1 SSIR Construction Work in Progress 47 WP8-4 Gas Stored Underground Account 1641 48 WP8-5 Accumulated Deferred Income Tax (ADIT) Accounts 190/282/283 49 WP 8-5-1 Accumulated Deferred Income Tax Adjustment to Account 190 50 \VP 8-5-2 Accumulated Deferred Income Tax Adjustment to Account 282 51 WP 8-5-3 Accumulated Deferred Income Tax Adjustment to Account 283 52 \VP 8-5-4 SSIR Accumulated Deferred Income Tax Adjustment 53 W'P 8-6 Customer Advances for Construction Account 252 54 WP8-7 Customer Deposits Account 235 55 WP8-8 Prepaid Pension Expense Miscellaneous Deferred Debit 1860, Sub Account 13993 56 WP8-9 Prepaid Account 165 57 WP 8-10 AFUDC Capital Interest 58 WP 8-11 Cash-Basis Cash Working Capital Analysis 59 WP 8-11-1 Sales, Revenue Taxes and Franchise Fees Collected 60 Schedule 9 Capital Structure and Cost of Capital 61 WP9-l Schedule of Consolidated Long Term Debt and Equity 62 WP9-2 Consolidated Long-Term Debt Outstanding w/ Calculation of Effective Interest Rates Table of Contents 2of2 Atmos Energy Corporation - Colorado Service Areas Allocation Factors Test Year Ended March 31, 2017 CO/KS Allocation Colorado Allocation Line No. Description SSU Allocation Factor Factor Factor (a) (b) (c) (d) 1 SSU General Office (I) (Division 002) 6.80% 42.51% 2.89% 2 SSU General Office - Greenville (2) 1.17% 3 SSU General Office - AEAM (3) 7.73% 42.51% 3.29% 4 SSU General Office -Aligne (4) 0.00% 42.51% 0.00% 5 6 SSU Customer Support (5) (Division 012) 8.07% 46.96% 3.79% 7 SSU Customer Support- CKV (6) 2.06% 8 9 CO/KS General Office (7) (Division 030) 42.51% IO 11 CO General Office (Division 031) 100.00% 12 13 Colorado Direct (Divisions 033, 034, 035, 036) 100.00% 14 15 Notes: 1. The SSU General Office allocation factor is a composite three-factor formula based upon gross direct PP&E, average 16 number of customers and total O&M expense. 2. The SSU General Office - Greenville allocation factor is a composite three-factor formula, the same as SSU General 17 Office, plus square footage usage at Greenville. 3. The SSU General Office - AEAM (Atmos Energy Atmos Marketing) allocation factor is based upon a composite three- 18 factor formula for all entities except Atmos Pipeline - Texas. 4. The SSU General Office - Aligne allocation factor is based upon transportation volumes billed for the applicable 19 divisions/jurisdictions. 20 5. The SSU Customer Support allocation factor is based on the number of customers. 6. SSU Customer Support - CKV (Charles K. Vaughan) allocation factor is based on the number of customers, number of 21 employees trained at CKV and square footage. 7. The CO/KS General Office allocation is a composite three-factor formula based upon Colorado's and Kansas' gross direct 22 PP&E, average number of customers and total O&M expense for each jurisdiction. Allocation Factors 1 ofl Atmos Energy Corporation - Colorado Service Areas Revenue Requirement and Revenue Deficiency Calculation Test Year Ended March 31, 2017 Adjusted Line Colorado No. Description Reference Service Area (a) (b) (c) 1 Total Rate Base Schedule 8 $ 140,938,189 2 3 Rate of Return on Rate Base Schedule 9 8.14% 4 5 Return on Rate Base (Ln 1*Ln3) $ 11,472,369 6 Operation & Maintenance Expense Schedule 4 15,756,894 7 Depreciation & Amortization Expense Schedule 6 9,726,747 8 Taxes Other Than Income Taxes Schedule 5 2,463,874 9 AFUDC Capital Interest W orkpaper 8-10 (19,026) 10 Income Tax Schedule 7 5,046,820 11 12 Total Cost of Service (Sum ofLns 5 - 10) $ 44,447,678 13 14 Margin Revenue at Present Rates Schedule 2 $ 41,532,075 15 16 Revenue Increase Required (Ln 12 - Ln 14) $ 2,915,603 Schedule 1 1of1 Atmos Energy Corporation - Colorado Service Areas Summary of Revenue at Present Rates Test Year Ended March 31, 2017 WNA& Line Vol. CcfAvg 14.65 Adjustments to Proration Adjusted Adjusted Total No. Description Number of Bills psi VolumeCcf % Variance Adjustment Total Bills Volumes (a) (b) (c) (d) (e) (f) (g) (h) Residential 1,270,158 71,958,583 5,273,791 -2.0% (25,776) 1,244,382 77,232,374 2 Commercial 146,418 46,863,776 2,950,941 -1.2% (1,788) 144,627 49,814,717 3 Irrigation 121 49,443 0 -2.0% (2) 119 49,443 4 5 Total Colorado Sales Revenue 1,416,697 118,871,802 8,224,732 -1.9% (27,566) 1,389,128 127,096,534 6 7 Vol. Ccf Avg 14.65 Adjustments to Adjustments to Proration Adjusted Adjusted Total Number of Bills psi VolumeCcf Bills Adjustment Total Bills Volumes 8 Trans11ortation Revenues 9 Max Rate - Commercial 1,676 9,350,490 828,645 112 1,788 10,179,135 10 Special Contract 2,556 43,708,940 (938,190) (84) 2,472 42,770,750 11 Total Transportation Revenues 4,232 53,059,430 (109,545) 28 4,260 52,949,885 12 13 Other Revenues 14 15 Total Colorado Revenue Schedule 2 1 of3 ... ,·. Atmos Energy Corporation - Colorado Service Areas Summary of Revenue at Present Rates Test Year Ended March 31, 2017 Line Adjusted Present Adjusted Gas Cost Adjusted Present No. Description Customer Charge Commodity Charge Base Revenue Revenues Total Revenue (a) (i) (j) (k) (I) (m) Residential $ 11.60 $ 0.18885 $ 29,020,171 $ 35,625,566 $ 64,645,737 2 Commercial 28.24 0.11145 9,636,124 23,075,200 32,711,324 3 Irrigation 45.17 0.10305 10,451 22,013 32,464 4 5 Total Colorado Sales Revenue $ 38,666,746 $ 58,722,779 $ 97,389,525 6 7 Transportation Transportation Transportation Adjusted Gas Cost Adjusted Present Customer Charge Commodity Charge Revenue Revenues Total Revenue 8 Transgortation Revenues 9 Max. Rate - Commercial $ 84.70 $ 0.09172 $ 1,085,074 $ $ 1,085,074 10 Special Contract 1,403,303 1,403,303 11 Total Transportation Revenues $ 2,488,377 $ $ 2,488,377 12 13 Other Revenues $ 376,952 $ 376,952 14 15 Total Colorado Revenue $ 41,532,075 $ 58,722,779 $ 100,254,854 Schedule2 2of3 ...... · ... ·•··. Atmos Energy Corporation - Colorado Service Areas Summary of Revenue at Present Rates Test Year Ended March 31, 2017 Proposed Base Rates Proposed Base Rates with Rate Case Expense Proposed Proposed Proposed Proposed Line Customer Commodity Customer Commodity No. Description Charge Rates Proposed Revenue Charge Rates Proposed Revenue (a) (n) (o) (p) (q) (r) (s) (t) Residential $ 12.45 $ 0.20269 $ 66,772,358 $ 12.59 $ 0.20494 $ 67,120,344 2 Commercial 30.31 0.11962 33,417,687 30.65 0.12095 33,533,114 3 Irrigation 48.48 0.11060 33,230 49.02 0.11183 33,354 4 5 Total Colorado Sales Revenue $ 100,223,275 $ 100,686,812 6 Proposed Proposed Proposed Proposed 7 Customer Commodity Customer Commodity Charge Rates Proposed Revenue Charge Rates Proposed Revenue 8 Transi:iortation Revenues 9 Max Rate - Commercial $ 90.91 $ 0.09844 $ 1,164,581 $ 91.92 $ 0.09953 $ 1,177,482 10 Special Contract 1,403,303 1,403,303 11 Total Transportation Revenues $ 2,567,884 $ 2,580,785 12 13 Other Revenues $ 376,952 $ 376,952 14 15 Total Colorado Revenue $ 103,168,111 $ 103,644,549 Schedule2 3 of3 Atmos Energy Corporation - Colorado Service Areas Summary of Per Books Revenues and Adjusted Transportation Revenue Test Year Ended March 31, 2017 Line No. DescriEtion Total (a) (b) 1 Per Book Revenues: 2 Sales Revenue (Including Unbilled) $ 78,866,219 3 4 Transportation Revenues 2,570,375 5 Other Revenues 376,952 6 Total "Transportation & Other" Revenue - Per Book (Sum Ln 4 + 5) $ 2,947,327 7 8 Total Revenues - Per Book (Sum Ln 2 + 6) $ 81,813,546 9 10 Transportation Revenue Adjustment: 11 Transportation Revenues (Ln 4) $ 2,570,375 12 Adjustments to Transportation Revenues (81,998) 13 Adjusted Transportation Revenues (Ln 11 + 12) $ 2,488,377 14 15 Other Revenues (Ln 5) $ 376,952 16 Adjustments to Miscellaneous Service Revenues 17 Adjusted Miscellaneous Service Revenues (Ln 15 + 16) $ 376,952 18 19 Transportation GCA Revenue $ 20 Total Transportation and Other Revenues - Adjusted (Sum Lns 13, 17, 19) $ 2,865,329 WP2-1 1of1 Atmos Energy Corporation - Colorado Service Areas Volume Adjustments Summary Test Year Ended March 31, 2017 Line Weather Stations (1) No. Description GGRB GCRA GGUN GSTE GCAN GLAM GDUR TOTAL (a) (b) (c) (d) (e) (f) (g) (h) (i) 1 Residential Ccf 2 NE Weather Adjustment 2,095,015 3 NE Non-Weather Adjustment 0 0 0 0 0 0 0 5 NE Volume Adjustment 2,095,015 0 0 0 0 0 0 2,095,015 6 7 NW/Central Weather Adjustment 0 222,101 498,326' 587,613 0 0 0 8 NW/Central Non-Weather Adjustment 0 0 0 0 0 0 0 10 NW/Central Volume Adjustment 0 222,101 498,326 587,613 0 0 0 1,308,040 11 12 SE Weather Adjustment 0 0 0 0 771,348 267,362 0 13 SE Non-Weather Adjustment 0 0 0 0 0 0 0 15 SE Volume Adjustment 0 0 0 0 771,348 267,362 0 1,038,710 16 17 SW Weather Adjustment 0 0 0 0 0 0 832,026 18 SW Non-Weather Adjustment 0 0 0 0 0 0 0 20 SW Volume Adjustment 0 0 0 0 0 0 832,026 832,026 21 WP2-2 1 of2 Atmos Energy Corporation - Colorado Service Areas Volume Adjustments Summary Test Year Ended March 31, 2017 Line Weather Stations (1) No. Description GGRE GCRA GGUN GSTE GCAN GLAM GDUR TOTAL (a) (b) (c) (d) (e} (f) (g) (h) (i) 22 Commercial Ccf 23 NE Weather Adjustment 1,045,507 0 0 0 0 0 0 24 NE Non-Weather Adjustment 0 0 0 0 0 0 0 26 NE Volume Adjustment 1,045,507 0 0 0 0 0 0 1,045,507 27 28 NW/Central/Weather Adjustment 0 167,903 329,697 522,446 0 0 0 29 NW/Central/ Non-Weather Adjustment 0 0 0 0 0 0 0 31 NW/Central Volume Adjustment 0 167,903 329,697 522,446 0 0 0 1,020,046 32 33 SE Weather Adjustment 0 0 0 0 246,236 138,170 0 34 SE Non-Weather Adjustment 0 0 0 0 {10,135) 0 0 36 SE Volume Adjustment 0 0 0 0 236,101 138,170 0 374,271 37 38 SW Weather Adjustment 0 0 0 0 0 0 511,117 39 SW Non-Weather Adjustment 0 0 0 0 0 0 0 41 SW Volume Adjustment 0 0 0 0 0 0 511,117 511,117 42 43 Total 3,140,522 390,004 828,023 1,110,059 1,007,449 405,532 1,343,143 8,224,732 44 45 Note: 46 1. Weather stations are as follows: GGRE =Greeley; GCRA =Craig; GGUN =Gunnison; GSTE = Steamboat; GCAN =Canon; GLAM =Lamar; GDUR =Durango. WP2-2 2of2 Atmos Energy Corp. - Colorado Service Areas Weather Normalization - Northeast Division 033 Test Year Ended March 31, 2017 Line No. Description Residential Commercial Total (a) (b) (c) (d) 1 Revenue: 2 Ccf Sold, Including non Weather Adjustments GORE 3 (Greeley) 30,862,766 16,768,299 47,631,066 Average Customers, Including non Weather 4 Adjustment OGRE 47,783 4,500 52,284 5 6 Ccf Sold per Customer OGRE (Ln 3 I Ln 4) 646.0 3,726 7 8 Non-heating Sales: 9 July 2016 Ccf Sales/Customer GORE 14.2 105.4 10 August 2016 Ccf Sales/Customer GORE 12.6 87.3 11 Total GORE (Ln 9+Ln10) 26.8 192.7 12 Annualized GORE (Ln 11 * 6) 160.6 1,156.3 13 14 Heating Sales per Customer GORE (Ln 6 - Ln 12) 485.0 2,570.0 15 Average Number of Customers GORE 47,783 4,500 52,284 16 17 Total Heating Sales Ccf OGRE (Ln 14 * Ln 15) 23,174,947 11,565,340 34,740,287 18 19 Degree Days GORE: 20 12 Months ended 3/31/17 4,933 4,933 21 NormalGGRE 5,423 5,423 22 WP2-3 1 of2 ···-·.· .· Atmos Energy Corp. - Colorado Service Areas Weather Normalization - Northeast Division 033 Test Year Ended March 31, 2017 Line No. Description Residential Commercial Total (a) (b) (c) (d) 23 24 Percent Change ((Ln 21 - Ln 20) I Ln 21) 9.04% 9.04% 25 26 CcfWeather Adjustment GGRE (Ln 24 * Ln 17) 2,095,015 1,045,507 3,140,522 27 Total Normalized Heating Volumes (Ln 17 + Ln 26) 25,269,962 12,610,847 28 29 Normal Heating Usage Per Customer (Ln 27 I Ln 15) 529 2,802 30 31 Avg Monthly Base Load (Ln 12 I 12) 13.4 96.4 32 33 Total Normal Usage Per customer (Ln 12 + Ln 29) 689 3,959 WP2-3 2 of2 .--.' Atmos Energy Corp. - Colorado Service Areas Weather Normalization - Northwest/Central Division 034 Test Year Ended March 31, 2017 Line No. Descri2tion Residential Commercial Total (a) (b) (c) (d) Revenue: 2 CcfSold, Including non Weather Adjustment GCRA 3 (Craig) 3,388,619 2,795,960 6,184,579 Average Customers, Including non Weather Adjustment 4 GCRA 4,595 676 5,271 5 6 Ccf Sold per Customer GCRA (Ln 3 I Ln 4) 737.0 4,134 7 8 Non-heating Sales: 9 July 2016 CcfSales/Customer GCRA 15.6 108.8 10 August 2016 CcfSales/Customer GCRA 12.6 94.l 11 Total GCRA (Ln 9 + Ln 10) 28.2 202.9 12 Annualized GCRA (Ln 11 * 6) 169.3 1,217.3 13 14 Heating Sales per Customer GCRA (Ln 6 - Ln 12) 568.0 2,917.0 IS Average Number of Customers GCRA 4,595 676 5,271 16 17 Total Heating Sales CcfGCRA (Ln 14 * Ln 15) 2,609,881 1,973,013 4,582,894 18 19 Degree Days - GCRA: 20 12 Months ended 3/31/17 7,463 7,463 21 NormalGCRA 8,157 8,157 22 23 24 Percent Change ((Ln21- Ln 20) I Ln 21) 8.51% 8.51% 25 26 CcfWeather Adjustment GCRA (Ln 24 * Ln 17) 222,101 167,903 390,004 27 Total Normalized Heating Volumes (Ln 17 + Ln 26) 2,831,982 2,140,916 28 29 Normal Heating Usage Per Customer (Ln 27 I Ln 15) 616 3,165 30 31 Avg Monthly Base Load (Ln 12 I 12) 14.1 101.4 32 33 Total Normal Usage Per customer (Ln 12 + Ln 29) 786 4,382 WP2-4 1 of3 Atmos Energy Corp. - Colorado Service Areas Weather Normalization - Northwest/Central Division 034 Test Year Ended March 31, 2017 Line No. DescriEtion Residential Commercial Total (a) (b) (c) (d) 34 Revenue: 35 CcfSold, Including non Weather Adjustment GGUN 36 (Gunnison) 8,ll6,083 7,562,309 15,678,392 Average Customers, Including non Weather Adjustment 37 GGUN 10,142 1,665 11,807 38 39 Ccf Sold per Customer GGUN (Ln 36 I Ln 3 7) 800.0 4,542 40 41 Non-heating Sales: 42 July 2016 CcfSales/Customer GGUN 20.9 184.4 43 August2016 CcfSales/Customer GGUN 19.2 197.2 44 Total GGUN (Ln 42 + Ln 43) 40.1 381.6 45 Annualized GGUN (Ln 44 * 6) 240.5 2,289.5 46 47 Heating Sales per Customer GGUN (Ln 39 - Ln 45) 559.0 2,253.0 48 Average Number of Customers GGUN 10,142 1,665 11,807 49 50 Total Heating Sales CcfGGUN (Ln 47 * Ln 48) 5,669,238 3,750,816 9,420,054 51 52 Degree Days - GGUN: 53 12 Months ended 3/31/17 9,273 9,273 54 NonnalGGUN 10,167 10,167 55 56 57 Percent Change ((Ln 54 - Ln 53) I Ln 54) 8.79% 8.79% 58 59 CcfWeather Adjustment GGUN (Ln 50 * Ln 57) 498,326 329,697 828,023 60 Total Normalized Heating Volumes (Ln 50 + Ln 59) 6,167,564 4,080,513 61 62 Normal Heating Usage Per Customer (Ln 60 I Ln 48) 608 2,451 63 64 Avg Monthly Base Load (Ln 45 / 12) 20.0 190.8 65 66 Total Normal Usage Per customer (Ln 45 + Ln 62) 849 4,741 WP2-4 2 of3 Atmos Energy Corp. - Colorado Service Areas Weather Normalization - Northwest/Central Division 034 Test Year Ended March 31, 2017 Line No. Descri2tion Residential Commercial Total (a) (b) (c) (d) 67 Revenue: 68 CcfSold, Including non Weather Adjustment GSTE 69 (Steamboat) 7,081,834 6;973,774 14,055,608 Average Customers, Including non Weather Adjustment 70 GSTE 7,212 1,221 8,433 71 72 CcfSo!d per Customer GSTE (Ln 69 / Ln 70) 982.0 5,713 73 74 Non-heating Sales: 75 July 2016 Ccf Sales/Customer GSTE 24.0 175.4 76 August 2016 Ccf Sales/Customer GSTE 22.5 161.3 77 Total GSTE (Ln 75 + Ln 76) 46.5 336.7 78 Annualized GSTE (Ln 77 * 6) 279.0 2,020.0 79 80 Heating Sales per Customer GSTE (Ln 72 - Ln 78) 703.0 3,693.0 81 Average Number of Customers GSTE 7,212 1,221 8,433 82 83 Total Heating Sales CcfGSTE (Ln 80 * Ln 81) 5,070,002 4,507,732 9,577,734 84 85 Degree Days - GSTE: 86 12 Months ended 3/31117 8,237 8,237 87 Nonna! GSTE 9,316 9,316 88 89 90 Percent Change ((Ln 87 - Ln 86) I Ln 87) 11.59% 11.59% 91 92 CcfWeather Adjustment GSTE (Ln 83 * Ln 90) 587,613 522,446 l,l I0,059 93 Total Normalized Heating Volumes (Ln 83 + Ln 92) 5,657,615 5,030,178 94 95 Normal Heating Usage Per Customer (Ln 93 I Ln 81) 784 4,121 96 97 Avg Monthly Base Load (Ln 78 / 12) 23.3 168.3 98 99 Total Normal Usage Per customer (Ln 78 + Ln 95) 1,063 6,141 WP2-4 3 of3 Atmos Energy Corp. - Colorado Service Areas Weather Normalization - Southeast Division 03S Test Year Ended March 31, 2017 Line No. Description Residential Commercial Total (a) (b) (c) (d) Revenue: 2 Ccf Sold, Including non Weather Adjustment GCAN 3 (Canon) 7,910,050 2,642,136 10,552,186 Average Customers, Including non Weather Adjustment 4 GCAN 13,003 1,004 14,007 5 6 Ccf Sold per Customer GCAN {Ln 3 I Ln 4) 608.0 2,631 7 8 Non-heating Sales: 9 July 2016 Ccf Sales/Customer GCAN 12.5 67.0 10 August 2016 Ccf Sales/Customer GCAN 11.1 50.4 11 Total GCAN {Ln 9 + Ln 10) 23.6 117.4 12 Annualized GCAN (Ln 11 * 6) 141.8 704.7 13 14 Heating Sales per Customer GCAN (Ln 6 - Ln 12) 466.0 1,926.0 15 Average Number of Customers GCAN 13,003 1,004 14,007 16 17 Total Heating Sales Ccf GCAN {Ln 14 * Ln 15) 6,059,295 1,934,300 7,993,595 18 19 Degree Days - GCAN: 20 12 Months ended 3/31/I 7 4,763 4,763 21 NormalGCAN 5,457 5,457 22 23 24 Percent Change ({Ln21 - Ln 20) /Ln 21) 12.73% 12.73% 25 26 Ccf Weather Adjustment GCAN {Ln 24 * Ln 17) 771,348 246,236 1,017,584 27 Total Normalized Heating Volumes (Ln 17 + Ln 26) 6,830,643 2,180,536 28 29 Normal Heating Usage Per Customer (Ln 27 I Ln 15) 525 2,171 30 31 Avg Monthly Base Load {Ln 12 I 12) 11.8 58.7 32 33 Total Normal Usage Per customer (Ln 12 + Ln 29) 667 2,876 WP2-5 1 of2 Atmos Energy Corp. - Colorado Service Areas Weather Normalization - Southeast Division 035 Test Year Ended March 31, 2017 Line -No. Description Residential Commercial Total (a) (b) (c) (d) 34 Revenue: 35 Ccf Sold, Including non Weather Adjustment GLAM 36 (Lamar) 3,599,813 2,068,038 5,667,851 Average Customers, Including non Weather Adjustment 37 GLAM 5,778 881 6,659 38 39 Ccf Sold per Customer GLAM (Ln 36 I Ln 3 7) 623.0 2,347 40 41 Non-heating Sales: 42 July 2016 Ccf Sales/Customer GLAM 12.7 60.0 43 August 2016 Ccf Sales/Customer GLAM 11.3 60.7 44 Total GLAM (Ln 42 + Ln 43) 24.0 120.7 45 Annualized GLAM (Ln 44 * 6) 144.0 724.4 46 47 Heating Sales per Customer GLAM (Ln 39 - Ln 45) 479.0 1,623.0 48 Average Number of Customers GLAM 5,778 881 6,659 49 50 Total Heating Sales Ccf GLAM (Ln 47 * Ln 48) 2,767,727 1,430,332 4,198,059 51 52 Degree Days - GLAM: 53 12 Months ended 3/31117 4,926 4,926 54 Norma!GLAM 5,452 5,452 55 56 57 Percent Change ((Ln 54 - Ln 53) I Ln 54) 9.66% 9.66% 58 59 Ccf Weather Adjustment GLAM (Ln SO * Ln 57) 267,362 138,170 405,532 60 Total Normalized Heating Volumes (Ln SO+ Ln 59) 3,035,089 1,568,502 61 62 Normal Heating Usage Per Customer (Ln 60 I Ln 48) 525 1,780 63 64 Avg Monthly Base Load (Ln 45 I 12) 12.D 60.4 65 66 Total Normal Usage Per customer (Ln 45 + Ln 62) 669 2,504 WP2-5 2 of2 .. ·.-::··. ·. .-:-.:·:· Atmos Energy Corp. - Colorado Service Areas Weather Normalization - Southwest Division 036 Test Year Ended March 31, 2017 Line No. Descri2tion Residential Commercial Total (a) (b) (c) (d) 1 Revenue: 2 CcfSold, Including non Weather Adjustments GDUR 3 (Durango) 10,999,418 8,053,259 19,052,677 Average Customers, Including non Weather Adjustment 4 GDUR 15,186 2,105 17,291 5 6 CcfSold per Customer GDUR (Ln 3 I Ln 4) 724.0 3,826 7 8 Non-heating Sales: 9 July 2016 CcfSales/Customer GDUR 15.6 119.4 10 August 2016 Ccf Sales/Customer GDUR 13.6 112.8 11 Total GDUR (Ln 9 + Ln 10) 29.2 232.2 12 Annualized GDUR (Ln 11 * 6) 175.1 1,393.3 13 14 Heating Sales per Customer GDUR (Ln 6 - Ln 12) 549.0 2,433.0 15 Average Number of Customers GDUR 15,186 2,105 17,291 16 17 Total Heating Sales CcfGDUR (Ln 14 * Ln 15) 8,336,931 5,121,415 13,458,346 18 19 Degree Days - GDUR: 20 12 Months ended 3/31/17 6,131 6,131 21 Norma!GDUR 6,810 6,810 22 23 24 Percent Change ((Ln21 - Ln 20) I Ln21) 9.98% 9.98% 25 26 CcfWeather Adjustment GDUR (Ln 24 * Ln 17) 832,026 511,117 1,343,143 27 Total Normalized Heating Volumes (Ln 17 + Ln 26) 9,168,957 5,632,532 28 29 Normal Heating Usage Per Customer (Ln 27 I Ln 15) 604 2,676 30 31 Avg Monthly Base Load (Ln 12 I 12) 14.6 116.l 32 33 Total Normal Usage Per customer (Ln 12 + Ln 29) 779 4,069 WP2-6 1 ofl Atmos Energy Corp. - Colorado Service Areas Actual Degree Days and Lagged Degree Days Test Year Ended March 31, 2017 Actual Degree Days La~ed De!£ee Days Line Greeley Craig Gunnison Steamboat Canon Lamar Durango Greeley Craig Gunnison Steamboat Canon Lamar Durango No. Month-Year Ddax:s Ddays Ddays Ddaxs Ddax:s Ddays Ddays Ddays Ddays Ddars Ddays Ddays Ddays Ddays (a) (b) (c) (d) (e) (f) (g) (h) (i) G) (k) (I) (m) (n) (o) 1 Mar-16 631 967 1,002 1,100 662 599 791 2 3 Apr-16 412 660 722 769 459 352 622 522 814 862 935 561 476 707 4 May-16 268 472 523 548 259 194 407 340 566 623 659 359 273 515 5 Jun-16 4 60 152 150 8 1 34 136 266 338 349 134 98 221 6 Jul-16 0 3 131 61 0 0 1 2 32 142 106 4 l 18 7 Aug-16 6 52 226 124 9 0 43 3 28 179 93 5 0 22 8 Sep-16 37 231 381 293 51 33 184 22 142 304 209 30 17 114 9 Oct-16 208 477 656 543 221 202 401 123 354 519 418 136 118 293 10 Nov-16 543 805 953 845 509 584 705 376 641 805 694 365 393 553 11 Dec-16 1,198 1,399 1,564 1,481 1,024 1,221 1,129 871 1,102 1,259 1,163 767 903 917 12 Jan-17 1,080 1,468 1,673 1,474 1,009 1,091 1,191 1,139 1,434 1,619 1,478 1,017 1,156 1,160 13 Feb-17 639 961 1,245 969 633 677 648 860 1,215 1,459 1,222 821 884 920 14 Mar-17 445 782 1,092 859 499 542 740 542 872 1,169 914 566 610 694 15 16 Total (Sum Ln 3 -14) 4,840 7,370 9,318 8,116 4,681 4,897 6,105 4,933 7,463 9,273 8,237 4,763 4,926 6,131 17 18 2010 30 Year Normals (1) 5,423 8,157 10,167 9,316 5,457 5,452 6,810 5,423 8,157 10,167 9,316 5,457 5,452 6,810 19 Percentage (2) 20 {Ln 16 - Ln 18) I {Ln 18) -10.75% -9.65% -8.35% -12.88% -14.22% -10.18% -10.35% -9.04% -8.51% -8.79% -11.59% -12.73% -9.66% -9.98% Degree Days From 21 Normal{Ln 16-Ln 18) (583) (787) (849) (1,200) (776) (555) (705) 22 23 Notes: 24 1. The source for the 20 l O 30 Year Normals was the National Oceanic and Atmospheric Administration (NOAA) (website: http://www.ncdc.noaa.gov/cdo-web/). 25 2. "Negative" percent indicates actual weather was warmer than normal. WP2-7 1of1 ··.·.·:.·.·-· ·.·· ...... ·,:··· Atmos Energy Corporation - Colorado Service Areas Summary of Present Rates Test Year Ended March 31, 2017 Tariff Tariff Tariff Calculated Adjusted Commodity Total Line Customer Commodity Gas Cost Margin Customer Adjusted Tariff Charge GCA Commodity No. Description Charge (1) Charge (1) Charge (c) - (d) Rider% Charge Margin Gas Cost Excluding GCA Jun - 17 (2} Charge (a) (b) (c) (d) (e) (t) (g) (h) (i) G) (k) (1) 1 Northeast 0.00% 2 Residential $ 11.60 $ 0.18885 $ - $ 0.18885 $ 11.60 $ 0.18885 $ - $ 0.18885 $ 0.48845 $ 0.67730 3 Commercial 28.24 0.11145 0.11145 28.24 0.11145 0.11145 0.48845 0.59990 4 Irrigation 45.17 0.10305 0.10305 45.17 0.10305 0.10305 0.48845 0.59150 5 6 Northwest 7 Residential $ 11.60 $ 0.18885 $ - $ 0.18885 $ 11.60 $ 0.18885 $ - $ 0.18885 $ 0.50681 $ 0.69566 8 Commercial 28.24 0.11145 0.11145 28.24 0.11145 0.11145 0.50681 0.61826 9 10 11 Southeast 12 Residential $ 11.60 $ 0.18885 $ - $ 0.18885 $ 11.60 $ 0.18885 $ - $ 0.18885 $ 0.44100 $ 0.62985 13 Commercial 28.24 0.11145 0.11145 28.24 0.11145 0.11145 0.44100 0.55245 14 Irrigation 45.17 0.10305 0.10305 45.17 0.10305 0.10305 0.44100 0.54405 15 16 17 Southwest 18 Residential $ 11.60 $ 0.18885 $ - $ 0.18885 $ 11.60 $ 0.18885 $ - $ 0.18885 $ 0.33053 $ 0.51938 19 Commercial 28.24 0.11145 0.11145 28.24 0.11145 0.11145 0.33053 0.44198 20 21 Notes: 1. Both the Tariff Customer and the Tariff Commodity Charge exclude the Rate Case Rider expense associated with Proceeding No. 15AL-0299G. The Company 22 also excludes the SSIR rates as the respective capital is not subject to a return. The Demand Side Management Cost Adjustment and Demand Side Management Volumetric Cost Adjustment rates are surcharges which are not recorded to a revenue account; therefore, these rates are also excluded. 23 2. The GCA rate (Col k) has been updated to June 2017 rates. WP2-8 I ofl Atmos Energy Corporation - Colorado Service Areas Normalized Cost of Gas - "Sales" Customers Test Year Ended March 31, 2017 Line No. Description Amount (a) (b) Colorado Distribution System Sales Volume Ccf 118,871,802 2 Weather and Customer Adjustments, Ccf 8,224,732 3 4 Normalized "Sales" Volumes Sold (Ln 1 + Ln 2) 127,096,534 5 6 Total Normalized "Sales" Gas Cost $ 58,722,779 7 8 Transportation Gas Cost (I) $ 9 10 Total (Ln 6 + Ln 8) $ 58,722,779 11 12 Note: 13 1. This represents the Transportation GCA applicable volumes for the 12 Months ending March 31, 2017 at the June 30, 2017 Transportation GCA rate. Schedule 3 1 of2 Atmos Energy Corp. - Colorado Service Areas Normalized Cost of Gas - "Sales" Customers Test Year Ended March 31, 2017 Line 033DIV 034 DIV 035DIV 036DIV No. Description Northeast NW/C Southeast Southwest (a) (b) (c) (d) (e) Colorado Distribution System Sales Vol Ccf 47,635,467 35,918,579 16,265,079 19,052,677 2 Weather and Customer Adjustments, Ccf 3,140,522 2,328,086 1,412,981 1,343,143 3 4 Normalized "Sales" Volumes Sold (Ln I+ Ln 2) 50,775,989 38,246,665 17,678,061 20,395,820 5 GCA Rates/Ccf at June 2017 $ 0.48845 $ 0.50681 $ 0.44100 $ 0.33053 6 Per Unit Base Gas Cost per Ccf $ $ $ $ 7 8 Normalized GCA Revenue $ 24,801,532 $ 19,383,792 $ 7,796,025 $ 6,741,430 9 Total Normalized "Sales" Gas Cost (Ln 8) $ 24,801,532 $ 19,383,792 $ 7,796,025 $ 6,741,430 10 11 033DIV 034DIV 035DIV 036DIV 12 Northeast NW/C Southeast Southwest 13 GCA Rates/Ccf at June 2017 $ 0.48845 $ 0.50681 $ 0.44100 $ 0.33053 Firm Transportation-Commercial, Small 14 Commercial $ 0.00626 $ 0.00626 $ 0.00626 $ 0.00626 15 Volumes 16 Transportation Gas Costs (Ln 14 * Ln 15) $ - $ - $ - $ Schedule 3 2 of2 .· .. ·.··· .. Atmos Energy Corporation - Colorado Service Areas Operation and Maintenance Expenses Test Year Ended March 31, 2017 As Adjusted Line Colorado No. Description Reference Amount (a) (b) (c} 1 Total Operation and Maintenance Expenses - Unadjusted WP4-1 $ 15,661,812 2 3 Adjustments to Ogeration & Maintenance Exgenses 4 Labor Adjustment WP4-2 $ 289,082 5 Benefits Adjustment - Pension & Insurance WP4-3 265,723 6 Adjustment for Unallocated Administrative Expenses WP 4-4-1 9,777 7 Promotional and Advertising Expense Adjustment WP4-5 (49,107) 8 Interest on Customer Deposits Adjustment WP4-6 10,284 9 Adjustment to Normalize Uncollectible Expense WP4-7 124,839 10 Adjustment for Rate Case Expenses WP4-8 (426,344) 11 Adjustments for Expense Reports and 5400 Series Accounts WP4-9 (42,854) 12 Pension Tracker Adjustment Colorado Direct and Allocated General Office WP4-10 (40,232) 13 Pension Tracker Adjustment Shared Services WP 4-10-1 (46,085) 14 Total Adjustments (Sum ofLns 4 - 13) $ 95,082 15 16 Total Adjusted Operation and Maintenance Expenses (Ln I+ Ln 14) $ 15,756,894 Schedule 4 1of1 Atmos Energy Corporation - Colorado Service Areas Colorado Revenue & Operating Expenses Test Year Ended March 31, 2017 Line Account No. Number Account Description Colorado Service Area Total (a) (b) (c) (d) 1 4800 Residential sales $ (54,197,711) 2 4805 Unbilled Residential Revenue 859,862 3 4811 Commercial Revenue (26,066,836) 4 4813 Irrigation Revenue (29,597) 5 4815 Unbilled Commercial Revenue 566,835 6 4820 Other Sales to Public Authority 1,227 7 4825 Unbilled Public Authority Revenue 8 4870 Forfeited discounts (73,427) 9 4880 Miscellaneous service revenues (303,525) 10 4893 Revenue-Transportation Distribution (2,570,375) 11 4950 Other gas revenues 0 12 Revenue (Sum ofLns 1 • 11) $ (81,813,546) 13 14 8001 Intercompany Gas Well-head Purchase $ 324,564 15 8010 Natural gas field line purchase 185,656 16 8040 Natural gas city gate purchase 32,444,533 17 8050 Other purchases (13,997) 18 8051 PGA for Residential 25,123,365 19 8052 PGA for Commercial 16,369,559 20 8054 PGA for Public Authorities 7,640 21 8055 PGA for Irrigation Sales 18,893 22 8057 PGA for Transportation Sales 23,763 23 8058 Unbilled PGA Cost (1,109,231) 24 8059 PGA Offset to Unrecovered Gas (49,165,421) 25 8060 Exchange gas 4,487 26 8081 Gas mthdrawn from storage 4,194,015 27 8082 Gas delivered to storage (3,937,574) 28 8120 Gas used for other utility operations 66,876 29 8130 Other gas supply expenses 30 8580 Transmission and compression 15,963,737 31 Gas Cost (Sum ofLns 14- 30) $ 40,500,864 32 WP4-l 1 of3 Atmos Energy Corporation - Colorado Service Areas Colorado Revenue & Operating Expenses Test Year Ended March 31, 2017 Line Account No. Number Account Description Colorado Service Area Total (a) (b) (c) (d) 33 7740 Power $ 9,800 34 8560 Mains Expenses 655 35 8570 Transmission-Measuring 2,631 36 8640 Maintenance of compressor station equipment 37 8700 Distnbution-Operation supervision 634,730 38 8710 Distribution load dispatching 116,731 39 8711 Odorization 40 8740 Mains and Services Expenses 2,526,041 41 8750 Distribution-Measuring and regulating station 23,513 42 8760 Distribution-Measuring and regulating station expenses-Industrial 43 8770 Distribution-Measuring and regulating station 47,520 44 8780 Meter and house regulator expense 331,001 45 8790 Customer installations expense 178,507 46 8800 Distribution-Other expenses 220,920 47 8810 Distribution-Rents 184,668 48 8850 Distribution-Maintenance 49 8870 Distribution-Maint of mains 78,345 so 8880 Maintenance of compressor station equipment 51 8890 Maintenance of measuring 19,014 52 8910 Maintenance of measuring 53 8920 Maintenance of services 1,429 54 8930 Maintenance of meters 16,707 55 8940 Maintenance of other equipment (0) 56 9010 Customer accounts-Operation 57 9020 Customer accounts-Meter reading 243,955 58 9030 Customer accounts-Customer 70,515 59 9040 Customer accounts-Uncollect:Lble 327,131 60 9050 Customer accounts-Miscellaneous 13,241 61 9070 Customer service-Supervision 6,112 62 9080 Customer service-Operating 19,156 63 9090 Informational and instructional advertising 199 64 9100 Customer service-Miscellaneous 244 65 9120 Sales-Demonstrating and selling expenses 66 9130 Sales-Advertising expenses 540 67 9200 A&G-Administrative & general 110,597 68 9210 A&G-Office supplies & expense 1,748 69 9220 A&G-Administrative expense 9,433,690 WP4-1 2of3 Atmos Energy Corporation - Colorado Service Areas Colorado Revenue & Operating Expenses Test Year Ended March31, 2017 Line Account No. Number Account Description Colorado Service Area Total (a) (b) (c) (d) 70 9230 A&G-Outside services employed 190 71 9240 A&G-Property insurance 77,284 72 9250 A&G-Injuries & damages 3,178 73 9260 A&G-Employee pensions and benefits 954,327 74 9301 A&G general advertising 75 9302 Miscellaneous general expenses 7,495 76 O&M Without Gas Cost (Sum ofLns 33 - 75) $ 15,661,812 77 78 4030 Depreciation Expense $ 9,286,980 79 System Safety and Integrity Rider (SSIR) Depreciation Expense (1) (100,982) 80 Depr/Amort (Ln 78 + Ln 79) $ 9,185,997 81 82 4081 4081 Taxes Other $ 2,506,745 83 Taxes Other (Ln 82) $ 2,506,745 84 85 Operating Income (Loss) before Tax & Interest (Ln 12 + 31 + 76 + 80 + 83) $ 13,958,128 86 87 4074 Regulatory Credits $ (23) 88 4091 Income taxes, utility operating income 89 4101 Provision for deferred income taxes 90 4190 Interest and dividend (21,771) 91 4210 l'vfiscellaneous nonoperating income (5,432) 92 4261 Donations 234,668 93 4263 Penalties 158 94 4264 Civic, Political and Related 48,392 95 4265 Other deductions 109,914 96 4270 Interest onL-Term Debt 2,881,646 97 4280 Amortization of debt discount 33,053 98 4281 Amortization ofloss 52,053 99 4300 Interest on debt to associated 26,606 100 4310 Other interest expense 191,757 101 4320 Allowance for borrowed funds under construction (30,693) 102 Other (Sum ofLns 87 - 101) $ 3,520,328 103 Total (Ln85-Ln102) $ 10,437,800 104 105 106 Note: 1. This amount is associated with SSIR depreciation The amount will be excluded from the filing. See WP 6-5 for firrther WP4-1 107 details. 