FILED March 2, 2018 INDIANA UTILITY REGULATORY COMMISSION STATE OF INDIANA
INDIANA UTILITY REGULATORY COMMISSION
PETITION OF NORTHERN INDIANA PUBLIC ) SERVICE COMPANY FOR (1) AUTHORITY TO ) MODIFY ITS RATES AND CHARGES FOR GAS ) UTILITY SERVICE THROUGH A PHASE IN OF ) RATES; (2) MODIFICATION OF THE SETTLEMENT ) AGREEMENTS APPROVED IN CAUSE NO. 43894; (3) ) APPROVAL OF NEW SCHEDULES OF RATES AND ) CHARGES, GENERAL RULES AND REGULATIONS, ) CAUSE NO. 44988 AND RIDERS; (4) APPROVAL OF REVISED ) DEPRECIATION RATES APPLICABLE TO ITS GAS ) PLANT IN SERVICE; (5) APPROVAL OF NECESSARY ) AND APPROPRIATE ACCOUNTING RELIEF; AND (6) ) AUTHORITY TO IMPLEMENT TEMPORARY RATES ) CONSISTENT WITH THE PROVISIONS OF IND. ) CODE CH. 8-1-2-42.73 )
INDIANA OFFICE OF UTILITY CONSUMER COUNSELOR
PUBLIC'S EXHIBIT NO. 7
TESTIMONY OF OUCC WITNESS BRADLEY E. LORTON
MARCH 2, 2018
Respectfully submitted,
1URC PUBL\C'S 1 TiffanyT. :r~~~( REP0RTt R Attorney Deputy Consumer Counselor
Scott Franson Attorney No. 27839-49 Deputy Consumer Counselor Public's Exhibit No. 7 Cause No. 44988 Page 1 of50
TESTIMONY OF OUCC WITNESS BRADLEY E. LORTON, CRRA CAUSE NO. 44988 NORTHERN INDIANA PUBLIC SERVICE COMP ANY LLC
I. INTRODUCTION
1 Q: Please state your name and business address. 2 A: My name is Bradley E. Lorton, and my business address is 115 W. Washington
3 Street, Suite 1500 South, Indianapolis, Indiana, 46204.
4 Q: By whom are you currently employed and in what capacity? 5 A: I am a Utility Analyst in the Natural Gas Division of the Indiana Office of Utility
6 Consumer Counselor ("OUCC"). For a summary of my education and
7 professional experience, and general preparation for this case, please see
8 Appendix BEL-1 attached to my testimony.
9 Q: What is the purpose of your testimony? 10 A: I testify on the cost of common equity capital, sometimes referred to as the
11 authorized return on equity ("ROE"). In its direct case, Northern Indiana Public
12 Service Company LLC ("NIPSCO" or "Petitioner") recommended a 10.7% cost
13 of equity. Based on the results of the Discounted Cash Flow ("DCF") method,
14 Capital Asset Pricing Model ("CAPM"), and macroeconomic analysis, I conclude
15 that a cost of equity of 9.0% would be a reasonable and appropriate ROE for
16 NIPSCO.
II. PETITIONER'S PROPOSED COST OF EQUITY IS TOO IDGH
17 Q: What is Petitioner's current authorized ROE? 18 A: Petitioner's current ROE of 9.9% was approved by the Commission's Order in
19 Cause No. 43894 on November 4, 2010. Public's Exhibit No. 7 Cause No. 44988 Page 2 of50
1 Q: What is Petitioner's proposed ROE? 2 A: Petitioner's witness Mr. Vincent V. Rea recommends a return on equity of 10.7%.
3 Q: Do you agree with Mr. Rea's recommendation? 4 A: No.
5 Q: What level of ROE do you recommend? 6 A: I recommend an ROE of9.0%.
7 Q: Why do you recommend a lower authorized ROE at this time? 8 A: Neither my DCF nor my CAPM analyses yield a return as high as NIPSCO's
9 current 9.9%, let alone Mr. Rea's proposed 10.7% cost of equity. The current
10 economic condition, both nationally and in the State of Indiana, is best described
11 as a maturing recovery. Data on bond yields, dividend yields, inflation and
12 economic growth do not support projections of double-digit rates of return.
13 Moreover, regulated public utilities tend to be less risky than the market as a
14 whole.
15 Lower ROEs have become more common, and less threatening to public
16 utilities, over the past decades. Graph 1 illustrates the long term downward
17 national trend of average annual natural gas utility ROE. Each bar represents the
18 average of authorized ROE from each calendar year between 1990 and 2016, as
19 published by Regulatory Research Associates (S&P Global Market Intelligence)
20 (Attachment BEL-1). The average for 2016 was 9.5%. Public's Exhibit No. 7 Cause No. 44988 Page 3 of 50
GRAPHl
!AVERAGE AUTHORIZED RETURN ON EQUITYj I AmmaHy, 1990 through 2016 ! 14.00% 12 67%
12.00%
10.00%
~ -~ 8.00% ~"' :::
"E 6.00% ---- f------!
2.00%
0.00% ~~~~~~~~~~~~~~~~~~~~~~~~~~~ ~~~~~~~~~~~~~~~~~~~~~~~~~~~ Calendar Year
1 Not only has the annual natural gas utility average authorized ROE been
2 below 10% every year since 2011, but in the past four calendar years the average
3 authorized ROE has been above 10% only once, in the fourth quarter of 2014.
4 Graph 2 illustrates the quarterly averages from calendar year 2013 through 2016. Public's Exhibit No. 7 Cause No. 44988 Page 4 of50
GRAPH2
AVERAGE AUTHORIZED RETURN ON EQUITY QUARTERLY, 2013 THROUGH 2016 14.00% ,------, I Source: Regulatory Research Associates, "Regulatory Focus," January 18, 1017, p. 4 I 12.00%
10.28% 10;00% 9.57% 9.47% 9.60% 9·83% 9.54% 9'84% 9.45% 9.47% 9.43% 9.75% 9-68% 9.48% 9.42% 9,47% 9.60%
6.00% --
4.00%
2.00% -
0.00%
1 Moreover, investors are aware of the trend toward lower ROE. In March
2 2015, Moody's Investors Service issued an in-depth report titled, "Lower
3 Authorized Equity Returns Will Not Hurt Near-Term Credit Profiles,"
4 (Attachment BEL-2) in which Moody's posited that lowering authorized ROE's
5 will not inhibit the flow of cash to the utility:
6 The credit profiles of US regulated utilities will remain intact over 7 the next few years despite our expectation that regulators will 8 continue to trim the sector's profitability by lowering its authorized 9 returns on equity (ROE). Persistently low interest rates and a 10 comprehensive suite of cost recovery mechanisms ensure a low 11 business risk profile for utilities, prompting regulators to scrutinize 12 their profitability, which is defined as the ratio of net income to 13 book equity. We view cash flow measures as a more important 14 rating driver than authorized ROEs, and we note that regulators 15 can lower authorized ROEs without hurting cash flow, for instance Public's Exhibit No. 7 Cause No. 44988 Page 5 of 50
1 by targeting depreciation, or through special rate structures. 2 Regulators can also adjust a utility's equity capitalization in its rate 3 base. All else being equal, we think most utilities would prefer a 4 thicker equity base and a lower authorized ROE over a small 5 equity layer and a high authorized ROE.
6 (Moody's Investors Service, "Lower Authorized Equity Returns 7 Will Not Hurt Near-Term Credit Profiles," Sector In-Depth, March 8 10, 2015, p. 1.) (Emphasis added.)
9 Since this article was published, long term interest rates remain low inspite
10 of recent market pressures. Cost recovery mechanisms, like NIPSCO's TDSIC
11 tracker, remain common and continue to keep business risk low.
12 Moody's goes on to point out that local distribution companies' financial
13 performance has remained stable, even with declining authorized ROEs:
14 Utilities' actual financial performance remains stable. Earned 15 ROEs, which typically lag authorized ROEs, have not fallen as 16 much as authorized returns in recent years. Since 2007, vertically 17 integrated utilities, transmission and distribution only utilities, and 18 natural gas local distribution companies have maintained steady 19 earned RO Es in the 9% - 10% range.
20 (Id.) (Emphasis added.)
21 As detailed later in my testimony, my DCF and CAPM results for
22 NIPSCO are both below 9%; therefore, I recommend 9.0% as a reasonable cost of
23 common equity in NIPSCO's capital structure.
24 Q: Do you believe your recommendation will allow Petitioner access to capital 25 on reasonable terms? 26 A: Yes. As I have noted, the long term, national trend has been toward lower ROEs,
27 and specifically ROEs below 10%. As I elaborate in Section III of my testimony, I
28 use the same Combination Utility proxy group as Mr. Rea, and add a Gas Utility
29 proxy group to my analysis. Graph 3 compares the proportion of long term debt Public's Exhibit No. 7 Cause No. 44988 Page 6 of50
1 in the capital structures of each company in Mr. Rea's Combination Utility Group
2 to that of NIPSCO. Graph 4 makes the same comparison of NIPSCO to
3 companies in the Gas Utility Group.
GRAPH3
'i,m1g Term Debt Ratio 2018 I
Combination Utility Group J 70.0% Source: Value Line, December 1, 2017 60.0%
.g 50.0% i::, ~· ~ 40.0% Cl 34.0% 33.5% 30.0% ] 30.0% ~ sS 20.0%
10.0%
0.0% Public's Exhibit No. 7 Cause No. 44988 Page 7 of 50
GRAPH4
Long Term Debt Ratio 2018 I Gas Utility Group I 60.0% Source: Value Line, December 1, 2017
50.0% -- 49.5% ---- __48.0% __ ----47..5-%------o-· ------45.5 1/o 45.0% 44.0¾
~"" 40.0% I:::; .::;; "' ~ 30.0% ~ e~ ~ 20.0% ~
10.0% ! I I 0.0% , Spire, Inc. Southwest Gas South Jersey New Jersey Northwest Atmos Energy NIPSCO L______In_d_us_tr_ies __ R_e_so_ur_ce_s __N_a_tu_raJ_G_a_s ___c_o_rp_. ______,
1 Q: Why is a 9.0% ROE reasonable? 2 A: My DCF model indicated an ROE of 9.0% for the combination utility proxy
3 group and 8.8% for the gas utility proxy group. My CAPM analysis results
4 indicated an ROE of 7.12% for the combination utility proxy group, and 7.48%
5 for the gas utility proxy group.
6 As bond yields have remained in a historically low range, my review of 5-
7 year, 10-year, 20-year and 30-year constant maturity Treasury bonds do not
8 produce a CAPM risk free rate above 3.0%. Therefore, I am using the same 3.5%
9 normalized risk free rate based on calculations by Duff & Phelps (Attachment
BEL-3). In fact Duff & Phelps' recommended Equity Risk Premium ("ERP")
11 was reduced in a Client Alert on October 30, 2017 from 5.5% to 5.0%.
12 (Attachment BEL-3.) Together these reductions yield a market return of 8.5%. Public's Exhibit No. 7 Cause No. 44988 Page 8 of50
1 Duff & Phelps' ERP and normalized risk free rate apply across U.S. equity
2 markets, and include companies with higher business risks than those of a
3 regulated gas utility.
4 Moreover, in my DCF analysis, I use a growth rate considerably higher
5 than Value Line's forecasted growth rates in earnings per share, dividends per
6 share and book value per share. To do this, I considered long term growth rates in
7 the U.S. economy, in order to produce as reasonable a growth rate as possible for
8 the Company. Even with these factors, economic and financial trends do not
9 justify a higher ROE.
Certain considerations in the macro-economy, in Federal Reserve policy,
11 and in utility regulation could suggest a gradual increase of important variables in
12 the DCF and CAPM calculations. However, considering the Federal Reserve
13 remains committed to gradual increases in interest rates and a target of 2%
14 inflation with the broader economy growing at a slower rate than in past
15 recoveries; and the fact that regulatory commissions continue to consistently
16 determine ROE in the 9.0% range for the past four years, my 9.0%
17 recommendation is justified.
18 While the stock market has made significant gains in recent years, other
19 macroeconomic variables do not support a return of an inflationary economy.
20 The Consumer Price Index rose only 5.1 index points during calendar year 2017,
21 a 2.1 % increase. (https://data.bls.gov/cgi-bin/surveymost) Even with some
22 tightening by the Federal Reserve, interest rates remain well below those of
23 previous inflationary periods. Expectations of significantly higher rates of return Public's Exhibit No. 7 Cause No. 44988 Page 9 of50
1 have not accelerated. The Duke University CFO Magazine Business Outlook
2 Survey for the fourth quarter of 2017 reveals expectations of an average 6.57%
3 return on S&P 500 stocks over the next year and 7.16% over the next ten years.
4 The survey revealed only a 1-in-10 chance that the return to S&P 500 stocks
5 would be greater than 10.67% over the same period. (Attachment BEL-4.)
6 Finally, I would point out that 9.0% is much more in line with recent
7 ROEs authorized for investor-owned companies around the nation than Mr. Rea's
8 10.7%. In its January 2017 "Regulatory Focus," Regulatory Research Associates
9 ("RRA") highlighted 23 companies with rate cases decided in 2016. Of those 23,
10 only two were authorized 10% or above. Of the 21 companies that were
11 authorized a cost of equity under 10%, four were authorized a 9.0% cost of
12 equity. Graph 5 illustrates the results of all the cases reported by RRA for 2016 as
13 compared to the ROE proposed by NIPS CO in this Cause. Public's Exhibit No. 7 Cause No. 44988 Page 10 of 50
GRAPHS
RETURN ON EQUITY I(Authorized in 2016, compared to NIPSCO Proposed)
I
NIPSCO (IN) •• PROPOSED llm!liElli!ll!!lll!Rll1,!i!ililli1lll!j!ll!!l!lllliil!!Riffl11!1illlllllil!m!-!llll'illllllllll!1iffilii1 10.70% Oklahoma Natural Gas Company (OK) :: ~% Texas Gas Service Co. (TX) ]"50% Public Service Co. (CO) =l!lllli!lllllllllilllllll!l!IIIIIII_IIID_lliillillllll!lll-lmli!lllllll-lli!IIIIIII Q.50% Columbia Gas of MD, Inc. (MD) ll!lllillllll!!liBBl!Dlillllllllllllll-llllillllll!lll-lllllilllllll!IIM-111111111 ~.70% New Jersey NG Co. (NJ) lllllll!l!lllllllllllll"1!1111!11!11111111111-!lllllllillllllllllllllllllllllllll!ll-illl!iliilll 19.75% Wisconsin Power & Light Co. (WI) 10.00%:
Fitchburg Gas & Electric Light Co. (MA) 1 ------9.80% Public Service Co. (NC) !lllll!il!lllillllllllJll!lillil!lillllllllllll-illllllllllllllil!ll-llll!llllllillll-!1111111111 [9.70% Baltimore Gas & Electric Co. (MD) l!l!...... ,llil!lllillllll!!lllllllll!llili!llllli•-illlllll•--•-- b.6s% Minnesota Energy Resources Corp. (MN) 1% i 9.i~ ~ Maine NG (ME) 55% I t"' Center-Point Energy Resources Corp. (NM) 49% ! I 9i· (l Avista Corporation (OR) 40% i 9i Liberty Utilities (New England NG (MA) I ,· 60% ! l Avista Corporation (WA) ~- 50% I I I Sierra Pacific Power Co. 50% I Brooklyn Union Gas Co. (NY) ' 9.01 % i I I KeySpan Gas East Corp. (NY) 9.0~ % ; Rochester Gas & Electric Corp. (NY) 9.0f % i I New York State Electric & Gas Corp. (NY) ' 9.00 % ! i SourceGas Arkansas (AR) 91 40% ! I ! DTE Gas Co. (Ml) ' Center-Point Energy Resources Corp. (AR) ~- 50% j i I -- ' 1 0.00% 2.00% 4.00% 6.00% 8.00% 10.00% 12.00% Return on Equity(%)
1 Based on this companson, Mr. Rea's recommended 10.7% ROE for
2 NIPSCO is not consistent with recent trends. It is too high, particularly
3 considering the fact NIPSCO has a lower long term debt ratio than all other
4 companies in the gas utility proxy group and all but one company in the
5 combination utility proxy group. Public's Exhibit No. 7 Cause No. 44988 Page 11 of50
1 Q: To what extent does NIPSCO's TDSIC contribute to a reasonable reduction 2 to NIPSCO's ROE from its current level? 3 A: Since NIPSCO's last rate order in 2010, Ind. Code § 8-1-39 was enacted, which
4 provides regulated Indiana gas utilities with 80% expedited recovery of eligible
5 capital expenditures through a Transmission, Distribution, and Storage System
6 Improvements Charge ("TDSIC"). NIPSCO's 7-Year TDSIC Plan was approved
7 by the Commission on April 30, 2014 in Cause No. 44403, and NIPSCO has been
8 receiving cost recovery through its TDSIC since January 28, 2015.
9 The implementation of a TDSIC tracker eliminates a significant amount of
10 business risk for a utility. In fact, the TDSIC tracker is an example of the cost
11 recovery mechanisms cited by Moody's as a reason utility ROEs can be safely
12 lowered. (Attachment BEL-2.)
13 Q: How do you respond to Mr. Rea's contention that a downward adjustment to 14 ROE is not appropriate when taking the impact of NIPSCO's TDSIC tracker 15 into account? 16 A: Mr. Rea testified:
17 My evaluation further determined that six out of the nine 18- companies comprising the Combination Utility Group utilize 19 infrastructure cost recovery mechanisms that· are generally 20 comparable to NIPSCO's TDSIC program. As such, the market 21 based data of the Combination Utility Group companies would 22 already capture a significant portion of any level of theoretical risk 23 reduction that would result from the reduced regulatory lag 24 associated with these infrastructure cost recovery mechanisms. For 25 these reasons, it would be inappropriate to apply a downward 26 adjustment to NIPSCO's proposed ROE due to the presence of the 27 Company's TDSIC program, since such an adjustment would be 28 redundant to the effects that would already be impounded within 29 the market data of the proxy group companies.
30 (Pet. Exh. No. 13, p. 45.) Public's Exhibit No. 7 Cause No. 44988 Page 12 of 50
1 I agree, and I have made no decrement to my ROE calculation in either the
2 gas utility proxy group or the combination utility proxy group as a result of the
3 risk reduction due to NIPSCO's TDSIC tracker. However, research supports the
4 conclusion that the addition of a cost recovery mechanism like NIPSCO's TDSIC
5 tracker significantly reduces risk - and that reduction was not reflected in the
6 ROE established in NIPSCO's last rate case. Combining the long term downward
7 trend in approved ROE with my own ROE estimates and macroeconomic
8 analysis, the reduction of risk from the TDSIC tracker supports lowering
9 NIPSCO's current 9.9% ROE.
10 Q: How can the impact of the risk reduction attributable to NIPSCO's TDSIC 11 tracker on cost of equity be evaluated? 12 A: My research on the impact of trackers on cost of equity focused on the research
13 paper titled "Riders, Trackers, Surcharges, Pre-Approvals and Decoupling: How
14 Do They Affect Cost of Equity" by Scott Hempling. (Included as Attachment
15 BEL-5.) In this paper, Mr. Hempling cautions that, "A reduction in authorized
16 ROE due to riders and pre-approvals should be calibrated to the actual level of
17 risk reduction." ("Riders, Trackers, Surcharges, Pre-Approval and Decoupling,"
18 Scott Hempling, 2012, p. 3.)
19 Mr. Hempling identifies five considerations required for the "calibration"
20 of the impact on cost of equity: (a) the types of risks faced by the utility
21 generally, (b) the specific risks reduced by the riders and pre-approvals, ( c) the
22 size of the rider-reduced risks relative to total risks, ( d) the variances of these
23 risks from the utility's traditional risks, and ( e) the proportion of total earnings
24 affected by the rider. (Id., p. 3) Public's Exhibit No. 7 Cause No. 44988 Page 13 of50
1 Mr. Hempling further stated:
2 The equation is straightforward: The clearer the government 3 promise, the lower the risk for the expenditure subject to that 4 promise; and, the lower the expenditure's risk, the lower its 5 associated cost of equity, relative to a situation of no government 6 promise.
7 (Hempling, Id., p. 3.)
8 Mr. Hempling' s observation confirms that the risk reduction associated
9 with the implementation of a tracker mechanism implies a lower cost of equity.
10 Q: Does Mr. Hempling identify the type of risks NIPSCO's TDSIC tracker is 11 designed to minimize? 12 A Yes. Mr. Hemp ling defined the risk component of ROE as follows:
13 The total risk component of authorized ROE represents the several 14 shareholder risks: the risk of not recovering their investment, of 15 recovering it later than desired, and of receiving a return less than 16 what they could earn on alternative investments of comparable 17 risk; in short, the risk of not receiving the real return (i.e., adjusted 18 for inflation) they expected when they invested in the utility.
19 (Hempling, Id., pp. 6-7.)
20 The risk components Mr. Hempling identifies in the above quote are
21 addressed by the NIPSCO TDSIC tracker.
22 Q: What impact should the TDSIC tracker have on NIPSCO's ROE given Mr. 23 Hempling's analysis? 24 A: I emphasize again that I do not make or recommend a decrement to either my
25 DCF or CAPM estimates as a result of the TDSIC tracker. Rather, I believe the
26 TDSIC tracker is an important consideration when determining if a decrease to
27 NIPSCO's current ROE is reasonable. When coupled with my DCF and CAPM
28 estimates, and with the industry and macroeconomic trends I describe, I believe
29 NIPSCO's ROE can be and should be reasonably reduced. Public's Exhibit No. 7 Cause No. 44988 Page 14of50
1 Q: Are there any other reasons you believe NIPSCO's ROE should be lowered 2 from its current level? 3 A: Yes. On November 29, 2017, the Commission issued an order in Cause No.
4 44970 approving a settlement agreement between NIPSCO and the Commission's
5 Pipeline Safety Division regarding 261 instances of violations by NIPSCO of
6 state and federal laws and regulations on pipeline safety:
7 These violations . . . occurred in two categories: the failure to 8 follow procedures and inadequate mapping of facilities, both of 9 which are related to locating NIPSCO facilities. The evidence 10 presented demonstrates that property damage occurred to 11 underground facilities in all of the 261 violations identified.
12 (Petition of the Pipeline Safety Division, Cause No. 44970, November 30, 2017, 13 Order at 9).
14 The settlement required NIPSCO to participate in ongoing compliance activities
15 with the Pipeline Safety Division and the OUCC, focusing on four areas:
16 (1) ongoing communication and exchange of information 17 between the parties, (2) ongoing reporting of performance metrics 18 related to pipeline safety standards, (3) NIPSCO's agreement to 19 implement a safety management system, and (4) NIPSCO's 20 agreement to pay penalties for both past and future violations that 21 might occur through calendar year 2019.
22 (Id. at 3.)
23 In its order in the Indianapolis Power and Light Company ("IPL") rate case,
24 Cause No. 44576/44602, of March 16, 2016, the Commission established cost of
25 equity as a "reasonable mechanism" to provide an incentive for IPL's
26 participation in a collaborative process to address the maintenance and operation
27 of IPL's downtown network, and the related public safety concerns. In so doing,
28 the Commission stated: Public's Exhibit No. 7 Cause No. 44988 Page 15 of 50
1 In order to provide an appropriate message to IPL management, 2 the Commission finds that the use of an incentive linked to IPL's 3 constructive participation in the collaborative process is warranted 4 and that an adjustment to the COE used for ratemaking provides a 5 reasonable mechanism to review IPL's participation. As noted 6 above, the unadjusted cost of equity of 10.0% represents the 7 midpoint of the appropriate range of cost of equity for IPL. The 8 midpoint between 10.0% and the low end of the range of 9. 7% is 9 9.85%, which we find to be representative of an appropriate 10 adjustment. We recognize that this adjustment will be reconsidered 11 in IPL's next rate case review in the context of its participation in 12 the collaborative, and expect that IPL will respond accordingly. In 13 conclusion, we find that the appropriate authorized COE for IPL is 14 9.85%, which we note is higher than the cost of equity Dr. Avera 15 considered insufficient.
16 (Indianapolis Power and Light Company, Cause No. 44576/44602, March 16, 17 2016, Order at 43.)
18 I do not propose any decrement to my cost of equity recommendation in
19 this Cause. However, in recognizing the similarities between the public safety
20 concerns and the ongoing, informal commitments to address them, I believe it
21 would be appropriate for the Commission to send a signal to NIPSCO similar to
22 the one it sent to IPL's management in Cause No. 44576/44602. Awarding a cost
23 of equity lower than the current 9.9% may provide an equivalent incentive
24 mechanism.
III. THE PROXY GROUP USED FOR DCF AND CAPM ANALYSES
25 Q: Please describe your approach to establish a cost of equity estimate for 26 Petitioner. 27 A: I relied primarily on the DCF model and CAPM to estimate Petitioner's cost of
28 equity. Public's Exhibit No. 7 Cause No. 44988 Page 16 of 50
1 Q: Can you apply the DCF model and CAPM directly to Petitioner? 2 A: No. Petitioner is not publicly traded. Consequently, much of the data that would
3 be available for publicly traded companies, is not available for Petitioner. This
4 fact makes it impractical to apply the DCF and CAPM directly to Petitioner.
5 Therefore, I calculated cost of equity for Petitioner based on a proxy group of
6 publicly traded companies.
7 Q: Please describe how you derived the proxy group for your DCF and CAPM 8 studies. 9 A: I used the same combination electric and gas utility proxy group as Mr. Rea
10 ("Combination Utility Group"). Unlike Mr. Rea, I also used a gas utility proxy
11 group ("Gas Utility Group"). Mr. Rea has limited his DCF and CAPM
12 calculations to the use of the Combination Utility Group. His proxy group was
13 selected from companies listed in the Standard Edition of the Value Line
14 Investment Survey as electric utilities. Mr. Rea's testimony establishes proxy
15 group selection criteria including the requirement that a company "must have
16 been engaged in both the natural gas distribution and electric distribution
17 businesses for at least the past five years." (Pet. Exh. No. 13, p. 23, lines 13
18 through 15.)
19 Q: Did Mr. Rea provide any rationale for using a proxy group selected from 20 Value Line electric utility companies? 21 A: In response to OUCC Data Request No. 8-002, Petitioner states ''Mr. Rea's
22 objective was to identify a group of publicly-traded combination gas and electric
23 companies with risk characteristics similar to NIPSCO." The response went on to
24 say, "This approach is consistent with the Commission's past directive with Public's Exhibit No. 7 Cause No. 44988 Page 17 of 50
1 regard to rate proceedings for the gas distribution operations of integrated gas and
2 electric utilities." (Attachment BEL-6.)
3 The "past directive" cited in Petitioner's data request response appears to
4 be from a 2007 Commission order in which Vectren South was encouraged to
5 look at companies that more closely resemble its operations and reflect similar
6 financial realities:
7 Specifically, the Company should look at integrated companies 8 which may be more comparable to Petitioner and more closely 9 resemble Vectren's operations, and reflect the financial realities of 10 Vectren as testified to elsewhere by Petitioner. There is no 11 question that selection criteria for the proxy group determines or 12 affects the conclusion.
13 (Vectren Energy Delivery of Indiana, Cause No. 43112, 14 Commission Final Order at 29, August 1, 2007.)
15 Rates in this Cause will be set for NIPSCO's gas operations only. In selecting the
16 appropriate proxy group(s) for this Cause, this fact should not be overlooked.
17 While the Commission's Order in Cause No. 43112 suggests Vectren South "look
18 at integrated companies," it does not suggest that excluding companies from the
19 industry most comparable to the operations of the utility is appropriate.
20 Q: Has Mr. Rea employed both gas utility and combination utility proxy groups 21 in setting rates for other NiSource gas affiliate companies? 22 A: Yes. Mr. Rea used both gas utility and combination utility proxy groups in his
23 cost of equity testimony for other NiSource gas company operations in the states
24 of Virginia, Maryland, and Massachusetts. In examining Mr. Rea's cost of equity
25 testimony in the cases listed in Petitioner's Exhibit No. 13-A, I discovered he
26 used both a gas utility proxy group and a combination proxy group in each of the
27 following cases: Public's Exhibit No. 7 Cause No. 44988 Page 18 of 50
1 ■ Bay State Gas Company, D.P.U. 12-25, Massachusetts 2 Department of Public Utilities, April 2012.
3 ■ Bay State Gas Company, D.P.U. 13-75, Massachusetts 4 Department of Public Utilities, April 2013.
5 ■ Bay State Gas Company, D.P.U. 13-129, Massachusetts 6 Department of Public Utilities, August 2013.
7 ■ Bay State Gas Company, D.P.U. 15-50, Massachusetts 8 Department of Public Utilities, April 2015.
9 ■ Columbia Gas of Maryland, Case No. 9316, Maryland 10 Public Service Commission, February 2013.
11 ■ Columbia Gas of Maryland, Case No. 9417, Maryland 12 Public Service Commission, April 2016.
13 ■ Columbia Gas of Maryland, Case No. 9447, Maryland 14 Public Service Commission, April 2017.
15 ■ Columbia Gas of Virginia, PUE-2014-00020, Virginia 16 State Corporations Commission, April 2014.
17 ■ Columbia Gas of Virginia, PUE-2016-00033, Virginia 18 State Corporations Commission, April 2016.
19 In fact, the present Cause is a departure for Mr. Rea as it is the first time he has
20 presented cost of equity testimony in a gas utility rate proceeding without a gas
21 utility proxy group.
22 Q: Are there any advantages for Petitioner in using a proxy group of electric 23 companies to determine the cost of equity for natural gas utility operations? 24 A: Yes. Mr. Rea is aware of this advantage. In his testimony in Bay State Gas
25 Company's rate case in 2015, he was able to quantify this advantage even while
26 trying to minimize its importance:
27 Substantial evidence suggests that to the extent combination gas 28 and electric utilities are riskier than pure-play gas utilities, the risk 29 differential is almost inconsequential. This is demonstrated by the 30 average difference in authorized ROEs granted to gas versus 31 electric utilities by state regulatory commissions over the past 34 Public's Exhibit No. 7 Cause No. 44988 Page 19 of 50
1 years (1981-2014), which have only been about 14 basis points 2 higher for electric utilities. More recently, during the past IO-year 3 period (2005- 2014), the difference in authorized ROEs has been 4 about 19 basis points higher for electric utilities. Considering that 5 my Combination Utility Group derives an average of 25%-30% of 6 its revenues from regulated gas distribution operations, it clearly 7 possesses an even lower risk profile than the typical electric utility.
8 (Bay State Gas Company, Massachusetts Department of Public 9 Utilities, D.P.U. 15-50, Direct Testimony of Vincent V. Rea, 10 Exhibit CMANVR-1, p. 32, line 18 through p. 33, line 1.)
11 Q: What companies are in your Gas Utility Group? 12 A: I used the same six companies used by Mr. Rea in his most recent rate case filing
13 prior to this one, the Columbia Gas of Maryland rate case, Case No. 9447, which
14 was filed before the Maryland Public Service Commission in April 2017. They
15 are: Atmos Energy Corporation, New Jersey Resources Corporation, Northwest
16 Natural Gas Company, South Jersey Industries, Southwest Gas Corporation, and
17 Spire, Incorporated. (Attachment BEL-7.)
18 Q: What companies are in your Combination Utility Group? 19 A: The same as used by Mr. Rea in this Cause, which are: Alliant Energy Corp,
20 Black Hills Corp., CMS Energy Corp., Consolidated Edison, Inc., Eversource
21 Energy, MGE Energy Inc., Northwestern Corp., Vectren Corp., and WEC Energy
22 Group. (Attachment BEL-8.)
IV. DISCOUNTED CASH FLOW ANALYSIS
23 Q: Please describe DCF Analysis. 24 A: DCF analysis helps investors determine the appropriate price to pay for particular
25 assets, such as utility stocks. The model has been adapted for regulatory
26 proceedings in order to determine the cost of utility equity capital. The DCF Public's Exhibit No. 7 Cause No. 44988 Page 20 of50
1 model holds that the price of an asset today should equal the sum of all the cash
2 flows that the asset will generate, discounted by the appropriate rate back to the
3 present. This discount rate equals the cost of capital. With utility stocks,
4 dividends are the relevant cash flows.
5 Q: Please describe the "Constant Growth" DCF Model. 6 A: The underlying principle of the "Constant Growth" DCF Model is that the price
7 of a firm's stock reflects the expected cash flows (i.e., dividends) associated with
8 that stock, discounted at a rate equal to the cost of equity capital. This can be
9 expressed mathematically with the following equation:
10 Po = D1/(K - g)
11 In this equation, the current price, Po, can be calculated by dividing the expected
12 annual dividend for the next year, D 1, by the term K - g, where K represents the
13 cost of equity capital and g equals the expected, long-run annual growth rate in
14 dividends per share ("DPS"). This model relies on the assumption that investors
15 expect earnings per share ("EPS"), book value per share ("BPS"), and stock price
16 per share to also grow at a constant long-run rate (g).
17 By rearranging the algebraic terms, it becomes possible to solve for the
18 cost of equity capital. The resulting formula is the DCF model most familiar in
19 utility regulation:
20 K = (D1/Po) + g
21 Here, the cost of equity capital, K, equals the "forward dividend yield,"
22 D1/Po, plus the expected growth rate in dividends per share, g. The DCF model, Public's Exhibit No. 7 Cause No. 44988 Page 21 of 50
1 therefore, requrres estimates of the forward dividend yield and the expected
2 growth rate.
3 Q: Is the "Constant Growth" DCF Model1 considered a reliable method for 4 estimating cost of equity for public utilities? 5 A: Yes. When combined with reasonable judgment, this model provides a realistic
6 and reliable method of estimating a utility's cost of equity. It also formulates the
7 cost of equity as "yield plus growth," which accurately defines the incentive for
8 investors to purchase stocks.
9 The DCF model is also relatively simple in that it states cost of equity in
10 terms of just two components, and only one of these involves any significant
11 controversy. The calculation of dividend yield generally involves few disputes.
12 Most of the controversy in DCF calculations focuses on the growth rate, g. This
13 should not be surprising since the growth rate projects into the future, and
14 disagreements will always arise regarding such projections. However, a
15 reasonable estimate for g can be developed by evaluating variables such as
16 dividends, earnings, and book value per share.
17 Q: What is the difference between current and forward dividend yields? 18 A: The current yield, Do/Po, equals the current annual dividend rate, Do, divided by
19 the current stock price, Po. The current annual dividend rate, Do, equals the most
20 recent quarterly dividend multiplied by four -- it does not include any projection
21 into the next year. Dividend yields published by The Wall Street Journal are
22 current dividend yields, Do/Po.
1 For the balance of my testimony, the "Constant Growth DCF Model" will simply be referred to as the "DCF model." Public's Exhibit No. 7 Cause No. 44988 Page 22 of50
1 The forward yield, D 1/P o, adjusts the current yield Do/Po to reflect likely
2 dividend growth in the subsequent year. The forward yield replaces the current
3 dividend rate, Do, with a prospective dividend rate, D1. D1 is the rate expected
4 during the following year, and the forward yield will then be calculated by
5 dividing D1 by the current price, Po. This adjustment is frequently accomplished
6 by increasing the current dividend yield for one-half of a year's growth in
7 dividends. This method is often referred to as the "half-year method," and has
8 been recognized as valid and reasonable by this Commission. I use this method in
9 my DCF analysis to convert current dividend yields (Do/Po) into forward dividend
10 yields (D1/Po).
11 Q: What is the result of your forward dividend yield calculations for your Gas 12 Utility Group? 13 A: My calculation resulted in a 2.9% forward dividend yield for the Gas Utility
14 Proxy Group. This calculation applies the "half year method" to the data from
15 Value Line. Attachment BEL-9, p. 2 shows my calculation.
16 Q: What is the result of your forward dividend yield calculations for your 17 Combination Utility Group? 18 A: My calculation resulted in a 3.1 % forward dividend yield for the Combination
19 Utility Group. This calculation also applies the "half year method" to the data
20 from Value Line. Attachment BEL-10, p. 2 shows my calculation. In Petitioner's
21 Exhibit No. 13-A, Mr. Rea also uses an average dividend yield of 3.0% dividend
22 yield for the Combination Utility Group. Public's Exhibit No. 7 Cause No. 44988 Page 23 of 50
1 Q: What do you conclude with respect to the Dividend Yield of the DCF model? 2 A: I conclude that a 2.9% dividend yield is reasonable for my Gas Utility Group
3 DCF calculations. I also conclude that 3 .1 % is a reasonable dividend yield for the
4 Combination Utility Group.
5 Q: Please describe the results of your growth calculations. 6 A: I conclude that 5.9% is a reasonable growth rate for the Gas Utility Proxy Group.
7 (See page 3 of Attachment BEL-9 for Value Line Growth Rate data and averages.)
8 This rate results from analyzing both historical and projected EPS, DPS, and BPS
9 growth rates for the proxy group. My 5.9% projected growth rate is well above
10 the projected growth rates for the proxy group companies of 5 .1 % for EPS and
11 4.3% for DPS. It is also above the 5.4% projected BPS for the proxy group. I
12 also use the 5.9% growth rate in my Combination Utility Group DCF analysis.
13 Q: Do you agree with Mr. Rea's elimination of "low-end" growth rates from his 14 DCF analysis? 15 A: No. I have eliminated zero and negative growth rates from my analysis.
16 However, I do not agree with Mr. Rea's elimination of low end estimates based
17 on a 100 basis point premium over Baa utility bond yields.
18 Mr. Rea applied a 13% threshold for "high end" growth rates, and a 17%
19 threshold for companies with DCF estimated cost of equity. As a result, he
20 eliminated only low end outliers, while allowing growth rates more than twice the
21 annual average rate of growth of U.S. Gross Domestic Product since 1980. For
22 example, Mr. Rea's calculations includes a 5-year Historical EPS growth rate of
23 11.0% for Black Hills Corp. and a 10-year Historical EPS growth rate of 12.0%
24 for Eversource Energy. He also allows a 12.0% projected EPS growth for Black Public's Exhibit No. 7 Cause No. 44988 Page 24 of 50
1 Hills Corp. (Pet. Exh. No. 13-A, Schedule 5.) Eliminating low-end outliers while
2 including high-end outliers umeasonably skews Mr. Rea's analysis to Petitioner's
3 benefit.
4 Q: What have you concluded based on your DCF analysis? 5 A: My DCF calculations for the Gas Utility Group result in a cost of equity of 8.8%.
6 This combines the 2.9% forward yield and the 5.9% growth rate. (Attachment
7 BEL-9, p. 1.)
8 My DCF calculations for the Combination Utility Group result in a cost of
9 equity of 9.0%. This combines the 3.1 % forward yield and the 5.9% growth rate.
(AttachmentBEL-10, p. 1.)
V. CAPITAL ASSET PRICING MODEL
11 Q: Please describe the CAPM. 12 A: The underlying assumption of CAPM is that the stock market compensates
13 investors for risk that cannot be eliminated by means of a diversified stock
14 portfolio. In CAPM, the required return on a stock equals the sum of a risk free
15 rate of return (Rf) plus a risk premium [W(Rm- Rf)], which is proportional to the
16 level of market risk. Market risk cannot be eliminated through diversification.
17 The CAPM formula is:
18
19 where,
20 13 = Beta, a measure of risk for the company,
21 K = Required return (i.e., cost of equity) on the stock of the company,
22 Rf= Risk-free rate ofretum, Public's Exhibit No. 7 Cause No. 44988 Page 25 of50
1 Rm = Market equity return, and
2 (Rm - Rf) = Market equity risk premium.
3 The "beta" is considered the measure of risk most relevant in CAPM. A
4 stock with a beta below 1.0 is considered less volatile and less risky than the stock
5 market. If beta exceeds 1.0, the stock is considered more volatile and more risky
6 than the stock market as a whole. By definition, the stock market has a beta of
7 1.0. The stock market is usually represented by a large and highly diversified
8 portfolio of stocks such as the Standard & Poor's 500.
9 Q: Were you able to perform a CAPM analysis directly for Petitioner? 10 A: No. Petitioner is not a publicly traded company. Consequently, the necessary
11 data does not exist to perform a CAPM analysis directly for Petitioner. Therefore,
12 I have used Mr. Rea's proxy group to perform a CAPM analysis.
13 Q: How did you determine beta for purposes of your analysis? 14 A: I used betas from the Value Line Investment Survey. For this analysis I used the
15 average of the Value Line adjusted betas for the proxy group, 0.76 for the Gas
16 Utility Group, (Attachment BEL-11, p. 3) as the beta estimate in my CAPM
17 analysis. For the Combination Utility Group, I calculated an average beta of 0.69
18 (Attachment BEL-12, p. 3).
19 Q: What risk free rate (Rr) did you use for your CAPM calculations? 20 A: I used 3.5% for my risk free rate.
21 Q: Please describe how you determined the risk free rate of 3.5%. 22 A: I used the Duff & Phelps normalized risk free rate, as described in a Client Alert
23 on January 12, 2017. (See Attachment BEL-3.) Duff & Phelps actually lowered
24 the normalized risk-free rate in 2017, from the 4.0% published in its March 16, Public's Exhibit No. 7 Cause No. 44988 Page 26 of50
1 2016 Client Alert. I reviewed bond yield performance for calendar year 2017,
2 and could justify a risk free rate no higher than 2.92% based on the average 30
3 year bond yields over the 12 months ending November 2017. I also examined
4 recent term trends in yields on 5-year, IO-year, 20-year, and 30-year Treasury
5 Bonds from data available from the Federal Reserve (w1,,v\v.federalreserve.gov)
6 and calculated averages for the 3 month, 6 month and 12 month periods ending in
7 November 2017.
8 Twenty-year Treasury yields averaged 2.60% in November 2017, below the
9 2.75% level in January 2017. The 20 year Treasury bond stood at 2.59% on
10 December 27, 2017. This is an increase of only 3 basis points since the Fed's 25
11 basis point increase of the Federal Funds Rate on December 13, 2017. The 30 year
12 Treasury stood at 2.75% on December 27, as compared to 2.74% on December 13.
13 These long term bond yields are down from a year ago, in spite of three 25 basis
14 point increases over the calendar year. In December 2016, the 20 year Treasury
15 stood at 2.84%, and the 30 year Treasury at 3.11 %. These yields remain well below
16 historical levels experienced in recent decades. I believe that it is fair and reasonable
17 to adopt the 3.5% normalized risk free rate recommend by Duff & Phelps.
18 I also examined the economic projections from the Congressional Budget
19 Office ("CBO") in The Budget and Economic Outlook: Fiscal Years 2017-2027,
20 updated in June 2017. The latest CBO projection for IO-year Treasuries in 2018
21 is 2.8%. The CBO projection for 2019-2020 is 3.4% and 3.7% in the 2021-2027
22 timeframe. (Congressional Budget Office, The Budget and Economic Outlook: Public's Exhibit No. 7 Cause No. 44988 Page 27 of50
1 Fiscal Years 2017-2027, Update June, 2017. www.cbo.gov shown in Attachment
2 BEL-13.)
3 The above research and analysis leads me to conclude that 3.5% is a
4 reasonable risk-free rate to use in my CAPM analysis, considering both recent
5 experience and future projections.
6 Q: How did you estimate the Market Risk Premium (Rm - Rr)? 7 A: I calculated long term market risk premiums based on historical data from the
8 Stocks, Bonds, Bills and Inflation (SBBI), 2017 Yearbook, by Duff & Phelps,
9 previously published by Morningstar, Inc. (Attachment BEL-14.) These data
10 points are directly comparable with previous Morningstar and Ibbotson
11 Associates publications. The SBBI database covers the period between 1926 and
12 2016.
13 There are two methods of calculating historical holding period returns:
14 the geometric mean (or compound annual return) and the arithmetic mean, which
15 is a simple average of one year holding period returns. The geometric mean
16 return measures the average compound annual rate of return from an investment
17 over a period of more than one year. The arithmetic mean measures the average
18 of one year holding period returns. Unless the investment provides a constant
19 return year after year, the arithmetic mean rate of return always exceeds the
20 geometric mean rate of return. The arithmetic mean approach also produces
21 higher estimates of the market risk premium and higher overall CAPM results.