3 of3 Atmos Energy Corporation - Colorado Service Areas Labor Adjustment Test Year Ended March 31, 2017 Div002 Div012 Div 030 Div 031 Line Colorado ssu ssu CO/KS Div Colorado Total No. Description Service Area General Office Customer Support General Office Adm in. Colorado (a) (b) (c) (d) (e) (f) (g) 1 Labor Expense Per Book $ 2,808,234 $ 48,074,034 $ 29,304,244 $ 1,338,407 $ 546,778 2 3 Allocation to Colorado 100% 2.89% 3.79% 42.51% 100% 4 5 Colorado Jurisdictional Labor Expense (Ln I * Ln 3) $ 2,808,234 $ 1,389,584 $ 1,110,535 $ 568,923 $ 546,778 $ 6,424,053 6 7 Budgeted Merit Increase (1) 4.50% 4.50% 4.50% 4.50% 4.50% 8 9 Total Labor Adjustment (Ln 5 * Ln 7) $ 126,371 $ 62,531 $ 49,974 $ 25,602 $ 24,605 $ 289,082 10 11 Note: 1. A 3% merit increase occurred on Oct 1, 2016 and will occur on Oct 1, 2017. The merit calculation for the test year is as follows: 6 months (April 2016- Oct 12 2016 at 1.5%) 12 months (Nov 2016 - Oct 2017 at 3%). This adjustment normalizes the merit increases. WP4-2 1of1 - .. _ _._._ ... Atmos Energy Corporation - Colorado Service Areas Labor Sub-Accounts 01000-01016, Excluding 01010 (1) Test Year Ended March 31, 2017 Line No. Account Sub-Account Colorado Direct Division 002 Division 012 Division 030 Division 031 (a) (b) (c) (d) (e) (f) (g) 1 8560 01002 $ - $ (25,220) $ - $ - $ 2 8560 01006 1,204 3 8560 01008 41 4 8560 01011 25,220 5 8560 01014 (1,204) 6 8570 01000 2,275 7 8570 01008 37 8 8700 01000 76,159 1,165,584 313,945 9 8700 01001 3,255,861 1,708,697 1,048,102 10 8700 01002 (2,621,285) (54,110) (1,865,934) (1,599,510) 11 8700 01006 85,074 0 12 8700 01008 (2,392) (41,564) (3,530) 13 8700 01011 297,906 54,110 1,582,720 1,505,810 14 8700 01012 (932,483) (1,425,482) (954,402) 15 8700 01013 105,128 1,270 483 16 8700 01014 (87,260) (0) 17 8710 01000 111,889 18 8710 01008 (2,511) 19 8740 01000 1,529,956 33,884 170,380 20 8740 01006 1,547 21 8740 01008 (41,617) (1,191) (6,343) 22 8740 01013 1,547 23 8740 01014 (1,547) 24 8750 01000 13,353 25 8750 01008 (1,171) 26 8780 01000 323,892 27 8780 01008 (7,423) 28 8790 01000 159,163 29 8790 01008 (6,238) 30 8800 01000 195,023 WP4-2-l 1 of2 Atmos Energy Corporation - Colorado Service Areas Labor Sub-Accounts 01000-01016, Excluding 01010 (1) Test Year Ended March 31, 2017 Line No. Account Sub-Account Colorado Direct Division 002 Division 012 Division 030 Division 031 (a) (b) (c) (d) (e) (f) (g) 31 8800 01008 (8,129) 32 8850 01000 12,278 33 8850 01008 (252) 34 8870 01000 68,206 4,714 35 8870 01008 (745) (244) 36 8890 01000 7,266 37 8890 01008 50 38 8920 01000 1,271 39 8930 01000 14,253 40 8930 01008 334 41 9010 01000 4,534,644 19,515 6,496 42 9010 01008 (184,681) 1,086 (192) 43 9020 01000 102,370 13,402 990 44 9020 01008 (1,284) 677 45 9030 01000 64,602 1,422,709 21,067,072 151,233 46 9030 01008 (3,896) (100,406) (842,934) 8,589 47 9080 01000 47,907 48 9080 01008 (2,026) 49 9200 01000 114,084 48,033,523 4,844,107 643 50 9200 01001 1,796,385 425,554 51 9200 01002 (1,450,468) (678,406) 52 9200 01008 (3,486) (1,281,833) (128,044) (19) 53 9200 01011 1,069,310 381,578 54 9200 01012 (1,415,226) (128,726) 55 9210 01006 607 56 9210 01014 (607) 57 Grand Total (Sum ofLns I - 56) $ 2,808,234 $ 48,074,034 $ 29,304,244 $ 1,338,407 $ 546,778 58 59 Note: 60 1. Sub Account 01010 is Employee Illness Bank. WP4-2-1 2 of2 Atmos Energy Corporation - Colorado Service Areas Benefits Adjustment - Pension & Insurance Test Year Ended March 31, 2017 Division 030 Division 031 Div 002 Div 012 Line Colorado CO/KS BU Colorado Atmos SSU AtmosSSU Total No. Description Direct General Office Admin. General Office Customer Support Colorado (a) (b) (c) (d) (e) (f) (g) 1 Labor Expense (WP 4-2, Ln 5) $ 2,808,234 $ 568,923 $ 546,778 $ 1,389,584 $ 1,110,535 $ 6,424,053 2 Budgeted Merit Increase (WP 4-2, Ln 9) 126,371 25,602 24,605 62,531 49,974 289,082 3 Profonna Labor Expense (Ln 1 + Ln 2) $ 2,934,604 $ 594,524 $ 571,383 $ 1,452,115 $ 1,160,509 $ 6,713,136 4 5 CO/KS Fiscal 2017 Benefits Percent [1] 34.32% 34.32% 34.32% 35.27% 35.27% 6 7 Proforma Pension & Insurance Expense (Ln 3 * Ln 5) $ 1,007,020 $ 204,013 $ 196,072 $ 512,119 $ 409,278 $ 2,328,502 8 9 10 Account 925/926 Pension & Insurance (WP 4-3-1, Ln 29) $ 907,019 $ 334,146 $ 210,009 $ 14,612,322 $ 10,062,710 $ 26,126,206 11 Allocation to Colorado 100.00% 42.51% 100.00% 2.89% 3.79% 12 Pension & Insurance Expense (Ln 10 * Ln 11) $ 907,019 $ 142,037 $ 210,009 $ 422,370 $ 381,344 $ 2,062,780 13 14 15 Total Benefits Adjustment (Ln 7 - Ln 12) $ 100,001 $ 61,976 $ (13,937) $ 89,748 $ 27,934 $ 265,723 16 17 18 [1] Calculation of Benefits Rate: 19 12 Months 20 CO/KS Div Fiscal 2017 Pension & Insurance Expense Budget (Including Workers Compensation) $ 3,265,679 21 CO/KS Div Fiscal 2017 Labor Expense Budget 9,516,664 22 Benefits Percent Fiscal 2017 (Ln 20 I Ln 21) 34.32% 23 24 SSU Div Fiscal 2017 Pension & Insurance Expense Budget $ 28,270,800 25 SSU Div Fiscal 2017 Labor Expense Budget 80,162,000 26 Benefits Percent Fiscal 2017 (Ln 24 / Ln 25) 35.27% WP4-3 1 ofl Atmos Energy Corporation - Colorado Service Areas Benefits Detail Test Year Ended March 31, 2017 Llne Sub Colorado CO/KS BU Div COAdmln SSU General SSU Customer No. Account Account Descri~tion Direct 030 Div031 Office Div 002 Support Div 012 Per Book Total (a) (b) (c) (d) (e) (f) {g) (h) (i) 9250 1208 Workers Comp Variance $ - $ (46,847) $ - $ 71,812 $ - $ 24,966 2 9250 1221 Worker's Comp Insurance 180,333 253,368 433,701 3 9250 1293 Workers Comp Benefits Load Projects 1,792 26 42 86 1,946 4 9260 1202 Benefits Pension Load 201,609 96,804 40,620 2,862,189 1,972,486 S,173,709 5 9260 1203 Benefits FAS 106 Load 27,821 17,894 4,948 1,712,116 1,170,870 2,933,648 6 9260 1206 Benefits Pension Variance (34,095) 102,960 68,865 7 9260 1207 Benefits FAS106 Variance (132,559) (134,611) (267,170) 8 9260 1226 Pension Regulated Asset O&M 35,112 35,112 9 9260 1251 Medical Benefits Load 485,689 240,674 97,897 7,639,048 5,227,557 13,690,866 10 9260 1252 Medical Benefits Variance (41,247) (329,827) (371,074) 11 9260 1253 Medical Benefits Load Projects 19,040 222 355 3,933 23,551 12 9260 1257 Empr ESOP Benefits Load 102,438 50,278 20,648 1,519,253 1,039,651 2,732,267 13 9260 1258 Empr ESOP Benefits Variance (14,557) 139,140 124,583 14 9260 1259 Empr ESOP Benefits Load Projects 4,137 51 82 782 5,052 15 9260 1260 Emp HSA Benefits Load 2,705 1,337 545 42,787 29,304 76,678 16 9260 1261 Emp HSA Benefits Variance 12,848 40,815 53,663 17 9260 1262 Emp HSA Benefits Load Projects 87 1 2 13 103 18 9260 1263 RSP FACC Benefits Load 15,289 8,209 3,011 386,067 262,438 675,015 19 9260 1264 RSP FACC Benefits Variance 26,469 121,359 147,829 20 9260 1265 RSP FACC Benefits Load Projects 3,557 6 10 387 3,959 21 9260 1266 Basic Life Benefits Load 15,599 7,080 3,023 239,919 167,976 433,596 22 9260 1267 Basic Life Benefits Variance (27,145) (186,574) (213,718) 23 9260 1268 Basic Life Benefits Load Projects 1,753 7 11 211 1,981 24 9260 1269 LTD Benefits Load 17,517 8,292 3,502 277,145 192,428 498,884 25 9260 1270 LTD Benefits Variance (20,063) (152,385) (172,448) 26 9260 1271 LTD Benefits Load Projects 557 10 15 151 733 27 9260 1291 Pension Benefits Load 6,802 107 170 1,531 8,610 28 9260 1292 FAS106 Benefits Load P 627 10 16 646 1,298 29 Subtotal Pension & Insurance (Sum ofLns 1 - 28) $ 907,019 $ 334,146 $ 210,009 $ 14,612,322 $ 10,062,710 $ 26,126,206 30 WP4-3-1 1 of2 Atmos Energy Corporation - Colorado Service Areas Benefits Detail Test Year Ended March 31, 2017 Line Sub Colorado CO/KS BU Div COAdmin SSU General SSU Customer No. Account Account Description Direct 030 Div031 Office Div 002 Support Div 012 Per Book Total (a) (b) (c) (d) (e) (f) (g) (h) (i) 31 9250 4070 Insurance $ - $ 31,185 $ - $ 108,295 $ - $ 139,480 32 9250 5418 Settlement 134,119 279 134,398 33 9250 7115 Insurance Reserve (1,000,000) (1,000,000) 34 9250 7119 Insurance D&O 1,728,266 1,728,266 35 9250 7121 Insurance - Public Liability 17,627,809 17,627,809 36 9250 2001 Inventory Materials 306 306 37 9250 2004 Warehouse Loading Charge 43 43 38 9250 2005 Non-Inventory Supplies 1,037 1,037 39 9260 5010 Office Supplies 86 86 40 9260 5111 Postage/Delivery Service 95 95 41 9260 5411 Meals & Entertainment 7,311 30 7,341 42 9260 5412 Spousal & Dependent Travel 280 18,911 19,191 43 9260 6111 Contract Labor 416 416 44 9260 7421 Service Awards 42,854 106,915 85,076 234,846 45 9260 7443 Uniforms 10,879 478 99 11,455 46 9260 7444 Uniforms Capitalized (5,159) (280) (5,438) 47 9260 7447 Education Assist Program 223,408 223,408 48 9260 7450 Capitalized Restricted Stock (170,521) (28,108) (198,629) 49 9260 7452 Variable Pay & Mgt Incentive Plans 2,392,399 1,686 15,999,327 4,122 18,397,534 50 9260 7453 Exec Compensation - Other 399 399 51 9260 7454 VPP & MIP - Capital Credit (1,308,296) (1,308,296) 52 9260 7458 Restricted Stock 191,SJO 34,078 6,147,230 228,919 6,602,038 53 9260 7460 RSU Long Term Incentive Plan 117,238 10,491 4,086,022 138,892 4,352,643 54 9260 7463 Mgmt Incentive Plan 5,686 424,917 19,937 450,540 55 9260 7486 Rabbi Trust {1,680,624) (1,680,624) 56 9260 7487 COLI CSV & Premiums (89,933) (468,830) (558,763) 57 9260 7488 COLI Loan Interest 50,929 933,729 984,657 58 9260 7489 NQ Retirement Cost 164,394 9,320,660 9,485,054 59 9260 7490 SERP Capitalized (87,840) (87,840) 60 9260 7495 Employee Broadcast and Publication 552 552 61 9260 7499 Misc Employee Welfare Exp. 34,681 1,512 58 37,797 74,048 62 9260 7590 Misc General Expense 140 140 63 Subtotal Other Employee Benefits (Sum ofLns 31 - 62) $ 50,485 $ 1,341,645 $ 152,324 $ 53,614,512 $ 477,226 $ 55,636,192 64 65 66 Total Benefits Accounts 925 and 926 Per Book (Ln 29 + Ln 63) $ 957,505 $ 1,675,792 $ 362,333 $ 68,226,834 $ 10,539,935 $ 81,762,398 WP 4-3-1 2 of2 Atmos Energy Corporation - Colorado Service Areas Income & Expense Accounts - Per Book (Amounts before Allocation Percentages) Test Year Ended March 31, 2017 Line No. Account Description Division 030 Division 031 Total (a) (b) (c) (d) (e) 1 8059 PGA Offset to Unrecovered Gas $ - $ - $ 2 Gas Cost (Ln 1) $ $ $ 3 4 7590 Other expenses $ - $ 5 8350 Maintenance of regulating equipment 6 8560 Mains expenses 7 8700 Distribution-Operation supervision 2,119,698 558,929 8 8740 Mains and Services Expenses 110,698 346,116 9 8770 Measuring and regulating station expenses 10 8780 Meter and house regulator expense 11 8800 Distribution-Other expenses 189 2,403 12 8850 Distribution-Maintenance 670 17,180 13 8870 Distribution-Maint of mains 1,569 5,267 14 8900 Maintenance of measuring and reg equip 15 9010 Customer accounts-Operation 21,206 8,957 16 9020 Customer accounts-Meter reading 724 990 17 9030 Customer accounts-Customer 2,017,440 6,029 18 9070 Customer service-Supervision 19 9080 Customer service-Operating 225 61,537 20 9090 Customer service-Operating 42,201 21 9100 Customer service-Miscellaneous customer service 9,551 22 9110 Sales-Supervision 23 9120 Sales-Demonstrating and selling 2,878 24 9130 Sales-Advertising expenses 7,156 25 9200 A&G-Administrative & general (80,138) 623 26 9210 A&G-Office supplies & expense (23,849) (1,060) 27 9220 A&G-Administrative expense (5,908,088) (2,009,380) WP4-4 28 9230 A&G-Outside services employed 55,404 140,855 1 of2 Atmos Energy Corporation - Colorado Service Areas Income & Expense Accounts - Per Book (Amounts before Allocation Percentages) Test Year Ended March 31, 2017 Line No. Account Description Division 03 0 Division 031 Total (a) (b) ( c) (d) (e) 29 9240 A&G-Property insurance (17,017) (49) 30 9250 A&G-Injuries & damages 164,698 134,161 31 9260 A&G-Employee pensions and benefits 1,511,093 228,172 32 9280 Regulatory commission expenses 428,738 33 9302 Miscellaneous general expenses 38,442 18,780 34 9310 A&G-Rents 35 O&M Excluding Gas Cost (Sum ofLns 4 - 34) $ 23,000 $ (0) $ 23,000 36 37 4030 Depreciation Expense $ (0) $ (0) $ (0) 38 39 4081 4081 Taxes Other (0) $ (0) 40 41 Operating Income (Loss) before Tax & Interest (-Ln 2 - Ln 35 -Ln 37 - Ln 39) $ (23,000) $ 0 $ (23,000) 42 43 4091 Income tax $ (1,603,767) $ 700,626 44 4101 Provision 2,187,547 2,854,557 45 4074 Regulatory Credits 0 46 4261 Donations 0 0 47 4264 Civic, Political and Related 48 4265 Other deductions 0 0 49 4310 Other interest expense 50 Other (Sum of Ln 43 - 49) $ 583,780 $ 3,555,183 $ 4,138,963 51 52 Total (Ln 41 + Ln 50) $ 4,161,963 WP4-4 2 of2 .. -:-·.·.,-,·:.:.· . .- - ..' .. ··· Atmos Energy Corporation - Colorado Service Areas Adjustment for Unallocated Administrative Expenses Test Year Ended March 31, 2017 As Adjusted Line Unallocated Allocated No. Description Total Allocation Percentage Total (a) (b) (c) (d) 1 Per Book O&M Excluding Gas Cost: 2 CO/KS General Office Division 030 $ 23,000 42.51% $ 9,777 3 4 Colorado Admin Division 031 (0) 100.00% (0) 5 6 Total Adjustment for Unallocated Administrative Expenses (Ln 2 + Ln 4) $ 9,777 WP 4-4-1 1of1 .. : .. :... :... :.· Atmos Energy Corporation - Colorado Service Areas Promotional and Advertising Expense Adjustment Test Year Ended March 31, 2017 Div 031 - Div030- Line Sub Colorado Colorado CO/KS Div002- Div 012- No. Account Account Description Direct Admin General ssu ssu Total (a) (b) (c) (d) (e) (±) (g) (h) (i) 1 Promotional Advertising Exgense Adjusted: 2 8700 04002 Required By Law, Safety $ $ $ 28,635 $ $ $ 28,635 3 8700 04018 Safety 4 8700 04040 Community Rel&Trade Shows 395 2,633 1,008 4,036 5 8740 04018 Safety 454 454 6 8740 04040 Community Rel&Trade Shows 107 107 7 9010 04040 Community Rel&Trade Shows 286 286 8 9070 04040 Community Rel&Trade Shows 4,210 4,210 9 9070 04046 Cust Relations & Assist. 280 280 10 9080 04040 Community Rel&Trade Shows 4,534 7,012 11,546 11 9080 04046 Cust Relations & Assist. 3,937 326 4,263 Customer service-Operating informational and instructional 12 9090 04023 242 advertising expense 242 13 9100 04040 Community Rel&Trade Shows 9,551 9,551 14 9120 04046 Cust Relations & Assist. 2,378 2,378 15 9130 04021 Promo Other, Misc 208 208 16 9210 04021 Promo Other,Misc 22,504 84 22,588 17 9210 04040 Community Rel&Trade Shows 18,611 18,611 18 9210 04046 Cust Relations & Assist. 18,155 18,155 19 Total Promotional and Advertising Expense (Sum ofLns 2 - 18) $ 13,916 $ 19,764 $ 32,229 $ 59,270 $ 370 $ 125,550 20 21 Allocation Percentages 100% 100% 42.51% 2.89% 3.79% 22 23 Total Promotional and Advertising Expense Adjustment (Ln 19 * Ln 21) $ 13,916 $ 19,764 $ 13,700 $ 1,713 $ 14 $ 49,107 WP4-5 1of1 Atmos Energy Corporation - Colorado Service Areas Interest on Customer Deposits Adjustment Test Year Ended March 31, 2017 Line Colorado No. Description Amount (a) (b) 1 13 Month Average Customer Deposits (See WP 8-7) $ 3,024,754 2 3 2017 Interest Rate on Customer Deposits ( 1) 0.34% 4 5 Total Interest on Customer Deposits Adjustment (Ln 1xLn3) $ 10,284 6 7 8 Note: 9 1. Interest rate per https://www.colorado.gov/pacific/dora/cdir. WP4-6 1of1 Atmos Energy Corporation - Colorado Service Areas Adjustment to Normalize Uncollectible Expense Test Year Ended March 31, 2017 Line No. Description Colorado Amount (a) (b) 1 Test Year Per Book Uncollectible Expense, Account 904 (WP 4-1, Ln 59, Col (c)) $ 327,131 2 3 Normalized Sales Revenue - Residential (Sch 2, Ln 1, Col (m)) $ 64,645,737 4 Normalized Sales Revenue - Commercial /Public Authority (Sch 2, Ln 2, Col (m)) 32,711,324 5 Normalized Sales Revenue - Irrigation (Sch 2, Ln 3, Col (m)) 32,464 6 Normalized Sales Revenue (Sum ofLn 3 - 5) $ 97,389,525 7 8 Normal Experience Rate for Uncollectible Expense 0.46% 9 10 Normalized Level ofUncollectible Expense Account 904 (Ln 6 * Ln 8) $ 451,970 11 12 Total Adjustment to Normalize Uncollectible Expense (Ln 10 - Ln 1) $ 124,839 WP4-7 1of1 Atmos Energy Corporation - Colorado Service Areas Adjustment for Rate Case Expenses Test Year Ended March 31, 2017 Line No. Account Description Amount (a) (b) (c) 1 9280 A&G-Regulatory commission expenses $ (426,344) 2 9230 A&G-Outside services employed 3 4 Total Adjustment to Remove Rate Case Expenses (Ln 1 +Ln 2) $ (426,344) 5 6 Notes: 1. The amounts removed are rate case expenses from dockets 14AL-0300G and 15AL-0299G recorded 7 in the test year. 8 2. The rate case expenses for the current docket are estimated on WP 4-8-1 and not included in base rates. WP4-8 1of1 Atmos Energy Corporation - Colorado Service Areas Estimate of Rate Case Expenses for Surcharge Test Year Ended March 31, 2017 Line No. Provider/Firm Description Estimated Cost (a) (b) (c) 1 Holland & Hart (Thorvald Nelson) Attorney Services $ 349,039 2 ScottMadden Inc. (Robert Hevert) Expert Testimony - Return on Equity 83,244 3 Various Postage, Printing, Notice and Other Company Expenses 20,199 4 Various Employee Travel 19,995 5 Total Estimated Rate Case Expenses (Sum ofLns 1 - 4) $ 472,477 6 ======7 Amortization Period (Years) 1 8 9 Estimated Rate Case Expense Per Year (Ln 5 I Ln 7) $ 472,477 10 11 Note: 12 1. Please see the proposed Tariff Sheet No. 19. WP 4-8-1 1of1 Atmos Energy Corporation - Colorado Service Areas Adjustments for Expense Reports and 5400 Series Accounts Test Year Ended March 31, 2017 Allocation Total Line No. Description Gross Amounts Percentage Colorado (a) (b) (c) (d) 1 Shared Services 2 Division 002 Expense Report Adjustments - 4/16 - 3/17 $ 325,931 2.89% $ 9,421 3 Division 002 5400 Series Adjustments - 4/16 - 3/17 53,161 2.89% 1,537 4 Division 002 Expense Report and 5400 Series Adjustments (Ln 2 + Ln 3) $ 10,958 5 6 Division 012 Expense Report Adjustments - 4/16 - 3/17 $ 151,572 3.79% $ 5,744 7 Division 012 5400 Series Adjustments - 4/16 - 3/17 24,622 3.79% 933 8 Division 012 Expense Report and 5400 Series Adjustments (Ln 6 + Ln 7) $ 6,677 9 10 Colorado Direct 11 Direct Expense Report Adjustments - 4/16 - 3/17 $ 20,880 12 Direct 5400 Series Adjustments - 4/16 - 3/17 4,339 13 Direct Sub Accounts 07510, 07520, and 07590 Adjustments - 4/16 - 3/17 14 Direct Expense Reports, 5400 Series and Other Sub-Accounts Adjustments (Ln 11 + Ln 12 + Ln 13) $ 25,220 15 16 Total Adjustments for Expense Reports, 5400 Series and Other Sub-Accounts (1) (Ln 4 + Ln 8 + Ln 14) $ 42,854 17 18 Note: 19 1. The adjustment includes removal of applicable dues, donations and other items which might be deemed controversial. WP4-9 1 ofl Atmos Energy Corporation - Colorado Service Areas Pension Tracker Adjustment Colorado Direct and Allocated General Office Test Year Ended March 31, 2017 Expense in Excess Actual of (Less than) Month/Year Amount in Base Pension Amount In Base Cumulative Line No. (1) Rates (1) Expense (2) Rates (3) Balance Interest (4) Total (a) (b) (c) (d) (e) (f) (g = d+f) 1 Jan-16 $ 26,404 $ 26,424 $ 20 $ 20 $ 0 $ 20 2 Feb-16 26,404 22,664 (3,740) (3,719) (18) (3,758) 3 Mar-16 26,404 18,158 (8,245) (11,964) (59) (8,304) 4 Apr-16 26,404 23,093 (3,310) (15,275) (75) (3,385) 5 May-16 26,404 24,812 (1,592) (16,866) (83) (1,675) 6 Jun-16 26,404 22,239 (4,165) (21,031) (103) (4,268) 7 Jul-16 26,404 21,292 (5,112) (26,143) (129) (5,241) 8 Aug-16 26,404 19,496 (6,908) (33,051) (162) (7,070) 9 Sep-16 26,404 19,833 (6,570) (39,621) (195) (6,765) 10 Oct-16 26,404 26,001 (402) (40,023) (197) (599) 11 Nov-16 26,404 23,008 (3,395) (43,419) (213) (3,609) 12 Dec-16 26,404 23,631 (2,773) (46,191) (227) (3,000) 13 Jan-17 26,404 24,938 (1,466) (47,657) (234) (1,700) 14 Feb-17 26,404 23,133 (3,271) (50,928) (250) (3,521) 15 Mar-17 26,404 24,371 (2,032) (52,961) (260) (2,293) 16 Apr-17 26,404 26,208 (195) (53,156) (261) (457) 17 May-17 26,404 23,965 (2,439) (55,595) (273) (2,712) 18 Jun-17 26,404 23,965 (2,439) (58,033) (285) (2,724) 19 Jul-17 26,404 23,965 (2,439) (60,472) (297) (2,736) 20 Aug-17 26,404 23,965 (2,439) (62,911) (309) (2,748) 21 Sep-17 26,404 23,965 (2,439) (65,349) (321) (2,760) 22 Oct-17 26,404 23,965 (2,439) (67,788) (333) (2,772) 23 Nov-17 26,404 23,965 (2,439) (70,227) (345) (2,784) WP 4-10 1 of2 -.. - . .. . ·; ~ .~.- _... _ ·. ·. -- Atmos Energy Corporation - Colorado Service Areas Pension Tracker Adjustment Colorado Direct and Allocated General Office Test Year Ended March 31, 2017 Expense in Excess Actual of (Less than) Month /Year Amount in Base Pension Amount In Base Cumulative Line No. (1) Rates (1) Expense (2) Rates (3) Balance Interest ( 4) Total (a) (b) (c) (d) (e) (f) (g= d+f) 24 Dec-17 26,404 23,965 (2,439) (72,665) (357) (2,796) 25 Jan-18 26,404 23,965 (2,439) (75,104) (369) (2,808) 26 Total $ 660,090 $ 584,986 $ (75,104) $ (5,360) $ (80,464) 27 28 Amortization Period (Years) 2 29 30 Total Amortization of Pension Expense in Excess of Amount in Base Rates (Ln 26/Ln 28) $ (40,232) 31 32 Notes: I. New Pension tracker was implemented on January 1, 2016 based upon the Stipulation and Settlement Agreement in 33 Docket No. 15AL-0299G. The amounts represent the monthly pension expense included in the agreement for Denver General Office $38,734 [$38,734/12=$3,228 per month] and Direct Colorado Operations $278,109 [$278,109/12=$23,176 per month] [$3,228+$23,176=$26,404]. 2. The amounts are the pension expense for the respective period; the amounts for June 2017 - January 2018 have been 34 estimated. The estimate amounts are that of May 201 7's actual expense amount. 35 3. The amounts are the difference between the amounts included in Base Rates and the actual pension 4. The interest rate is 0.059 on an annual basis and 0.0049167 per month as per proceeding No. 15AL- 36 0299G. WP 4-10 2 of2 '-:.···"' Atmos Energy Corporation - Colorado Service Areas Pension Tracker Adjustment Shared Services Test Year Ended March 31, 2017 SSU - GO - Division 002 SSU - CS - Division 012 Actual Expense in Amount in Pension Allocated Actual Allocated Total SSU Excess of (Less Line- Month/ Base Rates Expense Allocation Actual Pension Allocatio Actual Actual than) Amount 'In Cumulative Interest No. Year (1) (1) (2) Factor Expense Expense (2) n Factor Expense Expense Base Rates (3) Balance (4) Total (a) (b) (c) (d) (e=c*d) (f) (g) (h=f*g) (i=e+h) G=i-b) (k) (1) (m=j+l) Jan-16 $ 13,477 $177,492 2.89% $ 5,130 $ 169,113 3.79% $ 6,409 $ 11,539 $ (1,938) $ (1,938) $ (10) $ (1,948) 2 Feb-16 13,477 155,978 2.89% 4,508 165,765 3.79% 6,283 10,790 (2,687) (4,625) (23) (2,710) 3 Mar-16 13,477 119,155 2.89% 3,444 191,871 3.79% 7,272 10,715 (2,762) (7,387) (36) (2,798) 4 Apr-16 13,477 181,469 2.89% 5,244 168,931 3.79% 6,402 11,647 (1,830) (9,217) (45) (1,876) 5 May-16 13,477 155,921 2.89% 4,506 169,384 3.79% 6,420 10,926 (2,551) (11,769) (58) (2,609) 6 Jun-16 13,477 163,291 2.89% 4,719 167,507 3.79% 6,349 11,068 (2,410) (14,178) (70) (2,479) 7 Jul-16 13,477 170,224 2.89% 4,919 160,511 3.79% 6,083 11,003 (2,474) (16,653) (82) (2,556) 8 Aug-16 13,477 145,617 2.89% 4,208 176,691 3.79% 6,697 10,905 (2,572) (19,225) (95) (2,667) 9 Sep-16 13,477 130,120 2.89% 3,760 191,235 3.79% 7,248 11,008 (2,469) (21,694) (107) (2,576) 10 Oct-16 13,477 219,164 2.89% 6,334 120,455 3.79% 4,565 10,899 (2,578) (24,272) (119) (2,698) 11 Nov-16 13,477 169,078 2.89% 4,886 137,786 3.79% 5,222 10,108 (3,369) (27,641) (136) (3,505) 12 Dec-16 13,477 180,942 2.89% 5,229 102,251 3.79% 3,875 9,105 (4,373) (32,014) (157) (4,530) 13 Jan-17 13,477 182,273 2.89% 5,268 116,156 3.79% 4,402 9,670 (3,807) (35,821) (176) (3,983) 14 Feb-17 13,477 275,944 2.89% 7,975 82,034 3.79% 3,109 11,084 (2,393) (38,214) (188) (2,581) 15 Mar-17 13,477 177,560 2.89% 5,131 115,687 3.79% 4,385 9,516 (3,961) (42,175) (207) (4,169) 16 Apr-17 13,477 212,009 2.89% 6,127 85,431 3.79% 3,238 9,365 (4,112) (46,288) (228) (4,340) 17 May-17 13,477 160,591 2.89% 4,641 112,689 3.79% 4,271 8,912 (4,565) (50,853) (250) (4,815) 18 Jun-17 13,477 160,591 2.89% 4,641 112,689 3.79% 4,271 8,912 (4,565) (55,418) (272) (4,838) 19 Jul-17 13,477 160,591 2.89% 4,641 112,689 3.79% 4,271 8,912 (4,565) (59,984) (295) (4,860) 20 Aug-17 13,477 160,591 2.89% 4,641 112,689 3.79% 4,271 8,912 (4,565) (64,549) (317) (4,883) 21 Sep-17 13,477 160,591 2.89% 4,641 112,689 3.79% 4,271 8,912 (4,565) (69,114) (340) (4,905) 22 Oct-17 13,477 160,591 2.89% 4,641 112,689 3.79% 4,271 8,912 (4,565) (73,679) (362) (4,928) 23 Nov-17 13,477 160,591 2.89% 4,641 112,689 3.79% 4,271 8,912 (4,565) (78,245) (385) (4,950) WP 4-10-1 1 of2 Atmos Energy Corporation - Colorado Service Areas Pension Tracker Adjustment Shared Services Test Year Ended March 31, 2017 SSU - GO - Division 002 SSU - CS - Division 012 Actual Expense in Amount in Pension Allocated Actual Allocated Total SSU Excess of (Less Line Month/ Base Rates Expense Allocation Actual Pension Allocatio Actual Actual than) Amount 'In Cumulative Interest No. Year (1) (1) (2) Factor Expense Expense (2) n Factor Expense Expense Base Rates (3) Balance (4) Total (a) (b) (c) (d) (e=c*d) (f) (g) (h=:f*g) (i=e+h) G=i-b) (k) (1) (m=j+l) 24 Dec-17 13,477 160,591 2.89% 4,641 112,689 3.79% 4,271 8,912 (4,565) (82,810) (407) (4,972) 25 Jan-18 13,477 160,591 2.89%_$__ 4_.,_64_1_ 112,689 3. 79% __4,~2_71_.,.---_8~,9_12_...,.-- _ __..(4_.,_56_5.._) (87,3 75)_..... c 4_3 ...... o)'-- _ _,_c4,,_,9_95_._) 26 Total $ 336,931 123,159 $126,397 $249,556 $ (87,375) $(4,794) $ (92,170) 27 28 Amortization Period (Years) 2 29 30 Total Amortization of Pension Expense in Excess of Amount in Base Rates (Ln 26/Ln 28) $ (46,085) 31 32 Notes: I. New Pension tracker was implemented on January 1, 2016 based upon the Stipulation and Settlement Agreement in Docket No. 15AL-0299G. The amounts represent 33 the monthly pension expense included in the agreement for Shared Services in the amount of$161,727 [$161,727/12=$13,477]. 2. The amounts are the pension expense for the respective period; the amounts for June 2017 - January 2018 have been estimated. The estimate amounts are that ofMay 34 2017's actual expense amount. 35 3. The amounts are the difference between the amounts included in Base Rates and the actual pension expense. 36 4. The interest rate is 0.059 on an annual basis and 0.0049167 per month as per proceeding No. 15AL-0299G. WP 4-10-1 2 of2 . ·.:.·_- ·.·. . ······ ·.· .. ·-·-·- . ..··- Atmos Energy Corporation - Colorado Service Areas Taxes Other Than Income Taxes Test Year Ended March 31, 2017 As Adjusted Div 031 Line Colorado Colorado No. DescriEtion Rate Service Area Admin. Colorado Total (a) (b) (c) (d) (e) 1 Taxes Other Than Income Taxes - Account 4081 2 3 FICA (01210) $ 196,370 $ 39,329 $ 235,700 4 Federal Unemployment (01211) 1,692 346 2,038 5 State Unemployment (01212) 2,431 515 2,947 6 FICA Accrual (01213) (2,279) (536) (2,814) 7 FUTA Accrual (01214) (16) (4) (19) 8 SUTA Accrual (01215) (75) (18) (93) 9 Denver City Head Tax (01220) 93 19 112 10 Payroll Tax Projects (01256) 8,235 162 8,398 11 Taxes Other Than Inc Tax (09344-5) 2,174,971 (2,085,660) 89,311 12 Ad Valorem accrual (30101-2) 9,468 1,681,745 1,691,213 13 Occupational License (30103) 40 470 510 14 City Franchise Fee (30107) 15 US DOT Pipe Safety funding (30108) 16 Billing for CSC Depr & Taxes Other ( 41129) 115,813 0 115,813 17 Billing for SS Depr & Taxes Other (41130) 130,056 130,056 18 Public Srvc Comm Assessment (30112) 233,574 233,574 19 Sales Tax True-up (07595) 20 Total Colorado Taxes Other Per Book (Sum ofLns 3 - 19) $ 2,506,745 $ (0) $ 2,506,745 21 Schedule 5 1 of2 Atmos Energy Corporation - Colorado Service Areas Taxes Other Than Income Taxes Test Year Ended March 31, 2017 As Adjusted Div 031 Line Colorado Colorado No. Description Rate Service Area Admin. Colorado Total (a) (b) (c) (d) (e) 22 Calculations: 23 Ad Valorem Tax Adjustment - [a]: 24 Colorado Ad Valorem Adjusted (1) $ 1,638,564 25 Per Book, Allocated to the Colorado Divisions (1,691,213) 26 Adjustment (Ln 24 + Ln 25) $ (52,649) 27 28 PSC Assessment Adjustment - [b]: 29 Total Normalized Revenues (Schedule 2, Ln 15, Col (m)) $ 100,254,854 30 Normalized PSC Assessment (Ln 29 * 0.23%) 0.23% $ 232,270 31 Per Book, Allocated to the Colorado Divisions (233,574) 32 Adjustment (Ln 30 + Ln 31) $ (1,303) 33 34 Pavroll Tax Adjustment - [c]: 35 Colorado Adjusted Labor Expense (WP 4-2, Ln 5 + Ln 9, Col (b) and (f)) $ 2,934,604 $ 571,383 $ 3,505,987 36 Normalized Payroll Tax (Ln 35 * 7.34%) 7.34% 215,409 41,941 257,351 37 Per Book Payroll Tax {206,453) (39,815) (246,2692 38 Adjustment (Ln 36 + Ln 37) $ 8,956 $ 2,126 $ 11,082 39 40 Summary of Adjustments fa. b, cl: 41 Colorado Ad ValoremAdjustment [al (Ln 26) $ (52,649) 42 PSC Assessment Adjustment [b] (Ln 32) (1,303) 43 Payroll Tax Adjustment [c] (Ln 38) 11,082 44 Total Adjustments - Taxes Other than Income Taxes (Ln 41 + Ln 42 + Ln 43) $ ~42,871) 45 46 Total Taxes Other Than Income Tax, Adjusted (Ln 20 + Ln 44) $ 2,463,874 47 48 Note: 49 I. March 2017 Ad Valorem tax annualized is net of the related SSIR Ad Valorem taxes. Schedule 5 2 of2 Atmos Energy Corporation - Colorado Sen'ice Areas Taxes Other Than Income Taxes, Account 4081 Per Books Test Year Ended March 31, 2017 Line Sub Colorado No. Account Description Service Area Division 002 Division 012 Division 03 0 Division 031 Total (a) (b) (c) (d) (e) (f) (g) (h) = (c + g) 1 1201 Benefits $ - $ - $ - $ - $ - $ 2 1210 Pica 196,370 3,656,509 2,506,168 152,050 39,329 235,700 3 1211 Futa 1,692 31,177 18,786 1,051 346 2,038 4 1212 Suta 2,431 83,228 50,756 1,492 515 2,947 5 1213 Pica (2,279) (99,787) (84,697) (225) (536) (2,814) 6 1214 Futa (16) (1,164) (946) (5) (4) (19) 7 1215 Suta (75) (2,788) (2,344) (19) (18) (93) 8 1220 Denver 93 49 19 112 9 1256 Payroll Tax Projects 8,235 1,767 102 162 8,398 10 1290 Benefit Load Projects 11 9344 Taxes other 12 9345 Taxes other than inc tax 2,174,971 (208,494) (2,085,660) 89,311 13 30101 Ad Va 690,000 585,000 54,000 1,681,740 1,681,740 14 30102 Taxes property and other 9,468 92,582 5 9,473 15 30103 Occup 40 470 510 16 30105 Corp/State Franchise 17 30107 City Franchise 18 30108 DotT 19 30112 Publi 233,574 233,574 20 40001 Billed to Tex Div (361,229) (299,051) 21 40002 Billed to CO/KS Div (302,703) (247,399) 22 40003 Billed to LA Div (412,498) (346,723) 23 40004 Billed to Mid St Div (458,614) (335,421) 24 40005 Billed to KY Div 25 40007 Billed to NonUtilities (74,282) WP 5-1 I of2 .. , ...... ·.·.·-· .-.·.· .- Atmos Energy Corporation - Colorado Senrice Areas Taxes Other Than Income Taxes, Account 4081 Per Books Test Year Ended March 31, 2017 Line Sub Colorado No. Account Description Service Area Division 002 Division 012 Division 030 Division 031 Total (a) (b) (c) (d) (e) (f) (g) (h)=(c+g) 26 40008 Billed to Mid-Tex Div (1,774,805) (1,596,984) 27 40009 Billed to MS Div (314,294) (247,145) 28 40010 Billed to Atmos Pipeline Div (750,812) 29 40011 Billed to AELIG (275) 30 40012 Billed to WK.GS (275) 31 40013 Billed to AEH (412) 32 40014 Billed to UCGS (344) 33 40015 Billed to TLGP (1,031) 34 41124 Billing for taxes other 302,703 35 41129 Billing for CSC Depr & Taxes 115,813 0 115,813 36 41130 Billing for SS Depr & Taxes Other (302,703) 130,056 130,056 37 Total (Sum of Lines 1 through 36) $ 2,506,745 $ (49) $ 0 $ - $ (0) $ 2,506,745 WP5-1 2 of2 Atmos Energy Corporation - Colorado Service Areas Depreciation and Amortization Expense Test Year Ended March 31, 2017 Line Colorado No. Description Amount (a) (b) 1 Depreciation & Amortization Expense (WP 4-1, Ln 80, Col (d)) (1) $ 9,185,997 2 3 Adjustment to Year End Level of Plant and Current Depreciation Rates $ 540,749 4 Total Current Depreciation and Amortization Expense, As Adjusted (2) (Ln 1+Ln3) $ 9,726,747 5 6 Adjustment for Proposed Depreciation Rates (3) $ 7 8 Total Current Depreciation and Amortization Expense at Proposed Rates (Ln 4 + Ln 6) $ 9,726,747 9 10 Notes: 11 1. The depreciation and amortization expense excludes amounts attributable to SSIR assets. 12 2. See WP 6-1, 6-2, 6-3, 6-4, and 6-5 for additional details. 13 3. The Company is not proposing any change to the existing depreciation rates. Schedule 6 1of1 Atmos Energy Corporation - Colorado Service Areas Colorado Service Area Depreciation Adjustment Test Year Ended March 31, 2017 Fully&Non Current SSIR Proforma Line Balance as of Adjusted Depreciable Depreciable Depreciation Adjustment Proforma Clearing No. Account Description 03/31/2017 Adjustments Amount Plant Plant Rate (1) Expense (2) (a) (b) (c) (d) (e) (f) (g) (h) (i) (j) (k) 374.00 Land and Land Rights s 84,916 $ - $ 84,916 $ 84,916 $ 0.00% $ - $ 2 374.02 Rights-of-Way 161,556 161,556 161,556 1.49% 2,407 3 375.00 Structures and Improvements 161,172 161,172 161,172 2.26% 3,642 4 376.00 Mains - Cathodic Protection 2.142.554 2,142,554 2,142,554 3.58% 31 76,672 376.01 Mains - Steel 33,426,120 33,426,120 33,426,120 2.58% 22,588 839,806 6 376.02 Mains - Plastic 55,291,456 55,291,456 55,291,456 2.58% 36,957 1,389,562 7 376.03 Mains-Anodes 1,227,908 1,227,908 1,227,908 6.67% 81,901 8 376.04 Mains - Leak Clamps and Sleeves 2,530,081 2,530,081 2,530,081 5.55% 140,420 9 378.00 M&R Station Equipment-Gen 4,876,331 4,876,331 4,876,331 3.62% 1,019 175,SOS 10 379.00 City Gate Equipment 4,086,150 4,086,150 4,086,150 3.46% 141,381 11 379.08 M&R Station Equipment 29,307 29,307 29,307 3.46% 1,014 12 380.00 Services 69,256,210 69,256,210 69,256,210 3.32% 40,387 2,258,920 13 381.00 Meters 33,864,415 33,864,415 33,864,415 4.25% 1,439,238 14 382,00 Meter Installations 32,735,706 32,735,706 32,735,706 4.25% 1,391,268 15 383.00 House Regulators 3,609,035 3,609,035 3,609,035 4.25% 153,384 16 384.00 House Regulator Installations 18,123 18;123 18,123 4.25% 17 385.00 Industrial M&R Equipment 843,494 843,494 843,494 2.94% 24,799 18 387.00 Other Equipment 97,369 97,369 97,369 12.51% 19 389.00 Land and Land Rights 11,493 11,493 11,493 0.00% 20 390.00 Structures and Improvements 3,834,721 3,834,721 3,834,721 3.43% 131,531 21 390,03 Improvements 4,743 4,743 4,743 3.43% 163 22 390.09 Improvements to Lease 1,204,773 1,204,773 1,204,773 3.43% 41,324 23 391.00 Office Furniture and Equipment 374,661 374,661 374,661 6.67% 24,990 24 391.03 Office machines 24,545 24,545 24,545 6.67% I,637 25 392.00 Transportation Equipment 126,268 126,268 126,268 4.14% 5,228 26 393.00 Stores Equipment 22,016 22,016 22,016 4.00% 395 $ 486 27 394.00 Tools, Shop and Garage Equipment 2,500,413 2,500,413 2,500,413 8.33% 93,211 115,073 28 395.00 Laboratory Equipment 16,722 16,722 16,722 9.09% 681 839 29 396.00 Power Operated Equipment 34,282 34,282 34,282 11.55% 79 3,880 30 396.03 Ditchers 11.55% 31 396.04 Backhoes 91,018 91,018 91,018 11.55% 10,513 32 396.05 Welders 11.55% 33 397.00 Communication Equipment 549,842 549,842 549,842 9.09% 49,981 34 397.01 Communication Equipment 9.09% 35 397,02 Al\ilR Equipment 15,297 15,297 15,297 9.09% 1,390 36 397.05 Telemetering Equipment 9.09% 37 398.00 Miscellaneous Equipment 477,126 477,126 477,126 10.00% 47,713 38 399.00 Other Tangible Property 213,023 213,023 213,023 6.67% 14.209 39 399.01 Servers Hardware 115,675 115,675 115,675 14.29% 16,530 WP6-l 1 of2 AtmDs Energy CDrpDratiDn - Colorado Service Areas CDIDrado Service Area Depreciation Adjustment Test Year Ended March 31, 2017 Fully&Non Current SSIR Profonna Line Balance as of Adjusted Depreciable Depreciable Depreciation Adjustment Proforma Clearing No. Account Description 03/31/2017 Adjustments Amount Plant Plant Rate (1) Expense (2) (a) (b) (c) (d) (e) (f) (g) (h) (i) (k) 40 399.02 Servers Software 14.29% 41 399.03 Network Hardware 467,842 467,842 467,842 14.29% 66,855 42 399.06 PC Hardware 1,112,518 1,ll2.518 1,112,518 20.00% 222,504 43 399.07 PC Software 66,821 66,821 66,821 20.00% 13,364 44 399.08 Application Software 1,099,548 1,099,548 1,099,548 14.29% 157,125 45 46 Total (Sum of Lines 1 through 44) $ 256,805,251 $ $ 256,805,251 $ 211,902 $ 256,593,349 3.52% $ 100,982 s 9,019,338 s 120,278 47 48 49 Notes: 50 I. This amount is associated with SSIR depreciation. The amount will be excluded from the filing. See WP 6-5 for further details. 51 2. Amounts normally charged to clearing accounts. WP6-1 2 of2 Atmos Energy Corporation - Colorado Service Areas Division 030 Depreciation Adjustment Test Year Ended March 31, 2017 Fully&Non Current Line Balance as of Depreciable Depreciable Depreciation Proforma Proforma No. Account Description 03/31/2017 Plant Plant Rate Expense Clearing (1) (a) (b) (c) (d) (e) (t) (g) (h) 1 390.09 Improv. to Leased Premises $ 275,783 $ - $ 275,783 12.07% $ 33,287 2 391.00 Office Furniture and Equipment 373,242 373,242 7.80% 29,113 3 392.00 Transportation Equipment 27,655 27,655 20.00% 5,531 4 394.00 Tools, Shop and Garage Equipment 73,057 73,057 16.39% 5,359 $ 6,615 5 397.00 Communication Equipment 39,177 39,177 10.67% 4,180 6 398.00 Miscellaneous Equipment 40,575 40,575 16.74% 6,792 7 399.01 Servers Hardware 48,328 48,328 21.70% 10,487 8 399.03 Network Hardware 93,530 93,530 19.19% 17,948 9 399.06 PC Hardware 36,459 36,459 22.00% 8,021 10 399.07 PC Software 34,929 34,929 20.00% 6,986 11 12 Total (Sum of Lns 1 - 10) $ 1,042,735 $ $ 1,042,735 12.25% $ 127,704 $ 6,615 13 14 Total Division 030 Allocated to Colorado (2) (Ln 12, Col (g) * 42.51 %): 42.51% $ 54,284 15 18 Notes: 19 1. Amounts normally charged to clearing accounts. 20 2. CO\KS General Office is allocated to Colorado at 42.51 %. WP6-2 1 of I Atmos Energy Corporation - Colorado Service Areas Division 002 Depreciation Adjustment Test Year Ended March 31, 2017 Fully&Non Current Line Balance as of Depreciable Depreciable Depreciation Proforma No. Account Description 03/3112017 Plant Plant Rate Expense (a) (b) (c) (d) (e) (f) (g) 390.00 Structures & Improvements $ 1,898,968 $ - $ 1,898,968 3.01% $ 57,159 2 390.09 Leasehold Improvements 9,258,889 9,258,889 3.25% 300,914 3 391.00 Office Furniture and Equipment 5,065,000 5,065,000 3.96% 200,574 4 392.00 Transportation Equipment 7,125 7,125 8.34% 594 5 394.00 Tools, Shop and Garage Equipment 159,989 159,989 8.37% 13,391 6 395.00 Laboratory Equipment 10.05% 7 397.00 Communication Equipment 1,788,308 1,788,308 5.85% 104,616 8 398.00 Miscellaneous Equipment 136,510 136,510 5.29% 7,221 9 399.00 Other Tangible Property 162,268 162,268 13.06% 10 399.01 Servers Hardware 34,595,563 34,595,563 9.48% 3,279,659 II 399.02 Servers Software 19,005,572 19,005,572 8.93% 1,697,198 12 399.03 Network Hardware 3,548,953 3,548,953 6.99% 248,072 13 399.06 PC Hardware 1,804,023 1,804,023 10.49% 189,242 14 399.07 PC Software 1,473,265 1,473,265 6.63% 97,677 15 399.08 Application Software 62,040,477 62,040,477 6.52% 4,045,039 16 399.09 Mainframe Software 39,252 39,252 10.32% 17 18 Total SSU General Offic~ (Sum ofLns 1 - 16) $ 140,984,161 $ 201,520 $ 140,782,642 7.27% $ 10,241,357 19 20 Greenville Data Center 21 390.05 -G-Structures & Improvements $ 9,133,015 $ - $ 9,133,015 3.01% $ 274,904 22 391.04 -G-Office Furniture & Equip. 63,741 63,741 3.96% 2,524 23 24 Total Greenville Data Center (Ln 21 + Ln 22) $ 9,196,755 $ $ 9,196,755 3.02% $ 277,428 25 WP6-3 1 of2 Atmos Energy Corporation - Colorado Service Areas Division 002 Depreciation Adjustment Test Year Ended March 31, 2017 Fully &Non Current Line Balance as of Depreciable Depreciable Depreciation Proforma No. Account Description 03131/2017 Plant Plant Rate Expense (a) (b) (c) (d) (e) (f) (g) 26 Distribution and Marketing 27 390.20 Structures & Improvements $ - $ - $ 3.01% $ 28 390.29 Improvements to Leased Premises 3.25% 29 391.20 Office Furniture & Equipment 263,338 263,338 3.96% 10,428 30 394.20 Tools & Work Equipment 39,435 39,435 8.37% 3,301 31 397.20 Communication Equipment - Telephone 8,824 8,824 5.85% 516 32 398.20 Miscellaneous Equipment 7,388 7,388 5.29% 391 33 399.21 Other Tangible Property-Servers Hardware 1,628,900 1,628,900 9.48% 154,420 34 399.22 Other Tangible Property-Servers Software 961,256 961,256 8.93% 85,840 35 399.23 Other Tangible Property-Network-Hardware 60,170 60,170 6.99% 4,206 36 399.26 Other Tangible Property-PC Hardware 314,379 314,379 10.49% 32,978 37 399.28 Other Tangible Property-Application Software 19,243,616 19,243,616 6.52% 1,254,684 38 39 Total Distribution and Marketing (Sum ofLn 27 - Ln 37) $ 22,527,307 $ $ 22,527,307 6.87% $ 1,546,764 40 41 Aligne 42 399.31 ALGN-Servers Hardware $ 297,267 $ - $ 297,267 9.48% $ 28,181 43 399.32 ALON-Servers Software 345,730 345,730 8.93% 30,874 44 399.38 ALGN-Applications Software 17,517,104 17,517,104 6.52% 1,142,115 45 46 Total Aligne (Sum ofLn 42 - Ln 44) $ 18,160,101 $ $ 18,160,101 6.61% $ 1,201,170 47 48 49 Total SSU Division 002 (Before Allocation) (Ln 18 + Ln 24 + Ln 39 + Ln 46) $ 190,868,324 $ 201,520 $ 190,666,805 6.96% $ 13,266,718 50 51 52 Total SSU General Office allocated to Colorado (1): (Ln 18 * 2.89%) 2.89% $ 296,027 53 Total Greenville Data Center allocated to Colorado (1): (Ln 24 * 1.17%) 1.17% 3,233 54 Total Distribution and Marketing allocated to Colorado (1): (Ln 39 * 3.29%) 3.29% 50,824 55 Total Aligne allocated to Colorado (1): (Ln 46 * 0.00%) 0.00% 56 57 Total Division 002 allocated to Colorado (Ln 52 + Ln 53 + Ln 54 + Ln 55) $ 350,084 58 59 Note: 60 1. See the Allocation Factors workpaper for additional detail. WP6-3 2of2 Atmos Energy Corporation - Colorado Service Areas Division 012 Depreciation Adjustment Test Year Ended March 31, 2017 Fully&Non Current Line Balance as of Depreciable Depreciable Depreciation Proforma No. Account Description 03/31/2017 Plant Plant Rate Expense (a) (b) (c) (d) (e) (f) (g) 1 389.00 Land $ 2,874,240 $ 2,874,240 $ 0.00% $ 2 390.00 Structures & Improvements 12,620,665 12,620,665 3.01% 379,882 3 390.09 Leasehold Improvements 2,820,614 2,820,614 3.25% 91,670 4 391.00 Office Furniture and Equipment 2,365,025 2,365,025 3.96% 93,655 5 391.03 Office Furn. - Copiers & Type 3.96% 6 397.00 Communication Equipment 1,913,117 1,913,117 5.85% 111,917 7 398.00 Miscellaneous Equipment 70,016 70,016 5.29% 3,704 8 399.00 Other Tangible Property 629,166 629,166 13.06% 82,169 9 399.01 Servers Hardware 9,310,701 9,310,701 9.48% 882,654 10 399.02 Servers Software 1,891,145 1,891,145 8.93% 168,879 11 399.03 Network Hardware 629,226 629,226 6.99% 43,983 12 399.06 PC Hardware 859,801 859,801 10.49% 90,193 13 399.07 PC Software 190,247 190,247 6.63% 12,613 14 399.08 Application Software 88,537,849 88,537,849 6.52% 5,772,668 15 16 Total SSU Customer Support (Sum ofLns 1 - 14) $ 124,711,811 $ 2,874,240 $ 121,837 ,571 6.35% $ 7,733,988 17 18 Charles K. Vaughan Center 19 389.10 CKV-Land & Land Rights $ 1,887,123 $ 1,887,123 $ 0.00% $ 20 390.10 CKV-Structures & Improvements 11,342,491 11,342,491 3.01% 341,409 21 391.10 CKV-Office Furniture & Equipment 284,686 284,686 3.96% 11,274 22 392.10 CKV-Transportation Equipment 96,290 96,290 8.34% 8,031 23 394.10 CKV-Tools Shop Garage 347,775 347,775 8.37% 29,109 24 395.10 CKV-Laboratory Equipment 23,632 23,632 10.05% 2,375 25 397.10 CKV-Communication Equipment 294,319 294,319 5.85% 17,218 26 398.10 CKV-Misc Equipment 509,283 509,283 5.29% 26,941 27 399.10 CKV-Other Tangible Property 113,831 113,831 13.06% 14,866 28 399.16 CKV-Oth Tang Prop-PC Hardware 228,123 228,123 10.49% 23,930 29 399.17 CKV-Oth Tang Prop-PC Software 102,576 102,576 6.63% 6,801 30 399.18 CKV-Oth Tang Prop-App 20,560 20,560 6.52% 1,341 31 32 Total Charles K. Vaughan Center (Sum of Lines 19 through 30) $ 15,250,689 $ 1,887,123 $ 13,363,566 3.62% $ 483,293 WP 6-4 1 of2 Atmos Energy Corporation - Colorado Service Areas Division 012 Depreciation Adjustment Test Year Ended March 31, 2017 Fully&Non Current Line Balance as of Depreciable Depreciable Depreciation Proforma No. Account Description 03/31/2017 Plant Plant Rate Expense (a) (b) (c) (d) (e) (f) (g) 33 34 Total SSU Division 012 (Before Allocation) (Ln 16 + Ln 32) $ 139,962,499 $ 4,761,363 $ 135,201,137 6.08% $ 8,217,281 35 36 Total SSU Customer Support allocated to Colorado (I): (Ln 16 * 3.79%) 3.79% $ 293,093 37 Total Charles K. Vaughan Center allocated to Colorado (1): (Ln 32 * 2.06%) 2.06% 9,947 38 39 Total Allocated Division 012 (Ln 36 + Ln 37) $ 303,040 40 41 Note: 42 1. See the Allocation Factors workpaper for additional detail. WP6-4 2of2 .. -.·:.-: Atmos Energy Corporation - Colorado Service Areas System Safety and Integrity Rider (SSIR) Depreciation Test Year Ended March 31, 2017 Line No. Date Colorado Amount (1) (a) (b) 1 04/30/16 $ 1,474 2 05/31/16 1,474 3 06/30/16 1,474 4 07/31/16 1,474 5 08/31/16 8,096 6 09/30/16 7,410 7 10/31116 5,118 8 11/30/16 14,387 9 12/31/16 15,018 10 01/31/17 15,018 11 02/28/17 15,018 12 03/31/17 15,018 13 Total $ 100,982 14 15 Note: 1. The amounts are depreciation associated with SSIR assets that were closed to 16 utility plant and determined to be used and useful. The total amount is excluded from the depreciation balance on WP 4-1, Ln 79, Col (c). WP6-5 1of1 Atmos Energy Corporation - Colorado Service Areas State and Federal Taxes Test Year Ended March 31, 2017 As Adjusted Line No. Description Rate Amount (a) (b) (c) 1 Rate Base (Schedule 8, Ln 27, Col (c)) $ 140,938,189 2 Rate of Return on Rate Base (Schedule 9, Ln 6, Col (e)) 8.14% 3 Required Return (Ln 1 * Ln 2) $ 11,472,369 4 Interest Deduction (Ln 1 * (Schedule 9 , Ln 2, Col (e )) 3,241,578 5 Equity Portion of Return (Ln 3 - Ln 4) $ 8,230,791 6 Application of Composite Tax Rate to Net Income Before Taxes (Ln 5 * Ln 9) $ 3,128,524 7 State Tax Rate 4.63% 8 Federal Tax Rate 35.00% 9 Composite Tax Rate 38.01% 10 11 Tax Expansion Factor (1 I (I - 38.01 %) 1.6132 12 Total Income Tax Liability - Before Adjustment (Ln 6 * Ln 11) $ 5,046,820 13 Add Taxable Trust Contributions (WP 7-1, Ln 10, Col (d)) 0 14 Total Income Tax Liability (Ln 12 + Ln 13) $ 5,046,820 Schedule 7 1of1 Atmos Energy Corporation - Colorado Service Areas Allocation of Taxable SFAS 106 Trust Contributions Over PAY GO Test Year Ended March 31, 2017 As Adjusted Line No. Description Div 031 Colorado Div 030 CO/KS Total (a) (b) (c) (d) 1 Statement of Financial Accounting Standards (SPAS) 106 Expense $ (37,591) $" (8,634) 2 3 PAYGO expense 309,284 64,709 4 5 Excess of SPAS 106 OverPAYGO (1) $ $ 6 7 Allocation of SF AS 106 Over PAYOO to: 100% 42.51% 8 9 10 Total Colorado (Ln 5 * Ln 7) $ $ $ 11 12 Note: 13 1. If SF AS 106 expense minus PAYOO expense is less than $0; then the amount is $0. WP7-1 1of1 -·· ·.. · -.--··· - .. ·:: .-:.·-· .· .: .. : .. ," Atmos Energy Corporation - Colorado Service Areas Computation ofSFAS 106 Expense OverPAYGO Test Year Ended March 31, 2017 As Adjusted 6 Months Ended 12 Months Ended 6 Months Ended 12 Months Ended Line No. Description 3/31/2016 9/30/2016 3/31/2017 3/31/2017 (a) (b) (c) (d) (e) 1 Colorado 2 3 SFAS 106 Expense $ 4,156 $ 8,240 $ (41,675) $ (37,591) 4 5 PAYOO Expense 157,747 326,566 140,465 309,284 6 7 Excess of SFAS 106 Over PAYOO (1) $ $ $ $ 8 9 Colorado Kansas General Office 10 11 SFAS 106 Expense $ 823 $ 1,679 $ (9,490) $ (8,634) 12 13 PAYOO Expense 31,577 65,496 30,789 64,709 14 15 Excess of SFAS 106 Over PAYGO (1) $ $ $ $ 16 17 Note: 18 1. If SPAS 106 expense minus PAYOO expense is less than $0; then the amount is $0. WP 7-1-1 1of1 Atmos Energy Corporation - Colorado Service Areas Colorado Rate Base Test Year Ended March 31, 2017 Line No. Description Reference Colorado Amount (a) (b) (c) 1 Average Rate Base: 2 Net Plant in Service (1) WP 8-1 $ 149,050,714 3 Work in Progress WP8-3 3,698,161 4 Average Storage Gas WP8-4 1,993,308 5 Accumulated Deferred Federal Income Tax WP8-5 (15,467,628) 6 Customer Advances for Construction WP8-6 (732,988) 7 Customer Deposits WP8-7 (3,024,754) '- 8 Prepaid Pension Expense WP8-8 1,472,606 9 Working Capital: 10 Prepayments WP8-9 870,914 11 Cash Requirements WP 8-11 (1,710,369) 12 13 Total Average Rate Base (Sum ofLns 2 - 11) $ 136,149,965 14 Schedule 8 1 of2 Atmos Energy Corporation - Colorado Service Areas Colorado Rate Base Test Year Ended March 31, 2017 Line No. Description Reference Colorado Amount (a) (b) (c) 15 March 2017 Rate Base: 16 Net Plant in Service (1) WP 8-1 $ 153,201,819 17 Work in Progress WP8-3 1,919,381 18 Average Storage Gas (2) WP 8-4 1,993,308 19 Accumulated Deferred Federal Income Tax WP8-5 (13,051,728) 20 Customer Advances for Construction (2) WP8-6 (732,988) 21 Customer Deposits (2) WP 8-7 (3,024,754) 22 Prepaid Pension Expense (2) WP8-8 1,472,606 23 Working Capital: 24 Prepayments (2) WP8-9 870,914 25 Cash Requirements WP 8-11 (1,710,369) 26 27 Total Rate Base (Sum ofLns 16 - 25) $ 140,938,189 28 29 Notes: 30 I. Net Plant in Service excludes SSIR amounts. 31 2. Denotes 13 month averages. Schedule 8 2of2 Atmos Energy Corporation - Colorado Service Areas Plant In Service For the Thirteen Months Ended 3/31/2017 Line SSU Division SSU Division SSU Division SSU Division SSU Division SSU Division Colorado Service No. Date 002-GO 002 - Greenville 002-AEAM 002-Aligne 012- cs 012- CKV Division 030 Area (1) (a) (b) (c) (d) (e) (f) (g) (h) (i) 1 03/31/16 $165,973,519 $ 9,196,755 $ 21,720,201 $ - $ 148,987,856 $ 12,955,099 $ 1,308,636 $ 236,579,511 2 04/30/16 166,017,098 9,196,755 21,720,201 148,981,307 12,955,099 1,308,636 236,658,419 3 05/31/16 166,700,805 9,196,755 21,720,201 149,321,871 12,955,099 1,333,931 236,360,359 4 06/30/16 166,749,207 9,196,755 21,720,201 149,400,613 12,955,099 1,332,945 235,509,074 5 07/31116 167,413,171 9,196,755 21,720,201 149,406,119 12,955,099 1,336,363 235,202,822 6 08/31/16 165,513,148 9,196,755 21,694,056 149,325,218 15,056,078 1,340,433 235,434,352 7 09/30/16 133,411,908 9,196,755 21,970,034 17,637,860 125,095,393 15,067,448 1,392,130 234,942,193 8 10/31116 136,534,428 9,196,755 21,970,034 17,713,576 125,312,693 15,067,448 1,392,130 236,063,785 9 11/30/16 138,730, 739 9,196,755 21,970,034 17,840,215 125,312,554 15,067,448 1,392,130 243,082,592 10 12/31/16 143,947,579 9,196,755 22,527,307 18,093,299 124,480,648 15,067,448 1,037,905 243,653,619 11 01131117 145,492,815 9,196,755 22,527,307 18,115,631 124,588,243 15,229,806 1,047,904 244,279,509 12 02/28/17 145,505,267 9,196,755 22,527,307 18,157,511 124,606,630 15,244,500 1,047,904 244,976,666 13 03/31/17 140,984,161 9,196,755 22,527,307 18,160,101 124,711,811 15,250,689 1,042,735 245,993,311 14 13 Month Average $152,536,450 $ 9,196,755 $ 22,024,184 $ 9,670,630 $ 136,117,766 $ 14,294,335 $ 1,254,906 $ 239,133,555 15 16 Allocation Percentages 2.89% 1.17% 3.29% 0.00% 3.79% 2.06% 42.51% 100.00% 17 Allocation of Shared Services Division 002 - GO (Ln 14, Col (b) * 2.89%) $ 4,409,079 18 Allocation of Shared Services Division 002 - Greenville (Ln 14, Col (c) * 1.17%) 107,167 19 Allocation of Shared Services Division 002 -AEAM (Ln 14, Col (d) * 3.29%) 723,677 20 Allocation of Shared Services Division 002 -Aligne (Ln 14, Col (e) *0.00%) 21 Allocation of Shared Services Division 012- CS (Ln 14, Col (f) * 3.79%) 5,158,417 22 Allocation of Shared Services Division 012 - CKV (Ln 14, Col (g) * 2.06%) 294,211 23 Allocation ofDivision 030 (Ln 14, Col (h) * 42.51%) 533,429 24 Total Average Plant in Service at March 31, 2017 (Ln 14 +(Sum ofLns 17-23) $ 250,359,535 25 26 Accumulated Depreciation (WP 8-2, Ln 24, Col (i)) $ (101,308,821) 27 28 Total Average Net Plant in Service (Ln 24 + Ln 26) $ 149,050,714 WP 8-1 1 of2 Atmos Energy Corporation - Colorado Service Areas Plant In Service For the Thirteen Months Ended 3/31/2017 Line SSU Division SSU Division SSU Division SSU Division SSU Division SSU Division Colorado Service No. Date 002- GO 002 - Greenville 002 - AEAM 002-Aligne 012-CS 012-CKV Division 030 Area (1) (a) .(b) (c) (d) (e) (f) (g) (h) (i) 29 30 31 32 Plant in Service At March 31, 2017(Ln13) $140,984,161 $ 9,196,755 $ 22,527,307 $ 18,160,101 $ 124,711,811 $ 15,250,689 $ 1,042,735 $ 245,993,311 33 34 Allocation Percentages 2.89% 1.17% 3.29% 0.00% 3.79% 2.06% 42.51% 100.00% 35 Allocation of Shared Services Division 002 - GO (Ln 32, Col {b) * 2.89%) $ 4,075,159 36 Allocation of Shared Services Division 002 - Greenville (Ln 32, Col (c) * 1.17%) 107,167 37 Allocation of Shared Services Division 002 -AEAM (Ln 32, Col (d) * 3.29%) 740,209 38 Allocation of Shared Services Division 002 - Aligne (Ln 32, Col (e) *0.00%) 39 Allocation of Shared Services Division 012 - CS (Ln 32, Col (f) * 3.79%) 4,726,169 40 Allocation of Shared Services Division 012 - CKV (Ln 32, Col (g) * 2.06%) 313,895 41 Allocation of Division 030 (Ln 32, Col (h) * 42.51 %) 443,240 42 Total Plant in Service at March 31, 2017 (Ln 32 +(Sum ofLns 35 - 41) $ 256,399,150 43 44 Accumulated Depreciation (WP 8-2, Ln 38, Col (i)) $ (103,197,331) 45 46 Total Net Plant in Service at March 31, 2017 (Ln 42 + Ln 44) $ 153,201,819 47 48 Note 49 1. The Plant in Service balances are net of the SSIR balance on WP 8-1-1. WP8-1 2 of2 Atmos Energy Corporation - Colorado Service Areas SSIR Plant In Service For the Thirteen Months Ended 3/31/2017 Line No. Date Colorado Amount (1) (a) (b) 1 03/31116 $ 966,485 2 04/30/16 1,640,315 3 05/31116 2,622,951 4 06/30/16 4,232,580 5 07/31/16 5,504,986 6 08/31116 7,150,735 7 09/30/16 8,155,546 8 10/31116 9,473,491 9 11/30/16 10,343,254 10 12/31/16 10,811,940 11 01/31117 10,811,940 12 02/28117 10,811,940 13 03/31/17 10,811,940 14 13 Month Average $ 7,179,854 15 16 Note: 1. The balances represent the SSIR assets that were closed to Plant in Service and determined to be used and useful. No SSIR assets were transferred to Plant after December 17 2016; the SSIR balance for the period 1/31117 through 3/31/17 is the December 2016 balance. WP 8-1-1 1of1 Atmos Energy Corporation - Colorado Service Areas Accumulated Depreciation & Amortization Acct 108 For the Thirteen Months Ended 3/31/2017 Line SSU Division 002- SSU Division 002- SSU Division 002- SSU Division 002- SSU Division 012 · SSU Division 012 · Colorado Service No. Date GO Greenville AEAM Aligne cs CKV Division 030 Area (1) (a) (b) (c) (d) (e) (t) (g) (h) (i) 03/31/16 $ (109,168,317) $ (2,467,032) $ (10,929,362) $ - $ (52,315,508) $ (2,3 02,992) $ (509,253) $ (93,387,425) 2 04/30/16 (110,111,894) (2,523, 780) (11,052,414) (53,071, 720) (2,335, 795) (525,251) (93,943,640) 3 05/31116 (1I1,060,437) (2,580,529) (11, 175,449) (53,830,113) (2,368,597) (544,895) (94,445,577) 4 06/30/16 (112,009,383) (2,637,278) (11,298,485) (54,589,147) (2,401,400) (561,337) (95,141,989) 5 07/31116 (112,966,391) (2,694,026) (11,421,521) (55,348,241) (2,434,203) (577,894) (95,485,895) 6 08/31/16 (113,610,434) (2,750,734) (11,548,390) (56,097,945) (2, 792, 145) (594,617) (95,850,579) 7 09/30/16 (79 ,90 1, 486) (2,807,442) {11,680,946) (935,438) (31,838,422) (2,834,434) (616,598) (96, 130,390) 8 10/31/16 (80,686,229) (2,864,132) (11,805,436) (1,091,052) (32,480,695) (2,876,312) (633,860) (96,802,235) 9 11130116 (81,478,246) (2,920,821) (11,930,153) (1,247,277) (33,122,968) (2,918,189) (651,123) (97, 192,332) 10 12/31116 (79,041,905) (2,977,471) (12,055,934) (1,404,844) (30,010,54 7) (2,960,067) (310,438) (97,710,443) 11 01131117 (79,891,891) (3,034,053) (12,181,828) (1,562,238) (30,650,714) (3,001,944) (324,090) (98,111,648) 12 02/28/17 (80,741,786) (3,090,635) (12,307, 705) (1,719,908) (31,290,956) (3,043,870) (337,743) (98,588, 779) 13 03/31/17 (77,051,490) (3,147,217) (12,433,58 I) (1,877,597) (31,929,684) (3,085,633) (346,197) (99,104,232) 14 13 Month Average $ {94,439,992) $ (2,807,319) $ (11,678,554) $ (756,796) $ (42,044,358) $ (2, 719,660) $ (502,561) $ (96,299,628) 15 16 Allocation Percentages 2.89% 1.17% 3.29% 0.00% 3.79% 2.06% 42.51% 100.00% 17 Allocation of Shared Services Division 002 - GO (Ln 14, Col (b) * 2.89%) $ (2, 729, 796) 18 Allocation of Shared Services Division 002 - Greenville (Ln 14, Col (c) * 1.17%) (32,713) 19 Allocation of Shared Services Division 002 -AEAM (Ln 14, Col (d) * 3.29%) (383,737) 20 Allocation of Shared Services Division 002 -Aligne (Ln 14, Col (e) *0.00%) 21 Allocation of Shared Services Division 012 -CS (Ln 14, Col (t) * 3.79%) (1,593,343) 22 Allocation of Shared Services Division 012 -CKV (Ln 14, Col (g) * 2.06%) (55,977) 23 AllocationofDivision 030 (Ln 14, Col (h) * 42.51%) (213,626) 24 Total Average Accumulated Depreciation & Amortization (Ln 14 +(Sum ofLns 17 - 23)) $ (101,308,821) WP 8-2 1 of2 ·.· .. ···:· Atmos Energy Corporation - Colorado Service Areas Accumulated Depreciation & Amortization Acct 108 For the Thirteen Months Ended 3/31/2017 Line SSU Division 002- SSU Division 002- SSU Division 002- SSU Division 002- SSU Division 012 - SSU Division 012 · Colorado Service No. Date GO Greenville AEAM Aligne CS CKV Division 030 Area (1) (a) (b) (c) (d) (e) (f) (g) (h) (i) 25 26 27 Accumulated Depreciation & 28 Amortization atMarch2017(Ln13) $ (77,051,490) $ (3,147,217) $ (12,433,581) $ (1,877,597) $ (31,929,684) $ (3,085,633) $ (346,197) $ (99,104,232) .....~...i...... ~.....i...... ~...i...== ...... ====~,,,..;,== ...... ====~~======""==="=='"===-======""=~====~~~~ 29 30 Allocation Percentages 2.89% 1.17% 3.29% 0.00% 3.79% 2.06% 42.51% 100.00% 31 Allocation of Shared Services Division 002 - GO (Ln 28, Col (b) * 2.89%) $ (2,227,180) 32 Allocation of Shared Services Division 002 - Greenville (Ln 28, Col (c) * 1.17%) (36,673) 33 Allocation of Shared Services Division 002 -AEAM (Ln 28, Col (d) * 3.29%) (408,546) 34 Allocation of Shared Services Division 002 -Aligne (Ln 28, Col (e) *0.00%) 35 Allocation of Shared Services Division 012 - CS (Ln 28, Col (f) * 3. 79%) (1,210,030) 36 Allocation of Shared Services Division 012 - CKV (Ln 28, Col (g) * 2.06%) (63,510) 37 Allocation of Division 030 (Ln 28, Col (h) * 42.51 %) (147,160) 38 Total Accumulated Depreciation & Amortization at March 31, 2017 (Ln 28 +(Sum ofLns 31 - 37)) $ (103,197,331) 39 40 Note: 41 1. The Accumulated Depreciation balance for Division 31 was transferred to Division 33 within May business. The Company removed the Accumulated Depreciation balances associated with SSIR assets. The SSIR balances are shown on WP 8-2-1. The Colorado Service Area balance includes Division 31 and excludes the SSIR balance. WP 8-2 2of2 .:.:.··.· ... ·.· .. ·.- ·. Atmos Energy Corporation - Colorado Service Areas SSm. Accumulated Depreciation & Amortization For the Thirteen Months Ended 3/31/2017 Line No. Date Colorado Service Area (a) (b) 1 03/31/16 $ (17,693) 2 04/30/16 (19,167) 3 05/31/16 (20,642) 4 06/30/16 (22,116) 5 07/31/16 (23,591) 6 08/31/16 (31,686) 7 09/30/16 (39,096) 8 10/31/16 (44,215) 9 11/30/16 (58,602) 10 12/31/16 (73,620) 11 01/31/17 (88,639) 12 02/28/17 (103,657) 13 03/31/17 (118,675) 14 13 Month Average $ (50,877) 15 16 Note: 1. The balances represent accumulated depreciation associated with SSIR assets that were 17 closed to Plant in Service and determined to be used and useful. The Company is excluding . the balance from the Accumulated Depreciation balance on WP 8-2, Lns 1 - 13 Col (i). WP 8-2-1 1of1 Atmos Energy Corporation - Colorado Service Areas Construction Work in Progress (CWIP) 107 For the Thirteen Months Ended 3/31/2017 Line SSU Division SSU Division Colorado Service No. Date 002 012 Division 030 Division 031 Area (1) (a) (b) (c) (d) (e) (f) 1 03/31/16 $ 24,496,289 $ 1,375,485 $ 338,267 $ 14,198 $ 856,736 2 04/30/16 25,393,188 1,880,317 (104,222) (16,786) 1,625,445 3 05/31/16 25,332,896 1,873,986 (493,501) (141,384) 2,828,107 4 06/30/16 28,458,555 2,120,281 310,010 27,812 4,364,881 5 07/31/16 28,786,709 2,281,485 26,526 (155,068) 5,505,868 6 08/31/16 29,472,446 2,699,372 (862,719) (498,261) 6,514,969 7 09130116 14,245,888 3,463,699 315,538 18,631 6,997,212 8 10/31/16 12,792,468 3,457,249 125,691 18,131 6,950,781 9 11/30/16 5,911,075 2,139,615 297,446 16,649 622,283 10 12/31/16 15,016,644 3,748,167 (10,561) 45,776 614,374 11 01/31/17 5,730,948 2,160,833 348,498 212,911 727,631 12 02/28/17 7,419,945 2,489,320 268,764 199,868 995,394 13 03/31/17 8,701,524 3,073,692 636,250 15,610 1,265,316 14 13 Month Average $ 17,827,583 $ 2,520,269 $ 91,999 $ (18,609) $ 3,066,846 15 16 Allocation Percentage 2.89% 3.79% 42.51% 100.00% 17 Allocation of SSU Division 002 (Ln 14, Col (b) * 2.89%) $ 515,308 18 Allocation ofSSUDivision 012(Ln14, Col (c) * 3.79%) 95,510 19 Allocation ofDivision 030 (Ln 14, Col (d) * 42.51%) 39,106 20 Allocation of Division 031 (Ln 14, Col (e) * 100.00%) (18,609) 21 22 Total 13 Month Average CWIP (Ln 14 +(Sum ofLns 17 - 20)) $ 3,698,161 WP 8-3 1 of2 Atmos Energy Corporation - Colorado Service Areas Construction Work in Progress (CWIP) 107 For the Thirteen Months Ended 3/31/2017 Line SSU Division SSU Division Colorado Service No. Date 002 012 Division 030 Division 031 Area (1) (a) (b) (c) (d) (e) (t) 23 24 25 CWIP at At March 31, 2017 (Ln 13) $ 8,701,524 $ 3,073,692 $ 636,250 $ 15,610 $ 1,265,316 26 27 Allocation Percentage 2.89% 3.79% 42.51% 100.00% 28 Allocation of SSU Division 002 (Ln 25, Col (b) * 2.89%) $ 251,518 29 Allocation of SSU Division 012 (Ln 25, Col (c) * 3.79%) 116,483 30 Allocation of Division 030 General Office (Ln 25, Col (d) * 42.51 %) 270,454 31 Allocation of Division 031 Colorado Admin (Ln 25, Col (e) * 100.00%) 15,610 32 33- Total CWIP at March 31, 2017 (Ln 25 +(Sum ofLns 28 - Ln 31)) $ 1,919,381 34 35 Note: 36 1. The balances are net of the SSIR CWIP balance on WP 8-3-1. WP8-3 2 of2 .- ...... ·:· Atmos Energy Corporation - Colorado Service Areas SSIR Construction Work in Progress For the Thirteen Months Ended 3/31/2017 Line No. Date Colorado Service Area (1) (a) (b) 1 03/31/16 $ 2 04/30/16 3 05/31/16 4 06/30/16 5 07/31/16 6 08/31/16 7 09/30/16 250,091 8 10/31/16 45,393 9 11/30/16 23,553 10 12/31/16 (1,589) 11 01/31/17 14,639 12 02/28/17 384,045 13 03/31/17 1,212,646 14 13 Month Average $ 148,367 15 16 Note 1. The balances within the 2017 calendar year represent those SSIR assets that have not been closed to Plant in Service and determined to be used and useful. The balances in the 2016 17 calendar year are associated with planning for the 2017 SSIR assets. These balances were excluded from the Colorado Direct CWIP balance on WP 8-3, Lns 1 - 13, Col (f). WP 8-3-1 1of1 ... . ··: ...-.· .. ·.·: . ... ,. .. . . ':...... :~. - . Atmos Energy Corporation - Colorado Service Areas Gas Stored Underground Account 1641 Other Rate Base Components For the Thirteen Months Ended 3/31/2017 Line Colorado No. Date Division 031 Direct Total (a) (b) (c) (d) I 03/31/16 $ - $ 441,471 $ 441,471 2 04/30/16 576,557 576,557 3 05/31/16 1,098,821 1,098,821 4 06/30/16 1,572,279 1,572,279 5 07/31/16 2,176,859 2,176,859 6 08/31/16 2,800,942 2,800,942 7 09/30/16 3,453,232 3,453,232 8 10/31/16 4,226,799 4,226,799 9 11/30/16 3,560,465 3,560,465 IO 12/31/16 2,693,165 2,693,165 11 01/31/17 1,890,084 1,890,084 12 02/28/17 1,048,112 1,048,112 13 03/31/17 374,215 374,215 14 13 Month Average $ $ 1,993,308 $ 1,993,308 WP8-4 1of1 ·:·.·.·:·: .... :.: ... ···-· Atmos Energy Corporation - Colorado Service Areas Accumulated Deferred Income Tax (ADIT) Accounts 190/282/283 Other Rate Base Components For the Thirteen Months Ended 3/31/2017 Line SSU Division No. Date Account Number SSU Division 002 012 Division 030 Division 031 (I) Total (a) (b) (c) (d) (e) (t) (g) 1 03/31/16 Account 1900 $ 608,022,792 $ 2,696,777 $ 4,488,831 $ (2,559,380) $ 612,649,020 2 04/30/16 Account 1900 609,381,027 2,696,777 4,488,831 (2,559,380) 614,007,255 3 05/31/16 Account 1900 609,381,027 2,696,777 4,488,831 (2,559,380) 614,007,255 4 06/30/16 Account 1900 614,286,662 2,696,777 4,488,831 (2,559,380) 618,912,890 5 07/31/16 Account 1900 614,286,662 2,696,777 4,488,831 (2,559,380) 618,912,890 6 08/31/16 Account 1900 614,286,662 2,696,777 4,488,831 (2,559,380) 618,912,890 7 09/30/16 Account 1900 804,032,688 (0) 5,262,737 (2,975,242) 806,320,183 8 10/31/16 Account 1900 804,032,688 (0) 5,262,737 (2,975,242) 806,320,183 9 11/30/16 Account 1900 804,032,688 (0) 5,262,737 (2,975,242) 806,320,183 10 12/31/16 Account 1900 814,487,516 (0) 5,262,737 (2,975,242) 816, 775,010 11 01/31/17 Account 1900 814,487,516 (0) 5,262,737 (2,975,242) 816,775,010 12 02/28/17 Account 1900 814,487,516 (0) 5,262,737 (2,975,242) 816,775,010 13 03/31/17 Account 1900 828,348,815 (0) 5,262,737 (2,975,242) 830,636,309 14 03/31/16 Account 2820 $ (28,104,920) $ (32,444,285) $ (1,805,184) $ (36,659,317) $ (99,013,706) 15 04/30/16 Account 2820 (28,104,920) (32,444,285) (I,805,184) (36,659,317) (99,013,706) 16 05/31116 Account 2820 (28, 104,920) (32,444,285) (1,805,184) (36,659,317) (99,013,706) 17 06130116 Account 2820 (6, 179,902) (32,444,285) (2,876,604) (36,659,317) (78,160,108) 18 0713 I/16 Account 2820 (6, 179,902) (32,444,285) (2,876,604) (36,659,317) (78,160,108) 19 08/31/16 Account 2820 (6, 179,902) (32,444,285) (2,876,604) (36,659,317) (78,160,108) 20 09/30/16 Account 2820 (22,179,584) (27,916,937) (188,986) (39,379,193) (89,664, 700) 21 10/31/16 Account 2820 (22,179,584) (27,916,937) (188,986) (39,379,193) (89,664,700) 22 11/30/16 Account 2820 (22,179,584) (27,916,937) (188,986) (39,379,193) (89,664,700) 23 12/31/16 Account 2820 823,198 (27,916,937) (1,355,879) (39,379,193) (67,828,811) 24 01/31/17 Account 2820 823,198 (27,916,937) (1,355,879) (39,379,193) (67,828,811) 25 02/28/17 Account 2820 823,198 (27,916,937) (1,355,879) (39,379,193) (67,828,811) 26 03/31/17 Account 2820 ( 49,976,379) (27,916,937) (4,681,997) (39,379,193) (121,954,506) WPS-5 1 of3 Atmos Energy Corporation - Colorado Service Areas Accumulated Deferred Income Tax (ADIT) Accounts 190/282/283 Other Rate Base Components For the Thirteen Months Ended 3/31/2017 Line SSU Division No. Date Account Number SSU Division 002 012 Division 030 Division 03 I (1) Total (a) (b) (c) (d) (e) (f) (g) 27 03/31/16 Account 2830 $ 38,160,453 $ - $ (108,600) $ 2,472,172 $ 40,524,025 28 04/30/16 Account 2830 34,430,342 (108,600) 2,472,172 36,793,914 29 05/31/16 Account 2830 38,530,091 (108,600) 2,472,172 40,893,663 30 06/30/16 Account 2830 60,630,610 (108,600) 2,472,172 62,994,182 31 07/31/16 Account 2830 69,180,048 (108,600) 2,472,172 71,543,621 32 08/31116 Account 2830 73,835,787 (108,600) 2,472,172 76,199,359 33 09/30/16 Account 2830 70,236,799 (574,779) (176,522) 2,830,500 72,315,998 34 10/31/16 Account 2830 52,433,128 (574,779) (176,522) 2,830,500 54,512,327 35 11130/16 Account 2830 23,335,754 (574,779) (176,522) 2,830,500 25,414,952 36 12/31/16 Account 2830 18,200,874 (574,779) (176,522) 2,830,500 20,280,072 37 01/31/17 Account 2830 15,873,894 (574,779) (176,522) 2,830,500 17,953,093 38 02/28117 Account 2830 14,260,639 (574,779) (176,522) 2,830,500 16,339,838 39 03/31117 Account 2830 14,934,609 (574,779) (176,522) 2,830,500 17,013,807 40 03/31/16 Total $ 618,078,325 $ (29,747,509) $ 2,575,047 $ (36,746,525) $ 554,159,339 41 04/30116 Total 615,706,449 (29,747,509) 2,575,047 (36,746,525) 551,787,463 42 05/31/16 Total 619,806,198 (29,747,509) 2,575,047 (36,746,525) 555,887,212 43 06/30116 Total 668,737,371 (29,747,509) 1,503,627 (36,746,525) 603,746,964 44 07/31116 Total 677,286,809 (29,747,509) 1,503,627 (36,746,525) 612,296,402 45 08/31/16 Total 681,942,547 (29,747,509) 1,503,627 (36,746,525) 616,952,140 46 09/30/16 Total 852,089,904 (28,491,717) 4,897,229 (39,523,936) 788,971,480 47 10/31116 Total 834,286,233 (28,491,717) 4,897,229 (39,523,936) 771,167,809 48 11130116 Total 805, 188,859 (28,491,717) 4,897,229 (39,523,936) 742,070,435 49 12/31/16 Total 833,511,588 (28,491,717) 3,730,335 (39,523,936) 769,226,271 50 01/31/17 Total 831, 184,608 (28,491,717) 3, 730,335 (39,523,936) 766,899,291 51 02/28/17 Total 829,571,354 (28,491,717) 3,730,335 (39,523,936) 765,286,037 52 03/31/17 Total 793,307,044 (28,491,717) 404,218 (39,523,936) 725,695,610 53 Total 13 Month Average (Sum ofLns 40 -52) $ 743,130,561 $ (29,071,313) $ 2,963,303 $ (38,242,054) $ 678,780,496 WP8-5 2 of3 Atmos Energy Corporation - Colorado Service Areas Accumulated Deferred Income Tax (ADIT) Accounts 190/282/283 Other Rate Base Components For the Thirteen Months Ended 3/31/2017 Line SSU Division No. Date Account Number SSU Division 002 012 Division 03 0 Division 031 (I) Total (a) (b) (c) (d) (e) (f) (g) 54 55 ADIT 13 Month Average 56 Allocation ofSSU Division 002 (Ln 53, Col (c) * 2.89%) 2.89% $ 21,480,252 57 Allocation ofSSU Division 012 (Ln 53, Col (d) * 3.79%) 3.79% (I,101,707) 58 Allocation of Division 030 (Ln 53, Col (e) * 42.51%) 42.51% 1,259,625 59 Allocation of Division 031 (Ln 53, Col (f) * 100.00%) 100.00% (38,242,054) 60 Colorado Direct SSIR (2) {WP 8-5-4, Ln 14, Col (b)) 100.00% 1,136,256 61 Total Average ADIT (Sum ofLns 56 - 60) $ (15,467,628) 62 63 ADIT at March 31, 2017 64 Allocation ofSSU Division 002 (Ln 52, Col (c) * 2.89%) 2.89% $ 22,930,608 65 Allocation ofSSU Division 012 (Ln 52, Col (d) * 3.79%) 3.79% (1,079,743) 66 Allocation of Division 030 (Ln 52, Col (e) * 42.51%) 42.51 % 171,823 67 Allocation of Division 031(Ln52, Col (f) * 100.00%) 100.00% {39,523,936) 68 Colorado Direct SSIR (2) (WP 8-5-4, Ln 13, Col (b)) 100.00% 4,449,519 69 TotalADIT at March 31, 2017 {Sum ofLns 64- 68) $ (13,051,728) 70 71 Notes: 72 1. Colorado Division 31 includes Divisions 33, 34, 35 and 36. 73 2. The ADIT balance is associated with SSIR assets. This amount is excluded from filing. See WP 8-5-4 for further details. WP8-5 3 of3 -...... : ..... ·,·. Atmos Energy Corporation - Colorado Service Areas Accumulated Deferred Income Tax Adjustment to Account 1900 Other Rate Base Components For the Thirteen Months Ended 3/31/2017 Line Account SSU Division SSU Division No. Date Number 002 012 Division 030 Division031 (1) Total (a) (b) (c) (d) (e) (t) (g) 1 Per Books 2 03/31/16 Account 1900 $ 386,465,313 $ 2,696,777 $ 4,488,831 $ 520,739 $ 394,171,660 3 04/30/16 Account 1900 387,823,548 2,696,777 4,488,831 520,739 395,529,895 4 05/31/16 Account 1900 387,823,548 2,696,777 4,488,831 520,739 395,529,895 5 06/30/16 Account 1900 387,916,036 2,696,777 4,488,831 520,739 395,622,383 6 07/31/16 Account 1900 387,916,036 2,696,777 4,488,831 520,739 395,622,383 7 08/31/16 Account 1900 387,916,036 2,696,777 4,488,831 520,739 395,622,383 8 09/30/16 Account 1900 572,351,133 (0) 5,262,737 494,648 578, 108,518 9 10/31/16 Account 1900 572,351,133 (0) 5,262,737 494,648 578, 108,518 10 11/30/16 Account 1900 572,351,133 (0) 5,262,737 494,648 578, 108,518 11 12/31/16 Account 1900 575,007,856 (0) 5,262,737 494,648 580,765,241 12 01/31117 Account 1900 575,007,856 (0) 5,262,737 494,648 580,765,241 13 02/28/17 Account 1900 575,007,856 (0) 5,262,737 494,648 580,765,241 14 03/31/17 Account 1900 575,258, 176 (0) 5,262,737 494,648 581,015,560 15 Deferred Gas Cost 16 03/31/16 Account 1900 $ 3,080,119 $ 3,080,119 17 04/30/16 Account 1900 3,080,119 3,080,119 18 05/31/16 Account 1900 3,080,119 3,080,119 19 06/30/16 Account 1900 3,080,119 3,080,119 20 07/31/16 Account 1900 3,080,119 3,080,119 21 08/31/16 Account 1900 3,080,119 3,080,119 22 09/30/16 Account 1900 3,469,890 3,469,890 23 10/31/16 Account 1900 3,469,890 3,469,890 24 11/30/16 Account 1900 3,469,890 3,469,890 25 12/31/16 Account 1900 3,469,890 3,469,890 26 01/31/17 Account 1900 3,469,890 3,469,890 27 02/28/17 Account 1900 3,469,890 3,469,890 28 03/31/17 Account 1900 3,469,890 3,469,890 WP 8-5-1 1 of3 Atmos Energy Corporation - Colorado Service Areas Accumulated Deferred Income Tax Adjustment to Account 1900 Other Rate Base Components For the Thirteen Months Ended 3/31/2017 Line Account SSU Division SSU Division No. Date Number 002 012 Division 03 0 Division 031 (1) Total (a) (b) (c) (d) (e) (f) (g) 29 FD-NOL Credit Carzyforward - Other 30 03/31/16 Account 1900 $ 5,386,873 $ 5,386,873 31 04/30/16 Account 1900 5,386,873 5,386,873 32 05/31/16 Account 1900 5,386,873 5,386,873 33 06/30/16 Account 1900 5,386,873 5,386,873 34 07/31/16 Account 1900 5,386,873 5,386,873 35 08/31/16 Account 1900 5,386,873 5,386,873 36 09/30/16 Account 1900 6,052,102 6,052,102 37 10/31/16 Account 1900 6,052,102 6,052,102 38 11/30/16 Account 1900 6,052,102 6,052,102 39 12/31/16 Account 1900 6,052,102 6,052,102 40 01/31/17 Account 1900 6,052,102 6,052,102 41 02/28/17 Account 1900 6,052,102 6,052,102 42 03/31/17 Account 1900 6,052,102 6,052,102 43 Federal NOL - Can:yover - Non Reg 012erations 44 03/31/16 Account 1900 $ (226,944,352) $ (226,944,352) 45 04/30/16 Account 1900 (226,944,3 52) (226,944,352) 46 05/31/16 Account 1900 (226,944,3 52) (226,944,352) 47 06/30/16 Account 1900 (231, 757,499) (231,757,499) 48 07/31/16 Account 1900 (231, 757,499) (231,757,499) 49 08/31/16 Account 1900 (231,757,499) (231, 757,499) 50 09/30/16 Account 1900 (237, 733,657) (237,733,657) 51 10/31/16 Account 1900 (237,733,657) (237,733,657) 52 11/30/16 Account 1900 (237,733,657) (237,733,657) 53 12/31116 Account 1900 (245,531,762) (245,531,762) 54 01/31/17 Account 1900 (245,531,762) (245,531,762) 55 02/28/17 Account 1900 (245,531,762) (245,531,762) 56 03/31/17 Account 1900 (259,142,741) (259,142,741) WP 8-5-1 2 of3 ..... ·. ·.