22 The Commission has consistently expressed its preference for considering
23 both the geometric mean and arithmetic mean approaches. For instance, in its Public's Exhibit No. 7 Cause No. 44988 Page 28 of50
1 final order in the Indiana-American Water rate case (Cause No. 42520), the
2 Commission once again expressed this preference:
3 In past rate cases this Commission has given weight to both the 4 arithmetic and the geometric mean risk premiums. This position was 5 reaffirmed in our 1996 Rate Order, when we stated "[t]he debate 6 over the proper use of the arithmetic and geometric means is one we 7 consider resolved. As we stated in Indianapolis Water Company, 8 Cause No. 39713-39843 [sic], each method has its strengths and 9 weaknesses, and neither is so clearly appropriate as to exclude 10 consideration of the other." (1996 Rate Order, Cause No. 40103, p. 11 41.) Also, in the 2002 Rate Order, we stated " ... that, while the 12 debate over the proposed use of the arithmetic and geometric means 13 continues, however, each method has its strengths and weaknesses, 14 neither is so clearly appropriate as to exclude consideration of the 15 other. (2002 Rate Order, Cause No. 42029, p. 32.) ...
16 . . . We will continue to give both the geometric and arithmetic 17 mean risk premiums substantial weight. Neither the arithmetic nor 18 geometric mean risk premiums should be excluded in favor of the 19 other.
20 (November 18, 2004 Order, Cause No. 42520, p. 59.)
21 Following this well-established directive, I calculated market risk premiums
22 giving equal weight to both the geometric and arithmetic mean approaches. I
23 used the resulting market risk premium of 5.25% in my CAPM calculations. (See
24 Attachment BEL-11, p. 4 for Gas Utility Group and Attachment BEL-12, p. 4 for
25 Combination Utility Group.)
26 Q: Please describe the results of your CAPM analysis. 27 A: I used the Duff & Phelps normalized risk free rate of 3.5%, which is 75 basis
28 points above the 30-year Treasury bond yield on December 27, 2017. I used only
29 the adjusted betas from Value Line, and balanced the weight given to the
30 geometric mean and arithmetic mean approaches. For the Gas Utility Group, my Public's Exhibit No. 7 Cause No. 44988 Page 29 of 50
1 CAPM estimate is 7.48%. (Attachment BEL-11, p. 1.) For the Combination
2 Utility Group, my CAPM estimate is 7.12%. (Attachment BEL-12, p. 1.)
3 Q: Mr. Rea applies a relative size adjustment of 93 basis points to his CAPM 4 estimate, which he claims is needed to reflect NIPSCO's risk. Do you believe 5 a small stock adjustment is justified? 6 A: No. The applicability of a small stock adjustment to regulated public utilities is
7 questionable. Regulation reduces the financial risks faced by Petitioner. Annie
8 Wong of Western Connecticut State University writes that business and financial
9 risks are very similar among utilities regardless of size in Utility Stock and the
10 Size Effect: An Empirical Analysis:
11 The fact that the two samples show different, though weak results 12 indicates that utility and industrial stocks do not share the same 13 characteristics. First, given firm size, utility stocks are consistently 14 less risky than industrial stocks. Second, industrial betas tend to 15 decrease with firm size, but utility betas do not. These findings 16 may be attributed to the fact that all public utilities operate in an 17 environment with regional monopolistic power and regulated 18 financial structure. As a result, the business and financial risks are 19 very similar among the utilities regardless of their size. Therefore, 20 utility betas would not necessarily be related to firm size.
21 The object of this study is to examine if the size effect exists in the 22 utility industry. After controlling for equity values, there is some 23 weak evidence that firm size is a missing factor from the CAPM 24 for industrial but not utility stocks. This implies that although the 25 size phenomenon has been strongly documented for industrials, 26 findings suggest that there is no need to adjust for the firm size in 27 utility regulation. (Emphasis added.) 28 (Annie Wong, "Utility Stock and the Size Effect: An Empirical 29 Analysis," Journal of the Midwest Finance Association, 1993, p. 30 98.)
31 Further, Michael Paschall and George B. Hawkins, authors of Do Smaller
32 Companies Warrant a Higher Discount Rate for Risk?: The "Size Effect" Debate, Public's Exhibit No. 7 Cause No. 44988 Page 30 of50
1 state that privately held companies should be analyzed individually to determine
2 if a size premium is appropriate:
3 A size premium does not automatically apply in every case. Each 4 privately held company should be analyzed to determine if a size 5 premium is appropriate in its particular case. There can be unusual 6 circumstances where a small company has risk characteristics that 7 make it far less risky than the average company, warranting the use 8 of a very low risk premium. One possible example of this is a 9 private water utility (monopoly situation, very low risk, near 10 guarantee of payments).
11 (Paschall and Hawkins, Do Smaller Companies Warrant a Higher 12 Discount Rate for Risk?: The "Size Effect" Debate, CCH Business 13 Valuation Alert, December, 1999.)
14 Moreover, the Commission has found that a blind application of Ibbotson's small
15 company adjustment ignores the fact that the risk of regulated utilities is not as
16 great as small companies:
17 We are familiar with the Ibbotson-derived 400 basis point small 18 company risk premium used by Mr. Beatty. The rationale behind 19 this approach is that, all other things being equal, the smaller the 20 company, the greater the risk. However, to blindly apply this risk 21 premium to Petitioner is to ignore the fact that Petitioner is a 22 regulated utility. The risks from small size for a regulated water 23 utility are not as great as those small companies facing competition 24 in the open market.
25 (South Haven Sewer, Cause No. 40398, Final Order May 28, 1997, 26 pp. 30-31.)
27 More recently, in an Indiana-American rate case order in Cause No. 43680
28 issued on April 30, 2010, the Commission stated that regulated utilities have
29 different risk than other small companies:
30 The Commission rejects Petitioner's equity size premmm 31 adjustment because it cannot be directly applied to regulated 32 water utilities. Regulated water utilities do not experience the 33 same risks as other small companies. Public's Exhibit No. 7 Cause No. 44988 Page 31 of 50
1 (Indiana-American Water, Cause No. 43680, Final Order, p. 47.)
2 The same principle can be applied to regulated natural gas companies.
VI. INHERENT PROBLEMS IN MR. REA'S OTHER MODELS
3 Q: Does Mr. Rea use any models that you do not? 4 A: Yes. In addition to his DCF and CAPM analyses, Mr. Rea uses a variant of
5 CAPM analysis called the Empirical Capital Asset Pricing Model ("ECAPM"), a
6 Risk Premium Model ("RPM"), and a Comparable Earnings Approach ("CEA").
7 Q: Do you agree with Mr. Rea's ECAPM estimate? 8 A: No. Mr. Rea's ECAPM produced an estimated cost of equity of 11.3% for his
9 Combination Utility Group and 10.49% for his Non-Regulated Group. The
10 ECAPM is designed to address a theoretical downward bias in risk by increasing
11 the risk factor, called "beta." This is accomplished by giving a 25% weight to the
12 Market Risk Premium and a 75% weight to a traditional CAPM risk premium for
13 the proxy group. It essentially limits the impact of the beta calculated for the
14 proxy group. However, Mr. Rea also uses betas which have already been
15 upwardly adjusted. His ECAPM estimate includes an additional upward
16 adjustment and produces an artificially inflated result.
17 Q: Has the Commission expressed an opinion on the use and results of an 18 ECAPM approach? 19 A: Yes. The Commission has rejected the use of ECAPM in at least two previous
20 Causes (Cause Nos. 40003 and 42359). In its Final Order in Cause No. 42359,
21 the Commission affirmed its previous finding that the ECAPM is unreliable for
22 ratemaking purposes: Public's Exhibit No. 7 Cause No. 44988 Page 32 of 50
1 With respect to the ECAPM analysis performed by Dr. Morin we 2 note that the Commission rejected this model in Cause No. 40003, 3 and found that: "the Empirical CAPM is not sufficiently reliable 4 for ratemaking purposes." Cause No. 40003 at 32. We went on to 5 conclude that the ECAPM ". . . would adjust, in essence, future 6 expectations with regard to investor perceptions of relative risks 7 for further change which may occur years hence." The 8 Commission concluded that " ... we do not believe exercises in 9 approximating future cost of capital are conducive to such precise 10 estimation as the Empirical CAPM would suggest." Id. We find 11 that nothing presented in this Cause has changed our prior 12 determination that ECAPM is not sufficiently reliable for 13 ratemaking purposes and hereby reject the model in this 14 proceeding. 15 (PSI Energy, Cause No. 42359, May 18, 2004, Final Order, p. 56.)
16 Q: Please describe Mr. Rea's RPM analysis. 17 A: Mr. Rea calculates two RPM estimates of cost of equity. One estimate uses
18 Annual Total Returns for S&P Composite Index (1926-2016) less the Annual
19 Total Returns for Long-Term Corporate Bonds (1926-2016) to calculate a
20 Historical Equity Risk Premium. His Prospective Equity Risk Premium is
21 calculated based on the difference between a Prospective Annual Market Return
22 over the next 3 to 5 years and a Prospective Aaa Corporate Bond Yield. His RPM
23 produces estimated costs of equity of 10.57% for his Combination Utility Group
24 and 11.03% for his Non-Regulated Group.
25 Q: Do you agree with Mr. Rea's RPM approach? 26 A: No. I believe Mr. Rea's calculations are based on skewed or unrealistic estimates.
27 Mr. Rea's Historical Risk Premium calculation on page 3 of Schedule 8 (Pet. Exh.
28 13, Attachment 13-A) relies solely on the arithmetic mean of Annual Total
29 Returns on the S&P 500 Composite Index and on Long Term Corporate Bonds. Public's Exhibit No. 7 Cause No. 44988 Page 33 of 50
1 He ignores the corresponding geometric mean returns, which yield a 4.0%
2 Historical Equity Risk Premium, compared to his 5.7%.
3 Also, Mr. Rea calculates the Prospective Equity Risk Premium based on a
4 12.37% Prospective Annual Market Return for the next 3 to 5 years (Id.). This
5 compares to the total 8.5% market return based on the Duff & Phelps normalized
6 risk :free rate and recommended ERP. Moreover, the 12.37% Prospective Annual
7 Market Return relies on a 10.28% Prospective Growth Rate (Id., Schedule 7, p.l).
8 The Prospective Growth rate compares to EPS growth data used in Mr. Rea's
9 DCF analysis of his Non-Regulated Group showing estimates from Yahoo
10 Finance, Zack's and Value Line ranging from 7.5% to 8.3%. (Id., Schedule 6, p.
11 1.) The Prospective Growth Rate also compares with the 5.9% growth in EPS
12 growth data he used in his DCF analysis for the Combination Utility Group.
13 Q: Please describe Mr. Rea's Comparable Earnings Approach ("CEA") 14 approach. 15 A: Mr. Rea's CEA approach estimated costs of equity at 13.0% based on an average
16 of 13.6% on Realized Historical Returns on Book Equity for his Non-Regulated
17 Proxy Group, and Projected Returns on Book Equity through 2022 from Value
18 Line. His CEA approach averaged 3-5 year estimated returns on common equity
19 of nine non-regulated companies, resulting in 12.4%.
20 Q: Do you agree with Mr. Rea's CEA approach? 21 A: No. His Realized Historical Returns on Book Equity data include results up to
22 17.0%. This allows for outliers far above the average ROEs for gas utilities
23 across the United States, and twice the total market return derived from Duff &
24 Phelps normalized data. Further, his CEA approach includes estimates of Public's Exhibit No. 7 Cause No. 44988 Page 34 of50
1 historical amounts to a compilation of Value Line's 3-5 year estimated returns on
2 common equity. Value Line's 3-5 year forecasted return on common equity is an
3 intermediate forecast, not a required return nor a cost of equity. Forecasts of
4 companies over-earning or under-earning can distort and skew expectations and
5 future rates if used in determining an authorized return. Moreover, as many
6 companies also have unregulated operations, Mr. Rea's CEA approach would
7 include forecasted returns on those operations. Value Line's intermediate
8 forecasted returns should not be used to estimate cost of equity.
VII. MACROECONOMIC TRENDS
9 Q: Do macroeconomic factors and trends influence the cost of equity? 10 A: Yes. The most noteworthy of these factors are interest rates, economic growth,
11 and inflation.
12 Q: Do economic forecast data s11pport 9.0% as a reasonable ROE for Petitioner? 13 A: Yes. The CFO Magazine Business Outlook Survey, published by Duke
14 University in the Fourth Quarter 2017 (http://www.cfosurvey.org!) (the "CFO
15 Survey") states that "[o]n November 14, 2017 the annual yield on 10-yr Treasury
16 bonds was 2.37%," and asked respondents for their expectations on the future rate
17 of return for S&P 500 companies. Their responses revealed an average expected
18 return of 6.57% over the next year and 7.16% over the next 10 years. My
19 recommended ROE of 9.0% for Petitioner is 243 basis points above the
20 expectations of respondents to the CFO Survey for next year, and 184 basis points
21 above expectations for the next ten years. Survey respondents expect only a l-in-
22 10 chance of the annual S&P 500 return being greater than 10.67%. (Attachment Public's Exhibit No. 7 Cause No. 44988 Page 35 of 50
1 BEL-4.) Mr. Rea's ROE recommendation of 10.7% is above the high-end 1-in-10
2 chance threshold established in the survey. I emphasize that these return estimates
3 apply to companies in the S&P 500, which includes many industrial companies
4 considered more risky than regulated utilities.
5 Q: Please discuss bond yields as an influencing factor on the cost of equity. 6 A: Bond yields are extremely important factors influencing cost of equity. Yields on
7 U.S. Treasury Bonds are commonly used to establish the risk-free rate of return in
8 CAPM and other risk premium analyses. Moreover, changes in bond yields and
9 interest rates affect investor expectations.
10 Q: Please compare current and historical trends in bond yields. 11 A: The long period of low cost capital experienced in recent years is continuing. In
12 spite of some economic data improvements and the Federal Reserve increasing
13 the Federal Funds rate, long term Treasury bond yields remain low and have been
14 flat or dropping over the past year. Lower yields have occurred over a span of
15 two decades; it is a long run phenomenon, and not simply a result of the last
16 recession. Graphs 6 through 9 below show the monthly interest rate trend on 5-
17 year, 10-year, 20-year and 30-year Constant Maturity Treasury Bonds, reported
18 by the Federal Reserve. These graphs illustrate the American economy remains
19 in a period with bond yields well below those of the 1980s and 1990s.
20 In November 2017, long term bond yields remained low in comparison to
21 earlier periods. On December 27, 2017, the spot yield on the bellwether 10-year
22 Treasury bond stood at 2.42% and the 5-year Treasury stood at 2.22%. The 20- Public's Exhibit No. 7 Cause No. 44988 Page 36 of 50
1 year Treasury closed at 2.59% and the 30-year Treasury stood at 2.75%.
2 (https:/ /wv,,rw .federalreserve. gov/ datadownload/Choose.aspx ?rel=H 15.)
GRAPH6
js Year Treasury Bond Yields, 1980-20171
18.00% 16.00% ~ 14.00% a::"' "t:J Latest: Novembers 2017 = 2.05% c:: 12.00% 0 tQ 10.00%
~U) Source: Federal Reserve "' 8.00% ~ ... 6.00% ~"' I() 4.00% 2.00% 0.00%
Month /Year
3 Graphs 7, 8 and 9 reveal similar trends for 10-year, 20-year and 30-year Treasuries. Public's Exhibit No. 7 Cause No. 44988 Page 37 of 50
GRAPH7 110 Year Treasury Bond Yields, 1980-20171
18.00% 3:! 16.00% ~ "0 14.00% C: 0 Latest: November, 2017 = 2.35% IXI 12.00% ~ 10.00% :a Source: Federal ReseNe e 8.00% i.;;;... Ctl 6.00% ~ ....0 4.00% 2.00% 0.00%
GRAPHS 20 Year Treasu Bond Yields, 1980-2017
16.00%
14.00% ~ ~ 12.00% § Latest: November, 2017 = 2.60% ~ 10.00% ::, m a.00% i!:: lo ~ 6.00%
4.00%
2.00%
0.00%
Month/Year Public's Exhibit No. 7 Cause No. 44988 Page 38 of 50
GRAPH9 130 Year Treasury Bond Rates, 1980-2017t -.e,-l•-•- .,--~,___. -~-- . ··"·-.,,-,+."<•- --.,., _.,,.,,.,-- -·•-•·---~-- "._ ._ •.... -, .. _._ .,, ...•. • ,.p,,.,,_ ~• ---.~----. ,c.S
16.00% ~------~
12.00%
~ Latest: November, 2017 = 2.80% ;:_ 10.00% c:' :, Source: Federal Reserve "'~ 8.00% 1-... ,:."' 6.00% 0 M
4.00%
2.00%
0.00% · ~ ' ~ ~ ~ ~ ' ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ' ~ ~ ~ ,, ~,, ~q;. ~ 'p ~C/j 9) 9) ~.?. ~ 9) ~ 5S j:> ~~ j:> 5S ~<;:) !'- !' ~!' !'. !'- # ~, ~ ~ ✓ ~ ~ ~ ~ ~ # # ~ ~ ~ ~ ✓ ~ ~ ~ ~ ~ # Month-Year
1 Q: How does economic growth influence cost of equity? 2 A: Economic growth primarily influences cost of equity through interest rates and
3 investor expectations. A booming, high-growth economy tends to put upward
4 pressure on interest rates. A lackluster or recessionary economy tends to lead to
5 stagnant or falling interest rates.
6 Data from the U.S. Department of Commerce, Bureau of Economic
7 Analysis ("BEA") (wwv1.bea.gov) and from the CBO provides historical
8 perspectives. The CBO, using BEA data, projects 4.0% nominal growth (growth
9 measured in current dollars -not adjusted for inflation) in 2018. CBO projections
indicate a 3.5% rate of nominal growth for the period 2019-2020 and 4.0% in the
11 period 2021-2027 (Attachment BEL-13). Public's Exhibit No. 7 Cause No. 44988 Page 39 of50
1 Real economic growth is growth measured in constant (inflation adjusted)
2 dollars. Moreover, CBO forecasts 2.0% real growth in 2018, 1.5% for the period
3 2019-2020, and 1.9% in 2021-2027. (Id.) Graph 10 shows annual percent
4 changes in real GDP in the period 1930 through 2016, as published by BEA.
5 (https://www.bea.gov/nationa1/indcx.htm#gdp.)
GRAPHlO
lAmmaJ Percent Change in Reai GDP, 1930-2016i 25.0% ~------~
20.0% >------<
J 1s.0% 1-- ~ l 10.0% 6
-10.0% ,_.,,,___ __,, ______Saurce: US Bureau ofEcunmHfc Analysis -15.0% ,______,
6 Prior to the 1990's, economic expansion periods included at least one or
7 more years above 5% real growth. The U.S. economy has not experienced that
8 level ofreal GDP growth on an annual basis since 1984.
9 Thus, recent data indicates the U.S. economy is in a mature recovery,
10 continuing to struggle to achieve historically robust rates of growth. The fourth
11 quarter of 2017 saw a real annual growth rate of 2.6%. (U.S. Department of
12 Commerce, Bureau of Economic Analysis, http://www.bea.gov.) While an
13 improvement from recent years, it still falls short of earlier recoveries. Public's Exhibit No. 7 Cause No. 44988 Page 40 of50
1 Q: In your analysis, have you taken into account current and projected 2 inflation? 3 A: Yes. I examined historical and projected rates of inflation from both government
4 and private sector sources, including the Bureau of Labor Statistics, the
5 Congressional Budget Office, and Morningstar, Inc. Spikes or long-term
6 increases in inflation can affect the prospective real return, but I found no reason
7 to believe that inflation will experience such increases in the near term.
8 Q: Please describe the trends in the rate of inflation. 9 A: The U.S. economy remains in a relatively low inflation period, with the Federal
10 Reserve continuing to target an inflation level of 2%. In her November 29, 2017
11 testimony on the outlook of the economy before the U.S. Congressional Joint
12 Economic Committee, former Federal Reserve Chairperson Janet L. Yellen
13 explained that inflation is moving consistent with the Federal Open Market
14 Committee's ("FOMC") expectations. She also indicated the FOMC expects only
15 gradual increases in future interest rates:
16 We continue to expect that gradual increases in the federal funds 17 rate will be appropriate to sustain a healthy labor market and 18 stabilize inflation around the FOMC's 2 percent objective. That 19 expectation is based on the view that the current level of the 20 federal funds rate remains somewhat below its neutral level--that 21 is, the rate that is neither expansionary nor contractionary and 22 keeps the economy operating on an even keel. The neutral rate 23 currently appears to be quite low by historical standards, implying 24 that the federal funds rate would not have to rise much further to 25 get to a neutral policy stance. If the neutral level rises somewhat 26 over time, as most FOMC participants expect, additional gradual 27 rate hikes would likely be appropriate over the next few years to 28 sustain the economic expansion.
29 https://www.federalreserve.gov/newsevents/testimony/yellen20171 30 129a.htm Public's Exhibit No. 7 Cause No. 44988 Page41 of50
1 The overall (also called "headline") Consumer Price Index ("CPI") has
2 :fluctuated over the past two years, but has remained relatively low in spite of the
3 high volatility of energy prices. (CPI data from U.S. Department of Labor, Bureau
4 of Labor Statistics, www.bls.gov.) As of the end of November 2017, the
5 unadjusted CPI for "All Urban Consumers" stood at 246.669, 2.66% higher than
6 its November 2016 level. (https://www.bls.gov/news.release/cpi.t01.htm.) Core
7 inflation, which removes the impact of energy and food price volatility, remains
8 low. The CBO estimates core inflation at 2.3% in 2018 (Attachment BEL-13).
9 Annual inflation rates from 1976 through 2016 indicate the United States
10 remains subject to low inflation, despite recent volatile energy costs. Current
11 inflation is nowhere near levels experienced in earlier decades. Data from Duff &
12 Phelps, which I have recreated below in Graph 11, indicates inflation evaporated
13 in 2008, falling from 4.1 % in 2007 to 0.1 %. Inflation rebounded slightly in 2009
14 to 2.7%, retreated to 1.4% in 2010, and was 3.0% in 2011. However, inflation fell
15 to 1.7% in 2012, 1.5% in 2013, 0.8% in 2014, 0.7% in 2015 and rebounded to
16 2.1 % in 2016. This compares to an annual average of 3.0% between 1990 and
17 2000, and 5.2% between 1980 and 1990. (Duff & Phelps, 2017 Classic Ibbotson
18 SBBI Yearbook, Table C-7.) (Attachment BEL-15.) Public's Exhibit No. 7 Cause No. 44988 Page 42 of 50
GRAPHll
!INFLATION, U.S., 1976-20161
14.0%
12.0%
Source: Ibbotson 2015 Classic Yearbook, !v1orninrrstar, Inc. 10.0% ,·,saar Table C-7
~ .. 8.0% Q: C: 0 :;:; .::.. 6.0% ..!: 4.0%
2.0%
0.0%
Year
1 Moreover, the latest forecast from the CBO projects modest increases in
2 both the overall CPI and the Core CPI, which excludes highly volatile
3 commodities such as energy, over the next decade. The CBO projects a 2.3%
4 increase in the overall CPI for 2018, followed by 2.4% in 2019-2020, with
5 increases in the period 2021-2027 averaging 2.4% per year. (Attachment BEL-
6 13.) The Federal Reserve Bank of Philadelphia projects core inflation at 2.1 % in
7 2018 and 2.2% in 2019. Philadelphia Fed also projected continued low headline
8 inflation:
9 Measured on a fourth-quarter over fourth-quarter basis, the CPI 10 and PCE inflation forecasts are about the same now as they were 11 three months ago, particularly for core inflation measures. Core 12 CPI inflation is expected to average 1.7 percent in 2017, 2.1 13 percent in 2018, and 2.2 percent in 2019.
14 (Attachment BEL-16, p. 4.) Public's Exhibit No. 7 Cause No. 44988 Page 43 of50
1 Even with the 2018 core inflation increase, my research and analysis shows
2 inflation remains low by historical standards. Low inflation rates tend to support
3 lower interest rates and lower costs of financing capital investment, including
4 utility plant investments.
5 Q: Are you arguing there should be a decrease to ROE because of continued low 6 levels of headline and core inflation? 7 A: No. I have made no reduction to my ROE recommendation due to inflation. I use
8 inflation data projections merely to illustrate that inflation, which remains low and
9 stable, is not likely to put pressure on interest rates and ROE in the near future.
10 Q: What conclusions have you reached about the macroeconomic trends that 11 influence cost of equity? 12 A: Recent trends in interest rates, inflation, and economic growth have shown
13 upward movement, but do not suggest a return to an inflationary economy.
14 Instead, recent trends point to a continuing, but maturing recovery from the
15 financial crisis and recession that started in 2008. There is no indication that
16 macroeconomic trends are fueling any significant increase in capital costs.
17 Petitioner's proposed 10.7% cost of equity far exceeds market expectations, even
18 for a more risky stock portfolio like the S&P 500 containing many industrial
19 companies. Consequently, my recommended ROE of 9.0% is much more in line
20 with current economic conditions. Public's Exhibit No. 7 Cause No. 44988 Page 44 of 50
VIII. PETITIONER'S RECOMMENDED RETURN ON FAIR VALUE DOES NOT REMOVE HISTORICAL INFLATION
1 Q: What role does inflation play in the determination of a fair rate of return to 2 apply to a utility's fair value rate base? 3 A: Inflation should not be included in both the rate base and the fair rate of return.
4 An original cost rate base does not reflect the effects of inflation on the value of
5 the plant. In such a case, inflation is reflected in the rate of return.
6 Unlike a net original cost rate base, a Reproduction Costs New Less
7 Depreciation ("RCNLD") study, which Petitioner has used to estimate its fair
8 value, indicates a current value of assets by determining what it would cost to
9 replace the assets today, less an amount to reflect the assets' depreciation. Such
10 RCNLD estimates of fair value rate base reflect historical inflation. In such case,
11 it is neither necessary, nor appropriate, to apply rates of return that will again
12 include an upward adjustment to reflect inflation. Applying a rate of return to a
13 fair value rate base - which is designed to be applied to an original cost rate base -
14 will result in double recovery or double counting.
15 Q: How may such double recovery or double counting be avoided? 16 A: To avoid a double counting of the inflationary impact, the return on fair value
17 should be reduced by historical inflation. In Principles of Public Utility Rates,
18 (Second Edition, 1988, pp. 348-349), Bonbright, Danielsen and Kamerschen
19 discuss the possibility for such a double counting:
20 If adjustment is to be made for inflation (and its long dormant kin 21 deflation) whether as a matter of experiment or as a matter of 22 general policy, the question arises whether it should be made in the 23 rate base or in the rate of return. Bonbright (1961, pp. 274-276) 24 preferred the former alternative as a means of avoiding the false 25 appearance of an excessive rate of return during a period of Public's Exhibit No. 7 Cause No. 44988 Page 45 of50
1 inflation, but stressed that this does not mean the adoption of a fair 2 value rule of ratemaking. Instead, he proposed the acceptance of a 3 rate base measured by depreciated original cost restated in terms of 4 dollars equal to the purchasing power of the original capital 5 contributions. Moreover, the restatement would be confined to 6 common equity capital since the objective is that of maintaining 7 the integrity of stockholders' investment. The index number by 8 which to measure price changes should be the Bureau of Labor 9 Statistics Consumer Price Index, since it approximates, at least to 10 some extent, the cost of living of shareholders and it is 11 exogenously determined, as opposed to say an index of inputs 12 purchased by utilities, over which utilities have some endogenous 13 control making it susceptible to creative regulation. While we find 14 his suggestion probative, but not dispositive, at a minimum, this 15 would require that the return be in real and not nominal terms as 16 the rate base adjusted for inflation together with a rate of return 17 adjusted for inflation would be double counting.
18 (Emphasis added).
19 The Commission has long recognized the potential for double counting m
20 applying a rate of return to a fair value rate base:
21 It is inappropriate to apply to the fair value of Petitioner's used and 22 useful property its weighted cost of capital because the weighted 23 cost of capital contains both historic and prospective inflationary 24 factors. We have accounted for the historic inflationary factors in 25 determining the fair value of Petitioner's property. Therefore, to 26 arrive at a fair return to be applied to the fair value of Petitioner's 27 property the historical inflationary consideration must be removed, 28 lest they be double counted.
29 (Indiana Michigan Power Company, Cause No. 38728, Final Order at p. 30 28, August 24, 1990.)
31 Q: Did Mr. Rea remove inflation from his estimate of Petitioner's fair rate of 32 return? 33 A: Yes. However, Mr. Rea removed inflation from his proposed fair rate of return
34 based on prospective inflation rates, and not historical inflation rates, which are
35 higher. (Pet. Exh. 13, p. 104.) The effect of using prospective inflation rates in
36 this situation is to allow some double recovery or double counting of the inflation. Public's Exhibit No. 7 Cause No. 44988 Page 46 of50
1 Q: How does this allow some double counting of inflation? 2 A: The higher asset values shown in the RCNLD study include the results of
3 historical inflation. The Commission has consistently determined that, when
4 considering the historical effects of inflation on the asset values, the historical
5 inflation rate should be removed from the cost of equity. By removing inflation
6 based on lower prospective inflation rates, Petitioner's cost of equity is overstated
7 by the difference in inflation rates.
8 Q: Is there a difference in the historical and prospective rates of inflation? 9 A: Yes. Historical inflation over the past two decades is higher than the projections
10 for future years that both Mr. Rea and I have found.
11 Q: What inflation rate did Mr. Rea remove from his ROE? 12 A: Mr. Rea recommended the removal of a 1.99% prospective inflation rate from
13 ROE to calculate his return on fair value.
14 Q: What did you determine to be the historical inflation rate? 15 A: I considered the change in the Consumer Price Index from January, 1998 to
16 November, 2017 to arrive at an historical inflation rate of 2.65%. In December
17 1997, the CPI for All Urban Consumers stood at 161.80, according to the Bureau
18 of Labor Statistics. In November 2017 the same index stood at 247.592. Over a 20
19 year period, this represents an average annual change in the CPI of 2.65%. Graph
20 12 depicts historical inflation according to annual changes in the CPI over this
21 period. Public's Exhibit No. 7 Cause No. 44988 Page 47 of 50
GRAPH 12
Annual Inflation Change in Co.mm.mer Price Index, 1998-2017 4.5%
4.0% ------3.8%, ·------
3.4% 3.4% 3.5% 3.2% 3.2%
3.0% 2.S"k------2_7% -- ---2,&%---
2.5% ------2,3%--- 2.2% 2.1 % 2.1 % 2·2¾ 2.0% 1.6% 1.6% 1.6% 1.5% 1.6% 1.5%
1.0% 0.5% tr; ··••• ·• 0.0% l I l 1998 1999 2000 2001 2002 2003 2004 2005 2006 2007 2008 219 2010 2011 2012 2013 2014 2015 2016 2017 -0.5% -0.4% -1.0%
1 Q: What rate of return on Petitioner's proposed fair value do you recommend? 2 A: I proposed an ROE of 9.0% to apply to Petitioner's original cost rate base. If the
3 Commission deems the use of a fair value or current cost rate base appropriate,
4 2.65% should be removed from the 9.0% cost of common equity I calculated to
5 prevent double counting of inflation. Therefore, I would recommend a fair rate of
6 return of 6.35% (9.0% - 2.65% = 6.35%) to be applied to common equity in
7 NIPSCO's capital structure for a fair value rate base.
IX. SUMMARY AND RECOMMENDATIONS ON COST OF EQUITY
8 Q: Please summarize your testimony on DCF calculations for the proxy group. 9 A: Using the same Combination Utility proxy group as Mr. Rea, I calculated a 3.1 %
forward dividend yield. Using the same Gas Utility proxy group as Mr. Rea used
11 in a Columbia Gas of Maryland proceeding in April 2017, I calculated a 2.9% Public's Exhibit No. 7 Cause No. 44988 Page 48 of50
1 forward dividend yield. I also performed calculations and analysis with both the
2 Combination Utility Group and the Gas Utility Group, which led me to conclude
3 that a DCF growth rate, g, of 5.9% is reasonable. This estimate was made using
4 historical and projected growth rates from Value Line, and economic growth data
5 from the Federal Reserve Bank of St. Louis. I considered both projected and
6 historical data. Overall, my DCF calculations resulted in 9.0% ROE for the
7 Combination Utility Group and 8.8% for the Gas Utility Group.
8 Q: Please summarize your testimony on CAPM calculations for the proxy 9 group. 10 A: Based on Value Line betas and using the same proxy group, I calculated an
11 average beta for the proxy group of 0.69 for the Combination Utility Group and
12 0.76 for the Gas Utility Group. As the beta is less than 1.0, it also describes a
13 relatively low-risk industry. I used the Duff & Phelps normalized risk-free rate of
14 3.5%. I reviewed 5-year, 10-year, 20-year, and 30-year bond yield data ending in
15 November 2017 in arriving at this estimate. Giving equal weight to both the
16 geometric mean and arithmetic mean approaches, I calculated a market risk
17 premium of 5.25% for both groups. This results in a CAPM cost of equity for the
18 proxy group of 7.12% for the Combination Utility Group and 7.48% for the Gas
19 Utility Group.
20 Q: Please summarize your testimony on macroeconomic and capital market 21 trends influencing cost of equity. 22 A: In contrast to the market expectations described in CFO Magazine of a 6.57%
23 anticipated return on the S&P 500 over the next year and 7.16% for the next ten
24 years, Petitioner proposes a rate of return of 10.7% for a regulated public utility. Public's Exhibit No. 7 Cause No. 44988 Page 49 of 50
1 In today's capital market, a proposal that high is simply not in accord with current
2 conditions.
3 I examined three macroeconomic variables that can influence the cost of
4 equity capital. First, I examined interest rates. Interest rates on 5-year, 10-year,
5 20-year and 30-year bonds remain low by historical standards, and recent
6 increases have been modest. Second, CBO forecasts real GDP growth over the
7 next 10 years to range from 2.2% in 2017, declining to 2.0% in 2018, 1.6% in the
8 period 2019-2020, and 1.9% in the period 2021-2027. Growth in this range is not
9 likely to drive up interest rates.
10 Third, the United States is in a continuing period of low inflation. Even
11 with energy price volatility in recent years, both "headline" inflation and core
12 inflation remain low compared to earlier periods. While inflation fears are always
13 a policy consideration for the Federal Reserve, recent experience and projections
14 by the CBO tend to indicate inflation is under control in spite of volatility in
15 energy pnces.
16 Q: Please summarize your recommendation for Petitioner's ROE. 17 A: I recommend the Commission authorize a 9.0% cost of equity for Petitioner. This
18 recommendation reflects a risk premium close to 600 basis points over recent
19 yields on 30-year Treasury bonds, which currently hovers below 3.0%. This
20 recommendation is at the high end of the range of my DCF and CAPM
21 calculations for both the Combination Utility and Gas Utility proxy group. The
22 Federal Reserve has maintained a long term gradual course to higher interest
23 rates. Prospects of continued moderate economic growth, gradual increases in Public's Exhibit No. 7 Cause No. 44988 Page 50 of50
1 inflation and recent trends in utility rate cases all suggest the 9.0% level is
2 reasonable. I have found no evidence that would lead me to believe dramatic
3 changes in economic trends are likely in the foreseeable future. Given these
4 economic conditions, and my DCF and CAPM calculations, I believe my
5 recommendation is both fair and reasonable.
6 Q: Please summarize your recommendation for Petitioner's proposed fair rate 7 of return on fair value.
8 A: Consistent with its previous findings, if the Commission deems the use of a fair
9 value rate base appropriate, the return on the fair value rate base should remove
10 historic inflation from the cost of equity calculated for an original cost rate base.
11 This will remove the impact of inflation in the return on fair value. Based upon
12 my analysis, I recommend a 6.35% return on fair value.
13 Q: Does this conclude your testimony? 14 A: Yes. AFFIRMATION
I affirm, under the penalties for perjury, that the foregoing representations are true.
' ,". /V {~.~ ~/ ,~_£."1~ Date Appendix BEL-1 Cause No. 44988 Page 1 of2
APPENDIX BEL-1 TO TESTIMONY OF OUCC WITNESS BRADLEY E. LORTON
1 Q: Please describe your educational background and experience. 2 A: My expertise is in economics and public utility regulation. I hold Bachelor of
3 Science and Master of Science degrees in Economics from Indiana State
4 University. I also completed additional courses in Economics, Mathematics and
5 Labor Studies at Indiana University-Purdue University at Indianapolis. I have
6 completed the Regulatory Studies Program sponsored by the National Association
7 of Regulatory Utility Commissioners ("NARUC") at Michigan State University. I
8 recently completed NARUC's Advanced Regulatory Studies Program:
9 Ratemaking, Accounting and Economics.
10 I have over forty years of experience in government and private industry.
11 My career in public utility regulation began in 2001 when I accepted my current
12 position with the OUCC. Prior to that, I served in management and business analyst
13 positions with the U.S. Department of the Navy at the Naval Air Warfare Center in
14 Indianapolis, and its privatized successor organizations. I also served as an
15 Economist at the Bureau of Labor Statistics, United States Department of Labor,
16 and as a Statistician for the Indiana Division of Labor.
17 I have been awarded the professional designation Certified Rate of Return
18 Analyst ("CRRA") by the Society of Utility and Regulatory Financial Analysts.
19 This designation is awarded based upon experience and successful completion of a
20 written examination. Appendix BEL-1 Cause No. 44988 Page 2 of2
1 Q: Have you previously testified before the Indiana Utility Regulatory 2 Commission? 3 A: Yes. I have previously testified before this Commission addressing economic and
4 financial issues over the past fifteen years, including rate cases in which I testified
5 on cost of common equity.
6 Q: Please describe the review and analysis you conducted in order to prepare 7 your testimony. 8 A: I reviewed NIPSCO's Petition, Case-in-Chief and exhibits, prepared data requests,
9 and reviewed Petitioner's responses. I researched Petitioner's previous rate case
10 from 2010. I also prepared data requests and analyzed the responses to those
11 questions. I researched economic data and analysis from government and
12 authoritative private sector sources. I used the results of this research to run my
13 cost of equity models and support my analyses. Attachment BEL-1 Regulatory Research Associates Cause No. 44988 Page 1 of 13
RRA is an offering of S&P Global Market Intelligence January 18, 2017 MAJOR RATE CASE DECISIONS - JANUARY-DECEMBER 2016
The average ROE authorized electric utilities was 9.77% in rate cases decided in 2016, compared to 9.85% in 2015. There were 42 electric ROE determinations in 2016, versus 30 in 2015. This data includes several limited issue rider cases; excluding these cases from the data, the average authorized ROE was 9.6% in rate cases decided in 2016, the same as in 2015. RRA notes that this differential in electric authorized ROEs is largely driven by Virginia statutes that authorize the State Corporation Commission to approve ROE premiums of up to 200 basis points for certain generation projects (see the Virginia Commission Profile). The average ROE authorized -9.flli utilities was 9.5% in 2016 versus 9.6% in 2015. There were 24 gas cases that included an ROE determination in 2016, versus 16 in 2015.
Graph 1: Average authorized RO Es - electric and gas rate decisions
-Electric -GAS
13.0%
12.5%
12.0%
11.5%
11.0%
10.5%
10.0%
9.5% 9.50% 9.0% '90 '91 '92 '93 '94 '95 '96 '97 '98 '99 '00 '01 '02 '03 '04 '05 '06 '07 '08 '09 '10 11 '12 '13 '14 '15 '16
Source: Regulate ry Research Assa c'Jates, an offering of S&P Gia bal Mark et Intelligence
As shown in Graph 2 below, after reaching a low in the early-2000s, the number of rate case decisions for energy companies has generally increased over the last several years, peaking in 2010 at more than 125 cases.
Graph 2: Volume of electric and gas rate case decisions
140
120
100
80
60
40
20
0 '90 '9'1 '92 '93 '94 '95 '96 '97 '98 '99 '00 '01 '02 '03 '04 '05 '06 '07 '08 '09 '10 '11 '12 '13 '14 '15 '16
Source: Regulate ry Research Associates, an offering of S&P Gia bal Mark et Intelligence
[email protected];p1inted 4/1I/2017 Attachment BEL-1 Cause No. 44988 Since 2010, the number of rate cases has moderated somewhat but has been 90 or more friltfiJ Pcfsl:~ive calendar years. There were 111 electric and gas rate cases resolved. in 2016, 92 in 2015, 99 in both 2014 and 2013, and 110 in 2012, and this level of rate case activity remains robust compared to the late 1990s/early 2000s. Increased costs associated with environmental compliance, including possible CO2 reduction mandates, generation and delivery infrastructure upgrades and expansion, renewable generation mandates and employee benefits argue for the continuation of an active rate case agenda over the next few years. In addition, if the Federal Reserve continues its policy initiated in December 2015 to gradually raise the federal funds rate, utilities eventually would face higher capital costs and would need to initiate rate cases to reflect the higher capital costs in rates. However, the magnitude and pace of any additional Federal Reserve action to raise the federal funds rate is quite uncertain.
Included in tables on pages 6 and 7 of this report are comparisons, since 2006, of average authorized ROEs by settled versus fully litigated cases, general rate cases versus limited issues rider proceedings and vertically integrated cases versus delivery only cases. For both electric and gas cases, no pattern exists in average annual authorized ROEs in cases that were settled versus those that were fully litigated. In some years, the average authorized ROE was higher for fully litigated cases, in others it was higher for settled cases, and in a few years the authorized ROE was similar for fully litigated versus settled cases. Regarding electric cases that involve limited issue riders, over the last several years the annual average authorized ROEs in these cases was typically at least 100 basis points higher than in general rate cases, driven by the ROE premiums authorized in Virginia. Limited issue rider cases in which an ROE is determined have had extremely limited use in the gas industry. Comparing electric vertically integrated cases versus delivery only proceedings, RRA finds that the annual average authorized . ROEs in vertically integrated cases are from roughly 40 to 70 basis points higher than in delivery only cases, arguably reflecting the increased risk associated with generation assets.
Graph 3: Average authorized electric ROEs
-Vertically Integrated -Delivery Only
11.0%
10.8%
10.6%
10.4%
10.2%
10.0%
9.8%
9.6%
9.4%
9.2%
9.0% '06 '07 '08 '09 '10 11 '12 '13 '14 '15 '16
Source: Regulate ry Research Assa ciates, an offering of S&P Gia bal Mark et Intelligence
We note that this report utilizes the simple mean for the return averages. In addition, the average equity returns indicated in this report reflect the cases decided in the specified time periods and are not necessarily representative of the returns actually earned by utilities industry wide.
As a result of electric industry restructuring, certain states unbundled electric rates and implemented retail competition for generation. Commissions in those states now have jurisdiction only over the revenue requirement and return parameters for delivery operations, which we footnote in our chronology beginning on page 8, thus complicating historical data comparability. We note that from 2008 through 2015, interest rates declined significantly, and average authorized ROEs have declined modestly. We also note the increased utilization of limited issue rider proceedings that allow utilities to recover certain costs outside of a general rate case and typically incorporate previously-determined return parameters.
The table on page 4 shows the average ROE authorized in major electric and gas rate decisions annually since 1990, and by quarter since 2013, followed by the number of observations in each period. The tables on page 5 indicate the composite electric and gas industry data for all major cases summarized annually since 2002 and by quarter for the past eight quarters. The individual electric and gas cases decided in 2016 are listed on pages 8-13, with the decision date shown first, followed by the company name, the abbreviation for the state
[email protected];printed 4/11/2017 Attachment BEL-1 Cause No. 44988 issuing the decision, the authorized rate of return, or ROR, ROE, and percentage of common equitflt~eifi&1atibpted capital structure. Next we indicate the month and year in which the adopted test year ended, whether the commission utilized an average or a year-end rate base, and the amount of the permanent rate change authorized. The dollar amounts represent the permanent rate change ordered at the time decisions were rendered. Fuel adjustment clause rate changes are not reflected in this study.
The table below tracks the average equity return authorized for all electric and gas rate cases combined, by year, for the last 27 years. As the table indicates, since 1990 authorized ROEs have generally trended downward, reflecting the significant decline in interest rates and capital costs that has occurred over this time frame. The combined average equity returns authorized for electric and gas utilities in each of the years 1990 through 2016, and the number of observations for each year are as follows:
Composite Electric and Gas Average Annual Authorized RO Es: 1990 - 2016
Average Average Year ROE{%) Observations Year ROE{%) Observations 1990 12.69 (75) 2004 10.67 (39) 1991 12.51 (80) 2005 10.50 (55) 1992 12.06 (77) 2006 10.39 (42) 1993 11.37 (77) 2007 10.30 (76) 1994 11.34 (59) 2008 10.42 (67) 1995 11.51 (49) 2009 10.36 (68) 1996 11.29 (42) 2010 10.28 (100) 1997 11.34 (24) 2011 10.21 (59) 1998 11.59 (20) 2012 10.08 (93) 1999 10.74 {29) 2013 9.92 (71) 2000 11.41 (24) 2014 9.86 (63) 2001 11.05 {25) 2015 9.76 (46) 2002 11.10 (43) 2016 9.67 (66) 2003 10.98 (47) Source: Regulatory Research Associates, an offering of S&P Global Market Intelligence
Please Note: Historical data provided in this report may not match data provided on RRA 's website due to certain differences in presentation, including the treatment of cases that were withdrawn or dismissed.