-.·-·· .... , Atmos Energy Corporation - Colorado Service Areas Accumulated Deferred Income Tax Adjustment to Account 1900 Other Rate Base Components For the Thirteen Months Ended 3/31/2017 Line Account SSU Division SSU Division No. Date Number 002 012 Division 030 Division 031 (1) Total (a) (b) (c) (d) (e) (f) (g) 57 Adjusted 58 03/31/16 Account 1900 $ 608,022,792 $ 2,696,777 $ 4,488,831 $ (2,559,380) $ 612,649,020 59 04/30/16 Account 1900 609,381,027 2,696,777 4,488,831 (2,559,380) 614,007,255 60 05/31/16 Account 1900 609,381,027 2,696,777 4,488,831 (2,559,380) 614,007,255 61 06/30/16 Account 1900 614,286,662 2,696,777 4,488,831 (2,559,380) 618,912,890 62 07/31/16 Account 1900 614,286,662 2,696,777 4,488,831 (2,559,380) 618,912,890 63 08/31116 Account 1900 614,286,662 2,696,777 4,488,831 (2,559,380) 618,912,890 64 09/30/16 Account 1900 804,032,688 (0) 5,262,737 (2,975,242) 806,320,183 65 10/31/16 Account 1900 804,032,688 (0) 5,262,737 (2,975,242) 806,320, 183 66 11/30/16 Account 1900 804,032,688 (0) 5,262,737 (2,975,242) 806,320, 183 67 12/31/16 Account 1900 814,487,516 (0) 5,262,737 (2,975,242) 816,775,010 68 01/31/17 Account 1900 814,487,516 (0) 5,262,737 (2,975,242) 816,775,010 69 02/28/17 Account 1900 814,487,516 (0) 5,262,737 (2,975,242) 816,775,010 70 03/31/17 Account 1900 828,348,815 (0) 5,262,737 (2,975,242) 830,636,309 71 72 Note: 73 I. Colorado Division 31 includes Divisions 33, 34, 35 and 36. WP 8-5-1 3 of3 , ..... -.. _...... ·· Atmos Energy Corporation - Colorado Service Areas Accumulated Deferred Income Tax Adjustment to Account 282 Other Rate Base Components For the Thirteen Months Ended 3/3112017 Line Account SSU Division No. Date Number SSU Division 002 012 Division 030 Division 031 (I) Total (a) (b) (c) (d) (e) (f) (g) 1 Per Books 2 03/31/16 Account 2820 $ (28,104,920) $ (32,444,285) $ (3,765,848) $ (36,659,317) $(100,974,370) 3 04/30/16 Account 2820 (28,104,920) (32,444,285) (3,765,848) (36,659,317) (100,974,370) 4 05/31/16 Account 2820 (28,104,920) (32,444,285) (3,765,848) (36,659,317) ( 100,97 4,370) 5 06/30/16 Account 2820 (6,179,902) (32,444,285) (2,178,232) (36,659,317) (77,461,737) 6 07/31/16 Account 2820 (6,179,902) (32,444,285) (2,178,232) (36,659,317) (77,461,737) 7 08/31/16 Account 2820 (6,179,902) (32,444,285) (2, 178,232) (36,659,317) (77,461,737) 8 09/30/16 Account 2820 (22,179,584) (27,916,937) (188,986) (39,379,193) (89,664, 700) 9 10/31/16 Account 2820 (22,179,584) (27,916,937) (188,986) (39,379,193) (89,664, 700) IO 11/30/16 Account 2820 (22,179,584) (27,916,937) (188,986) (39,379,193) (89 ,664, 700) 11 12/31/16 Account 2820 823,198 (27 ,916,93 7) (3,689,670) (39,379,193) (70, 162,602) 12 01/31/17 Account 2820 823,198 (27,916,937) (3,689,670) (39,379,193) (70, 162,602) 13 02/28/17 Account 2820 823,198 (27,916,937) (3,689,670) (39,379,193) (70, 162,602) 14 03/31/17 Account 2820 (49,976,379) (27,916,937) (6,659,725) (39,379,193) (123,932,234) 15 Deferred Gas Cost 16 03/31/16 Account 2820 $ 335,820 $ 335,820 17 04/30/16 Account 2820 335,820 335,820 18 05/31/16 Account 2820 335,820 335,820 19 06/30/16 Account 2820 2,280,882 2,280,882 20 07/31/16 Account 2820 2,280,882 2,280,882 21 08/31/16 Account 2820 2,280,882 2,280,882 22 09/30/16 Account 2820 23 10/31/16 Account 2820 24 11/30/16 Account 2820 25 12/31/16 Account 2820 (2,813,520) (2,813,520) 26 01/31/17 Account 2820 (2,813,520) (2,813,520) 27 02/28/17 Account 2820 (2,813,520) (2,813,520) 28 03/31/17 Account 2820 (2,957,229) (2,957,229) WP 8-5-2 1 of2 Atmos Energy Corporation - Colorado Service Areas Accumulated Deferred Income Tax Adjustment to Account 282 Other Rate Base Components For the Thirteen Months Ended 3/31/2017 Line Account SSU Division No. Date Number SSU Division 002 012 Division 030 Division 031 (1) Total (a) (b) (c) (d) (e) (f) (g) 29 PGA - Amended Item/Over Recoverv 30 03/31/16 Account 2820 $ (2,296,484) $ (2,296,484) 31 04/30/16 Account 2820 (2,296,484) (2,296,484) 32 05/31/16 Account 2820 (2,296,484) (2,296,484) 33 06/30/16 Account 2820 (1,582,511) (1,582,511) 34 07/31/16 Account 2820 (1,582,511) (1,582,511) 35 08/31/16 Account 2820 (1,582,511) (1,582,511) 36 09/30/16 Account 2820 37 10/31116 Account 2820 38 11/30/16 Account 2820 39 12/31/16 Account 2820 479,729 479,729 40 01/31/17 Account 2820 479,729 479,729 41 02/28/17 Account 2820 479,729 479,729 42 03/31/17 Account 2820 979,501 979,501 43 Adjusted 44 03/31116 Account 2820 $ (28,104,920) $ (32,444,285) $ (1,805,184) $ (36,659,317) $ (99,013,706) 45 04/30/16 Account 2820 (28,104,920) (32,444,285) (1,805,184) (36,659,317) (99,013,706) 46 05/31/16 Account 2820 (28,104,920) (32,444,285) (1,805, 184) (36,659,317) (99,013,706) 47 06/30/16 Account 2820 (6,179,902) (32,444,285) (2,876,604) (36,659,317) (78,160,108) 48 07/31/16 Account 2820 (6,179,902) (32,444,285) (2,876,604) (36,659,317) (78,160,108) 49 08/31/16 Account 2820 (6,179,902) (32,444,285) (2,876,604) (36,659,317) (78,160,108) 50 09/30/16 Account 2820 (22,179,584) (27,916,937) (188,986) (39,379,193) (89,664,700) 51 10/31/16 Account 2820 (22,179,584) (27,916,937) (188,986) (39,379,193) (89,664,700) 52 11/30/16 Account 2820 (22,179,584) (27,916,937) (188,986) (39,379,193) (89,664,700) 53 12/31/16 Account 2820 823,198 (27,916,937) (1,355,879) (39,379,193) (67,828,811) 54 01/31/17 Account 2820 823,198 (27,916,937) (1,355,879) (39,379,193) (67,828,811) 55 02/28/17 Account 2820 823,198 (27,916,937) (1,355,879) (39,379,193) (67,828,811) 56 03/31/17 Account 2820 (49,976,379) (27 ,916,937) (4,681,997) (39,379,193) (121,954,506) 57 58 Note: 59 I. Colorado Division 31 includes Divisions 33, 34, 35 and 36. WP 8-5-2 2of2 Atmos Energy Corporation - Colorado Service Areas Accumulated Deferred Income Tax Adjustment to Account 283 Other Rate Base Components For the Thirteen Months Ended 3/31/2017 Line SSU Division SSU Division No Date Account Number 002 012 Division 030 Division 031 (1) Total (a) (b) (c) (d) (e) (f) (g) Per Books 2 03/31/16 Account 2830 $ 38,160,453 $ - $ (108,600) $ (1,313,675) $ 36,738,178 3 04/30/16 Account 2830 34,430,342 (108,600) (1,313,675) 33,008,067 4 05/31/16 Account 2830 38,530,091 (108,600) (1,313,675) 37,107,815 5 06/30/16 Account 2830 60,630,610 (108,600) (1,313,675) 59,208,335 6 07/31/16 Account 2830 69,180,048 (108,600) (1,313,675) 67,757,773 7 08/31/16 Account 2830 73,835,787 (108,600) (1,313,675) 72,413,511 8 09/30/16 Account 2830 70,236,799 (574,779) (176,522) (1,417,130) 68,068,368 9 10/31/16 Account 2830 52,433,128 (574,779) (176,522) (l,417,130) 50,264,697 10 11/30/16 Account 2830 23,335,754 (574,779) (176,522) (1,417,130) 21,167,322 11 12/31/16 Account 2830 18,200,874 (574,779) (176,522) (1,417,130) 16,032,442 12 01/31/17 Account 2830 15,873,894 (574,779) (176,522) (1,417,130) 13,705,463 13 02/28/17 Account 2830 14,260,639 (574,779) (176,522) (1,417,130) 12,092,208 14 03/31/17 Account 2830 14,934,609 (574,779) (176,522) (1,417,130) 12,766,177 15 Deferred Gas Cost 16 03/31/16 Account 2830 $ 17 04/30/16 Account 2830 18 05/31/16 Account 2830 19 06/30/16 Account 2830 20 07/31/16 Account 2830 21 08/31/16 Account 2830 22 09/30/16 Account 2830 23 10/31/16 Account 2830 24 11130/16 Account 2830 25 12/31/16 Account 2830 26 01/31/17 Account 2830 27 02/28/17 Account 2830 28 03/31/17 Account 2830 WP 8-5-3 1 of2 Atmos Energy Corporation - Colorado Service Areas Accumulated Deferred Income Tax Adjustment to Account 283 Other Rate Base Components For the Thirteen Months Ended 3/31/2017 Line SSU Division SSU Division No Date Account Number 002 012 Division 030 Division 031 (1) Total (a) (b) (c) (d) (e) (f) (g) 29 Over Recoveries of PGA 30 03/31/16 Account 2830 $ (3,785,848) $ (3,785,848) 31 04/30/16 Account 2830 (3,785,848) (3,785,848) 32 05/31/16 Account 2830 (3,785,848) (3,785,848) 33 06/30/16 Account 2830 (3, 785 ,848) (3,785,848) 34 07/31/16 Account 2830 (3,785,848) (3,785,848) 35 08/31116 Account 2830 (3,785,848) (3,785,848) 36 09/30/16 Account 2830 (4,247,630) ( 4,24 7 ,630) 37 10/31/16 Account 2830 (4,247,630) (4,247,630) 38 11/30/16 Account 2830 (4,247,630) (4,247,630) 39 12/31/16 Account 2830 (4,247,630) (4,247,630) 40 01/31/17 Account 2830 (4,247,630) (4,247,630) 41 02/28/17 Account 2830 (4,247,630) (4,247,630) 42 03/31117 Account 2830 (4,247,630) (4,247,630) 43 Adjusted 44 03/31116 Account 2830 $ 38,160,453 $ $ (108,600) $ 2,472,172 $ 40,524,025 45 04/30/16 Account 2830 34,430,342 (108,600) 2,472,172 36,793,914 46 05/31/16 Account 2830 38,530,091 (108,600) 2,472,172 40,893,663 47 06/30/16 Account 2830 60,630,610 (108,600) 2,472,172 62,994,182 48 07/31/16 Account 2830 69,180,048 (108,600} 2,472,172 71,543,621 49 08/31/16 Account 2830 73,835,787 (108,600) 2,472,172 76,199,359 50 09/30/16 Account 2830 70,236,799 (574,779} (176,522) 2,830,500 72,315,998 51 10/31/16 Account 2830 52,433,128 (574,779) (176,522) 2,830,500 54,512,327 52 11/30/16 Account 2830 23,335,754 (574,779) (176,522) 2,830,500 25,414,952 53 12/31/16 Account 2830 18,200,874 (574,779} (176,522) 2,830,500 20,280,072 54 01/31/17 Account 2830 15,873,894 (574,779) (176,522) 2,830,500 17,953,093 55 02/28/17 Account 2830 14,260,639 (574,779) (176,522) 2,830,500 16,339,838 56 03/31/17 Account 2830 14,934,609 (574,779) (176,522) 2,830,500 17,013,807 57 58 Note: 59 1. Colorado Division 31 includes Divisions 33, 34, 35 and 36. WP 8-5~3 2of2 ...... -,.:. . .·,-.:;.,_· . .· ..... _:,::.::- .. ··· Atmos Energy Corporation - Colorado Service Areas SSIR Accumulated Deferred Income Tax Adjustment Other Rate Base Components For the Thirteen Months Ended 3/31/2017 SSIR Accumulated Deferred Income Line No Date Tax Balance (1) (a) (b) 1 3/31/16 $ 329,139 2 4/30/16 338,816 3 5/31/16 259,021 4 6130116 (2,441) 5 7/31116 (166,196) 6 8/31/16 (440,902) 7 9/30/16 (529,616) 8 10/31/16 (636,400) 9 11/30/16 (643,120) 10 12/31/16 (556,018) 11 1/31/17 (4,093,872) 12 2/28/17 (4,180,214) 13 3/31/17 (4,449 ,519) 14 Total 13 Month Average $ (1,136,256) 15 16 Note: 1: These balances are associated with SSIR assets and are excluded from the 17 balances on WP 8-5, Ln 60 (for Average) and Ln 68 (for end of Test Year). WP 8-5-4 1 of I ·· .. ·_·_·:- ··- .-.·.-:·, ,····· Atmos Energy Corporation - Colorado Service Areas Customer Advances for Construction Account 252 Other Rate Base Components For the Thirteen Months Ended 3/31/2017 Line No. Date Colorado Amount (a) (b) 1 03/31/16 $ (795,061) 2 04130116 (642,683) 3 05/31/16 (655,474) 4 06/30/16 (620,070) 5 07/31/16 (681,420) 6 08/31/16 (715,920) 7 09/30/16 (775,223) 8 10/31/16 (760,223) 9 11/30/16 (774,603) 10 12/31/16 (770,973) 11 01/31/17 (767,403) 12 02/28/17 (787,403) 13 03/31/17 (782,382) 14 15 Total Average Customer Advances for Construction $ (732,988) WP 8-6 1of1 Atmos Energy Corporation - Colorado Service Areas Customer Deposits Account 235 Other Rate Base Components For the Thirteen Months Ended 3/31/2017 Line No Date Colorado Amount (a) (b) 1 03/31/16 $ (3,502,911) 2 04/30/16 (3,505,421) 3 05/31/16 (3,520,672) 4 06/30/16 (3,529,852) 5 07/31/16 (3,512,278) 6 08/31/16 (3,532,712) 7 09/30/16 (3,524,579) 8 10/31/16 (3,449,742) 9 11/30/16 (3,427,828) 10 12/31/16 (2,527,949) 11 01/31/17 (1,964,817) 12 02/28/17 (1,711,838) 13 03/31/17 (1,611,199) 14 15 Total Average Customer Deposits $ (3,024,754) WP8-7 1of1 .·, ... ·.·:·: Atmos Energy Corporation - Colorado Service Areas Prepaid Pension Expense Miscellaneous Deferred Debit 1860, Sub Account 13993 For the Thirteen Months Ended 3/31/2017 Other Rate Base Components Line No. Date SSU Division 002 (a) (b) 1 03/31/16 $ 51,346,343 2 04/30/16 49,466,589 3 05/31/16 47,586,836 4 06/30/16 60,707,082 5 07/31/16 58,827,328 6 08/31/16 56,942,216 7 09/30/16 53,988,492 8 10/31/16 51,978,874 9 11/30/16 50,140,025 10 12/31/16 48,215,791 11 01/31/17 46,291,557 12 02/28/17 44,367,324 13 03/31/17 42,443,090 14 Thirteen Month Average Balance $ 50,946,273 15 16 Division 002 Allocation Factor 2.89% 17 18 Thirteen Month Average Allocated to Colorado (Ln 14 * Ln 16) $ 1,472,606 19 20 March 31, 2017 Allocated to Colorado (Ln 13 * Ln 16) $ 1,226,821 WP 8-8 1of1 ·· .. ·. ___ ,, __ .,_: Atmos Energy Corporation - Colorado Service Areas Prepaid Account 165 Other Rate Base Components For the Thirteen Months Ended 3/31/2017 Line SSU Division No Date SSU Division 002 012 Division 030 Division 031 (a) (b) (c) (d) (e) 1 03/31/16 $ 26,445,249 $ - $ 38,876 $ (64,902) 2 04/30/16 25,550,137 34,017 (11,454) 3 05/31/16 27,278,517 29,157 (26,588) 4 06/30/16 24,655,461 24,298 23 5 07/31/16 22,751,428 19,4JS 95,873 6 08/31/16 19,812,706 14,579 50,083 7 09/30/16 16,834,769 9,719 32,202 8 10/31/16 34,994,758 2,061,046 4,860 36,684 9 11/30/16 36,967,739 1,290,907 74,050 IO 12/31/16 33,944,542 1,968,032 53,455 32,942 11 01/31/17 32,452,354 1,848,566 48,595 58,739 12 02/28/17 28,243,166 2,174,650 43,736 13,164 13 03/31/17 31,839,499 1,879,184 38,876 (4,087) 14 15 13 Month Average $ 27,828,487 $ 863,261 $ 27,662 $ 22,056 WP8-9 1 of2 Atmos Energy Corporation - Colorado Service Areas Prepaid Account 165 Other Rate Base Components For the Thirteen Months Ended 3/31/2017 Line SSU Division No Date SSU Division 002 012 Division 030 Division 031 (a) (b) (c) (d) (e) 16 17 Allocation of SSU Division 002 (Ln 15, Col (b) * 2.89%) 2.89% $ 804,385 18 Allocation of SSU Division 012 (Ln 15, Col (c) * 3.79%) 3.79% 32,715 19 Allocation of Division 030 (Ln 15, Col (d) * 42.51 %) 42.51% 11,758 20 Allocation of Division 031(Ln15, Col (e) * 100.00%) 100% 22,056 21 22 Thirteen Month Average Allocated to Colorado (Sum Lns 17 - 20) $ 870,914 23 24 12 Month Period Ending March 31, 2017: 25 Allocation of SSU Division 002 (Ln 13, Col (b) * 2.89%) 2.89% $ 920,323 26 Allocation of SSU Division 012 (Ln 13, Col (c) * 3.79%) 3.79% 71,215 27 Allocation of Division 030 (Ln 13, Col (d) * 42.51%) 42.51% 16,525 28 Allocation of Division 031 (Ln 13, Col ( e) * 100.00%) 100% (4,087) 29 30 March 31, 2017 Allocated to Colorado (Sum of Lns 25 - 28) $ 1,003,976 WP8-9 2 of2 .·.··:.,.· .. ·.· ..... ·.·.·:,-.'-'.. ·.. · .-·-,· ...... ·.·:_·.-.·.· Atmos Energy Corporation - Colorado Service Areas AFUDC Capital Interest Test Year Ended March 31, 2017 Line Colorado No. Description Date Service Area (a) (b) (c) 1 Capitalized Interest - Acct 432 04/30/16 $ (1,115) 2 Capitalized Interest - Acct 432 05/31/16 (1,977) 3 Capitalized Interest - Acct 432 06/30/16 (3,213) 4 Capitalized Interest - Acct 432 07/31/16 (4,570) 5 Capitalized Interest - Acct 432 08/31116 (5,292) 6 Capitalized Interest - Acct 432 09/30/16 (5,926) 7 Capitalized Interest - Acct 432 10/31/16 (6,092) 8 Capitalized Interest - Acct 432 11/30/16 1,669 9 Capitalized Interest - Acct 432 12/31/16 (667) 10 Capitalized Interest - Acct 432 01/31117 (643) 11 Capitalized Interest - Acct 432 02/28117 (902) 12 Capitalized Interest - Acct 4 32 03/31/17 (1,964) 13 Total Capitalized Interest (Sum ofLns I - 12) $ (30,693) 14 15 Application of State Tax Rate (Ln 13 * 4.63%) 4.63% $ (1,421) 16 17 Net Income before Federal Tax (Ln 13 - Ln 15) $ (29,272) 18 19 Application of Federal Tax Rate (Ln 17 * 35.00%) 35.00% $ (10,245) 20 21 Net AFUDC -Test Year (Ln 17 - Ln 19) $ (19,026) WP 8-10 I of 1 ,' .. ·,. Atmos Energy Corporation - Colorado Service Areas Cash-Basis Cash Working Capital Analysis Test Year Ended March 31, 2017 Adjusted Amounts ewe No. Description Colorado Amount CWC Factor Colorado Amount (a) (b) (c) (d) 1 Gas Purchased $ 58,722,779 (0.017003) $ (998,463) 2 3 O&M Ex12ense 4 LaborO&M 6,713,136 0.046093 309,429 5 OtherO&M 9,043,759 0.043216 390,835 6 7 Franchise Tax 2,665,080 (0.022619) (60,281) 8 Sales Tax 3,285,572 0.002751 9,039 9 State and Federal Income Tax 5,046,820 (0.002839) (14,328) 10 Other Taxes 2,463,874 (0.546537) (1,346,598) 11 12 Total (Sum of Lines 1 through 10) $ 87,941,021 $ (1, 710,369) WP 8-11 1of1 Atmos Energy Corporation - Colorado Service Areas Sales, Revenue Taxes and Franchise Fees Collected Test Year Ended March 31, 2017 Line No. Description Colorado Amount (a) (b) 1 Franchise Fee $ 2,665,080 2 Tax - City Sales 2,262,541 3 Tax - County Sales 442,276 4 Tax - State Sales 563,941 5 Tax - Transit Revenue tax 16,814 6 Total Taxes and Franchise Fees (Sum of Lines 1 through 5) $ 5,950,653 WP 8-11-1 1of1 .: .. ·. .. :...... · Atmos Energy Corporation - Colorado Service Areas Capital Structure and Cost of Capital For the Period Ended March 31, 2017 Line Overall Cost of No. Description Capital Ratio Average Cost Rate (1) Capital (a) (b) (c) (d) (e) I Atmos Energy Corp., Consolidated: 2 Long Term Debt Capital $ 3,064,620,157 44.42% 5.17% 2.30% 3 Equity Capital 3,834,864,598 55.58% 10.50% ------5.84% 4 5 6 Total Capital (Line 2 + 3) $ 6,899,484,755 100.00% 8.14% 7 8 Note: 1. The Long Term Debt Rate and Capital Structure have been adjusted by the following known and measurable transactions 9 which occurred on the trade date of June 5, 2017: 10 a. The $250 million Sr Note (See WP 9-2, Ln 11 for debt terms) was paid off by the Company. b. The Company added $250 million to the Note due in 2044 (See WP 9-2, Ln 15). The Company issued a $500 million Sr 11 Note due in 2027 (See WP 9-2, Ln 16 for debt terms). Schedule 9 1of1 Atmos Energy Corporation - Colorado Service Areas Schedule of Consolidated Long Term Debt and Equity For the Period Ended March 31, 2017 Atmos Consolidated Balances Line No. Month-Year Long-Term Debt Equity (a) (b) (c) 1 Mar-16 $ 2,455,559 ,278 $ 3,344,565,075 2 Apr-16 2,455,587,801 3,383,622,256 3 May-16 2,455,616,325 3,436,952,412 4 Jun-16 2,455,644,849 3,466,723,837 5 Jul-16 2,455,673,372 3,472,256,616 6 Aug-16 2,455,701,896 3,438,618,783 7 Sep-16 2,438,778,635 3,463,058,963 8 Oct-16 2,563,918,889 3,520,473,562 9 Nov-16 2,564,059,143 3,595,033,060 10 Dec-16 2,564,199,396 3,698,975,167 11 Jan-17 2,564,339,650 3,778,803,299 12 Feb-17 2,564,479 ,903 3, 790,503,944 13 Mar-17 3,064,620, 157 3,834,864,598 14 15 Period Ended March 31, 2017 $ 3,064,620,157 $ 3,834,864,598 16 17 13 Month Average $ 2,542,936,869 $ 3,555,727,044 WP 9-1 1of1 .. -·.--: _,:::·;·: .. :·:-·· .· .. -.-:· Atmos Energy Corporation Consolidated Long-Term Debt Outstanding w/ Calculation of Effective Interest Rates March 31, 2017 Atmos Energy Corp., Consolidated: Outstanding Outstanding Outstanding Outstanding Outstanding ~ Debt Series Issued ~1~1/2D16 4/30/2016 5/31/2016 6/3D/2D16 713112D16 (a) (b) (c) (d) (e) (f) (g) 9.40% First Mortgage Bond J due May 2021/RET 2005 04/01/91 $ - $ - $ - $ - $ 2 6.75% Debentures Unsecured due July 2028 07127/98 150,DOO, DOD 150,DOO,OOO 150,000, 000 15D,ODD,ODO 150,000,000 3 5.125% Senior Notes due Jan 2013 01113/03 4 10.43% First Mortgage Bond P due 2017 (eff2012) 11101/87 5 9.75% First Mortgage Bond Q due Apr 202DIRET 2005 04/01/90 6 9.32% First Mortgage Bond T due June 20211RET 2005 06/01/91 7 8. 77% First Mortgage Bond LI due May 20221RET 2005 D5/01/92 8 6.67% MTN A 1 due Dec 2025 12/15/95 10,000,000 1D,ODO,ODO 10,000,000 10,000,000 1D,DOD,OOO 9 4.95% Sr Nole due 10/15/2014 10/22104 10 5.95% Sr Note due 10/15/2034 10/22104 200,000,000 200,000,000 200,000,000 200,000,000 200,000,000 11 6.35% Sr Note due 6/15/2017 6/2007 250,DOO,OOD 250,000,000 250,000,000 25D,ODO,OOO 250,000,000 12 Sr Note 5.50% Due 06/15/2_041 6/1012D11 4DO,DOD,ODD 400,000,000 400,000,000 4D0,000,000 4DO,DOD,OOO 13 8.50% Sr Note due 3/15/2019 03/23/D9 450,000,000 450,00D,OOO 450,000,00D 450,000,000 450,000,000 14 4.15% Sr Note due 1/1512043 01115/13 500,000,000 500,000,000 50D,ODO,OOO 500,000,000 500,000,000 15 500,000,000 50D,ODO,DOO 500,000,000 500,000,00D SDO,DOD,000 16 17 March 2019 - Swap Position 0312D19 18 $200MM 3YR. Sr Credi! Facility (Established 9/22/16) 19 Subtotal -- Utility Long-Term Debt $ 2,460,000,000 $ 2,460,DOO,DOO $ 2,460,000,000 $ 2,460,000,00D $ 2,460,000,000 20 27 28 Effective Avg Cost of Consol Debt 29 Consolidated & Utility 30 31 Note: The initial March 2017 Consolidated Long-Term Debt report was adjusted by the highlighted 32 known and measurable transactions. WP9-2 1 of4 Atmos Energy Corporation Consolidated Long-Term Debt Outstanding w/ Calculation of Effective Interest Rates March 31, 2017 ·Atmos Energy Corp., .Consolidated: Outstanding Outstanding Outstanding Outstanding Outstanding Line No. Debt Series Issued 8/3112016 9/30/2016 10/31/2016 11/30/2016 12/31/2016 (a) (b) (h) (i) m (k) (l) 9.40% First Mortgage Bond J due May 2021/RET 2005 04/01/91 $ - $ - $ - $ - $ 2 6.75% Debentures Unsecured due July 2028 07/27/9B 150,000,000 150,000,000 150,000,000 150,000,000 150,000,000 3 5.125% Senior Notes due Jan 2013 01/13/03 4 10.43% First Mortgage Bond P due 2017 (eff 2012) 11/01/87 5 9.75% First Mortgage Bond Q due Apr 2020/RET 2005 04/01/90 6 9.32% First Mortgage Bond T due June 2021/RET 2005 06/01191 7 8.77% First Mortgage Bond U due May 2022/RET 2005 05/01192 8 6.67% MTN A 1 due Dec 2025 12/15195 10,000,000 10,000,000 10,000,000 10,000,000 10,000,000 9 4.95% Sr Note due 10/15/2014 10/22104 10 5.95% Sr Note due 10/15/2034 10/22104 200,000,000 200,000,000 200,000,000 200,000,000 200,000,000 11 6.35% Sr Note due 6/15/2017 612007 250,000,000 250,000,000 250,000,000 250,000,000 250,000,000 12 Sr Note 5.50% Due 06/15/2041 6/10/2011 400,000,000 400,000,000 400,000,000 400,000,000 400,000,000 13 8.50% Sr Note due 3/15/2019 03/23/09 450,000,000 450,000,000 450,000,000 450,000,000 450,000,000 14 4.15% Sr Note due 1/15/2043 01/15/13 500,000,000 500,000,000 500,000,000 500,000,000 500,000,000 15 500,000,000 500,000,000 500,000,000 500,000,000 500,000,000 16 ,..:.· 17 March 2019 - Swap Position 03/2019 18 $200MM 3YR. Sr Credit Facility (Established 9/22116) 125,000,000 125,000,000 125,000, 000 19 Subtotal -- Utility Long-Term Debt $ 2,460,000,000 $ 2,460,000,000 $ 2,585,000,000 $ 2,585,000,000 $ 2,585,000,000 20 21 Atmos Leasing, Inc. 22 Industrial Develop Revenue Bond 07/13 1991 $ $ $ $ $ 23 Total Long-Term Debt $ 2,460,000,000 $ 2,460,000,000 $ 2,585,000,000 $ 2,585,000,000 $ 2,585,000,000 24 ~tiR~l~~I!11m~~r~1r~~~a~,9[~,sK~n!r~1~~~1!etllimm}llW~~~11~w;mr,~1 $ 4,298,104 $ 4,269,581 $ 4,241,057 $ 4,212,533 $ 4,184,010 25 Less Unamortized Debt Expense $ 16,951,784 $ 16,840,054 $ 16,728,324 $ 16,616,594 26 t~mB:~1~£~1~me1~1i~7rt1~~1~l~£~,~1\§~~1~1nim1~~m~1~1~~ft~!~e:t11.,18:~~xJ;1~m1~ni¥~!!Jl~lli11:~~ 27 Net Debt $ 2,438,778,635 $ 2,563, 918,889 $ 2,564,059, 143 $ 2,564, 199,396 28 Effective Avg Cost of Consol Debt Gross Minus Disc & Exp 29 Consolidated & Utility 30 31 Note: The initial March 2017 Consolidated Long-Term Debt report was adjusted by the highlighted 32 known and measurable transactions. VIP 9-2 2 of4 Atmos Energy Corporation Consolidated Long-Term Debt Outstanding w/ Calculation of Effective Interest Rates March 31, 2017 Atmos Energy Corp., Consolidated: Outstanding Outstanding Outstanding End Annual Int at Debt Series Issued 1/31/2017 2/28/2017 3/31/2017 ln!Rate March 31, 2017 (a) (b) (m) (n) (o) (p) (q) 9.40% First Mortgage Bond J due May 2021/RET 2005 04/01/91 $ - $ - $ 9.40% $ 2 6. 75% Debentures Unsecured due July 2028 07/27/98 150,000,000 150,000,000 150,000,000 6.75% 10, 125,000 3 5.125% Senior Notes due Jan 2013 01/13/03 5.13% 0 4 10.43% First Mortgage Bond P due 2017 (eff 2012) 11/01187 10.43% 0 5 9.75% First Mortgage Bond Q due Apr 2020/RET 2005 04101/90 9.75% 0 6 9.32% First Mortgage Bond T due June 2021/RET 2005 06/01191 9.32% 0 7 8. 77% First Mortgage Bond U due May 2022/RET 2005 05101/92 8.77% 0 8 6.67% MTN A1 due Dec 2025 12/15/95 10,000,000 10,000,000 10,000,000 6.67% 667,000 9 4.95% Sr Note due 10115/2014 10122/04 4.95% 0 1 O 5.95% Sr Note due 10/15/2034 10/22/04 200,000,000 200,000,000 5.95% 11,900,000 11 6.35% Sr Note due 6/15/2017 6/2007 250,000,000 250,000,000 6.35% 0 12 Sr Note 5.50% Due 06115/2041 6110/2011 400,000,000 400,000,000 5.50% 22,000,000 13 8.50% Sr Note due 3/15/2019 03/23/09 450,000,000 450,000,000 8.50% 38,250,000 14 4.15% Sr Note due 1/15/2043 01/15/13 500,000,000 500,000,000 4.15% 20,750,000 15 500,000,000 500,000,000 30,937,500 16 15,000,000 17 March 2019 - Swap Position 03/2019 0 18 $200MM 3YR. Sr Credit Facility (Established 9/22116) 125, 000, 000 125,000,000 125,000,000 1.95% ____2~,4_3~7,_50_0_ 19 Subtotal -- Utility Long-Term Debt $ 2,585,000,000 $ 2,585,ooo,ooo $ 3,085,ooo,ooo _$~_1_52~,0_6_7~,o_oo_ 20 21 Atmos Leasing, Inc. 22 Industrial Develop Revenue Bond 07/13 1991 $ $ $ 7.90% $ 23 Total Long-Term Debt ....,.------~---,-.,.------$ 2,585,000,000 $ 2,585,000,000 $ 3,085, 000,000 $ 152, 067' 000 24 ~~:'~[§~llilla~ffi:gm;'~~i~~m~~rtw91J~!E~~,~t1gf[~iBmn?i~liiliwrrtIB\~l12i&i! =$======4,155,486 ..... $ ======4, 126,963 25 Less Unamortized Debt Expense $ 16,504,864 $ 16,393,134 $ 26 [~\1W!m!l~i~:til%%1gftl~tl'.e!eli~!!§fn!ii~2jJ,:fi~~~[~*p~1~i~~~fi1Rl~BWf~lfJ~§n~Iimifu~tl\~r1~~tiJ;;'))}~'-·------6,343,346 2,564,339,650 $ 2,564,479,903 $ 3,066,350,522 $ 158,410,346 27 28 Effective Avg Cost of Consol Debt =$====:;,;~======;,;;o;;=====-----======~==5.17% End of Period 29 Consolidated & Utility = 5.17% End of Period 30 31 Note: The initial March 2017 Consolidated Long-Term Debt report was adjusted by the highlighted 32 known and measurable transactions. WP9-2 3 of4 .. ·.':... -.. ,.·.· Atmos Energy Corporation Consolidated Long-Term Debt Outstanding w/ Calculation of Effective Interest Rates March 31, 2017 Unamort Debt Exp 2241, 1650 Annualized Annualized Penalty 1890 Atmos Energy Corp., Consolidated: Outstanding Avg Annual Int 4270Amort 4280-81 Amert Dsct 2260 Debt Series Issued 13 mth Average Int Rate 13 m!h Average for T-lock/SwaQs Debt ExQ&Dsct March 31, 2017 (a) (b) (r) (s) (t) (u) (v) (w) (x) (y) 9.40% First Mortgage Bond J due May 2021/RET 2005 04/01/91 $ 9.40% $ $ - $ 560,397 $ 2,288,290 2 6. 75% Debentures Unsecured due July 2028 07/27/98 150,000,000 6.75% 10,125,000 0 99,938 1,128,946 3 5.125% Senior Notes due Jan 2013 01/13/03 5.13% 0 0 0 4 10.43% First Mortgage Bond P due 2017 (eff2012) 11/01187 10.43% 0 33,837 19,738 5 9. 75% First Mortgage Bond Q due Apr 2020/RET 2005 04/01/90 9.75% 0 337,581 1,040,874 6 9.32% First Mortgage Bond T due June 2021/RET 2005 06/01191 9.32% 0 362,746 1,511,443 7 8.77% First Mortgage Bond U due May 2022/RET 2005 05/01/92 8.77% 0 368,719 1,874,322 8 6.67% MTN A 1 due Dec 2025 12/15195 10,000,000 6.67% 667,000 0 7,777 67,724 9 4.95% Sr Note due 10/15/2014 10/22104 4.95% 0 0 (0) 10 5.95% Sr Note due 10/15/2034 10122104 200,000,000 5.95% 11,900,000 2,031,429 11 6.35% Sr Note due 6115/2017 6/2007 230,769,231 6.35% 14,653,846 76,760 12 Sr Note 5.50% Due 06/15/2041 6/10/2011 400,000,000 5.50% 22,000,000 (669,302) 186,860 4,515,774 13 8.50% Sr Note due 3/15/2019 03123/09 450,000,000 8.50% 38,250,000 (77,734) 1,161,169 2,322,339 14 4.15% Sr Note due 1/15/2043 01115/13 500,000,000 4.15% 20,750,000 2,220,857 378,080 9,750,013 15 ·:~:ii1" 519,230, 769 4.125% 21,418,269 924, 726 (40,355) (1, 123,399) 16 ;~~L_,. 38,461,538 tl0;W9l~~I 1,153,846 o ;,2ii1i.i;s@111m~rn~§§t~I~]~~j1;1ffii1iB1i:rnlfg1§;'~§§i.~!i9:· 17 March 2019 - Swap Position 0312019 0 0 0 18 $200MM 3YR. Sr Credit Facility (Established 9/22116) 57,692,308 1.70% 980, 192 0 115,667 266,275 19 Subtotal-- Utility Long-Term Debt $ 2,556,153,846 $ 141,898,154 $ 2,312,337 $ 4,031,009 $ 31,136,517 20 21 Atmos Leasing, Inc. 22 Industrial Develop Revenue Bond 07113 1991 $ 7.90% $ $ $ $ 23 Total Long-Term Debt $ 2,556,153,846 $ 141,898,154 24 \".!1%R~§~iiWn~fill~,~~~1i~m1§i~ER~;~f2~1\§~~j~fiITT1~mfil~~@fil[@r@ll~~llil $ 3,625,385 $ 2,312,337 $ 4,031,009 $ 31,136,517 25 Less Unamortized Debt Expense $ 17,565,762 26 [~22Hiff~~1:~l2[.~1~,m~:l~i~~~!~'X[~[~i~fil~f~?ll~l~~i~!tj!~~~~ilR:~~~[[~m18;,i11tfi~(ITfl~{f~,~ $ 6,343,346 27 $ 2,534,962,699 $ 148,241,500 28 Effective Avg Cost of Consol Debt 5.85% 13 Month Average 29 Consolidated & Utility 5.85% 13 Month Average 30 31 Note: The initial March 2017 Consolidated Long-Term Debt report ms adjusted by the highlighted 32 known and measurable transactions. WP9-2 4 of4 0 )> :!! 0 ~ 1;; r- :::c c!oen ::E c ;:ti -< 2S -z -~G) Schedule CWCI Atmos Energy Corporation ~ Colorado Service Area Cash-Basis Cash Working Capital Analysis Test Year Ending March 31, 2017 Cash Line ewe Working No. Description Amount Factor Capital (a) (b) (c) (d) 1 Gas Purchased $ 58,722,779 (0.017003) $ (998,463) 2 3 O&M Expense: 4 LaborO&M 6,713,136 0.046093 309,429 5 OtherO&M 9,043,759 0.043216 390,835 6 7 Franchise Tax 2,665,080 (0.022619) (60,281) 8 Sales Ta.X 3,285,572 0.002751 9,039 9 10 State and Federal Income Tax 5,046,820 (0.002839) (14,328) 11 Other Taxes 2,463,874 (0.546537) (1,346,598) 12 13 Total $ 87,941,021 $ (1,710,369) Page I of 1 ·.·,·. ·. -· Atmos Energy Corporation - Colorado Service Area CWCWP 1-1 Payroll Test Year Ending March 31, 2017 Div02 Div12 030DIV 031DIV Line Colorado Atmos SSU Atmos SSU CO/KS Div Colorado Total No. DescriEtion Service Area General Office Cust SuEEOrt Gen Office Admin Colorado (a) (b) (c) (d) (e) (f) (g) 12 Mo Ended 3/31/2017 (Note 1) $ 2,808,234 $ 48,074,034 $ 29,304,244 $ 1,338,407 $ 546,778 2 3 Allocation Factor 100% 2.89% 3.79% 42.51% 100% 4 5 Allocated Labor 2,808,234 1,389,584 1,110,535 568,923 546,778 6,424,053 6 7 8 Labor Adjustment 289,082 9 10 Total Adjusted Labor $ 6,713,136 11 12 13 Note 1: SOURCE: COS Schedule 4, WP 4-2 Page 1of1 Schedule ewe2 Atmos Energy Corporation - Colorado Service Area Computation of CWC Factors Test Year Ending March 31, 2017 Line Revenue Expense Net ewe No. Description Lag Lag Lag Factor (a) (b) (c) (d) (e) 1 Gas Purchased 36.21 42.42 (6.21) (0.017003) 2 3 O&M Expense: 4 LaborO&M 36.21 19.39 16.82 0.046093 5 OtherO&M 36.21 20.44 15.77 0.043216 6 7 Franchise Tax 36.21 44.47 (8.26) (0.022619) 8 Sales Tax 36.21 35.21 1.00 0.002751 9 10 State and Federal Income Tax 36.21 37.25 (1.04) (0.002839) 11 Other Taxes 36.21 235.70 (199.49) (0.546537) Page 1of1 Schedule CWC3 Atmos Energy Corporation - Colorado Service Area Revenue Lag Study Test Year Ending March 31, 2017 Line No. Description Lag (a) (b) 1 Service Lag = 365 days I 12 months I 2 = 15.21 2 3 Billing Lag [1] = 1.24 4 5 Collection Lag = Test Yr Average Daily Accounts 18.76 6 Receivable I Test Yr Average Daily Revenue: 7 8 Bank Lag= 1.00 9 10 Total Lag= 36.21 Note [1] See relied file: Billing Lag Transactions.xlsx Page 1of1 Atmos Energy Corporation - Colorado Service Area CWCWP3-l Collection Lag Analysis Colorado-Kansas Daily Accounts Receivable Balances 12 Mo.Ended 12Mo. Ended 12 Mo.Ended Line No. 3131/15 Daily AIR 3131116 Daily AIR 3131/17 Daily AIR (a) (b) (o) (d) (e) (f) l Tuesday, April 01, 2014 $ 8,382,459 Wednesday, April 01, 2015 $ 10,854,562 Friday, April 01, 2016 $ 4,709,930 2 Wednesday, April 02, 2014 8,250,567 Thursday, April 02, 2015 10,346,887 Saturday, April 02, 2016 4,556,289 3 Thursday, April 03, 2014 8,654,378 Friday, April 03, 2015 9,839,213 Sunday, April 03, 2016 4,163,647 4 Friday, April 04, 2014 9,056,478 Saturday. April 04, 2015 9,331,538 Monday, April 04, 2016 4,382,267 5 Saturday, April 05, 2014 9,056,478 Sunday, April 05, 2015 8,823,864 Tuesday, April 05, 2016 4,741,535 6 Sunday, April 06, 2014 9,056,478 Monday, April 06, 2015 8,316,189 Wednesday, April 06, 2016 5,039,546 7 Monday, April 07, 2014 8,584,348 Tuesday, April 07, 2015 8,602,316 Thursday, April 07, 2016 5,329,070 8 Tuesday, April 08, 2014 8,791,396 Wednesday, April 08, 2015 8,898,168 Friday, April 08, 2016 5,329,070 9 Wednesday, April 09, 2014 8,927,496 Thursday, April 09, 2015 9,034,913 Saturday, April 09, 2016 5,239,517 10 Thursday, April 10, 2014 9,244,003 Friday, April 10, 2015 8,932,500 Sunday, April IO, 2016 4,967,770 II Friday, April ll, 2014 9,720,535 Saturday, April 11, 2015 8,932,500 Monday, April IL, 2016 5,095,694 12 Saturday, April 12, 2014 9,720,535 Sunday, April 12, 2015 8,932,500 Tuesday, April 12, 2016 5,525,102 13 Sunday, April 13, 2014 9,720,535 Monday, April 13, 2015 8,302,829 Wednesday, April 13, 2016 5,661,476 14 Monday, April 14, 2014 9,237,000 Tuesday, April 14, 2015 8,517,624 Thursday, April 14, 2016 5,970,042 15 Tuesday, April 15, 2014 9,439,200 Wednesday, April 15, 2015 8,563,541 Friday, April 15, 2016 5,970,042 16 Wednesday, April 16, 2014 9,986,534 Thursday, April 16, 2015 8,844,599 Saturday, April 16, 2016 5,818,334 17 Thursday, April 17, 2014 10,107,753 Friday, April 17, 2015 9,336,160 Sunday, April 17, 2016 6,377,885 18 Friday, April 18, 2014 10,107,753 Saturday, April 18, 2015 9,336,160 Monday, April 18, 2016 6,245,881 19 Saturday, April 19, 2014 10,107,753 Sunday, April 19, 2015 9,336,160 Tuesday, April 19, 2016 6,225,375 20 Sunday, April 20, 2014 10,107,753 Monday, April 20, 2015 8,877,859 Wednesday, April 20, 2016 6,348,752 21 Monday, April 21, 2014 9,144,733 Tuesday, April 21, 2015 9,031,457 Thursday, April 21, 2016 6,422,415 22 Tuesday, April 22, 2014 9,048,147 Wednesday, April 22, 2015 8,997,453 Friday, April 22, 2016 6,422,415 23 Wednesday, April 23, 2014 9,073,788 Thursday, April 23, 2015 9,006,375 Saturday, April 23, 2016 6,243,614 24 Thursday, April 24, 2014 9,271,915 Friday, April 24, 2015 9,302,997 Sunday, April 24, 2016 6,083,882 25 Friday, April 25, 2014 9,133,590 Saturday, April 25, 2015 9,302,997 Monday, April 25, 2016 5,848,814 26 Saturday, April 26, 2014 9,133,590 Sunday, April 26, 2015 9,302,997 Tuesday, April 26, 2016 5,531,134 27 Sunday, April 27, 2014 9,133,590 Monday, April 27, 2015 8,386,679 Wednesday, April 27, 2016 5,258,132 28 Monday, April 28, 2014 8,122,578 Tuesday, April 28, 2015 8,053,438 Thursday, April 28, 2016 5,038,782 29 Tuesday, April 29, 2014 7,675,983 Wednesday, April 29, 2015 7,103,325 Friday, April 29, 2016 4,945,524 30 Wednesday, April 30, 2014 7,214,511 Thursday, April 30, 2015 6,850,143 Saturday, April 30, 2016 4,852,267 31 Thursday, May 01, 2014 7,251,951 Friday, May 01, 2015 6,850,143 Sunday, May 01, 2016 4,759,009 32 Friday, May 02, 2014 7,289,391 Saturday, May 02, 2015 6,850,143 Monday, May 02, 2016 4,533,456 33 Saturday, May 03, 2014 7,289,391 Sunday, May 03, 2015 7,071,535 Tuesday, May 03, 2016 4,524,523 34 Sunday, May 04, 2014 7,289,391 Monday, May 04, 2015 6,294,768 Wednesday, May 04, 2016 4,785,070 35 Monday, May 05, 2014 6,926,868 Tuesday, May 05, 2015 6,217,801 Thursday, May 05, 2016 4,823,654 36 Tuesday, May 06, 2014 7,074,299 Wednesday, May 06, 2015 6,445,547 Friday, May 06, 2016 4,823,654 37 Wednesday, May 07, 2014 7,267,372 Thursday, May 07, 2015 6,964,718 Saturday, May 07, 2016 4,672,532 38 Thursday, May 08, 2014 7,460,446 Friday, May 08, 2015 7,020,799 Sunday, May 08, 2016 4,563,814 39 Friday, May 09, 2014 7,458,177 Saturday, May 09, 2015 7,020,799 Monday, May 09, 2016 4,394,382 40 Saturday, May 10, 2014 7,458,177 Sunday, May 10, 2015 7,020,799 Tuesday, May 10, 2016 4,394,540 41 Sunday, May 11, 2014 7,458,177 Monday, May 11, 2015 6,475,146 Wednesday, May 11, 2016 4,604,650 42 Monday, May 12, 2014 7,058,278 Tuesday, May 12, 2015 6,667,006 Thursday, May 12, 2016 4,647,027 43 Tuesday, May 13, 2014 7,258,774 Wednesday, May 13, 2015 6,740,685 Friday, May 13, 2016 4,647,027 44 Wednesday, May 14, 2014 7,649,694 Thursday, May 14, 2015 6,862,695 Saturday, May 14, 2016 4,532,784 45 Thursday, May 15, 2014 7,948,056 Friday, May 15, 2015 7,270,375 Sunday, May 15, 2016 4,561,881 46 Friday, May 16, 2014 8,238,430 Saturday, May 16, 2015 7,270,375 Monday, May 16, 2016 4,798,587 47 Saturday, May 17, 2014 8,238,430 Sunday, May 17, 2015 7,270,375 Tuesday, May 17, 2016 4,729,434 48 Sunday, May 18, 2014 8,238,430 Monday, May 18, 2015 6,907,743 Wednesday, May 18, 2016 5,022,474 49 Monday, May 19, 2014 7,787,948 Tuesday, May 19, 2015 6,927,620 Thursday, May 19, 2016 5,074,436 50 Tuesday, May 20, 2014 7,762,816 Wednesday, May 20, 2015 6,875,341 Friday, May 20, 2016 5,074,436 51 Wednesday, May 21, 2014 7,761,205 Thursday, May 21, 2015 6,872,919 Saturday, May 21, 2016 4,935,233 52 Thursday, May 22, 2014 7,806,569 Friday, May 22, 2015 6,962,512 Sunday, May 22, 2016 4,742,308 53 Friday, May 23, 2014 7,961,974 Saturday, May 23, 2015 6,962,512 Monday, May 23, 2016 4,732,261 54 Saturday, May 24, 2014 7,961,974 Sunday, May 24, 2015 6,962,512 Tuesday, May 24, 2016 4,568,875 Page I of7 Atmos Energy Corporation - Colorado Service Area CWCWP3-1 Collection Lag Analysis Colorado-Kansas Daily Accounts Receivable Balances 12 Mo.Ended 12Mo.Ended 12Mo.Ended Line No. 3/31/15 DailxAIR 3/31/16 Daili::AIR 3/31/17 Daily AIR (a) (b) (c) (d) (e) (f) 55 Sunday, May 25. 2014 7,961,974 Monday, May 25, 2015 6,962,512 Wednesday. May 25, 2016 4.555,279 56 Monday, May 26, 2014 7,961,974 Tuesday, May 26, 2015 6,197,162 Thursday, May 26, 2016 4,362,322 57 Tuesday, May 27, 2014 6,444,916 Wednesday, May 27, 2015 5,791,069 Friday, May 27, 2016 4,362,322 58 Wednesday, May 28. 2014 6,241,376 Thursday, May 28, 2015 5,872,904 Saturday, May 28, 2016 4,362,322 59 Thursday, May 29. 20 I 4 6,042,704 Friday, May 29, 2015 5,533,671 Sunday, May 29, 2016 4,207,534 60 Friday, May 30, 2014 6,013,820 Saturday, May 30, 2015 5,533,671 Monday, May 30, 2016 3,587,665 61 Saturday, May 31, 2014 6,013,820 Sunday, May 31, 2015 5,441,985 Tuesday, May 31. 2016 3,496,617 62 Sunday, June 01, 2014 6,013,820 Monday, June 01, 2015 5,441,985 Wednesday, June 01, 2016 3,429,679 63 Monday, June 02, 2014 5,457,510 Tuesday, June 02, 2015 5,269,963 Thursday, June 02, 2016 3,623,670 64 Tuesday, June 03, 2014 5,248,912 Wednesday, June 03, 2015 5,221,026 Friday, June 03, 2016 3,623,670 65 Wednesday, June 04, 2014 5,359,909 Thursday, June 04, 2015 5,497,103 Saturday, June 04, 2016 3,552,661 66 Thursday, June 05, 2014 5,549,166 Friday, June 05, 2015 5,602,623 Sunday, June 05, 2016 3,415.310 67 Friday, June 06, 2014 5,698,950 Saturday, June 06, 2015 5,602,623 Monday, June 06, 2016 3,405,531 68 Saturday, June 07, 2014 5,698,950 Sunday, June 07, 2015 5,602,623 Tuesday, June 07, 2016 3,425,645 69 Sunday, June 08, 2014 5,698,950 Monday, June 08, 2015 5,459,574 Wednesday, June 08, 2016 3,334,989 70 Monday, June 09, 2014 5,348,826 Tuesday, June 09, 2015 5,247,674 Thursday, June 09, 2016 3,401,939 71 Tuesday, June IO, 2014 5,258,737 Wednesday, June IO, 2015 5,291,536 Friday, June 10, 2016 3,401,939 72 Wednesday, June ll, 2014 5,311,154 Thursday, June 11, 2015 5,420.220 Saturday, June 11, 2016 3,307,375 73 Thursday, June 12, 2014 5,418,324 Friday, June 12. 2015 5,540,222 Sunday, June 12, 2016 3,ll9,260 74 Friday, June 13, 2014 5,478,617 Saturday, June 13, 2015 5,540,222 Monday, June 13, 2016 3,365,549 75 Saturday, June 14, 2014 5,478,617 Sunday, June 14, 2015 5,540,222 Tuesday, June 14, 2016 3,426,398 76 Sunday, June 15, 2014 5,478,617 Monday. June 15, 2015 5,268,473 Wednesday, June 15, 2016 3,494,157 77 Monday, June 16, 2014 5,469,430 Tuesday, June 16, 2015 5,343,739 Thursday, June 16, 2016 3,499,119 78 Tuesday, June 17, 2014 5,571,176 Wednesday, June 17, 2015 5,363,731 Friday, June 17,2016 3,499,119 79 WednesdaY, June 18, 2014 5,538,660 Thursday, June 18, 2015 5,542,330 Saturday, Jnoe 18, 2016 3,433,578 80 Thursday, June 19, 2014 5,492,351 Friday, June 19, 2015 5,582,951 Sunday, June 19, 2016 3,265,997 81 Friday, June 20, 2014 5,501,291 Saturday, June 20, 2015 5,582,951 Monday, Jnoe 20, 2016 3,241,351 82 Saturday. June 21, 2014 5,501,291 Sunday, June 21, 2015 5,582,951 Tuesday, June 21. 2016 3,176,411 83 Sunday, June 22, 2014 5,501,291 Monday, June 22, 2015 5,010,362 Wednesday, June 22, 2016 3,166,340 84 Monday, June 23. 2014 5,060,922 Tuesday, June 23, 2015 5,004,972 Thursday, June 23, 2016 3,109,350 85 Tuesday, June 24, 2014 4,971,155 Wednesday, June 24, 2015 4,909,629 Friday, June 24, 2016 3,109,350 86 Wednesday, June 25, 2014 4,885,450 Thursday, June 25, 2015 4,829,873 Saturday, June 25, 2016 3,034,555 87 Thursday, June 26, 2014 4,765,492 Friday, June 26, 2015 4,614,609 Sunday, June 26, 2016 2,651,634 88 Friday, June 27, 2014 4,701,250 Saturday, June 27, 2015 4,614,609 Mond3Y, June 27, 20!6 2,492,676 89 Saturday, June 28, 2014 4,701,250 Sunday, June 28. 2015 4.614,609 Tuesday, June 28, 2016 2,311,864 90 Sunday, June 29, 2014 4,701,250 Monday, Juno 29, 2015 4,007,788 Wednesday, June 29, 2016 2,162,135 91 Monday, June 30, 2014 4,172,759 Tuesday, June 30, 2015 3,796,603 Thursday, June 30, 2016 2,048,903 92 Tuesday, July 01, 2014 3,987,540 Wednesday, July 01, 2015 3,588,820 Friday, July 01, 2016 2,048,903 93 Wednesday, July 02, 2014 3,884,997 Thursday, July 02, 2015 3,527,534 Saturday, July 02, 2016 2,048,903 94 Thursd3Y. July 03, 2014 3,994,958 Friday, July 03, 2015 3,527,534 Sunday, July 03, 2016 I,965,964 95 Friday, July 04, 2014 3.994,958 Saturday, July 04, 2015 3,527,534 Monday, July 04, 2016 1,657,230 96 Saturday, July 05, 2014 3,994,958 Sunday, July 05, 2015 3,296,096 Tuesday, July 05, 2016 1,631,181 97 Sunday, July 06, 2014 3,994,958 Monday, July 06, 2015 2,973,083 Wednesday, July 06, 2016 I,663,980 98 Monday, July 07, 2014 3,621,743 Tuesday, July 07, 2015 3,117,872 Thursday, July 07, 2016 l,906,229 99 Tuesday, July 08, 2014 3,597,223 Wednesday, July 08, 2015 3,232,152 Friday, July 08, 2016 l,906,229 100 Wednesday, July 09, 2014 3,683,135 Thursday, July 09, 2015 3,132,582 Saturday, July 09, 2016 1,865,143 101 Thursday, July 10, 2014 3,683,135 Friday, July 10, 2015 3,099,113 Sunday, July 10, 2016 1,778,811 102 Friday. July 11. 2014 3,797,040 Saturday, July I 1, 2015 3,065,645 Monday, July 11,2016 1,720,139 103 Saturday, July 12, 2014 3,797,040 Sunday, July 12, 2015 2,925,111 Tuesday, July 12, 2016 1,785,393 104 Sunday, July 13, 2014 3,797,040 Monday, July 13, 2015 3,020,057 Wednesday, July 13, 2016 1,828.025 !05 Monday, July 14. 2014 3,777,833 Tuesday, July 14, 2015 3,070,959 Thursday, July 14, 2016 2,144,715 106 Tuesday, July 15, 2014 3,807,017 Wednesday, July 15, 2015 3,091,964 FridaY, July 15, 2016 2,144,715 107 Wednesday, July 16, 2014 3,891,934 Thursday, July 16, 2015 3,438.781 Saturday, July 16, 2016 2,100,879 !08 Thursday, July 17, 2014 3,891,934 Friday, July 17, 2015 3,399,890 Sunday, July 17, 2016 2,142,179 Page 2 of7 Atmos Energy Corporation - Colorado Service Area CWC\VP3-l Collection Lag Analysis Colorado-Kansas Daily Accounts Receivable Balances l2Mo.Ended 12 Mo. Ended 12Mo. Ended Line No. 3/31/15 DailxAIR 3/31/16 DailxAJR 3/31/17 Daily AIR (a) (b) (c) (d) (e) (t) 109 Friday, July 18, 2014 4,089,494 Saturday, July 18, 2015 3,360,999 Monday, July 18, 2016 2,215,288 110 Saturday, July 19, 2014 4,089,494 Sunday, July 19, 2015 3,322,108 Tuesday, July 19, 2016 2,217,863 lll Sunday, July20, 2014 4,089,494 Monday, July 20, 2015 3,333,567 Wednesday, July 20, 2016 2,291,816 112 Monday, July 21, 2014 4,089,494 Tuesday, July 21, 2015 3,381,767 Thursday, July 21, 2016 2,284,413 113 Tuesday, July 22, 2014 3,744,103 Wednesday, July 22, 2015 3,446,125 Friday, July 22, 2016 2,259,108 114 Wednesday, July 23, 2014 3,726,112 Thursday, July 23, 2015 3,500,550 Saturday, July 23, 2016 2,233,803 115 Thursday, July 24, 2014 3,745,872 Friday, July 24, 2015 3,458.193 Sunday, July 24, 2016 2,207,458 116 Friday, July 25, 2014 3,732,749 Saturday, July 25, 2015 3,415,836 Monday, July 25, 2016 2,091,277 117 Saturday. July 26, 2014 3,732,749 Sunday, July 26, 2015 3,070,479 Tuesday, July 26, 2016 1,957,609 118 Sunday, July 27, 2014 3,732,749 Monday, July 27, 2015 2,979,889 Wednesday, July 27, 2016 1,847,315 119 Monday, July 28, 2014 3,230,108 Tuesday, July 28, 2015 2,870,015 Thursday, July 28, 2016 1,758,671 120 Tuesday, July 29, 2014 3,064,357 Wednesday, July 29, 2015 2,728,866 Friday, July 29, 2016 1,758,671 121 Wednesday, July 30, 2014 2,885,310 Thursday, July 30, 2015 2,645,191 Saturday, July 30, 2016 1,695,029 122 Thursday, July 31, 2014 2,790,473 Friday, July 31, 2015 2,561,516 Sunday, July 31, 2016 l,481,979 123 Friday, August 01, 2014 2,711,110 Saturday, August 01, 2015 2,477,840 Monday, August 01, 2016 1,373,772 124 Saturday, August 02, 2014 2,711,110 Sunday, August 02, 2015 2,319,618 Tuesday, August 02, 2016 1,330,239 125 Sunday, August 03, 2014 2,711,llO Mollday, August 03, 2015 2,129,219 Wednesday, August 03, 2016 l,408,027 126 Monday, August 04, 2014 2,338,616 Tuesday, August 04, 2015 1,987,317 Thursday, August 04, 2016 1,421,944 127 Tuesday, August 05, 2014 2,374,667 Wednesday, August 05, 2015 2,157,518 Friday, August 05, 2016 1,421,944 128 Wednesday, August 06, 2014 2,393,950 Thursday, August 06, 2015 2,267,663 Saturday, August 06, 2016 1,379,576 129 Thursday, August 07, 2014 2,393,950 Friday, August 07, 2015 2,267,663 Sunday, August07, 2016 1,251,206 130 Friday, August 08, 2014 2,621,240 Saturday, August 08, 2015 2,180,099 Monday, August 08, 2016 1,223,859 131 Saturday, August 09, 2014 2,621,240 Sunday, August 09, 2015 2,137,021 Tuesday, August 09, 2016 1,191,120 132 Sunday, August 10, 2014 2,621,240 Monday, August 10, 2015 2,092,612 Wednesday, August 10, 2016 1,302,897 133 Monday, August 11, 2014 2,441,841 Tuesday, August 11, 2015 2,123,000 Thursday, August 11, 2016 1,389,785 134 Tuesday, August 12, 2014 2,397,187 Wednesday, August 12, 2015 2,356,130 Friday, August 12, 2016 1,389,785 135 Wednesday, August 13, 2014 2,541,198 Thursday, August 13, 2015 2,384,029 Saturday, August 13, 2016 1,326,055 136 Thursday, August 14, 2014 2,629,255 Friday, August 14, 2015 2,345,747 Sunday, August 14, 2016 1,299,269 137 Friday, August 15, 2014 2,780,699 Saturday, August 15, 2015 2,307,464 Monday, August 15, 2016 1,639,530 138 Saturday, August 16, 2014 2,780,699 Sunday, August 16, 2015 2,288,573 Tuesday, August 16, 2016 1,633,573 139 Sunday, August 17, 2014 2,780,699 Monday, August 17, 2015 2,437,087 Wednesday, August 17,2016 1,729,610 140 Monday, August 18, 2014 2,743,223 Tuesday, August 18, 2015 2,635,639 Thursday, August 18, 2016 1,736,998 141 Tuesday, August 19, 2014 2,759,840 Wednesday, August 19, 2015 2,741,018 Friday, August 19, 2016 1,736,998 142 Wednesday, August 20, 2014 3,177,492 Thursday, August20,2015 2,746,065 Saturday, August 20, 2016 1,684,294 143 Thursday, August21, 2014 3,245,416 Friday, August 21, 2015 2,718,306 Sunday, August2l, 2016 1,582,820 144 Friday, August 22, 2014 3,245,779 Saturday, August 22, 2015 2,690,548 Monday, August 22, 2016 1,659,957 145 Saturday, August23, 2014 3,245,779 Sunday, August 23, 2015 2,481,873 Tuesday, August 23, 2016 1,590,067 146 Sunday, August 24, 2014 3,245,779 Monday, August 24, 2015 2,534,236 Wednesday, August 24, 2016 1,515,412 147 Monday, August 25, 2014 3,016,507 Tuesday, August25, 2015 2,512,976 Thursday, August 25, 2016 1,411,265 148 Tuesday, August 26, 2014 2,855,530 Wednesday, August 26, 2015 2,501,859 Friday, August 26, 2016 l,4ll,265 149 Wednesday, August 27, 2014 2,737,248 Thtirsday, August 27, 2015 2,389,060 Saturday, August 27, 2016 1,360,178 150 Thursday, August28, 2014 2,638,729 Friday, August 28, 2015 2,319,427 Sullday, August28, 2016 1,089,718 151 Friday, August 29, 2014 2,537,500 Saturday, August 29, 2015 2,249,794 Monday, August29, 2016 925,663 152 Saturday, August 30, 2014 2,537,500 Sunday, August 30, 2015 1,996,086 Tuesday, August 30, 2016 771,286 153 Sunday, August31, 2014 2,485,052 Monday, August 31, 2015 1,742,379 Wednesday, August 31, 2016 826,277 154 Monday, September 01, 2014 2,485,052 Tuesday, September 01, 2015 1,754,078 Thursday, September 01, 2016 881,269 155 Tuesday, September 02, 2014 2,121,895 Wednesday, September 02, 2015 1,819,436 Friday, September 02, 2016 881,269 156 Wednesday, September 03, 2014 1,882,482 Thursday, September 03, 2015 1,860,692 Saturday, September03, 2016 881,269 157 Thursday, s.,ptember 04, 2014 1,974,805 Friday, September 04, 2015 1,827,232 Sunday, September 04, 2016 789,021 158 Friday, September 05, 2014 2,089,789 Saturday, September 05, 2015 1,793,773 Monday, September 05, 2016 639,458 159 Saturday, September06, 2014 2,089,789 Sunday, September 06, 2015 1,760,314 Tuesday, September 06, 2016 724,408 160 Sunday, September 07, 2014 2,089,789 Monday, September 07, 2015 1,614,559 Wednesday, September 07. 20 I 6 820,356 161 Monday, September 08, 2014 1,865,465 Tuesday, September 08, 2015 1,579,946 Thursday, September 08, 2016 967,405 162 Tuesday, September 09, 2014 1,940,420 Wednesday, September 09, 2015 1,552,393 Friday, September 09, 2016 967,405 Page 3 of7 Atmos Energy Corporation" Colorado Service Area CWCWP3-1 Collection Lag Analysis Colorado-Kansas Daily Accounts Receivable Balances 12Mo. Ended 12 Mo. Ended l2Mo.Ended Line No. 3/31/J5 Daily AIR 3131116 Daily AIR 3/31/l 7 Daily AIR (a) (b) (c) (d) (e) (f) 163 Wednesday, September 10, 2014 1,925,563 Thursday, September 10, 2015 1,649,825 Satnrday, September 10, 2016 938,732 164 Thursday, September II, 2014 1,974,146 Friday, September II. 2015 1,611,075 Sunday, September 11, 2016 842,277 165 Friday, September 12, 2014 2,171,736 Satnrday, September 12, 2015 1,572.325 Monday, September 12, 2016 914,705 166 Saturday, September 13, 2014 2,171,736 Sunday, September 13, 2015 1,534,178 Tuesday, September 13, 2016 1,085,154 167 Sunday, September 14, 2014 2,171,736 Monday, Septemb0< 14, 2015 1,559,590 Wednesday, September 14, 2016 1,091,367 168 Monday, September 15, 2014 1,936,164 Tuesday, September 15, 2015 1,690,487 Thursday, September 15, 2016 1,478,342 169 Tuesday, September 16, 2014 2,054,683 Wednesday, September 16. 2015 1,857,980 Friday, September 16, 2016 1,478,342 170 Wednesday, September 17, 2014 2,268,085 Thw:sday, September 17, 2015 2,099,350 Satnrday, September 17. 2016 1,420,260 17! Thursday, September 18, 2014 2,441,115 Friday, September 18, 2015 2,068,364 Sunday, September 18, 2016 1,554,801 172 Friday, September 19, 2014 2,574,754 Saturday, September 19, 2015 2,037,378 Mollday, September 19, 2016 1,537,716 173 Satnrday, September 20, 2014 2,574,754 Sunday, September 20, 2015 1,991,122 Tuesday, September20, 2016 1,619,049 174 Sunday, September 21, 2014 2.574,754 Monday, September 21, 2015 1,957,151 Wedllesday, September 21, 2016 1,702,796 175 Monday, September 22, 2014 2,379,292 Tuesday, September 22, 2015 2,004,004 Thursday, September 22, 2016 1,747,646 176 Tuesday, September 23, 2014 2,375,938 Wednesday, September 23, 2015 2,117,746 Friday, September23, 2016 1,747,646 177 Wednesday, September24, 2014 2,445,341 Thw:sday, September 24, 2015 2,132,647 Satnrday, September 24, 2016 1,704,989 178 Thursday, September 25, 2014 2,402,228 Friday, September 25, 2015 2,132,647 Sunday, September 25, 2016 1,550,892 179 Friday, September 26, 2014 2,422,197 Saturday, September 26, 2015 2,039,838 Monday, September26, 2016 1,478,393 180 Satnrday, September 27, 2014 2,422,197 Sunday, September27, 2015 1,755,817 Tuesday, September 27, 2016 1,405,102 181 Sunday, September28, 2014 2,422,197 Monday, September 28, 2015 1,526.273 Wednesday, September 28, 2016 1,325,095 182 Monday, September 29, 2014 1,975,230 Tuesday, September 29, 2015 1,493,205 Thw:sday, September 29. 2016 1,218,237 183 Tuesday, September 30, 2014 1,859,774 Wednesday, September 30, 2015 1,460,136 Friday, September 30, 2016 1,214,591 184 Wednesday, October 01, 2014 1,798,673 Thursday, October OJ, 2015 1,534,768 Saturday, October 01, 2016 1,210,946 185 Thursday, October 02, 2014 1,798,673 Friday, October02, 2015 1,534,768 Sunday, October 02, 2016 1,143,460 186 Friday, October 03, 2014 1,791,920 Satnrday, October 03, 2015 1,431,752 Monday, October 03, 2016 1,041,640 187 Saturday, October 04, 2014 1,791,920 Sunday, October 04, 2015 1,144,410 Tuesday, October 04, 2016 969,642 188 Sunday, October 05, 2014 1,791,920 Mollday, October 05, 2015 1,282,310 Wednesday, October 05, 2016 1,123,899 189 Monday, October 06, 2014 1,616,253 Tuesday, October 06, 2015 1,387,495 Thursday, October 06, 2016 1,226,664 190 Tuesday, October 07, 2014 1,690,677 Wednesday, October 07, 2015 l,494,027 Friday, October07, 2016 1,226.664 191 Wednesday, October08, 2014 1,892,279 Thursday, October 08, 2015 1,565,180 Satnrday, October 08, 2016 1,186,826 192 Thmsday, October 09, 2014 1,941,809 Friday, October 09, 2015 1,565,180 Sunday, October 09, 2016 1,300,206 193 Friday, October 10, 2014 1,941,809 Satnrday, October 10. 2015 1,443,787 Monday, October IO, 2016 1,167,065 194 Saturday, October II, 2014 2,108,715 Sunday, October II, 2015 1,317,931 Tuesday, October 11, 2016 1,215,074 195 Sunday, October 12, 2014 2,108,715 Monday, October 12, 2015 1,517,414 Wednesday, October 12, 2016 1,623,935 196 Monday, October 13, 2014 2,108,715 Tuesday, October 13, 2015 1,586,787 Thursday, October 13, 2016 1,688,053 197 Tnesday, October 14, 2014 2,032,055 Wednesday, October 14, 2015 1,994,542 Friday, October 14, 2016 1,688,053 198 Wednesday, October 15, 2014 2,049,974 Thursday, October 15, 2015 2,216,647 Saturday, October 15, 2016 1,612,403 199 Thursday. October 16, 2014 2,281,223 Friday, October 16, 2015 2,216,647 Sunday, October 16, 2016 1,684,731 200 Friday, October 17.2014 2,646,101 Satnrday, October 17. 2015 2,111,346 Monday, October 17, 2016 1,852,548 201 Saturday, October 18, 2014 2,646,101 Sunday, October 18, 2015 1,965,512 Tuesday, October 18, 2016 1,876,084 202 Sunday, October 19, 2014 2,646,101 Monday, October 19, 2015 2,027,870 Wednesday, October 19, 2016 1,984,521 203 Monday, October 20, 2014 2,646,101 Tuesday, October 20, 2015 2,080,192 Thursday, October20, 2016 1,960,267 204 Tuesday, October 21, 2014 2,543,071 Wednesday, October 21, 2015 2,040,953 Friday, October 21, 2016 1,960,267 205 Wednesday, October22, 2014 2,854,627 Thursday, October 22, 2015 2,209,777 Saturday, October 22, 2016 1,898,795 206 Thmsday, October23, 2014 2,930,539 Friday, October 23, 2015 2.209,777 Sunday, October23, 2016 1,763,184 207 Friday, October 24, 2014 2,935,430 Saturday, October 24, 2015 2.097,422 Monday, October 24, 2016 1,827,730 208 Saturday, October 25, 2014 2,935,430 Sunday, October 25, 2015 l,828,267 Tuesday, October 25. 2016 1,733,515 209 Sunday, October26, 2014 2,935,430 Monday, October 26, 2015 l,755,500 Wednesday, October26, 2016 1,732.207 210 Monday, October 27, 2014 2,403,906 Tuesday, October 27, 2015 l,625,371 Thursday, October 27, 2016 1,577.434 211 Tuesday, October 28, 2014 2,201,422 Wednesday, October28, 2015 1,471,396 Friday, October28, 2016 l,577,434 212 Wednesday, October 29, 2014 2,051,631 Thursday, October 29. 2015 l.298,888 Saturday, October 29, 2016 1,472,937 213 Thursday, October 30, 2014 1,955,917 Friday, October 30, 2015 l,215,501 Sunday, October 30, 2016 1,138,750 214 Friday, October 31, 2014 1,864,193 Saturday, October 31, 2015 1,132,115 Monday, October 31, 2016 1,194,670 215 Saturday, November 01, 2014 1,864,193 Sunday, November 01, 2015 l,048,728 Tuesday, November 01, 2016 1,182,773 216 Sunday, November 02, 2014 1,864,193 . Monday, November02, 2015 974,329 Wednesday, November 02, 2016 1,340.218 Page 4 of7 Atmos Energy Corporation - Colorado Senrice Area CWCWP3-l Collection Lag Analysis Colorado-Kansas Daily Accounts Receivable Balances 12Mo.Ended 12Mo.Ended 12 Mo. Ended Line No. 3/31/15 Da.ili::AIR 3/31/16 Daily AIR 3/31/17 Daily AIR (a) (b) (c) (d) (e) (f) 217 Monday, November 03, 2014 1,864.193 Tuesday. November 03, 2015 1,066,494 Thursday, November 03, 2016 1,573,712 218 Tuesday, November 04, 2014 1,702,992 Wednesday. November 04, 2015 1,494,823 Friday, November 04, 2016 1,573,712 219 Wednesday, November 05, 2014 1,982,605 Thursday, November 05. 2015 1.685,740 Saturday, November 05, 2016 l,519,297 220 Thursday, November 06, 2014 2,717,766 Friday, November 06, 2015 1,685,740 Sunday, November 06, 2016 1,487,560 221 Friday, November 07, 2014 3,109,328 Saturday, November 07, 2015 1,578,144 Monday, November 07, 2016 1,677.669 222 Saturday, November 08, 2014 3,109,328 Sun Page 5 of? Atmos Energy Corporation - Colorado Service Area CWCWP3-l Collection Lag Analysis Colorado-Kansas Daily Accounts Receivable Balances 12 Mo.Ended 12Mo.Ended 12Mo.Ended Line No. 3/31/15 Daill:'. AIR 3/31/16 Daill:'. AIR 3131/17 Dail):'. AIR (a) (b) (c) (d) (•) (f) 271 Saturday, December 27, 2014 9,846,058 Sunday, December 27, 2015 6,035,599 Tuesday, December 27, 2016 5,097,367 272 Sunday, December28, 2014 9,846,058 Monday, December 28, 2015 5,947,247 Wednesday, December 28, 2016 4,764,202 273 Monday, December 29, 2014 8,672,655 Tuesday, December 29, 2015 5,061,926 Thursday, December29, 2016 4,452,619 274 Tuesday, December 30, 2014 8,294,754 Wednesday, December 30, 2015 4,925,811 Friday, December 30, 2016 4,422,826 275 Wednesday, December 31, 2014 7,633,599 Thursday, December 31, 2015 4,789,696 Saturday, December 31, 2016 4,369,052 276 Thursday, Jaouwy OJ, 2015 7,633,599 Friday, Jaonwy 01, 2016 4,653,580 Sucday, Januwy 01, 2017 4,315,279 277 Friday, Januwy 02, 2015 7,633,599 Saturday, Januwy 02, 2016 4,517,465 Monday, January 02, 20 l 7 4,171,930 278 Saturday, January 03, 2015 7,633,599 Sunday, Jannwy 03, 2016 4,544,429 Tuesday, Januwy 03, 2017 3,796,143 279 Sunday, Jannwy 04, 2015 7,633,599 Monday, Januwy 04, 2016 4,660,332 Wednesday, January 04, 2017 3,757,837 280 Monday, January 05, 2015 6,975,646 Tuesday, January 05, 2016 5,147,684 Thursday, Jannwy 05, 2017 5,471,262 281 Tuesday, January 06, 2015 8,027,546 Wednesday, January 06, 2016 6,668,517 Friday, January 06, 2017 5,471,262 282 Wednesday, J annwy 07, 2015 8,900,428 Thursday, January 07, 2016 7,224,697 Saturday, January 07, 2017 5,357,368 283 Thursday, January 08, 2015 9,728,927 Friday, January 08, 2016 7,224,697 Sunday, January 08, 2017 5,500,684 284 Friday, January 09, 2015 10,698,515 Saturday, January 09, 2016 7,022,392 Monday, January 09, 2017 5,933,288 285 Saturday, January 10, 2015 10,698,515 Sunday, Jaouwy 10, 2016 6,751,164 Tuesday, January 10, 2017 6,033,796 286 Sunday, Januwy 11, 2015 10,497,595 Monday, January 11, 2016 7,226,156 Wednesday, January 11, 2017 6,523,834 287 Monday, January 12, 2015 10,296,675 Tuesday, January 12, 2016 8,000,886 Thursday, Januwy 12, 2017 7,225,159 288 Tuesday, January 13, 2015 ll,018,684 Wednesday, January 13, 2016 8,688,586 Friday, Januwy 13, 2017 7,225,159 289 Weduesday, January 14, 2015 12,143,806 Thursday, Januwy 14, 2016 8,951,730 Saturday, January 14, 2017 7,022,947 290 Thursday, January 15, 2015 13,034,821 Friday, January 15, 2016 9,214,875 Sunday, January 15, 2017 7,617,411 291 Friday, Januwy 16, 2015 14,172,036 Saturday, Jaouwy 16, 2016 9,116,272 Monday, January 16, 2017 7,949,546 292 Saturday, Jannwy 17, 2015 14,172,036 Sunday, January 17, 2016 10,072,433 Tuesday, January 17, 2017 9,173,524 293 Sunday, January 18, 2015 14,172,036 Monday, January 18, 2016 10,276,534 Wednesday, Jannwy 18, 2017 9,316,789 294 Monday, January 19, 2015 15,224,200 Tuesday, January 19, 2016 10,480,635 Thursday, January 19, 2017 9,577,321 295 Tuesday, January20, 2015 15,186,057 Wednesday.Jaouwy 20, 2016 10,684,736 Friday, Januwy 20, 2017 9,577,321 296 Wednesday, January 21, 2015 15,803,992 Thursday, January 21, 2016 10,888,837 Saturday, January 21, 2017 9,380,592 297 Thursday, Januwy 22, 2015 16,492,006 Friday, January 22, 2016 11,092,939 Sunday, Januwy 22, 2017 9,091,756 298 Friday, January 23, 2015 16,838,438 Saturday, Jannwy 23, 2016 10,337,680 Monday, January 23, 2017 9,370,000 299 Saturday, Jaouary 24, 2015 16,838,438 Sunday, January 24, 2016 10,267,110 Tuesday, January 24, 2017 9,393,431 300 Sunday, January 25, 2015 16,838,438 Monday, Jaouary 25, 2016 10,196,540 Wednesday, Januwy 25, 2017 9,484,261 301 Monday, January 26, 2015 15,894,343 Tuesday, Januwy 26, 2016 9,912,860 Thursday, January 26, 2017 9,334,518 302 Tuesday, Jannwy 27, 2015 15,176,597 Wednesday, January 27, 2016 9,912,860 Friday,January 27, 2017 9,334,518 303 Wednesday, January 28, 2015 14,950,918 Thursday, January 28, 2016 8,950,898 Saturday, January 28, 2017 9,033,604 304 Thursday, January 29, 2015 14,489,442 Friday, January 29, 2016 8,950,898 Sunday, January 29, 20 l 7 8,115,123 305 Friday, Januwy 30, 2015 14,141,644 Saturday, Jaouwy 30, 2016 8,734,871 Monday, January 30, 2017 7,488,724 306 Saturday, Januwy 31, 2015 14,012,847 Sunday, Jannwy 31, 2016 8,518,845 Tuesday, Januwy 31, 2017 7,750,686 307 Sunday, Febrnwy 01, 2015 14,012,847 Monday, Februwy 01,2016 8,325,204 Wednesday, February 01, 2017 7,832,767 308 Monday, February 02, 2015 12,871,929 Tuesday, February 02, 2016 8,581,766 Thursday, February 02, 2017 8,158,184 309 Tuesday, Febrnwy 03, 2015 12,464,288 Wednesday, Febrnwy 03, 2016 9,078,679 Friday, February 03, 2017 8,158,184 310 Wednesday, February 04. 2015 13,011,298 Thursday, February 04, 2016 9,326,343 Saturday, Febrnwy 04,2017 8,035,905 311 Thursday, February 05, 2015 14,420,369 Friday, February 05, 2016 9,326,343 Sucday, February 05, 2017 7,559,415 312 Friday, February 06, 2015 15,024,795 Saturday, February 06, 2016 8,974,729 Monday, Februwy 06, 2017 7,626,489 313 Saturday, February 07, 2015 15,024,795 Sunday, February 07, 2016 8,780,875 Tuesday, February 07, 2017 7,775,707 314 Sunday, Febrnwy 08, 2015 15,024,795 Monday, Febrnwy 08, 2016 8,515,686 Wednesday, February 08, 2017 8,484,818 315 Monday, February 09, 2015 13,519,727 Tuesday, February 09, 2016 8,587,622 Thursday, February 09, 2017 9,044,946 316 Tuesday, February 10, 2015 13,419,769 Wednesday, February 10, 2016 9,142,895 Friday, February IO, 2017 9,044,946 317 Wednesday. Febrnwy ll, 2015 13,950,584 Thursday, February 11, 2016 9,438,825 Saturday, Febrnwy 11, 2017 8,865,550 318 Thursday, February 12, 2015 14,630,370 Friday, Febrnwy 12, 2016 9,43&,825 Sunday, February 12, 2017 8,562,496 319 Friday, Februwy 13, 2015 14,895,273 Saturday, February 13, 2016 9,319,891 Monday, Februwy 13, 2017 8,616,292 320 Saturday, Febrnwy 14, 2015 14,895,273 Sunday, Februwy 14, 2016 9,322,167 Tuesday, February 14, 2017 9,079,249 321 Sunday, February 15, 2015 14,895,273 Monday, February 15, 2016 9,576,192 Wednesday, February 15, 2017 9,056,870 322 Monday, Februwy 16, 2015 14,409,935 Tuesday, February 16, 2016 9,812,360 Thursday, February 16, 2017 9,474,505 323 Tnesday,February 17, 2015 14,412,726 Wednesday, February 17, 2016 I0,231,262 Friday, February 17, 2017 9,474,505 324 Wednesday, Febrnwy 18, 2015 14,626,751 Thursday, February 18, 2016 I0,033,225 Saturday, February 18, 2017 9,262,542 Page 6 of7 Atmos Energy Corporation - Colorado Service Area CWCWP3-l Collection Lag Analysis Colorado-Kansas Daily Accounts Receivable Balances 12Mo. Ended 12Mo. Ended 12Mo.Ended Line No. 3/31/15 Daily AIR 3/31/16 Daily AIR 3131/17 Daily AIR (a) (b) (c) (d) (e) (f) 325 Thursday, February 19, 2015 14,806,169 Friday, February 19, 2016 10,033,225 Sunday, February 19, 2017 9,049,657 326 Friday, February 20, 2015 14,755,004 Saturday, February 20, 2016 9,717,506 Monday, February 20, 2017 8,861,608 327 Saturday, February 21, 2015 14,755,004 Sunday, February 21, 2016 9,280,236 Tuesday, February 21, 2017 8,789,032 328 Sunday, February 22, 2015 14,755,004 Monday, February 22, 2016 9,249,733 Wednesday, February 22, 2017 8,745,855 329 Monday, February 23, 2015 13,181,713 Tuesday, February 23, 2016 8,321,244 Thursday, February 23, 2017 8,403,735 330 Tuesday, February 24, 2015 12,688,139 Wednesday, February 24, 2016 8,070,048 Friday, Februey 24, 2017 8,403,735 331 Wednesday, February 25, 2015 11,429,096 Thursday, February 25, 2016 7,705,448 Saturday, F ebmary 25, 2017 8,266,433 332 Thursday, February 26, 2015 11,047,690 Friday, February 26, 2016 7,705,448 Sunday, February 26, 2017 7,277,977 333 Friday, February 27, 2015 10,655,814 Saturday, February 27, 2016 7,461,381 Monday, February 27, 2017 6,759,082 334 Saturday, February 28, 2015 10,560,913 Sunday, February 28, 2016 7,053,180 Tuesday, February 28, 2017 6,902,890 335 Sunday, March 01, 2015 10,560,913 Monday, February 29, 2016 6,644,980 Wednesday, March 01, 2017 6,793,365 336 Monday, March 02, 2015 10,560,913 Tuesday, March 01, 2016 6,236,779 Thursday, March 02, 2017 6,986,668 337 Tuesday, March 03, 2015 9,866,461 Wednesday, March 02, 2016 6,485,668 Friday, March 03, 2017 6,986,668 338 Wednesday, March 04, 2015 10,206,990 Thursday, March 03, 2016 6,854,975 Saturday, March 04, 2017 6,910,048 339 Thursday, March 05, 2015 10,792,476 Friday, March 04, 2016 6,854,975 Sunday, l\lfarch 05, 2017 6,680,559 340 Friday, March 06, 2015 11,035,091 Saturday, March 05, 2016 6,670,655 Monday, March 06, 2017 6,160,471 341 Saturday, March 07, 2015 ll,035,091 Sunday, March 06, 2016 6,312,592 Tuesday,March07, 2017 6,349,163 342 Sunday, March 08, 2015 ll,035,091 Monday, March 07, 2016 6,498,438 Wednesday, March 08, 2017 6,247,212 343 Monday, March 09, 2015 10,814,372 Tuesday, March 08, 2016 6,445,156 Thursday, March 09, 2017 6,499,807 344 Tnesday, March 10, 2015 10,810,406 Wednesday, March 09, 2016 6,577,410 Friday, March 10, 2017 6,499,807 345 Wednesday, March 11, 2015 11,313,222 Thursday, March 10, 2016 6,951,528 Saturday, March ll, 2017 6,281,372 346 Thursday, March 12, 2015 12,053,528 Friday, March 11, 2016 6,951,528 Sunday, March 12, 2017 6,320,477 347 Friday, March 13, 2015 12,285,640 Saturday, March 12, 2016 6,612,997 Monday, March 13, 2017 6,348,730 348 Saturday, March I 4, 2015 12,285,640 Sunday, March 13, 2016 6,612,997 Tuesday, March 14, 2017 6,741,721 349 Sunday, March 15, 2015 12,285,640 Monday, March 14, 2016 6,504,185 Wednesday, March 15, 2017 7,322,694 350 Monday, March 16, 2015 12,188,482 Tuesday, March 15, 2016 6,810,415 Thursday, March 16, 2017 7,187,582 351 Tuesday, March 17, 2015 12,942,110 Wednesday, March 16, 2016 7,043,974 Friday, March 17, 2017 7,187,582 352 Wednesday, March 18, 2015 12,826,455 Thursday, March 17, 2016 7,024,535 Saturday, March 18, 2017 6,999,600 353 Thursday, March I 9, 2015 13,350,821 Friday, March 18, 2016 7,024,535 Sunday, March 19, 2017 6,857,962 354 Friday, March 20, 2015 13,617,194 Saturday, March 19, 2016 6,827,628 Monday, March 20, 2017 6,793,623 355 Saturday, March 2 l, 2015 13,617,194 Sunday, March 20, 2016 6,655,569 Tuesday, March 21, 2017 6,833,952 356 Sunday, March 22, 2015 13,617,194 Monday, March 21, 2016 6,590,518 Wednesday, March22, 2017 7,0l!,322 357 Monday, March 23, 2015 12,758,673 Tuesday, March 22, 2016 6,586,406 Thursday, March 23, 2017 6,846,005 358 Tnesday, March 24, 2015 12,745,492 Wednesday, March 23, 2016 6,562,509 Friday, March 24, 2017 6,846,005 359 Wednesday, March 25, 2015 12,576,008 Thursday, March 24, 2016 6,562,509 Saturday, March 25, 2017 6,685,497 360 Thursday, March 26, 2015 12,338,848 Friday, March 25, 2016 6,562,509 Sunday, March 26, 2017 6,158,299 361 Friday, March 27, 2015 12,338,848 Saturday, March 26, 2016 6,249,909 Monday, March 27, 2017 5,455,690 362 Saturday, March 28, 2015 12,026,860 Sunday, March 27, 2016 5,708,245 Tuesday, March 28, 2017 5,122,147 363 Sunday, March 29, 2015 12,026,860 Monday, March 28, 2016 5,305,094 Wednesday, March 29, 2017 4,781,609 364 Monday, March 30, 2015 11,694,548 Tuesday, March 29, 2016 4,739,249 Thursday, March 30, 2017 4,461,107 365 Tuesday, March 31, 2015 11,362,236 Wednesday, March 30, 2016 4,724,589 Friday, March 31, 2017 4,414,874 366 Thursday, March 31, 2016 4,709,930 367 368 Avg Daily AIR $ 6,913,142 Avg Daily AIR $ 5,044,868 Avg Daily AIR $ 3,978,179 369 370 Billed Revenues $ 120,321,506 Billed Revenues $ 97,048,319 Billed Revenues $ 89,190,846 371 372 Avg Daily Revenues: $ 329,648 Avg Daily Revenues: $ 265,159 Avg Daily Revenues: $ 244,358 373 374 Collection Lag [1] 20.97 Collection Lag [l] 19.03 Collection Lag [l] 16.28 375 376 Three yea.