Dennis Sperdute
©2017, Regulatory Research Associates, Inc., an offering of S&P Global Market Intelligence. All Rights Reserved. Confidential Subject Matter. WARNING! This report contains copyrighted subject matter and confidential information owned solely by Regulatory Research Associates, Inc. ("RRA"). Reproduction, distribution or use of this report in violation of this license constitutes copyright infringement in violation of federal and state law. RRA hereby provides consent to use the "email this story" feature to redistribute articles within the subscriber's company. Although the information in this report has been obtained from sources that RRA believes to be reliable, RRA does not guarantee its accuracy.
[email protected];printed 4/11/2017 Attachment BEL-1 Cause No. 44988 Page 4 ofl3
RRA-REGULATORY FOCUS -4- January 18, 2017
Average Equity Returns Authorized January 1990 - December 2016 Electric Utilities Gas Utilities Year Period ROE% (# Cases) ROE% (# Cases) 1990 Full Year 12.70 (44) 12.67 (31) 1991 Full Year 12.55 (45) 12.46 (35) 1992 Full Year 12.09 (48) 12.01 (29) 1993 Full Year 11.41 (32) 11.35 (45) 1994 Full Year 11.34 (31) 11.35 (28) 1995 Full Year 11.55 (33) 11.43 (16) 1996 Full Year 11.39 (22) 11.19 (20) 1997 Full Year 11.40 (11) 11.29 (13) 1998 Full Year 11.66 (10) 11.51 (10) 1999 Full Year 10.77 (20) 10.66 (9) 2000 Full Year 11.43 (12) 11.39 (12) 2001 Full Year 11.09 (18) 10.95 (7) 2002 Full Year 11.16 (22) 11.03 (21) 2003 Full Year 10.97 (22) 10.99 (25) 2004 Full Year 10.75 (19) 10.59 (20) 2005 Full Year 10.54 (29) 10.46 (26) 2006 Full Year 10.32 (26) 10.40 (15) 2007 Full Year 10.30 (38) 10.22 (35) 2008 Full Year 10.41 (37) 10.39 (32) 2009 Full Year 10.52 (40) 10.22 (30) 2010 Full Year 10.37 (61) 10.15 (39) 2011 Full Year 10.29 (42) 9.92 (16) 2012 Full Year 10.17 (58) 9.94 (35)
1st Quarter 10.28 (14) 9.57 (3) 2nd Quarter 9.84 (7) 9.47 (6) 3rd Quarter 10.06 (7) 9.60 (1) 4th Quarter 9.91 (21) 9.83 (11) 2013 Full Year 10.03 (49) 9.68 (21)
1st Quarter 10.23 (8) 9.54 (6) 2nd Quarter 9.83 (5) 9.84 (8) 3rd Quarter 9.87 (12) 9.45 (6) 4th Quarter 9.78 (13) 10.28 (6) 2014 Full Year 9.91 (38) 9.78 (26)
1st Quarter 10.37 (9) 9.47 (3) 2nd Quarter 9.73 (7) 9.43 (3) 3rd Quarter 9.40 (2) 9.75 (1) 4th Quarter 9.62 (12) 9.68 (9) 2015 Full Year 9.85 (30) 9.60 (16)
1st Quarter 10.29 (9) 9.48 (6) 2nd Quarter 9.60 (7) 9.42 (6) 3rd Quarter 9.76 (8) 9.47 (4) 4th Quarter 9.57 (18) 9.60 (8) 2016 Full Year 9.77 (42) 9.50 (24) Source: Regulatory Research Associates, an offering of S&P Global Market Intelligence
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RRA-REGULATORY FOCUS -5- January 18, 2017 Electric Utilities--Summary Table Period ROR% (# Cases} ROE o/o (# Cases} Cap. Struc. (# Cases} $Mil. (# Cases} 2002 Full Year 8.72 (20} 11.16 (22} 46.27 (19} -475.4 (24} 2003 Full Year 8.86 (20} 10.97 (22} 49.41 (19} 313.8 (12} 2004 Full Year 8.44 (18} 10.75 (19} 46.84 (17} 1,091.5 (30} 2005 Full Year 8.30 (26} 10.54 (29} 46.73 (27} 1,373.7 (36} 2006 Full Year 8.32 (26) 10.32 (26} 48.54 (25} 1,318.1 (39) 2007 Full Year 8.18 (37} 10.30 (38} 47.88 (36} 1,405.7 (43} 2008 Full Year 8.21 (39} 10.41 (37} 47.94 (36} 2,823.2 (44} 2009 Full Year 8.24 (40} 10.52 (40} 48.57 (39} 4,191.7 (58) 2010 Full Year 8.01 (62) 10.37 (61) 48.63 (57) 4,921.9 (78) 2011 Full Year 8.00 (43) 10.29 (42) 48.26 (42) 2,595.1 (56) 2012 Full Year 7.95 (51) 10.17 (58) 50.69 (52) 3,080.7 (69} 2013 Full Year 7.66 (45) 10.03 (49) 49.25 (43} 3,328.6 (61} 2014 Full Year 7.60 (32} 9.91 (38} 50.28 (35} 2,053.7 (51}
1st Quarter 7.74 (10} 10.37 (9) 51.91 (9) 203.6 (11} 2nd Quarter 7.04 (9) 9.73 (7) 47.83 (6) 819.5 (17) 3rd Quarter 7.85 (3) 9.40 (2) 51.08 (3) 379.6 (5) 4th Quarter 7.22 (13) 9.62 (12) 48.24 (12) 488.7 (19} 2015 Full Year 7.38 (35} 9.85 (30} 49.54 (30} 1,891.5 (52}
1st Quarter 7.03 (9) 10.29 (9) 46.06 (9) 311.2 (12) 2nd Quarter 7.42 (7) 9.60 (7) 49.91 (7) 117.7 (9) 3rd Quarter 7.23 (8) 9.76 (8) 49.11 (8) 499.1 (13) 4th Quarter 7.38 (17) 9.57 (18) 49.93 (17) 1,421.4 (23} 2016 Full Year 7.28 (41} 9.77 (42} 48.91 (41} 2,349.4 (57} Gas Utilities--Summary Table Period ROR% (# Cases} ROE% (# Cases} Cap. Struc. (# Cases) $Mil. (# Cases} 2002 Full Year 8.80 (20) 11.03 (21) 48.29 (18} 303.6 (26) 2003 Full Year 8.75 (22) 10.99 (25) 49.93 (22) 260.1 (30} 2004 Full Year 8.34 (21) 10.59 (20} 45.90 (20} 303.5 (31} 2005 Full Year 8.25 (29} 10.46 (26) 48.66 (24) 458.4 (34} 2006 Full Year 8.44 (17) 10.40 (15} 47.24 (16) 392.5 (23} 2007 Full Year 8.11 (31} 10.22 (35} 48.47 (28} 645.3 (43} 2008 Full Year 8.49 (33} 10.39 (32} 50.35 (32) 700.0 (40) 2009 Full Year 8.15 (29) 10.22 (30) 48.49 (29} 438.6 (36} 2010 Full Year 7.99 (40) 10.15 (39} 48.70 (40} 776.5 (50) 2011 Full Year 8.09 (18} 9.92 (16} 52.49 (14} 367.0 (31} 2012 Full Year 7.98 (30) 9.94 (35) 51.13 (32) 264.0 (41} 2013 Full Year 7.39 (20) 9.68 (21) 50.60 (20} 494.9 (38} 2014 Full Year 7.65 (27) 9.78 (26) 51.11 (28) 529.2 (48)
1st Quarter 6.41 (2) 9.47 (3) 50.41 (2) 168.9 (9) 2nd Quarter 7.29 (3) 9.43 (3) 50.71 (3) 34.9 (8) 3rd Quarter 7.35 (1) 9.75 (1) 42.01 (1) 103.9 (8) 4th Quarter 7.54 (10) 9.68 (9) 50.40 (10) 186.5 (15) 2015 Full Year 7.34 (16} 9.60 (16) 49.93 (16} 494.1 (40)
1st Quarter 7.12 (6) 9.48 (6) 50.83 (6) 120.2 (11) 2nd Quarter 7.38 (6) 9.42 (6) 50.01 (6) 276.3 (16) 3rd Quarter 6.59 (5) 9.47 (4) 48.44 (4) 106.3 (8) 4th Quarter 6.71 (7) 9.60 (8) 48.74 (7) 733.1 (19) 2016 Full Year 6.95 (24) 9.50 (24) 49.56 (23) 1,235.9 (54) Source: Regulatory Research Associates, an offering of S&P Global Market Intelligence
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RRA-REGULATORY FOCUS -6- January 18, 2017
Electric Average Authorized RO Es: 2006 - 2016
Settled versus Fully Litigated Cases All Cases Settled Cases Fully Litigated Cases Year ROE% {# Cases) ROE% {# Cases) ROE% {# Cases) 2006 10.32 (26) 10.26 (11) 10.37 (15) 2007 10.30 (38) 10.42 (14) 10.23 (24) 2008 10.41 (37) 10.43 (17) 10.39 (20) 2009 10.52 (40) 10.64 (16) 10.45 (24) 2010 10.37 (61) 10.39 (34) 10.35 (27) 2011 10.29 (42) 10.12 (16) 10.39 (26) 2012 10.17 (58) 10.06 (29) 10.28 (29) 2013 10.03 (49) 10.12 (32) 9.85 (17) 2014 9.91 (38) 9.73 (17) 10.05 (21) 2015 9.85 (30) 10.07 (14) 9.66 (16) 2016 9.77 (42) 9.80 (17) 9.74 (25)
General Rate Cases versus Limited Issue Riders All Cases General Rate Cases Limited Issue Riders Year ROE% {# Cases) ROE% {# Cases) ROE% {# Cases) 2006 10.32 (26) 10.34 (25) 9.80 (1) 2007 10.30 (38) 10.31 (37) 9.90 (1) 2008 10.41 (37) 10.37 (35) 11.11 (2) 2009 10.52 (40) 10.52 (38) 10.55 (2) 2010 10.37 (61) 10.29 (58) 11.87 (3) 2011 10.29 (42) 10.19 (40) 12.30 (2) 2012 10.17 (58) 10.01 (52) 11.57 (6) 2013 10.03 (49) 9.81 (42) 11.34 (7) 2014 9.91 (38) 9.75 (33) 10.96 (5) 2015 9.85 (30) 9.60 (24) 10.87 (6) 2016 9.77 (42) 9.60 (32) 10.31 (10)
Vertically Integrated Cases versus Delivery Only Cases Vertically All Cases Integrated Cases Delivery Only Cases Year ROE% {# Cases) ROE% {# Cases) ROE% (# Cases) 2006 10.32 (26) 10.63 (15) 9.91 (10) 2007 10.30 (38) 10.50 (26) 9.86 (11) 2008 10.41 (37) 10.48 (26) 10.04 (9) 2009 10.52 (40) 10.66 (28) 10.15 (1 OJ 2010 10.37 (61) 10.42 (41) 9.98 (17) 2011 10.29 (42) 10.33 (28) 9.85 (12) 2012 10.17 (58) 10.10 (39) 9.73 (13) 2013 10.03 (49) 9.95 (31) 9.41 (11) 2014 9.91 (38) 9.94 (19) 9.50 (14) 2015 9.85 (30) 9.75 (17) 9.23 (7) 2016 9.77 (42) 9.77 (20) 9.31 (12) Source: Regulatory Research Associates, an offering of S&P Global Market Intelligence
[email protected];printed 4/11/2017 Attachment BEL-1 Cause No. 44988 Page 7 of13
RRA-REGULATORY FOCUS -7- January 18, 2017
Gas Average Authorized ROEs: 2006 - 2016
Settled versus Fully Litigated Cases All Cases Settled Cases Fully Litigated Cases Vear ROE% (# Cases) ROE% (# Cases) ROE% (# Cases) 2006 10.40 (15) 10.26 (7) 10.53 (8) 2007 10.22 (35) 10.24 (22) 10.20 (13) 2008 10.39 (32) 10.34 (20) 10.47 (12) 2009 10.22 (30) 10.43 (13) 10.05 (17) 2010 10.15 (39) 10.30 (12) 10.08 (27) 2011 9.92 (16) 10.08 (8) 9.76 (8) 2012 9.94 (35) 9.99 (14) 9.92 (21) 2013 9.68 (21) 9.80 (9) 9.59 (12) 2014 9.78 (26) 9.51 (11) 9.98 (15) 2015 9.60 (16) 9.60 (11) 9.58 (5) 2016 9.50 (24) 9.43 (14) 9.61 (10)
General Rate Cases versus Limited Issue Riders All Cases General Rate Cases Limited Issue Riders Vear ROE% (# Cases) ROE% (# Cases) ROE% (# Cases) 2006 10.40 (15) 10.40 (15) (0) 2007 10.22 (35) 10.22 (35) (0) 2008 10.39 (32) 10.39 (32) (0) 2009 10.22 (30) 10.22 (30) (0) 2010 10.15 (39) 10.15 (39) (0) 2011 9.92 (16) 9.91 (15) 10.00 (1) 2012 9.94 (35) 9.93 (34) 10.40 (1) 2013 9.68 (21) 9.68 (21) (0) 2014 9.78 (26) 9.78 (26) (0) 2015 9.60 (16) 9.60 (16) (0) 2016 9.50 (24) 9.49 (23) 9.70 (1) Source: Regulatory Research Associates, an offering of S&P Global Market Intelligence
[email protected];printed 4/11/2017 Attachment BEL-1 Cause No. 44988 Page 8 of13
RRA-REGULATORY FOCUS -8- January 18, 2017
Electric Utility Decisions Common ROR Equity as 0/o Test Amt. Date Company State 0/o ROE 0/o of Capital Year Rate Base $ Mil. Footnotes
1/5/16 MDU Resources Group ND 7.95 10.50 50.27 12/16 15.1 (B,LIR,1) 1/6/16 Avista Corporation WA 7.29 9.50 48.50 9/14 -8.1 (Bl 1/28/16 Northern India-- Public Service Co. IN 0.0 (LIR,2)
2/2/16 Kentucky Utilities Company VA 12/14 5.5 (Bl 2/23/16 Entergy Arkansas AR 4.52 9.75 28.46 3/15 219.7 (B,*) 2/29/16 Virginia Electric and Power Company VA 7.90 11.60 49.99 3/17 Average 21.0 (LIR,3) 2/29/16 Virginia Electric and Power Company VA 7.40 10.60 49.99 3/17 Average -9.3 (LIR,4) 2/29/16 Virginia Electric and Power Company VA 7.40 10.60 49.99 3/17 Average 6.6 (LIR,5) 2/29/16 Virginia Electric and Power Company VA 7.40 10.60 49.99 3/17 Average -16.8 (LIR,6)
3/16/16 Indianapolis Power & Light Company IN 6.51 9.85 37.33 6/14 Year-end 29.6 (*) 3/25/16 MDU Resources Group MT 12/14 7.4 (B,Z) 3/29/16 Virginia Electric and Power Company VA 6.90 9.60 49.99 3/17 Average 40.4 (LIR,7)
2016 1ST QUARTER: AVERAGES/TOTAL 7.03 10.29 46.06 311.2 OBSERVATIONS 9 9 9 12
4/29/16 Fitchburg Gas and Electric Light Co. MA 8.46 9.80 52.17 12/14 Vear-end 2.1 (DJ
6/3/16 Baltimore Gas and Electric Company MD 7.28 9.75 51.90 11/15 Average 44.1 (D,R) 6/8/16 El Paso Electric Company NM 7.67 9.48 49.29 12/14 Vear-end 1.1 6/15/16 New York State Electric & Gas Corp. NY 6.68 9.00 48.00 4/17 Average 29.6 (B,D,Z,8) 6/15/16 Rochester Gas and Electric Corp. NY 7.55 9.00 48.00 4/17 Average 3.0 (B,D,Z,8) 6/23/16 San Diego Gas & Electric Co. CA 12/16 Average 3.0 (B,Z,9) 6/30/16 Appalachian Power Company WV 55.1 (B,LIR, 10) 6/30/16 Virginia Electric and Power Company VA 7.40 10.60 49.99 8/17 Average -25.7 (LIR, 11) 6/30/16 Virginia Electric and Power Company VA 6.90 9.60 49.99 8/17 Average 5.4 (LIR,12)
2016 2ND QUARTER: AVERAGES/TOTAL 7.42 9.60 49.91 117.7 OBSERVATIONS 7 7 7 9
7 /18/16 Northern Indiana Public Service Co. IN 6.74 9.98 47.42 3/15 Year-end 72.5 (B,*)
8/9/16 Kingsport Power Company TN 6.18 9.85 40.25 12/17 Average 8.6 (Bl 8/10/16 Southwestern Public Service Co. NM 23.5 (Bl 8/10/16 Empire District Electric Company MO 6/15 20.4 (Bl 8/18/16 El Paso Electric Company TX 3/15 40.7 (l,B) 8/18/16 UNS Electric, Inc. AZ 7.22 9.50 52.83 12/14 Year-end 15.1 8/22/16 Virginia Electric and Power Company VA 8/17 21.3 (LIR, B, 13) 8/24/16 Atlantic City Electric Company NJ 7.64 9.75 49.48 12/15 Year-end 45.0 (D,B)
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RRA-REGULATORY FOCUS -9- January 18, 2017
Electric Utility Decisions (continued)
Common ROR Equity as% Test Amt. Date Company State o/o ROE o/o of Capital Year Rate Base $ Mil. Footnotes
9/1/16 PacifiCorp WA 7.30 9.50 49.10 6/15 Year-end 13.7 (Z) 9/8/16 Upper Peninsula Power Company Ml 7.47 10.00 53.49 12/16 Average 4.6 (I,*) 9/28/16 Public Service Co. of New Mexico NM 7.71 9.58 49.61 9/16 Average 61.2 9/28/16 KCP&L Greater Missouri Operations MO 3.0 (B) 9/30/16 Massachusetts Electric Company MA 7.58 9.90 50.70 6/15 Year-end 169.7 (D)
2016 3RD QUARTER: AVERAGES/TOTAL 7.23 9.76 49.11 499.3 OBSERVATIONS 8 8 8 13
10/6/16 Appalachian Power Company VA 9.40 - (LIR) 10/19/16 South Carolina Electric & Gas Co. SC 8.24 51.35 6/16 Year-end 64.4 (LIR, 14) 10/26/16 Northern States Power Company - WI WI 12/17 24.5 (15)
11/9/16 Madison Gas and Electric Company WI 7.89 9.80 57.16 12/17 Average -3.3 11/10/16 Public Service Company of Oklahoma OK 6.94 9.50 44.00 1/15 Year-end 14.5 11/15/16 Potomac Electric Power Company MD 7.49 9.55 49.55 12/15 Average 52.5 (D) 11/18/16 Wisconsin Power and Light Company WI 7.91 10.00 52.20 12/18 Average 9.4 (B,Z) 11/29/16 Florida Power & Light Company FL 10.55 12/18 811.0 (B,Z)
12/1/16 Liberty Utilities (CalPeco Electric) LLC CA 7.51 10.00 52.50 12/16 Average 8.3 (B) 12/6/16 Commonwealth Edison Company IL 6.71 8.64 45.62 12/15 Year-end 130.9 (D) 12/6/16 Ameren Illinois Company IL 7.28 8.64 50.00 12/15 Year-end -8.8 (D) 12/6/16 Entergy Arkansas, Inc. AR 12/17 54.4 (B) 12/7/16 Duke Energy Progress, LLC SC 7.21 10.10 53.00 12/15 Year-end 56.2 (B,Z) 12/9/16 Monongahela Power Company WV 6/16 25.0 (B,LIR, 16)
12/12/16 Jersey Central Power & Light Co. NJ 7.47 9.60 45.00 6/16 Year-end 80.0 (B,D) 12/14/16 United Illuminating Company CT 7.08 9.10 50.00 12/15 Average 57.4 (D,Z) 12/15/16 Avista Corporation WA 0.0 (17) 12/19/16 Black Hills Colorado Electric Utility Co. co 7.43 9.37 52.39 12/15 Average 0.6 12/19/16 Emera Maine ME 7.45 9.00 49.00 12/14 Average 3.0 (D,Hy) 12/20/16 Georgia Power Company GA 12/17 - (LIR,W,18) 12/22/16 Sierra Pacific Power Company NV 6.65 9.60 48.03 12/15 -2.9 (B) 12/22/16 Virginia Electric and Power Company NC 7.37 9.90 51.75 12/15 Year-end 34.7 (B,I) 12/23/16 Hawaiian Electric Company, Inc. HI 0.0 (19) 12/28/16 Avista Corporation ID 7.58 9.50 50.00 12/15 Average 6.3 (B) 12/30/16 Appalachian Power Company VA 7.30 10.00 47.22 12/17 Average 3.3 (B,LIR,20)
2016 4TH QUARTER: AVERAGES/TOTAL 7.38 9.57 49.93 1,421.4 OBSERVATIONS 17 18 17 23 2016 FULL YEAR: AVERAGES/TOTAL 7.28 9.77 48.91 2,349.6 OBSERVATIONS 41 42 41 57 Source: Regulatory Research Associates, an offering of S&P Global Market Intelligence
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RRA-REGULATORY FOCUS -10- January 18, 2017
Gas Utility Decisions
Common ROR Equity as% Test Amt. Date Company State % ROE% of Capital Year Rate Base $ Mil. Footnotes
1/6/16 Oklahoma Natural Gas Company OK 7.31 9.50 60.50 3/15 Year-end 30.0 (B) 1/6/16 Avista Corporation WA 7.29 9.50 48.50 09/14 10.8 (B) 1/28/16 SourceGas Arkansas AR 5.33 9.40 39.46 3/15 Year-end 8.0 (B,*)
2/10/16 Liberty Utilities (New England Nat. Gas) MA 7.99 9.60 50.00 12/14 Year-end 7.8 (B) 2/16/16 Public Service Company of Colorado co 7.33 9.50 56.51 12/14 Average 39.2 (l,Z,R) 2/25/16 Black Hills Kansas Gas Utility Company KS 10/15 Year-end 0.8 (LIR,21) 2/29/16 Avista Corporation OR 7.46 9.40 50.00 12/16 Average 4.5
3/17 /16 Atmos Energy Corporation KS 3/15 2.2 (B) 3/30/16 Indiana Gas Company, Inc. IN 6/15 Year-end 7.0 (LIR,22) 3/30/16 Northern Indiana Public Service Co. IN 6/15 Year-end 7.6 (LIR,23) 3/30/16 Southern Indiana Gas and Electric Co. IN 6/15 Vear-end 2.3 (LIR,22)
2016 1ST QUARTER: AVERAGES/TOTAL 7.12 9.48 50.83 120.2 OBSERVATIONS 6 6 6 11
4/21/16 Consumers Energy Company Ml 12/16 40.0 (l,B) 4/29/16 Fitchburg Gas and Electric Light Company MA 8.46 9.80 52.17 12/14 Year-end 1.6
5/5/16 CenterPoint Energy Resources Corp. MN 7.07 9.49 50.00 9/16 Average 27.5 (I) 5/11/16 Liberty Utilities (Midstates Nat. Gas) MO 1/16 0.2 (LIR,24) 5/19/16 Delta Natural Gas Company KY 12/15 Year-end 1.4 (LIR) 5/19/16 Laclede Gas Company MO 2/16 Year-end 5.4 (LIR,25) 5/19/16 Missouri Gas Energy MO 2/16 Year-end 3.6 (LIR,25)
6/1/16 Maine Natural Gas ME 7.28 9.55 50.00 9/14 Average 2.5 (B,Z) 6/3/16 Baltimore Gas and Electric Company MD 7.23 9.65 51.90 11/15 Average 47.9 (R) 6/15/16 New York State Electric & Gas Corporation NV 6.68 9.00 48.00 4/17 Average 13.1 (B,Z,7) 6/15/16 Rochester Gas and Electric Corp. NY 7.55 9.00 48.00 4/17 Average 8.8 (B,Z,7) 6/22/16 Northern Indiana Public Service Co. IN 12/15 Year-end 6.7 (LIR,E,26) 6/23/16 San Diego Gas & Electric Co. CA 12/16 Average -1.6 (B,Z,27) 6/23/16 Southern California Gas Company CA 12/16 Average 106.9 (B,Z,9) 6/29/16 Indiana Gas Company, Inc. IN 12/15 Year-end 10.2 (LI R,28) 6/29/16 Southern Indiana Gas and Electric Co. IN 12/15 Year-end 2.1 (LI R,28)
2016 2ND QUARTER: AVERAGES/TOTAL 7.38 9.42 50.01 276.3 OBSERVATIONS 6 6 6 16
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RRA-REGULATORY FOCUS -11- January 18, 2017
Gas Utility Decisions (continued) Common ROR Equity as% Test Amt. Date Company State % ROE% of Capital Year Rate Base $ Mil. Footnotes
7/7/16 Cascade Natural Gas Corporation WA 7.35 4.0 (B) 7/19/16 CenterPoint Energy Resources Corp. OK 12/15 0.0 (B,29)
8/4/16 Atmos Energy Corporation KY 5/17 0.5 (B) 8/22/16 Questar Gas Company UT - (30)
9/1/16 UGI Utilities, Inc. PA 9/17 27.0 (B) 9/2/16 CenterPoint Energy Resources Corp. AR 4.53 9.50 30.85 9/15 Year-end 14.2 (B,*) 9/23/16 New Jersey Natural Gas Company NJ 6.90 9.75 52.50 6/16 Year-end 45.0 (B) 9/27/16 Texas Gas Service Company TX 7.28 9.50 60.10 9/15 Year-end 8.8 9/29/16 Minnesota Energy Resources Corp. MN 6.88 9.11 50.32 12/16 Average 6.8 (l,E)
2016 3RD QUARTER: AVERAGES/TOTAL 6.59 9.47 48.44 106.3 OBSERVATIONS 5 4 4 8
10/26/16 Northern States Power Company - WI WI 12/17 4.8 (15) 10/27/16 Columbia Gas of Maryland, Inc. MD 4/16 3.7 (B) 10/27/16 Columbia Gas of Pennsylvania, Inc. PA 12/17 35.0 (B) 10/28/16 Public Service Co. of North Carolina NC 7.53 9.70 52.00 12/15 Year-end 19.1 (B)
11/9/16 Madison Gas and Electric Company WI 9.80 12/17 3.1 11/14/16 Atmos Energy Corporation KY 9/17 Year-end 5.0 (LIR,31) 11/15/16 Texas Gas Service Company · TX 12/15 6.8 (B) 11/18/16 Wisconsin Power and Light Company WI 7.84 10.00 52.20 12/18 Average 9.4 (B,Z) 11/23/16 Baltimore Gas and Electric Company MD 12/18 Average 6.1 (B,Z,LIR,32) 11/29/16 Kansas Gas Service Company KS 15.5 (B)
12/1/16 Pacific Gas and Electric Company CA 12/15 Average 100.0 (Tr,I, 33) 12/9/16 DTE Gas Company Ml 5.76 10.10 38.65 10/17 Average 122.3 (I,*) 12/14/16 Columbia Gas of Maryland, Inc. MD 7.53 9.70 54.29 12/17 Average 1.2 (LI R,32) 12/15/16 KeySpan Gas East Corporation NY 6.42 9.00 48.00 12/17 Average 112.0 (B,34) 12/15/16 Brooklyn Union Gas Company NY 6.15 9.00 48.00 12/17 Average 272.1 (B,35) 12/15/16 Avista Corporation WA 0.0 (17) 12/20/16 Columbia Gas of Virginia, Inc. VA 12/17 Average 1.3 (LI R,36) 12/22/16 Columbia Gas of Kentucky, Inc. KY 18.1 (B) 12/22/16 Sierra Pacific Power Company NV 5.75 9.50 48.03 12/15 -2.4 (B)
2016 4TH QUARTER: AVERAGES/TOTAL 6.71 9.60 48.74 733.1 OBSERVATIONS 7 8 7 19
2016 FULL YEAR: AVERAGES/TOTAL 6.95 9.50 49.56 1,235.9 OBSERVATIONS 24 24 23 54 Source: Regulatory Research Associates, an offering of S&P Global Market Intelligence
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RRA-REGULATORY FOCUS -12- January 18, 2017
FOOTNOTES
A Average B- Order followed stipulation or settlement by the parties. Decision particulars not necessarily precedent-setting or specifically adopted by the regulatory body. CWIP Construction work in progress D Applies to electric delivery only DCt Date certain rate base valuation E- Estimated F- Return on fair value rate base Hy- Hypothetical capital structure utilized 1- Interim rates implemented prior to the issuance of final order, normally under bond and subject to refund. LIR Limited-issue rider proceeding M- "Make-whole" rate change based on return on equity or overall return authorized in previous case. R- Revised Te Temporary rates implemented prior to the issuance of final order. Tr- Applies to transmission service U- Double leverage capital structure utilized. W Case withdrawn YE- Year-end 2- Rate change implemented in multiple steps. * Capital structure includes cost-free items or tax credit balances at the overall rate of return.
(1) Rate increase approved in renewable resource cost recovery rider. (2) Case represents the company's transmission, distribution, and storage system improvement charge, or TDSIC rate adjutment mechanism. The case was dismissed by the Commission, with no rate change authorized. (3) Proceeding determines the revenue requirement for Rider B, which is the mechanism through which the company recovers costs associated with its plan to convert the Altavista, Hopewell, and Southampton Power Stations to burn biomass fuels. (4) Represents rate decrease associated with the company's Rider R proceeding, which is the mechanism through which the company recovers the investment in the Bear Garden generating facility. (5) This proceeding determines the revenue requirement for Rider S, which recognizes in rates the company's investment in the Virginia City Hybrid Energy Center. (6) Decrease authorized through a surcharge, Rider W, which reflects in rates investment in the Warren County Power Station. (7) Proceeding involves a new gas-fired generation facility, the Greensville County project, and creation of a new rider mechanism, Rider GV, to reflect the related revenue requirement in rates. (8) Rate increase effective S/1 /16; additional increases to be effective 5/1/17 and 5/1 /18. (9) Settlement adopted with modifications. Rate increase effective retroactive to 1/1/16; additional increases to be effective 1/1/17 and 1/1/18. (10) Represents the company's joint expanded net energy cost, or ENEC, proceeding. (11) Represents rate decrease associated with the company's Rider BW proceeding, which is the mechanism through which the company recovers the investment in its Brunswick County Power Station. (12) Represents the rate increase associated with the company's Rider US-2, which is the mechanism through which the company recovers the revenue requirement associated with three new solar generation facilities. (13) Case involves the company's request to establish Rider U for recovery of investment and costs associated with a project to underground certain distribution lines. (14) The present case involves South Carolina Electric & Gas' request for a cash return on incremental V.C. Summer Units 2 and 3 construction work in progress (CWI P) and incorporates the 10.5% return on equity that was authorized in September 2015 for use in the Summer CWIP-related proceedings beginning in 2016. (15) The rate case is for the limited purpose of recovering anticipated increases in: generation and transmission fixed charges and fuel and purchased power expenses related to the interchange agreement with affiliate NSP-Minnesota; and, rate base investment.
[email protected];printed 4/11/2017 Attachment BEL-1 Cause No. 44988 Page 13 of13
RRA-REGULATORY FOCUS -13- January 18, 2017
FOOTNOTES (continued)
(16) Case is a consolidated expanded net energy cost proceeding for Monongahela Power and affiliate Potomac Edison. (17) Rate increase rejected by commission. (18) As a result of the commission's adoption of a settlement in another proceeding, the company withrew its rate increase request in this proceeding, and no rate change was implemented. (19) No change in base rates was sought by the company, and on 12/23/16, the commission issued an order closing this docket. (20) Case involves the company's G-RAC rider mechanism that addresses its investment in the Dresden Generating Plant, and establishes the revenue requirement for the rider to become effective 1/1/17. (21) Case involves the company's gas system reliabillity surcharge, or GSRS, rider and reflects investments made from July 1, 2014 through Oct. 31, 2015. (22) Case involves company's "compliance and system improvement adjustment" mechanism, and includes compliance related investments made between Jan. 1 and June 30, 2015, and certain other investments made between July 1, 2014 and June 30, 2015. (23) Case establishes the rates to be charged to customers under the company's transmission, distribution and storage system improvement charge rate adjustment mechanism, and reflects investments made between July 1, 2014 and June 30, 2015. (24) Case involves the company's infrastructure system replacement surcharge rider and reflects incremental investments made from 6/1/15 through 1/31/16. (25) Case involves the company's infrastructure system replacement surcharge rider and reflects incremental investments made from 9/1/15 through 2/29/16. (26) Case establishes the rates to be charged to customers under the company's transmission, distribution and storage system improvement charge rate adjustment mechanism, and reflects investments made between 7/1/15 and 12/31 /15. (27) Settlement adopted with modifications. Rate decrease effective retroactive to 1/1/16; rate increases to be effective 1/1 /17 and 1/1/18. (28) Case involves company's "compliance and system improvement adjustment" mechanism, and includes compliance related investments made between 7/1/15 and 12/31/15. (29) Case involves the company's performance based ratemaking plan. (30) On 8/22/16, the PSC approved the company's petition to withdraw the rate increase request, effectively closing the case. The request to withdraw the filing comported with provisions of a settlement filed in the Questar/Dominion Resources merger proceeding. (31) Case is an annual update to the company's pipe replacement program rider. (32) Case involves the company's strategic infrastrucure development and enhancement, or STRIDE, rider. (33) Case involves the company's gas transmission and storage operations. The decision also authorized attrition rate increases of $246 million for 2016, $64 million for 2017 and $105 million for 2018. (34) Adopted joint proposal provides for the company to implement a $112 million rate increase effective 1/1/17, a $19.6 million rate increase effective 1/1/18, and a $27 million rate increase effective 1/1/19. (35) Adopted joint proposal provides for the company to implement a $272.1 million rate increase effective 1/1 /17, a $41 million rate increase effective 1/1/18, and a $48.9 million rate increase effective 1/1/19. (36) Case involves the company's investments under the Steps to Advance Virginia's Energy Plan.
Dennis Sperduto
[email protected];printed 4/11/2017 Attachment BEL-2
• i,. I ~ II: t ~ ~ INFRASTRUCTURE ~ND f'RC'Jff"T FINANCE
SECTOR IN-DEPTH US Regulated Utilities 10 MARCH 2015 Lower Authorized Equity Returns Will
Rate this Research Not Hurt Near-Term Credit Profiles m The credit profiles of US regulated utilities will remain intact over the next few years despite our expectation that regulators will continue to trim the sector's profitability by lowering its authorized returns on equity (ROE). Persistently low interest rates and a comprehensive suite of cost recovery mechanisms ensure a low business risk profile for utilities, prompting ANALYST CONTACTS regulators to scrutinise their profitability, which is defined as the ratio of net income to Jim Hempstead 212-553-4318 book equity. We view cash flow measures as a more important rating driver than authorized Associate /vlanaging Director [email protected] ROEs, and we note that regulators can lower authorized ROEs without hurting cash flow, for instance by targeting depreciation, or through special rate structures. Regulators can Ryan Wobbrock 212-553-7104 AVP-Analyst also adjust a utility's equity capitalization in its rate base. All else being equal, we think most ryan. [email protected] utilities would prefer a thicker equity base and a lower authorized ROE over a small equity
Jeffrey F. Cassella 212-553-1665 layer and a high authorized ROE. AVP-Analyst [email protected] » More timely cost recovery helps offset falling RO Es. Regulators continue to permit
Lesley Ritter 212-553-1607 a robust suite of mechanisms that enable utilities to recoup prudently incurred operating Analyst costs, including capital investments such as environment related or infrastructure [email protected] hardening expenditures. Strong cost recovery is credit positive because it ensures a stable Jairo Chung 212-553-5123 financial profile. Despite lower authorized ROEs, we see the sector maintaining a ratio of Analyst Funds From Operations (FFO) to debt near 20%, a level that continues to support strong [email protected] investment-grade ratings. Natividad Martel 212-553-4561 VP-Senior Analyst » Utilities' cash flow is somewhat insulated from lower ROEs. Net income represents [email protected] about 30% - 40% of utilities' cash flow, so lower authorized returns won't necessarily Susana Vivares 212-553-4694 affect cash flow or key financial credit ratios, especially when the denominator (equity) VP-Senior Analyst [email protected] is rising. Regulators set the equity layer when capitalizing rate base, and the equity layer multiplied by the authorized ROE drives the annual revenue requirements. Across the Toby Shea 212-553-1779 VP-Senior Analyst sector, the ratio of equity to total assets has remained flat in the 30% range since 2007. [email protected] » Utilities' actual financial performance remains stable. Earned ROEs, which typically Swami Venkataraman, CFA 212-553-7950 VP-Sr Credit Officer lag authorized RO Es, have not fallen as much as authorized returns in recent years. [email protected] Since 2007, vertically integrated utilities, transmission and distribution only utilities, and natural gas local distribution companies have maintained steady earned RO E's in the 9% -10% range. Holding companies with primarily regulated businesses also earned ROEs of around 9% -10%, while returns for holding companies with diversified operations, namely unregulated generation, have fallen from 11% (over the past seven year average) to around 9% today. Attachment BEL-2
Cost recovery wiU help offset falling RO Es Robust cost recovery mechanisms will help ensure that US regulated utilities' credit quality remains intact over the next few years. As a result, falling authorized ROEs are not a material credit driver at this time, but rather reflect regulators' struggle to justify the cost of capital gap between the industry's authorized RO Es and persistently low interest rates. We also see utilities struggling to defend this gap, while at the same time recovering the vast majority of their costs and investments through a variety of rate mechanisms.
In the table below, we show the US Treasury 10-year yield, which has steadily fallen from the 5% range in the summer of 2007 to the 2% range today. US utilities benefit from these lower interest rates because they borrow approximately $50 billion a year. For some utilities, a lower cost of debt translates directly into a higher return on equity, as long as their rate structure includes an embedded weighted average cost of capital (and the utilities can stay out of a general rate case proceeding).
Exhibit 1 Regulators hold up their end of the bargain by limiting reduction in return on equity (ROE) and overall rate of return (ROR) when compared with the decline in US Treasury 10-year yields
ROE --ROR 18 16 14
12
10
8
6
4
2
SOURCE: SNL Financial, LP, Moody's
This publication does not announce. a credit rating action. For any credit ratings referenced in this publication, please see the ratings tab on the issuer/entity page on \NVV\N.moodys.corn for the most updated credit rating action information and rating histo1y
z 10 MARCH 2015 US REGULATED UTILITIES: LOWER AUTHORIZED EQUITY RETURNS WILL NOT HURT NEAR-TERM CREDIT PROFILES Attachment BEL-2
As utilities increasingly secure more up-front assurance for cost recovery in their rate proceedings, we think regulators will increasingly view the sector as less risky. The combination of low capital costs, high equity market valuation multiples (which are better than or on par with the broader market despite the regulated utilities' low risk profile), and a transparent assurance of cost recovery tend to support the case for lower authorized returns, although because utilities will argue they should rise, or at least stay unchanged.
One of the arguments for keeping authorized RO Es steady is that lowering them would make utilities less attractive to providers of capital. Utility holding companies assert that they would rather invest in higher risk-adjusted opportunities than in a regulated utility with sub-par return prospects. We see a risk that this argument could lead to a more contentious regulatory environment, a material credit negative. We do not think this scenario will develop over the next few years.
Our default and recovery data provides strong evidence that regulated utilities are indeed less risky (from the perspective of a probability of default and expected loss given default, as defined by Moody's) than their non-financial corporate peers. On a global basis, we nonetheless see a material amount of capital looking for regulated utility investment opportunities, and the same is true in the US despite, despite a lower authorized return. This is partly because investors can use holding company leverage to increase their actual equity returns, by borrowing capital at today's low interest rates and investing in the equity of a regulated utility.
Despite the reduction in authorized ROEs, US utilities are thankful to their regulators for the robust suite of timely cost recovery mechanisms which allow them to recoup prudently incurred operating costs such as fuel, as well as some investment expenses. These recovery mechanisms drive a stable and transparent dividend policy, which translates into historically very high equity multiples. Moreover, cost recovery helps keep the sector's overall financial profile stable, thereby supporting strong investment-grade ratings.
Exhibit 2 With better recovery mechanisms, the ratio of debt-to-EBITDA can rise, modestly, without negatively impacting credit profiles
0g7 yr avg {2013 - 2007) · 5 yr avg {2013 - 2009) Iii! 3 yr avg {2013 - 2011) ,, 7 yr {2013) !'3 LTM September 2014 5.0
4.5
4.0
3.5
3.0
2.5
2.0 Diversified Holdco's Regulated Holdco's LDC's T&D's Vert. Integrated
SOURCE: Company filings; Moody's
3 10 MARCH 2015 US REGULATED UTILITIES: LOWER AUTHORiZED EQUITY RETURl,JS WILL NOT HURT NEAR-TERM CREDiT PROFILES Attachment BEL-2
• II. • ;,,a ;,,a I ~ ~ MOODY'S INVESTORS SERVICE INFRASTRUCTURE A''D PROIECT flNANCE
Exhibit 3 The ratio of Funds From Operations to debt is rising, a material credit positive, but the rise is partly funded by bonus depreciation and deferred taxes, which will eventually reverse
■ 7 yr avg (2013 - 2007) i~ 5 yr avg (2013 - 2009) ■ 3 yr avg (2013 - 2011) ■ 1 yr (2013) ■ LTM September 2014 28%
26%
24%
22%
20%
18%
16%
14%
12%
10% Diversified Holdco's Regulated Holdco's LDC's T&D's Vert. Integrated
SOURCE: Company filings; Moody's
Utilities' cash flow is somewhat insulated from declining RO Es Across all our utility group sub-sectors (see Appendix), net income - the numerator in the calculation of ROE - accounts for between 30% - 40% of cash flow. While net income is important, cash flow exerts a much greater influence over creditworthiness. This is primarily because cash flow takes into account depreciation and amortization expenses, along with other deferred tax adjustments. We note that deferred taxes have risen over the past few years, in part due to bonus depreciation elections, which will eventually reverse. From a credit perspective, there is a difference between the nominal amount of net income, which goes into cash flow, and the relationship of net income to book equity (a measure of profitability).
In the chart below, we highlight the ratio of net income to cash flow from operations (CFO) for our selected peer groups. Across all of the sectors, the longer term historical average of net income to CFO has fallen compared with the late 2000s, but has been rising over the more recent past. This is partly a function of deferred taxes, which have become a larger component of CFO over the past decade.
Exhibit 4 Net income as a % of cash flow from operations has been steadily rising (since 2011)
■ 7 yr avg (2013 - 2007) 1, 5 yr avg (2013 - 2009) ■ 3 yr avg (2013 - 2011) ■ 1 yr (2013) ■ LTM September 2014 50%
45%
40%
35%
30% •1,··1~ l~ i;,111;,,, 25% Diversified Holdco's Regulated Holdco's LDC's T&D's Vert. Integrated
SOURCE: Company filings, Moody's
4 10 MARCH 2015 US REGULATED UTILITIES: LOWER AUTHORIZED EQUITY RETURNS WILL NOT HURT NEAR-TERM CREDIT PROFILES Attachment BEL-2
We can also envisage scenarios where regulators seek to achieve a reduction in authorized ROEs without harming credit profiles by focusing on utilities' equity layer. In the chart below, we illustrate median equity as a percentage of total assets for our selected peer groups. In our illustration, utilities will benefit from acquisition related goodwill on one hand, and impairments on the other.
Exhibit 5 Equity as a % of total assets, not capitalization, includes both goodwill and impairments
ll! 7 yr avg {2013 - 2007) ·· 5 yr avg {2013 - 2009) !113 yr avg {2013 - 2011) "' 1 yr {2013} !1J LTM September 2014 36%
34%
32%
30%
26%
24%
22%
20% Diversified Holdco's Regulated Holdco's LDC's T&D's Vert. Integrated
SOURCE: Company filings; Moody's
Utilities' actual financial performance remains stable Earned ROE's, as reported by utilities and adjusted by Moody's, have been relatively flat over the past few years, despite the decline in authorized ROEs. This means utilities are closer to earning their authorized equity returns, which is positive from an equity market valuation perspective.