- average Collection Lag 18.76 377 378 [l] Avg Daily AIR divided by Avg Daily Revenues Page 7 of7 Atmos Energy Corporation - Colorado Service Area CWCWP3-2 Collection Lag Analysis Test Year Ending March 312015,2016 and 2017 Revennes 12 Mo. Ended 12Mo. Ended 12Mo. Ended 12Mo. Ended 12 Mo. Ended 12 Mo. Ended 3/3112015 3/31/2015 3/3112016 3/3112016 3/3112017 3/3112017 Line No. Account Account DescriEtion Activitl;'. wt o unbilled Activity w/ounbi!Ied Activitl:'. w/o unbilled (a) (b) (c) (d) (e) (f) (g) (h) 1 Company060 2 4800 Residential sales $ (165,483, 743) $ (165,483,743) $ (132,846,688) $ (132,846,688) $ (54,197,711) $ (54,197,711) 3 4805 Unbilled Residential Revenue 2,958,134 (15.131) 859,862 4 4811 Commercial Revenue-Banner (64, 120,603) (64,120,603) (48,956,222) (48,956,222) (26,066,836) (26,066,836) 5 4812 Industrial Revenue-Banner (401.233) (40!,233) (255,686) (255,686) 0 0 6 4813 Irrigation Revenue-Banner (5,545,740) (5,545, 740) (3,979,313) (3,979,313) (29,597) (29,597) 7 4815 Unbilled Comm-Ind-Irrg Revenue 1,097,196 300,142 566;835 8 4820 Other Sales to Public Authorit (1,857,094) (1,857,094) (1,343,982) (1,343,982) 1,227 1,227 9 4825 Unbilled Public Authority Reve 51,057 10,671 0 IO 4870 Forfeited discounts (507,600) (507,600) (397,134) (397,134) (73,427) (73,427) 11 4880 Miscellaneous service revenues (924,443) (924,443) (832,971) (832,971) (303,525) (303,525) 12 4890 Revenues from transporation of 0 0 0 0 13 4893 Revenue-Transportation Distribution (7,896,958) (7,896,958) (7,989,378) (7,989,378) (2,570,375) (2,570,375) 14 4895 Revenue-Transportation Commerc 0 0 0 0 0 0 15 4896 Revenue-Transportation Industr 0 0 0 0 0 16 4900 Sales of products extracted fr 0 0 0 0 17 4950 Other gas revenues (824,748) (824,748) (114,190) (114.190) 0 0 18 $ (243,455,775) $ (247,562,162) $ (196,419,884) $ (196,715,565) $ (81,813,546) $ (83,240,244) 19 20 Divison 081 21 4800 Residential sales $ (94,699,462) $ (94,699,462) $ (74,836,439) $ (74,836,439) $ $ 22 4805 Unbilled Residential Revenue 1,940,924 325,271 23 481 I Commercial Revenue-Banner (25,486,412) (25,486,412) (19,254,696) (19,254,696) 24 4812 Industrial Revenue-Banner (401,233) (401,233) (255,686) (255,686) 25 4813 Irrigation Revenue-Banner (5,449,791) (5,449,791) (3,909 ,305) (3,909,305) 26 4815 Unbilled Comm-Ind-Irrg Revenue 512,430 418,645 27 4820 Other Sales to Public Authorit (1,857,676) (1,857,676) (!,340,943) (1,340,943) 28 4825 Unbilled Public Authority Reve 51,101 10,592 29 4870 Forfeited discounts (394,572) (394,572) (302,629) (302,629) 30 4880 Miscellaneous service revenues (627,376) (627,376) (565,186) (565,186) 31 4893 Revenue-Transportation Distribution (5,402,652) (5,402,652) (5,436,206) (5,436,206) 32 4950 Other gas revenues (821,281) (821,281) (19.940) (19,940) 33 $ (132,636,000) $ (135,140,456) $ (!05,166,522) $ (105,921,030) $ $ 34 35 Billed Taxes $ (7,899,799) $ (6,253, 785) $ (5,950,602) 36 37 Company 06"0 billed net of Division 081 $ (120,321,506) $ (97,048,319) $ (89,190,846) Page I ofl Schedule CWC4 Atmos Energy Corporation-Colorado Per Books Purchase Gas Cost Test Year Ending March 31, 2017 Production Month $Days Line Service Date of Invoice Payment Date - Checks Payment Adjusted No. Supplier Start Service Finish Service Lag Invoice Lag Date Paid Lag Total Lag A.mount Cleared Lag Lag (m)x(j) (a) (b) (c) (d) (e) (f) (g) (h) (i) (j) (k) (!) (m) (n) Black Hills Energy 03/01/16 3/31/16 15.5 4/1/16 1.0 04/21/16 20.0 36.50 13,875.00 36.5 $ 506,438 2 BP Energy Company 03101/16 3/31/16 15.5 4121/16 21.0 04/25/16 4.0 40.50 280,579.01 40.5 ll,363,450 Cima Energy Ltd 03/01/16 3/31116 15.5 4113/16 13.0 04/25/16 12.0 40.50 113,306.11 40.5 4,588,897 4 Colorado Interstate Gas Company 03101/16 3/31/16 15.5 4113/16 13.0 04/25/16 12.0 40.50 252,650.94 40.5 10,232,363 5 Concord Energy LLC 03/01/16 3/31/16 15.5 4/8/16 8.0 04/25/16 17.0 40.50 981,033.93 40.5 39,731,874 Northwest Pipeline Corporation 03/01/16 3/31/16 15.5 4/5/16 5.0 04125/16 20.0 40.50 55.800.00 40.5 2,259,900 Questar Pipeline 03/01116 3/31/16 15.5 4/12116 12.0 04125/16 13:0 40.50 $ 7.217.35 40.5 292,303 Red Cedar Gathering Company 03/01116 3131/16 15.5 4/14/16 14.0 04125/16 11.0 40.50 $ 62.578.lO 40.5 2,534,413 9 Renegade Oil and Gas Company LLC 03101116 3/31116 15.5 4/13/16 13.0 04/25116 12.0 40.50 $ 9,844.08 40.5 398,685 10 Tallgras• Interstate Gas Transmission LLC 03101/16 3/31/16 15.5 4/13/16 13.0 04/25116 12.0 40.50 $ 505,397.02 40.5 20,468,579 11 United Energy Trading~ LLC 03/01/16 3/31/16 15.5 4/5/16 5.0 04/25/16 20.0 40.50 s 309,032.61 40.5 12,515,821 12 Wyoming Interstate Company 03/01/16 3/31/16 15.5 4/11/16 11.0 04/21116 10.0 36.50 $ 21,292.00 36.5 777,158 13 Xcel Energy 03/01/16 31'llll6 15.5 4/12/16 12.0 04129116 17.0 44.50 2,942.36 05/09/16 10.0 54.5 160,359 14 Xcel Energy 03/01/16 3/31/16 15.5 4/14/16 14.0 04129116 15.0 44.50 600,098.35 05/09116 10.0 54.5 32,705,360 15 Black Hills Energy 04/01/16 4/30/16 15.0 5/10/16 10.0 05/16/16 6.0 31.00 13,875.00 31.0 430,125 16 BP Energy Company 04/01/16 4/30/16 15.0 5/13/16 13.0 05/25116 12.0 40.00 202,363.00 40.0 8,094,520 17 Cima Energy Ltd 04/01/16 4/30/16 15.0 5/6/16 6.0 05/25116 19.0 40.00 83,726.73 40.0 3,349,069 18 Colorado Interstate Gas Company 04/01/16 4/30/16 15.0 5/19116 .19.0 05/23116 4.0 38.00 211.309.10 38.0 8,029,746 19 Concord Energy LLC 04/01/16 4/30116 15.0 5/16116 16.0 05/25116 9.0 40.00 1,150,560.69 40.0 46,022,428 20 Northwest Pipeline Corporation 04/01/16 4/30/16 15.0 515116 5.0 05/25/16 20.0 40.00 16.200.00 40.0 648,000 21 Questar Pipeline 04/01/16 4/30/16 15.0 5/l!/16 11.0 05/23/16 12.0 38.00 6,762.35 38.0 256,969 22 Red Cedar Gathering Company 04/01/16 4/30/16 15.0 5/16/16 16.0 05/25/16 9.0 40.00 51.123.16 40.0 2,044,926 23 Renegade Oil and Gas Company LLC 04/01/16 4/30/16 15.0 5/20116 20.0 05/25/16 5.0 40.00 9,828.10 40.0 393,124 24 Tallgrass Interstate Gas Tran•mission LLC 04/01/16 4/30/16 15.0 5/12116 12.0 05/23/16 11.0 38.00 505,397.02 38.0 19,205,087 25 United Energy Trading, LLC 04/01/16 4/30/16 15.0 5/6116 6.0 05/25/16 19.0 40.00 260,737.73 40.0 10,429,509 26 Wyoming Interstate Compony 04/01/16 4/30/16 15.0 5110116 10.0 05/20/16 10.0 35.00 24,334.00 35.0 851,690 27 Xcel Energy 04/01/16 4/30/16 15.0 5/ll/16 11.0 05/27/16 16.0 42.00 2,942.36 06/02/16 6.0 48.0 141,233 28 Xcel Energy 04/01/16 4/30/16 15.0 5112!16 12.0 06103/16 22.0 49.00 515,434.55 06/13116 10.0 59.0 30,410,638 29 Black Hills Energy 05/01/16 5/31/16 15.5 6/10/16 10.0 06/14/16 4.0 29.50 13,875.00 29.S 409,313 30 BP Energy Company 05/01/16 5/31/16 15.5 6/15116 15.0 06127116 12.0 42.50 $ 162,394.65 42.5 6,901,773 31 Cima Energy Ltd 05/01/16 5/31116 15.5 6/15/16 15.0 06127/16 12.0 42.50 $ 71,985.19 42.5 3,059,371 32 Colorado Interstate Gas Compony 05/01/16 5/31/16 15.S 6/13/16 ·13.0 06/23116 lO.O 38.50 $ 204,2.24.19 38.5 7,862,631 33 Concord Energy LLC 05101116 5/31/16 15.5 6121/16 21.0 06127/16 6.0 42.50 $ 1,215,185.70 42.5 51,645,392 34 Northwest Pipeline Corporation 05101116 5/31/16 15.5 6/3/16 3.0 06/24116 21.0 39.50 s 16,740.00 39.5 661,230 35 QuestarPipeline 05/01/16 5131116 15.5 6110116 10.0 06/23/16 13.0 38.50 s 206.22 38.5 7,939 36 Red Cedar Gathering Company 05/01116 5/31/16 15.5 6115116 15.0 06/27/16 12.0 42.50 $ 47,479.46 42.5 2,017,877 37 Renegade Oil and Gas Company LLC 05/01/!6 5/31/16 15.5 6117/16 17.0 06/27/16 10.0 42.50 $ 6,249.36 42.5 265,598 38 Tallgrass Interstate Gas Transmission LLC 05/01/!6 S/31/16 15.S 6/!3/16 13.0 06123/16 10.0 38.50 $ 505,397.02 38.5 !9,457,785 39 United Energy Tra.din~ LLC 05101/16 5/31/16 15.5 6114/16 14.0 06/27116 13.0 42.50 $ 178,935.05 42.5 7,604,740 40 Wyoming Interstate Company 05101116 5/31116 15.5 6/9/16 9.0 06/20116 11.0 35.50 $ 24,334.00 35.5 863,857 41 Xcel Energy 05/01116 5/31/16 15.5 6/10/16 10.0 06/24116 14.0 39.50 2,901.66 07/01/16 .7.0 46.5 134,927 Page I of5 Schedule CWC4 Atmos Energy Corporation-Colorado Per Books Purtbase Gas Cost Test Year Ending March Jl, 2017 Production Month $Days Line Service Date of Invoice Payment Dato - Checks Payment Adjusted No. Supplier Start Service Finish Service Log Invoice Lag Date Paid Log Total Log Amount Cl oared Lag Lag (m)xG) (a) (b) (c) (d) (•) (f) (g) (h) (i) m (k) (I) (m) (n) 42 Xoel Energy 05/01116 5131/16 15.5 6/13/16 13.0 06/29/16 16.0 44.50 $ 454,385.65 07/06/16 7,0 51.5 23,400,861 43 Black HiHs Energy 06101116 6130116 15.0 7112116 12.0 07118/16 6.0 33.00 $ 13,875.00 33.0 457,875 44 BP Energy Company 06/01/16 6130116 15.0 1115116 15.0 07125/16 10.0 40.00 $ 87,657.00 40.0 3,506,280 45 Cima Energy Ltd 06101116 6130/16 15.0 7/14116 14.0 07/25/16 11.0 40.00 46,758.79 40.0 1,870,352 46 Colorado Interstate Gas Company 06/01/16 6130116 15.0 7/14/16 14.0 07/25/16 11.0 40.00 $ 173,505.17 40.0 6,940,207 4 7 Concord Energy LLC 06/01116 6130116 15.0 7/21/16 21.0 07/25/16 4.0 40.00 $ 800,413,59 40.0 32,016,544 48 Northwest Pipeline Corporation 06101116 6130116 15.0 7113/16 13.0 07/25/16 12.0 40.00 $ 16,200,00 40.0 648,000 49 Questar Pipeline 06101116 6130116 15.0 7113/16 13.0 07/25/16 12.0 40.00 $ 631.54 40.0 25,262 SO Red Cedar Gathering Company 06101116 6/30/16 15.0 7115/16 15.0 07/25/16 10,0 40.00 $ 42,881.03 40.0 1,715.241 51 Renegade Oil and Oas Company LLC 06/01/16 6/30/16 15.0 7/19116 19,0 07/25/16 6.0 40.00 s 12,048.28 40.0 481,931 52 Tal!grass Interstate Oas TI>!llsmission LLC 06/01116 6130/16 15.0 7114/16 14.0 07125/16 11.0 40.00 s 505,397.02 40.0 20,215,881 53 United Energy Trading, LLC 06/01116 6130116 15.0 717116 7.0 07/25/16 ts.a 40.00 s 79,141.12 40.0 3,165,645 54 Wyoming Interstate Company 06101116 6130/16 15.0 7/12116 12.0 07/22116 10.0 37.00 $ 24,334.00 37.0 900,358 55 Xoel Energy 06101116 6130/16 15.0 7114116 14.0 07/29/16 15.0 44.00 398,S00.90 08/08/16 10.0 54,0 21,535,249 56 Xcel Energy 06/01116 6130/16 15.0 7114/16 14.0 07/29/16 15.0 44.00 2,901.66 08/08/16 10.0 54.0 156,690 51 Black Hills Energy 07/01/16 7131/16 15.5 8/15116 15.0 08125/16 10.0 40.50 13,875.00 40.5 561,938 58 BP Energy Company 07/01/16 7131116 15.5 8115116 15.0 08/25/16 10.0 40.50 126,439,25 40.5 5,120,790 59 Cima Energy Ltd 07/01/16 7131/16 15.5 8/15/16 15.0 08/25/16 10.0 40.50 56,125.51 40.5 2,273,083 60 Colorado Interstate Gas Company 07/01/16 7131/16 15.5 8/11/16 11.0 08/22/16 11.0 37.50 119,771.72 37.5 4,491,440 61 Concord Energy LLC 07/01/16 7131/16 15.5 8/23/16 23.0 08/25/16 2.0 40.50 1,056,982.21 40.5 42,807,780 62 Northwest Pipeline Corporation 07/01/16 7131/16 15.5 813/16 3.0 08/25/16 22.0 40.50 16,740.00 40.5 677,970 63 Questar Pipeline 07/01116 7/31116 15.5 8/10/16 IO.O 08/22116 12.0 37,50 15i98 37.5 5,774 64 Red Cedar Gathering Company 07/01/16 7131116 15.5 8/15/16 15,0 08125/16 10.0 40.50 43,203.41 40.5 1,749,738 65 Renegade Oil and Gas Company LLC 07/01/16 7/31/16 15.5 8/15/16 15.0 08125/)6 10.0 40.50 17,200.80 40.5 696,632 66 Tallgrass Interstate Oas Transmission LLC 07/01/16 7/31/16 15.5 8/11/16 11.0 08122/16 11.0 37.50 505,397.02 37.5 18,952,388 67 United Energy Trading, LLC 07101116 7131/16 15.5 8/5116 5.0 08125/16 20.0 40.50 110,763.67 40.5 4,485,929 68 Wyoming Interstate Company 07101116 7131/16 15.5 8/9116 9.0 08119/16 10.0 34.50 24,334.00 34.5 839,523 69 · Xcel Energy 07101/16 7131/16 15.5 8110/16 10.0 08131/16 21.0 46.50 2,901.66 09/08/16 8.0 54,5 158,140 70 Xcel Energy 07/01/16 7131116 15.5 8/11/16 11.0 08131/16 20.0 46.50 418,641.20 09/08/16 8.0 54.5 22,815,945 71 Black Hills Energy 08/01/16 8131116 15.5 9/12116 12.0 09/21/16 9.0 36.50 13,875.00 36.5 506,438 72 BP Energy Company 08/01/16 8/31116 15.5 9/15/16 15.0 09/26/16 11.0 41.50 $ 136,058,65 41.5 5,046,434 73 Cima Energy Ltd 08/01/16 8131116 15.5 9/14/16 14.0 09/26/16 12.0 41.50 $ 56,597.38 41.5 2,348,791 74 Colorado Interstate Oas Company 08/01116 8131/16 15.5 9/14/16 14.0 09/26116 12.0 41.50 $ 121,481.08 41.5 5,041,465 75 Concord Energy LLC 08/01/16 8131116 15.5 9/21/16 21.0 09/23116 2.0 38.50 $ 1,114,879.19 38.S 42,922,849 76 Northwest Pipeline Corporation 08/01/16 8131/16 15,5 9/6/16 6,0 09/23/16 17.0 38.50 s 16,740.00 38.5 644,490 77 Questar Pipeline 08/01/16 8/31/16 15.5 9/13/16 13,0 09/26/16 13.0 41.50 s 428.73 41.5 17,792 78 Red Cedar Gathering Company 08/01/16 8131116 15,5 9/15/16 15,0 09/26/16 11.0 41.50 s 43,627.96 41.5 1,810,560 79 Renegade Oil and Gas Company LLC 08/01/16 8131/16 15.5 9/20/16 20,0 09/26/16 6.0 41.50 s 16,002.23 41.5 664,093 80 Tallgrass Interstate Gas Transmission LLC 08/0l/16 8131/16 15.5 9/14/16 14.0 09/26/16 12.0 41.50 s 505,397.02 41.5 20,973,976 81 United Energy Trading, LLC 08101116 8131116 ]5.5 9/8116 8.0 09/26116 18.0 41.50 s 135,224.92 41.5 5,611,834 82 Wyoming Interstate Company 08/0l/16 8/31/16 15.5 9/12116 12.0 09/22116 10.0 37.50 s 24,334.00 37.5 912,525 Page2 of5 Schedule CWC4 Atmos Energy Corporation-Colorado Por Books Purchase Gao Cost Test Year Ending March 31, 2017 Production Month $Days Line Service Date of Invoice Payment Date - Checks Payment Adjusted No. Supplier Start Service Finish Service Lag Invoice Lag Date Paid Lag Total Lag Amount Cleared Lag Lag (m)x(j) (a) (b) (c) (d) (•) (!) (g) (h) (i) (j) (k) (1) (m) (n) 83 Xcel Energy 08/01/16 8131/16 15,5 9/13/16 13.0 09/30/16 17.0 45.50 $ 2,901.66 10/11/16 11.0 56.5 163,944 84 Xcel Energy 08/01/16 8/31/16 15.S 9/14/16 14.0 09/30/16 16.0 45.50 s 399,207.14 10/11/16 11.0 56.5 22,555,203 85 Black Hills Energy 09/01/16 9/30/16 15.0 10/17/16 17.0 10/21/16 4.0 36.00 s 13,875.00 36.0 499,500 86 BP Energy Company 09/01/16 9130/16 15.0 10/14/16 14.0 10/25/16 11.0 40.00 s 157,890.00 40.0 6.315,600 87 Cima Energy Ltd 09/01/16 9/30/16 15.0 10/14/16 14.0 10/25/16 11.0 40.00 s 65,784.38 40.0 2,631,375 88 Colorado Interstate Gas Company 09/01/16 9130/16 15.0 10/14/16 14.0 10/24/16 10.0 39.00 $ 167,398.78 39,0 6,528,552 89 Concord Energy LLC 09/01/16 9130/16 15.0 10/21/16 21.0 10/25/16 4.0 40.00 $ 1,195,105.33 40,0 47,804,213 90 Northwest Pipeline Corporation 09/01/16 9130/16 15.0 10/5/16 5.0 10125/16 20.0 40.00 16,200.00 40.0 648,000 91 Questar Pipeline · 09/01/16 9130116 15.0 10/12/16 12.0 10124116 12.0 39.00 2,641.57 39.0 103,021 92 Red Cedar Gathering Company 09/01/16 9130/16 15.0 10117/16 17.0 ID/25116 8.0 40.00 44,352.32 40.0 1,774,093 93 Renegade Oil and Gas Company LLC 09/01/16 9130/16 15.0 10120/16 20.0 10125/16 5.0 40.00 16,266.81 40.0 650,672 94 Tallgrass Interstate Gas Transmission LLC 09/01/16 9130/16 15.0 10/14/16 14.0 10/24/16 10.0 39,00 505,397.02 39.0 19,710,484 95 United Energy Trading, LLC 09/01/16 9130116 15.0 10/21/16 21.0 10/25/16 4.0 40.00 160,430.95 40.0 6,417,238 96 Wyoming Interstate Company 09/01/16 9/30/16 15.0 10/12116 12.0 10/24/16 12.0 39.00 $ 24,334.00 39.0 949,026 97 Xcel Energy 09/01/16 9/30/16 15,0 10/12116 12.0 11/02116 21.0 48.00 $ 2,901.66 11114/16 12.0 60.0 174,100 98 Xcel Energy 09/01/16 9/30/16 15,0 10/13/16 13.0 11102116 20.0 48.00 $ 410,857.76 11/14116 12.0 60.0 24,651,466 99 Black Hills Energy 10/01/16 10131/16 15.5 11/15/16 15.0 11121116 6.0 36.50 s 13,875.00 36.5 506,438 100 BP Energy Company 10/01/16 10131/16 15.5 ll/l6/l6 16.0 11125/16 9.0 40.50 s 274,392.75 40.5 11,112,906 101 Cima Energy Ltd 10/01/16 10/31/16 15.5 11/21/16 21.0 11125/16 4.0 40.50 s 111,179.60 40.5 4,502,774 102 Colorado Interstate Gas Company 10/01/16 10/31/16 15.5 11/14/16 14.0 11125/16 11.0 40.50 s 217,545.84 40,5 8,810,607 103 Concord Energy LLC 10101/16 10131/16 15.5 11115116 15.0 11125116 10.0 40.50 s 1,842,410.42 40,5 74,617,622 104 Northwest Pipeline Corporation lOIOl/16 10131/16 15.5 11/3/16 3.0 11125/16 22.0 40.50 $ 16,740.00 40.5 677,970 I 05 Questar Pipeline 10101/16 10131/16 15.5 11/l0/16 10.0 12/22116 42.0 67.50 $ (0.20) 67.5 (14) 106 Red Cedar Gathering Company 10101/16 10131/16 15.5 11/15/16 15.0 11125/16 10.0 40.50 s 48,473,92 40.5 1,963,194 107 Renegade Oil and Gas Company LLC 10101/16 10/31/16 15.5 11/18/16 18.0 11/25/16 7,0 40.50 s 16,965,36 40.5 687,097 108 Tall grass Interstate Gas Transmission LLC 10101/16 10/31/16 15.5 11114/16 14.0 11/25/16 11,0 40.50 $ 505,397.02 40.5 20,468,579 I 09 United Energy Trading, LLC 10101/16 10/31/16 15.5 11116/16 16.0 11125/16 9.0 40.50 s 290,597.28 40.5 11,769,190 110 Wyoming Interstate Company 10101/16 10/31/16 15.5 11/9/16 9.0 11/21116 12,0 36.50 s 24,334.00 36.S 888,191 111 Xcel Energy 10/01/16 10131/16 15.5 11/10/16 10,0 IJ/28/16 18.0 43.50 s 2,901.66 12113/16 15.0 58.5 169,747 112 Xcel Energy 10/01/16 10/31/16 15.5 11/14116 14.0 12102116 18.0 47.50 s 458,610,07 12121/16 19.0 66.5 30,497,570 113 Black Hills Energy 11101/16 11/30/16 15.0 12115/16 15.0 12122116 7.0 37.00 s 13,875.00 37.0 513,375 114 BP Energy Company l 1/0l/16 ll/30/16 15.0 12121116 21.0 12127/16 6.0 42.00 $ 395,667.50 42.0 16,618,035 115 Cima Energy Ltd 11101116 11!30/16 15.0 12114116 14.0 12127116 13.0 42.00 152,495.48 42,0 6,404,810 116 Colorado Interstate Gas Company 11/01116 11130/16 15.0 12113116 13.0 12122116 9.0 37.00 221,365.64 37.0 8,190,529 117 Conoord Energy LLC 11/01/16 Il/30/16 15.0 12/21/16 21.0 12122116 1.0 37.00 1,409,466.14 37.0 52,150,247 118 Enstor Energy Servioes LLC 11/01/16 11/30/16 15.0 1216/16 6.0 12127/16 21.0 42.00 514,554.53 42,0 21,611.290 119 Enstor Energy Servioes LLC 11101/16 11130/16 15.0 1216/16 6.0 12127/16 21.0 42.00 6,199.09 42.0 260,362 120 Northwest Pipeline Corporation 11/01/16 11130/16 15.0 1215/16 5.0 12122/16 17.0 37.00 54,000.00 37.0 l,998,000 121 QuestarPipeline 11/01/16 11130/16 15.0 12/13/16 13.0 12122116 9.0 37,00 4, 742.87 37.0 175,486 122 Red Cedar Gathering Company 11101116 11/30/16 15.0 12/15/16 15.0 12127/16 12,0 42,00 67,936.43 42.0 2,853.330 123 Renegade Oil and Gas Company LLC 11101/16 11130/16 15.0 12/20/16 20.0 12127/16 7,0 42,00 14,244.45 42.0 598.267 Page 3 of5 -:.··· Schedule CWC4 Atmo• Energy Corporatioo·Colorado Per Books Purchase Gas Cost Test Year Ending March 31, 2017 Production Month $Days Line Service Date of Invoice Payment Date - Checks Payment Adjusted No. Supplier Start Service Finish Service Lag Invoice Lag Date Paid Lag Total Lag Amount Cleared Lag Lag (m)x(i) (a) (b) (c) (d) (e) (f) (g) (h) (i) (j) (k) (1) (m) (n) 124 Tallgrass Interstate Gas Transmission LLC 11101116 11/30116 15.0 12113116 13.0 12122/16 9.0 37.00 505,397.02 37.0 18,699,690 125 Wyoming Intemate Company 11101116 11/30/16 15.0 1219/16 9,0 12119/16 10.0 34.00 24,334.00 34.0 827,356 126 Xcel Energy 11101/16 11/30/16 15.0 12113/16 13,0 12128/16 15.0 43.00 2,840.86 01106117 9.0 52,0 147,725 127 Xcel Energy !l/01116 !l/30/16 15.0 12/14/16 14.0 12128/!6 14.0 43.00 543,700.79 01106/17 9.0 52.0 28,272,441 128 Black Hillo Energy 12101/16 12/31/16 15.5 1/18/17 18.0 01/23/17 5.0 38.50 13,875.00 38.5 534,188 129 BP Energy Company 12101/16 12/31/16 15.5 1113/17 13.0 01/25/17 12.0 40.50 834,374.35 40,5 33,792,161 13 O Cima Energy Ltd 12/01116 12/31/16 15.5 1/18/17 18.0 01/25/17 7.0 40.50 279,600.31 40.5 11,323,813 13 l Colorado Interstate Gas Company 12101/16 12/31/16 15.5 1/13/17 13.0 01/23/17 10.0 38.50 226,604.89 38,5 8,724,288 132 Concord Energy LLC 12/01/16 12/31116 15.S 1/23/17 23.0 01/25117 2.0 40.50 4,071,214.24 40.5 164,884, 177 133 Enstor Energy Services LLC 12101/16 12131116 15.5 115117 5.0 01/25/I 7 20.0 40.50 1,036,127.94 40.5 41,963,182 134 Enstor Energy Services LLC 12/01116 12131116 15.5 1/5/17 5.0 01125/17 20.0 40.50 8,194.35 40.5 331,871 135 Northwest Pipeline Corporation 12/01116 1213 l/I6 15.5 115111 5.0 01125/I 7 20.0 40.50 $ 55,800.00 40.S 2,259,900 136 Questar Pipeline 12101116 12131116 15.5 1/12117 12.0 01123/I 7 ll.O 38.50 $ 14,464.65 38.5 556,889 137 Red Cedar Gathering Company 12101116 12131/16 15.5 1/17/17 17.0 01/25117 8.0 40.50 $ 77,876.96 40.5 3,154,017 138 Renegade Oil and Gas Company LLC 12/01116 12131/16 15.5 1/18/17 18.0 01/25117 7.0 40.50 s 20,964.27 40.5 849,053 139 Tallgrass Interstate Gas Transmission LLC 12/0!/!6 12/31/16 15.5 !/13/17 13,0 01/23117 10.0 38.50 s 505,397.02 38.5 19,457,785 140 Wyoming Interstate Company 12/01/16 12/31116 15.5 l/11/17 11.0 01/23117 12.0 38.50 $ 24,334.00 38,5 936,859 141 Xcel Energy 12/01/16 12/31/16 15.5 1/12/17 12,0 01/27117 15.0 42.50 $ 2,840.86 02103/17 7.0 49,5 140,623 142 Xcel Energy 12/01/16 12/31/16 15.5 !/13/17 13,0 01/30117 17.0 45.50 $ 730,785.46 02/06/17 7.0 52,5 38,366,237 143 Black Hills Energy 01/01/17 l/31/17 15.5 2/8/17 8,0 02114117 6.0 29.50 $ 13,875.00 29,5 409,313 144 BP Energy Company 01/01/17 1131117 15.5 2115/17 15.0 02127117 12.0 42.50 $ 905,279.35 42.5 38,474,372 145 Cima Energy Ltd O!I0!/17 1/31/17 15.5 2114/17 I4.0 02127117 13.0 42.50 s 334,559.27 42.5 14,218,769 146 Colorado Interstate Gas Company 01/01/17 1/31/17 15.5 2113/17 13.0 02123117 10.0 38.50 s 205,866.71 38.5 7,925,868 147 Concord Energy LLC 01/01/)7 1131117 15.5 2/23/17 23.0 02127/17 4.0 42.50 $ 4,374,385.83 42.5 l 85,911,398 148 Enstor Energy Services LLC 01101117 1131/17 15.5 2/9/17 9.0 02127/17 18.0 42.50 $ 1,200,481,88 42.5 51,020,480 149 Enstor Energy Servicos LLC 01101117 1131/17 15.5 2/9/17 9.0 02/27/17 18.0 42.50 $ 10,491,60 42.5 445,893 150 Northwest Pipeline Corporation 01/01117 1131/17 15.5 213117 3.0 02/24/17 21.0 39.50 $ 55,800,00 39.5 2,204,100 151 Questar Pipeline 0!/01117 113 l/I7 15.5 2110/17 10.0 02/23/I 7 13.0 38.50 $ 15,8I7.29 38.5 608,966 152 Red Cedar Gathering Company 01101117 1131117 15.5 2115/17 15.0 02/27/I 7 12.0 42.50 $ 79,462.70 42.S 3,377,165 153 Renegade Oil and Gas Company LLC 01/01117 1131/17 15.5 2127/17 27.0 03/02/17 3.0 45.50 $ 26,690.94 45.5 1,214,438 154 Tallgrass Interstate Gas Transmission LLC 01101/17 1131/17 15.5 2113/17 13.0 02/23117 !0.0 38.50 $ 505,397.02 38.5 19,457,785 155 Wyoming Interstate Company 01101/17 1131/17 15.5 2/9/17 9.0 02/21117 12.0 36.50 s 24,334.00 36.5 888,191 156 Xcel En..-gy 01/0!/l 7 1/31117 15.5 2/13/17 13,0 03/03117 18.0 46.50 s 3,096.62 03/13/17 10.0 56.5 174,959 157 Xcel Energy 01/0!/17 1/31117 15.5 2114/17 14,0 03/03/17 17.0 46.50 $ 791,285.96 03/13/17 10.0 56.5 44,707,657 I58 Black Hills Energy 02101/17 2/28/17 14.0 3/4/17 4.0 03114117 10.0 28.00 $ 13,875.00 28.0 388,500 159 BP Energy Company 02101/17 2128/17 14.0 3/15/17 15,0 03/27117 12.0 41.00 $ 586,880.80 41.0 24,062,113 160 Cima Energy Ltd 02/01/17 2/28/17 14.0 3/20/17 20.0 03/27117 7.0 41.00 $ 204,933.66 41.0 8,402,280 161 Colorado lntemate Gas Company 02101/17 2/28/17 14.0 3/13/17 13,0 03/23117 10.0 37.00 $ 204,879.24 37.0 7,580,532 I 62 Concord Energy LLC 02/01/17 2/28/17 14.0 3/24/17 24.0 03127117 3.0 41.00 $ 2,016,624.64 41.0 82,681,610 163 Enstor Energy Services LLC 02/0I/17 2128/17 14.0 3/15/17 15.0 03/27117 12.0 41.00 $ 745,617.85 41.0 30,570,332 164 Enstor Energy Services LLC 02/01/17 2/28/17 14.0 3/15/17 15.0 03127117 12.0 41.00 $ 7,916.65 41.0 324,583 Page 4 of 5 Schedule CWC4 Atmos Energy Corporation-Colorado Per Books Purchase Ga• Cost Test Year Ending March 31, 2017 Production Month $Days Line Service Date of Invoice Payment Date - Checks Payment Adjusted No. Supplier Start Service Finish Service Lag Invoice Lag Date Paid Lag TotalL:ag Amount Cleared Lag Lag (m)xG) (a) (b) (c) (d) (e) (f) (g) (h) (i) (j) (k) (l) (m) (n) 165 Northwest Pipeline Corpora±ion 02/01/17 2128117 14.0 3/3/17 3.0 03/24/17 21.0 38.00 50,400.00 38.0 1,915,200 166 Questar Pipeline 02/01/17 2/28/17 14.0 3/13/17 13.0 03123/17 10.0 37.00 13,322.55 37.0 492,934 167 Red Cedar Gathering Company 02/01/17 2128/17 14.0 3115117 15,0 03/27/17 12.0 41.00 $ 72,306.64 41.0 2,964,572. 168 Renegade Oil and Gas Company LLC 02/01117 2/28/17 14.0 3/27/17 27.0 03/31/l 7 4.0 45.00 $ 19,351.08 45.0 870,799 169 Tallgrass lnterstate Gas Transmission LLC 02/01/17 2/28/17 14.0 3113/17 13.0 03/23/17 10.0 37.00 $ 505,397.02 37.0 18,699,690 170 Wyomi_ng Interstate Company 02/01/17 2128117 14.0 3/9117 9.0 03/20/17 11.0 34.00 24,334.00 34.0 827,356 171 Xcel Energy 02/01/17 2/28/17 14.0 3114117 14.0 03/29117 15.0 43.00 2,865.92 04/10/17 12.0 55.0 157,626 172 Xcel Energy 02/01/17 2/28/17 14.0 3115117 15.0 0313 l/l 7 16.0 45.00 637,441.96 04110/! 7 10.0 55.0 35,059,308 173 Total 48,571,467 $ 2,060,390,917 174 175 Total Lag 42.42 Page 5 ofS . ' ... , :. ·. ··.:· ·········.· ....:.·.·-· ...· . Schedule CWC5 Atmos Energy Corporation - Colorado Service Area Labor Expense Lag Colorado- Kansas Payroll Analysis Test Year Ending March 31, 2017 Line Check Total Weighted No. Payroll Type Gross Payroll Reference Lead/Lag Reference Float [3] Reference Lead/Lag Dollar Days (a) (b) (c) (d) (e) (t) (g) (h) (i) 1 Employee direct deposits [1] $ 9,971,379 [1}[2] 14.00 WP 5-1 14.00 $ 139,599,301 2 Employee checks [1] 95,954 [1][2] 14.00 WP 5-1 8.93 WP 5-2 22.93 2,200,231 3 PTO 905,309 [2] 78.28 WP5-3 0.09 WP 5-2 78.37 70,945,086 4 TOTAL $ 10,972,642 $ 212,744,618 5 6 TOTAL LABOR LAG 19.39 7 8 Without check float 9 Employee direct deposits $ 9,971,379 [1][2] 14.00 WP 5-1 14.00 $ 139,599,301 10 Employee checks regular pay 95,954 [1][2] 14.00 WP 5-1 14.00 1,343,360 11 PTO 905,309 [2] 78.28 WP 5-3 78.28 70,868,032 12 TOTAL $ 10,972,642 $ 211,810,692 13 14 TOTAL LABOR LAG 19.30 15 16 17 [1] 0.95% of May 27, 2016 payroll payments were paid by check and the remainder by direct deposit 18 [2] Data for Gross Payroll for Colorado direct before allocations 19 [3] PTO Float based on overall check to direct deposit proportions Page 1 of I Atmos Energy Corporation - Colorado Service Area ewe WP 5-1 Direct Labor Test Year Ending March 31, 2017 Start End Morning Evening Total Line of 1st day ofLastDay No.of Service Date Payment Payroll No. of PaJ:: Period of PaJ:: Period DaJ::S Lag Paid Lag Lag (a) (b) (c) (d) (e) (f) (g) 1 03/26/16 04/08/16 14 7.0 04/15/16 7 14 2 04/09/16 04/22/16 14 7.0 04/29/16 7 14 3 04/23/16 05/06/16 14 7.0 05/13/16 7 14 4 05/07/16 05/20/16 14 7.0 05/27/16 7 14 5 05/21116 06/03/16 14 7.0 06/10/16 7 14 6 06/04/16 06/17/16 14 7.0 06/24/16 7 14 7 06/18/16 07/01/16 14 7.0 07/08/16 7 14 8 07/02/16 07/15/16 14 7.0 07/22/16 7 14 9 07116116 07/29/16 14 7.0 08/05/16 7 14 10 07/30/16 08/12/16 14 7.0 08/19/16 7 14 11 08/13/16 08/26/16 14 7.0 09/02/16 7 14 12 08/27/16 09/09/16 14 7.0 09116116 7 14 13 09/10/16 09/23/16 14 7.0 09/30/16 7 14 14 09/24/16 10/07/16 14 7.0 10/14/16 7 14 15 10/08/16 10/21/16 14 7.0 10/28/16 7 14 16 10/22/16 11/04/16 14 7.0 11/11/16 7 14 17 11/05/16 11/18/16 14 7.0 11/25/16 7 14 18 11/19/16 12/02/16 14 7.0 12/09/16 7 14 19 12/03/16 12/16/16 14 7.0 12/23/16 7 14 20 12/17116 12/30/16 14 7.0 01/06/17 7 14 21 12/31/16 01/13/17 14 7.0 01/20/17 7 14 22 01/14/17 01/27117 14 7.0 02/03/17 7 14 23 01/28/17 02/10/17 14 7.0 02/17/17 7 14 24 02/11/17 02/24/17 14 7.0 03/03/17 7 14 25 02/25/17 03/10/17 14 7.0 03/17/17 7 14 26 03/11/17 03/24/17 14 7.0 03/31/17 7 14 27 03/25/17 04/07/17 14 7.0 04/14/17 7 14 28 29 Average 14.0 Page I ofl . ·. -. .' ... -- Atmos Energy Corporation - Colorado Service Area CWCWP5-2 Check Clearing Days Test Year Ending March 31, 2017 Atmos Payroll- Paid by Check May 27, 2016 Line No. Check Cleared Count Percent MaxLag WtdAvg (a) (b) (c) (d) (e) 1 Same Day 1 1.639% 0 0.00 2 Next business day 0 0.000% 3 0.00 3 2 business days 10 16.393% 4 0.66 4 3-7 business days 34 55.738% 7 3.90 5 8-14 business days 10 16.393% 14 2.30 6 >2 weeks 6 9.836% 21 2.07 7 61 100.0% 8.93 Page 1of1 Atmos En4l":rgr Corpomtion Co10.r-ad0; CWCWP5·3 PTOWEIGlITED DAYS CALC{,"LATION Colotn1lo~Kansas Division Test Year Ending M'Arth 31~ 1017 Pavment Dn.te 118116 I/22116 215116 1119116 3/4116 3118116 411116 4/15/16 4129116 5/B/16 512.1116 6/1-0116 612A/16 7181161 7/221161 S/5/li$l 81191161 9121161 91161161 91301161 IM4/161 10/281161 Jl/IOll61 111251161 1219116 12113116 Tata.I EPTOPriotY011rTllkenNE 3,329. 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 .l.;329 E :PTO Prior Yea:r T;i.ken EX Ll.84 520 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 1.704 .EPTOTu~nNE 0 723 797 798 862 94; 1.18) 1.209 947 1.354 i.m 1.710 1,469 1,Sl6 1,656 1,470 l,35S. 1.075 1,524 1,696 1,416 1,393 1,417 1,649 2.m l.9!)0 ;,:;~.492 E PTO T111ken EX 0 60 9Z 18S 180 200 )12 252 tn. 292 348 516 336 592 630 556 380 572 460 332 252 512 392 49l 564 $32 nw iotall'a:kcn 4,513 1,303 889 986 1,042 1,145 1,495 1,461 1.119 1,646 1,485 2,246 E,805 2,128 2,291 2,026 1,738 1.647 1,984 2,-028 1,668 1.905 U09 2.141 2.726 2.,;522 47,746 Totnl Takan m C;,.lcnda:r .2016 986 1,14.Jo 1,461 1,119 1,646 1.485 2.,246 r.aos 2,128 2,292 2,026 l,138. 1,647 1,984 .2,{128 l,661!i 1.905 1.809 2,141 2,726 2,522 PfQ C:::anyoller into 2CH6 7,-089.08 ~al:!:!.dat~~n ~C:eIQ L!e: [1] Beg:iruiioe; of Pay Period 1.2119115 112116 1116116 1130116 2113/I6 2127/!6 3112116 3126116 419/16 4123116 5n116 5121116 6/4116 611&116 7/2116 7116116 7130116 8/ll/16 8127116 9110/16 ~124/IO 1018110 IOf.!:2116 11/:5116 11119116 1213116 E.IidofPayPeriod I/1116 lJl.5116 112-9116 2111116 l/.'.!:6/I6 :3111116 .3.f.25116 418116 412:2116 :5/6116 S/2G/16 613116 6117116 7/1116 7/IS/16 7129116 8112116 8126116 919/10 9123116 rnn116 Wf.!:l/I6 ll/4/I6 11118116 1212116 12116/16 Midpoint of Pay Period 12125115 113116 ll.U16 215116 2119116 )/4116 3/18116 411/16 4115116 4/W/16 5/13ii6 5127116 6110/16 6124/16 718116 7122116 :&1.5116 8119116 9/2116 9/16116 91>0/16 10114116 10128116 11111/16 1112:5/16 12/9116 Lag from Mid Year (18!)) (175) (161) (147) (13l) (119) (IDS) (91) (77) (63) (49) (;lSJ (21) (7) 7 21 ;5 49 63 77 91 105 119 m 147 161 Lag .5-om Mid Year ('.Prior Yci: 176 190 204 218 :!:3l Z46 200 274 288 302 316 330 344 358 372 386 400 414 428. 442 456 470 484 498 512 526 PTO Ta'ken~ Earn~d !his YcBl 0 0 0 0 0 0 0 711 l,1I9 1.646 1,485 2.,246 1,805 2,128 2.292 2,026 1,738 1,647 1,984 2,-02& 1,668 1.905 1.809 2,141 2.726 l,S.22 :3.S,623 PTO R CBny 0vel'" 0 7"3 889 986 1,042 l,14j l,45Jj 750 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 7,0851 Weighted Monthly Los NIA 190 204 218 232 246 260 (77) (63) (49) (;35) (21) (7) 7 21 35 40 63 77 91 105 119 m 147 161 Pertcnt of .&lll'l.'ltal PTO taken 0.0% LS% 2..1% 2.3% 2.4% 2.7% 3.:5% 3.4%" 2.6% 3.9% 3.5% .S..3% 4.2% 5.0% 5.4% 4,'71'.4 4.1% 3.9% 4.6% 4.7% 3.9% 4.S% 4.2% 5.0% 6.4% 5.5'% Weighted Annual Las NIA 3.48 4.24 5.03 5.66 6.59 9.10 3.30 (2.02) (2.4') (1.70) (1.84) (0.89) (0.35) 0.38 1,00 1.42 1.89 2.93 3.66 3.55 4.68 5.04 6.67 9.38 9.50 78.28 Beginning of Ye:ii:r lll/16 .Endof"ieur 12131116 M'idpointorY~ 7/1116 fiirtd~o-intofPrior Ye.or 712/ll [l] Maximum omoun.t of PTO canied ovel'" is l ~ek, all athofl(I" PTO [;i. taklilll in :tlJeo yeo.r it is accrued. PTO ~nied over is rusum.ed to. be mke- f':li'St in the new calendar year. PTO is accrued thr.ou~out the co.1end1tr year so is accrued Ol\ a'l/erus,e ;111 mid y.car {July 1), PTO token in 11 pii.y period is .11.:Ssurned to. be take:n. at the middle of the po.y period. Prior year PTO .fl.~sUmt!d to bi:: takl!:n in lo~ DE>cE>mber Page! ofl Atmos Energy Corporation - Colorado Service Area CWCWP5-4 Employee Percent Paid by Check Test Year Ending March 31, 2017 Sample Payroll of 05/27 /16 Line No. Description % of Payments #of Payments (a) (b) (c) 1 Employee direct deposits 99.05% 6,339 2 Third Party direct deposits 0.00% 0 3 Employee checks 0.95% 61 4 3rd Party checks 0.00% 0 5 Totals 100% 6,400 6 7 Percent of employees paid by check 0.95% Page 1 of I Schedule CWC6 Atmos Energy Corporation - Colorado Service Area Other O&M Payment Lag Test Year Ending March 31, 2017 Line Invoice Invoice Colorado Service Period Midpoint Payment Payment Weighted No. Vendor Date Amount Amount Invoice# Payment TyQe From To Svc Period Date Paid Cleared Laa Pm± Laa (a) (b) (c) (d) (•) (f) (g) (h) (i) (i) (k) (1)-k-(i orb) (m)-(l*d) A AND R TRADUCTORES 9-Jul-16 $ 280.00 $ 25.76 ATl60427Y CHECK 27-Apr-16 9-Jul-16 2-Jun-16 13-Jul-16 28-Jul-16 56 $ 1,443 2 ABRITELLC 31-May-16 550 550 ll07 CHECK l-May-16 31-May-16 16-May-16 27-Jun-16 7-Jul-16 52 28,600 3 A KIDS PLACE INC 2-Mar-17 1,000 1,000 CHE030217 CHECK 2-Mar-17 2-Mar-17 2-Mar-l7 17-Mar-17 4-Apr-17 33 33,000 4 ACES HIGH SERVICES INC 31-Aug-16 179 179 A19!93l CHECK l-Aug·16 31-Aug-16 16-Aug-16 26-Sep-!6 ll-Oct-16 56 10,024 5 ADVANCEDALAR.M:COMPA.'IY l-Nov-16 201 201 98071 CHECK l-Nov-16 31-Jan-17 16-Dec-16 21-Nov-16 29-Nov-16 (18) (3,618) 6 AIRGAS USA LLC l-Jun-16 155 155 9051922108 CHECK l-Jun-16 1-Jun-16 l-Jun-16 27-Jun-16 30-Jun-16 29 4,482 7 AIRGAS USA LLC 19-Jan-17 267 267 9059393022 CHECK 19-Jan-17 19-Jan-17 19-Jan-17 17-Feb-17 24-Feb-17 36 9,597 8 AIRGAS USA LLC 14-Feb-17 92 92 9060280373 CHECK 14-Feb-17 14-Fob-17 14-Fob-17 13-Mar-17 17-Mar-!7 31 2,839 9 ALL COPY PRODUCTS 22-Feb-17 138 138 AR2036598 Direct Deposit 22-Feb-17 22-Fob-17 22-Feb-17 20-Mar-17 20-Mar-17 26 3,580 10 AMERICA<'< ELECTRlC COMPANY 3-Aug-16 19 19 1932669863 CHECK 3-Aug-16 3-Aug-16 3-Aug-16 29-Aug-16 6-Sop-16 34 635 11 APEX INSTRUMENTS INC 23-Sep-16 513 513 26112 Direct Deposit 23-Sep-16 23-Sep-16 23-Sep-16 17-Jan-17 17-Jan-17 116 59,479 12 APPLIED CONTROL EQUIPMENT LLC lO-Aug-16 965 965 CD10!0573 CHECK 10-Aug-16 10·Augnl6 10-Aug-!6 14-Sep-16 20-Sop-16 41 39,585 13 APPLIED CONTROL EQUIPMENT LLC 27-Dec-16 150 150 CD1014486 CHECK 23-Dec-16 23-Dec-16 23-Doc-16 25-Jan-17 31-Jan-17 39 5,839 14 AT&T 9-Jun-16 2,134 21 214 2062200 022 70616-0 CHECK 9-Jun-16 8-Jul-16 23-Jun-16 5-Jul-16 12-Jul-16 19 393 15 AT&T 5-Jul-16 1,250 166 8310001533 5100716-070 CHECK 5-Jul-16 4-Aug-16 20-Jul-!6 13-Jul-16 22-Jul-16 2 333 16 AT&T 19-Aug-16 39 39 055 264 3866 0010816-08 CHECK 20-Jul-16 19-Aug-16 4-Aug-16 9-Sop-16 19-Sep-16 46 1,776 17 AT&T 9-Sep-16 2,141 21 214 2062200 022 70916-0 CHECK 9-Sep-16 8-0ct-16 23-Sep-16 26-Sep-16 4-0ct-16 11 228 18 AT&T 9-0ct-16 2,138 21 2142062200 022 71016-1 CHECK 9-0ct-16 8-Nov-16 24-0ct-16 31-0ct-16 8-Nov-16 15 311 19 AT&T l-Feb-l7 9,540 12 800292364700217-0201 t:CHECK 1-Fob-17 28-Feb-17 14-Feb-17 17-Feb-17 24-Feb-17 10 117 20 AT&T 1-Mar-17 9,472 11 S00292364700317-0301 l:CHECK 1-Mar-17 31-Mar-17 16-Mar-17 17-Mar-17 27-Mar-17 11 124 21 AT&T MOBILITY 24-Jan-17 46,766 81 29181920117-012417 CHECK 24-Jan-17 24-Feb-17 S-Feb-17 1-Feb-17 10-Fob-17 2 162 22 ATMOS ENERGY CORPORATIOJS 9-Mar-16 74 74 3019255332 030916 CHECK 10-Feb-16 9-Mar-16 24-Feb-16 1-Apr-16 5-Apr-16 41 3,050 23 AUTOMOTIVE RESOURCES INTERNATIONAi 6-May-16 490,979 23,538 ARI 106-MAY-16 Direct Deposh 1-Apr-16 30-Apr-16 15-Apr-16 9-May-16 9-May-16 24 564,909 24 AUTOMOTIVE RESOURCES INTERNATIONAI 6-Sep-16 430,245 23,335 ARI I 06-SEP-16 Direct Deposit 1-Aug-16 31-Aug-16 16-Aug-16 7-Sep-16 7-Sep-16 22 513,364 25 Balandron, Mich...! A (Mike) 31-0ct-16 10 lO IEXP-1504185 Direct Deposit 25-0ct-16 25-0ct-16 25-0ct-16 2-Nov-16 2-Nov-16 8 84 26 Balandron, Mich...! A (Mike) 31-0ct-16 26 26 IEXP-1504168 Direot Deposit 27-0ct-16 27-0ct-16 27-0ct-16 2-Nov-16 2-Nov-16 6 156 27 BANK OF AMERICA 16-Apr-16 553 487 060_ALAN.MANNING_tEFT 16-Mar-16 14-Apr-16 30-Mar-16 28-Apr-16 28-Apr-16 29 14,114 28 BANK OF AMERICA 16-Apr-16 194 194 060 MICHAEL.COOPEREFT 15-Mar-16 5-Apr-16 25-Mar-16 28-Apr-16 28-Apr-16 34 6,585 29 BA.'1K OF AMERICA 16-Apr-16 217 205 060-JUAl'<.REYES APR-EFT 24-Mar-16 12-Apr-16 2-Apr-16 28-Apr-16 28-Apr-16 26 5,333 30 BA..'1K OF AMERICA 16-May-16 123 123 060-NICK.PLANANSKYEFT 15-Apr-16 IO-May-16 27-Apr-16 27-May-16 27-May-16 30 3,696 31 BA."IK OF AMERICA !6-May-16 114 114 060=CHRISTINA.RITSCJEFT 28-Apr-16 28-Apr-16 28-Apr-16 27-May-16 27-May-16 29 3,313 32 BA.'