The authorized ROE is a popular focal point in many regulatory rate case proceedings. In addition, many regulatory jurisdictions look to established precedents that rely on various methodologies to determine an appropriate ROE, such as the capital asset pricing model or discounted cash flow analysis. In some jurisdictions where formulaic based rate structures point to lower RO Es for a longer projected period of time, regulators are incorporating a view that today's interest rate environment is "artificially" being held low.
Regardless, we think interest rates will go up, eventually. When they do, we also think authorized RO Es will trend up as well. However, just as authorized RO Es declined in a lagging fashion when compared to falling interest rates, we expect authorized RO Es to rise in a lagging fashion when interest rates rise.
Depending on alternative sources of risk-adjusted capital investment opportunities, this could spell trouble for utilities. For now, utilities can enjoy their (historically) high equity valuations, in terms of dividend yield and price-earnings ratios.
5 10 MARCH 2015 US REGULATED UTILITIES: LOWER AUTHORIZED EQUITY RETURNS WILL NOT HURT NEAR-TERM CREDIT PROFILES Attachment BEL-2
• It.: • ~ ~ I ~ ~ MOODY'S INVESTORS SERVICE INFRASTRUCTURE A",I[) PROIECT l'INANCE
Exhibit 6 GAAP adjusted earned ROE's are relatively flat across all sub-sectors except Holding Companies with Diversified Operations, while the lower-risk LDC sector is outperforming
■ 7 yr avg (2013 - 2007) l!l 5 yr avg {2013 - 2009) ■ 3 yr avg (2013 - 2011) ■ 1yr (2013) ■ LTM September 2014 11.5% 11.0% 10.5%
10.0% 9.5%
9.0% 8.5% 8.0%
7.5% 7.0% ' Diversified Holdco's Regulated Holdco's LDC's T&D's 1•Vert. Integrated NOTE: GAAP adjusted ROE, not regulated ROE, does not adjust for goodwill or impairments. Source: Company filings; Moody's
6 10 MARCH 2015 US REGULATED UTILITIES: LOWER AUTHORIZED EQUITY RETURNS WILL NOT HURT NEAR-TERM CREDIT PROFILES Attachment BEL-2 •Ii.•~~·~~ MOODY'S INVESTORS SERVICE INFRASTRUCTURE A'ID PR01ECT f!NANCE
Appendix
Exhibit? Utilities with the highest earned RO Es (ranked by 7-year average)
5-year 1-year 3-year average 7 -year average average average (2013 (2013 - (2013 - Company Name Sector Rating (2013) ROE -2011) ROE 2009) ROE 2007) ROE CenterPoint Energy Houston Electric, LLC T&D A3 33% 32% 25% 23% Questar Corporation Holdco - Primarily Regulated AZ 14% 18% 20% 20% AEP Texas Central Company T&D Baa1 14% Z8% ZZ% Z0% Exelon Corporation Holdco - Diversified BaaZ 7% 10% 14% 17% CenterPoint Energy, Inc. Holdco - Primarily Regulated Baa1 7% 16% 15% 17% Ohio Edisor, Company T&D Baa1 Z3% 18% 17% 16% Public Service Enterprise Group Holdco - Diversified BaaZ 11% 1Z% 14% 15% Dayton Power & Light Company T&D Baa3 7% 9% 13% 15% Dominion Resources Inc. Holdco - Diversified Baa2 13% 9% 1Z% 15% Southern California Gas Company LDC A1 14% 13% 14% 15% PECO Energy Company T&D AZ 1Z% 1Z% 1Z% 14% PPL Corporation Holdco - Diversified Baa3 9% 1Z% 11% 14% UGI Utilities, Inc. LDC AZ 15% 13% 13% 13% Entergy Corporation Holdco - Diversified Baa3 7% 11% 12% 13% Cleco Corporation Holdco - Primarily Regulated Baa1 10% 12% 13% 13% Alabama Gas Corporation LDC AZ 4% 11% 1Z% 13% Entergy New Orleans, Inc. Vertically Integrated Utility BaZ 5% 10% 11% 1Z% Entergy Gulf States Louisiana, LLC Vertically Integrated Utility Baa1 11% 13% 1Z% 1Z% Piedmont Natural Gas Company, Inc. LDC AZ 11% 11% 1Z% 1Z% Ohio Power Company T&D Baa1 ZS% 14% 13% 12% Southern Company (The) Holdco - Primarily Regulated Baa1 9% 11% 11% 1Z% Georgia Power Company Vertically Integrated Utility A3 1Z% 1Z% 1Z% 1Z% Alabama Power Company Vertically Integrated Utility A1 1Z% 1Z% 1Z% 1Z% Southern California Edison Company Vertically Integrated Utility AZ 8% 12% 1Z% 1Z% NextEra Energy, Inc. Holdco - Diversified Baa1 10% 11% 11% 1Z% Wisconsin Energy Corporation Holdco - Primarily Regulated AZ 13% 13% 1Z% 1Z% West Penn Power Company T&D Baa1 17% 13% 1Z% 1Z% San Diego Gas & Electric Company Vertically Integrated Utility A1 9% 10% 11% 1Z% Interstate Power and Light Company Vertically Integrated Utility A3 10% 9% 9% 1Z% NOTE: GAAP adjusted ROE, not regulated ROE, does not adjust for goodwill or impairments.
SOURCE: Moody's; company filings
7 10 MARCH 2015 US REGULATED UTILITIES: LOWER AUTHORIZED EQUITY RETURNS WILL NOT HURT NEAR-TERM CREDIT PROFILES Attachment BEL-2
Exhibit 8 Highest (over 30%) and lowest (less than 20%) equity level as a% of total assets (ranked by ?-year average) [NOTE: Book equity is not adjusted for goodwill or impairments] 1-year 5-year 7-year average 3~year average average average Company Name Sector Rating (2013) (2013 - 2011) (2013 - 2009) (2013 - 2007) Duke Energy Ohio, Inc. T&D Baal 48% 47% 48% 50% Yankee Gas Services Company LDC Baal 41% 4Z% 43% 43% Texas-New Mexico Power Company T&D Baal 43% 43% 43% 43% Oncor Electric Delivery Company LLC T&D Baal 40% 41% 41% 43% Dayton Power & Light Company T&D Baa3 37% 38% 39% 40% Pennsylvania Power Company T&D Baal ZS% 30% 34% 40% Black Hills Power, Inc. Vertically Integrated Utility A3 38% 38% 37% 38% ALLETE, Inc. Vertically Integrated Utility A3 38% 37% 37% 38% Central Maine Power Company T&D A3 39% 38% 38% 38% MGE Energy, Inc. Holdco - Primarily Regulated NR 39% 37% 38% 38% Duke Energy Corporation Holdco - Primarily Regulated A3 36% 36% 37% 38% Jersey Central Power & Light Company T&D BaaZ 3Z% 33% 36% 38% Oklahoma Gas & Electric Company Vertically Integrated Utility Al 36% 37% 37% 37% Public Service Company of Colorado Vertically Integrated Utility A3 37% 37% 37% 37% Virginia Electric and Power Company Vertically Integrated Utility AZ 37% 37% 37% 35% Wisconsin Public Service Corporation Vertically Integrated Utility Al 34% 34% 34% 35% PacifiCorp Vertically Integrated Utility A3 36% 35% 35% 35% UGI Utilities, Inc. LDC AZ 35% 34% 34% 34% Cleco Corporation Holdco - Primarily Regulated Baal 37% 36% 34% 34% Empire District Electric Company (The) Vertically Integrated Utility Baal 35% 34% 34% 34% Great Plains Energy Incorporated Holdco - Primarily Regulated BaaZ 35% 35% 34% 34% Nevada Power Company Vertically Integrated Utility Baal 3Z% 33% 33% 33% Tampa Electric Company Vertically Integrated Utility AZ 34% 33% 33% 33% Wisconsin Power and Light Company Vertically Integrated Utility Al 34% 33% 3Z% 33% Questar Corporation Holdco - Primarily Regulated AZ Z9% ZS% 31% 33% Duke Energy Kentucky, Inc. Vertically Integrated Utility Baal 31% 30% 33% 33% Florida Power & Light Company Vertically Integrated Utility Al 36% 35% 34% 33% Alabama Gas Corporation LDC AZ 59% 40% 35% 33% El Paso Electric Company Vertically Integrated Utility Baal 34% 3Z% 3Z% 33% IDACORP, Inc. Holdco - Primarily Regulated Baal 34% 33% 33% 33% PPL Electric Utilities Corporation Vertically Integrated Utility Baal 34% 34% 34% 33% Commonwealth Edison Company T&D Baal 31% 3Z% 3Z% 33% Georgia Power Company Vertically Integrated Utility A3 33% 33% 33% 33% CMS Energy Corporation Holdco - Primarily Regulated BaaZ Z0% 19% 18% 18% Hawaiian Electric Industries, Inc. Holdco - Diversified 17% 16% 16% 16% CenterPoint Energy, Inc. Holdco - Primarily Regulated Baal Z0% 19% 17% 15% CenterPoint Energy Houston Electric, LLCT&D A3 9% 15% 15% 15% AEP Texas Central Company T&D Baal 13% 15% 14% 13% SOURCE: Moody's; company filings
8 10 MARCH 2015 US REGULATED UTILITIES: LOWER AUTHORIZED EQUITY RETURNS WILL NOT HURT NEAR-TERM CREDIT PROFILES Attachment BEL-2
Exhibit 9 Highest (over 30%} and lowest (less than 15%} ratio of FFO to debt (ranked by 7-year average) 3-year 5-year 7-year 1-year average average average average (2013 (2013 - (2013 - Company Name Sector Rating (2013) - 2011) 2009) 2007) Dayton Power & Light Company T&D Baa3 32% 34% 42% 42% Questar Corporation Holdco - Primarily Regulated A2 29% 30% 31% 42% Pennsylvania Power Company T&D Baa1 30% 34% 32% 37% Exelon Corporation Holdco - Diversified Baa2 28% 34% 37% 37% Alabama Gas Corporation LDC A2 23% 27% 32% 36% Florida Power & Light Company Vertically Integrated Utility A1 34% 35% 35% 35% Southern California Gas Company LDC A1 42% 37% 35% 34% Southern California Edison Company Vertically Integrated Utility A2 32% 33% 35% 32% Madison Gas and Electric Company Vertically Integrated Utility A1 39% 35% 34% 31% PECO Energy Company T&D A2 29% 31% 33% 31% Dominion Resources Inc. Holdco - Diversified Baa2 16% 17% 16% 14% Entergy Texas, Inc. Vertically Integrated Utility Baa3 15% 14% 12% 14% Monongahela Power Company T&D Baa2 13% 16% 15% 14% CMS Energy Corporation Holdco - Primarily Regulated Baa2 18% 16% 15% 14% Appalachian Power Company Vertically Integrated Utility Baa1 15% 13% 14% 14% Pennsylvania Electric Company T&D Baa2 15% 14% 12% 13% NiSource Inc. Holdco - Diversified Baa2 15% 14% 14% 13% Puget Energy, Inc. Vertically Integrated Utility Baa3 14% 12% 12% 13% Toledo Edison Company T&D Baa3 10% 10% 8% 13% Cleveland Electric Illuminating Company T&D Baa3 11% 11% 12% 13% AEP Texas Central Company T&D Baa1 14% 15% 13% 12% SOURCE: /v/oody's; company filings
iO MARCH 2015 US REGULATED UTILITIES: LOVvER AUTHORIZED EQUITY RETURNS WILL NOT HURT NEAR-TERM CREDIT PROFILES Attachment BEL-2
Exhibit 10 Highest {over 4.Sx) and lowest {less than 3.0x) ratio of debt to EBITDA {ranked by 1-year average, 2013, to focus on more recent performance)
1-year 3-year 5-year 7-year average average average average Company Name Sector Rating (2013) (2013 - 2011) (2013 - 2009) (2013 - 2007) Berkshire Hathaway Energy Company Holdco - Diversified A3 7.1 5.8 5.6 5.3 FirstEnergy Corp. Holdco - Diversified Baa3 6.0 5.2 4.8 4.4 Wisconsin Electric Power Company Vertically Integrated Utility A1 5.9 6.1 5.6 5.0 Entergy Texas, Inc. Vertically Integrated Utility Baa3 5.8 6.1 6.2 6.1 Monongahela Power Company T&D Baa2 5.6 5.2 5.7 6.0 NiSource Inc. Holdco - Diversified Baa2 5.2 5.5 5.4 5.5 PPL Corporation Holdco - Diversified Baa3 5.1 4.9 5.1 4.6 Appalachian Power Company Vertically Integrated Utility Baa1 5.0 5.0 5.2 5.4 Progress Energy, Inc. Holdco - Primarily Regulated Baa1 4.9 5.6 5.1 4.9 Puget Energy, Inc. Vertically Integrated Utility Baa3 4.9 5.6 5.9 5.6 Cleveland Electric Illuminating Company T&D Baa3 4.9 5.2 4.7 4.2 Northwest Natural Gas Company LDC A3 4.8 4.8 4.5 4.2 Jersey Central Power & Light Company T&D BaaZ 4.7 5.5 4.2 3.6 NorthWestern Corporation Vertically Integrated Utility A3 4.7 4.5 4.4 4.3 Pepco Holdings, Inc. Holdco - Primarily Regulated Baa3 4.7 5.1 5.2 5.2 Laclede Gas Company LDC A3 4.7 5.5 5.3 5.6 Atlantic City Electric Company T&D Baa2 4.7 4.9 4.8 4.7 Nevada Power Company Vertically Integrated Utility Baa1 4.6 4.6 4.9 5.0 Black Hills Power, Inc. Vertically Integrated Utility A3 2.9 3.2 3.8 3.6 Virginia Electric and Power Company Vertically Integrated Utility A2 2.9 3.1 3.4 3.4 Duke Energy Kentucky, Inc. Vertically Integrated Utility Baa1 2.9 3.3 3.3 3.4 Texas-New Mexico Power Company T&D Baa1 2.9 2.9 3.2 3.3 Oklahoma Gas & Electric Company Vertically Integrated Utility A1 2.9 2.9 2.9 3.0 Cleco Power LLC Vertically Integrated Utility A3 2.9 3.2 3.6 3.7 Consumers Energy Company Vertically Integrated Utility A1 2.9 3.1 3.3 3.5 Alabama Power Company Vertically Integrated Utility A1 2.8 2.9 3.0 3.1 Public Service Electric and Gas Company T&D AZ 2.8 3.0 3.2 3.3 Alabama Gas Corporation LDC AZ 2.8 2.7 2.5 2.4 Pinnacle West Capital Corporation Holdco - Primarily Regulated Baa1 2.8 3.1 3.3 3.6 Cleco Corporation Holdco - Primarily Regulated Baa1 2.8 2.9 3.4 3.6 PECO Energy Company T&D AZ 2.8 3.0 2.6 2.6 Northern States Power Company (Wisconsin) Vertically Integrated Utility AZ 2.8 2.9 2.8 2.8 Duke Energy Carolinas, LLC Vertically Integrated Utility A1 2.8 3.1 3.2 3.1 UGI Utilities, Inc. LDC AZ 2.7 3.0 3.1 3.3 Exelon Corporation Holdco - Diversified Baa2 2.7 2.8 2.5 2.5 West Penn Power Company T&D Baa1 2.7 3.3 3.3 3.4 Questar Corporation Holdco - Primarily Regulated AZ 2.7 2.8 2.7 2.3 Tampa Electric Company Vertically Integrated Utility AZ 2.6 2.7 2.8 2.9 Arizona Public Service Company Vertically Integrated Utility A3 2.6 2.9 3.1 3.3 New York State Electric and Gas Corporation T&D A3 2.6 2.9 3.2 4.3 Dayton Power & Light Company T&D Baa3 2.5 2.2 2.0 1.9 Florida Power & Light Company Vertically Integrated Utility A1 2.4 2.7 2.6 2.6 Ohio Power Company T&D Baa1 2.4 2.8 3.1 3.3 Madison Gas and Electric Company Vertically Integrated Utility A1 2.4 2.8 2.8 2.9 Pennsylvania Power Company T&D Baa1 2.4 2.3 2.4 2.2 MGE Energy, Inc. Holdco - Primarily Regulated NR 2.3 2.7 2.9 3.1 Rochester Gas & Electric Corporation T&D Baa1 2.3 2.9 3.0 3.5 Public Service Enterprise Group Incorporated Holdco - Diversified Baa2 2.3 2.3 2.3 2.4 NSTAR Electric Company T&D AZ 2.2 2.6 2.7 2.8 Southern California Gas Company LDC A1 2.2 2.5 2.4 2.5 Mississippi Power Company Vertically Integrated Utility Baa1 (3.2) 3.5 3.4 3.1
10 10 MARCH 2015 US REGULATED UTILITIES: LO\VER AUTHORIZED EQUiTY RETURf~S WILL NOT HURT MEAR-TERM CREDIT PROFILES Attachment BEL-2
Exhibit 11 List of Companies {NOTE: in our appendix tables, we exclude utilities with private ratings) Company Name Sector Rating Berkshire Hathaway Energy Company Holdco - Diversified A3 Black Hills Corporation Holdco - Diversified Baa1 Dominion Resources Inc. Holdco - Diversified Baa2 DTE Energy Company Holdco - Diversified A3 Entergy Corporation Holdco - Diversified Baa3 Exelon Corporation Holdco - Diversified Baa2 FirstEnergy Corp. Holdco - Diversified Baa3 Hawaiian Electric Industries, Inc. Holdco - Diversified NR Integrys Energy Group, Inc. Holdco - Diversified A3 NextEra Energy, Inc. Holdco - Diversified Baa1 NiSource Inc. Holdco - Diversified Baa2 PPL Corporation Holdco - Diversified Baa3 Public Service Enterprise Group Incorporated Holdco - Diversified Baa2 Sempra Energy Holdco - Diversified Baa1
Alliant Energy Corporation Holdco - Primarily Regulated A3 Ameren Corporation Holdco - Primarily Regulated Baa2 American Electric Power Company, Inc. Holdco - Primarily Regulated Baa1 CenterPoint Energy, Inc. Holdco - Primarily Regulated Baa1 Cleco Corporation Holdco - Primarily Regulated Baa1 CMS Energy Corporation Holdco - Primarily Regulated Baa2 Consolidated Edison, Inc. Holdco - Primarily Regulated A3 Duke Energy Corporation Holdco - Primarily Regulated A3 Edison International Holdco - Primarily Regulated A3 Great Plains Energy Incorporated Holdco - Primarily Regulated Baa2 IDACORP, Inc. Holdco - Primarily Regulated Baa1 MGE Energy, Inc. Holdco - Primarily Regulated NR Northeast Utilities Holdco - Primarily Regulated Baa1 Pepco Holdings, Inc. Holdco - Primarily Regulated Baa3 PG&E Corporation Holdco - Primarily Regulated Baa1 Pinnacle West Capital Corporation Holdco - Primarily Regulated Baa1 PNM Resources, Inc. Holdco - Primarily Regulated Baa3 Progress Energy, Inc. Holdco - Primarily Regulated Baa1 Questar Corporation Holdco - Primarily Regulated AZ SCANA Corporation Holdco - Primarily Regulated Baa3 Southern Company (The) Holdco - Primarily Regulated Baa1 Wisconsin Energy Corporation Holdco - Primarily Regulated A2 Xcel Energy Inc. Holdco - Primarily Regulated A3
Alabama Gas Corporation LDC A2 Atmos Energy Corporation LDC AZ DTE Gas Company LDC Aa3 Laclede Gas Company LDC A3 New Jersey Natural Gas Company LDC Aa2 Northern Natural Gas Company [Private] LDC A2 Northwest Natural Gas Company LDC A3 Piedmont Natural Gas Company, Inc. LDC AZ South Jersey Gas Company LDC AZ Southern California Gas Company LDC A1 Southwest Gas Corporation LDC A3 UGI Utilities, Inc. LDC AZ Washington Gas Light Company LDC A1 Wisconsin Gas LLC [Private] LDC A1 Yankee Gas Services Company LDC Baa1
AEP Texas Central Company T&D Baa1 AEP Texas North Company T&D Baa1 Atlantic City Electric Company T&D Baa2
11 10 MARCH 2015 us REGULATED UTILITIES: LOWER AUTHORIZED EQUITY RETURNS WILL r,oT HURT NEAR-TERM CREDIT PROFILES Attachment BEL-2
Baltimore Gas and Electric Company T&D A3 CenterPoint Energy Houston Electric, LLC T&D A3 Central Hudson Gas & Electric Corporation T&D AZ Central Maine Power Company T&D A3 Cleveland Electric Illuminating Company (The) T&D Baa3 Commonwealth Edison Company T&D Baa1 Connecticut Light and Power Company T&D Baal Consolidated Edison Company of New York, Inc. T&D AZ Dayton Power & Light Company T&D Baa3 Delmarva Power & Light Company T&D Baa1 Duke Energy Ohio, Inc. T&D Baa1 Jersey Central Power & Light Company T&D BaaZ Metropolitan Edison Company T&D Baal Monongahela Power Company T&D BaaZ New York State Electric and Gas Corporation T&D A3 NSTAR Electric Company T&D AZ Ohio Edison Company T&D Baal Ohio Power Company T&D Baal Oncor Electric Delivery Company LLC T&D Baa1 Orange and Rockland Utilities, Inc. T&D A3 PECO Energy Company T&D AZ Pennsylvania Electric Company T&D BaaZ Pennsylvania Power Company T&D Baa1 Potomac Edison Company (The) T&D BaaZ Potomac Electric Power Company T&D Baal Public Service Electric and Gas Company T&D AZ Rochester Gas & Electric Corporation T&D Baal Texas-New Mexico Power Company T&D Baa1 Toledo Edison Company T&D Baa3 West Penn Power Company T&D Baal Western Massachusetts Electric Company T&D A3 Alabama Power Company Vertically Integrated Utility Al ALLETE, Inc. Vertically Integrated Utility A3 Appalachian Power Company Vertically Integrated Utility Baa1 Arizona Public Service Company Vertically Integrated Utility A3 Avista Corp. Vertically Integrated Utility Baa1 Black Hills Power, Inc. Vertically Integrated Utility A3 Cleco Power LLC Vertically Integrated Utility A3 Consumers Energy Company Vertically Integrated Utility Al DTE Electric Company Vertically Integrated Utility AZ Duke Energy Carolinas, LLC Vertically Integrated Utility A1 Duke Energy Florida, Inc. Vertically Integrated Utility A3 Duke Energy Kentucky, Inc. Vertically Integrated Utility Baa1 Duke Energy Progress, Inc. Vertically Integrated Utility Al El Paso Electric Company Vertically Integrated Utility Baa1. Empire District Electric Company (The) Vertically Integrated Utility Baa1 Entergy Arkansas, Inc. Vertically Integrated Utility BaaZ Entergy Gulf States Louisiana, LLC Vertically Integrated Utility Baal Entergy Louisiana, LLC Vertically Integrated Utility Baal Entergy Mississippi, Inc. Vertically Integrated Utility BaaZ Entergy New Orleans, Inc. Vertically Integrated Utility BaZ Entergy Texas, Inc. Vertically Integrated Utility Baa3 Florida Power & Light Company Vertically Integrated Utility Al Georgia Power Company Vertically Integrated Utility A3 Gulf Power Company Vertically Integrated Utility AZ Hawaiian Electric Company, Inc. Vertically Integrated Utility Baa1 Idaho Power Company Vertically Integrated Utility A3 Indiana Michigan Power Company Vertically Integrated Utility Baal Interstate Power and Light Company Vertically Integrated Utility A3 Kansas City Power & Light Company Vertically Integrated Utility Baal Kentucky Power Company Vertically Integrated Utility BaaZ
12 10 MARCH 2015 US REGULATED UTILITIES: LOWER AUTHORiZED EQUITY RETURNS WILL NOT HURT NEAR"TERM CREDIT PROFILES Attachment BEL-2
Madison Gas and Electric Company Vertically Integrated Utility A1 MidAmerican Energy Company Vertically Integrated Utility A1 Mississippi Power Company Vertically Integrated Utility Baa1 Nevada Power Company Vertically Integrated Utility Baa1 Northern States Power Company (Minnesota) Vertically Integrated Utility A2 Northern States Power Company (Wisconsin) Vertically Integrated Utility A2 NorthWestern Corporation Vertically Integrated Utility A3 Oklahoma Gas & Electric Company Vertically Integrated Utility A1 Pacific Gas & Electric Company Vertically Integrated Utility A3 PacifiCorp Vertically Integrated Utility A3 Portland General Electric Company Vertically Integrated Utility A3 PPL Electric Utilities Corporation Vertically Integrated Utility Baa1 Public Service Company of Colorado Vertically Integrated Utility A3 Public Service Company of New Hampshire Vertically Integrated Utility Baa1 Public Service Company of New Mexico Vertically Integrated Utility Baa2 Public Service Company of Oklahoma Vertically Integrated Utility A3 Puget Energy, Inc. Vertically Integrated Utility Baa3 Puget Sound Energy, Inc. Vertically Integrated Utility Baa1 San Diego Gas & Electric Company Vertically Integrated Utility A1 Sierra Pacific Power Company Vertically Integrated Utility Baa1 South Carolina Electric & Gas Company Vertically Integrated Utility Baa2 Southern California Edison Company Vertically Integrated Utility A2 Southwestern Electric Power Company Vertically Integrated Utility Baa2 Southwestern Public Service Company Vertically Integrated Utility Baa1 Tampa Electric Company Vertically Integrated Utility A2 Tucson Electric Power Company Vertically Integrated Utility Baa1 Union Electric Company Vertically Integrated Utility Baa1 Virginia Electric and Power Company Vertically Integrated Utility A2 Wisconsin Electric Power Company Vertically Integrated Utility A1 Wisconsin Power and Light Company Vertically Integrated Utility A1 Wisconsin Public Service Corporation Vertically Integrated Utility A1
13 10 MARCH 2015 US REGULATED UTILITIES: LOWER. AUTHORIZED EQU!TY RETURNS WILL HOT HURT NEAR-TERM CREDIT PROFILES Attachment BEL-2
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Services Ag€ncy and their r2gistr.ation numbers .:n-e FSA Cornrn!ssicner (Ratings) !\lo. 2 and 3 respectively. l'-'ij!.'..:l< or f'-1SFJ (as appUcable) hereby disclose that :nost issuers of d2bt s~curities (induding corporate and rn:.midpal bo11ds, deb<::nturcs, notes and comme-cia! paper) and p1eterred stock rated by f•0 1Jn~ or MSFJ (as apptic2bl2) have, prior to assignment of any rating, agreeci to pay to i"'1Jl<:X or {c1s applicable) for opprai:i3l and 1-atlng services rendered by it fees ranging from JPYZ00,000 to apprmdmatEly JPY350,C00,000. MJKI( and MSFJ also n1aintain policies and procedu(e::.: to address Japanese regulatory i'equi(emenls 14 10 M/\.RCH 2015 US REGULATED UTILITIES: LOWER AUTHORIZED EQUITY RETURNS WILL NOT HURT NEAR-TERM CRED!T PROFILES Attachment BEL-2 • it.: I ~ ~ I ~ ! MOODY'S INVESTORS SERVICE INFRASTRUCTURE ~N[) PROIECT flNANCE ANALYST CONTACTS NEW YORK 212-553-1653 Mihoko Manabe 212-553-1942 Senior Vice President [email protected] Michael Haggarty 212-553-7172 Associate /Vlanaging Director [email protected] William L. Hess 212-553-3837 /Vlanaging Director - Utilities [email protected] Mooov's INVESTORS SERVICE 15 10 MARCH 2015 US REGULATED UTILITIES: LOWER AUTHORIZED EQUITY RETURNS WILL NOT HURT NEAR-TERM CREDIT PROFILES Attachment BEL-3 Cause No. 44988 Page 1 of24 DUFF&PHELPS Client Alert: January 12, 2017 Executive Summary The Equity Risk Premium (ERP) changes over time. Fluctuations in global economic and financial conditions warrant periodic reassessments of the selected ERP and accompanying risk-free rate. Based on current market conditions, Duff & Phelps is reaffirming its U.S. Equity Risk Premium recommendation of 5.5% to be used in conjunction with a normalized risk-free rate. However, based on declining real interest rates and long-term growth estimates for the U.S. economy, we are lowering the U.S. normalized risk-free rate from 4.0% to 3.5%, when developing discount rates as of November 15, 2016 and thereafter, until further guidance is issued. In summary: Equity Risk Premium: Reaffirmed at 5.5% Risk-Free Rate: Decreased from 4.0% to 3.5% (normalized) Base U.S. Cost of Equity Capital: 9.0% (5.5% + 3.5%) Background The Equity Risk Premium (ERP) is a key input used to calculate the cost of capital within the context of the Capital Asset Pricing Model (CAPM) and other models for developing discount rates to be used in discounting expected net cash flows. Duff & Phelps regularly reviews fluctuations in global economic and financial market conditions that warrant a periodic reassessment of the ERP.1 Based on current market conditions, we are reaffirming the recommended U.S. ERP of 5.5%, which was previously established as of January 31, 2016 and thereafter. We will maintain our recommendation to use a 5.5% U.S. ERP when developing discount rates until there is evidence indicating equity risk in financial markets has materially changed. We are closely monitoring the aftermath of the U.S. presidential election held on November 8, 2016 and its impact on cost of capital assumptions. The current ERP recommendation was developed in conjunction with a "normalized" 20-year yield on U.S. government bonds as a proxy for the risk-free rate (R1 ). Based on recent academic literature and market evidence of a secular decrease in real interest rates (a.k.a. the "rental" rate) and lower long-term real GDP growth estimates for the U.S. economy, we lowered our concluded normalized risk-free rate from 4.0% to 3.5% for valuation dates as of November 15, 2016 and thereafter. Duff & Phelps Attachment BEL-3 Cause No. 44988 Client Alert: Duff & Phelps U.S. Normalized Risk-Free Rate Decreased from 4.0% to 3.5% Page 2 of24 Methods of Estirnating a Estimating a normalized risk-free rate can be accomplished in a number of ways, including (i) simple averaging, and (ii) various "build-up" methods. Normalized Risk-Free Rate The first method of estimating a normalized risk-free rate entails calculating averages of yields to maturity on long-term government securities over various periods. This method's implied assumption is that government bond yields revert to the mean. For example, as of October 31, 2016, the trailing 10-year average for the yield on 20-year U.S. Treasury bonds was 3.5%. In contrast, the corresponding spot yield on October 31, 2016 was 2.3%. Taking the average over the last 10 years is a simple way of "normalizing" the risk-free rate. An issue with using historical averages, though, is selecting an appropriate comparison period that can be used as a reasonable proxy for the future. The second method of estimating a normalized risk-free rate entails using a simple build-up method, where the components of the risk-free rate are estimated and then added together. Conceptually, the risk-free rate can be (loosely) illustrated as the return on the following two components::' Risk-Free Rate Real Rate + Expected Inflation In Exhibit 1, we summarize long-term real rate estimates and inflation expectations for the United States at the end of October 2016, based on data assembled from a variety of sources. We also display the spot 20-year U.S. Treasury yield and its long-term (10-year) trailing average as of October 31, 2016. Exhibit i: Estimated Long-term Real Risk-Free Rate 0.0%to 2.0% Expected Long-term Inflation 1.70/oto 2.4% ------~-·------·--- Range of Normalized Risk-Free Rates 1.7% to 4.4% Midpoint 3.1% 20-Year U.S. Government Securities -Spot Rate 2.3% -Long-Term (10-year) Trailing Average Yield 3.5% Concluded Normalized Risk-Free Rate 3.5% Duff & Phelps 2 Attachment BEL-3 Cause No. 44988 Client Alert: Duff & Phelps U.S. Normalized Risk-Free Rate Decreased from 4.0% to 3.5% Page 3 of24 The long-term real rate estimate of 0.0% to 2.0% represents a lower range relative to prior Duff & Phelps analyses. Recently, research in this area has been very active. Academic researchers and economic analysts have proposed a number of explanations for the secular (i.e., not cyclical or temporary) decline in global real interest rates, which they argue precedes the onset of the 2008 global financial crisis. The following are some of the most-often-cited factors:' Lower global long-run output and productivity growth Shifting demographics (aging population leading to slower labor force expansion) have rJ.ocumontod a trend Global "savings glut" Safe asset shortage (increased demand for safe-haven assets, accompanied by a declining supply) With regards to long-te1·m inflation expectations, the same declining trend has been taking hold in the United States and across several other developed markets over the last few years. Inflation has been persistently below the 2.0% target set by major central banks, such as the Federal Reserve Bank (Fed), the European Central Bank, the Bank of England, and the Bank of Japan. The sharp decline in oil prices from mid-2014 until early 2016 has put additional pressure on an already very low inflation environment. However, the results of the U.S. presidential election seem to have spurred higher inflation expectations for global investors. Long-term government bond yields rose sharply in (for example) the United States, United Kingdom, and Germany in the short period between the election day and the date of writing this alert. This is the opposite of what happened following the June 23, 2016 vote by the U.K. electorate to leave the European Union (known in the financial press as "Brexit"). We will continue to monitor the aftermath of the U.S. presidential election and its potential impact on inflation expectations and consequent effects on the normalized long-te1·m risk-free rate. A long-term "normalized" risk-free rate attempts to capture the sustainable average return of long Can the t\iormalized term bonds issued by a government considered "safe" or free of default risk (e.g., U.S. Treasuries).··, Risk-Free Rate Decline However, the use of a normalized risk-free rate during certain periods does not preclude "spot" rates from fluctuating during these periods. While the Spot Yield is lncreasina? Exhibit 2 is a graphical illustration of both the daily "spot" long-term U.S. risk-free rate (using 20- '-' year U.S. Treasury yields), and the Duff & Phelps recommended "normalized" long-term U.S. risk free rate from January 1, 2008 through November 15, 2016. The red line in Exhibit 2 is the Duff & Phelps suggested risk-free rate, which has been the "spot" rate during certain periods (the red, spiky areas in the graph) and has been a "normalized" rate during certain periods (the areas in the graph that are red, straight, horizontal lines). The blue lines in Exhibit 2 represent the "spot" rate (during times that Duff & Phelps suggested using a normalized rate). Duff & Phelps 3 Attachment BEL-3 Cause No. 44988 Client Alert: Duff & Phelps U.S. Normalized Risk-Free Rate Decreased from 4.0% to 3.5% Page 4 of24 Exhibit 2: (i) Duff & Phelps Recommended U.S. Long-term Risk-Free Rate (both "spot" and "normalized"), and (ii) Spot 20-Year U.S. Treasury Yield During Normalization Periods9 January 1, 2008-November 15, 2016 Normalization Period A 4.5% "Old Normal 1" Normalization Normalization 6.0 (11-1-08 to 5-31-09) Period B Period D 4.0% "Old Normal 2" 4.0% "Old Normal 2" Normalization (6-1-10 to 11-30-10) (7-1-11 to 11-14-16) Period E 5.0 l 3.5% "New Normal" l (11-15-16 until further notice) ,...__ 4.0 e,,~ l gi 'lil O::'. 3.0 Q) ~ Duff &Phelps continues -"' to closely monitor rates "' a:: 2.0 Normali:zation PeriodC 4.0% "Old Normal 2" 1.0 (5-1-11 to 5-31-11) --Duff & Phelps R10/o (either "spot" or "normalized") --Spot R, 0/o 0.0 (X) (X) (X) (X) Cl) Cl) Cl) Cl) 0 0 0 0 CN CN CN CN (I') (I') (I') (I') -st -st -st -st LO LO LO LO co co co co co 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 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 C'I CN CN CN CN CN CN CN CN CN CN CN CN CN CN CN CN C'I CN CN C'I CN CN CN CN CN CN CN C'I CN CN CN CN CN CN CN CN I ...L I ...L I I I I I I I I I I C L L C L L C L L C L ..!.. L C L ..!. C L ...L L C L ..!.. L C L ...L L C L ..!.. L LO cu 0. ::, (.) 0. ::, (.) cu 0. :5 (.) 0. ::, (.) 0..::, t, cu 0. ::, (.) cu 0. ::, (.) cu 0.. ::, (.) cu 0..::, (.) -, <( ...., 0 .!!l <( ...., 0 -, <( ...., 0 .!!l <( ...., 0 .!!l <( ...., 0 -, <( -, 0 ...., <( ...., 0 -, <( ...., 0 -, <( ...., 0 Ei z During periods that Duff & Phelps suggested using a normalized rate (the areas in the graph that are red, straight, horizontal lines), the spot rate (the blue lines) still fluctuated, at times significantly.10 Spot rates will almost undoubtedly fluctuate during the current period as well, just as they have fluctuated in all previous periods of normalization. This fluctuation in itself does not alter our recommendation based on economic fundamentals. Duff & Phelps will continue to monitor risk-free rates and other cost of capital inputs very closely. If and when (i) long-term spot yields increase to a level that approaches the Duff & Phelps recommended U.S. normalized risk-free rate (e.g., differences are lower than 50 b.p.), and (ii) there is evidence that this increase in spot yields is not transitory, we will then consider recommending a return to using the spot rate as the basis for the risk-free rate to be used in conjunction with our recommended U.S. ERP. Duff & Phelps 4 Attachment BEL-3 Cause No. 44988 Client Alert: Duff & Phelps U.S. Normalized Risk-Free Rate Decreased from 4.0% to 3.5% Page 5 of24 Duff & Phelps' U.S. Duff & Phelps last changed its U.S. ERP recommendation on January 31, 2016. On that date, our ERP recommendation was increased to 5.5% (from 5.0%) in response to evidence that suggested Equity Risk Premium a heightened level of risk in financial markets and deteriorating economic conditions. Recommendation and Duff & Phelps monitors various economic and financial market indicators, as well as two quantitative "Base" Cost of Equity models as corroboration to arrive at its U.S. ERP recommendation. While the current evidence seems to be pointing to a decline in equity risk in financial markets relative to January 31, 2016, from a qualitative perspective we deem it prudent to let some time elapse, in order to better assess the impact of the U.S. presidential election's results on the forward-looking ERP. We took a similar "wait-and-see" approach when evaluating the impact of Brexit on cost of capital assumptions. Accordingly, Duff & Phelps is reaffirming the recommended U.S. ERP of 5.5%, to be used in conjunction with a normalized risk-free rate of 3.5%, when developing discount rates as of November 15, 2016 and thereafter. The combination of the new normalized risk-free rate (3.5%) and the reaffirmed U.S. recommended ERP (5.5%) results in an implied U.S. "base" cost of equity capital estimate of g,0% (3.5% + 5.5%). Were we to use the spot yield-to-maturity on 20-year U.S. Treasuries of 2.6% as of November 15, 2016, one would have to increase the ERP assumption accordingly. One can determine the ERP against the spot 20-year yield as of November 15, 2016, inferred by Duff & Phelps' recommended U.S. ERP (used in conjunction with the normalized risk free rate), by using the following formula: == D&P Recommended U.S. ERP + Normalized Risk-Free Rate - Spot 20-Year U.S. Treasury Yield = 5.5% + 3.5% - 2.6% = 6.4% Endnotes For a discussion of some of the studies and factors we evaluate, refer to Chapter 3 of the Duff & Phelps 2016 Valuation Handbook - Guide to Cost of Capital or to Duff & Phelps' Client Alert entitled "Duff & Phelps Increases U.S. Equity Risk Premium Recommendation to 5.5%, Effective January 31, 2016". To obtain a free copy of this Client Alert, visit For a more detailed discussion on reasons for normalization and methods that can be used to normalize risk-free rates, refer to Chapter 3 of the Duff & Phelps 2016 Valuation Handbook - Guide to Cost of Capital. This is a simplified version of the "Fisher equation", named after Irving Fisher. Fisher's "The Theory ot Interest" was first published by Macmillan (New York), in 1930. Sources of real rates: Haubrich, Joseph, George Pennacchi, and Peter Ritchken, "Inflation Expectations, Real Rates, and Risk Premia: Evidence from Inflation Swaps," Review of Financial Studies Vol. 25 (5) (2012): 1588-1629; Andrew Ang and Geer! Bekaert "The Term Structure of Real Rates and Expected Inflation," The Journal of Finance, Vol. LXIII (2) (April 2008); Olesya V Grishchenko and Jing-zhi Huang "Inflation Risk Premium: Evidence From the TIPS Market," The Journal of Fixed Income, Vol. 22 (4) (2013); Pescatori, Andrea and Jarkko Turunen, "Lower for Longer: Neutral Rates in the United States", IMF Working Paper No, 15/135 (June 2015); Kiley, Michael T., 'What Can the Data Tell Us About the Equilibrium Real Interest Rate?", Finance and Economics Discussion Series 2015-077. Washington: Board of Governors of the Federal Reserve System (August 2015); Lubik, Thomas A. and Christian Matthes "Calculating the Natural Rate of Interest: A Comparison ofTwo Alternative Approaches", Richmond Fed Economic Brief (October 2015); Reza, Abeer and Subrata Sarker, "Is Slower Growth The New Normal In Advanced Economies?", Bank Of Canada Review (Autumn 2015): Hamilton, James, Ethan Harris, Jan Hatzius, and Kenneth West, "The Equilibrium Real Funds Rate: Past, Present and Future", working paper (May 2016); Holston, Kathryn, Thomas Laubach, and John C. Williams, "Measuring the Natural Rate of Interest: International Trends and Determinants", Federal Reserve Bank of San Francisco Working Paper 2016-11 (August 2016); Lansing, Kevin J,, "Projecting the Long-Run Natural Rate of Interest", FRBSF Economic Letter 2016-25 (August 2016), Sources at long-term inflation expectations: The Livingston Survey, dated June 8, 2016; Survey of Professional Forecasters, Third Quarter 2016; (August 12, 2016) Cleveland Federal Reserve's Inflation Expectations, released October 18, 2016; Blue Chip Financial Forecasts dated June 1, 2016 and November 1, 2016; Blue Chip Economic Indicators, dated October 10, 2016; Philadelphia Federal Reserve, Aruoba Term Structure of Inflation, October 2016; the University of Michigan Inflation Expectations, October 2016. For a more detailed discussion of some of these and other factors, see, for example, Rachel, Lukasz and Thomas D Smith "Secular drivers of the global real interest rate", Bank of England Staff Working Paper No. 571, December 2015. Also, consider reviewing Chapter 3 of the Duff & Phelps 2016 Valuation Handbook - Guide to Cost of Capital (Hoboken, NJ: John Wiley & Sons, 2016). Beginning with the global financial crisis of 2008 (the "Financial Crisis"), analysts have had to reexamine whether the "spot" rate is still a reliable building block upon which lo base their cost of equity capital estimates. The Financial Crisis challenged long-accepted practices and highlighted potential problems of simply continuing to use the spot yield-to-maturity on a safe government security as the risk-free rate, together with historical equity risk premiums, without any further adjustments. The general framework for the normalization argument could be described as follows: (i) that the extremely-low rates we have experienced in recent years would not exist without the market intervention by "non-market" participants (i.e., central banks) pushing rates down "artificially", (ii) that these abnormally-low rates are not sustainable in the long-term, and (iii) that rates \end to revert to a mean that reflects the long-term relationship between nominal and real interest rates. Source of government bond yields used herein is the Board of Governors of the Federal Reserve System website at: For a complete table with Duff & Phelps recommended ERP and corresponding recommended risk-free rate since Duff & Phelps 5 Attachment BEL-3 Cause No. 44988 Page 6 of24 DUFF&PHELPS Authors Roger J. Grabowski, FASA Managing Director [email protected] Carla S. Nunes, CFA Managing Director [email protected] James P. Harrington Director [email protected] Contributors Kevin Madden Analyst [email protected] Aaron Russo Analyst [email protected] For more information please visit: www.duffandphelps.com/costofcapital About Duff & Phelps Duff & Phelps is the premier global valuation and corporate finance advisor with expertise in complex valuation, disputes and investigations, M&A, real estate, restructuring, and compliance and regulatory consulting. The firm's more than 2,000 employees serve a diverse range of clients from offices around the world. For more information, visit www.duffandphelps.com. M&A advisory, capital raising and secondary market advisory services in the United States are provided by Duff & Phelps Securities, LLC. Member FINRAISIPC. Pagemi/1 Partners is a Division of Duff & Phelps Securities, LLC. M&A advisory and capital raising advisory services are provided in a number of European countries through Duff & Phelps Securities Ltd, UK, which includes branches in Ireland and Germany. Duff & Phelps Securities Ltd, UK, is regulated by the Financial Conduct Authority. Duff & Phelps Copyright © 2017 Duff & Phelps LLC. All rights reserved. Attachment BEL-3 Cause No. 44988 DUFF SPif~LPS Executive Summary The Equity Risk Premium ("ERP") changes over time. Fluctuations in global economic and financial conditions warrant periodic reassessments of the selected ERP and accompanying risk-free rate. Based upon current market conditions, Duff & Phelps is decreasing its U.S. Equity Risk Premium recommendation from 5.5% to 5.0%. The 5.0% ERP guidance is to be used in conjunction with a normalized risk-free rate of 3.5% when developing discount rates as of September 5, 2017 and thereafter, until further guidance is issued. In summary: Equity Risk Premium: Decreased from 5.5% to 5.0% Risk-Free Rate: Reaffirmed at 3.5% (normalized) Base U.S. Cost of Equity Capital: 8.5% (5.0% + 3.5%) Background The ERP is a key input used to calculate the cost of capital within the context of the Capital Asset Pricing Model ("CAPM") and other models. Duff & Phelps regularly reviews fluctuations in global economic and financial market conditions that warrant a periodic reassessment of the ERP.1 Based on current market conditions, we are decreasing the recommended U.S. ERP from 5.5% to 5.0% when developing discount rates as of September 5, 2017 and thereafter, until there is evidence indicating equity risk in financial markets has materially changed and new guidance is issued. Duff & Phelps last changed its U.S. ERP recommendation on January 31, 2016.2 On that date, our recommendation was increased to 5.5% (from 5.0%) in response to evidence in late 2015 and early 2016 that suggested an increased level of risk in financial markets. Later in the year, on November 15, 2016, Duff & Phelps reaffirmed its U.S. ERP recommendation of 5.5%, but lowered the accompanying normalized risk-free rate from 4.0% to 3.5%, supported by academic evidence of declining real interest rates and long-term growth potential for the U.S. economy.3 Attachment BEL-3 & Client Alert - Duff & Phelps' U.S. Equity Risk Premium Recommendation Decreased from 5.5% to 5.0%, Effective Se~ NO.Cl4il988 Page 8 of24 Towards the end of 2016 - particularly after the surprising win of the U.S. presidential elections by Mr. Trump - and the beginning of 2017, we saw some indications that equity risk in financial markets was declining. However, at that time, several economists and market analysts were questioning the record highs in stock markets and the extremely low levels of volatility, given the potential global turmoil that could be generated in 2017 by a variety of events and risk factors. Notably, uncertainty surrounding the new U.S. Administration's policies and global geopolitical risks associated with a rising populism and anti-globalization sentiment were reasons for concern, which could be exacerbated by the scheduled presidential and parliamentary elections in major countries in Europe (e.g., Netherlands, France, Germany) and other parts of the world, as well as the predicted official triggering of Brexit by the United Kingdom.4 From a qualitative perspective, we deemed it prudent to adopt a "wait-and-see" approach to better assess the impact of the U.S. presidential election results and other geopolitical events in on our estimate of the forward-looking ERP. As such, on December 31, 2016 we reaffirmed the Duff & Phelps U.S. ERP recommendation of 5.5%.5 We are now revisiting our recommendation based on recent trends in economic indicators and financial market conditions. Overview of the A Two-Dimensional Process There is no single universally accepted methodology for estimating the ERP; consequently, Duff & Phelps' there is wide diversity in practice among academics and financial advisors regarding ERP ERP Methodology estimates. For this reason, Duff & Phelps employs a two-dimensional process that considers a broad range of economic information and multiple ERP estimation methodologies to arrive at its recommendation. First, a reasonable range of normal or unconditional ERP is established. Second, based on current economic conditions, we estimate where in the range the true ERP likely lies (top, bottom, or middle). Long-term research indicates that the ERP is cyclical.6 We use the term normal, or unconditional ERP to mean the long-term average ERP without regard to current market conditions. This concept differs from the conditional ERP, which reflects current economic conditions.7 The "unconditional" ERP range versus a "conditional" ERP is further distinguished as follows: "What is the range?" Unconditional ERP Range - The objective is to establish a reasonable range for a normal or unconditional ERP that can be expected over an entire business cycle. Based on an analysis of academic and financial literature and various empirical studies, we have concluded that a reasonable long-term estimate of the normal or unconditional ERP for the U.S. is in the range of 3.5% to 6.00/o. 8 "Where are we in the range?" Conditional ERP - The objective is to determine where within the unconditional ERP range the conditional ERP should be, based on current economic conditions. Research has shown that ERP fluctuates during the business cycle. When the economy is near (or in) a recession, the conditional ERP is at the higher end of the normal, or unconditional ERP range. As the economy improves, the conditional ERP moves back toward the middle of the range and at the peak of an economic expansion, the conditional ERP approaches the lower end of the range. Duff & Phelps ■ Attachment BEL-3 & Client Alert - Duff & Phelps' U.S. Equity Risk Premium Recommendation Decreased from 5.5% to 5.0%, Effective Se~ N&.041988 Page 9 of24 Basis for Estimating the Conditional Equity Risk Premium In estimating the conditional ERP, valuation analysts cannot simply use the long-term historical U.S. Equity Risk Premium ERP without further analysis. There is ample academic evidence that equity risk premia are as of September 5 1 2017 not constant over time. Professor John Cochrane (senior fellow at the Hoover Institution at Stanford University) has summarized the changes in our knowledge of estimating rates of return for equity over the last 40 years, while emphasizing the need to adjust our valuation procedures and methodologies accordingly: 9 "Discount rates vary a lot more than we thought. Most of the puzzles and anomalies that we face amount to discount-rate variation we do not understand. Our theoretical controversies are about how discount rates are formed. We need to recognize and incorporate discount-rate variation in applied procedures." Duff & Phelps goes beyond historical measures of ERP by examining approaches that are sensitive to the current economic and financial market conditions. In Exhibit 1, we list the primary factors considered when arriving at the Duff & Phelps recommended U.S. ERP: we document the evolution of these factors from January 31, 2016 - the last time we changed our recommendation - through July 31, 2017, along with the corresponding relative impact on ERP indications.10 Exhibit 1: Factors Considered in the U.S. ERP Recommendation: Reiative Change from January 2016 to July 2017 Factor Change Effect on ERP U.S. Equity Markets Implied Equity Volatility Corporate Spreads Economic Policy Uncertainty (EPU) and Equity Uncertainty Indices Historical Real GDP Growth and Forecasts Unemployment Environment Consumer and Business Sentiment Sovereign Credit Ratings Damodaran Implied ERP Model Default Spread Model A high-level review of the same factors in August 2017 does not change materially the picture depicted above, other than an improvement in U.S. real gross domestic product ("GDP") growth (with a significant upward revision in second quarter's real growth), corroborating the view that system-wide risks have declined since January 2016, Current Economic Conditions Macroeconomic conditions provide the foundation for financial market performance, with economic growth influencing the level of interest rates, inflation, corporate earnings, and other factors that impact financial asset returns. More than eight years have elapsed since the U.S. economy began its recovery from the global financial crisis of 2008 (the "Financial Crisis"). The 2008-2009 U.S. recession was declared officially over in June 2009, and was of greater duration than those of 1973-1975 and 1981-1982. The current business cycle expansion is now the third longest in U.S. history.11 However, the recent recovery has fallen short of the rebound observed in other Duff & Phelps Attachment BEL-3 & Client Alert - Duff & Phelps' U.S. Equity Risk Premium Recommendation Decreased from 5.5% to 5.0%, Effective Se~ ~~1988 Page 10 of24 post-World War II recessions. Real GDP growth in the year following the recessions of 1957-1958, 1973-1975, and 1981-1982 was on average 5.6%.12 In contrast, real GDP expanded by 2.5% during 2010 and by an average of 2.1% over the 2010-2016 period (see Exhibit 2). Exhibit 2: U.S. Real Gross Domestic Product (GDP) Growth: 2007-2017 2007 2008 2009 2010 2011 2012 2013 2014 2015 2016 2017 (•) 2.9% 2010-2016 Average= 2.1% -2.8% Source of underlying data: Historical data: U.S. Bureau of Economic Analysis. Forecast data based on average from the following: The Livingston Survey, June 16, 2017; Survey of Professional Forecasters, Second Quarter 20i 7, May 12, 2017; Blue Chip Financial Forecasts, August 1, 2017; Blue Chip Economic Indicators, July 10, 2017: Consensus Forecasts USA, July 2017; Bloomberg's Contributor Composite estimates, dated August 11, 2017. For the last several years, the U.S. and the broader global economy have been oscillating between periods of strong and accelerating growth and periods when growth is either stagnating or weakening to positive but lackluster pace. At the beginning of 2016, less than two years ago, the world economy faced faltering growth and financial market turbulence. Fast forward to mid-2017, and the picture that emerges is very different: the world economy is finally experiencing some growth momentum, with real GDP accelerating in U.S., Europe (except for the U.K.), Japan, and China. After a disappointing first quarter, the U.S. economy expanded in the second quarter of 2017 at its most robust pace since early 2015, supported by solid consumer spending and a pickup in business investment.13 Consumer confidence and business sentiment have improved markedly, with the former well above its long-term average.14 The employment situation has also improved, with the unemployment rate gradually declining since the beginning of 2016 and the U.S. economy moving close to full employment. However, the U.S. labor force participation is hovering around its lowest level since the late 1970s and wages do not appear to be rising materially, especially given that the unemployment rate is near a 16-year low. Furthermore, the initial upward pressure on inflation observed in the latter half of 2016 due to rising oil prices (from a 12-year low reached back in January 2016) seems to have subsided: consumer price inflation measures remain stubbornly below the U.S. central bank's (the Federal Reserve, or the "Fed") target of 2.0%.15 Finally, it is noted that in the near-term, U.S. economic indicators may temporarily reflect the negative impact of Hurricanes Harvey and Irma, which caused severe damage in Texas and Florida, respectively. Thus far, the global economic recovery has been supported by unprecedented monetary policies introduced after the Financial Crisis began. Since the onset of the crisis, the Fed and other major central banks - including the European Central Bank ("ECB"), the Bank of England ("BOE"), and the Bank of Japan ("BOJ") - have (i) lowered their benchmark interest rates near or below 0.0% (zero); and (ii) implemented several rounds of unconventional quantitative easing ("OE") measures. Duff & Phelps ■ Attachment BEL-3 & Client Alert - Duff & Phelps' U.S. Equity Risk Premium Recommendation Decreased from 5.5% to 5.0%, Effective Se~ ~o'.041988 Page 11 of24 Exhibit 3: Yields on 10-year Government Bonds Issued by the U.S., U.K., Germany, and Japan December 2007-July 2017 6.0% United States Treasury Constant Maturity - 10 Year United Kingdom Government Debt - 1 0 Year 5.0% Germany Government Debt - 1 0 Year Japan Goverment Debt - 10 Year 4.0% 3.0% 2.30% 2.0% 1.28% 1.0% • 0.45% 0.0% 0.08% -1.0%'------~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ 0 ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~###~###~###✓###~###~###~###✓###~###~### $0urc8 of underlying dat2: Car,,//a/ 10 The resulting sizable increases in these central banks' balance sheets (largely due to holdings of long-term governments securities considered "safe" by investors), along with various flight-to quality episodes, have continued to exert a downward pressure on global long-term interest rates (see Exhibit 3). 16 In a recently-released academic study (June 2017), the authors showed empirical evidence suggesting that the composition of the Fed's balance sheet can significantly affect prices of U.S. Treasury securities (and therefore their yields), as well as the term structure of interest rates; this is contrary to most theoretical literature, which would suggest that the ability of the Fed to have an impact on long term interest rates is limited." In a separate academic study, released in April 2017, the authors estimated that (at that time) the cumulative effect of the Fed's OE programs resulted in a reduction in the 10-year U.S. Treasury yield term premium of about 100 basis points ("b.p."). For practical purposes, this is what this estimate would translate into: in absence of OE actions by the Fed, the 10-year yield of 2.3% as of July 31, 2017 (see Exhibit 3) would likely have been around 3.3% instead.' 8 The Fed kept a zero-interest-rate policy (dubbed "ZIRP" in the financial press) for seven years, from December 2008 until December 2015. After a 10-year period with only one interest rate hike (in December 2015), the Fed finally embarked on a path of monetary policy normalization: the Fed raised the target range for its benchmark rate (the Federal Funds Rate) three times in six months, a 25 b.p. rise at each of its December 2016, March 2017, and June 2017 meetings. Another 25 b.p. rate rise is expected at the Fed's December meeting, with further hikes projected for 2018.19 In addition, in the June 2017 meeting, the Fed revealed some details on its strategy to reduce its $4.5 trillion balance sheet, corroborated at its July meeting - this slow and lengthy unwinding process is slotted to begin in October 2017. 20 The Fed has cited improvements in economic activity, labor market conditions, and a gradual Duff & Phelps Attachment BEL-3 Client Alert - Duff & Phelps' U.S. Equity Risk Premium Recommendation Decreased from 5.5% to 5.0%, Effective Se~ N~04lJ988 Page 12 of24 increase in inflation measures towards its target, as support for the rate increases and OE unwinding (or "OExit", as labeled in some of the financial press). Nevertheless, the current range of 1.00% to 1.25% for the Fed's benchmark rate is well below historical levels, and is still providing a significant stimulus to the economy. Likewise, the outlined plan for OE unwinding means that only a small fraction of the Fed's large asset holdings will be coming off its balance sheet at a time, thereby contributing to only gradual increases in interest rates. As a starting point, the Fed plans to let an approximately combined $1 O billion in U.S. Treasuries, agency debt, and agency mortgage-backed securities expire on a monthly basis. Over time, these amounts will gradually increase to levels up to $50 billion per month. The Fed will continue its policy of reinvesting the principal of its other maturing assets."' For perspective, even a $50 billion monthly amount of expiring securities represents just slightly-above 1% of the Fed's current balance sheet (or $600 billion, around 13%, on an annual basis). This may partially help explain why U.S. government bond yields continue to be so low, despite the latest decisions by the Fed regarding monetary policy tightening. Other drivers may also include the expectation that loose monetary policies by other major central banks (e.g., ECB, BOJ) will continue in the foreseeable future, the belief that real rates could be permanently lower, and the perception that a U.S. political gridlock may thwart attempts to kickstart real economic growth to a 3.0% level - the historical long-term average prior to the Financial Crisis. 2" In other words, investors seem to be pricing a "lower for longer" scenario. The concept that investors may be pricing lower real (neutral) rates has been reiterated by Fed Chair Janet Yellen in the press conference following the Fed's September meeting: 21•1" "Market participants may have lower estimates or believe that a low neutral rate may be more persistent." Of course, this monetary policy path could be altered by President Trump's selection of a new Fed Chair. Dr. Yell en's current term is set to expire in February 2018. Failure to renew her term for another four years could have significant repercussions, not just for the interest rate policy in the United States, but also wider side effects to the global economy. In Exhibit 4, we show how the 20-year U.S. Treasury yield - a typical proxy for the risk-free rate in U.S. dollars - has evolved from December 2007 through July 2017; in particular, notice the initial uptick in yields immediately after the November Presidential election, then a slight decrease followed by a standstill ever since. Looking at more recent data, the 20-year yield was 2.5% at the end of August and 2.4% on September 5, 2017, the effective date for the new Duff & Phelps U.S. ERP recommendation. Both are still below the 10-year trailing average of 3.3% for the 20-year U.S. Treasury yield. The current range of 1.00% to 1.25~ti for the Fed's benchmark rate is well be!ovv historical levels. Duff & Phelps Attachment BEL-3 [,:i Client Alert - Duff & Phelps' U.S. Equity Risk Premium Recommendation Decreased from 5.5% to 5.0%, Effective Se~ Nti.041988 Page 13 of24 Exhibit 4: Monthly 20-year U.S. Treasury Yield (spot rate) and Trailing 10-year Average Monthly 20-year U.S. Treasury Yield December 2007-July 2017 2008 Financial Crisis 5.0% January 31, 2016 2.4% (D&P increases ERP to 5.5% from 5.0%) 4.0% Avg. Monthly Yield (last 10 years) ------3.3% 3.0% l''~; g '< ¾t~ December 31, 2008 \.#~ J. 2.0% 3.1% ______.. \ l ~ ''fl (Brexit Vote) July 31, 2017 2.7% 1.0% July 8, 2016 November 8, 2016 1.7% 2.3% (Post-Brexit Low) (U.S. Presidential Elections) 0.0% -·-· ~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~ <:/'cf~fl)<: ,,v'\l{;if~q}' ,,.::fc:F'<:1,}'<:f ~q}' ,,v'\Ji,'1,/1~q}' ,,v«0 0\:i In summary, while current economic indicators are generally strong, there are still significant risks in the medium term. The International Monetary Fund ("IMF") has recently emphasized the current positive global economic conditions in its semi-annual "World Economic Outlook", but added a word of caution on the incompleteness of the recovery from the Financial Crisis and the possible sense of complacency by policymakers and financial markets:''5 "The global cyclical upswing that began midway through 2016 continues to gather strength. Only a year and a half ago, the world economy faced stalling growth and financial market turbulence. The picture now is very different, with accelerating growth in Europe, Japan, China, and the United States. Financial conditions remain buoyant across the world, and financial markets seem to be expecting little turbulence going forward, even as the Federal Reserve continues its monetary normalization process and the European Central Bank inches up to its own. These positive developments give good cause for greater confidence, but neither policymakers nor markets should be lulled into complacency. A closer look suggests that the global recovery may not be sustainable-not all countries are participating, inflation often remains below target with weak wage growth, and the medium-term outlook still disappoints in many parts of the world. The recovery is also vulnerable to serious risks. Financial markets that ignore these risks are susceptible to disruptive repricing, and are sending a misleading message to policymakers." Duff & Phelps Attachment BEL-3 & Client Alert - Duff & Phelps' U.S. Equity Risk Premium Recommendation Decreased from 5.5% to 5.0%, Effective Se~ N~041988 Page 14 of24 Current Financial Market Conditions The last time Duff & Phelps changed its U.S. ERP recommendation was on January 31, 2016 (from 5.0% to 5.5%). Since then, aggregate risks in U.S. markets appear to have declined. U.S. Equity Markets Looking back, 2016 turned out to be a year full of surprises and extreme events. Early 2016 saw financial markets in turmoil, with sharp declines in equity prices, further widening of credit spreads, and a general tightening of financial conditions. Although some financial markets rebounded from the beginning-of-the-year jitters, uncertainty increased in late June, when (contrary to analysts' and global investors' predictions) the U.K. electorate voted to end its membership in the European Union (known in the financial press as "Brexit"). Yields on U.S., German, and Japanese government securities fell sharply in safe-haven flows, while global equity prices declined significantly. However, the second major surprising political event of the year - the outcome of the U.S. presidential election in November 2016 - marked a change in investor sentiment, accompanied initially by a rise in global interest rates, a sharp narrowing of credit spreads, a strengthening of the U.S. dollar, and a rally in equity markets to record highs. While the so-called "reflation trade" abated at times during the first half 2017 (with government bond yields reversing some of the earlier gains), stock markets have continued their ascent. For perspective, as of July 31, 2017, the S&P 500 Index has increased 10.3% since year-end 2016 and is up 27.3% since January 2016 (see Exhibit 5). The S&P 500 closed at record highs in June and July 2017. Exhibit 5: S&P 500 Index Performance Since January 31, 2016 July 31, 2017 S&P 500 = 2,470.3 December 31, 2016 S&P 500 = 2,238.8 January 31, 2016 S&P 500 = 1,940.2 ------Source of underlying data: Capital 10 Since then, new records have been reached across U.S. equity markets in August, September, and through early October 2017. Duff & Phelps II Attachment BEL-3 & Client Alert - Duff & Phelps' U.S. Equity Risk Premium Recommendation Decreased from 5.5% to 5.0%, Effective Se~ No.o4il988 Page 15 of24 Progress on the U.S. legislative front has been disappointing and expectations for a big fiscal stimulus package to be passed during 2017 have diminished. Yet, strong earnings growth, still-accommodative monetary policies, and benign global macroeconomic trends have buoyed U.S. stocks. Corporate earnings have surpassed expectations, fueling hopes for even higher dividend payouts and stock buybacks. More recently, the announcement of a high-level plan for U.S. corporate tax reform, including a corporate statutory tax rate cut from 35% to 20%, has spurred further stock market records. Some analysts have characterized the current environment as a "goldilocks" children's tale of "not-too-hot and not-too-cold": modest growth, subdued inflation, low unemployment, and low interest rates, accompanied by high valuations and low implied volatility. In July 2017, Mohamed EI-Erian, Chief Economic Advisor at Allianz, and a well-known market analyst, described the state of financial markets as follows:26 "Over the past few months, government bond yields have fallen, the dollar has weakened and financials have underperformed, yet the major stock indexes are at or very near record highs, as persistently supportive liquidity conditions have more than compensated for policy and growth disappointments. By boosting returns and repressing volatility, ample liquidity is a gift for investors. It makes the investment journey pleasing, comfortable and lengthy. But it is not a destination. (. . .) The markets' overall sense of 'goldilocks' -- not too hot, not too cold -- explains much of the gap between buoyant stock indexes and lagging economic and policy fundamentals." In a later article, he justified the current levels in stock markets as follows:27 "With plentiful liquidity having conditioned investors to 'buy on dips', it would take a major shock to dislodge investors from behaviour that, repeatedly, has proven highly remunerative, despite unusually fluid geopolitical, institutional and political conditions." For the time being, there appears to be some justification for the positive investor sentiment particularly given the benign macroeconomic conditions and the support provided by major central banks' monetary policies. However, it remains to be seen what the impact will be to financial markets, when major central banks begin their monetary policy normalization and some of their support is removed. Strong earnings growth, still-accommodative monetary policies, and benign global macroeconomic trends have buoyed U.S. stocks Duff & Phelps II Attachment BEL-3 Client Alert - Duff & Phelps' U.S. Equity Risk Premium Recommendation Decreased from 5.5% to 5.0%, Effective Se~ ~G'.04iil988 Page 16 of24 Exhibit {;: Chicago Board Options Exchange (CBOE) "VIX" Index July 2012-Juiy 2017 45.0 August 24, 2015 40.7 40.0 if June 24, 2016 I 25.8 '~ (Day After Brexit 35.0 ' Vote) February 11, 2016 30.0 28.1 / November 8, 2016 18.7 25.0 (U.S. Presidential Elections) 20.0 / 15.0 10.0 -·"·- CBOE Volatility S&P 500 Index (AVIX) January 31, 2016 5.0 - - - Long-Term Average 20.2 I ., 5-Year Average (D&P increases ERP to July 31, 2017 5.5% from 5.0%) 10.3 0.0 Implied Equity Volatility Implied equity volatility, as measured by the Chicago Board Options Exchange (CBOE) "VIX" Index, has been termed a "fear index" as it can be a gauge of investor apprehension. Volatility in U.S. equity markets has declined sharply since January 2016 (see Exhibit 6). Investors appear remarkably upbeat, despite high valuations across many asset classes and considerable U.S. political uncertainty and elevated geopolitical tensions. Since the U.S. Presidential elections, the VIX Index has gradually decreased and it has now declined to levels well below the long-term average (see Exhibit 6). In fact, since May 2017, the VIX Index has dipped several times below a level of 10.0, a rare occurrence prior to 2017. As shown in Exhibit 7, before 2017, there were only nine (9) times in the VIX history when the index was below 10.0. In contrast, since the beginning of the year until the end of August 2017, the VIX was below 10.0 in 18 separate occasions. More recent data reveals that this trend has continued in September and early October. Remarkably, on October 5, 2017, the VIX recorded its lowest level in history of 9.19. The previous low-level record of 9.3 was reached in December 1993. Duff & Phelps Attachment BEL-3 & Client Alert - Duff & Phelps' U.S. Equity Risk Premium Recommendation Decreased from 5.5% to 5.0%, Effective Se~ !5!0.04i1988 Page 17 of24 Exhibit 7: Historical Number of Occurrences with "VIX" Index below 10.0 January 1992-August 2017 10 Total YTD 1 August 20171 18 I 4 = 4 3 3 Source of underlying data: Capital /0 It is true that various events that were forecasted in early 2017 to be potential sources of global geo-political risks were not as disruptive as anticipated. For instance, anti establishment, anti-European Union candidates in major European elections have not gained power, as once feared. The Dutch parliamentary elections in March did not yield power to the nationalist populist candidate. Likewise, the French presidential elections in April and May ended in the decisive defeat of the far-right nationalist candidate and her party, offering significant relief to the future of the European Union. In June, the attempt to gain a clear mandate for Brexit negotiations by Prime Minister Theresa May ended with a failure to maintain her Conservative Party's majority in Parliament. While increasing political uncertainty for the United Kingdom, this made the possibility of a "Soft Brexit" more plausible. More recently, however, tensions between the United States and North Korea have increased the threat of nuclear confrontation between the two countries. Elsewhere, the German far right party has gained substantially more votes in parliamentary elections than anticipated, leading to a more fragmented government coalition led by Chancellor Angela Merkel, which may create new sources of instability in 2018. Notwithstanding the current investor perception of negligible levels of risk, sentiment could quickly reverse if the U.S. Administration fails to implement its pro-growth policies, interest rates rise too quickly, global growth stalls, or one of the various sources of geopolitical risk comes to the forefront. Various economists and analysts have warned of excessive complacency in financial markets. Central bankers have also started to take notice. A recent article summarizes how their views on this matter may be interpreted:28 "Central banks have taken note. The concerted policy message in the past couple of months has been to caution about complacency in global market valuations, as reflected in unusually low risk premia across assets and geographies. (. ..) In a nutshell, central banks are not necessarily turning more hawkish, in defiance of their inflation stability mandates. Rather they are clearly signalling that investors are becoming far too complacent about the policy outlook - and that risks financial stability." Duff & Phelps ■ Attachment BEL-3 & Client Alert - Duff & Phelps' U.S. Equity Risk Premium Recommendation Decreased from 5.5% to 5.0%, Effective Se~ Na1.04l4988 Page 18 of24 Exhibit 8: Spread of U.S. High-Yield Corporate Bond Yields over U.S. Investment Grade Corporate Bond Yields July 2012-July 2017 7.0% January 31, 2016 February 11, 2016 5.6% 6.5% (D&P increases ERP to 6.0% 5.5% from 5.0%) June 24, 2016 5.0% / 4.5% / (Day After Brexit Vote) 4.0% 3.0% 2.0% November - Spread of U.S. High Yield Corporate Bond Yields 8, 2016 3.4% over U.S. Investment Grade Corporate Bond Yields (U.S. Presidential 1.0% --- Longer Term Average Elections) July 31, 2017 2.4% --- 5-Year Average 0.0% ts,'v ,,._11, 1s,'!l ,,._'!l 1s,'!l ,,._'!l ~ "I>< ,._I>< ~ ,,._0 ~ ~ ,,._0 ..._~ ~ ~ ~ ,t /,! cf'-..: ~ /,! /,! ,t "~ /,!"~ ,t"~ /,! ·-l ov ':,'I>« '?-~ )~ ':,'I>' ~ ':,~ r:Jf ':,'I>« '?-~ )~ Oc; ':,'I>« '?-~ ':,~ cf ':,'I>« ~ ':,~ Source of underlying data: Capital IQ Corporate Credit Spreads Since February 2016, corporate credit spreads have tightened materially. As mentioned earlier, the outcome of the U.S. presidential elections in November marked a change in investor sentiment, which was accompanied initially by a rise in global interest rates and a sharp narrowing of credit spreads. Since early 2017, U.S. Treasury yields have plateaued, as an initial rise in inflation reversed course and hopes for an imminent U.S. fiscal expansion diminished. Corporate spreads, however, reached their lowest levels since mid-2014 (see Exhibit 8). Since the onset of the 2008 Financial Crisis, fixed income markets have been significant beneficiaries of the OE policies implemented by major central banks across the globe. Large asset purchases by central banks have created an environment of ultra-low interest rates, encouraging new corporate debt issuance on a global basis. In addition, OE programs in the Eurozone, United Kingdom, and Japan include investment-grade corporate debt securities, thereby decreasing borrowing costs for those corporations even further. Duff & Phelps II Attachment BEL-3 & Client Alert - Duff & Phelps' U.S. Equity Risk Premium Recommendation Decreased from 5.5% to 5.0%, Effective Ser:@amm ~~041988 Page 19 of24 Ratings agencies have started warning of the potential challenges that may ensue when central banks start normalizing their interest rate policies and unwinding their balance sheets. The most immediate danger comes from the United States, where the Fed has now embarked on its path to normalization. A recent report from Fitch Ratings cautions that despite a current positive environment, the unwinding of OE will create challenges to both lenders (investors) and borrowers (corporations): 29 "( . .) the improving outlook for global credit quality is underpinned by years of loose central bank monetary policy, including quantitative easing (OE), as well as what are now the strongest world growth conditions since 2010. 'Looking ahead in the rating cycle, the most benign credit market conditions in modern history will gradually begin to normalise as central bank assistance is withdrawn and world growth peaks in 2018. This could begin to temper the otherwise upbeat rating outlook trend' ( . .) Unwinding OE will pose challenges to both borrowers and lenders." Additional indicators Supporting the ERP Change - Quantitative Models In addition to the general economic factors a_nd financial market conditions described above, lmoliedI ERP Duff & Phelps monitors other indicators that may provide a more quantitative view of where we are within the range of reasonable long-term estimates for the U.S. ERP. indications have Duff & Phelps currently uses several models as corroborating evidence. We reviewed the declined following indicators at the end of July and August 2017: substantially since Damodaran Implied ERP Model - New York University Professor Aswath Damodaran calculates implied ERP estimates for the S&P 500 and publishes his estimates on his January 2016 website. Prof. Damodaran estimates an implied ERP by first solving for the discount rate that equates the current S&P 500 index level with his estimates of cash distributions (dividends and stock buybacks) in future years. He then subtracts the current yield on 10-year U.S. government bonds to arrive at an implied ERP. Prof. Damodaran allows the user to select a variety of methods to project cash flow yields, as well as several expected growth rate choices for the terminal year in the valuation. Duff & Phelps converts Prof. Damodaran's implied ERP estimates to an arithmetic average equivalent measured against the 20-year U.S. government bond yield, relying primarily on two measures of projected cash flows: (i) the trailing 12-month cash flow yield (dividends plus buybacks) of S&P 500 constituents; and (ii) the trailing 10-year average cash flow yield (dividends plus buybacks) of S&P 500 constituents.30 Based on Prof. Damodaran's estimates of the trailing 12-month cash flow yield, the implied ERP (converted into an arithmetic average equivalent) was approximately 6.07% at end of July 2017, when measured against an abnormally low 20-year U.S. government bond yield (2.66%).11 The equivalent normalized implied ERP estimate was 5.23% measured against a normalized 20-year U.S. government bond yield of 3.5%. At the end of August 2017, the implied ERP (converted into an arithmetic average equivalent) was approximately 6.09%, when measured against the spot 20-year U.S. government bond yield (2.47%)? The equivalent normalized implied ERP estimate was 5.06% measured against a 3.5% normalized 20-year risk-free rate. These July and August normalized implied ERP estimates represent a decline of 62 b.p. and 79 b.p. respectively, relative to the January 2016 estimate (5.85%). Duff & Phelps Attachment BEL-3 & Client Alert - Duff & Phelps' U.S. Equity Risk Premium Recommendation Decreased from 5.5% to 5.0%, Effective Se~ No>.041988 Page20 of24 Default Spread Model (DSM) - The Default Spread Model is based on the premise that the long-term average ERP (the unconditional ERP) is constant and deviations from that average over an economic cycle can be measured by reference to deviations from the long-term average of the default spread between corporate bonds rated in the Baa category by Moody's versus those in the Aaa rating category. This model notably removes the risk--free rate itself as an input in the estimation of ERP. 33 However, the ERP indication resulting from the DSM is still interpreted as an estimate of the relative return of stocks in excess of risk-free securities. At the end of July and August 2017, the conditional ERP calculated using the DSM model was 4.86% and 4.90%, respectively. These indications represent declines of 79 b.p. and 75 b.p. respectively, relative to the 5.65% ERP indication at the end of January 2016. Hassett Implied ERP (Hassett) - Stephen Hassett has developed a model for estimating the implied ERP, as well as the estimated S&P 500 index level, based on the current yield on long-term U.S. government bonds and a risk premium factor ("RPF").34 The RPF is the empirically derived relationship between the risk-free rate, S&P 500 earnings, real interest rates, and real GDP growth to the S&P 500 index over time. The RPF appears to change only infrequently. The m.odel can be used monthly to estimate the S&P 500 and the conditional ERP based on the current level of interest rates. 35 Hassett's analysis uses the spot 10-year risk-free rate for the period from January 2008 through July 2011; thereafter, his analysis uses a normalized yield on U.S. Treasuries of 4.0% (2.0% real risk-free rate plus 2.0% inflation) and 4.5% (2.0% real risk-free rate plus 2.5% inflation).36 Using a normalized 4.0% risk-free rate at the end of July and August 2017, the S&P 500 index appeared to be somewhat overvalued based on the Hassett model's predictions, whereas using a 4.5% normalized risk-free rate would imply the index is substantially overvalued. Alternatively, based on the S&P 500 index level at :the end of July and August 2017, the implied risk-free rate commensurate with the index closing price was 3.58% and 3.57%, respectively. These indications for the risk free rate are very close to the Duff & Phelps concluded normalized risk-free rate of 3.5%, effective November 15, 2016 and thereafter (reaffirmed on September 5, 2017 and until further notice). Default Spread Model ERP indications have declined substantially since January 2016 Duff & Phelps Attachment BEL-3 & Client Alert - Duff & Phelps' U.S. Equity Risk Premium Recommendation Decreased from 5.5% to 5.0%, Effective Se~ N0.041988 Page21 of24 Duff & Phelps' U.S. Based on current market conditions, we find sufficient evidence for decreasing the Duff & Phelps U.S. ERP recommendation from 5.5% to 5.0%, for valuation dates as of September Equity Risk Premium 5, 2017 and thereafter. We will maintain our recommendation to use a 5.0% U.S. ERP when Recommendation and developing discount rates until there is evidence indicating equity risk in financial markets has "Base" Cost of Equity materially changed. We are continuing to closely monitor the aftermath of the U.S. presidential election held on November 8, 2016 and its impact on cost of capital assumptions. as of September 5, 2017 The current ERP recommendation was developed in conjunction with a "normalized" 20-year yield on U.S. government bonds as a proxy for the risk-free rate. Based on recent academic literature and market evidence of a secular decrease in real interest rates (a.k.a. the "rental" rate) and lower long-term real GDP growth estimates for the U.S. economy, we are reaffirming our concluded normalized risk-free rate of 3.5%, established as of November 15, 2016. 37 The combination of the new U.S. recommended ERP (5.0%) and the reaffirmed normalized risk-free rate (3.5%) results in an implied U.S. "base" cost of equity capital estimate of 8.5% (5.0% + 3.5%). Adjusting the risk-free rate in conjunction with the ERP is only one of the alternatives available when estimating the cost of equity capital. Were we to use the spot yield-to-maturity of 2.4% on 20-year U.S. Treasuries as of September 5, 2017, one would have to increase the ERP assumption accordingly. One can determine the ERP against the spot 20-year yield as of September 5, 2017, inferred by Duff & Phelps' recommended U.S. ERP (used in conjunction with the normalized risk-free rate), by using the following formula: U.S. ERP Against Spot 20-year Yield (Inferred) = = D&P Recommended U.S. ERP + Normalized Risk-Free Rate - Spot 20-year U.S. Treasury Yield = 5.0% + 3.5% - 2.4% = 6.1% Duff & Phelps II Attachment BEL-3 Client Alert - Duff & Phelps' U.S. Equity Risk Premium Recommendation Decreased from 5.5% to 5.0%, Effective Se~ N(W4:il988 Page 22 of24 Endnotes 1. For a discussion of some of the studies and factors we evaluate, refer to Chapter 3 of the Duff & Phelps 2017 Valuation Handbook - U.S. Guide to Cost of Capital. 2. Refer to the Duff & Phelps Client Alert issued on March 16, 2016, which was titled "Duff & Phelps Increases U.S. Equity Risk Premium Recommendation to 5.5%, Effective January 31, 2016". To obtain a free copy of this Client Alert and prior ones documenting the Duff & Phelps' U.S. ERP recommendation over time, visit: www.D 1Jf~andPhelps.com/CostofCapita!. 3. See the Duff & Phelps Client Alert issued on January 12, 2017, which was titled "Duff & Phelps' U.S. Normalized Risk-Free Rate Decreased from 4.0% to 3.5%, Effective November 15, 2016", also found at: www.DuffandPhebs.com/CostuiCapital. 4. On June 23, 2016, the U.K. electorate voted to leave the European Union, which is known in the financial press as the "Brexit" vote. For further details, refer to the Duff & Phelps Client Alert "Brexit: The Impact on Cost of Capital", dated September 14, 2016, available at www.DcffandPhelps.com/CostofCapital. In March 2017, the U.K. government officially triggered the two-year negotiation period to exit the European Union. 5. For a more detailed discussion of this decision, refer to Chapter 3 of the Duff & Phelps 2017 Valuation Handbook - U.S. Guide to Cost of Capital. 6. See for example John Cochrane's "Discount Rates. American Finance Association Presidential Address" on January 6, 2011, where he presented research findings on the cyclicality of discount rates in general. His remarks were published as Cochrane, J. H. (2011), "Presidential Address: Discount Rates," The Journal of Finance, 66: 1047-11081 available at: http://on:!ne:lb:·a,y.v,d!ey.corn/doi/10.11 ii /j.1540-6261 .2011.01671.x/fu\L A video of his remarks is available at: http://wvrN.afajof.org/detaiis/video_l2870771 /201 i-Pres\dential-Address.htrnl. 7. The "conditional" ERP is the ERP estimate published by Duff & Phelps as the "Duff & Phelps Recommended ERP". 8. See Shannon P. Pratt and Roger J. Grabowski, Cost of Capital: Applications and Examples, Fifth Edition, Chapter 8 "Equity Risk Premium", and accompanying Appendices BA and BB, for a detailed discussion of the unconditional ERP. This discussion has been updated with more recent data in Chapter 3 of the Duff & Phelps 2017 Valuation Handbook - U.S. Guide to Cost of Capital. 9. John C. Cochrane (2011), "Presidential Address: Discount Rates," The Journal of Finance, 66: 1047-1108 http://or~llne\ibrary.wi\ey.com/do'./10.1111 /j.1540-6261 ,201-1.01671.x/f di. I 0. The discussion in this article was based on the review of data for periods ended on or around July 31, 2017, with selected data updated through the end of August 2017. However, general information available through the time of writing (October 12, 2017) was also considered as corroborating evidence. 11. "U.S. Business Cycle Expansions and Contractions", National Bureau of Economic Research. Underlying data accessible here: htt:i:i!www.nber.org!cycles.htrnl. 12. Source of underlying real GDP data: the U.S. Bureau of Economic Analysis. 13. Source of underlying real GDP data: the U.S. Bureau of Economic Analysis. 