<"K OF AMERICA 16-May-16 247 247 060 WILLIAM.FOLEY !EFT 7-Apr-16 25-Apr-16 16-Apr-16 27-May-16 27-May-16 41 10,125 33 BA.i"!K OF AMERICA 16-Jun-16 18 18 060- RANDY.VALENCIP EFT 16-May-16 16-May-16 !6-May-16 28-Jun-16 28-Jun-16 43 759 34 BANK OF AMERICA 16-Jul-16 694 694 060-KEVIN.ROSS JUL-:EFT 20-Jun-16 22-Jun-16 21-Jun-16 28-Jul-16 28-Jul-16 37 25,681 35 BANK OF AMERICA 16-Jul-16 66 66 060)AMES.HUBBARD_ EFT 25-Jun-16 28-Jun-16 26-Jun-16 28-Jul-16 28-Jul-16 32 2,119 36 BANK OF AMERICA !6-Jul-16 482 482 060 MARC.SCHELLER EFT 10-Jun-16 23-Jun-16 16-Jun-16 28-Jul-16 28-Jul-16 42 20,251 37 BANK OF AMERICA !6-Jul-16 173 173 060-LOGAN.SANSONI - EFT 17-Jun-16 27-Jun-16 22-Jun-16 28-Jul-16 28-Jul-16 36 6,246 38 BANK OF AMERICA 16-Jul-16 402 402 060- MICHAEL.JOHNSO EFT 22-Jun-16 22-Jun-16 22-Jun-16 28-Jul-!6 28-Jul-16 36 14,486 39 BANK OF AMERICA 16-Aug-16 80 29 060···HAROLD.BROWN EFT 4-Aug-16 15-Aug-16 9-Aug-16 30-Aug-16 30-Aug-16 21 612 40 BANK OF AMERICA 16-Aug-16 84 84 060- MICHAEL. COOPER EFT 18-Jul-16 22-Jul-16 20-Jul-16 30-Aug-16 30-Aug-16 41 3,436 41 BANK OF AMERICA 16-Aug-16 229 229 060=DA V!D.HERGENREEFT 5-Aug-16 5-Aug-16 5-Aug-16 30-Aug-16 30·Augnl6 25 5,725 42 BANK OF AMERICA 16-Sep-16 68 68 060 HAROLD.NELSON EFT 19-Jul-16 25-Aug-16 6-Aug-16 28-Sep-16 28-Sep-16 53 3,582 43 BANK OF AMERICA 16-Sep-16 176 176 060- CHRISTINA.RITScl EFT 25-Aug-16 2-Sep-16 29-Aug-16 28-Sep-16 28-Sep-16 30 5,289 44 BANK OF AMERICA 16-Sep-16 38 38 060-JUSTIN.DUFVA SEEFT 31-Aug-16 6-Sep-16 3-Sep-16 28-Sep-16 28-Sep-16 25 943 45 BANK OF AMERICA 16-Sop-16 77 77 060-TREVOR.MALTBY EFT 13-Sep-16 !3-Sep-16 13-Sep-16 28-Sep-16 28-Sep-16 15 l,152 46 BA.i'-'K OF AMERICA 16-Sop-16 380 380 060-JENlFEllHERNANiEFT 4-Aug-16 !5-Sep-16 25-Aug-16 28-Sep-16 28-Sep-16 34 12,907 47 BANK OF AMERICA 16-0ct-16 490 490 060-KOLBY.PALMER CEFT 17-Sep-16 16-0ct-16 1-0ct-16 28-0ct-16 28-0ct-16 27 13,228 48 BANK OF AMERICA 16-0ct-16 155 24 060-DAVID.GORE OCrEFT 20-Sep-16 6-0ct-16 28-Sop-16 28-0ct-16 28-0ct-16 30 731 49 BANK OF AMERICA 16-Nov-16 592 592 060=PAUL.VANVLEET _EFT 21-0ot-16 24-0ct-16 22-0ct-16 30-Nov-16 30-Nov-16 39 23.071 50 BANK OF AMERICA 16-Nov-16 28 28 060 LOGAN.SANSON! .EFT 19-0ct-16 8-Nov-16 29-0ot-!6 30-Nov-16 30-Nov-16 32 896 51 BANK OF AMERICA 16-Dec-16 48 48 060-JUSTIN.DUFVA DIEFT 16-Nov-16 1-Doc-16 23-Nov-16 30-Dec-16 30-Dec-16 37 l,776 52 BANK OF AMERICA 16-Dec-16 213 62 060-DAMON.MCCAIN :EFT 16-Nov-16 5-Dec-16 25-Nov-16 30-Dec-16 30-Dec-16 35 2,179 53 BANK OF AMERICA 16-Dec-16 663 663 060-ADAM.STRAUCH -!EFT 28-Nov-16 7-Dec-16 2-Dec-16 30-Dec-16 30-Dec-16 28 18,556 54 BANK OF AMERICA 16-Jan-l 7 1.603 1,603 060-CAL.DOBIE JAl'<-l"EFT 20-Dec-16 14-Jan-17 l-Jan-17 30-Jan-17 30-Jan-17 29 46,491 55 BANK OF AMERICA 16-Jan-l 7 253 253 060-CHRISTINAluTSCIEFT 27-Dec-16 ll-Jan-17 3-Jan-17 30-Jan-17 30-Jan-17 27 6,836 56 BANK OF AMERICA 16-Feb-17 2,058 2,058 060=ROBINEITE.KNOC EFT 23-Nov-16 14-Feb-17 3-Jan-17 28-Feb-17 28-Feb-17 56 ll5,225 Page 1 of7 Schedule CWC6 Atmos Energy Corporation - Colorado Service Are.a Other O&M Payment Lag Test Year Ending March 31,2017 Line Invoice Invoice Colorado Service Period Midpoint Payment Payment Weighted No. Vendor Date Amount Amount Invoice# P!!j'.mentT~e• From To Svc Period Date Paid Cleared Laa PrntLa2 (•) (b) (c) (d) (e) (f) (g) (h) (i) Gl (k) (I)= k-(i orb) (m)-(l'd) 57 BANK OF AMERlCA 16-Feb-17 388 388 060 MIKE.HERBST FE! EFT !6-Jan-17 10-Feb-17 28-Jan-17 28-Feb-17 28-Feb-17 31 12,033 58 BANK OF AMERlCA l6-Mar-l7 348 348 060=CAL.D0BIE_MAR-:EFT 20-Feb-17 15-Mar-17 3-Mar-17 28-Mar-17 28-Mar-17 25 8,688 59 BLACK HILLS ENERGY 14-Nov-16 143 143 122732l853 111416 CHECK 3-0ct-16 ll-Nov-16 22-0ct-16 2-Dec-16 9-Dec-16 48 6,870 60 BLACK HILLS ENERGY 13-Jan-!7 20 20 5224955189-011317 CHECK 12-Doc-16 12-Jan-17 27-Deo-16 27-Jan-17 3-Feb-17 38 758 61 BLACK HILLS ENERGY 16-Mar-17 131 131 1227321853-031617 CHECK 31-Jan-17 15-Mar-17 21-Feh-17 24-Mar-17 31-Mar-17 38 4,983 62 Blake, Michael S (Mike) 18-Nov-16 758 310 IEXF-15072l3 Diroct Deposit 13-Nov-16 6-Deo-16 24-Nov-16 21-Nov-16 21-Nov-16 (4) (1,241) 63 BLUE ONION 17-Jan-17 813 813 038585 CHECK 17-Jan-17 17-Jan-17 17-Jan-17 27-Jan-17 7-Feb-17 21 17,063 64 BOB LILLY PROFESSIONAL PROMC 22-Jul-16 484 69 52879 Direct Deposit l-Jun-16 30-Jun-16 l5-Jun-16 16-Aug-16 16-Aug-16 62 4,290 65 BOB LILLY PROFESSIONAL PROMC 13-0ct-16 30 30 55113 Direct Deposit 13-0ct-16 13-0ct-16 13-0ct-16 7-Nov-16 7-Nov-16 25 751 66 BOB LILLY PROFESSIONAL PROMC 31-Deo-16 594 85 56985 Diroct Deposit l-Oct-16 31-0ct-16 16-0ct-16 26-Jan-17 26-Jan-17 102 8,670 67 Boutwell, Eric (Eric) 27-Mar-17 1,153 1,153 IEXP-2485468 Direct Deposit 31-Jan-17 3-Feb-17 l-Feb-17 29-Mar-17 29-Mm-17 56 64,594 68 BUCKEYE WELDING SUPPLY CO INC 6-May-16 21 21 9564208 CHECK 6-May-16 6-May-16 6-May-16 3-Jun-16 13-Jun-16 38 791 69 BUCKEYE WELDING SUPPLY CO INC 10-Jun-16 310 310 9566670 CHECK 10-Jun-16 10-Jun-16 10-Jun-16 5-Jul-16 12-Jul-16 32 9,919 70 BUCKEYE WELDING SUPPLY CO INC 8-Sep-16 301 301 544087 CHECK 8-Sep-16 8-Sep-16 8-Sep-16 23-Jan-17 31-Jan-17 145 43,636 71 BUCKEYE WELDING SUPPLY CO INC 29-Nov-16 284 284 9578949 CHECK 29-Nov-16 29-Nov-16 29-Nov-16 6-Jan-17 17-Jan-17 49 13,893 72 Callahan, Lorinda 22-Aug-16 10,962 75 IEXF-1418933 Djrect Deposit l-Aug-16 22-Aug-16 l!-Aug-16 25-Aug-16 25-Aug-16 14 1.050 73 CASCADE WATER COFFEE CO INC 2-May-l6 116 116 519359 CHECK 2-Moy-16 2-May-16 2-May-16 27-May-16 2-Jun-16 31 3.596 74 CASCADE WATER COFFEE CO INC 22-Aug-16 31 31 14978 CHECK 22-Aug-16 22-Aug-l6 22-Aug-16 16-Sep-16 27-Sep-16 36 1,103 75 CASCADE WATER COFFEE CO INC 12-Sep-16 29 29 924199 CHECK 12-Sep-16 12-Sep-16 12-Sep-16 7-0ct-16 13-0ct-16 31 903 76 CASCADE WATER COFFEE CO INC 19-Sop-16 23 23 522928 CHECK 19-Sep-16 l9-Sep-l6 19-Sep-16 14-0ct-16 24-0ct-16 35 789 77 CENTURYLINK 16-Nov-15 4,014 4,014 K303l119267034Ml115-CHECK 30-Sep-15 15-Dec-15 7-Nov-15 6-May-16 16-May-16 191 766,7!0 78 CENTURYLINK 19-MOf-16 53 53 7193958361 914B0316-03CHECK 19-Mar-16 !8-Apr-16 3-Apr-16 8-Apr-16 14-Apr-16 ll 583 79 CENTURYLL"!K 19-Mm-16 50 50 7193954881 869B03!6-03CHECK 19-Mar-16 18-Apr-16 3-Apr-16 13-Apr-16 20-Apr-16 17 857 80 CEl\'TURYLINK 22-Mm-16 55 55 9702846356 222B0316-03CHECK 22-Mar-16 21-Apr-16 6-Apr-16 13-Apr-16 20-Apr-16 14 764 81 CENTURYLINK l6-Mar-16 51 51 9707379155 758B0316-03 CHECK 16-Mar-16 15-Apr-16 31-MOf-16 6-Apr-16 14-Apr-16 14 716 82 CENTURYLINK 22-Mar-16 58 58 9702473813 784B0316-03 CHECK 22-Mar-16 21-Apr-16 6-Apr-16 13-Apr-16 20-Apr-16 14 807 83 CENTURYLINK 4-Apr-l6 174 174 9703049089 246B0416-04 CHECK 4-Apr-16 3-May-16 18-Apr-16 22-Apr-16 2-May-16 14 2,430 S4 CENT!JR.YLINK 22-Apr-16 730 730 K9702473996 48SM0416-CHECK 22-Apr-l6 21-May-16 6-May-16 9-May-16 16-May-16 10 7,296 85 CENTURYLINK 23-Apr-16 18 18 3007790880416-042316 CHECK 23-Apr-16 22-May-16 7-May-16 11-May-16 23-May-16 16 290 86 CEN11JRYLINK 4-May-16 54 54 9703780599 243B0516-05 CHECK 4-May-16 3-Jun-16 19-May-16 6-Jun-16 14-Jun-16 26 1,414 87 CENT!JR.YLINK 10-May-16 51 51 9703521511 583B0516-05 CHECK 10-May-16 9-Jun-16 25-May-16 8-Jun-16 14-Jun-16 20 1,022 88 CENTURYLINK 10-May-16 54 54 9703525482 205B0516-05CHECK 10-May-16 9-Jun-16 25-May-16 8-Jun-16 14-Jun-16 20 1,084 89 CENTURYLINK 25-May-16 56 56 97064l2775 083B0516-05 CHECK 25-May-16 24-Jun-16 9-Jun-16 22-Jun-16 l-Jul-16 22 1,225 90 CENTURYLINK 25-May-16 52 52 9703304263482B 052516 CHECK 25-May-16 24-Jun-!6 9-Jun-16 8-Jun-16 14-Jun-16 s 258 91 CENTURYLINK 7-Jun-16 51 51 7195395062 402B0616-0e CHECK 7-Jun-16 6-Jul-16 21-Jun-16 8-Jul-16 21-Jul-16 30 1,543 92 CENTURYLINK 19-Jun-16 54 54 9703535656 223B0616-0eCHECK 19-Jun-16 18-Jul-16 3-Jul-16 13-Jul-16 2l-Jul-16 18 975 93 CENTURYLINK 22-Jun-16 55 55 9707379023 043B0616-0eCHECK 22-Jun-16 21-Jul-16 6-Jul-16 22-Jul-16 28-Jul-16 22 1,208 94 CENTURYLINK 22-Jun-16 714 714 K3033525890 503M06!6-CHECK 22-Jun-16 21-Jul-16 6-Jul-16 B-Jul-16 2l-Jul-16 15 10,712 95 CENTURYLINK l-Jul-16 73 73 9706426375 247B0716-07CHECK l-Jul-16 31-Jul-16 16-Jul-16 27-Jul-16 4-Aug-16 19 1,385 96 CENTURYLINK 4-Jul-16 222 222 9703041952 620B0716-07CHECK 4-Jul-16 3-Aug-16 19-Jul-16 27-Jul-16 4-Aug-16 16 3,558 97 CENTURYLINK 10-Jul-16 52 52 9703521511 583B0716-07 CHECK 10-Jul-16 9-Aug-16 25-Jul-16 10-Aug-16 19-Aug-16 25 1,290 98 CENTURYLINK 19-Jul-16 57 57 9703757703 241B0716-07CHECK 19-Jul-16 18-Aug-16 3-Aug-16 22-Aug-16 30-Aug-16 27 1,530 99 CENTURYLINK 22-Jul-16 56 56 9707850113 230B0716-07CHECK 22-Jul-16 21-Aug-16 6-Aug-16 29-Aug-16 7-Sep-16 32 1,780 100 CENT!JR.YLINK 4-Aug-16 57 57 9708751028 200B0816-08 CHECK 4nAug~16 3-Sep-16 19-Aug-16 24-Aug-16 2-Sep-16 14 796 101 CENTURYLINK 4-Aug-16 56 56 9703781584 594B0816-08 CHECK 4-Aug-16 3-Sep-16 19-Aug-16 22-Aug-16 30-Aug-16 11 614 102 CENTURYLINK 4-Aug-16 54 54 3037321042 550B0816-08 CHECK 4-Aug-16 3-Sep-16 19-Aug-16 22-Aug-16 30-Aug-16 11 589 I 03 CENT!JR.YLINK 4-Aug-16 224 224 9703041952 620B0816-08 CHECK 4-Aug-16 3-Sep-16 19-Aug-16 24-Aug-16 2-Sep-16 14 3,135 104 CEl\'T!JR.YLINK 13-Aug-16 57 57 7197840828 413B0816-08 CHECK 13-Aug-16 12-Sep-16 28-Aug-16 21-Sep-16 30-Sep-16 33 1,873 105 CENTURYLINK 22-Aug-16 54 54 9704545429 247B0816-08 CHECK 22-Aug-16 21-Sep-16 6-Sep-16 21-Sep-16 30-Sep-16 24 1,296 106 CENTu'RYl,JNK 22-Sep-16 55 55 9708341291 878B0916-0S CHECK 22-Sep-16 21-0ct-16 6-0ot-16 19-0ct-16 31-0ot-16 25 1,376 107 CENTURYLINK 22-Sep-16 54 54 9708342741 075B0916-0S CHECK 22-Sep-16 21-0ct-16 6-0ct-16 19-0ct-16 31-0ct-16 2S 1,338 108 CENTURYLINK 7-0ct-16 55 55 9703460041 OOIB1016-1CCHECK 7-0ct-16 6-Nov-16 22-0ct-16 28-0ct-16 8-Nov-16 17 931 l 09 CENTUR.YLINK 22-0ct-16 54 54 9708342741 07SB1016-IC CHECK 22-0ct-l6 21-Nov-16 6-Nov-16 24-0ct-16 1-Nov-16 (5) (268) 11 o CEl\'TURYLINK 7-Nov-16 56 56 9708719426194Blll6-11CHECK 7-Nov-16 6-Deo-16 21-Nov-16 9-Nov-16 17-Nov-16 (5) (279) 11 l CENTu"R.YLINK 22-Nov-16 57 57 9704541563431Bll16-11CHECK 22-Nov-16 21-Deo-16 6-Doc-16 11-Jan-17 19-Jan-17 44 2,523 112 CENTu"R.YLINK 23-Nov-16 360 360 3007792401116-112316 CHECK 23-Nov-16 22-Dec-16 7-Dec-16 9-Doc-16 21-Dec-16 14 5,042 113 CENTURYLINK 23-Nov-!6 191 191 3007920761116-112316 CHECK 23-Nov-16 22-Dec-16 7-Doo-16 20-Jan-17 26-Jan-17 50 9,575 Page 2 of7 Schedule CWC6 Atmos Energy Corporation - Colorado Service Area Other O&M Payment Lag Test Year End;ng March 31, 2017 Line Invoice Invoice Colorado Service Period Midpoint Payment Payment Weighted No. Vendor Dato Amount Amount Invoice# Payment T:rn• From To Svc Period Date Paid Cleared L!lB: PmtLag (a) (b) (c) (d) (•) ((I (g) (h) (i) (j) (k) (l)=k·(iorb) (m)=(l"d) 114 CENTURYLINK 2S-Nov-16 51 51 9703304263482B ll25!6CHECK 25-0ct-16 24-Dec-16 24-Nov-16 14-Dec-16 23-Dec-16 29 1,493 115 CENTURYLINK 13-Dec-16 53 53 9708265131 176BI216-l2CHECK 13-Dec-!6 12-Jan-17 28-Deo-16 30-Dec-16 4-Jon-17 7 372 !16 CENTURYLINK 19-Dec-16 55 55 9708700209 188B1216-12CHECK 19-Doc-16 18-Jan-17 3-Jan-17 ll-Jan-17 19-Jan-17 16 88S 117 CENTURYLINK 22-Dec-16 52 52 9702846574 228Bl216-12 CHECK 22-Dec-16 21-Jan-17 6-Jon-17 ll-Jan-17 19-Jan-17 13 679 118 CENTURYLINI< 22-Dec-16 58 58 9702473813 784Bl216-12CHECK 22-Dec-16 21-Jan-17 6-Jan-17 11-Jan-17 19-Jan-17 13 751 !l9 CENTURYLINK 22-Dec-16 52 52 970737239S 259Bl216-12CHECK 22-Dec-16 21-Jan-17 6-Jan-17 20-Jan-17 30-Jan-17 24 1,248 120 CENTURYLINK l-Jan-17 74 74 970642637S 247BOl l 7-0lCHECK 1-Jan-17 31-Jan-17 16-Jan-17 22-Feb-17 l-Mar-17 44 3,252 121 CENTURYLINK 7-Jan-17 39 39 9703822261 811BOll7-0!CHECK 7-Jan-17 6-Feb-17 22-Jan-17 6-Feb-17 14-Feb-17 23 891 122 CENTURYLINI< 22-Jan-17 54 54 9702841116216BOl17-0ICHECK 22-Jan-l7 21-Feb-17 6-Feb-17 22-Feb-17 l-Mar-17 23 1,239 123 CENTURYLINK 22-Jan-17 54 54 9708342741 075BOll7-0ICHECK 22-Jan-17 21-Feb-17 6-Feb-17 10-Mar-17 22-Mar-17 44 2,372 124 CENTURYLINK 22-Jan-17 52 52 9702847825 234B0ll7-0ICHECK 22-Jan-17 21-Mar-17 20-Feb-17 22-Feb-17 1-Mar-17 9 465 125 Cfil\'TURYLINK 25-Jan-17 56 56 9706412775083BD117-0ICHECK 25-Jan-17 24-Feb-17 9-Feb-17 22-Feb·l7 l-Mar-17 20 1,127 126 CENTURYLINK ID-Feb-17 59 59 9703308038 969B0217-02CHECK 10-Feb-17 9-Mar-\7 23-Feb-!7 17-Mar-17 28-Mar-17 33 1,953 127 Cfil\'TURYLINK 22-Feb-17 56 56 9707852416 355B0217-02CHECK 22-Feb-17 21-Mar-17 7-Mm-17 10-Mar-17 22-Mar-17 15 836 128 CENTURYLINK 16-Mar-17 166 166 9705657585 580B03 l 7-03 CHECK 16-Mar-17 15-Apr-17 31-Mar-17 24-Mm-!7 5-Apr-17 5 831 129 CENTURYLINK 22-Mar-17 55 55 9707852416 355B0317-03CHECK 22-Mar-17 21-Apr-17 6-Apr-17 29-Mm-17 5-Apr-17 (!) (55) 130 CENTURYLINK 22-Mar-17 52 52 9702847825 234B03 I 7-03 CHECK 22-Mm-17 21-Apr-\7 6-Apr-17 29-Mar-17 5-Apr-17 (!) (52) 131 CHARTER COMMUNICATION! 2-Feb-17 1,366 1,366 8313 10 048 03246670217CHECK 1-Fob-17 28-Feb-17 14-Feb-17 22-Feb-17 3-Mar-17 17 23,222 132 Cl!\'TAS CORPORATIOl'.' 29-Apr-!6 42 42 8402699792 CHECK 29-Apr-16 29-Apr-16 29-Apr-16 23-May-!6 31-May-16 32 1,331 133 Cll\'TAS CORPORAT!Ol'.' 30-Apr-16 218 218 8402705371 CHECK 30-Apr-16 30-Apr-16 30-Apr-16 25-May-16 3-Jun-16 34 7,421 134 CINTAS CORPORATIOJ'.' 31-Aug-16 60 60 9010518158 CHECK 31-Aug-16 31-Aug-16 3\-Aug-\6 17-0ct-16 26-0ct-16 56 3,362 135 CINTAS CORPORATIOJ'.' 25-Nov-16 79 79 737431328 CHECK 25-Nov-16 25-Nov-16 25-Nov-16 7-Dec-16 15-Dec-16 20 1,574 136 CINTAS CORPORAT!Ol'.' 30-Dec-16 123 123 737438726 CHECK 30-Dec-16 30-Dec-16 30-Dec-16 11-Jan-17 18-Jan-17 19 2,328 137 CINTAS CORPORAT!Ol'.' 25-Jan-17 355 355 5007013133 CHECK 25-Jan-17 25-Jan-17 25-Jan-17 20-Feb-17 27-Feb-17 33 11,711 138 CINTAS CORPORAT!Ol'.' 3-Mar-17 67 67 737452015 CHECK 3-Mar-17 3-Mar-17 3-Mar-17 31-Mar-17 IO-Apr-17 38 2,563 139 CITY OF CORTEZ 18-Apr-16 60 60 33157382 041816 CHECK 4-Mar-16 4-Apr-16 19-Mar-16 29-Apr-16 9-May-16 51 3,070 140 CITY OF CORTEZ 28-Feb-17 131 131 343001 022817 CHECK 17-Jan-16 I 7-Feb-16 l-Feb-16 17-Mar-17 27-Mar-17 420 54,852 141 CITYOFDALLAS 20-Mar-17 289 6 050452713207 CHECK 20-Feb-17 20-Mar-17 6-Mar-17 31-Mar-17 !3-Apr-17 38 212 142 CITY OF GREELEY 9-Dec-16 !06 !06 03176309801_1209!6 CHECK 9-Nov-16 9-Dec-16 24-Nov-16 28-Dec-!6 5-Jan-17 42 4,432 143 CITY OF GREELEY 3-Mar-17 75 75 OOIAODl341 CHECK l-Jan-17 16-Jan-17 8-Jan-l 7 27-Mar-17 4-Apr-17 86 6,450 144 CITY OF GUNNISOJ'.' 24-Mar-16 84 84 2S5000000 032416 CHECK 3-Feb-16 10-Mar-16 21-Feb-16 6·Apr-16 14-Apr-16 53 4,428 145 CITY OF GUNNISOJ'.' 24-Jun-16 348 348 235500000-062416 CHECK 8-May-16 10-Jun-16 24-Moy-!6 !3-Jul-16 2-Aug-16 70 24,389 146 CITY OF LAMAR 30-Mar-!6 22 22 17224 033016 CHECK l-Mar-16 31-Mar-16 16-Mar-16 13-Apr-16 20-Apr-16 35 770 147 CITYOFLAMAR 29-Jun-16 52 52 17202-062916 CHECK 16-May-16 17-Jun-16 1-Jun-16 11-Jul-16 20-Jul-16 49 2,540 148 CITY OF LAMAR 30·Aug-16 59 59 17202-083016 CHECK 1-Aug-16 3!-Aug-16 16-Aug-16 14-Sep-16 21-Sep-16 36 2,114 149 CITY OF LAMAR 27-Jan-17 56 56 661 Ol2717 CHECK 1-Jan-17 31-Jan-17 !6-Jan-17 13-Feb-17 22-Feb-l 7 37 2,083 ISO CITY OF LAMAR 24-Feb-17 22 22 2279_022417 CHECK 5-Jan-l 7 3-Feb-17 19-Jan-17 22-Mar-17 29-Mar-17 69 1,518 151 CITY OF STEAMBOAT SPRING:; 31-Jul-16 63 63 3470401_073116 CHECK l-Jul-16 31-Jul·\6 16-Jul-16 IS-Aug-16 24-Aug-!6 39 2,469 152 CITY OF STEA..\IBOAT SPRING> 3!-0ct-16 23 23 3520200_103116 CHECK 1-0ct-16 31-0ct-16 16-0ct-16 18-Nov-16 29-Nov-16 44 1,002 153 CITY OF STEA..\IBOAT SPRINGo 31-Dec-16 113 113 3470401 123116 CHECK l-Dec-16 31-Dec-16 16-Dec-16 16-Jan-17 24-Jan-17 39 4,419 154 COMCAST CABLEVIS!Ol\ 19-Nov-16 141 141 8497 30 J26 13739721 llf CHECK 19-Nov-16 18-Dec-16 3-Doc-16 7-Dec-16 16-Dec-16 13 1,838 155 COMCAST CABLEVIS!Ol\ 19-Fob-17 144 144 8497 30 326 1373972021 I CHECK 19-Feb-17 18-Mar-17 4-Mar-17 22-Feb-17 l-Mar-17 (4) (575) 156 COMCAST CABLEVIS!Ol'.' 19-Mar-17 138 138 8497 30 326 13739720311 CHECK 19-Mar-17 18-Apr-17 3-Apr-17 20-Mar-17 31-Mar-17 (3) (414) 151 COMTEMPORARY CYBERNETICS GROUP INC 28-0ct-16 3,046 1,310 794621 Direct Deposit 25-Feb-17 24-Feb-18 26-Aug-17 22-Nov-16 22-Nov-16 (277) (362,870) 158 Cook, Jonathan K (Kyle) 16-Jun-16 1,562 1,531 IEXP-1165866 Direct Deposit 6-Jun-16 !O-Jun-16 8-Jun-16 6-Jul-16 6-Jul-16 28 42,881 159 CORKYS PLUMBING 20-Jul-!6 SS 55 241 CHECK 20-Jul-16 20-Jul-16 20-Jul-16 3-Aug-16 30-Aug-!6 41 2,255 160 CORTEZ SANITATION DJSTRIC1 26-Sep-16 32 32 00320301_092616 CHECK 7-Aug-16 6-Sop-16 22-Aug-16 IO-Oct-16 18-0ot-16 57 1,824 !61 CORTEZ SANITATION DISTRIC1 25-Jan-17 40 40 00167601_012517 CHECK l-Dec-16 3!-Dec-16 16-Dec-16 13-Feb-17 22-Feb-17 68 2,720 162 COWPOKEFEEDS l-Apr-16 10 ID 214547 CHECK l-Apr-16 l·Apr-16 l-Apr-16 6-Apr-16 12-Apr-16 II !lo 163 COWPOKE FEEDS 22-Feb-17 188 188 220133 CHECK 22-Feb-17 22-Feb-17 22-Feb-!7 3-Mar-17 13·Mar-17 19 3,575 164 Crane, Donald !9-0ct-16 757 671 IEXP-1499190 Direct Deposit 8-Sep-16 3-Nov-16 6-0ct-16 21-0ct-16 21-0ct-16 15 10,069 165 CRAW KAN TELEPHONE COOP INC l-Aug-16 284 284 1215050816-080116 CHECK 21-Jun-16 31-Aug-16 26-Jul-16 15-Aug-16 22-Aug-16 27 7,658 166 CRC JANITORIAL SERVICES INC 31-Jul-16 980 980 1616 CHECK 1-Jul-16 3!-Jul-16 16-Jul-16 8-Aug-16 17-Aug-16 32 31,360 167 CREDIT WORLD SERVICES INC l-Jun-16 3,104 3,104 2869000183 CHECK l-Jun-16 l-Jun-16 1-Jun-16 27-Jun-16 12-Jul-16 41 127,251 168 CREDIT WORLD SERVICES INC 3-Jan-17 l,3SS l,35S 2869000206 CHECK l-Dec-16 31-Dec-16 16-Deo-16 30-Jan-17 !3-Feb-17 59 79,929 169 CRESTED BUTTE NEWS INC 20-Jan-17 206 206 649124 CHECK 20-Jan-17 20-Jan-17 20-Jan-17 15-Feb-17 l-Mar-17 40 8,240 170 DC AND B SUPPLY INC 19-Jul-16 142 142 20367 CHECK 19-Jul-16 19-Jul-16 \9-Jul-16 15-Aug-16 23-Aug-!6 35 4,955 Page3 of7 Schedule CWC6 Atmos Energy Corporation~ Colo.-ado Service Area Other O&M Payment Lag Test Year Ending March 31, 2017 Line Invoice Invoice Colorado Service Period Midpoint Payment Payment Weighted No. Vendor Date Amount Amount Invoice# Pavment Ty2e From To Svc Period Date Paid Cleared L!lfl PmtLao (a) (b) (c) (d) (•) (f) (g) (h) (i) (j) (k) (l)-k-(iorb) (m)=(l"d) 171 DEERE CREDIT INC 18-May-16 168,990 8,789 JDLeaBe-18-MAY-16 Direct Deposit 18-May-16 17-Jun-16 2-Jun-16 19-May-16 19-May-16 (14) (123,047) 172 DILLON RANCHES LLF I-Oct-16 546 546 LEASE3-0CT-l6 CHECK 1-0cH6 31-0ct-16 16-0ct-16 3-0ct-16 24-0ct-16 8 4,371 173 DILLON RANCHES LLF 1-Jan-17· 546 546 LEASE3-JAN-17 CHECK 1-Jan-17 31-Jan-17 16-Jan-17 3-Jan-17 3-Feb-17 18 9,834 174 DIRECTVINC 12-Dec-16 102 102 0394892151216-121216 CHECK 11-Dec-16 10-Jan-17 26-Dec-16 28-Deo-16 6-Jan-17 11 1,122 175 DOUBLE K CAR WASH LLC 1-Deo-16 7 7 2029 120116 CHECK ll-Nov-16 ll-Nov-16 11-Nov-16 7-Deo-16 21-Dec-16 40 280 176 DOUBLEK CAR WASHLLC 1-Mar-17 7 7 2029-030117 CHECK 2-Feb-17 2-Feb-17 2-Feb-17 13-Mar-17 22-Mar-17 48 336 177 DURANGO CHAMBER OF COMMERCE l-Jan-17 460 460 1031884 CHECK 1-Jan-17 Jl-Dec-17 2-Jul-17 13-Jan-17 24-Jan-17 (159) (73,140) 178 DURANGO WEST METROPOLITAN DISTIUCT NO. l-Aug-16 546 546 RENT2-AUG-16 CHECK 1-Aug-16 31-Aug-16. 16-Aug-16 l-Aug-16 11-Aug-16 (5) {2,732) 179 BCE DESIGN IO-May-16 1,950 1,950 INV00041!4 Direct Deposit l-Jul-16 30-Jun-17 30-Dec-16 29-Jun-16 29-Jun-16 (184) (358,828) 180 EGIAELECTRICAND GASINDUSTRIESASSOCIATI01 6-Mar-17 462 462 43090 Direct Deposit 1-Jan-17 31-Jan-17 16-Jan-17 13-Mar-17 13-Mar-17 56 25.858 181 EGWUTILITIESINC 13-Feb-17 231 231 1083437 Direct Deposit 13-Feb-17 13-Feb-17 !3-Feb-17 IO-Mar-17 10-Mor-17 25 5,775 182 ELECSYS INTERNATIONAL CORPORATim 21-May-16 16 16 149791 Direct Deposit 21-May-16 21-May-16 21-May-16 15-Jun-16 15-Jun-16 25 400 183 ELECSYS INTERNATIONAL CORPORATIO~ 21-May-16 32 32 149793 Direct Deposit 21-May-16 21-May-16 21-May-16 15-Jun-16 15-Jun-16 25 800 184 ELECSYS INTERNATIONAL CORPORATim 21-Jul-16 8 8 151987 Direct Deposit 21-Jul-16 21-Jul-16 21-Jul-16 15-Aug-16 15-Aug-16 25 200 185 ELECSYS INTERNATIONAL CORPORATIO~ 21-Sep-16 8 8 154399 Direct Deposit 21-Sep-16 21-Sep-16 21-Sep-16 17-0ct-16 17-0ct-16 26 208 186 ELEM!ll'<"I' FLEET 28-Mar-17 2,367,768 27,884 GE-Fleet - 28-MAR-l 7 Direct Deposit l-Feb-17 28-Feb-17 14-Feb-17 30-Mar-17 30-Mar-17 26 724,988 187 EMPIRE ELECTRIC ASSOCIATION INC 28-Deo-16 34 34 7373_122816 CHECK 20-Nov-16 22-Dec-16 6-Dec-16 16-Jan-17 24-Jan-17 49 1,654 188 EMPIRE ELECTRIC ASSOCIATION INC !3-Jan-17 84 84 34328001_011317 CHECK 8-Dec-16 8-Jan-16 23-Jun-16 27-Jan-17 3-Feb-17 225 18,977 189 EXTINGUISHER SOLUTIONS INC 18-Jul-16 1,056 1,056 2452 CHECK 18-Jul-16 18-Jul-16 18-Jul-16 12-Aug-16 19-Aug-16 32 33,780 190 FASTTRACKCOMMUNICATIONSINC 1-0ct-16 90 90 UTILITY3-0CT-IE CHECK 1-0ct-16 31-0ct-16 16-0ct-16 3-0ct-16 11-0ct-16 (5) (450) 191 FASTTRACKCOMMUNICATIONSIN( 1-Nov-16 90 90 UTIL!TY3-NOV-IE CHECK l-Nov-16 30-Nov-16 15-Nov-16 31-0ct-16 7-Nov-16 (9) (810) 192 FISERVINC 23-Jan-l 7 11,459 710 91002107 Direct Deposit l-Dec-16 31-Dec-16 16-Dec-16 26-Jan-17 26-Jan-17 41 29,110 193 Fogle, Kendall L (Ken) 26-Sep-16 222 214 IEXP-1433100 Direct Deposit 9-Sep-16 19-Sep-16 14-Sep-16 28-Sep-16 28-Sep-16 14 2,997 194 FOUR CORNERS BROADCASTING LLC 26-Feb-17 595 593 712000060000 CHECK 1-Fob-17 19-Feb-17 10-Feb-17 15-Mar-17 23-Mar-17 41 24,395 195 FREMONT SA.i'l!TATION DISTRIC1 26-0ct-16 23 23 104112735_102616 CHECK 27-Sep-16 25-0ct-16 ll-Oot-16 ll-Nov-16 21-Nov-16 41 939 196 FREMONT SANITATION DISTRIC1 28-Dec-16 23 23 101722735_122816 CHECK 29-Nov-16 27-Dec-16 13-Deo-16 lS-Jan-17 25-Jan-17 43 1,004 197 Geiger. Jared N 5-Apr-16 1,955 l,955 IEXP-865865 Direot Deposit 29-Mor-16 9-Jun-16 4-May-16 8-Apr-16 8-Apr-16 (26) (50,821) 198 Geiger~ Jared N 6-Sep-16 460 460 IEXP-1424103 Direct Deposit 24-Aug-16 30-Aug-16 27-Aug-16 9-Sep-16 9-Sep-16 13 5,979 199 GENERALAIRINC 31-0ct-16 108 108 920811791 Direct Deposit 31-Jul-16 31-0ct-16 !5-Sep-16 23-Nov-16 23-Nov-16 69 7,445 200 GENESYS INSTRUMENTATION LLC 3-Feh-17 36 36 INST2031 CHECK l-Feb-17 28-Feb-17 14-Feb-17 27-Feb-17 10-Mor-17 24 864 201 GEORG FISCHER CENTRAL PLASTICS LLC 23-Jan-17 460 460 1794694 Direct Deposit 23-Jan-17 23-Jan-17 23-Jan-17 17-Feb-17 17-Feb-17 25 11,488 202 GEORG FISCHER CENTRAL PLASTICS LLC 3-Feb-17 410 410 1797158 Direct Deposit 3-Feb-17 3-Feb-17 3-Feb-17 28-Feb-17 28-Feb-17 25 10,259 203 GLASSCO - LA.c'v!AR COLORADC 16-Nov-16 368 368 8779 CHECK 16-Nov-16 16-Nov-16 16-Nov-16 12-Deo-16 23-Dec-16 37 13,623 204 Gorecki, Morein 27-Sep-16 511 506 IEXP-1433975 Direct Deposit 19-Sep-16 21-Sep-16 20-Sep-16 30-Sep-16 30-Sep-16 lO 5,064 205 GOVDOCS DOT COM 22-Sop-16 18 18 196095 CHECK 22-Sep-16 22-Sep-16 22-Sop-16 17-0ct-16 25-0ct-16 33 610 206 GRAEBEL RELOCATION SVCS WORLDWIDE 10-Mar-17 48,523 1,000 50150075 Direct Deposit l-Mor-17 1-Mor-17 1-Mar-17 13-Mor-17 13-Mar-17 12 12,000 207 GRANADA CITY OF l-Apr-16 50 50 413_040116 CHECK 28-Feb-16 29-Mar-16 14-Mar-16 6-Apr-16 13-Apr-16 30 1,499 208 Gregory. Gary W 27-Sep-16 1,246 498 IEXP-143 3998 Direct Deposit l-Sep-16 19-0ct-16 25-Sep-16 30-Sep-16 30-Sep-16 5 2,491 209 Gregory, Gary W 28-Sep-16 265 265 IEXP-1434239 Direct Deposit 1-0ct-16 30-Sep-17 l-Apr-17 30-Sep-16 30-Sep-16 (183) (48,495) 210 GUNN!SON COUNTRY TIME! 15-Jan-17 340 340 00088627 CHECK 12-Jan-17 12-Jan-17 12-Jan-17 1-Feb-17 15-Feb-17 34 11,560 211 GUNNISON COUNTRY TIME! 24-Jan-17 340 340 00088828 CHECK 19-Jan-17 19-Jan-17 19-Jan-17 6-Feb-17 15-Feb-17 27 9,180 212 Harper~ Georgia A ll-Apr-16 58 58 IEXP-923872 Direct Deposit 4-Apr-16 4-Apr-16 4-Apr-16 14-Apr-16 14-Apr-16 10 583 213 Hartley, Russell T (Russ) 30-Nov-16 1,904 1,904 IEXP-1516285 Direct Deposit 29-Nov-16 29-Nov-16 29-Nov-16 5-Dec-16 5-Deo-16 6 11,423 214 HAYDEN PARKS AND RECREATl01' 16-Jun-16 100 100 CHE06l616 CHECK 16-Jun-16 16-Jun-16 16-Jun-16 27-Jun-16 12-Jul-16 26 2,600 215 Hergenreder, David D (Dave) 27-0ct-16 1,716 1,702 IEXP-1503177 Direct Deposit 28-Sep-16 3-Nov-16 16-0ct-16 l-Nov-16 l-Nov-16 16 27,231 216 Hershberger, Melissa B 27-Sep-16 119 119 IEXP-1433287 Direct Deposit 22-Sep-16 22-Sep-16 22-Sep-16 30-Sep-16 30-Sep-16 g 950 217 Higgins, Daniel W (Dan) 3!-Jan-17 1,060 917 IEXP-1845133 Direct Deposit 31-0ct-16 30-Jan-17 15-Deo-16 2-Feb-17 2-Feb-17 49 44,926 218 Hockin, Ryan C 29-Jun-16 176 74 IEXP-1251164 Direct Deposit 22-Jun-16 l-Jul-16 26-Jun-16 1-Jul-16 1-Jul-16 5 368 219 HOLLAND AND HART LU 25-May-16 2,078 2.078 1481648 Direct Deposit i-Apr-16 26-Apr-16 13-Apr-16 11-Aug-16 ll-Aug-16 120 249,360 220 HOLLY TOWN OF 31-Jan-17 8 8 710000 013117 CHECK 29-Deo-16 31-Jan-17 14-Jan-17 22-Feb-17 28-Feb-17 45 361 221 HORIZON ENVIRONMENTAL SERVICES INC 25-Apr-16 5,310 5,310 ATM8M2516 CHECK 31-Mor-16 13-Apr-16 6-Apr-16 20-May-16 31-May-16 55 292,028 222 HOWARD DISPOSAI 21-Jul-16 80 80 434304 CHECK 21-Jun-16 21-Jul-16 6-Jul-16 5-Aug-16 ll-Aug-16 36 2,881 223 HOWARD DISPOSAI 23-Feb-17 80 80 469732 CHECK 23-Jan-17 23-Feb-17 7-Feb-17 15-Mar-17 28-Mar-17 49 3,921 224 HUDSON ENERGY LLC 10-May-16 130,751 384 S 1605120003-00 I Direct Deposit IO-Apr-16 IO-May-16 25-Apr-16 31-May-16 31-May-16 36 13,834 225 HUDSON ENERGY LLC 12-Dec-16 143,009 722 Sl612130004-00I Direct Deposit 12-Nov-16 12-Dec-16 27-Nov-16 15-Dec-16 15-Dec-16 18 12,987 226 ITRON INC 12-Dec-16 16,224 1,136 434751 Direct Deposit l-Jan-17 31-Mar-17 14-Feb-17 6-Jan-17 6-Jan-17 (40) (45,427) 227 JAY AND CAROL ENTERPRISES INC 1-Apr-16 150 150 LEASE2-APR-l6 Direct Deposit 1-Apr-16 30-Apr-16 15-Apr-16 1-Apr-16 l-Apr-16 (15) (2,250) Page 4 of7 Schedule CWC6 Atmos Energy Corporation .. Colorado Service Area Other O&M Payment Log Test Year Ending March 31, 2017 Llne Invoice Invoice Colorado Service Period Midpoint Payment Payment Weighted No. Vendor Date Amount Amount Invoice# Pa~ment Tx!!• From To Svc Period Date Paid Cleared Las PmtLag (a) (b) (c) (d) (e) (f) (g) (h) (i) (j) (k) (l)~k-(iorb) (m)~(l"d) 228 JAY At"\ID CAROL ENTERPRlSES INC l-Jan-17 150 150 LEASE3-JAN-17 Direct Deposit l-Jan-17 31-Jan-17 16-Jan-17 3-Jan-17 3-Jan-17 (13) (l,950) 229 JJ KELLER AND ASSOCIATES INC 31-May-16 550 165 192884 Direct Deposit 31-May-16 31-May-16 31-May-16 27-Jun-16 27-Jun-16 27 4,455 230 JJ KELLER AND ASSOCIATES INC 31-0ct-16 624 125 221507 Direct Deposit 31-0ct-16 31-0ct-16 31-0ct-16 23-Nov-16 23-Nov-16 23 2,872 231 Johnson, Tori D 5-Aug-16 500 500 IEXP-1401958 Direct Deposit 13-Jul-16 4-Aug-16 24-Jul-16 9-Aug-16 9-Aug-16 16 7,993 232 Johnson, Tori D 28-0ct-16 12,896 12,896 IEXP-1503330 Direct Deposit 24-0ct-16 27-0ct-16 25-0ct-16 l-Nov-16 l-Nov.-16 7 90,272 233 Kage, Tim 30-Mar-16 242 242 IEXP-855896 Direct Deposit 29-Mar-16 29-Mar-16 29-Mar-16 20-Apr-16 20-Apr-16 22 5,316 234 Kage~ Tim 29-Sep-16 666 666 IEXP-1434455 Direct Deposit 19-Sep-16 7-0ct-16 28-Sep-16 3-0ct-16 3-0ct-16 5 3,3Z8 235 Knoche, Robin (Robin) 4-Apr-16 173 173 IEXP-861910 Direct Deposit l-Mar-16 30-Mar-16 15-Mar-16 7-Apr-16 7-Apr-16 23 3,974 236 KRAI FM AND 55 COUNTRY 17-Jan-17 195 195 CHE011717 CHECK 17-Jan-l 7 17-Jan-17 17-Jan-17 20-Jan-17 3-Feb-17 17 3,315 237 LAPLATAELECTRlC ASSOCIATION INC 7-Jun-16 24 24 6595294200 060716 CHECK 26-Apr-16 25-May-16 10-May-16 22-Jun-16 29-Jun-!6 50 1,200 238 Lucero, Benjamin E (Ben) 17-0ct-!6 601 601 IEXP-1499349 Direct Deposit 12-Sep-16 Il-Oct-16 26-Sep-16 19-0ot-16 19-0ct-16 23 13,819 239 Magee, Kevin J 2-May-16 56 56 IEXP-955865 Direct Deposit 17-Apr-16 23-Apr-16 20-Apr-16 6-May-16 6-May-16 16 896 240 MARlPOSA PLANTS 30-Sep-16 95 95 230824 Direct Deposit l-Oct-16 31-0ct-16 16-0ct-16 25-0ct-16 25-0ct-16 9 855 241 MARlPOSAPLANTS 31-0ct-16 95 95 231441 Direct Deposit l-Nov-16 30-Nov-16 15-Nov-16 23-Nov-16 23-Nov-16 8 760 242 Marshall, Karen P 2-Jun-16 734 718 IEXP-1088041 Direct Deposit 13-Apr-16 24-May-16 3-May-16 3-Jun-16 3-Jun-16 31 22,259 243 MASTER PRlNTERS !8-Apr-16 23 23 IZ0455E7 041816 I CHECK 18-Apr-16 18-Apr-16 !8-Apr-16 7-Dec-16 15-Dec-16 241 5,603 244 MASTER PRlNTERS l-Jul-16 19 19 IZ0455E7- 070 ll 6- CHECK l-Jul-16 l-Jul-16 l-Jul-16 29-Jul-16 Il-Aug-16 41 766 245 MASTER PRlNTERS 27-Dec-16 89 89 1Z0455E7)22716 CHECK 27-Deo-16 27-Dec-16 27-Dec-16 8-Feb-17 17-Feb-17 52 4,632 246 MCLARENS YOUNG INTERNATIONAi 17-Aug-16 l,053 1,053 0412057 CHECK 22-Mar-16 10-Jun-16 l-Ma:y-16 9-Sep-16 20-Sep-16 142 149,526 247 Merritt, Gary S 28-Dec-16 868 868 IEXP-1536143 Direct Deposit 13-Dec-16 22-Deo-16 17-Dec-16 3-Jan-17 3-Jan-17 17 14,754 248 MESA POINT ENERGY 21-Jul-16 1,515 1,515 224 CHECK 6-Jun-16 30-Jun-16 !S:Jun-16 15-Aug-16 20-Sep-16 94 142,410 249 MESA POINT ENERGY 24-Aug-16 7,310 7,310 234 CHECK l-Jul-16 15-Aug-16 23-Jul-16 19-Sep-16 29-Sep-16 68 497,061 250 MESA POINT ENERGY 22-Nov-16 2,600 2,600 -246 CHECK 3-0ct-16 3!-0ct-16 17-0ct-16 19-Dec-16 28-Deo-16 72 187,200 251 Mitchell, David S (Steve) 28-0ct-16 906 906 !EXP-1503283 Direct Deposit 24-0ct-16 28-0ct-16 26-0ct-16 1-Nov-16 l-Nov-16 6 5,437 252 MONETTE ERNEST 1-0ct-16 200 200 LEASE3-0CT-16 CHECK 1-0ct-16 31-0ct-16 16-0ct-16 3-0ct-16 12-0ct-16 (4) (800) 253 MOORE AND VAN ALLEN PLLC 15-Doc-16 991 991 752326-1 CHECK 5-Nov-16 30-Nov-16 17-Nov-16 23-Jan-17 30-Jan-17 74 73,334 254 MRC GLOBAL 9-May-16 74,076 4,223 MCJUNKIN - 16128GGC Direct Deposit l-May-16 7-May-16 4-May-16 31-May-16 31-May-16 27 114,034 255 MRC GLOBAL l-Aug-16 139,051 2,546 MCJUNKIN - l6212GGC Direct Deposit 24-Jul-16 30-Jul-16 27-Jul-16 22-Aug-16 22-Aug-16 26 66,198 256 MRC GLOBAL 29-Aug-16 72,444 1,525 MCJUNKIN - 16240GGC Direct Deposit 21-Aug-16 27-Aug-16 24-Aug-16 19-Sep-16 19-Sep-16 26 39,658 257 MRC GLOBAL lO-Oct-16 68,349 921 MCJUNKIN - 16282GGC Direct Deposit 2-0ct-16 8-0ct-16 5-0ct-16 31-0ot-16 31-0ct-16 26 23,947 258 MRC GLOBAL 27-Dec-16 17,990 2,184 MCJUNKIN - 16358GGC Direct Deposit 18-Doc-16 24-Doc-16 21-Dec-16 17-Jan-17 17-Jan-17 27 58,958 259 MRC GLOBAL 30-Jan-17 107,223 1,424 MCJUNKIN - l 7028GGC Direct Deposit 23-Jan-17 29-Jan-17 26-Jan-17 21-Feb-17 21-Feb-17 26 37,028 260 MRC GLOBAL 20-Feb-17 75,706 1,169 MCJUNKIN - l 7049GGC Direct Deposit 13-Fob-17 19-Feb-17 !6-Feb-17 13-Mar-17 13-Mar-17 25 29,213 261 MRC GLOBAL 6-Mar-17 204,698 1,495 MCJUNKIN - l 7063GGC Direct Deposit 27-Fob-17 5-Mar-17 2-Mar-17 27-Mar-17 27-Mar-17 25 37,373 262 NIEMAN PRlNTlNG INC 27-Apr-16 1,204 120 275263 CHECK 27-Apr-16 27-Apr-16 27-Apr-16 11-May-16 17-Ma:y-16 20 2,407 263 NITEL INC l-Mar-17 15,789 932 201511S00103l7-030l! 7 Direct Deposit l-Mar-17 31-Mar-17 16-Mar-17 27-Mar-17 27-Mar-17 II 10,257 264 Nixon, Nancy R 26-Sep-16 153 153 IEXP-1433115 Direct Deposit 3-Sep-16 21-Sep-16 12-Sep-16 28-Sep-16 28-Sep-16 16 2,448 265 Nixon, Nancy R 30-Dec-16 199 199 IEXP-1540135 Direct Deposit 1-Apr-17 31-Mar-18 30-Sep-17 6-Jan-17 6-Jan-17 (267) (53,133) 266 NORTH WELD HERALD 20-0ct-16 440 440 OCT201611 CHECK 20-0ct-16 20-0ct-16 20-0ct-16 2-Nov-16 8-Nov-16 19 8,360 267 NUNN TELEPHONE CO 1-Apr-16 104 104 00000016800416-040116 CHECK l-Apr-16 30-Apr-16 15-Apr-16 13-Apr-16 21-Apr-16 6 625 268 NUNN TELEPHONE CO 1-0ct-16 104 104 00000016801016-l 00 l 16 CHECK l-Oct-16 31-0ct-16 16-0ct-16 12-0ct-16 20-0ct-16 4 416 269 OLD DOMINION FREIGHT Lll-<'E INC 16-Mar-17 497 497 0871108455 I CHECK 14-Mar-17 14-Mar-17 14-Mar-17 29-Mar-17 3-Apr-17 20 9,935 270 ORKIN PEST CONTROL !3-Jun-16 84 84 83534295 CHECK 13-Jun-16 13-Jun-16 13-Jun-16 15-Jul-16 26-Jul-16 43 3,615 271 ORTONS ON EMERALD MOUNTAIN LU l-Oct-16 839 839 LEASE3-Q4-16 CHECK 1-0ct-16 31-Deo-16 15-Nov-16 3-0ct-16 11-0ct-16 (36) (30,195) 272 PALMERCOLLEEN 1-Jan-17 500 500 CLEAN5-JAN-17 CHECK 1-Deo-16 31-Dec-16 16-Dec-16 25-Jan-17 2-Feb-17 48 24,000 273 Palmer, Kolby M 20-Mar-17 153 153 IEXP-2346161 Direct Deposit 14-Feb-17 3-Mar-17 22-Feb-17 21-Mar-17 21-Mar-17 27 4,119 274 Paradisa, Kurtis A 14-Jun-16 1,944 1,849 IEXP-tl 21869 Direct Deposit 5-Jun-16 10-Jun-16 7-Jun-16 21-Jun-16 21-Jun-16 14 25,883 275 Parker, Camille R 30-Sep-16 300 300 IEXP-1434726 Direct Deposit 30-Sep-16 30-Sep-16 30-Sep-16 5-0ct-16 5-0ct-16 5 1,502 276 Parker, Camille R 8-Mar-17 2,662 2,662 IEXP-2349153 Direct Deposit 24-Feb-17 11-Apr-17 19-Mar-17 9-Mar-17 9-Mar-17 (10) (26,623) 277 PC CONNECTION 30-Jun-16 165 165 53907035 Direct Deposit 30-Jun-16 30-Jun-16 30-Jun-16 · 25-Jul-16 25-Jul-16 25 4,135 278 PC CONNECTION 9-Sep-16 141 141 54112592 Direct Deposit 9-Sep-16 9-Sep-16 9-Sep-16 4-0ct-16 4-0ct-16 25 3,526 279 PC CONNECTION 30-Nov-16 611 6ll 54340197 Direct Deposit 30-Nov-16 30-Nov-16 30-Nov-16 27-Dec-16 27-Dec-16 27 l6,490 280 PC CONNECTION 16-Jan-17 501 501 54456766 Direct Deposit 16-Jan-17 16-Jan-17 16-Jan-17 10-Feb-17 10-Feb-17 25 12,529 281 PETERSON RAY AND COMPANY 3-Aug-16 1,750 138 433 CHECK 3-Aug-16 3-Aug-16 3.. Aug·l6 29-Aug-16 8-Sep-16 36 4,977 282 PITNEY BOWES GLOBAL FINANCIAL SERVICES LL( 26-0ct-16 ll 11 3302016197 CHECK 25-0ct-16 24-Jan-17 9-Dec-16 9-Nov-16 23-Nov-16 (17) (193) 283 PITNEY BOWES PURCHASE POWER 6-Apr-16 33 33 8000900010732216_0406 CHECK 6-Apr-16 6-Apr-16 6-Apr-16 21-Apr-16 28-Apr-16 22 719 284 PITNEY BOWES PURCHASE POWER 6-Jan-17 133 133 80009000 I 0732216_ 0106 CHECK 28-Doc-16 3-Jan-17 31-Deo-16 23-Jan-17 l-Feb-17 32 4,245 Page 5 of7 Schedule CWC6 Atmos Energy Corporation - Colorado Service Area Other O&M Payment Lag Test Year Ending March 31, 2017 Line Invoice Invoice Colorado Service Period Midpoint Payment Payment Weighted No. Vendor Date Amount Amount Invoice# P!!l'.mentTy2e From To Svc Period Date Paid Cleared L!lJ! PmtLag (a) (b) (o) (d) (e) (t) (g) (h) (i) (j) (k) (l)=k-(iorb) (m)=(l*d) 285 POSTMASTER 13-Apr-16 2,041 204 CHE0413!6 CHECK 12-Apr-16 12-Apr-16 12-Apr-16 !8-Apr-16 22-Apr-16 IO 2,041 286 Poulsen, Jake D 18-Jan-17 122 55 !EXP-1682145 Direct Deposit 3-Jan-17 3-Jan-17 3-Jan-17 20-Jan-17 20-Jan-17 17 933 287 Prieto Arias, Juan A 22-Jun-16 47 12 !EXP-1150866 Direct Deposit 1-Jun-16 21-Jun-!6 11-Jun-16 28-Jun-16 28-Jun-16 17 204 288 Prieto Arias, Juan A IO-Mar-17 401 250 IEXP-2268141 Direct Deposit 15-Feb-17 28-Feb-19 21-Feb-18 14-Mar-17 14-Mar-17 (345) (86,250) 289 PROFESSIONAL FINANCE COMPANY INC 22-May-16 2,619 807 52216 CHECK 15-May-16 22-May-16 18-May-!6 15-Jun-16 27-Jun-16 40 32,274 290 PUEBLO COMMUNITY COLLEGE FOUNDATIOI' 7-Apr-16 150 150 CHE040716 CHECK 7-Apr-16 7-Apr-16 7-Apr-16 2-May-16 ll-May-16 34 5,100 29! RHINO MAR.KING AND PROTECTION SYSTEMi 25-Mar-16 661 661 66796 Direct Deposit 25-Mar-16 25-Mar-16 25-Mar-16 26-Apr-16 26-Apr-16 32 21,157 292 Ritschard, Christina J 25-Apr-16 108 90 IEXP-935928 Direct Deposit 20-Apr-!6 20-Apr-16 20-Apr-16 27-Apr-16 27-Apr-16 7 631 293 Ritschard, Christina J 28-Dec-16 351 351 IEXP-1537148 Direct Depo•it 21-Dec-16 2l-Dec-l6 21-Deo-16 5-Jan-17 5-Jan-17 IS 5,265 294 ROGGEN TELFJ>HONE COOP 1-May-16 39 39 00000005690516-050116 CHECK l-May-16 31-May-16 16-May-!6 9-May-16 19-May-16 3 116 295 ROGGEN TELEPHONE COOP l-Oct-16 39 39 00000005691016-100116 CHECK 1-0ct-16 31-0ct-!6 16-0ot-16 lO-Oct-16 19-0ct-!6 3 116 296 ROSENGRANTS MATT 1-May-16 200 200 RENT4-MAY-16 CHECK 1-May-16 31-May-16 16-May-16 2-May-16 10-May-16 (6) (l,200) 297 ROSENGRANTS MATT l-Aug-16 200 200 RENT4-AUG-!6 CHECK 1-Augnl6 31-Aug-16 16-Aug-16 1-Aug.