14. For instance, the University of Michigan Consumer Sentiment Index registered a level of 93.4, compared to a long-term average (since 1978) of 85.6. 15. Source of underlying labor and inflation statistics: the U.S. Bureau of Labor Statistics. 16. For a more detailed discussion on the proportion of U.S. Treasury securities held by the Fed, as well as other factors that have contributed to lower global interest rates, refer to Chapter 3 of the Duff & Phelps 2017 Valuation Handbook - U.S. Guide to Cost of Capital. 17. Huther, Jeffrey, Jane Ihrig, and Elizabeth Klee (2017). "The Federal Reserve's Portfolio and its Effect on Interest Rates," Finance and Economics Discussion Series 2017-075. Washington: Board of Governors of the Federal Reserve System, htips.:/ido:.org/10.17016/FEDS.2017.075. 18. For a discussion on the impact of the Federal Reserve's OE programs on the term premium (or maturity premium) and the yield on 10-year U.S. Treasury bonds, see "The Effect of the Federal Reserve's Securities Holdings on Longer-term Interest Rates", accessible here: htt~s: / /v,;\\'W .fede.ra Ire S8'°VE': _gov leco n res !r.Dtes f feds-notes!effect- of-fr, e-f eds r o !- rese rvG s-sec u rities-ho!d: r,g s-o r.-l or:g e r-te ,..m-f '"'1te-rest· rafos---20170 4? 0. htrn. 19. Minutes of the Federal Open Market Committee of the Board of Governors of the Federal Reserve System can be found by visiting: http:/iv1 ,Nw. fodo rnl reserve, gov/ .no·-, e tary poi icy /fo m sea le ;ldars. htr,. 20. For the latest composition and size of the Fed's balance sheet, refer to the Federal Reserve Bank of Cleveland's Credit Easing data, available at: h ttps: !! w-..vvl. c ieve 1a n dfed. o rg/ o u r·-resea rch /'.:.di cato rs-and -d a.talc ,e d; t-e-as; n g. as px. 21. "FOMC issues addendum to the Policy Normalization Principles and Plans", June 14, 2017, available here: https://www.tede"a:':"ese-rv0.gov/"'lavv:sevents!pressreleascs/mo'let~1ry::-'.Oi 706 "l 4c. htm. Duff & Phelps Attachment BEL-3 & Client Alert - Duff & Phelps' U.S. Equity Risk Premium Recommendation Decreased from 5.5% to 5.0%, Effective Se~ ~&.04:il988 Page 23 of24 Endnotes 22. For a more detailed discussion on the trends behind the decline in real interest rates, refer to "Duff & Phelps' U.S. Normalized Risk-Free Rate Decreased from 4.0% to 3.5% 1 Effective November 15 1 2016", which can found here: v1ww.DuffandPhe(ps.e:0m/CostofCapitaL 23. "FOMC: Press Conference on September 20, 2017". The Transcript to this press conference can be found here: h ttps://wvr.v ,feds :a::ese rve .gov /1 nsd iacer.ts:/ r: :esiFO MC p resc on f 2017 09 2 0. p df. 24. The neutral real rate, also called r' (r-star), stands for the longer-run value of the neutral rate. This is what the inflation-adjusted interest rate (i.e., real rate) will be once the economy is back to full strength, i.e., consistent with the economy operating at maximum employment. 25. "World Economic Outlook, October 2017 Seeking Sustainable Growth: Short-Term Recovery, Long-Term Challenges", International Monetary Fund. For a copy of the report, visit: https://www.imf.orgien/Pu b1ications!VVE0/1ssues/2017i09/19/wor\d-toconornic.,cu tlook-october-2017. 26. EI-Erian, Mohamed A. "The Upside and Downside of Liquidity-Driven Markets." Bloomberg, July 21, 2017. This article can be accessed here: https: / /vvvvw. 01 oo mbe rg .com/v;ew/ a:t!c:es/2017-07-21 /the-ups ide··2rd-dov-,,- n side- of-liquid i ty--drive n- markets. 27. EI-Erian, Mohamed A. "Jackson Hole gathering looms for investors." Financial Times, August 9, 2017. This article can be accessed here: https://wwvdt.com/conten U790d1 bf 0-7b4a-11e7-9108-edda0bcbc928. 28. Komileva, Lena. "You are too complacent, central bankers warn markets." Financial Times, July 30, 2017. This article can be accessed here: https://wwv1.ft.com!con tent/8908f882-7 39 b-11 e7-93ff-99t383 b09ff9. 29. "Fitch: OE and World Growth Buoy Global Rating Outlooks", September 19, 2017. A summary of the report can be accessed here: https://www .titchratings.com/site/pr/i 02936 7?em _;-nmc= E:>!actTarget-.... • 30. Source of underlying data: downloadable dataset entitled "Spreadsheet to compute ERP for current month". To obtain a copy, visit: http: fl pages ,stern. ny u .ed u /~ad amoda d. 31. Damodaran's implied rate of return (based on the actual 10-year yield) on the S&P 500 = 7.33% as of August 1, 2017, minus the actual 20-year U.S. Treasury yield of 2.66% plus an adjustment to equate the geometric average ERP to its arithmetic equivalent. The result reflects conversion of the implied ERP to an arithmetic average equivalent. 32. Damodaran's implied rate of return (based on the actual 10-year yield) on the S&P 500 = 7.16% as of September 1, 2017, minus the actual 20-year U.S. Treasury yield of 2.4 7% plus an adjustment to equate the geometric average ERP to its arithmetic equivalent. The result reflects conversion of the implied ERP to an arithmetic average equivalent. 33. The Default Spread Model presented herein is based on Jagannathan, Ravi, and Wang, Zhenyu,"The Conditional CAPM and the Cross-Section of Expected Returns," The Journal of Finance, Volume 51, Issue 1, March 1996: 3-53. See also Elton, Edwin J. and Gruber, Martin J., Agrawal, Deepak, and Mann, Christopher "Is There a Risk Premium in Corporate bonds?", Working Paper. Duff & Phelps uses (as did Jagannathan, Ravi, and Wang) the spread of high-grade corporates (proxied by yields on Aaa rated bonds) against lesser grade corporates (proxied by yields on Baa rated bonds). Corporate bond series used in analysis herein: Bloomberg Barclays US Corp Baa Long Yid USD (Yield) and Bloomberg Barclays US Corp Aaa Long Yid USD (Yield); Source: Morningstar Direct. 34. Stephen D. Hassett, "The RPF Model for Calculating the Equity Risk Premium and Explaining the Value of the S&P with Two Variables," Journal of Applied Corporate Finance, 22, 2 (Spring 2010): 118-130. 35. For a more detailed description of Hassett's Risk Premium Factor model see Pratt and Grabowski, op.cit., Chapter BA, "Deriving ERP Estimates": 167-168. 36. To clarify, Stephen Hassett uses a 2.0% real rate in his analysis for a normalized yield on U.S. Treasuries. Duff & Phelps uses a range of 0.0% to 2.0% for the long-term real rate. Refer to Chapter 3 of the 2017 Valuation Handbook - U.S. Guide to Cost of Capital. 37. Refer to "Duff & Phelps' U.S. Normalized Risk-Free Rate Decreased from 4.0% to 3.5%, Effective November 15, 2016". For a more detailed discussion on how Duff & Phelps estimates a normalized risk-free rate, refer to Chapter 3 of the 2017 Valuation Handbook - U.S. Guide to Cost of Capital. Duff & Phelps Attachment BEL-3 Cause No. 44988 DUFF@ffl~LPS AUTHORS CONTRIBUTORS Roger J. Grabowski, FASA Kevin Madden Managing Director Senior Associate [email protected] [email protected] Aaron Russo Carla S. Nunes, CFA Managing Director Analyst [email protected] [email protected] Andrew Vey James P. Harrington Director Analyst [email protected] [email protected] About Duff & Phelps M&A advisory, capital raising and secondary market advisory services in the United States Duff & Phelps is the premier global valuation and corporate finance are provided by Duff & Phelps Securities, LLC. Member FINRAISI PC. Pagemill Partners advisor with expertise in complex valuation, disputes and investigations, is a Division of Duff & Phelps Securities, LLC. M&A advisory and capital raising services in Canada are provided by Duff & Phelps Securities Canada Ltd., a registered Exempt M&A, real estate, restructuring, and compliance and regulatory consulting. Market Dealer. M&A advisory, capital raising and secondary market advisory services in The firm's more than 2,000 employees serve a diverse range of clients the United Kingdom and across Europe are provided by Duff & Phelps Securities Ltd. from offices around the world. (DPSL), which is authorized and regulated by the Financial Conduct Authority. In Germany M&A advisory and capital raising services are also provided by Duff & Phelps For more information, visit www.duffandphelps.com GmbH, which is a Tied Agent of DPSL. Valuation Advisory Services in India are provided by Duff & Phelps India Private Limited under a category 1 merchant banker license issued © 2017 Duff & Phelps, LLC. All rights reserved. DP170280 by the Securities and Exchange Board of India. Attachment BEL-4 Cause No. 44988 Page 1 of 1 70 Duke CFO magazine Global Business Outlook survey - U.S. - Fourth Quarter, 2017 On November 14th, 2017 the annual yield on 10-yr treasury bonds was 2.37%. Please complete the following: (Winsorized) Mean SD 95% Cl Median Minimum Maximum Total Over the next 10 years, I expect the average annual S&P 500 return will be: There is a 1-ln-10 chance it will be less than: 1,76 4.90 1.13 - 2.38 2 -10,80 14.30 235 Over the next 10 years, I expect the average annual S&P 500 return will be: Expected return: 7,16 4,36 6,61-7.71 6 1 23,98 240 Over the next 10 years, I expect the average annual S&P 500 return will be: There is a 1-in-10 chance It will be greater than: 10.67 5.91 9.92-11.42 10 2 31.08 237 Over the next year, I expect the average annual S&P 500 return will be: There is a 1-in-10 chance it will be less than: -2.26 9.65 -3.49 - -1.03 1 -22.90 18.52 235 Over the next year, I expect the average annual S&P 500 return will be: Expected return: 6.57 5.57 5,86 - 7.27 6 -8.46 22.32 239 Over the next year, I expect the average annual S&P 500 return will be: There Is a 1-in-10 chance it will be greater than: 11,57 6.40 10.75 -12,39 10 0 28.88 234 Attachment BEL-5 Cause No. 44988 Page 1 of22 Riders, Trackers, Surcharges, Pre-Approvals and Decoupling: How Do They Affect the Cost of Equity? Scott Hempling1 Table of Contents Overview I. Regulatory decisions on authorized return on equity are bounded by Constitutional and statutory principles II. A rider's cost-of-equity effect depends on its context and content A What is risk's role in determining total cost of equity? B. How important is the rider-reduced risk, within the utility's full universe of risks? C. How large is the rider-related expenditure, relative to total expenditures? D. What are the rider's specific features? 1. Nature of the rider-associated risk in relation to normal risks 2. Relation to pre-approval a. Pre-approval with cost caps b. Pre-approval with prudence review 3. Balanced or unbalanced? a. Balance within the test year b. Balance within the rider itself 4. Method of cost recovery 5. Timing issues a. Existence and frequency of true-up b. Timing of recovery c. Growth over time d. Time span e. Investment timeline 6. Conclusion on the rider's specific features E. Are there factors external to the riders that affect the company's risk situation? 1. Commission rate practices 2. Utility's expenditure obligations III. A utility's riders should lower its ROE position within the zone of reasonableness only if its riders reduce risk more than the proxy companies' riders do 1 This paper was prepared for and funded by Oklahoma Gas & Electric Company, under a contract that precluded the utility from directing the paper's conclusions. 1 Attachment BEL-5 Cause No. 44988 Page 2 of22 Overview In an embedded cost rate case, the commission sets the utility's annual revenue requirement by predicting expenses, capital expenditures and the cost of capital for the upcoming rate year. The cost of capital comprises interest on debt and the cost of equity. Interest on debt is a known fact: the contractual interest rates on loans. Cost of equity is not a known fact; it is an estimate - of the return shareholders require to put and keep their money in the utility. The cost of equity is affected by a number of factors, including shareholders' risk of not recovering their money, of recovering it later than desired, and of receiving a return less than what they could earn elsewhere on investments of comparable risk. These shareholder risks flow from traditional ratemaking's central principle: that just and reasonable rates provide shareholders an opportunity, but not a promise, of earning the authorized return. This gap between opportunity and guarantee has drawn the attention of legislatures and commissions. A mix of devices now exists to reduce one or more of these shareholder risks, by allowing utilities to recover specified expenditures with more certainty. These devices include riders, cost-trackers, surcharges, pre-approvals and decoupling. The first three authorize a utility to collect or refund specified costs ( e.g., energy efficiency, renewable purchases, smart grid, nuclear power plants), as they increase or decrease, without filing a general rate case. Pre-approval occurs when the commission commits, prior to a rate case, not to question the reasonableness of a particular utility action or cost.2 Decoupling, in its most common form, insulates fixed cost recovery from sales volumes. Each of these devices contrasts with traditional regulation, where (a) the commission addresses all expenditures ( except perhaps fuel costs) in general rate cases only; and (b) capital expenditures receive approval for recovery only in rate cases filed after the associated asset entered commercial operation. While these devices can reduce shareholder risk, and thus the cost of equity, the regulatory community is struggling with how to reflect that risk reduction in the authorized return of equity. The debate has become more oppositional than factual, as experts' arguments boil down to this bipolarity: "Riders reduce risk, and reduced risk means reduced cost of equity; therefore we must lower the authorized ROE." "The utility faces new risks, and the rider does no more than to mitigate those risks; therefore we should not lower the ROE." In their written opinions, commissions consider both arguments sympathetically. But their decisions to adjust -- or not adjust -- authorized ROE often lack factual analysis specific to the 2 For a detailed discussion of pre-approvals, see S. Hempling and S. Strauss, Pre-Approval Commitments: When and Under What Conditions Should Regulators Commit Ratepayer Dollars to Utility-:Proposed Capital Projects? (NRRI 08-12 Nov. 2008), available at http://nrri.org/pubs/electricity/nrri__preapproval_ commitments_ 08-12.pdf 2 Attachment BEL-5 Cause No. 44988 Page 3 of22 riders at issue. Settlements are frequent, their black boxes revealing no reasoning. See the Appendix for examples. Future rate case participants, the financial community and the public remain unclear about what effects these devices have, or should have, on authorized ROE. While judgments about cost of equity are unavoidably subjective, the reasoning process can benefit from more fact-specificity, transparency and rigor. A reduction in authorized ROE due to riders and pre-approvals should be calibrated to the actual level ofrisk reduction. That calibration requires expert witnesses and commissions to identify, among other things, (a) the types of risks faced by the utility generally, (b) the specific risks reduced by the riders and pre-approvals, (c) the size of the rider-reduced risks relative to total risks, (d) the variances of these risks from the utility's traditional risks, and ( d) the proportion of total earnings affected by the rider. Judgment on each of these facts is inevitable, but making those judgments openly, on facts specific to the judgments, will help avoid under- or over-adjusting the authorized return on equity. The equation is straightforward: The clearer the government promise, the lower the risk for the expenditure subject to that promise; and, the lower expenditure's risk, the lower its associated cost of equity, relative to a situation of no government promise. The challenge is supplying the variables. This paper seeks to advance the conversation by identifying and organizing the relevant factors. With a logical scheme in place, financial experts can have a common analytical basis for better connecting specific riders with specific ROE effects. Part One sets the legal background by describing the Constitutional and statutory boundaries on commissions= return on equity decisions. Part Two explains that a rider's cost-of-equity effect depends on its context and content. Part Three explains that a utility's riders should lower its ROE position within the zone ofreasonableness only if its riders reduce risk more than the proxy companies' riders do. Terminology note: The concepts in this paper apply to all risk-reducing devices: riders, cost trackers, surcharges, pre-approvals and decoupling For brevity, the paper uses the term "riders" to refer to all these approaches. 3 Attachment BEL-5 Cause No. 44988 Page 4 of22 I. Regulatory decisions on authorized return on equity are bounded by Constitutional and statutory principles 11 ••• [N]or shall private property be taken for public use, without just compensation. 11 The Takings Clause of the Constitution's Fifth Amendment establishes a commission's obligation to shareholders when setting the authorized return on equity. When shareholders invest their funds in a regulated utility, their property is deemed "taken."3 The "just compensation" they must receive depends in part on their expectations at the time of the investment. See Penn Central Transportation Co. v. New York, 438 U.S. 104, 124 (1978) (listing factors involved in the Court's fact-based takings analysis, including the "economic impact of the regulation on the claimant and, particularly, the extent to which the regulation has interfered with distinct investment-backed expectations"). "The analysis is essentially ... ad hoc [and] factual." Jersey Central Power & Light v. Fed. Energy Regulatory Comm 'n, 810 F.2d 1168, 1192 (D.C. Cir. 1986) (Starr, J., concurring) (quoting Kaiser Aetna v. United States, 444 U.S. 164, 175 (1979)). These principles derive from two key Supreme Court passages addressing regulatory treatment of utility shareholder property. In Bluefield Water Works & Improvement Company v. Public Service Comm'n, 262 U.S. 679, 692 (1923), the Court stated: "[A] public utility is entitled to such rates as will permit it to earn a return on the value of the property which it employs for the convenience of the public equal to that generally being made at the same time and in the same general part of the country on investments in other business undertakings which are attended by corresponding risks and uncertainties .... The return should be reasonably sufficient to assure confidence in the fmancial soundness of the utility and should be adequate, under efficient and economical management, to maintain and support its credit and enable it to raise the money necessary for the proper discharge of its public duties." The Bluefield Court held that a rate ofreturn of under six percent was too low. Id. at 693. The Court also emphasized that low and irregular income would hurt the utility's security prices, causing investors to demand higher rates of return. Id. Twenty-one years later, after numerous complicated efforts at commission and courts to apply Bluefield, the Court distilled the inquiry to this sentence: 3 See Error! Main Document Only.State ofMissouri ex rel. Southwestern Bell Telephone Company v. Public Service Commission of Missouri, Error! Main Document Only.262 U.S. 276,290 (1923) ("The thing devoted by the investor to the public use is not specific property, tangible and intangible, but capital embarked in the enterprise. Upon the capital so invested the Federal Constitution guarantees to the utility the opporunity to earn a fair return.") (Brandeis, J., concurring). 4 Attachment BEL-5 Cause No. 44988 Page 5 of22 "Rates which enable [a] company to operate successfully, to maintain its financial integrity, to attract capital, and to compensate its investors for the risk assumed certainly cannot be condemned as invalid, even though they might produce only a meager return on the so called 'fair value' rate base." FPC v. Hope Natural Gas Co., 320 U.S. 591, 605 (1944). In the complicated world of commission proceedings, however, applying these principles and cases is not easy; there is no single-sentence solution. There is, instead, endless debate: "There is close to unanimous acceptance of the principle of comparable return for comparable risks, and little agreement on how it can be applied in any case." R. Pierce and E. Gellhorn, Regulated Industries (1999) at 136. Recognizing that appropriate shareholder compensation can only be estimated, courts and commissions refer to a "zone ofreasonableness." Within that zone, (a) any number can be lawful and (b) the commission can base its decision on its preferred policies. As Alfred Kahn put it: "The conception is that there is no single, scientifically correct rate of return, but a 'zone ofreasonableness,' within which judgment must be exercised." The Economics ofRegulation: Principles and Institutions, Vol. I (1988) at 42. Kahn then quoted Justice Oliver Wendell Holmes: "This is not a matter of economic theory, but of fair interpretation of a bargain. Id. at 43 (quoting Cedar Rapids Gas Light Co. v. Cedar Rapids, 223 U.S. 655, 669 (1912)).4 This legal terrain gives witnesses and commissions much room to maneuver. When we introduce riders, trackers, surcharges, pre-approvals and decoupling into the mix, the complexity of estimating cost of equity grows. There are many facts available to support many possible conclusions. The next two parts attempt to sort out those facts and possibilities. II. A rider's cost-of-equity effect depends on its context and content Analysis of a rider's cost-of-equity effect should start by placing the rider, and the associated risk, in context, and by understanding the rider's content. There are five critical questions: A. What is risk's role in determining total cost of equity? B. How important is the rider-reduced risk, within the utility's full universe ofrisks? C. How large is the rider-related expenditure, relative to the utility's total expenditures? D. What are the rider's specific features? E. Are there factors external to the riders that affect the company's risk situation? 4 But see the discussion of Conway Corp. v. Federal Power Commission, 426 U.S. 271 (1976), in Part III below, cautioning that a commission's discretion within the zone of reasonableness is not unbounded discretion. 5 Attachment BEL-5 Cause No. 44988 Page 6 of22 Answering these questions will enable proponents and policymakers to base their decisions on facts rather than generalizations. A. What is risk's role in determining total cost of equity? Risk is a contributor to, but not the totality of, investors' reasons for demanding a return on equity. Return on equity has multiple purposes. As the Bluefield Court stated, return on equity assures confidence in the utility's financial soundness, supports the utility's credit, and enables it to raise the money sufficient to perform its obligations. The return on equity can achieve these objectives because it reflects opportunity cost: what investors could expect to earn by investing their capital in assets having comparable risk. That risk accounts for only a part of required return is made explicit in the risk premium method for determining cost of equity. Risk premium analysis distinguishes among three contributors to cost of equity: (1) the risk-free rate, which is the rate of interest on default-free securities (that rate, in turn, consists of two components -- "an inflation-free (real) rate and a premium for anticipated inflation"); (2) the corporate bond risk premium (reflecting business risks like default); and (3) the equity risk premium ( equity has more risk than bonds because the corporation has no contract obligation to turn a profit for equity shareholders). 5 The point is that equity risk -- the portion of cost of equity affected by riders -- is only part of total cost of equity. Return on equity witnesses from competing perspectives generally agree that decades of data reveal a rate spread between bonds and equities. As the risk-free rate or historic spread between bonds and equities vary over time, the percentage that the equity risk contributes to total risk likewise varies. In sum: If a commission seeks to adjust the authorized ROE based on a reduction in the utility's risk, it first must determine what portion of the ROE is attributable to risk; then confine any reduction in authorized ROE to that component. B. How important is the rider-reduced risk within the utility's full universe of risks? The total risk component of authorized ROE represents the several shareholder risks: the risk of not recovering their investment, of recovering it later than desired, and of receiving a 5 D. Parcell, The Cost of Capital: A Practitioner's Guide (Society of Utility and Regulatory Financial Analysts 1997), at pp. 9-1 to 9.3. 6 Attachment BEL-5 Cause No. 44988 Page 7 of22 return less than what they could earn on alternative investments of comparable risk; in short, the risk of not receiving the real return (i.e., adjusted for inflation) they expected when they invested in the utility. This risk arises from the following possibilities: 1. Actual sales volume is less than the level assumed by the Commission when setting the revenue requirement (absent decoupling). This can occur for multiple reasons -- a slow economy, structural changes like new energy-efficient building stock and appliances, customer behavior changes, unexpected outages. 2. Actual demand is less than the level assumed (for customers whose bills are based on demand). The potential causes are similar to those for sales volume. 3. Actual costs are higher than assumed. Possible causes include unanticipated general inflation, special inflation of input costs, labor productivity below assumptions, unanticipated regulatory costs, and unanticipated accidents and repairs. Capital expenditures, when they exceed those assumed in the authorized revenue requirement, are a distinct source ofrisk: Unless the regulator permits deferral of these expenditures (i.e., allowing the utility to argue for their recovery later), the time lag from cost incurrence to later rate case approval leaves a permanent gap in recovery and return. 4. Actual delinquencies are higher than assumed. Possible causes include an unanticipated economic slowdown and the loss of a major employer in the service territory. 5. The commission reduces revenues for reasons other than imprudence. The Supreme Court has held that prudence does not guarantee recoverability; a statute or commission can disallow prudent costs under the principles of "used and useful" and "utility bears the business risk. 116 (A utility also faces the risk of nonrecovery due to imprudence or poor performance, but has no reasonable expectation of receiving compensation for this risk.) Other than full decoupling, no rider or pre-approval reduces all of these risks. A rider usually aims at a specific expenditure, and a specific risk associated with that expenditure. Those details are discussed in Part II.D below. 6 Duquesne Light Co. v. Barasch, 488 U.S. 299, 307-16 (1989). The utility had abandoned construction of a nuclear plant. The Pennsylvania Commission had found that the decisions to begin constructing the plant, and later to abandon the plant, were prudent. Based on a state statute limiting cost recovery to plant that "is used and useful in service to the public," the Commission declined to allow full cost recovery. The Court rejected the utility's argument that the Constitution's Fifth and Fourteenth Amendments require recovery of prudent costs. 7 Attachment BEL-5 Cause No. 44988 Page 8 of22 C. How large is the rider-related expenditure, relative to the utility's total expenditures? The third step in analyzing a rider's effects is to determine what share of total earnings the rider addresses. A $1 billion power plant plays a larger role in a utility's risk profile than a $50 million property tax bill. Recovering only financing costs has less effect than recovering out-of-pocket costs. Some riders collect only a percentage of the costs of a project, with the remainder recovered when the project is included in base rates. The risk effect of regulatory lag - delaying or foregoing recovery of costs incurred until the commission determines recoverability- also varies with the affected cost's relative size. The importance of size thus has two implications. First, one cannot generalize about riders' effects; scale matters. Second, when a rider-related reduction in ROE is appropriate, that reduction logically applies only to the portion of total utility expenditure affected by the rider. Transparent decisionmaking would (1) identify that ROE uniquely appropriate for the rider-related expenditure, (2) apply that ROE only to that expenditure, then (3) "roll it in" to the overall cost of equity. This approach would make the authorized return a weighted average: The non-protected part of the shareholder investment would receive the mid-range ROE; and the more-protected part would receive the lower-range ROE. Commission cases do not take these three steps. Except for sometimes assigning separate ROEs for gas and electric sections of the same utility, the cases skip the middle step, instead applying some basis point reduction to the overall ROE. This approach makes it impossible for the public and reviewing courts to assess the commission's reasoning. Blue.field focused on three things: comparable earnings, financial integrity, and capital attraction. Applying a lowered ROE to all the investment, based on a reduced risk for only some of that investment, violates all three concepts. D. What are the rider's specific features? A rider allows the utility to recover a specified cost outside a general rate case. The premise for reducing authorized ROE is that cost recovery occurs sooner, and with more certainty, outside a rate case. That premise's accuracy depends on the rider's specifics. Riders have at least 6 dimensions, discussed next: 1. Nature of the rider-associated risk in relation to normal risks 2. Relation to pre-approval 3. Balanced or unbalanced? 4. Method of cost recovery 5. Timing issues 6. Extent of commission discretion 8 Attachment BEL-5 Cause No. 44988 Page 9 of22 1. Nature of the rider-associated risk in relation to normal risks Consider a hypothetical utility having a conventional generation mix, and an historically predictable, average rate ofload growth. Assume now that it must address a previously unanticipated increase in load growth in the next ten years, when there is a high likelihood of expensive carbon regulation. The utility chooses to invest in its first nuclear plant. The plant's fmal construction cost will double the utility's book value. The pre-existing plants would continue in operation; the purpose of the new nuclear plant is to address the new load growth. This nuclear plant is a new risk, different from the utility's historic risks; and it is a large risk. It makes the utility's risk profile riskier. All else equal, shareholders will demand higher compensation for this new, large, different risk. Suppose the state legislature, prior to construction, commands the commission to establish a rider that guaranteed recovery of all prudent nuclear construction costs with a minimum oflag. In response, the commission approves a rider that (a) recovers Commission approved estimates predicted for each next quarter, then (b) trues up at the end of that quarter, for every quarter through plant completion. This rider will have eliminated much of the risk associated with nuclear construction. But it would not have addressed any of the risks associated with the utility's other capital costs and operations. The rider will have mitigated the cost of equity increase caused by the nuclear investment, but will not have reduced any of the pre-nuclear risk. In this hypothetical context it would be illogical to cite the rider as a reason to reduce the utility's authorized return on equity. This hypothetical helps establish the following principle: If a rider does no more than cancel out a unique risk associated with a new activity, the rider's incremental effect on cost of equity is zero. The question is whether the new rider-connected activity, absent the rider, increases the company's pre-existing risk (i.e., the risk arising from non-rider activities); and then whether the rider eliminates that incremental risk. We can describe the new rider-connected activity with two dimensions: Similarity or dissimilarity to existing activities: Expanding an existing transmission system by installing lines of voltage similar to existing lines, in terrain similar to existing terrain, is different from creating a new smart grid network consisting of interactive home meters and new central communications hardware. Size relative to existing activities: Adding a 250 MW plant to a 5000 MW system is different from adding a 1500 MW plant to a 5000 MW system. The combinations of these features create four possibilities: 9 Attachment BEL-5 Cause No. 44988 Page 10 of22 1. similar activity, small relative to the company's size 2. similar activity, large relative to the company's size 3. dissimilar activity, small relative to the company's size 4. dissimilar activity, large relative to the company's size Each of these situations represents a different change in company risk. Example: One might view smart grid as a business activity different from traditional utility responsibilities -- different from mere meter installation and meter reading, and different from traditional distribution system management. It involves new technology (both hardware and software) and new business processes. It is costly, and it might not work. There is risk that even with prudent behavior, the investment will not produce benefits commensurate with costs. It is experimental. Adding these unusual risks to the company's normal risks would increase its cost of equity. A rider that eliminates these unusual risks, all else equal, would leave the company in its pre-smart grid investment position -- the pre-investment cost of equity, not a lower cost of equity. 2. Relation to pre-approval A rider's risk-effect can vary with the nature of any associated pre-approval. Consider two of these variations: pre-approval with cost caps, and pre-approval with prudence review. a. Pre-approval with cost caps A pre-approval can take at least six forms, each having a different risk effect relative to the status quo: 1. pre-approval of an action, with the appropriateness of costs determined later ii. pre-approval of a specific cost level, "hard-capped," where the utility must bear any overage but can keep the underage iii. pre-approval of a specific cost level, "hard-capped," where the utility must bear any overage but must provide any underage to the customers 1v. variations of the preceding two options, where the utility and customers "share" in deviations according to pre-set percentages v. pre-approval of a specific cost level, "soft-capped," where the utility can request an increase in the cap but is not guaranteed. (A variation on the soft cap involves the Commission stating, in advance, that amounts above the soft cap will be recoverable only if the total does not exceed the cost of 10 Attachment BEL-5 Cause No. 44988 Page 11 of22 the least cost prudent alternative. In this situation the company has performance risk.) v1. pre-approval of all prudent costs, unknown at the time of the approval, but whatever they may be While a soft cap preserves the utility's right to seek more costs later, that right creates no more certainty than what the utility had without pre-approval. The effect of a soft cap is to guarantee recovery of the amounts up to the soft cap (which makes the term "soft cap" a complete misnomer; it's a hard floor, not a soft cap.) Provided the guaranteed amount is not different from what a prudent utility would have received at the back end, there is no shifting of risk and therefore no reduction in the cost of equity. b. Pre-approval with prudence review Does the rider make recovery automatic, or is recovery subject to a prudence or reasonableness review? If there is a prudence review, consider then the process and timing of that review. Does the review occur ( a) before project commencement, (b) throughout the project, or only ( c) after project completion? And is the "review" only an informal staff review and sign-off, reactive and unassisted by experts with experience comparable to the utility's experts; or is it a formal Commission review with expert testimony? Assuming a front-end review that is no less rigorous than a back-end review, there is no reason to assume that business risk shifts from shareholders to ratepayers. The front-end review reduces investor uncertainty, but that investor gain does not come at the customer's expense. One exception is the extent to which the company was historically at risk for a "used and useful" disallowance; i.e., a situation in which an investment prudently chosen, planned and implemented turns out not to be needed. Statutes permitting, commissions have the legal authority to disallow such prudent costs. See Duquesne Light Co. v. Barasch, 488 U.S. 299 (1989). Commissions vary in their tendency to use this authority. Indeed one reason for pre-approval statutes is to encourage, authorize or require the Commission not to use such authority. There is a legitimate debate over whether a front-end review is as rigorous as a back-end review. If there is a difference, with front-end review less rigorous, the result could be a shifting of risk (to customers) rather than a lessening of overall risk. 3. Balanced or unbalanced? Reducing authorized ROE, relative to what it would be absent the rider, makes sense if the rider is more likely to ease a utility's cost recovery than to impede it. That depends on whether the rider is balanced or unbalanced. Consider two types of balance: balance relative to other accounts in the test year; and balance within the rider itself. 11 Attachment BEL-5 Cause No. 44988 Page 12 of22 a. Balance within the pro forma test year A utility with riders receives its revenue requirement from two sources: its riders, and its base rates. Some riders, such as fuel clauses, tend to be permanent. Other riders are temporary, expiring either because (a) their associated costs become fully recovered (plant construction is completed), or (b) the commission "rolls" the rider costs into base rates in the next general rate case. The question of balance discussed next applies to riders which remain in place, i.e., are not rolled into base rates, even as a general rate case sets new rates. A rider's risk-effect depends on the extent to which it upsets the balance embedded in the test year revenue requirement. The purpose of a test year is to predict all costs and sales volumes for the rate year, account by account. Test year theory acknowledges that for any specific account, actual will vary from prediction; but for all accounts overall, overages will balance out underages. A rider removes an account from the test year, creating the possibility of imbalance. Whether imbalance occurs, and its extent, depends on the nature of the associated account and the rider's design. A rider for recovery of new plant construction adds costs; it is unidirectional. Other cost riders, like fuel clauses, are bidirectional -- they can add or subtract from the revenue requirement, depending on how actual fuel costs compare to the base level embedded in the revenue requirement. Some riders pass through both costs and revenues credited to the cost of service, such as clauses that charge customers for the utility's power purchases but credit them for the utility's power sales. Still other clauses reduce the passed-through costs by an amount reflecting the commission's expectations for savings related to those costs. An example is a clause that recovers smart grid investments, net of operational savings expected from the investments. For these bidirectional riders, the question then is whether the probabilities for a positive or a negative effect are roughly equal; in that case the rider does not upset the test year's balance and does not shift risks from shareholder to the ratepayer. Before one can generalize about whether a company's riders shift risk from shareholder to ratepayer, therefore, one must determine if the rider itself has a de-balancing effect on the test year. b. Balance within the rider itself Some riders accompany cost recovery with risk assignment to the utility. OGE's Smart Grid Rider Factor (SGRF) recovers smart grid investment, less an amount of predicted O&M savings from the investment. The company's full cost recovery thus depends on the investment's success. This type ofrider acts as a performance-based rate formula with its own set ofrisks, rather than as an inherent risk-reducer.7 7 The SGRF has a true-up provision, but that provision relates only to the revenues collected to cover estimated costs; the guaranteed O&M reduction is a guarantee unaffected by 12 Attachment BEL-5 Cause No. 44988 Page 13 of22 4. Method of cost recovery Does the rider recover the costs based on customer consumption; that is, is it a per-kwh or per-mcf charge? If so, then absent a true-up feature, the rider will under- or over-recover costs as actual consumption varies from predictions, leaving both parties at risk. If, however, the rider has a true-up feature, then recovery is indifferent to consumption, lowering the risk of non-recovery. Alternatively, does the rider recover costs on a per-customer basis rather than on a per-consumption basis? 