-16 9-Aug-16 (7) (1,400) 298 ROSENGRA.i"<'TS MAT! l-Mar-17 200 200 RENT5-MAR-l 7 CHECK 1-Mar-17 31-Mar-17 16-Mar-17 1-Mar-17 14-Mar-17 (2) (400) 299 ROSENST!EL SANDRA 23-Jun-16 210 16 A1922 CHECK 23-Jun-16 23-Jun-16 23-Jun-16 ll-Jul-16 20-Jul-16 27 435 300 Ross, Kevin E 7-Deo-16 150 150 !EXP-1518150 Direct Deposit 22-Nov-!6 22-Nav-16 22-Nov-!6 20-Dec-16 20-Deo-16 28 4,200 301 RUPPS TRUCK AND TRAILER REPAIR INC 24-Jul-16 385 385 1710 CHECK 24-Jul-16 24-Jul-!6 24-Jul-16 26-Aug-16 7-Sep-16 45 17,324 302 S.A\LESFORCECOMINC 12-Sep-16 21,184 2,378 08921190 CHECK 1-0ct-16 30-Sep-17 l-Apr-17 7-0ct-16 12-0ot-16 (171) (406,553) 303 SALIDA lJT!LITIES Till 25-May-16 84 84 0100000944500 052516 CHECK 26-Apr-16 25-May-16 10-May-16 10-Jun-16 23-Jun-16 44 3,689 304 SALIDA UT!LlTIES Till 21-Nov-16 44 44 0100000838400-112116 CHECK 25-0ct-l6 21-Nov-16 7-Nav-16 !9-Dec-16 29-Deo-16 52 2,290 305 SANGRE DE CRISTO ELECTRIC ASSOCIATION INC 31-Mar-16 35 35 20001600 0331 l6 CHECK 26-Feb-16 29-Mar-16 13-Mar-16 13-Apr-16 20-Apr-16 38 1,335 306 SANGRE DE CRISTO ELECTRIC ASSOCIATION INC 31-Jan-17 36 36 4008501 013117 CHECK 29-Dec-16 28-Jan-17 13-Jan-17 13-Feb-17 22-Feb-17 40 1,430 307 SANGRE DE CRISTO ELECTRIC ASSOCIATION INC 28-Feb-17 35 35 4008501-022817 CHECK 28-Jan-17 26-Feb-17 tl-Feb-17 17-Mar-17 29-Mar-17 46 1,632 308 SAVE THE BARN COMMITTEE 24-Jan-17 100 100 CHEOl24°17 CHECK 24-Jan-17 24-Jan-17 24-Jan-17 30-Jan-17 7-Feb-17 14 1,400 309 Schmidt, Marlon L 13-Jan-17 139 139 JEXP-1605155 Direct Deposit 6-Jan-17 6-Jan-17 6-Jan-17 24-Jan-17 24-Jan-17 18 2,496 310 SECOM INC 5-Mor-17 l,444 1,444 54800317-030517 CHECK 1-Mar-17 3!-Mar-17 16-Mar-17 17-Mar-17 28-Mar-17 12 17,329 311 SECOR JNC 26-Apr-16 235 235 021853!1N Direct Deposit 26-Apr-16 26-Apr-!6 26-Apr-16 23-May-16 23-May-!6 27 6,352 312 SIL VEYRA ERNESTINA 3!-Mar-16 2,180 2,180 663666 Diroct Deposit !-Mar-16 31-Mar-16 16-Mar-16 18-Apr-!6 18-Apr-16 33 71,940 313 SNOW!IlTELINEI\ 8-Feb-17 72 72 02929 CHECK 8-Feb-17 8-Feb-17 8-Feb-17 22-Feb-17 l-Mar-17 21 1,508 314 SOUTHEAST COLORADO POWER ASSOCIATIQ} 5-Apr-16 41 41 708061100 040516 CHECK 29-Feb-16 31-Mar-16 15-Mar-16 13-Apr-16 2l·Apr-16 37 1,531 315 SOUTHEAST COLORADO POWER ASSOCIATIQ} 5-May-16 44 44 708060500-050516 CHECK 31-Mar-16 30-Apr-16 15-Apr-16 IS-May-16 25-May-16 40 1,761 316 SOUTIIBAST COLORADO POWER ASSOCIATIQ} 6-Jun-16 30 30 2601007700_060616 CHECK 30-Apr-16 3!-May-16 15-May-16 22-Jun-16 29-Jun-16 45 1,366 317 SOUTHEASTCOLORADOPOWERASSOCIATIQ} 5-Jul-16 33 33 2601007700_0705!6 CHECK 31-May-16 28-Jun-16 14-Jun-!6 15-Jul-16 25-Ju!-16 41 1,369 318 SOUTIIEAST COLORADO POWER ASSOCIATIQ} 8-Augn16 31 31 2601005500 _080816 CHECK 30-Jun-16 31-Ju!-!6 15-Jul-16 19-Aug-16 29-Aug-16 45 1,380 319 SOUTIIEAST COLORADO POWER ASSOCIATim 6-Sep-16 40 40 708061200_090616 CHECK 31-Jul-16 31-Aug-16 15-Aug-16 23-Sep-16 3-0ct-16 49 l,955 320 SOUTHEAST COLORADO POVilER ASSOCIATim 7-Nov-16 58 58 708060600 l 10716 CHECK I-Oct-16 l-Nov-16 16-0ct-16 18-Nov-16 30-Nov-16 45 2,588 321 SOUTIIEAST COLORADO POVi/ERASSOCIATIO} 7-Nov-16 81 81 708060700-110716 CHECK 1-0ct-16 l-Nov-16 16-0ct-16 18-Nav-16 30-Nov-16 45 3,643 322 SOUTHEAST COLORADO POVi/ERASSOCIATim 5-Deo-16 34 34 708061200-120516 CHECK 1-Nav-16 30-Nav-16 15-Nov-16 19-Deo-16 29-Deo-16 44 1,487 323 SOUTHEAST COLORADO POWER ASSOCIATIOl 5-Deo-16 80 80 708060400-120516 CHECK 1-Nov-16 30-Nov-16 15-Nov-16 19-Deo-16 29-Dec-16 44 3,537 324 SOUTHEAST COLORADO POWER ASSOCIATim 5-Deo-16 45 45 70806110(120516 CHECK 1-Nov-16 30-Nov-16 15-Nov-16 19-Dec-16 29-Dec-16 44 1,984 325 SOUTHERN CROSS CORPORATIOJ\ 26-Sep-16 1,395 1,395 80877 Direct Deposit 26-Sep-16 26-Sep-16 26-Sep-16 6-0ct-16 6-0ct-16 10 13,954 326 SOUTHER.i"l CROSS CORPORATIOJ\ ll-Oot-16 514 514 81159 Direct Deposit ll-Oct-16 II-Oct-16 11-0ct-16 19-0ct-16 19-0ct-16 8 4,115 327 SOUTHERN METHODIST UNIVERSffi 13-Sep-16 28,125 350 V0002779 CHECK 27-Sep-16 5-0ct-16 l-Oct-16 16-Sep-16 6-0ct-16 5 1,750 328 SPECTRASITE COMMUNICATIONS INC l-Ma:y-16 563 563 271802;-MAY-16 Direct Deposit l-May-16 31-May-16 16-May-16 2-May-16 2-May-16 (14) (7,881) 329 SPECTRASITE COMMUNICATIONS INC l-Nov-16 563 563 271802:-NOV-16 Direct Deposit l-Nov-16 30-Nov-16 15-Nov-16 1-Nov-16 l-Nov-16 (15) (8,444) 330 SPRINT INC 6-Jun-16 630 IS 5478366160616-060616 CHECK 3-May-16 2-Jun-16 !8-May-16 10-Jun-16 22-Jun-16 35 644 33! SQUEAKYCLEANWINDOWCLEAN!N( 28-Dec-16 110 110 2284 CHECK 28-Dec-16 28-Dec-!6 28-Dec-16 23-Jan-17 30-Jan-17 33 3,630 332 STARIKA CARWASHES BEST CAR WASE 30-Nov-16 16 16 2050_120116 CHECK 4-Nav-16 23-Nov-16 13-Nov-16 21-Dec-16 29-De<:-16 46 714 333 STEVE GREEN COMPA."IYINC 15-Sep-!6 49 49 121263 CHECK 15-Sep-16 15-Sep-16 15-Sep-16 !O-Oct-16 19-0ct-16 34 1,653 334 Stolz, Tanner W 19-0ct-16 20 20 !EXP-1499559 Direct Deposit 19-0ct-16 !9-0ct-16 19-0ct-16 24-0ct-16 24-0ct-16 5 100 335 Stolz, TannerW 28-0ct-16 68 61 !EXP-1503232 Direct Deposit 24-0ct-16 26-0ct-16 25-0ot-16 31-0ct-16 31-0ct-16 6 369 336 TARGET UTILITY SERVICES CC 20-Jan-17 197 197 INI08872 CHECK 20-Jan-17 20-Jan-17 20-Jan-17 30-Jan-17 3-Feb-17 14 2,751 337 TER..V!INIX l-Jun-16 55 55 355432604 CHECK l-Jun-16 l-Jun-16 l-Jun-16 29-Jun-16 8-Ju!-16 37 2,035 338 TERMINIX 30-Jul-16 55 55 357080308 CHECK 30-Jul-16 30-Ju!-!6 30-Jul-16 28-0ct-16 8-Nov-16 101 5,555 339 TERMINIX 15-Feb-17 85 85 362977369 CHECK !5-Feb-17 15-Feb-17 15-Feb-17 15-Mar-17 23-Mar-17 36 3,060 340 TERRACON CONSULTANTS INC ll-May-16 950 950 T772493 CHECK 17-Apr-16 30-Apr-16 23-Apr-16 6-Jun-16 14-Jun-16 52 49,400 341 TESSCO INC 29-Sep-16 62 62 380110 Direct Deposit 29-Sep-16 29-Sep-16 29-Sep-16 24-0ct-16 24-0ct-16 25 1,552 Page 6 of7 Schedule CWC6 Atmos Energy Corporatio.n-Coiorado Service Area Other O&M Payment Lag Test Year Ending March 31, 2017 Line Invoice Invoice Colorado Service Period Midpoint Pa:yment Payment Weighted No. Vendor Date Amount Amount Invoice# PaJ'.ment TJ'.Ee From To Svc Period Date Poid Cleared L!!I;! PmtLag (a) (b) (c) (d) (•) (f) (g) (h) (i) (j) (k) (l)-k-(iorb) (m)-(l*d) 342 Thatcher, Troy L l3-May-16 743 743 IEXP-1065903 Direct Deposit 12-Feb-16 28-Apr-16 21-Mar-16 19-May-16 19-May-16 59 43,865 343 TIME WARNER CABLE l-Jul-16 5,417 372 0381290010716-070116 CHECK l-Jul-16 31-Jul-!6 !6-Ju\-16 18-Jul·16 29-Jul-16 l3 4,831 344 TlME WARNER CABLE 4-Aug-16 125 125 84486200 I 00032160816-CDirect Deposit 12-Jul-16 11-Aug-16 27-Jul-16 15-Aug-16 15-Aug-16 19 2,374 345 TYCO INTEGRATED SECURlT'l 21-0ct-16 32 32 27408838 Direct Deposit 21-0ct-!6 21-0ct-16 21-0ct-16 l-Nov-16 l-Nov-16 ll 352 346 URBAN 1547 BLAKE STREET LLC l-Jan-17 51,358 37,189 RENT5-JAN-l 7 CHECK 1-Jan-17 31-Jan-17 !6-Jan-17 3-Jan-17 ll-Jan-17 (5) (185,943) 347 URBAN 1547 BLAKE STREET LLC l-Mar-17 1,939 1,714 1547000017_030117 CHECK 26-Jan-17 31-Mar-17 27-Feb-17 l-Mar-17 8-Mar-17 9 15,426 348 US PAYJ'll[ENTS LLC 31-Mar-16 40,382 5,806 012551 Direct Deposit l-Mar-16 31-Mar-16 16-Mar-16 4-May-16 4-May-16 49 284,517 349 UTILITY NOTIFICATION CENTER OF COLORAD( 31-0ct-16 6,142 6,142 216100052 Direct Deposit l-Oct-16 31-0ct-16 16-0ct-16 7-Nov-16 7-Nov-16 22 135,121 350 UTILITY NOTIFICATION CENTER OF COLORAD( 28-Feb-17 3,895 3,895 217020046 Direct Deposit l-Feb-17 28-Feb-17 14-Feb-17 7-Mar-17 7-Mar-17 21 81,789 351 VALLEY FIRE EXTINGUISHER INC 17-Mar-16 70 70 120693 CHECK 17-Mar-16 17-Mar-16 17-Mar-16 22-Apr-16 3-May-16 47 3,269 352 VALLEY FIRE EXTINGUISHER INC 6-Apr-16 123 123 120900 CHECK 6-Apr-16 6-Apr-16 6-Apr-16 2-May-16 17-May-16 41 5,046 353 VALLEY FIRE EXTINGUISHER IN( !4-Apr-16 59 59 121021 CHECK 14-Apr-!6 14-Apr-16 14-Apr-16 9-May-16 24-May-16 40 2,354 354 VF IMAGEWEAR INC 7-0ot-16 286 286 0025605818 Direct Deposit 7-0ct-16 7-0ct-16 7-0ct-16 l-Nov-16 1-Nov-16 25 7,159 355 VF IMAGEWEAR INC 25.oi:t-16 254 254 0025718331 Direct Deposit 25-0ct-16 25-0ct-16 25-0ct-16 21-Nov-16 21-Nov-16 27 6,857 356 VF IMAGEWEAR INC 7-Dec-16 391 391 0026041717 Direct Deposit 7-Deo-16 7-Dec-16 7-Dec-16 17-Jan-17 17-Jan-17 41 16,013 357 VFIMAGEWEARINC 27-Jan-17 380 380 0026383501 Direct Deposit 27-Jan-17 27-Jan-17 27-Jan-17 21-Fob-17 21-Feb-17 25 9,504 358 VFIMAGEWEARINC 22-Feb-17 350 350 0026561863 Direct Deposit 22-Feb-17 22-Fob-17 22-Feb-17 20-Mar-17 20-Mar-17 26 9,105 359 VIAERO WIRELESS 16-Apr-16 1,786 l,7S6 2029040416-04 l 616 CHECK 17-Feb-16 16-Apr-16 17-Mar-16 22-Apr-16 2-May-16 46 82,166 360 Walsh. Micheal D (Mickey) 12-0ct-16 108 !08 IEXP-1496085 Direct Deposit 22-Sep-16 22-Sep-16 22-Sep-16 13-0ct-!6 13-0ot-!6 21 2,268 361 WASTE MA."IAGEMEl\'T 1-Apr-16 62 62 047082410870 CHECK 1-Mar-16 31-Mar-16 16-Mar-16 13-Apr-16 21-Apr-16 36 2,245 362 WASTE MANAGEMEl\'T 27-Feb-17 271 271 059107425205 CHECK 1-Mar-17 3!-Mar-17 !6-Mar-17 27-Mar-17 5-Apr-17 20 5,420 363 WASTE MANAGEMENT OF NORTHERN COLORADC 27-Feb-17 140 140 377858725346 CHECK 1-Mar-17 3!-Mar-17 16-Mar-17 15-Mar-17 27-Mar-17 11 1,541 364 Weinberg, Paul A 22-Aug-16 10 10 IEXP-1418919 Direct Deposit 20-Aug-16 20-Aug-16 20-Aug-16 24-Aug-16 24-Aug-16 4 41 365 WESTERN UNION FINANCIAL SERVICES IN( 2-Mar-17 8,511 294 CPI112185 CHECK l-Feb-17 28·Feb-17 14-Feb-17 20-Mar-17 5-Apr-17 50 14,692 366 Whitaker, Roger J 27-Sep-16 314 314 IEXP-1433271 Direct Deposit 17-Sep-16 23-Sep-16 20-Sep-16 30-Sep-16 30-Sep-16 10 3,143 367 WHITE RIVER ELECTRIC ASSOClATl01' 28-Apr-16 18 18 80229800_042816 CHECK 26-Mar-17 26-Apr-17 10-Apr-17 ll-May-16 17-May-16 (329) (5,912) 368 WHITE RIVER ELECTRIC ASSOCIAT!Ol- 31-Aug-16 30 30 6166004 083116 CHECK 27-Jul-!6 26-Aug-16 11-Aug-16 14-Sep-16 20-Sep-16 40 1,187 369 White, Amity M 3-0ct-16 967 933 IEXP-l 4J8006 Direct Deposit 25-Sep-16 30-Sep-16 27-Sep-16 5-0ct-16 5-0ct-16 8 7,467 370 Willis, John M 5-Jul-16 3,585 3,429 IEXP-1273867 Direct Deposit ll-May-16 29-Jun-16 4-Jun-16 8-Jul-16 8-Jul-16 34 116,582 371 WILSON OFFICE INTERIORS LLC 4-May-16 4,404 440 56 Page 7 of7 CWCWP6-l Atmos Energy Corporation - Colorado Service Area Other O&M Payment Lag Test Year Ending March 31, 2017 Service Midpoint Weighted Line Invoice Invoice Colorado Invoice Payment Period Service Date Payment Payment Payment No. Vendor Date Amount Amount # Ti:Qe From To Period Paid Cleared lag: Lag: (•) (b) (c) (d) (e) (t) (g) (h) (i) (i) (k) (l)=k-(iorb) (mJ=O•d) ELEMENT FLEET 7-Apr-16 $ 2,306,780 $ 84,089 GE-Fleet- 07-APR-16 Direct Deposit l-Mar-16 31-Mar-16 16-Mar-16 8-Apr-16 8-Apr-16 23 s 1,934,042 2 ELEMENT FLEET 6-May-16 1,946,672 30,459 GE-Fleet- 06-MA Y-16 Direct Deposit l-Apr-16 30-Apr-16 15-Apr-16 9-May-16 9-May-16 24 731,012 3 ELEMENT FLEET 9-Jun-16 1,999,374 72,827 GE-Fleet - 09-JUN-16 Direct Deposit l-May-16 31-May-16 16-May-16 10-Jun-16 !O-Jun-16 25 1,820,674 4 ELEMENT FLEET 8-Jul-16 2,176,175 74,359 GE-Fleet- 08-JUL-16 Direct Deposit l-Jun-16 30-Jun-16 15-Jun-16 14-Jul-16 14-Jul-16 29 2,156,405 5 ELEMENT FLEET 9-Aug-16 1,933,000 57,191 GE-Fleet - 09-AUG-16 Direct Deposit 1-Jul-16 31-Jul-16 !6-Jul-16 JO-Aug-16 10-Aug-16 25 1,429,765 6 ELEMENT FLEET 8-Sep-16 1,888,329 77,027 GE-Fleet-08-SEP-16 DirectDeposit 1-Aug-16 31-Aug-16 16-Aug-16 9-Sep-16 9-Sep-16 24 1,848,652 7 ELEMENT FLEET 11-0ct-16 2,303,177 62,434 GE-Fleet- 11-0CT-16 Direct Deposit l-Sep-16 30-Sep-16 15-Sep-16 13-0ct-16 13-0ct-16 28 1,748,163 8 ELEMENT FLEET 7-Nov-16 2,052,856 79,109 GE-Fleet-07-NOV-16 DirectDeposit l-Oct-16 31-0ct-16 16-0ct-16 8-Nov-16 8-Nov-16 23 1,819,497 9 ELEMENT FLEET 6-Dec-16 2,256,504 78,276 GE-Fleet- 06-DEC-16 Direct Deposit l-Nov-16 30-Nov-16 15-Nov-16 8-Dec-16 8-Dec-16 23 1.800.342 10 ELEMENT FLEET 5-Jan-17 2,167,530 76,806 GE-Fleet- 05-JAN-17 Direct Deposit 1-Dec-16 31-Dec-16 16-Dec-16 6-Jan-17 6-Jan-17 21 1,612,927 _, 11 ELEMENTFLBBT 7-Feb-17 1,913,376 62,849 GE-Fleet-07-FEB-17 DirectDeposit l-Jan-17 31-Jan-l 7 16-Jan-17 8-Feb-17 8-Feb-17 _?' 1,445,524 12 ELEMENT FLEET 28-Mar-17 2,367,768 86.385 GE-Fleet- 28-MAR-17 Direct Deposit l-Feb-17 28-Feb-17 14-Feb-17 30-Mar-17 30-Mar-17 44 3,800,936 Test Year Colorado Element Fleet $ 841,810 26 $ 22,147,939 Total normalized other O&M 9,043,759 Element Fleet percent of total O&M 9.31% O&M Sample Excluding Element Fleet 271,682 O&M Sample with GE Fleet at percent of total from above 299,566 Adjusted Element Fleet amount in sample $ 27,884 Page 1 ofl Schedule CWC7 Atmos Energy Corporation - Colorado Service Area Franchise Tax & Sales Tax Test Year Ending March 31, 2017 Line No. Description Amount (a) (b) 1 State Sales Tax - Paid monthly by the 20th of the following month. 2 3 March 2017 Ending Sales Tax Collected [1] 3,285,572.26 4 5 Payment lag 35.21 6 7 8 9 Franchise Fees 10 11 March 2017 Ending Franchise Fees Collected [1] $ 2,665,080.41 12 13 Average Payment Lag (WP 7-1) 44.47 [I] Source: COS WP 8-11-1 Page 1of1 Atmos Energy Corporation - Colorado Service Area CWCWP7-l Franchise Fee Payment Lag Test Year Ending March 31, 2017 Franchise Payment Franchise Franchise Period Payment Weighted Vendor Frequency Date Paid Period Start Period End Midpoint Total Payment Lag Lag (a) (b) (o) (d) (e) Ct) (g) (h) (i) Ault, City of Quarterly 4/19/2016 1/1/2016 313112016 2/15/2016 9,311.24 64 0.2204 Ault, City of Quarterly 7/18/2016 411/2016 6/30/2016 5116/2016 4,820.77 63 0.1123 Ault, City of Quarterly 10/14/2016 7/1/2016 9/30/2016 8/15/2016 2,759.86 60 0.0607 Ault, City of Quarterly 1116/2017 10/1/2016 12/31/2016 11/15/2016 6,424.27 62 0.1461 Brookside, Town of Annual 1116/2017 1/1/2016 12/3112016 7/112016 1,455.43 199 0.1069 Buena Vista, City of Quarterly 4/19/2016 111/2016 3/31/2016 2/15/2016 4,144.99 64 0.0981 Buena Vista, City of Quarterly 7/18/2016 4/1/2016 6/30/2016 5/16/2016 2,440.56 63 0.0569 Buena Vista, City of Quarterly 10/14/2016 711/2016 9/30/2016 8115/2016 1,609.81 60 0.0354 Buena Vista, City of Quarterly 1116/2017 10/1/2016 12/31/2016 11115/2016 2,756.90 62 0.0627 Canon City, City of Quarterly 4/19/2016 111/2016 3/3112016 2115/2016 54,803.78 64 1.2974 Canon City, City of Quarterly 7/18/2016 4/1/2016 6/30/2016 5/16/2016 30,652.98 63 0.7143 Canon City, City of Quarterly 10/14/2016 7/112016 9130/2016 8/15/2016 14,948.72 60 0.3290 Canon City, City of Quarterly 1/16/2017 10/1/2016 12/3112016 11/15/2016 28,523.85 62 0.6489 Cortez, City of Quarterly 4/19/2016 11112016 3/31/2016 2/15/2016 39,156.62 64 0.9270 Cortez, City of Quarterly 7/18/2016 4/1/2016 6/30/2016 5/16/2016 21,374.89 63 0.4981 Cortez, City of Quarterly 10/14/2016 7/112016 9/30/2016 8/15/2016 12,255.36 60 0.2697 Cortez, City of Quarterly 1116/2017 10/112016 12/3112016 11115/2016 22,281.75 62 0.5069 Craig, City of Annual 5/13/2016 11112016 12/3112016 7/112016 84,154.00 (50) (1.5409) Crested Butte, City of Quarterly 4/19/2016 111/2016 3/3112016 2/15/2016 9,837.01 64 0.2329 Crested Butte, City of Quarterly 7/18/2016 4/112016 6/30/2016 5/16/2016 5,788.06 63 0.1349 Crested Butte, City of Quarterly 10/14/2016 7/112016 9/30/2016 8/15/2016 3,561.46 60 0.0784 Crested Butte, City of Quarterly 1116/2017 10/112016 12/3112016 11/15/2016 5,312.52 62 0.1209 Dolores, City of Annual 1116/2017 11112016 12/3112016 711/2016 11,528.07 199 0.8465 Dove Creek, City of Quarterly 4/19/2016 11112016 3/3112016 2/15/2016 3,405.85 64 0.0806 Dove Creek, City of Quarterly 7/18/2016 4/112016 6/30/2016 5116/2016 1,811.54 63 0.0422 Dove Creek, City of Quarterly 10/14/2016 7/112016 9/30/2016 8/15/2016 978.78 60 0.0215 Dove Creek, City of Quarterly 1/16/2017 10/112016 12/31/2016 11/15/2016 2,400.74 62 0.0546 Durango, City of Monthly 4/19/2016 3/112016 3/31/2016 3/16/2016 14,000.00 34 0.1761 Durango, City of Monthly 5/13/2016 4/1/2016 4/30/2016 4/15/2016 14,000.00 28 0.1424 Durango, City of Monthly 6113/2016 5/1/2016 5/31/2016 5/1612016 4,500.00 28 0.0466 Durango, City of Monthly 7118/2016 6/112016 6/30/2016 6/15/2016 4,500.00 33 0.0541 Durango, City of Monthly 8118/2016 7/1/2016 7/31/2016 7/16/2016 4,500.00 33 0.0549 Durango, City of Monthly 9116/2016 8/112016 8/3112016 8/16/2016 4,500.00 31 0.0516 Durango, City of Monthly 10114/2016 9/112016 9/30/2016 9/15/2016 4,500.00 29 0.0474 Durango, City of Monthly 11116/2016 10/112016 10/3112016 10/16/2016 4,500.00 31 0.0516 Durango, City of Monthly 12/12/2016 111112016 11130/2016 11/15/2016 14,000.00 27 0.1372 Durango, City of Monthly 1116/2017 12/1/2016 12/31/2016 12/16/2016 17,000.00 31 0.1949 Durango, City of Monthly 2/15/2017 11112017 1/31/2017 1/16/2017 14,000.00 30 0.1554 Durango, City of Monthly 3/17/2017 2/1/2017 2/28/2017 2/14/2017 14,000.00 31 0.1579 Page 1 of5 Atmos Energy Corporation - Colorado Service Area CWCWP7-1 Franchise Fee Payment Lag Test Year Ending March 31, 2017 Franchise Payment Franchise Franchise Period Payment Weighted Vendor Frequency Date Paid Period Start Period End Midpoint Total Payment Lag Lag (a) (b) (c) (d) (o) (t) (g) (h) (i) Eads, City of Monthly 4/19/2016 3/1/2016 3131/2016 3/16/2016 654.18 34 0.0082 Eads, City of Monthly 5/13/2016 4/1/2016 4/30/2016 4/15/2016 544.40 28 0.0055 Eads, City of Monthly 6/13/2016 5/1/2016 5/31/2016 5/16/2016 409.91 28 0.0042 Eads, City of Monthly 7/18/2016 6/1/2016 6/30/2016 6/15/2016 283.60 33 0.0034 Eads, City of Monthly 8/18/2016 7/1/2016 7/31/2016 7116/2016 224.93 33 0.0027 Eads, City of Monthly 9/16/2016 8/1/2016 8/3112016 8116/2016 213.29 31 0.0024 Eads, City of Monthly 10/14/2016 9/1/2016 9/3012016 9115/2016 210.19 29 0.0022 Eads, City of Monthly 11116/2016 1011/2016 10131/2016 10/16(2016 219.24 31 0.0025 Eads, City of Monthly 12112/2016 11/112016 . l 1!30/2016 11/15/2016 259.07 27 0.0025 Eads, City of Monthly 1116/2017 12/112016 12/3112016 12/16/2016 498.65 31 0.0057 Eads, City of Monthly 2/15/2017 11112017 1!31/2017 1/16/2017 965.92 30 0.0107 Eads, City of Monthly 3117/2017 2/112017 212812017 2/14/2017 862.18 31 0.0097 Eaton, City of Quarterly 4/19/2016 1/1/2016 3/31/2016 2/15/2016 15,737.21 64 0.3726 Eaton, City of Quarterly 7/18/2016 4/1/2016 6/30/2016 5!16/2016 7,685.90 63 0.1791 Eaton, City of Quarterly 10/14/2016 7/112016 9/30(2016 8/15/2016 5,297.99 60 0.1166 Eaton, City of Quarterly 1116/2017 10/1/2016 12/31/2016 11/15/2016 11,640.86 62 0.2648 Evans, City of Monthly 4/19/2016 3/1/2016 3/31/2016 3/16/2016 19,583.63 34 0.2463 Evans, City of Monthly 5/13/2016 4/1/2016 4/30/2016 4115/2016 17,853.18 28 0.1816 Evans, City of Monthly 6/13/2016 511/2016 5/31/2016 5/16/2016 13,313.05 28 0.1379 Evans, City of Monthly 7/18/2016 6/1/2016 6/30/2016 6/15/2016 9,287.97 33 0.1117 Evans, City of Monthly 8/18/2016 711/2016 7/31/2016 7/16/2016 7,111.98 33 0.0868 Evans, City of Monthly 9/16/2016 811/2016 8/31/2016 8116/2016 6,558.63 31 0.0752 Evans, City of Monthly 10/14/2016 9!1/2016 9/30/2016 9/15/2016 7,027.72 29 0.0741 Evans, City of Monthly 11/16/2016 10/1/2016 10/31/2016 10/16/2016 7,527.79 31 0.0863 Evans, City of Monthly 12/12/2016 111112016 11130/2016 11/15/2016 9,522.54 27 0.'0933 Evans, City of Monthly 1/16/2017 12/1/2016 12/31/2016 12/16/2016 18,671.18 31 0.2141 Evans, City of Monthly 2/15/2017 1/112017 1/31/2017 1116/2017 30,574.13 30 0.3393 Evans, City of Monthly 3/17/2017 2/112017 2/28/2017 2/14/2017 24,210.51 31 0.2731 Florence, City of Monthly 4/19/2016 311/2016 3/31/2016 3/16/2016 4,004.15 34 0.0504 Florence, City of Monthly 5/13/2016 4/1/2016 4/30/2016 4/15/2016 3,958.81 28 0.0403 Florence, City of Monthly 6/13/2016 5/1/2016 5131/2016 5/16/2016 2,799.46 28 0.0290 Florence, City of Monthly 7/18/2016 6/1/2016 6/30/2016 6/15/2016 1,775.27 33 0.0213 Florence, City of Monthly 8/18/2016 7/1/2016 7/31/2016 7/16/2016 1,438.35 33 0.0176 Florence, City of Monthly 9/16/2016 8/1/2016 8131/2016 8/16/2016 1,368.74 31 0.0157 Florence, City of Monthly 10/14/2016 9/112016 9/30/2016 9/15/2016 1,501.75 29 0.0158 Florence, City of Monthly 11/16/2016 10/112016 10/31/2016 10/16/2016 1,657.78 31 0.0190 Florence, City of Monthly 12/12/2016 1111/2016 11/30/2016 11/15/2016 2,151.56 27 0.0211 Florence, City of Monthly 1/16/2017 12/1/2016 12/3112016 12/16/2016 4,759.66 31 0.0546 Florence, City of Monthly 2/15/2017 1/112017 1131/2017 1116/2017 6,799.85 30 0.0755 Page2 of5 ... ··.·.-.·-·.··:.-.-· Atmos Energy Corporation - Colorado Service Area CWCWP7-l Franchise Fee Payment Lag Test Year Ending March 31, 2017 Franchise Payment Franchise Franchise Period Payment Weighted Vendor Frequency Date Paid Period Start Period End Midpoint Total Payment Lag Lag (a) (b) (c) (d) (e) (f) (g) (h) (i) Florence, City of Monthly 3/17/2017 2/1/2017 2128/2017 2/14/2017 5,324.33 31 0.0601 Garden City, City of Quarterly 4/19/2016 1/1/2016 3/31/2016 2/15/2016 2,147.65 64 0.0508 Garden City, City of Quarterly 7/18/2016 4/1/2016 6130/2016 5/16/2016 1,067.67 63 0.0249 Garden City, City of Quarterly 10/14/2016 7/1/2016 9/30/2016 8/15/2016 504.58 60 0.0111 Garden City, City of Quarterly 1116/2017 10/1/2016 12/31/2016 11/15/2016 811.42 62 0.0185 Gilcrest, City of Annual 1/16/2017 1/1/2016 12/31/2016 711/2016 8,333.96 199 0.6119 Granada, City of Quarterly 4/19/2016 1/1/2016 3/31/2016 2/15/2016 1,677.56 64 0.0397 Granada, City of Quarterly 7/18/2016 4/1/2016 6/30/2016 5/16/2016 828.45 63 0.0193 Granada, City of Quarterly 10/14/2016 7/1/2016 9/30/2016 8/15/2016 428.63 60 0.0094 Granada, City of Quarterly 1/16/2017 10/112016 12/3112016 11/15/2016 757.30 62 0.0172 Greeley, City of Monthly 4/19/2016 3/112016 3/31/2016 3/16/2016 128,697.69 34 1.6186 Greeley, City of Monthly 5113/2016 4/112016 413012016 4/15/2016 118,225.13 28 1.2026 Greeley, City of Monthly 6/13/2016 5/1/2016 5/31/2016 5/16/2016 89,137.96 28 0.9232 Greeley, City of Monthly 7/18/2016 6/1/2016 6/30/2016 6/15/2016 60,919.86 33 0.7324 Greeley, City of Monthly 8/18/2016 7/112016 7/3112016 7/16/2016 46,670.71 33 0.5697 Greeley, City of Monthly 9/16/2016 8/1/2016 8/31/2016 8/16/2016 43,103.42 31 0.4943 Greeley, City of Monthly 10/14/2016 9/112016 9/30/2016 9/15/2016 48,200.28 29 0.5081 Greeley, City of Monthly 11116/2016 1011/2016 10/31/2016 10/16/2016 53,480.26 31 0.6133 Greeley, City of Monthly 12/12/2016 ll/112016 Il/30/2016 ll/15/2016 68,754.80 27 0.6740 Greeley, City of Monthly 1/16/2017 12/112016 12/31/2016 12/16/2016 144,881.35 31 1.6614 Greeley, City of Monthly 2/15/2017 1/1/2017 1/31/2017 1/16/2017 209,334.06 30 2.3230 Greeley, City of Monthly 3/17/2017 2/1/2017 2/28/2017 2114/2017 157,339.30 31 1.7751 Gunnison, City of Quarterly 4/19/2016 1/1/2016 3/31/2016 2/15/2016 50,520.37 64 1.1960 Gunnison, City of Quarterly 7/18/2016 4/1/2016 6/30/2016 5/!6/2016 26,575.28 63 0.6193 Gunnison, City of Quarterly 10/14/2016 7/I/2016 9/30/2016 8/15/2016 11,682.38 60 0.2571 Gunnison, City of Quarterly 1116/2017 10/1/2016 12/31/2016 11115/2016 23,599.67 62 0.5369 Hayden, City of Monthly 4/19/2016 3/1/2016 3/31/2016 3/16/2016 677.25 34 0.0085 Hayden, City of Monthly 5/13/2016 4/I/2016 4130/2016 4/1512016 601.78 28 0.0061 Hayden, City of Monthly 6/13/2016 5/1/2016 5/3112016 5/16/2016 404.28 28 0.0042 Hayden, City of Monthly 7/18/2016 611/2016 6/30/2016 6/15/2016 246.14 33 0.0030 Hayden, City of Monthly 8/18/2016 7/112016 7/31/2016 7/16/2016 186.23 33 0.0023 Hayden, City of Monthly 9/16/2016 811/2016 8/31/2016 8/1612016 179.59 31 0.0021 Hayden, City of Monthly 10/14/2016 9/1/2016 9/30/2016 9/1512016 188.42 29 0.0020 Hayden, City of Monthly 11116/2016 10/1/2016 10/31/2016 10/1612016 265.18 31 0.0030 Hayden, City of Monthly 12/12/2016 1111/2016 11130/2016 ll/1512016 336.27 27 0.0033 Hayden, City of Monthly 1116/2017 12/l/2016 12131/2016 12/1612016 672.20 31 0.0077 Hayden, City of Monthly 2/15/2017 111/2017 1/31/2017 1/1612017 905.61 30 0.0100 Hayden, City of Monthly 3/17/2017 211/2017 2/28/2017 2/1412017 739.05 31 0.0083 Holly, City of Quarterly 4/19/2016 1/1/2016 3/31/2016 2115/2016 3,958.38 64 0.0937 Page 3 of5 Atmos Energy Corporation - Colorado Service Area CWCWP7-1 Franchise Fee Payment Lag Test Year Ending March 31, 2017 Franchise Payment Franchise Franchise Period Payment Weighted Vendor Freguenc;i:: Date Paid Period Start Period End Midpoint Total Payment Lag Lag (a) (b) (c) (d) (e) (f) (g) (h) (i) Holly, City of Quarterly 7/18/2016 4/112016 6/30/2016 5116/2016 1,821.92 63 0.0425 Holly, City of Quarterly 10/14/2016 7/1/2016 9/30/2016 8/15/2016 1,086.74 60 0.0239 Holly, City of Quarterly 1/16/2017 10/1/2016 12/31/2016 11115/2016 2,279.82 62 0.0519 Hudson, City of Annual 1/16/2017 1/1/2016 12/31/2016 7/112016 12,308.07 199 0.9037 Keenesburg, City of Quarterly 4/19/2016 111/2016 3/31/2016 2/15/2016 3,245.47 64 0.0768 Keenesburg, City of Quarterly 7/18/2016 4/1/2016 6/30/2016 5/16/2016 1,785.38 63 0.0416 Keenesburg, City of Quarterly 10/14/2016 7/1/2016 9/30/2016 8/15/2016 881.51 60 0.0194 Keenesburg, City of Quarterly 1/16/2017 10/112016 12131/2016 11/15/2016 1,587.60 62 0.0361 Kersey, City of Annual 1/16/2017 1/112016 12/31/2016 7/1/2016 10,293.83 199 0.7558 La Salle, City of Annual 1116/2017 1/1/2016 12/3112016 7/1/2016 25,888.10 199 1.9009 Lamar, City of Monthly 4/19/2016 3/1/2016 3/31/2016 3116/2016 10,103.80 34 0.1271 Lamar, City of Monthly 5/13/2016 4/1/2016 4/30/2016 4/15/2016 9,254.98 28 0.0941 Lamar, City of Monthly 6/13/2016 5/1/2016 5/3112016 5/16/2016 6,503.42 28 0.0674 Lamar, City of Monthly 7/18/2016 6/1/2016 6/30/2016 6/15/2016 4,770.28 33 0.0573 Lamar, City of Monthly 8/18/2016 7/112016 7/31/2016 7/16/2016 4,095.41 33 0.0500 Lamar, City of Monthly 9/16/2016 8/112016 8/31/2016 8/16/2016 3,943.93 31 0.0452 Lamar, City of Monthly 10/14/2016 9/112016 9/30/2016 9/15/2016 4,176.59 29 0.0440 Lamar, City of Monthly 11/16/2016 10/1/2016 10/31/2016 10/16/2016 4,448.70 31 0.0510 Lamar, City of Monthly 12/12/2016 11/1/2016 11/30/2016 11/15/2016 5,895.22 27 0.0578 Lamar, City of Monthly 1116/2017 12/1/2016 12/31/2016 12/16/2016 14,315.97 31 0.1642 Lamar, City of Monthly 2/15/2017 111/2017 1/31/2017 1/16/2017 19,374.86 30 0.2150 Lamar, City of Monthly 3/17/2017 2/1/2017 2/28/2017 2/14/2017 14,111.83 31 0.1592 Mancos, City of Quarterly 4/19/2016 1/1/2016 3/31/2016 2/15/2016 5,635.73 64 0.1334 Mancos, City of Quarterly 7/18/2016 4/1/2016 6/3012016 5/16/2016 3,176.27 63 0.0740 Mancos, City of Quarterly 10/14/2016 7/1/2016 9/30/2016 8/15/2016 1,703.05 60 0.0375 Mancos, City of Quarterly 1/16/2017 10/1/2016 12/31/2016 11115/2016 3,422.32 62 0.0779 Meeker, City of Annual 1116/2017 1/1/2016 12/31/2016 7/1/2016 8,282.36 199 0.6081 Mt Crested Butte, City of Quarterly 4/19/2016 1/1/2016 3/31/2016 2/15/2016 3,901.05 64 0.0924 Mt Crested Butte, City of Quarterly 7/18/2016 4/1/2016 6/30/2016 5/16/2016 2,040.04 63 0.0475 Mt Crested Butte, City of Quarterly 10/14/2016 7/1/2016 9/3012016 8/15/2016 1,071.90 60 0.0236 Mt Crested Butte, City of Quarterly 1116/2017 10/112016 12/3112016 11/15/2016 1,769.29 62 0.0402 Nunn, City of Quarterly 4/19/2016 11112016 3/3112016 2/15/2016 2,070.10 64 0.0490 Nunn, City of Quarterly 7/18/2016 4/1/2016 6/3012016 5/16/2016 1,006.58 63 0.0235 Nunn, City of Quarterly 10/14/2016 7/1/2016 9130/2016 8/15/2016 499.63 60 0.0110 Nunn, City of Quarterly 1116/2017 10/112016 12131/2016 11/15/2016 1,322.18 62 0.0301 Pierce, City of Quarterly 4/19/2016 1/112016 3/31/2016 2/15/2016 4,353.00 64 0.1031 Pierce, City of Quarterly 7/18/2016 4/112016 6/30/2016 5/16/2016 2,272.09 63 0.0529 Pierce, City of Quarterly 10/14/2016 7/112016 9/30/2016 8/15/2016 1,234.35 60 0.0272 Pierce, City of Quarterly 1116/2017 10/112016 12/31/2016 11/15/2016 3,008.83 62 0.0684 Page 4 of5 Atmos Energy Corporation - Colorado Service Area CWCWP7-1 Franchise Fee Payment Lag Test Year Ending March 31, 2017 Franchise Payment Franchise Franchise Period Payment Weighted Vendor Frequency Date Paid Period Start Period End Midpoint Total Payment Lag Lag (a) (b) (c) (d) (•) (t) (g) (h) (i) Platteville, Town of Quarterly 4/19/2016 1/112016 3/31/2016 2/15/2016 15,025.54 64 0.3557 Platteville, Town of Quarterly 7/18/2016 4/1/2016 6/30/2016 5/16/2016 7,942.46 63 0.1851 Platteville, Town of Quarterly 10/14/2016 7/112016 9/30/2016 8/15/2016 3,763.93 60 0.0828 Platteville, Town of Quarterly 1/16/2017 10/112016 12/31/2016 11/15/2016 8,013.35 62 0.1823 Poncha Springs, City of Quarterly 4/19/2016 1/1/2016 3/31/2016 2/15/2016 2,934.18 64 0.0695 Poncha Springs, City of Quarterly 7/18/2016 4/112016 6/30/2016 5/16/2016 1,467.43 63 0.0342 Poncha Springs, City of Quarterly 10/14/2016 7/112016 9/30/2016 8/15/2016 860.89 60 0.0189 Poncha Springs, City of Quarterly 1116/2017 10/1/2016 12131/2016 11/15/2016 1,519.25 62 0.0346 Pritchett, City of Annual 1116/2017 1/1/2016 12/31/2016 7/1/2016 1,028.60 199 0.0755 Rockvale, City of Annual 2/15/2017 1/112016 12/3112016 7/112016 1,235.11 229 0.1044 Salida, City of Quarterly 4/19/2016 11112016 3/31/2016 2/15/2016 45,137.58 64 1.0686 Salida, City of Quarterly 7/18/2016 4/1/2016 6/30/2016 5/16/2016 24,840.77 63 0.5789 Salida, City of Quarterly 10/14/2016 7/112016 9/30/2016 8/15/2016 13,484.74 60 0.2968 Salida, City of Quarterly 1116/2017 10/1/2016 12/3112016 11/15/2016 23,046.29 62 0.5243 Springfield, City of Quarterly 4/19/2016 1/112016 3131/2016 2/15/2016 8,542.94 64 0.2022 Springfield, City of Quarterly 7/18/2016 4/112016 6/30/2016 5/16/2016 4,202.64 63 0.0979 Springfield, City of Quarterly 10/14/2016 7/1/2016 9/30/2016 8/15/2016 2,142.99 60 0.0472 Springfield, City of Quarterly 1116/2017 10/112016 12/3112016 11115/2016 4,089.17 62 0.0930 Steamboat Springs, City of Quarterly 4119/2016 11112016 3/3112016 2/15/2016 104,112.77 64 2.4648 Steamboat Springs, City of Quarterly 7/18/2016 4/112016 6/30/2016 5/16/2016 50,120.74 63 1.1680 Steamboat Springs, City of Quarterly 10/14/2016 7/1/2016 9/30/2016 8/15/2016 26,041.13 60 0.5731 Steamboat Springs, City of Quarterly 1/16/2017 10/1/2016 12/31/2016 11115/2016 51,379.68 62 1.1688 Walsh, City of Quarterly 4/19/2016 11112016 3/31/2016 2/15/2016 2,033.56 64 0.0481 Walsh, City of Quarterly 7/18/2016 4/1/2016 6/30/2016 5/16/2016 936.76 63 0.0218 Walsh, City of Quarterly 10/1412016 7/112016 9/3012016 8/15/2016 472.69 60 0.0104 Walsh, City of Quarterly 1116/2017 10/112016 12/3112016 11115/2016 986.21 62 0.0224 Wiley, City of Annual 2/1512017 1/112016 12/31/2016 7/1/2016 4,796.84 229 0.4054 WILLIAMSBURG, TOWN OF Annual 2/15/2017 1/112016 12/31/2016 7/1/2016 2,528.21 229 0.2137 Windsor, Town of Quarterly 4119/2016 11112016 3131/2016 2/1512016 5,802.84 64 0.1374 Windsor, Town of Quarterly 7/18/2016 4/1/2016 6/30/2016 5/16/2016 3,485.07 63 0.0812 Windsor, Town of Quarterly 10/14/2016 7/1/2016 9/30/2016 8/15/2016 2,655.81 60 0.0585 Windsor, Town of Quarterly 1/16/2017 10/1/2016 12/31/2016 11/15/2016 5,791.42 62 0.1318 Grand Total $ 2,703,393.26 44.47 Page 5 of5 Schedule ewes Atmos Energy Corporation - Colorado Service Area State and Federal Income Taxes Test Year Ending March 31, 2017 Line Due Tax Year Tax Year Lead Weighted No. Date Begin End Weight Days Lead Days (a) (b) (c) (d) (e) (±) State and Federal Income Tax 2 15-Jan 1-0ct 30-Sep 0.25 (76.0) (19.0) ,., .) 15-Mar 1-0ct 30-Sep 0.25 (17.0) (4.3) 4 15-Jun I-Oct 30-Sep 0.25 75.0 18.8 5 15-Sep 1-0ct 30-Sep 0.25 167.0 41.8 6 7 Total 37.3 Page 1of1 Atmos Energy Corporation - Colorado Service Area Schedule CWC9 Other Taxes Test Year Ending March 31, 2017 Line Lag As Adjusted Dollar No. DescriEtion Daj'.S $Amount Daj'.S (a) (b) (c) (d) 1 FICA - Paid on the first banking day after each 2 payday. 22.30 251,957 5,619,531 3 4 Federal Unemployment - Paid quarterly in arrears 5 at the end of the month following each quarter. 83.38 2,184 182,096 6 7 State Unemployment - Paid quarterly in arrears 8 at the end of the month following each quarter. 83.38 3,088 257,467 9 10 Denver City Head Tax - Paid monthly by the end 11 of the following month. 45.20 122 5,496 12 13 Ad Valorem - Calendar year taxes are paid in last 14 day in April of the following year. 302.50 1,638,564 495,665,610 15 16 Occupational Licenses - Paid annually by the end 17 of the year prior to year of doing business 0.00 510 0 18 19 PSC - Prepaid quarterly on the 15th of the month 20 beginning each quarter. 0.00 232,270 0 21 22 DOT Transmission User Tax - Paid annually at 23 the end of the first month of the current year 0.00 0 0 24 25 Sub-total 235.70 2,128,695 501,730,200 26 27 Allocated SSU Taxes 235.70 335,179 79,001,770 28 29 Total 2,463,875 580,731,970 30 Lag Days 235.70 Page 1 ofl Atmos Energy Corporation - Colorado Service Area CWCWP9-1 Taxes Other Than Income Taxes Test Year Ending March 31, 2017 Line No. DescriEtion Total [I] (a) (b) 1 FICA (01210) $ 235,700 2 Federal Unemployment (01211) 2,038 3 State Unemployment (01212) 2,947 4 FICA Accrual (01213) (2,814) 5 FUTA Accrual (01214) (19) 6 SUTA Accrual (01215) (93) 7 Denver City Head Tax (01220) 112 8 Payroll Tax Projects (01256) 8,398 9 Taxes Other Than Inc Tax (09344-5) 89,311 IO Ad Valorem accrual (30101-2) 1,691,213 11 Occupational License (30103) 510 12 City Franchise Fee (30107) 13 US DOT Pipe Safety funding (30108) 14 Billing for CSC Depr & Taxes Other (41129) 115,813 15 Billing for SS Depr & Taxes Other (41130) 130,056 16 Public Srvc Comm Assessment (30112) 233,574 17 Total CO Taxes Other per books 2,506,745 18 19 Adjustments 20 CO Ad valorem Adjustment (52,649) 21 PSC Assessment Adjustment (1,303) 22 Payroll Tax Adjustment 11,082 23 Total Adjustments (42,871) 24 25 Total Taxes Other Than Inc Tax, Adjusted $2,463,874 Page 1 of2 Atmos Energy Corporation - Colorado Service Area CWCWP9-1 Taxes Other Than Income Taxes Test Year Ending March 31, 2017 Line No. Description Total [1] (a) (b) 26 27 Pay Adj [2] 28 FICA 19,072 251,957 29 FUTA 165 2,184 30 SUTA 234 3,088 31 Denver City Head Tax 9 122 32 Allocated from SSU & GO 335,179 33 AdValorem 1,638,564 34 PSC 232,270 35 Occupational License 510 36 US DOT 0 37 19,480 $ 2,463,875 [1] Source: COS Schedule 5 [2] Allocated payroll adjustment and benefits load Page2 of2 S,42.% 23.51 4.29 Northwest Natural Gas Comparry NWN $59.18 4.30% 4.5D% S.OOo/o :3.415'% 3.46% 5.48% 80.00% 65.00% 65.58% 7.60% 32.63 5,95 Sempra Energy SRc S105.28 8.70% 9.27% 8.00% 2.73% 2.73% 5.48% 65.00% 61.00% 65.58% "'""$0,00 B.46% 23.19 4.2-3 Southwest Ga:s Corp.orati.o~ swx $76.46 5.00% 4.CH)% 5.50% .8.02% 4.00% 5.48% 53.DO% 52,00% 155,58% (.SO.OOJ 7.83% 28.26 5.16 Spite ln-c SR S64.75 4.10% 4.05% 8,00% 5.24% 4.05% 5.48% '60.00% 54.00% 65.58% (;&Li.1'.10) 8,66% 21.76 3.97 Vectren Coreoratia.n we $52.69 5.70% 5.57% 7.00% 6.46% 5.57% 5.48% 63.00% 58,CIDo/c. 65.58% (!Cl'.00] a.e3% 20.64 3.77 Mean 8.41% Mox 8.83% Min 7,60% Projected Annual Ea:rnin~s per Sl'tare [15! 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