5. Timing issues a. Existence and frequency of true-up: Is there a true-up, or is the utility bound by initial predictions? Ifthere is a true-up, is it annual, monthly, or at completion of project? Is the true up triggered only when deviations exceed some stated band? b. Timing of recovery: Does the rider recover costs as they are incurred, e.g., monthly, or is there a lag, and if so, how much? c. Growth over time: ls the amount ofrider-protected costs fixed at the front end? Or can the recoverable costs grow over time, with inflation, with an index, and/or as the actual costs grow? d. Time span: For how long will the mechanism be in place? That is, is it permanent, temporary, or subject to periodic review? Is it a one-time mechanism applicable only to a specific type of cost? Some riders expire with the next rate case, at which time the recovery of any remaining costs is no longer as certain as it was with the rider; instead, the cost goes into the general revenue requirement and is recoverable only to the extent that total costs are covered by revenues. Put another way, once the rider expires and the costs enter general rates, the costs are no longer insulated from the many risks that affect utility profitability. The shorter the time span, the lower the rider's risk-reducing effect. e. Investment timeline: For a rider-protected investment, at what point in the investment time line did it come into being? If the utility has almost completed the investment, then the rider's risk-reducing effect is less than if the spending was just beginning. the revenue true-up. That is, at the end of the true-up period, actual costs will be compared to estimated costs; any over- or under-collection will be reflected in the fuel adjustment charge. The guaranteed O&M reduction calculation is separate; the company absorbs the O&M costs if it fails to meet the guaranteed level. 13 Attachment BEL-5 Cause No. 44988 Page 14 of22 6. Extent of commission discretion A legislative command to allow riders creates more certainty, and thus more risk reduction, then situations where the commission has discretion to approve or disapprove these measures. Legislative actions tend to be more permanent than commission actions, leading to more certainty about risk reduction. 7. Conclusion on the rider's specific features A regulator needs to identify the specific risks associated with the rider-related cost, then determine how much the rider reduces those risks. Then we have to look at how this reduced risk compares to the utility's total risk. To use a simple example, if the riders and pre-approvals reduce Risk X by 10%, and Risk X represents 10% of the utility's total risk, on a weighted average basis, then one would reduce the equity risk premium portion of the ROE by an amount equal to 1% [.01= (0.1)(0.1)] times the equity risk premium. If the ROE before adjustment was 12%, consisting of a risk-free rate of 4% and an equity risk premium of8%, the risk-adjusted ROE should be 11.92% [0.1192 = 0.12 - (.08)(.01)]. E. Are there factors external to the riders that affect the company's risk situation? Viewing riders in isolation from other factors can distort a comparison between the rider and non-rider situations. Consider the roles played by a commission's rate practices and a utility's expenditure obligations. 1. Commission rate practices Commission rate practices affect risk. Consider: a. A rider makes less of a difference to risk if general rate cases are filed more frequently, because the lag benefit is less. b. A rider makes less of a difference where the jurisdiction frequently uses deferrals to preserve the possibility of recovering past expenditures in prospective rate cases. c. A pre-approval in an environment where the commission applies intensive scrutiny to expenditure prudence makes more of a different to risk than one in an environment where the commission is generally deferential to utility spending decisions. 14 Attachment BEL-5 Cause No. 44988 Page 15 of22 Combining these factors in different ways creates different risk situations. Here are two poles: a. Ifthe utility files frequent rate cases, and the commission allows deferrals and regularly approves cost recovery of utility expenditures, a rider has less risk-reducing effect because the risk is already relatively low. b. Ifthe utility files infrequent rate cases, and the commission limits deferrals while subjecting expenditures to intensive review, a rider has more risk-reducing effect because the pre-rider risk is relatively high. 2. Utility's expenditure obligations A company chooses utility status voluntarily, but once it does it is no longer a volunteer. It has an obligation to serve: an obligation to make all expenditures necessary to meet load, present and future. Investors' willingness to put their money in a particular utility is affected by that utility's future investment needs. Thus a utility facing obligatory capital expenditures faces more risk than a utility with sufficient resources for the foreseeable future. And if those capital expenditures will become necessary before the next rate case, those expenditures are at risk of later disallowance. These risks associated with future expenditures are not mitigated by riders associated with current expenditures; yet the future risks affect the cost of equity. As Pierce and Gellhorn state, "the risks and rates of return relevant to determining the appropriate rate of return to allow a regulated firm [to earn] in the future are the future risks and rates ofreturn on comparable· investments." R. Pierce and E. Gellhorn, Regulated Industries 139 (1999) ( emphasis in the original). Future risks involve not only construction expenditures, but business strategy. Utilities face an uncertain future: What form will carbon pricing take? Will nuclear power solve its safety problems? Will there be a skilled utility workforce when today's veterans retire? Will smart grid address consumers' needs? Their obligation to serve requires utilities to respond to these uncertainties by taking actions with uncertain results. Failure to move in some new direction means exposing the company to future pollution regulation, shortages in skilled labor, and customer demands for more ways to control their consumption. Inaction poses no less risk than action. Given the unavoidability of uncertainty, it makes sense to find ways to manage that uncertainty. Accompanying new uncertainties with new means of risk reduction does not necessarily lower the total risk of the company below what it was before the risks arose; it may only offset the new risk the company takes on. 15 Attachment BEL-5 Cause No. 44988 Page 16 of22 III. A utility's riders should lower its ROE position within the zone of reasonableness only if its riders reduce risk more than the proxy companies' riders do Three methods for estimating a utility's cost of equity -- discounted cash flow, capital asset pricing model and comparable earnings -- use proxy groups. The search for proxies involves identifying companies with similar risk profiles. Each method produces a zone of reasonable RO Es. If an analyst is going to adjust a utility's position within that zone based on the utility's riders, she must examine the riders of the proxy group's members. If the proxy group had riders similar to the utility at issue, the risk reduction effect would already have been captured in the zone of reasonableness produced by the proxy companies. There would be no logical basis for moving the utility downward. The problem is that what is "similar" itself invo Ives multiple judgments. The dimensions of similarity include all the factors discussed in Part II above: type of cost, type of risk, relative size, balancing effect, method and timing of cost recovery, extent and timing of prudence review, and type of true-up mechanism. In particular, if a proxy group member had decoupling of revenues from profits, it would have reduced the risk of consumption risk to near zero. Alabama Power has a formula rate, meaning that its entire revenue requirement is trued up to ensure it receives the authorized ROE. A careful comparison of utility riders to proxy group riders avoid ROE adjustments that are unsubstantiated. But that raises a knottier issue: Who has the burden to make the comparison? The utility, such that failure to show similarity means its authorized ROE is reduced? Or the intervenors, such that failure to show that the utility's riders reduce risk more than the proxy groups' means no downward adjustment? Simply picking a side to bear the burden does not solve the problem, because the commission has its own burden: It must set a revenue requirement, and it must support its decision with substantial evidence regardless of who has what burden. Ratemaking is not like a criminal trial, where the burden of proof assigns the risk of nonpersuasion, thereby relieving the court of having to find the ultimate fact. The prosecution has the burden of proving guilt beyond a reasonable doubt. Failure to prove guilt beyond a reasonable doubt means a failure to persuade. Since the prosecution bears the risk of nonpersuasion, the prosecution loses, resulting in acquittal. The trier of fact does not have to find the ultimate fact, i.e., whether the accused committed the crime. It simply finds the burden unmet, and the accused goes free. Ratemaking does not work that way. For the authorized ROE, the commission has to pick a number, based on substantial evidence. The commission cannot use burdens to avoid its obligation to find facts. The commission cannot make either of the following statements: "The zone ofreasonableness is 9.5% to 11.0%. Because the utility failed to show its riders were similar to those in the proxy group, we pick 9.5%." 16 Attachment BEL-5 Cause No. 44988 Page 17 of22 "The zone ofreasonableness is 9.5% to 11.0%. Because the intervenors failed to show that the utility's riders reduced risk more than those in the proxy group, we pick 11.0%." Unable to avoid its own evidentiary obligation by assigning the risk of nonpersuastion, a commission should require all parties to address the question. This approach supports the goals of clarity and transparency. As with any evidentiary contest, the prize will go to the party who works hardest to prove its point. The party that systematically collects, analyzes and compares rider information for the utility and the proxy group will be more persuasive than the party who generalizes. This approach gives the commission a richer, more thoughtful record for its decision. One might argue that as long as the authorized ROE is within the zone, a commission has full discretion to place it anywhere. That is incorrect. A commission does have discretion within the zone, but it cannot exercise that discretion arbitrarily or in disregard of other statutory principles. The Federal Power Commission learned this lesson the hard way, in Conway Corporation v. F.P.C., 426 U.S. 271 (1976). Captive wholesale municipal customers protested their utility wholesale rate hike, citing "price squeeze." The wholesale customers were also the utility's competitors for retail load. They asserted that the utility's wholesale rate hike was an attempt to squeeze them out of competing for industrial retail load. They said the FPC should take into account this anti-competitive effect when determining where, within the zone of reasonableness, to set the utility return on equity. The FPC declined, asserting that retail rates fell outside its jurisdiction over wholesale rates. The Supreme Court reversed. In exercising its discretion within the zone of reasonableness, the FPC was not allowed to ignore anticompetitive effects: "The Commission must arrive at a rate level deemed by it to be just and reasonable, but in doing so it must consider the tendered allegations that the proposed rates are discriminatory and anticompetitive in effect." 426 U.S. at 278. While the FPC had no authority to order a change in retail rates, it did have the authority to set the jurisdictional (wholesale) rate at a lower level within the zone of reasonableness, so as to remedy any discriminatory or anti-competitive effects of a higher rate on the retail market. Conclusion Estimating cost of equity requires multiple judgments. Rarely do expert witnesses agree on methods, data, assumptions, proxies and groups. With luck, their zones of reasonableness will overlap, allowing a commission to base its decision on the expert evidence while minimizing the risk of judicial review. When statutes and rules vary from traditional test year treatment, by introducing riders, trackers, surcharges, pre-approvals and/or decoupling, the estimation difficulty grows. Proxy groups become difficult to use because comparability -- the lodestar in the search for cost of 17 Attachment BEL-5 Cause No. 44988 Page 18 of22 equity- becomes elusive. The number of variations, including their possible combinations and interactions with each other and with external factors, nears infinity. Facing these difficulties, it is tempting to "pick a number" large enough to be tangible and small enough to avoid appeal. This paper, while sympathetic to commission workload, recommends that witnesses and decisionmakers identify and weigh as many relevant factors as possible before choosing a number. Doing so will advance the goals of transparency, precision and credibility. 18 Attachment BEL-5 Cause No. 44988 Page 19 of22 Appendix Examples of Cases Addressing Rider Effects on Authorized Return on Equity Southwest Gas Corporation, 277 P.U.R4th 182, 2009 WL 3807620 (Nev. PSC 2009) Southwest's rate hike request included a proposal for decoupling revenues from costs. The utility proposed a limited, 10 basis point reduction in ROE because the majority of utilities in the proxy group had weather or conservation mitigation measures. The utility also described a survey of 26 gas decoupling programs, arguing that the programs had sufficient variation in the resulting revenue stability to allow comparison. The study showed that"[ o ]f the 26 utilities, 17 utilities made no explicit acceptance or rejection of an ROE reduction." (Commission summary of Southwest's statements). The study further showed, according to the Commission's summary, that "ROE reductions that have accompanied decoupling range from O basis points to 25 basis points with a simple average reduction of 12.5 basis points." Southwest also cautioned that not every reduction in shareholder risk is an increase in customer risk. The Commission Staff recommended a decoupling-based reduction of20 basis points (from a base of 10.20 percent). Relying on other commission decisions is problematic, Staff argued, because they address multiple issues at once. The Bureau of Consumer Protection recommended a 50 basis point reduction, because, in the Commission's paraphrasing, it "represents less than three percent of the revenue stream being guaranteed by customers." The BCP noted that Southwest would benefit from full decoupling, whereas some of the proxy companies had only weather adjustments; and that its 50 basis point proposal did not account fully for the difference between full and partial decoupling. After finding a 10.40% ROE reasonable, the Commission reduced it 25 basis points to 10 .15% to account for decoupling. The Commission criticized the utility's reliance on other states' practices because the "do not inform the Commission as to the meaning and interpretation of the statute in this jurisdiction. Southwest was unable to distinguish between Nevada's decoupling mechanism and that of other states." Other than stating that its 25 basis point reduction was within the range proposed by Staff and BCP, the Commission did not explain how it arrived at the number. California-American Water Service Co.,_2007 WL 1434942 (Cal.P.U.C. 2007) California-American Water Company and the Division of Ratepayer Advocates (DRA) negotiated a proposed Water Revenue Adjustment Mechanism (WRAM) and Modified Cost Balancing Account (MCBA). The Commission stated that if it approved these two mechanisms, their risk reduction would require a 50 basis point reduction from 10.0% ROE to 9.5%. (DRA had recommended a reduction of 156 to 328 basis points while Cal-Am recommended no adjustment.) The Commission called the plan's risk reduction "substantial," citing the guaranteed 19 Attachment BEL-5 Cause No. 44988 Page 20 of22 cost recovery authorized to protect the utility's fiscal health in light of state effects to increase water conservation and the historic variability of annual water usage in the utility's service area. The Commission arrived at the 50 basis point figure after comparing the WRAM and MCBA to previous cases and adjustments. Potomlic Electric Power Company, 258 P.U.R.4th 463 (Md.P.S.C. 2007) PEPCO asked the Maryland Commission for a rate adjustment that included an 11 % ROE and a Bill Stabilization Adjustment (BSA). The BSA would decouple revenues from sales, and smooth out weather-induced bill differences. PEPCO's witness had proposed an 11.0% ROE, reduced to 10.75% due to the BSA. People's Counsel's witness proposed 9.78%, reduced to 8.97% to reflect the BSA. The Commission adopted the BSA, found a 10.5% ROE to be reasonable, and then lowered the ROE by 50 basis points due to the BSA. The Commission explained: "[Decoupling] will provide insurance that Pepco will achieve its level ofrevenue approved in this case. Thus, Pepco is less risky with the BSA than without it. In response to this decline in risk, all parties recognize the appropriateness of reducing Pepco's return on equity by some amount. The Commission rejects both the minimal reduction of basis points proposed by the Company, and the much larger reductions proposed by People's Counsel. Given that approval of the BSA will result in improved cost recovery by Pepco, the Commission shall reduce Pepco's ROE by 50 points, to 10 percent." Baltimore Gas & Elec. Co., 288 P.U.R.4th 25, 2011 WL 1405143 (Md. PSC 2011) Baltimore Gas & Electric proposed a rate increase with an ROE of 11.65%. The proposal included a decoupling mechanism, called "Rider 25." The mechanism decouples income from changes in customer usage, including changes caused by energy efficiency and conservation programs. The utility proposed no ROE adjustment based on Rider 25, arguing that (a) decoupling mechanisms were already factored into the proxy group; and, alternatively (b) the volumetric risks on both sides of the approved mechanism offset each other. The Commission summarized the BGE expert's position as follows: Dr. Avera claimed that there was no specific support for an ROE decoupling adjustment of 50 basis points. He argued that investors already have factored the impact ofBGE's decoupling mechanism into their calculations, making a further adjustment unnecessary. In addition, Dr. Avera argued that it was inappropriate to adjust utility rates based on just one risk factor, such as revenue decoupling. 20 Attachment BEL-5 Cause No. 44988 Page 21 of22 Another BGE witness, according to the Commission, "stated that' ... decoupling eliminates the upside associated with volumetric risks as well as the downside. 'He also claimed that the effects ofrevenue decoupling were already incorporated into the authorized returns of Dr. Avera's proxy groups." The Commission described the Staff witness's approach as follows (footnotes omitted): Mr. Schultz calculated that Rider 25 provided 3.8% of the Company's distribution revenues during the test year and, by Staffs calculation, bolstered the Company's overall rate of return during the test year by 85 basis points. He therefore considered a 50 basis point reduction to BGE's electric ROE for the effects of decoupling to be reasonable. As Mr. Schultz determined that his gas proxy group already incorporated the effects of decoupling, he did not apply a reduction to his gas ROE. The People Counsel witness also testified that Rider 25 justified a 50% basis point reduction. The Commission ordered an unadjusted ROE of 10.35%; then adjusted the rate downward by 50 basis points to 9.85% to account for Rider 25: We conclude further that the electric ROE should be adjusted downward by 50 basis points to account for the risk-reducing effect of the Rider 25 bill stabilization adjustment. Return on equity is closely linked to risk. It is a truism that the higher the risk, the higher the potential return. BGE is a monopoly distribution-only utility with a risk-reducing mechanism in Rider 25. As such, it cannot have protection against revenue volatility without that protection being reflected in its return on equity. BGE's Rider 25 increases the predictability of BGE's revenues, thereby significantly reducing its financial risk. It would not be reasonable for the Commission to ignore this fact in establishing BGE's ROE. We view this adjustment as simply a way to more accurately gauge and represent BGE's genuine level of risk. The Commission also rejected BGE's view that the proxy group's ROEs already reflected similar riders: BGE witness Avera offered that his utility proxy group companies already reflect reduced ROEs for revenue decoupling mechanisms, and that BGE's ROE should not be further reduced. This assertion, however, is not supported by the record evidence in this case. Rather, Dr. Avera's own testimony shows that only 4 out of the 13 companies in his utility proxy group have a revenue decoupling mechanism (termed 'RDM' by Dr. Avera). Further, many of the companies in his proxy group receive a majority of revenue from generation; thus decoupling applied to their distribution business would have a smaller impact on overall ROE than in 21 Attachment BEL-5 Cause No. 44988 Page 22 of22 BGE's case. There would be an even smaller and less material effect on the electric ROE if the RDM were applied only to their gas distribution business, where RDM is much more common. 22 Attachment BEL-6 Cause No. 44988 Cause No. 44988 Page 1 ofl Northern Indiana Public Service Company's Objections and Responses to Indiana Office of Utility Consumer Counselor's Set No. 8 OUCC Reguest 8-002: Please explain Mr. Rea's rationale for using a proxy group derived from companies with the Value Line industrial classification of "Electric Utility11 in this cause. Objections: Resnonse: In selecting a utility proxy group, Mr. Rea's objective was to identify a group of publicly-traded combination gas and electric utility companies with risk characteristics similar to NIPSCO. This approach is consistent with the Commission's past directive1 with regard to rate proceedings for the gas distribution operations of integrated gas and electric utilities, such as NIPSCO. It has been Value Line's historical practice to classify the combination gas and electric utilities that it evaluates in its "Electric Utility11 category. 1 See, Re Petition of Southern Indiana Gas and Electric Company; Cause No. 43112 (IURC 08/01/2017), at 29. Attachment BEL-7 .------.------,------,-----,-,----~-----.--...CauseNo 44988 ,~AJ'MQ~f~E_llGJ_C_Q-,--R_n---.-----.-_l...,..REC-ENT_!l1--.-1l~--,E I'\ r. NYSE-ATO PRICE , RATIO ,-2l!tTr---.ailin-g:2_4.7)-+-RE-LAT---,.IVE_1_1!~D~--rD , Median: 16.0 PIE RATIO , YLD _2~2.----o//(0 J1!W;111~ Pagel of6 TIMELINESS 2 Raised 11 13117 High: 33.1 33.5 29.3 30.3 32.0 35.6 37.3 47.4 58.2 64.8 82.0 91.0 Target Price Range Raised ~~~~NDS25.5 23.9 19.7 20.1 25.9 28.5 30.4 34.9 44.2 50.8 60.0 72.5 2020 2021 2022 SAFETY 1 616114 TECHNICAL 3 Raised 12/1/17 - dia~:d~vi1~1~~ ~le ,,·'--1'"...,>..,,_.··--1---;----1---;----11----+---t----+---t----+---t----+---t-160 • • • • Relative ~nee Strength 'i...'1 :/? 120 BETA .70 (1.00=Market) O.fil:ons: Yes . 5, •···· •···· ,-22lOi22:if.0-122fiiiPRRIO:f.JJEE:CC~T~IO~N~SCj!!}_h•~de~dt•re~a!:!i~nd~ica~te~s~re:§cess~io;n~=t~·•t=,=t==t==t=:=t==t==t=:~1_.....~~--d;::.;;,.,~.•t==t==t··:·~-~-t-·'.::·'.:'.·~-t~~O Ann'I Total : .;f ,,\::: :':f! /...... _ ~ •1" 1111 '"-••••• Price Gain Return l---+--+---4~;:;;.+--+--+--+-----:r'F-...... ::i,,..._-i-_-==-~--.,rf.Ul---+--=-=4:..:..._+-_-+__ +-_-+60 High 115 (+30%) 9% .,,,;"• ·"1 / ,I lt•.,,II 50 Low 95 (+5%) 4% ' .. S i,.. -- " " " '' 40 Insider Decisions ,. , ,. ; J ~ --';._,:',/, 1111 ,•,11 11 1 , 11111111 30 J F M A M J J A S ' 1' 11 "' 1' II I; 1.)1 :'co:1 11 •' ill" loBuy O O O O O O O 1 O •••"~•• ••,.• •·; '• IJll'.; '""•••• , ....••• 20 •-· .. Options 2 2 o 2 7 o 2 O O ',,... , ··c,, ··, '. ,!Q2016 1Q2017 2Q2017 Percent 24 :S;;ijji +±f;~-;+..,'t------_--;+_-_-.~.,..--fl+_-_-_-_-.,+_-_-_-_-.,t,-t----.,-.,t-,--~-;--t":------t------t------~I I STOCK INDEX - ~:~ri m i~~ m shares 16 ~ ... , I I ,, I.I I II .11 i~;: m ~+:6 Hld'slOOOI 76006 85813 84773 traded 8 111111111111 111111111 Ill 5yr. 179.6 92.9 Atmos Energy's history dates back to 2007 2008 2009 2010 2011 2012 2013 2014 2015 2016 2017 2018 @ VALUE LINE PUB. LLC 0-22 1906 in the Texas Panhandle. Over the 66.03 79.52 53.69 53.12 48.15 38.10 42.88 49.22 40.82 32.23 26.05 28.00 Revenues per sh A 45.85 years, through various mergers, it became 4.14 4.19 4.29 4.64 4.72 4.76 5.14 5.42 5.81 6.19 6.60 6.90 "Cash Flow'' per sh 7.55 part of Pioneer Corporation, and, in 1981, 1.94 2.00 1.97 2.16 2.26 2.10 2.50 2.96 3.09 3.38 3.60 3.80 Earnings per sh As 4.50 Pioneer named its gas distribution division 1.28 1.30 1.32 1.34 1.36 1.38 1.40 1.48 1.56 1.68 1.80 1.94 Div'ds Decl'd per sh c,, 2.30 Energas. In 1983, Pioneer organized 1--~4_=39-~5~,2~0+-~5.~51.-+-~=+~=-<1--~-+-~....+-~=-+~~-.~-~=+--1=2.=25--ca-p~'I 6.02 6.90 8.12 9.32 8.32 9.61 10.46 10.75 S~p-en_d,,...in~g p-e-rs~h--12~.7=--15 Energas as a separate subsidiary and dis- 22.01 22.60 23.52 24.16 24.98 26.14 28.47 30.74 31.48 33.32 36.80 37.00 Book Value per sh 38.50 tributed the outstanding shares of Energas 1---,8~9_=33-=90~.8~1~9=2.=55-+-~-=-+~-=-=-1f---,.,~+-s~.+-~,.,,..+-~+-,.,~c-1-c-,.,+~11=0.=oo,+.,co_m_m_o_n 90.16 90.30 90.24 90.64 100.39 101.48 103.93 106.00 s=h'-s =ou_ts_t'_g= 0 -+-1=20~.o,.,....Jo to Pioneer shareholders. Energas changed 15.9 13.6 12.5 13.2 14.4 15.9 15.9 16.1 17.5 20.8 22.0 Avg Ann'I PIE Ratio 23.5 its name to Atmos in 1988. Atmos acquired .84 .82 .83 .84 .90 1.01 .89 .85 .88 1.09 1.09 Relative PIE Ratio 1.45 Trans Louisiana Gas in 1986, Western Ken- 4.2% 4.8% 5.3% 4.7% 4.2% 4.1% 3.5% 3.1% 2.9% 2.4% 23% AvgAnn'IDiv'dYield 2.2% lucky Gas Utility in 1987, Greeley Gas in t-5-8-98-.4-+-72-21-.3-+-4-96-9.-1 +---+---+---+--+----11---+--+---+--3-08-0+R-ev~e-nu-es-($_m_ill_)A--+-55-0--104789.7 4347.6 3438.5 3886.3 4940.9 4142.1 3349.9 2759.7 1993, United Cities Gas in 1997, and others. 170_5 180_3 179_7 201.2 199.3 192.2 230.7 289.8 315.1 350.1 382.7 420 Net Profit($mill) 540 CAPITAL STRUCTURE as of 6/30/17 35.8% 38.4% 34.4% 38.5% 36.4% 33.8% 38.2% 39.2% 38.3% 36.4% 36.6% 37.0% Income Tax Rate 40.0% Total Debt $3325.3 mill. Due in 5 Yrs $1600.0 mill. 2.9% 2.5% 3.6% 4.2% 4.6% 5.6% 5.9% 5.9% 7.6% 10.5% 13.9% 13.6% Net Profit Margin 9.8% LT Debt $3066.7 mill. LT Interest $170.0 mill...... ,,52-.0-%.,...... ~50-_8-%-, +-,49-.9-%-, +-,~,-+...,...,~+---,-,,-+-,-,...,...,+----,-,--+~~+---~,..+-~+---44-.-0%-,-+L-o-ng---Te_nn_De~b-t45.4% 49.4% 45.3% 48.8% 44.3% 43.5% 38.7% 44.0% Ra-t1- 0 ---+-45-.0~%,...., (LT interest earned: 5.8x; total interest 48_0", 49_2", 50_1", 55.0% coverage: 5.8x) 1--""'""-+~""".c.+..c..:..:.;.,;".:.+-""-="-+""""'"-+..:..:.cc..:..:...+c.;_;:;_;c..+.c.c;,c..:..:...+...:=c:..+....:.c.=+.:-=c:..+....:5c.:.6.ccO%c.:.,+C"-'o"'m"'m;,:oc.:.n.:cEqi:1u:,:city,__Ra=-=tic:.o---1--"'"""";_i54.6% 50.6% 54.7% 51.2% 55.7% 56.5% 61.3% 56.0% Leases, Uncapitalized Annual rentals $17.1 mill. 4092.1 4172.3 4346.2 3987.9 4461.5 4315.5 5036.1 5542.2 5650.2 5651.8 6965 7270 Total Capital ($mill) 8400 Pfd Stock None 3836.8 4136.9 4439.1 4793.1 5147.9 5475.6 6030.7 6725.9 7430.6 8280.5 9260 9885 Net Plant($mill) 11500 Pension Assets-9/16 $474.0 mill. 5.9% 5.9% 5.9% 6.9% 6.1% 6.1% 5.9% 6.4% 6.6% 7.2% 7.0% 7.0% Return on Total Cap'I 8.0% Oblig. $545.5 mill. t--8~.7=%-, +-8-.8-%-, +-8-.3-%-, +--.-+--+----+--+----+--+--,..+---+-1-0.-5%-,-+R~e-tu_rn_o_n~S~h~-.9.2% 8.8% 8.1% 8.9% 9.4% 9.9% 10.1% 10.0% ~Eq-u~lty--+-~11-.5~%,...., Common Stock 106,065,596 shs. 8_7", 8_8", 11.5% as of 7/28/17 t---"-+--~"__,__8_.3~%_, +--,-+--+----+--+----+---+--,..+---+-1_0._5%_,-+R~e_tu~m_o~n_C~o_m_E~q1u_ity~-+-----'9.2% 8.8% 8.1% 8.9% 9.4% 9.9% 10.1% 10.0% MARKET CAP: $9.5 billion (Large Cap) 3.0% 3.1% 2.7% 3.5% 3.3% 2.8% 4.0% 4.7% 4.9% 5.1% 5.0% 5.0% Retained to Com Eq 5.5% CURRENT POSITION 2015 2016 6/30/17 65% 65% 68% 62% 62% 65% 56% 50% 51% 50% 50% 51% All Div'ds to Net Prof 51% caJ~Ml;~~ts 28 7 47 5 69 8 t--B-U-SI-N~ES_S_:_A_tm~o-s_E_n-erg~y-Co-r-po~ra-ti-on-is~e-ng-a-ge-d~p-ri-m-an-·1y+-in_th_e--+-m-er-ci-al~;2-%-,,-in-d~us_m_·a-l;-an~d-3- 0/c-, o-t~he-r._T_h_e-co_m_p-an_y_s_ol_d_A~tm_o_s_E_n_,...., Other 602:3 634:2 464:6 distribution and sale of natural gas to roughly three million custom- ergy Marketing, 1/17. Officers and directors own approximately Current Assets 631.0 681.7 534.4 ers through six regulated natural gas utility operations: Louisiana 1.6% of common stock (12/16 Proxy). President and Chief Execu- Accts Payable 238.9 259.4 164.4 Division, West Texas Division, Mid-Tex Division, Mississippi Divi- live Officer: Michael E. Haefner. Inc.: Texas. Address: Three Lin- Debt Due 457.9 1079.8 258.6 sion, Colorado-Kansas Division, and Kentucky/Mid-States Division. coin Centre, Suite 1800, 5430 LBJ Freeway, Dallas, Texas 75240. Other 458.0 449.1 322.7 Gas sales breakdown for fiscal 2016: 67%, residential; 28%, com- Telephone: 972-934-9227. Internet: www.atmosenergy.com. CurrentLiab. 1154.8 1788.3 745.7 t------1 Fix. Chg. Gov. 743% 768% 775% Atmos Energy looks poised to genera- around 18% higher than the prior-year fig- ANNUAL RATES Past Past Est'd •1 4.,16 te respectable results in fiscal 2018. ure, assuming that the midpoint of that ofchange(persh) 10Yrs. svrs. to'20-'22 (Years begin October 1st.) The natural gas range is used. Similar to fiscal 2017, it ap-- Revenues -4.0% -4.5% 2.0% distribution unit, which accounts for the pears that a substantial portion of the re- "Cash Flow" 4.5% 5.0% 4.5% biggest portion of total revenues, stands to sources will be deployed to enhance the Earnings 6.0% 8.0% 6.0% Dividends 2.5% 3.5% 6.5% benefit from increased throughput, assum-- safety and reliability of Atmos' natural gas Book Value 5.0% 5.5% 3.5% ing that both the weather and economic distribution and transmission systems. climate are generally favorable (leading to The quarterly common stock dividend F{!~:1 QUARTERLY REVENUES($ mill.) A {-ull 1 Ends Dec.31 Mar.31 Jun.30 Sep.30 ..}!;: a boost in consumption levels). Moreover, was increased about 7.8%, to $0.485 a 2014 255.1 1964.3 942.7 778.8 4940.9 we expect a decent performance from the share. Furthermore, our 2020-2022 2015 258.8 1540.1 686.4 656.8 4142.1 pipeline & storage division. At this junc- projections show that additional, steady 2016 906.2 1132.3 632.9 678.5 3349.9 ture, Value Line expects the bottom line to hikes in the distribution will occur. The 2017 780.2 988.2 526.5 464.8 2759.7 rise around 6%, to $3.80 a share, com- payout ratio during that span ought to be 2018 800 1030 640 610 3080 pared to the previous year's tally of $3.60. in the neighborhood of 50%, which seems Fiscal EARNINGSPERSHAREABE Full Concerning fiscal 2019, earnings per share manageable. J~3~ Dec.31 Mar.31 Jun.30 Sep.30 F{!~:1 stand to increase at a similar percentage These shares have traded at their 2014 .95 1.38 .45 .23 2.96 rate, to $4.00, as operating margins widen highest level ever since our last full- 2015 .96 1.35 .55 .23 3.09 further. page review in September. We think 2016 1.00 1.38 .69 .33 3.38 A new CEO took command on October that can be traced partially to the compa- 2017 1.08 1.52 .67 .34 3.60 1st. Michael E. Haefner, who had served ny's healthy fiscal 2017 earnings, and ex-- t--20_1_8-+-_1._15__ 1._51 __ ._75 __ .3_9_,__3_.8_0..,. as the chief operating officer, replaced Kim pectations of more glad tidings in the new Cal- QUARTERLY DIVIDENDS PAID c. Full R. Cocklin. Given that the succession pro- fiscal year. As a consequence, the equity is endar Mar.31 Jun.30 Sen.30 Dec.31 Year cess was in the works for some time, we currently ranked 2 (Above Average) for 1-20_1_3-+"e:_"'35'-'--=_"'35=-=_ 3""5=-=_3""7-'-+-1-.4cc.2..j believe the energy company is in capable Timeliness. Other noteworthy character-- 2014 .37 .37 .37 .39 1.50 hands. istics include the top Safety rank and rela- 2015 .39 .39 .39 .42 1.59 The fiscal 2018 capital spending budg- tively high grade (95 out of 100) for Price 2016 .42 .42 .42 .45 1.71 et is anticipated to fall between $1.3 Stability. 2017 .45 .45 .45 .485 billion and $1.4 billion. That would be Frederick L. Harris, III December 1, 2017 (A) Fiscal year ends Sept. 30th. (B) Diluted Next egs. rpt. due early Feb. . I(D) In millions. Company's Financial Strength A+ shrs. Exel. nonrec. items: '07, d2¢; 09, 12¢; (C) Dividends historically paid in early March, (E) Qtrs may not add due to change in shrs Stock's Price Stability 95 '10, 5¢; '11, (1¢). Excludes discontinued opera- June, Sept., and Dec.• Div. reinvestment plan. outstanding. Price Growth Persistence 75 lions: '11, 10¢; '12, 27¢; '13, 14¢; '17, 13¢. Direct stock purchase plan avail. Earnings Predictability 95 " 2017 Value Line, Inc. All rtghts reserved. Factual material is obtained from sources believed to be reliable and is provided without warranties of any ~nd. II! 1111 I THE PUBLISHER IS NOT RESPONSIBLE FOR ANY ERRORS OR OMISSIONS HEREIN. This ublication is strictly for subscriber's own, non-commercial;internal use. No part I 111""'"' I >I":11 • "Hlfl" "' I:111111 of ~ may be reproduced, resold, stored or transmitted in any printed, electronic or other fonn, or useJ for generating or marketing any printed or electronic publication, service or product. Attachment BEL-7 Nn .14988 RECENT 44 30 IP/E 23 8{Trailing: 24.7) RELATIVE 120 DIV'D Page of6 NEW JERSEY RES. NYSE-NJR PRICE , RATIO , Median: 16.0 P/E RATIO , YLD 2.5% TIMELINESS Raised8/25/17 High: 17.7 18.8 20.6 21.2 22.0 25.2 25.1 23.8 32.1 34.1 38.9 45.4 Target Price Range 2 Low: 13.8 15.2 12.3 15.0 16.7 19.8 19.3 19.5 21.9 26.8 30.5 33.7 2020 2021 2022 SAFETY 1 Raised 9/15106 LEGENDS TECHNICAL 3 Lowered 10/27117 - ~i~iid~vi1~~1:sf ~te '--'·,... ·-1-·,,,1--o.o\__,1----1---1----1----,1----1---1----+--+----+--+----+--+-80 BETA .80 (1.00 = Market) 3-for-2.•. • Relativesplit 3/08 Price Strength ~•~~t:~~ , /1==~~::::~::::~:::~~:::~::::j~?-~fn~,--~ 1;;;~;;:;::::;~::::~::::~::::~::::~::::t:60 __ 50 -~20=2=0~22~PR=o~J=E=c=r1=o=N=s--l 2-10r-, SP.lit 3115 < - •:: - • ___. • ·-~"' • 4 • Ann'! Total o~i~~~/t~a indicates recession ',Of;_: ''.,o:' ,,v 11•1"1 111 1''" • ,, 30° Price Gain Return 1 _.,., _·>", . , ,11 ,1 ' 25 ~~ ig 1:18~! .:#. I ·-,'.• ·' • _.-.-, ,;:.;Ill 11111 ''' '"IPJl'I '1 ',, 20 Insider Decisions IJ,.,,.,.,"'-r,rlrn+~1.:..••:..1' 1:r-,11.:..•'_J'111w1.!!.11I;J.JL~'"~,~i£'1~111 f:'li-i,.':=.··_••+'1 _•'_h_l'-+--+---+--+---+--+---t---t---t---t---t--+15 J F M A M J J A S ,.•••••••• ....•••• .., .....-;--::-~;_;;ti :·,;, •••• ••••••••••• • •• ;•.. • ••••••••• ..... ••••••••• toBuy O o o o o a o o o l--==..:;:~...,;~~4::=;~µ.i...-+::::::...:::j.,,C.-!-.::::::::.,b.::---l----:c:-:.-h;-:;,"°'t...:.::_~-f'!::::._:'.:.-J---+---+--+--+10 Options 2 4 o o o o o o a ;.,:/,f:.:,, ... , •• •·••-• ...... :• ·-·.•· toSell O 1 O O O O O O OJ---t--t---,t,;,f,"~'.,·-_;,--t\,,,S·<"l--:.--t--t----t--t-...... :7'.o:..-t----t--t-----t-----j %TOT.RETURN10/17 '-7·5 1 Institutional Decisions ''"''·°'' N' ?:i THIS VLARITH: 4Q2016 1Q2017 2Q2017 Percent 30 1 yr. ST~C1 l~~:;f .. ~:~fi 1 ~~ 1i~ 1~J shares 20 ~ .. 3yr. 65.9 27.5 ~ H~•,iooo• 54513 68340 66939 trad ed 10 IIIIIIIIIUll1lllllllllUllllh 111111111 11 5yr. 134.6 92.9 2001 2002 2003 2004 2005 2006 2007 2008 2009 2010 2011 2012 2013 2014 2015 2016 2017 2018 @VALUELINEPUB.LLC '0-22 25.61 22.06 31.14 30.44 38.10 39.81 36.31 45.37 31.17 32.05 36.30 27.08 38.38 44.40 32.09 21.90 26.28 27.75 Revenues per sh A 29.70 1.06 1.07 1.19 1.25 1.31 1.37 1.22 1.81 1.58 1.63 1.70 1.86 1.93 2.73 2.52 2.46 2.68 2.90 "Cash Flow" per sh 3.25 .65 .70 .79 .85 .88 .93 .78 1.35 1.20 1.23 1.29 1.36 1.37 2.08 1.78 1.61 1.73 1.90 Earnings per sh 8 2.05 .39 .40 .41 .43 .45 .48 .51 .56 .62 .68 .72 .77 .81 .86 .93 .98 1.04 1.09 Div'ds Decl'd per sh C■ 1.12 .55 .51 .57 .72 .64 .64 .73 .86 .90 1.05 1.13 1.26 1,33 1.52 3.76 4.15 2.15 2.20 Cap'I Spending per sh 2.35 4.40 4.35 5.13 5.62 5.30 7.50 7.75 8.64 8.29 8.81 9.36 9.80 10.65 11.48 12.99 13.58 14.40 15.25 Book Value per sh O 17.85 79.99 83.00 81.70 83.22 82.64 82.88 83.22 84.12 83.17 82.35 82.89 83,05 83.32 84.20 85.19 85.88 86.32 86.50 Common Shs Outst'g E 86.50 14.2 14.7 14.0 15.3 16.8 16.1 21.6 12.3 14.9 15.0 16.8 16.8 16.0 11.7 16.6 21.3 22.4 Avg Ann'I PIE Ratio 17.0 .73 .80 .80 .81 .89 .87 1.15 .74 .99 .95 1.05 1.07 .90 .62 .84 1.12 1.17 Relative PIE Ratio 1.05 4.2% 3.9% 3.7% 3.3% 3.1% 3.2% 3.0% 3.3% 3.5% 3.7% 3.3% 3.4% 3.7% 3.5% 3.1% 2.9% 2.7% Avg Ann'! Div'd Yield 3.2% CAPITAL STRUCTURE as of 6/30/17 3021.8 3816.2 2592.5 2639.3 3009.2 2248.9 3198.1 3738.1 2734.0 1880.9 2268.6 2400 Revenues ($mill) A 2565 Total Debt $1347.4 mill. Due in 5 Yrs $450 mill. 65.3 113.9 101.0 101.8 106.5 112.4 113.7 176.9 153.7 138.1 149.4 165 Net Profit ($mill) 180 LT Debt $897.7 mill. LT Interest $31.0 mill. Incl. $46.9 mill. capitalized leases. 38.8% 37.8% 27.1% 41.4% 30.2% 7.1% 25.4% 30.2% 26.3% 15.5% 32.0% 32.0% Income Tax Rate 32.0% {LT interest earned: 7.5x; total interest coverage: 2.2% 3.0% 3.9% 3.9% 3.5% 5.0% 3.6% 4.7% 5.6% 7.3% 6.6% 7.0% Net Profit Margin 7.0% 7.5x) 37.3% 38.5% 39.8% 37.2% 35.5% 39.2% 36.6% 38.2% 43.2% 47.7% 46.5% 45.5% Long-Tenn Debt Ratio 43.0% Pension Assets-9/16 $311.9 mill. 62.7% 61.5% 60.2% 62.8% 64.5% 60.8% 63.4% 61.8% 56.8% 52.3% 53.5% 54.5% Common Equity Ratio 57.0% Oblig. $454.1 mill. 1028.0 1182.1 1144.8 1154.4 1203.1 1339.0 1400.3 1564.4 1950.6 2230.1 2320 2410 Total Capital ($mill) 2720 pfd Stock None 970.9 1017.3 1064.4 1135.7 1295.9 1484.9 1643.1 1884.1 2128.3 2407.7 2455 2505 Net Plant ($mill) 2660 Common Stock 86,538,661 shs. 7.7% 10.7% 9.7% 9.7% 9.7% 9.2% 9.0% 12.1% 8.6% 6.9% 7.4% 8.0% Return on Total Cap'I 7.5% as of 7/31/17 10.1% 15.7% 14.6% 14.0% 13.7% 13.8% 12.8% 18.3% 13.9% 11.8% 12.0% 12.5% Return on 5hr. Equity 11.5% MARKET CAP: $3.8 billion (Mid Cap) 10.1% 15.7% 14.6% 14.0% 13.7% 13.8% 12.8% 18.3% 13.9% 11.8% 12.0% 12.5% Return on Com Equity 11.5% CURRENT POSITION 2015 2016 6/30/17 3.6% 9.5% 7.2% 6.7% 6.2% 6.2% 5.2% 11.0% 7.0% 4.8% 1.8% 6.0% Retained to Com Eq 5.5% ($MILL.) 64% 40% 50% 52% 55% 55% 59% 40% 50% 60% 60% 54% All Div'ds to Net Prof 54% Cash Assets 4.9 37.5 62.2 1-----'---'---.J...---'---"----'---'---'----'---'----'---'------'--- Other 539.6 569.8 575.4 BUSINESS: New Jersey Resources Corp. is a holding company mercial and electric utility, 65% incentive programs). N.J. Natural Current Assets 544.5 607.3 637.6 providing retail/wholesale energy svcs. to customers in New Jersey, Energy subsidiary provides unregulated retail/wholesale natural gas and in states from the Gulf Coast to New England, and Canada. and related energy svcs. 2016 dep. rate: 2.6%. Has 1,034 empls. Accts Payable 273.2 269.8 263 2 Debt Due 77.5 183.2 - New Jersey Nature! Gas had about 521,200 customers at 9/30/16 Off./dir. own about 1.5% of common (12/16 Proxy). Chrmn., CEO & Other 85.4 118.6 4t~:b in Monmouth and Ocean and other N.J. counties. Fiscal 2016 Pres.: Laurence M. Downes. Inc.: NJ Addr.: 1415 Wyckoff Road, Current Liab. 436.1 571.6 775.9 1-v_ol_um_e_:_3_37_b_il_l._cu_._ft_.('-18_%_in_te_rru_;p_ti_bl_e,_1_7°_¼_re_s_id_en_li_al_a_nd_co_m_-_w_a_ll,_N_J_0_7_71_9_. T_e_L_: 7_3_2-_93_8_-1_4_80_._w_e_b:_www __ .n_jr_es_o_ur_ces_.co_m_.___, Fix. Chg. Cov. 1007% 1088% 669% New Jersey Resources posted solid help to expand the companies service terri ANNUAL RATES Past Past Est'd '14-'16 fourth-quarter and fiscal-year finan- tory. boost capacity, and improve system of change (per sh) 10Yrs. 5Yrs. to '20-'22 cial results (ended September 30th). wide integrity and safety. Management Revenues -1.0% -- -1.5% "Cash Flow" 7.0% 9.5% 2.5% To that end, the company's top line ad- anticipates those efforts will eventually Earnings 7.5% 8.0% 2.0% vanced approximately 20%, to $2.27 bil- add 26,000-28,000 new customer accounts Dividends 7.5% 6.5% 3.5% lion, stemming largely from double-digit through 2020. Elsewhere, we look for the Book Value 7.5% 7.5% 6.0% growth at its nonutility business segment. NJR Clean Energy Ventures, Energy Serv Fiscal QUARTERLY REVENUES($ mill.) A I Year r-un Meanwhile, the New Jersey Natural Gas ices, Midstream, and Home Service seg Ends Dec.31 Mar.31 Jun.30 Sep.30 ,}!;~ (NJNG) regulated utility division was also ments to be nicely additive to net earn 2014 878.4 1579.6 688.3 591.9 3738.1 a contributing factor, despite that unit ex- ings. 2015 824.1 1013.1 458.5 438.3 2734.0 periencing slightly more modest revenue Acquisitions augur well for prospects. 2016 444.3 574.2 393.2 469.2 1880.9 gains, of late. That division has been get- Adelphi Gateway, a subsidiary of NJR, has 2017 541.0 733.5 457.5 536.6 2268.6 ting a boost from new customer accounts, entered into an agreement with Talen 2018 575 765 490 570 2400 as well as from higher base rates. Over the Generation to purchase all of Talen's Fiscal EARNINGS PER SHARE A B Full Year Fiscal course of this past 12 months, NJNG add- membership interest in Interstate Energy Ends Dec.31 Mar.31 Jun.30 Sep.30 Year ed 9,126 new meters. On the profitability Company LLC, which owns and operates 2014 .47 1.79 .05 d.23 2.08 front, overall expenses rose 150 basis an 84-mile pipeline in southeastern PA, 2015 .65 1.16 .03 d.06 1.78 points, as a function of revenues. Com- for roughly $166 million. Assuming all reg 2016 .58 .91 .13 d.02 1.61 bined, these factors equated to an almost ulatory approvals are received, this deal 2017 .47 1.21 .20 d.14 1.73 7.5% bottom-line increase, to $1.73 a would add about 250,000 dekatherms of 2018 .51 1.25 .24 d.10 1.90 share. This was in line with our call. natural gas per day to the greater Phila Cal QUARTERLY DMDENDS PAID c ■ Full The company appears poised to regis- delphia market. endar Mar.31 Jun.30 Seo.30 Dec.31 Year ter mid- to high-single-digit revenue At its recent quotation, these shares 2013 -- .20 .20 .20 .60 and earnings gains in fiscal 2018. The appear richly valued. That said, our 2014 .21 .21 .21 .23 .86 regulated utility division has more than Timeliness Ranking System has the equity 2015 .23 .23 .23 .24 .93 $120 million in capital projects planned to pegged to outpace the broader market 2016 .24 .24 .24 .255 .98 support new customer growth in the next averages in the coming year. 2017 .255 .255 .255 .273 three years. Those growth projects should Bryan J. Fong December 1, 2017 (A) Fiscal year ends Sept. 30th. (C) Dividends historically paid in early Jan., Imillion, $5.13/share. Company's Financial Strength A+ (B) Diluted earnings. Qtly egs may not sum to April, July, and October. 1Q '13 div'd paid in (E) In millions, adjusted for splits. Stock's Price Stability 80 total due to change in shares outstanding. Next 4Q '12. • Dividend reinvestment plan available. Price Growth Persistence 55 earnings report due late Jan. (D) Includes regulatory assets in 2016: $441.3 Earnings Predictability 55 © 2017 Value Line, Inc. All nghts reserved. Factual material is obtained from sources believed to be reliable and is provided without warranties of any ~nd. -!Tl•"l- ■ •l:U THE PUBLISHER IS NOT RESPONSIBLE FOR ANY ERRORS OR OMISSIONS HEREIN This publication is strictly for subscnber's own, non-commercial, internal use. No part I I I ' • • .,., of ii ma be re roduced, resold, stored or transmitted in any pnnted, electronic or other fonn, or used for eneratin or marketing any pnnted or elec~omc publicaUon, service or product Attachment BEL-7 (;911Q" Nn .:l 4988 RECENT 6615IP/E 28 acrailjng:30.1) RELATIVE 145 DIV'D ' Page. of6 N.W. NAT'L GAS NYSE-NWN PRICE , RATIO , Median: 19.0 P/E RATIO I YLD 2.9% TIMELINESS 4 Lowered 11117117 High: 43.7 52.8 55.2 46.5 50.9 49.0 50.8 46.6 52.6 52.3 66.2 68.6 Target Price Range Low: 32.8 39.8 37.7 37.7 41.1 39.6 41.0 40.0 40.1 42.0 48.9 56.5 2020 2021 2022 SAFETY 1 Raised 3/18/05 LEGENDS - 1.10 x Dividends rsh 120 TECHNICAL Lowered 1113117 divided b~nteres Rate ,,,, - - 100 3 ;' -- • , • • Relative ·ce Strength • ' - --- 80 BETA .70 (1.00 = Market) ,''.'( _/ - O~tions: Yes ·, , -- 64 haded area indicates recession ~ •• ;:;.:.;:. 1111" ------2020-22 PROJECTIONS - "''1·•,,1 .. - - 48 Ann'! Total 1 I (11•· "•'11• ... 11 •111,1111•1 11•• Ill 1,11·· ------Price Gain Return l(tt!'•ll p11•'h111 u,11• 32 High 60 f·10%! 1% 'j .... Low 50 -25% -3% ..... -~···--·······:·· .... .,, ··-······ .. 24 Insider Decisions ····· ...... 20 JFMAMJJAS •""'Ii '·'.'·' ...... 16 ..... • to Buy 0 0 0 0 0 0 0 0 0 '" ,, ...•-··· ······· 12 Options 011 1 1 4 4 0 1 2 to Sell 0 0 3 0 0 6 0 1 3 .,)~ ,,: '',•.. % TOT. RETURN 10/17 -8 Institutional Decisions ,;}~ 'ti" THIS VlARITH." I' STOCK lNDEX 4Q2016 1Q2017 2Q2017 Percent 15 I 106 99 105 I, 1 yr. 16.3 21.4 - shares 1,11,111 ,. - ra:~ri 81 74 86 breded 10mttlllllllll 11,11 3 yr. 56.8 27.5 - Hld's/0001 18267 21952 21864 111111111 tltttllllllllnf'Ill 'dffidt 5yr. 71.7 92.9 2001 2002 2003 2004 2005 20;6 2007 2008 2009 2010 2011 2012 2013 ~014 2015 2016 2017 2018 @ VALUE LINE PUB. LLC 0-22 25.78 25.07 23.57 25.69 33.01 37.20 39.13 39.16 38.17 30.56 31.72 27.14 28.02 27.64 26.39 23.61 26.20 27.10 Revenues per sh 29.65 3.86 3.65 3.85 3.92 4.34 4.76 5.41 5.31 5.20 5.18 5.00 4.94 5.04 5.05 4.91 4.93 5.40 5.15 "Cash Flow'' per sh 6.10 1.88 1.62 1.76 1.86 2.11 2.35 2.76 2.57 2.83 2.73 2.39 2.22 2.24 2.16 1.96 2.12 2.25 2.45 Earnings per sh A 3.15 1.25 1.26 1.27 1.30 1.32 1.39 1.44 1.52 1.60 1.68 1.75 1.79 1.83 1.85 1.86 1.87 1.88 1.89 Div'ds Decl'd per sh Ba 2.00 3.23 3.11 4.90 5.52 3.48 3.56 4.48 3.92 5.09 9.35 3.76 4.91 5.13 4.40 4.37 4.87 6.20 6.45 Cap'I Spending per sh 6.35 18.56 18.88 19.52 20.64 21.28 22.01 22.52 23.71 24.88 26.08 26.70 27.23 27.77 28.12 28.47 29.71 29.95 30.45 Book Value per sh 0 32.25 25.23 25.59 25.94 27.55 27.58 27.24 26.41 26.50 26.53 26.58 26.76 26.92 27.08 27.28 27.43 28.63 29.00 29.50 Common Shs Outst'g c 30.00 12.9 17.2 15.8 16.7 17.0 15.9 16.7 18.1 15.2 17.0 19.0 21.1 19.4 20.7 23.7 26.9 Boldffg res are Avg Ann'I PIE Ratio 17.0 .66 .94 .90 .88 .91 .86 .89 1.09 1.01 1.08 1.19 1.34 1.09 1.09 1.19 1.43 Value Line Relative P/E Ratio 1.05 5.1% 4.5% 4.6% 4.2% 3.7% 3.7% 3.1% 3.3% 3.7% 3.6% 3.9% 3.8% 4.2% 4.1% 4.0% 3.3% estin ates Avg Ann'! Div'd Yield 3.6% CAPITAL STRUCTURE as of 9/30117 1033.2 1037.9 1012.7 812.1 848.8 730.6 758.5 754.0 723.8 676.0 760 800 Revenues ($mill) 890 Total Debt $779.4 mill. Due in 5 Yrs $360.0 mill. 74.5 68.5 75.1 72.7 63.9 59.9 60.5 58.7 53.7 58.9 65.0 72.0 Net Profit ($mill) 90.0 LT Debt $757.4 mill. LT Interest $40.0 mill. 37.2% 36.9% 38.3% 40.5% 40.4% 42.4% 40.8% 41.5% 40.0% 40.9% 35.0% 35.0% Income Tax Rate 35.0% (Total interest coverage: 3.6x) 7.2% 6.6% 7.4% 8.9% 7.5% 8.2% 8.0% 7.8% 7.4% 8.7% 8.6% 9.0% Net Profit Margin 10.6% 46.3% 44.9% 47.7% 46.1% 47.3% 48.5% 47.6% 44.8% 42.5% 44.4% 44.5% 45.0% Long-Term Debt Ratio 45.5% Pension Assets-12/16 $257.7 mill. 53.7% 55.1% 52.3% 53.9% 52.7% 51.5% 52.4% 55.2% 57.5% 55.6% 55.5% 55.0% Common Equitv Ratio 54.5% Oblig. $457.8 mill. 1106.8 1140.4 1261.8 1284.8 1356.2 1424.7 1433.6 1389.0 1357.7 1529.8 1570 1625 Total Capital ($mill) 1775 Pfd Stock None 1495.9 1549.1 1670.1 1854.2 1893.9 1973.6 2062.9 2121.6 2182.7 2260.9 2350 2445 Net Plant ($mill) 2750 Common Stock 28,713,052 shares 8.5% 7.7% 7.3% 7.0% 6.2% 5.7% 5.8% 5.8% 5.5% 5.1% 5.0% 5.5% Return on Total Cap'I 6.5% as of 10/27/17 12.5% 10.9% 11.4% 10.5% 8.9% 8.2% 8.1% 7.6% 6.9% 6.9% 7.5% 8.0% Return on Shr. Equity 10.0% 12.5% 10.9% 11.4% 10.5% 8.9% 8.2% 8.1% 7.6% 6.9% 6.9% 7.5% 8.0% Return on Com Equity 10.0% MARKET CAP $1.9 billion (Mid Cap) 6.0% 4.5% 5.0% 4.0% 2.4% 1.6% 1.5% 1.1% .6% .9% 1.0% 1.5% Retained to Com Eq 3.5% CURRENT POSITION 2015 2016 9/30/17 52% 59% 56% 61% 73% 80% 81% 85% 92% 87% 84% 78% All Div'ds to Net Prof 64% ~MILL.) Cas Assets 4.2 3.5 15.8 BUSINESS: Northwest Natural Gas Co. distributes natural gas to Owns local underground storage. Rev. breakdown: residential, Other 327.9 284.6 183.7 90 communities, 704,000 customers, in Oregon (89% of customers) 35%; commercial, 22%; industrial, gas transportation, and other, Current Assets 332.1 288.1 199.5 and in southwest Washington state. Principal cities served: Portland 43%. Employs 1,092. BlackRock Inc. owns 11.9% of shares; of- Accts Payable 73.2 85.7 87.5 and Eugene, OR; Vancouver, WA. Service area population: 2.5 mill. ficers and directors, 1.5% (4/17 proxy). CEO: David H. Anderson. Debt Due 295.0 93.3 22.0 Other 109.5 95.5 93.5 (77% in OR). Company buys gas supply from Canadian and U.S. Kantor. Inc.: Oregon. Address: 220 NW 2nd Ave., Portland, OR Current Liab. 477.7 274.5 203.0 producers; has transportation rights on Northwest Pipeline system. 97209. Telephone: 503-226-4211. Internet: www.nwnatural.com. Fix. Chg. Cov. 300% 390% 358% Northwest Natural Gas' third-quarter from the Mist Storage project. The ANNUAL RATES Past Past Est'd '14-'16 results were in line with the previous company is in the final stages of building of change (per sh) 10Yrs. 5Yrs. to '20-'22 year. Revenues expanded to $88.2 million, its no-notice natural gas storage facility, Revenues -2.0% -5.0% 2.5% "Cash Flow" 1.5% -.5% 3.5% as growth in the customer base largely off- which will provide ample fuel to Portland Earnings -- -4.5% 7.0% set the effect of warmer temperatures. General Electric in the coming years. The Dividends 3.5% 2.0% 1.0% However, higher maintenance costs caused pipeline construction will likely be com- Book Value 3.0% 2.0% 2.0% losses to reach $0.30 per share during the pleted by the end of 2017, should current Cal- QUARTERLY REVENUES($ mill.) Full quarter. The company appears to be on construction schedules hold. Early in 2018, endar Mar.31 Jun.30 Sep.30 Dec.31 Year track for decent fourth-quarter operations, Northwest ought to start deployment of its 2014 293.4 133.1 87.2 240.3 754.0 as cooler weather takes hold and a bigger reservoir for testing. This capital expan- 2015 261.7 138.3 93.1 230.7 723.8 customer base allows for better fixed-cost sion project is expected to be in service 2016 255.5 99.2 87.7 233.5 676.0 coverage. Thus, we are keeping intact our during the fourth quarter of 2018, and 2017 297.3 136.2 88.2 238.3 760 2017 top- and bottom-line estimates of should allow for a sizable increase in fuel 2018 310 125 110 255 800 $760 million and $2.25 per share, respec- sold. We believe this will be a major factor Cal- EARNINGS PER SHARE A Full tively. that will drive earnings to $3.15 per share endar Mar.31 Jun.30 Sep.30 Dec.31 Year Near-term performance will be driven by the 2020-2022 period. 2014 1.40 .04 d.32 1.04 2.16 by growth in the coverage area. New Shares of Northwest Natural Gas are 2015 1.04 .08 d.24 1.08 1.96 housing permits were up 6% in the cover- unfavorably ranked for Timeliness (4). 2016 1.33 .07 d.29 1.00 2.12 age area, while unemployment rates con- Although we project significant earnings 2017 1.40 .10 d.30 1.05 2.25 tinue to be low. This likely drove up the growth out to 2020-2022, we think a lot of 2018 1.45 .10 d.25 1.15 2.45 population in the Portland area. In addi- this is priced into the stock already, given Cal- QUARTERLY DIVIDENDS PAID 8 ■ Full tion, more households are being fueled by the high price-to-earnings multiple. Still, endar Mar.31 Jun.30 Seo.30 Dec.31 Year natural gas, which ought to drive its usage interest-rate increases could hamper this. 2013 .455 .455 .455 .460 1.83 higher. Better operations will allow for However, the yield is decent, and the pay- 2014 .460 .460 .460 .465 1.85 greater fixed-cost coverage. This will likely out ought to grow at a much faster pace 2015 .465 .465 .465 .4675 1.86 allow for earnings to reach $2.45 per share starting in 2019. Too, Northwest is ranked 2016 .4675 .4675 .4675 .470 1.87 in 2018 . Highest (1) for Safety. 2017 .470 .470 .470 .4725 Long-term operations will benefit John E. Seibert III December 1, 2017 (A) Diluted earnings per share. Excludes non- (8) Dividends historically paid in mid-February, (D) Includes intangibles. In 2016: $357.5 mil- Company's Financial Strength A recurring items: '06, ($0.06); '08, ($0.03); '09, May, August, and November. lion, $12.48/share. Stock's Price Stability 95 6¢; May not sum due to rounding. Next earn- ■ Dividend reinvestment plan available. Price Growth Persistence 15 ings report due in early February. (C) In millions. Earnings Predictability 85 " 2017 Value Line, Inc. All ri&hts reserved. Factual material is obtained from sources believed to be reliable and is provided without warranties of an~ kind. - , THE PUBLISHER IS NOT RESP NSIBLE FOR ANY ERRORS OR OMISSIONS HEREIN. This ublication is strictiy for subscriber's own, non-commercial, imemal use. o part I I I ' • l~:11111'11/l1II l:l ■ rma of it may be reproduced, resold, stored or transmitted in any primed, electronic or other fmn, or useJ for generating or marketing any printed or electronic publication, service or product. Attachment BEL-7 ,a Nn 4 4988 IRECENT 32 39 IP/E 25 g{trailing:28.2) RELATIVE 130 DIV'D ' Page, of6 SOUTH JERSEY INDS. NYSE-SJI PRICE , RATIO , Median: 18.0 PIE RATIO I YLD 3.5% TIMELINESS 4 Raised 6/30/17 High: 17.1 20.6 20.3 20.4 27.1 29.0 29.0 31.1 30.6 30.4 34.8 38.4 Target Price Range Low: 12.8 15.6 12.6 16.0 18.6 21.4 22.9 25.3 25.9 21.2 22.1 31.4 2020 2021 2022 SAFETY 2 Lowered 1/4/91 LEGENDS - 1.00 x Dividends f sh ,• TECHNICAL Raised 11124/17 divided bp lnteres Rate 80 2 • , • • Relative rice Strength BETA .85 (1.00 ° Market) 2-for-1 split 7/05 60 2-for-1 split 5/15 0 , •• ' --- 50 2020-22 PROJECTIONS ,,,.__ c..--r . . 0 . 40 Ann'I Total ~t~~~d ~~~a indicates recession . ,, 11lll1llJ111·- .. -.. -...... Price Gain Return ./ ,,. 30 I 1Jl!.#I' II I , ... , p11'JIJI ,,, ,, ,Pl High 35 (+10%! 6% "' 25 Low 25 (-25% -1% .. .IW-- I I 20 .11 1111''' 1 ~,11 Insider Decisions .I t'1J.1L -·· 15 J F M A M J J A s ·•IJl .. 1'11. 1111 111 ,:;-•••- •• 1 ...... ···•····· ·... •······ toBuy 00000 0 0 0 0 ...... cc ········· 10 Options 20 o 10 o a 0 0 a o ...... ········· ··-····. >-7,5 to Sell a o o 1 o 0 a 0 0 ········· % TOT. RETURN 10/17 Institutional Decisions THIS VLARITH.• 4Q2016 1Q2017 2Q2017 I STOCK INDEX Percent 15 11 1 yr. 18.2 21.4 ... to Buy 100 92 101 shares 10 - ~ I ,l,.11111 .I II ,I 3yr. 29.2 27.5 lo Sell 89 95 85 traded ""' ~ Hld's/000 56733 66551 66240 5 i 11111111111111 1111111111 11111 5 yr. 59.9 92.9 2001 2002 2003 2004 2005 2006 .WW2007 2008 2009 2~10 2011 2012 2013 2014 2015 2016 2017 2018 @ VALUE LINE PUB. LLC 20-22 17.65 10.35 13.17 14.75 15.89 15.88 16.15 16.18 14.19 15.48 13.71 11.16 11.18 12.98 13.52 13.04 15.25 15.80 Revenues per sh 17.25 .95 1.06 1.12 1.22 1.25 1.75 1.60 1.74 1.86 2.10 2.23 2.34 2.48 2.67 2.42 2.67 2.40 2.70 "Cash Flow'' per sh 3.50 .57 .61 .68 .79 .86 1.23 1.05 1.14 1.19 1.35 1.45 1.52 1.52 1.57 1.44 1.34 1.15 1.45 Earnings per sh A 2.00 .37 .38 .39 .41 .43 .46 .51 .56 .61 .68 .75 .83 .90 .96 1.02 1.06 1.10 1.15 Div'ds Decl'd per sh 8 • 1.30 1.41 1.74 1.18 1.34 1.60 1.26 .94 1.04 1.83 2.79 3.20 4.01 4.84 5.01 4.87 3.50 3.25 3.70 Cap'I Spending per sh 5.35 3.91 4.84 5.63 6.20 6.75 7.55 8.12 8.67 9.12 9.54 10.33 11.63 12.64 13.65 14.62 16.22 15.95 17.00 Book Value per sh c 20.85 47.44 48.83 52.92 55.52 57.96 58.65 59.22 59.46 59.59 59.75 60.43 63.31 65.43 68.33 70.97 79.48 80.00 81.00 Common Shs Outst'g 0 84.00 13.6 13.5 13.3 14.1 16.6 11.9 17.2 15.9 15.0 16.8 18.4 16.9 18.9 18.0 17.9 21.7 Bold fig res are Avg Ann'I P/E Ratio 16.0 .70 .74 .76 .74 .88 .64 .91 .96 1.00 1.07 1.15 1.08 1.06 .95 .90 1.14 Value Line Relative PIE Ratio 1.00 estin ates 4.7% 4.6% 4.3% 3.7% 3.0% 3.2% 2.8% 3.1% 3.4% 3.0% 2.8% 3.2% 3.1% 3.4% 3.9% 3.6% Avg Ann'I Div'd Yield 4.1% CAPITAL STRUCTURE as of 9/30/17 956.4 962.0 845.4 925.1 828.6 706.3 731.4 887.0 959.6 1036.5 1220 1280 Revenues ($mill) 1450 Total Debt $1471.3 mill. Due in 5 Yrs $630 mill. 61.8 67.7 71.3 81.0 87.0 93.3 97.1 104.0 99.0 102.8 90.0 115 Net Profit ($mill) 170 LT Debt $1180.3 mill. LT Interest $40.0 mill. 41.9% 47.7% 23.0% 15.2% 22.4% 10.8% -· -· 5.9% 42.0% 25.0% 25.0% Income Tax Rate 25.0% (Total interest coverage: 2.0x) 6.5% 7.0% 8.4% 8.8% 10.5% 13.2% 13.3% 11.7% 10.3% 9.9% 7.4% 9.0% Net Profit Margin 11.7% Leases, Uncapitalized Annual rentals $.7 mill. 42.7% 39.2% 36.5% 37.4% 40.5% 45.0% 45.1% 48.0% 49.2% 38.5% 48.5% 47.5% Long-Term Debt Ratio 46.0% Pension Assets-12/16 $189.5 mill. 57.3% 60.8% 63.5% 62.6% 59.5% 55.0% 54.9% 52.0% 50.8% 61.5% 51.5% 52.5% Common Equity Ratio 54.0% Oblig. $278.3 mill. 839.0 848.0 856.4 910.1 1048.3 1337.6 1507.4 1791.9 2043.9 2097.2 2475 2625 Total Capital ($mill) 3250 pfd Stock None 948.9 982.6 1073.1 1193.3 1352.4 1578.0 1859.1 2134.1 2448.1 2623.8 2750 2900 Net Plant ($mill) 3500 Common Stock 79,549,080 shs. 8.6% 8.9% 9.0% 9.5% 8.9% 7.4% 6.8% 6.4% 5.4% 5.4% 4.5% 5.0% Return on Total Cap'! 6.0% as of 11/1/17 12.8% 13.1% 13.1% 14.2% 13.9% 12.7% 11.7% 11.2% 9.5% 8.0% 7.0% 8.5% Return on Shr. Equity 9.5% 12.8% 13.1% 13.1% 14.2% 13.9% 12.7% 11.7% 11.2% 9.5% 8.0% 7.0% 8.5% Return on Com Equity 9.5% MARKET CAP: $2.6 billion (Mid Cap) 6.7% 6.7% 6.4% 7.1% 6.7% 5.8% 4.8% 4.3% 2.8% 1.6% .5% 1.5% Retained to Com Eq 3.5% CURRENT POSITION 2015 2016 9/30/17 48% 49% 51% 50% 52% 55% 59% 61% 71% 80% 98% 81% All Div'ds to Net Prof 64% ($MILL) Cash Assets 3.9 18.3 13.7 BUSINESS: South Jersey Industries, Inc. is a holding company. sey Exploration, Marina Energy, South Jersey Energy Service Plus, Other 427.4 455.0 309.8 Subsidiary South Jersey Gas Co. distributes natural gas to 377,625 and SJI Midstream. Has about 750 employees. Off./dir. own less Current Assets 431.3 473.3 323.5 customers in New Jersey's southern counties. Gas revenue mix than 1% of common; BlackRock, Inc., 11.6%; The Vanguard Group, Accts Payable 186.4 243.7 208.0 '16: residential, 42%; commercial, 21%; cogeneration and electric Inc., 9.0% (3/17 proxy). Pres. & CEO: Michael J. Renna. Chairman: Debt Due 461.2 528.0 291.0 Other 184.9 180.9 185.2 generation, 16%; industrial, 21%. Nonutility operations include: Walter M. Higgins Ill. Inc.: NJ. Addr.: 1 South Jersey Plaza, Folsom, Current Liab. 832.5 952.6 684.2 South Jersey Energy, South Jersey Resources Group, South Jer- NJ 08037. Tel.: 609-561-9000. Web: www.sjindustries.com. Fix. Chg. Cov. 496% 602% 174% Shares of South Jersey Industries Prospects appear favorable for the ANNUAL RATES Past Past Est'd '14-'16 have pulled back in price in recent long haul. Utility South Jersey Gas ought of change (per sh) 10 Yrs. 5Yrs. to '20-'22 weeks. The company reported mixed re- to further benefit from an expansion in the Revenues -1.5% -2.0% 4.5% "Cash Flow" 6.5% 4.5% 5.0% sults for the third quarter. Revenue of customer base and investments in infra- Earnings 4.0% 1.5% 5.5% roughly $227 million increased 4% on a structure. On the nonutility side. SJ Ener- Dividends 9.0% 8.5% 4.0% year-to-year basis, and surpassed our ex- gy Group will likely gain from increased Book Value 8.0% 9.0% 6.0% pectation. However, cost of sales increased contributions from fuel supply manage- Cal- QUARTERLY REVENUES($ mill.) Full significantly on the nonutility side, and op- ment contracts. The Penn-East Pipeline endar Mar.31 Jun.30 Sep.30 Dec.31 Year erating expenses were considerably should also support performance. 2014 350.2 133.3 122.4 281.1 887.0 greater. South Jersey posted a share loss This good-quality issue has a number 2015 383.0 177.7 141.1 257.8 959.6 of $0.05 for the recent interim, which was of positive attributes. South Jersey In- 2016 333.0 154.4 219.1 330.0 1036.5 a dime below the prior-year figure. dustries earns good marks for Safety, Fi- 2017 425.8 244.4 227.1 322.7 1220 The company has agreed to acquire nancial Strength, Price Stability, and 2018 440 240 245 355 1280 two entities from Southern Company Earnings Predictability. Volatility is below Cal- EARNINGS PER SHARE A Full Gas. South Jersey will purchase average here, as well. Moreover, the divi- endar Mar.31 Jun.30 Sep.30 Dec.31 Year Elizabethtown Gas and Elkton Gas from dend yield is respectable for a utility. 2014 1.01 .15 d,05 .47 1.57 Southern Company for total consideration But the stock offers limited appeal at 2015 .86 .03 d,07 .62 1.44 of $1. 7 billion. This move will make SJI this juncture. The equity is ranked to lag 2016 .75 .12 .05 .42 1.34 the second-largest natural gas provider in the broader market averages for the com- 2017 .72 .06 d.05 .42 1.15 New Jersey, servicing over 675,000 cus- ing six to 12 months. Moreover, long-term 2018 .78 .10 .03 .54 1.45 tamers. These additions should nicely com- appreciation potential is below average. Cal- QUARTERLY DIVIDENDS PAID 8■ Full plement the company's existing utility as- The valuation remains fairly rich, and the endar Mar.31 Jun.30 Seo.30 Dec.31 Year sets. The deal is expected to close by mid- shares presently trade well within our 2013 .. .222 .222 .458 .90 2018, subject to regulatory approvals. As- Target Price Range. A price pullback some 2014 - . .237 .237 .488 .96 suming this occurs, utility earnings would time in the future may present conserva- 2015 -- .251 .251 .515 1.02 comprise over 80% of total earnings. The tive, income-oriented investors with a 2016 .. .264 .264 .536 1.06 company expects that the transaction will more attractive entry point. 2017 -· .273 .273 .553 be accretive to earnings by 2020. Michael Napoli, CFA December 1, 2017 (A) Based on economic egs. from 2007 on- gain (loss): '08, $0.16; '09, ($0.22); '10, due late February. (B) Div'ds paid early April, Company's Financial Strength A ward. GMP EPS: '08, $1.29; '09, $0.97; '10, ($0.24); '11, $0.04; '12, ($0.03); '13, ($0.24); July, Oct., and late Dec. • Div. reinvest. plan Stock's Price Stability 85 $1.11; '11, $1.49; '12, $1.49; '13, $1.28; '14, '14, ($0.11); '15, $0.08; '16, $0.22. Egs. may avail. (C) Incl. reg. assets. In 2016: $410.7 Price Growth Persistence 30 $1.46; '15, $1.52; '16, $1.56. Exel. nonrecur. not sum due to change in shares. Next egs. rpt. mill., $5.17 per shr. (D) In mill., adj. for split. Earnings Predictability 75 © 2017 Value Line, Inc. All rights reserved. Factual material is obtained from sources believed to be reliable and is provided without warranties of any ~nd. - , , THE PUBLISHER IS NOT RESPONSIBLE FOR ANY ERRORS OR OMISSIONS HEREIN. This ublication is strictly for subscriber's own, non-commercial, internal use. No part I I I ' • ,~:{1111'111'1 II l=-l ll1l- of it may be reproduced, resold, stored or transmitted in any printed, electronic or other form, or used for generating or marketing any printed or electronic publication, service or product. Attachment BEL-7 C'111HlP. No. ,4 4988 DIV'D IRECENT 8213 IP/E 22 5(Trailing:24.2) RELATIVE 113 Page' of6 SOUTHWEST GAS NYSE-SWX PRICE , RATIO , Median: 17.0 P/E RATIO I YLD 2.5%.imal_ TIMELINESS 2 Lowered 11/24n7 High: 39.4 39.9 33.3 29.5 37.3 43.2 46.1 56.0 64.2 63.7 79.6 86.6 Target Price Range Low: 26.0 26.5 21.1 17.1 26.3 32.1 39.0 42.0 47.2 50.5 53.5 72.3 2020 2021 2022 SAFETY 3 Lowered 1/4/91 LEGENDS ------~ 128 TECHNICAL 3 Raised 1211m - di&~:d ~vi1it~~:sr ~te ;;. • • • • Relative Price Strength ';°' ·- . 96 BETA = .. , . . .80 (1.00 Market) --,, '·' ------80 o~g~~~/ir~a indicates recession 2020-22 PROJECTIONS V ,1"1111• " ...... 64 ::"\ ._ ,,, ,,11,111l1 .,,,,,,,,•11' - Ann'I Total I.>+:: . / ., .. pl 48 Price Gain Return '' ,,,111,,• 40 High 5% ,,, ,.. -.. ,w 90 (+10%l i•r·• I 32 Low 60 (-25% -4% 1 ,.... , 111 1111 1111 'I''.).! Insider Decisions a••• ~,1 24 i,,...... J F M A M J J A S ..... ~ l_j').t: ..... 1oe ....•••••• ...... ·········· ...... _...... ·•·•· to Buy o o o o o o o o o ~-· 16 0pl~ns 1111 4 o 1 o o 2 o ?> ";) -12 loSeU o o o o 1 o o 2 o ,:,-,;, :-,.:, % TOT. RETURN 10/17 Institutional Decisions THIS VLARllli.' 4Q2016 1Q2017 2Q2017 Percent 15- I STOCK INDEX lo Buy 118 139 150 1 yr. 16.5 21.4 - shares 10 ., ''"' 3 yr. 53.4 27.5 - loSell 125 109 109 traded 5 .. - Hkl's/000' 37062 42400 41669 II Ill 11111 111111111 5yr. 116.2 92.9 2001 2002 2003 2004 2005 2006 2007 2008 2009 2010 2011 2012 2013 2014 1W 2016 2017 2018 © VALUE LINE PUB. LLC 0-22 42.98 39.68 35.96 40.14 43.59 48.47 50.28 48.53 42.00 40.18 41.07 41.77 42.08 45.61 52.00 51.82 52.60 54.10 Revenues per sh 62.50 4.79 5.07 5.11 5.57 5.20 5.97 6.21 5.76 6.16 6.46 6.81 7.73 8.24 8.47 8.62 9.29 9.05 9.90 "Cash Flow'' per sh 13.10 1.15 1.16 1.13 1.66 1.25 1.98 1.95 1.39 1.94 2.27 2.43 2.86 3.11 3.01 2.92 3.18 3.55 3.10 Earnings per sh A 4.80 .82 .82 .82 .82 .82 .82 .86 .90 .95 1.00 1.06 1.18 1.32 1.46 1.62 1.80 1.98 2.08 Div'ds Decl'd per sh 8-t 2.50 8.17 8.50 7.03 8.23 7.49 8.27 7.96 6.79 4.81 4.73 8.29 8.57 7.86 8.53 10.30 11.15 12.00 12.75 Cap'I Spending per sh 14.40 17.27 17.91 18.42 19.18 19.10 21.58 22.98 23.49 24.44 25.62 26.66 28.35 30.47 31.95 33.61 35.03 37.30 40.80 Book Value per sh 50.00 32.49 33.29 34.23 36.79 39.33 41.77 42.81 44.19 45.09 45.56 45.96 46.15 46.36 46.52 47.38 47.48 48.00 49.00 Common Shs Outst'g c 52.00 19.0 19.9 19.2 14.3 20.6 15.9 17.3 20.3 12.2 14.0 15.7 15.0 15.8 17.9 19.4 21.6 Boldffg res are Avg Ann'I P/E Ratio 16.0 .97 1.09 1.09 .76 1.10 .86 .92 1.22 .81 .89 .98 .95 .89 .94 .98 1.14 value Line Relative P/E Ratio 1.00 eslin ates 3.8% 3.6% 3.8% 3.5% 3.2% 2.6% 2.6% 3.2% 4.0% 3.2% 2.8% 2.8% 2.7% 2.7% 2.9% 2.6% Avg Ann'I Div'd Yield 3.3% CAPITAL STRUCTURE as of 9/30/17 2152.1 2144.7 1893.8 1830,4 1887.2 1927.8 1950.8 2121.7 2463.6 2460.5 2525 2650 Revenues ($mill} 3250 Total Debt $1870.9 mill. Due in 5 Yrs $350 mill. 83.2 61.0 87.5 103.9 112.3 133.3 145.3 141.1 138.3 152.0 175 185 Net Profit ($mill} 255 LT Debt $1732.0 mill. LT Interest $75.0 mill. 36.5% 40.1% 34.0% 34.7% 36.2% 36.2% 35.0% 35.7% 36.4% 33.9% 35.0% 35.0% Income Tax Rate 35.0% (Total interest coverage: 4.2x) (50% of Cap'I) Leases, Uncapitalized Annual rentals $7.0 mill. 3.9% 2.8% 4.6% 5.7% 6.0% 6.9% 7.4% 6.7% 5.6% 6.2% 6.9% 7.0% Net Profit Margin 7.8% Pension Assets-12/16 $787.1 mill. 58.1% 55.3% 53.5% 49.1% 43.2% 49.2% 49.4% 52.4% 49.3% 48.2% 49.5% 48.0% Long-Term Debt Ratio 44.5% Oblig. $1122.2 mill. 41.9% 44.7% 46.5% 50.9% 56.8% 50.8% 50.6% 47.6% 50.7% 51.8% 50.5% 52.0% Common Equitv Ratio 55.5% pfd Stock None 2349.7 2323.3 2371.4 2291.7 2155.9 2576.9 2793.7 3123.9 3143.5 3213.5 3540 3850 Total Capital ($mill} 4700 2845.3 2983.3 3034.5 3072.4 3218.9 3343.8 3486.1 3658.4 3891.1 4132.0 4450 4750 Net Plant ($mill) 5800 Common Stock 47,731,840 shs. 5.5% 4.5% 5.4% 6.1% 6.4% 6.4% 6.3% 5.7% 5.5% 5.8% 6.0% 6.0% Return on Total Cap'I 6.5% as of 10/27/17 8.5% 5.9% 7.9% 8.9% 9.2% 10.2% 10.3% 9.5% 8.7% 9.1% 10.0% 9.5% Return on 5hr. Equity 10.0% 8.5% 5.9% 7.9% 8.9% 9.2% 10.2% 10.3% 9.5% 8.7% 9.1% 10.0% 9.5% Return on Com Equity 10.0% MARKET CAP: $3.9 billion (Mid Cap) 4.8% 2.1% 4.1% 5.1% 5.3% 6.1% 6.1% 5.0% 4.0% 4.1% 4.5% 4.0% Retained to Com Eq 5.0% CURRENT POSITION 2015 2016 9/30/17 44% 63% 48% 43% 43% 40% 41% 47% 54% 55% 54% 55% All Div' ds to Net Prof 51% ($MILL.) Cash Assets 36.0 28.1 59.2 BUSINESS: Southwest Gas Holdings, Inc. is the parent holding transportation, 12%. Total throughput: 2.1 billion therms. Has 6,277 Other 522.2 505.2 479.7 company of Southwest Gas and Centuri Construction Group. employees. Off. & dir. own 1.1 % of common stock; BlackRock Inc., Current Assets 558.2 533.3 538.9 Southwest Gas is a regulated gas distributor serving about 2.0 mil- 11.3%; The Vanguard Group, Inc., 9.4% (3/17 Proxy). Chairman: Accts Payable 164.9 184.7 159.4 lion customers in sections of Arizona, Nevada, and California. Michael J. Malarkey. President & CEO: John P. Hester. Inc.: CA. Debt Due 37.5 50.1 139.0 Other 332.6 393.6 358.0 Centuri provides construction services. 2016 margin mix: residential Addr.: 5241 Spring Mountain Road, Las Vegas, Nevada 89193. Tel- Current Liab. 535.0 628.4 656.4 and small commercial, 85%; large commercial and industrial, 3%; ephone: 702-876-7237. Internet: www.swgas.com. Fix. Chg. Gov. 401% 401% 407% Shares of Southwest Gas have moved with multiyear pipe replacement pro- ANNUAL RATES Past Past Est'd '14-'16 higher in price in recent times. The grams. Centuri should be able to capitalize of change (per sh) 10Yrs. liYrs. to '20-'22 company posted a strong performance for on the need to replace aging infrastructure Revenues 1.0% 4.0% 4.0% "Cash Flow" 4.5% 6.5% 7.0% the third quarter. The top line increased in the coming years. Earnings 6.5% 6.5% 8.0% 10%, on a year-to-year basis. The utility Short-term accounts might want to Dividends 7.0% 10.0% 7.5% benefited from rate relief in Arizona and take a closer look. This stock is ranked Book Value 5.5% 5.5% 7.0% California, along with growth in the cus- to outperform the broader equity market Cal- QUARTERLY REVENUES($ mill.) Full tomer base. Elsewhere, construction serv- for the corning six to 12 months. Moreover, endar Mar.31 Jun.30 Sep.30 Dec.31 Year ices segment Centuri gained from an in- this issue offers some appeal for conserva- 2014 608.4 453.1 432.5 627.7 2121.7 crease in pipe replacement demand from tive subscribers. Southwest Gas earns fa- 2015 734.2 538.6 505.4 685.4 2463.6 existing customers. Overall. revenue vorable marks for Financial Strength, 2016 731.2 547.8 540.0 641.5 2460.5 growth outstripped that of operating costs, Price Stability, and Earnings Predic- 2017 654.7 560.5 593.2 716.6 2525 thanks to a decline in depreciation ex- tability. Volatility is subdued, as well 2018 685 590 625 750 2650 pense. As a result, share earnings of $0.21 (Beta: .80). Cal- EARNINGS PER SHARE A 0 Full marked a considerable improvement from But patient investors can probably endar Mar.31 Jun.30 Sep.30 Dec.31 Year the prior-year tally. We anticipate favor- find more-suitable choices elsewhere 2014 1.51 .21 .04 1.25 3.01 able comparisons for the fourth quarter, at this juncture. We anticipate solid 2015 1.53 .10 d.10 1.38 2.92 and greater revenues and earnings per growth in revenues and earnings per share 2016 1.58 .19 .05 1.36 3.18 share for full-year 2017 . for the company over the pull to early next 2017 1.45 .37 .21 1.52 3.55 The company should continue to fare decade. But this seems to be largely 2018 1.52 .40 .20 1.58 3.70 well from 2018 onward. The utility seg- reflected in the recent quotation, following Cal- QUARTERLY DIVIDENDS PAID 8-f Full ment ought to further benefit from rate fairly strong share-price appreciation over endar Mar.31 Jun.30 Sen.30 Dec.31 Year relief, expansion projects, infrastructure the past couple of years. Long-term capital 2013 .295 .330 .330 .330 1.29 tracker mechanisms, and steady growth in gains potential appears to be limited, as 2014 .330 .365 .365 .365 1.43 the customer base. Meanwhile, Centuri the shares presently trade well within our 2015 .365 .405 .405 .405 1.58 will probably continue to perform well Target Price Range. The stock's dividend 2016 .405 .450 .450 .450 1.76 going forward. This operation has a yield is not compelling for a utility, either. 2017 .450 .495 .495 .495 healthy base of large utility clients, many Michael Napoli, CFA December 1, 2017 (A) Diluted earnings. Exel. nonrec. gains and December. -t Div'd reinvestment and Company's Financial Strength B++ (losses): '02, (10¢); '05, (11¢); '06, 7¢. Next stock purchase plan avail. (C) In millions. Stock's Price Stability 85 egs. report due late February. (8) Dividends (D) Totals may not sum due to rounding. Price Growth Persistence 90 historically paid early March, June, September, Earnings Predictability 90 © 2017 Value Line, Inc. All ~hts reserved. Factual material is obtained from sources believed to be reliable and is provided without warranties of an~ ~nd. Im , - THE PUBLISHER IS NOT RESP NSIBLE FOR ANY ERRORS OR OMISSIONS HEREIN. This ublication is strictly for subscnber's own, non-commercial, internal use. o part I 1,,M I ,__, 11 ■ 111:H!Jl'll/ll o/ it may be reproduced, resold, stored or transmitted in any pnnted, electronic or other form, or useJ for generating or marketing any pnnted or electronic publication, service or product Attachment BEL-7 r .. n~P Nn J 4988 IRECENT 78 20 IP/E 20 7crailing:22.2) RELATIVE 104 DIV'D Page( of6 SPIRE INC, NYSE-SR PRICE , RATIO , Median: 16.0 PIE RATIO I YLD 2.9%_IEI TIMELINESS 2 Raised 11/10/17 High: 37.5 36.0 55.8 48.3 37.8 42.8 44.0 48.5 55.2 61.0 71.2 79.6 Target Price Range Low: 29.1 28.8 31.9 29.3 30.8 32.9 36.5 37.4 44.0 49.1 57.1 62.3 2020 2021 2022 LEGENDS SAFETY 2 Raised 6/20/03 . 128 TECHNICAL 3 Raised 1211117 - di~i~:d ~vi1it~~~sr ~~te • • , , Relative Price Strength 96 BETA .70 (1.00 = Market) f -- .... --- -...... - 80 'Zr~a indicates recession f 11 O~~~~!~ •· ./ 11 -- 64 2020-22 PROJECTIONS . . · ' _I.----" 111 Ann'I Total ,;.. ,I l1,i11l1 48 Price Gain Return IIS _lll'i!l'l • 40 lll1lr· High 85 (+10%! 5% L,11111 _111 ~,, ~I -Iii.. 111,fl,111 "' 32 Low 65 (-15% -1% "II ,...... 24 Insider Decisions ...... J F M A M J J A s ...... ·- ··········· ...... · ·····• .... lo Buy 0 0 0 0 0 0 0 0 0 . ······•..-. ... ········· 16 Options 1 7 0 0 0 0 0 0 0 -12 .· .. to Sell 0 1 0 0 0 0 0 0 0 % TOT. RETURN 10/17 Institutional Decisions THIS VLARITH.* 4Q2016 1Q2017 2Q2017 I STOCK INDEX Percent 15- 1 yr. 29.6 21.4 to Buy 135 121 128 shares 10 - - to Sell 109 112 93 traded 111111 ,111,, 1111 di 1111 11.1111111 11,111,111 ,II 3 yr. 71.4 27.5 - Hld's1000 35783 41441 43554 5 I 1111 1111111111 11I~ II ttllll Ill 11111 1111111111 1111111111 1111111111 5 yr. 125.8 92.9 2001 2002 2003 2004 2005 2006 2007 2008 2009 2010 2011 2012 2013 2014 2015 2016 2017 2018 @ VALUE LINE PUB. LLC 0-22 53.08 39.84 54.95 59.59 75.43 93.51 93.40 100.44 85.49 77.83 71.48 49.90 31.10 37.68 45.59 33.68 36.07 44.35 Revenues per sh A 58,50 3.00 2.56 3.15 2.79 2.98 3.81 3.87 4.22 4.56 4.11 4.62 4.58 3.12 3.87 6.15 6.16 6.54 6.90 "Cash Flow'' per sh 8.15 1.61 1.18 1.82 1.82 1.90 2.37 2.31 2.64 2.92 2.43 2.86 2.79 2.02 2.35 3.16 3.24 3.43 3.80 Earnings per sh A 8 4.65 1.34 1.34 1.34 1.35 1.37 1.40 1.45 1.49 1.53 1.57 1.61 1.66 1.70 1.76 1.84 1.96 2.10 2.25 Div'ds Decl'd per sh c. 2.50 2.51 2.80 2.67 2.45 2.84 2.97 2.72 2.57 2.36 2.56 3.02 4.83 4.00 3.96 6.68 6.42 9.08 6.90 Cap'I Spending per sh 7.10 15.26 15.07 15.65 16.96 17.31 18.85 19.79 22.12 23.32 24.02 25.56 26.67 32.00 34.93 36.30 38.73 41.26 43.90 Book Value per sh 0 48.30 18.88 18.96 19.11 20.98 21.17 21.36 21.65 21.99 22.17 22.29 22.43 22.55 32.70 43.18 43.36 45.65 48.26 48,50 Common Shs Outst'g E 50.00 14.5 20.0 13.6 15.7 16.2 13.6 14.2 14.3 13.4 13.7 13.0 14.5 21.3 19.8 16.5 19.6 19.8 Avg Ann'I P/E Ratio 16.0 .74 1.09 .78 .83 .86 .73 .75 .86 .89 .87 .82 .92 1.20 1.04 .83 1.03 .97 Relative P/E Ratio 1.00 5.7% 5.7% 5.4% 4.7% 4.4% 4.3% 4.4% 3.9% 3.9% 4.7% 4.3% 4.1% 4.0% 3.8% 3.5% 3.1% 3.1% Avg Ann'I Div'd Yield 3.4% CAPITAL STRUCTURE as of 9/30/17 2021.6 2209.0 1895.2 1735.0 1603.3 1125.5 1017.0 1627.2 1976.4 1537.3 1740.7 2150 Revenues ($mill) A 2925 Total Debt $2572.3 mill. Due in 5 Yrs $625.0 mill. 49.8 57.6 64.3 54.0 63.8 62.6 52.8 84.6 136.9 144.2 161.6 185 Net Profit ($mill) 230 LT Debt $1995.0 mill. LT Interest $70.0 mill. 33.4% 31.3% 33.6% 33.4% 31.4% 29.6% 25.0% 27.6% 31.2% 32.5% 32.4% 23.5% Income Tax Rate 24.0% (Total interest coverage: 3.6x) 2.5% 2.6% 3.4% 3.1% 4.0% 5.6% 5.2% 5.2% 6.9% 9.4% 9.3% 8.6% Net Profit Margin 7.9% 45.3% 44.4% 42.9% 40.5% 38.9% 36.1% 46.6% 55.1% 53.0% 50.9% 50.0% 49.5% Long-Term Debt Ratio 49.0% Leases, Uncapitalized Annual rentals $11.0 mill. 54.6% 55.5% 57.1% 59.5% 61.1% 63.9% 53.4% 44.9% 47.0% 49.1% 50.0% 50.5% Common Equity Ratio 51.0% Pension Assets-9/17 $531.6 mill. 784.5 876.1 906.3 899.9 937.7 941.0 1959.0 3359.4 3345.1 3601.9 3986.3 4225 Total Capital ($mill) 4755 Oblig, $7 48.8 mill. 793.8 823.2 855.9 884.1 928.7 1019.3 1776.6 2759.7 2941.2 3300.9 3665.2 3850 Net Plant ($mill) 4215 Pfd Stock None Common Stock 48,266,858 shs. 8.5% 8.1% 8.7% 7.4% 8.1% 7.9% 3.3% 3.1% 5.1% 4.9% 5.0% 5.0% Return on Total Cap'I 5.5% as of 11/10/17 11.6% 11.8% 12.4% 10.1% 11.1% 10.4% 5.0% 5.6% 8.7% 8.2% 8.1% 8.5% Return on Shr. Equity 9.5% 11.6% 11.8% 12.4% 10.1% 11.1% 10.4% 5.0% 5.6% 8.7% 8.2% 8.1% 8.5% Return on Com Equity 9.5% MARKET CAP: $3.8 billion (Mid Cap) 4.3% 5.2% 5.9% 3.6% 4.9% 4.3% 1.0% 1.5% 3.7% 3.3% 3.3% 3.5% Retained to Com Eq 4.5% CURRENT POSITION 2015 2016 9/30/17 63% 56% 53% 64% 56% 59% 81% 73% 58% 59% 60% 59¾ All Div'ds to Net Prof 54¾ ($MILL.) Cash Assets 13.8 5.2 7.4 BUSINESS: Spire Inc., formerly known as the Laclede Group, Inc., tial, 29%; commercial and industrial, 15%; transportation, 49%; Other 516.3 564.4 718.1 is a holding company for natural gas utilities, which distributes natu- other, 6%. Has around 3,279 employees. Officers and directors Current Assets 530.1 569.6 725.5 ral gas across Missouri, including the cities of St. Louis and Kansas own 3.1% of common shares (1/17 proxy). Chairman: Edward City. Has roughly 1. 7 million customers. Acquired Missouri Gas Glotzbach; CEO: Suzanne Sitherwood. Inc.: Missouri. Address: 700 Accts Payable 146.5 210.9 257.1 Debt Due 418.0 648.7 577.3 9/13, Alabama Gas Co 9/14. Utility therms sold and transported in Market Street, St. Louis, Missouri 63101. Telephone: 314-342- Other 289.3 301.7 263.5 fiscal 2017: 3.0 bill. Revenue mix for regulated operations: residen- 0500. Internet: www.thelacledegroup.com. Current Liab. 853.8 1161.3 1097.9 Spire recorded mixed fiscal fourth- calendar 2018. This project is expected to Fix. Chg. Gov. 365% 366% 361% quarter results (year ended Septem- be in service by fiscal 2019, and will cost ANNUAL RATES Past Past Est'd '15-'17 her 30th). Revenues declined to $258.7 between $190 million and $210 million in of change (per sh) 10 Yrs. 5Yrs. to '20·'22 Revenues -8.0% -10.5% 7.0% million, as gas utility increases were more additional capital expenditures. This "Cash Flow" 6.0% 7.0% 7.0% than offset by a decline in gas marketing project ought to allow for greater return Earnings 4.0% 4.0% 8.0% activities. Better operations allowed for rates, and will improve margins at its util- Dividends 3.5% 4.0% 5.0% Book Value 7.5% 9.0% 4.5% margins to expand a bit, though higher ities with cheaper natural gas sources. maintenance expense still put some pres- This should help drive long-term earnings Fiscal QUARTERLY REVENUES ($ mill.)A Full Year Fiscal sure on the bottom line during the to $4.65 per share. Ends Dec,31 Mar.31 Jun.30 Sep.30 Year quarter. In all, losses narrowed to $0.28 The company recently raised its divi- 2014 468.6 694.5 241.8 222.3 1627.2 per share. dend 7% to $2.25 per share annually. 2015 619.6 877.4 275.2 204.2 1976.4 The company appears poised for solid This represents a decent increase, and 2016 399.4 609.3 249.3 279.3 1537.3 near-term results. It will work to further management expects to raise the payout 2017 495.1 663.4 323.5 258.7 1740.7 4% to 6% annually over the coming years. 2018 600 800 300 450 2150 integrate its operations, through the rebranding of its utility operations into the As the payout is covered by cash flows, we Fiscal EARNINGS PER SHARE A B F Full Year Fiscal Spire brand. This will allow for marketing expect that this goal will be easily Ends Dec.31 Mar.31 Jun.30 Sep.30 Year efficiencies. Meantime, it will spend achieved. The balance sheet remains 2014 1.09 1.59 .33 d.35 2.35 around $485 million in capital expendi- manageable, though debt is slated to in- 2015 1.09 2.18 .32 d.43 3.16 tures, including increased outlays on the crease for infrastructure buildouts. 2016 1.08 2.31 .24 d.31 3.24 STL Pipeline. Spire also has new cases Shares of Spire are ranked to out- 2017 .99 2.36 .45 d.28 3.43 2018 1.10 2.55 .40 d.25 3.80 pending for its two Missouri utilities, perform the broader market averages which may allow for greater rates. In all, (Timeliness: 2). In addition, they offer a Cal• QUARTERLY DIVIDENDS PAID c • Full we think the company will be able to earn decent yield. Still, they are trading near endar Mar.31 Jun.30 Seo.30 Dec.31 Year $3.80 per share in fiscal 2018 . the high end of our long-term Target Price 2014 .44 .44 .44 .44 1.76 The STL Pipeline appears to be on Range, and at an elevated price-to- 2015 .46 .46 .46 .46 1.84 track. Spire received its FERC environ- earnings ratio. Long-term accounts would 2016 .49 .49 .49 .49 1.96 mental assessment, and will look to in- be best served looking elsewhere, for now. 2017 .525 .525 .525 .525 crease its spending on the STL Pipeline in John E. Seibert III December 1, 2017 2018 .5625 (A) Fiscal year ends Sept. 30th. (B) Based on due late January. (C) Dividends historically $19.07/sh. (E) In millions. (F) Olly. egs. may Company's Financial Strength B++ diluted shares outstanding. Excludes nonrecur- paid in early January, April, July, and October. not sum due to rounding or change in shares Stock's Price Stability 100 ring loss: '06, 7¢. Excludes gain from discontin- • Dividend reinvestment plan available. (D) outstanding in 2014, 2016, and 2017. Price Growth Persistence 40 ued operations: '08, 94¢. Next earnings report Incl. deferred charges. In '17: $920.2 mill., Earnings Predictability 85 © 2017 Value Line, Inc. Al! rights reserved. Factual material is obtained from sources believed to be reliable and is provided without warranties of any kind. THE PUBLISHER IS NOT RESPONSIBLE FOR ANY ERRORS OR OMISSIONS HEREIN. This f"blication is strictly for subscriber's own, non-commercial, internal use. No part I [1"11..~ 111J;.'flfi ff,Ii,:j I ■ i,:{111 l'll/!1I11:11111I :Ill of it may be reproduced, resold, stored or transmitted in any printed, electronic or other form, or use for generating or marketing any printed or electronic publication, service or product. Attachment BEL-8 Cause No 44988 0 1 9 t-A_L_L_IA_N_T_E_N_ER_G_Y_N_YS_E_-LN_T ~~'~-tCJe_Nr_4_4_.3_4_.__1:_r10_2_3._1 (_~~-il/~~-;i~_:O.J_~i_Lti_i~_1_.1_4,__~r_o _3_.0_%__ Pa--lgt of TIMELINESS 2 Raisedll/17117 High: 20.0 23.3 21.2 15.8 18.8 22.2 23.8 27.1 34.9 35.4 41.0 45.6 Target Price Range Raised t~~~Noi3.8 17.5 11.4 10.2 14.6 17.0 20.9 21.9 25.0 27.1 30.4 36.6 2020 2021 2022 SAFETY 2 9128107 TECHNICAL 3 Raised12/1n7 - ~i~i:d~;i1~t~~~~te 1-l..---!Cc".I.;.:;.;: .. -+---+--l--+---+---1----1----1---1---+---1---1----1-80 • , • • Relative Prtce Strength k,. I i. 60 BETA .70 (1.00=Market) 2-for-1 SP.llt 5/16 1; ,- , 50 1 11 f-~20=2=0.=22~P=R=o~J=Ec=r=1o=N=S-i o=~=g~=~!=/fa"ie=•='"=du;~·•~te=sre=c=es~si!onI 4o Price Gain An~itJ~al:-1 ,,., •. ~;:~--tt'i I');3 11 1 Insider Decisions l--r'""-"1;,1tr;-:--:w"'f-_"..:.li"''"7''tti;.ir>li¾~(fir!j,ml',.;:-/:i-:,:11<'"'1+1 A.:...... ''+---'+---+--+---+--+r-=--+--+---+--+---+--+-15 F M A M J J A S O J111! ..•• 1 111,1'· I f,,~ ,. • ,••• ••• •-.•••••►·•••••••••• ...••••••• ta Buy O O O O O O O O O ••• •• • ...... •• !l!fl-:wP.;,.;a,:•=--·1--;:::;o:..;•••:...,.,,_;:...:•_•+=""=--•-••_••+-..::":,.•-d,.-.,.:<+.=-·..._-+--+---+--+---+--+---+10 Options O 10 O11 O O O O O •• :I':/':: •• •••• ···• ··••- ta Sell 1 1 o 5 o o 3 o o .,,+-,,.,,,--+---+--+---+--+---+--+---+--+----! %TOT.RETURN 11117 - 7-5 Institutional Decisions THIS VL ARITH." 1Q2017 2Q2017 3Q2017 Percent 30 I STOCK INDEX taBu~ 254 242 210 shares 20 ., 1 yr. 27.7 16.8 - " 3 yr. 65.3 30.2 ~J.:1000 273~J? 273jj~ 2B2?f~ traded 10 11111 1111111111 5 yr. 140.9 96.6 2001 2002 2003 2004 2005 2006 2007 2008 20 9 2010 2011 2012 2013 2014 1~~~~111~016 2017 2018 @ VALUE LINE PUB. LLC 0-22 72.16 60.28 34.21 28.06 28.52 30.57 28.95 30.13 27.23 25.77 25.59 23.90 24.68 26.09 23.29 22.92 22.95 23.85 Revenues per sh 26.00 5.24 d.09 2.39 2.87 3.43 3.22 3.08 3.88 3.47 3.70 3.65 3.82 4.06 4.22 4.59 4.88 5.30 5.65 "Cash Flow'' per sh 7.00 1.27 d2.99 d.29 .74 1.10 .64 .64 1.23 .93 1.33 1.45 1.53 1.66 1.74 1.89 1.98 2.15 2.30 Earnings per sh A 2.75 1.46 1.09 -- .. -· .. .20 .36 .50 .66 .84 .96 1.02 1.08 1.16 1.24 1.33 1.42 Dlv'd Decl'd per sh 8 • 1.10 9.49 5.18 3.32 2.69 2.69 3.01 5.61 3.50 3.59 3.29 3.47 4.65 4.98 5.73 5.64 5.99 6.55 6. 65 Cap') Spending per sh 6.25 14.21 7.86 9.84 10.63 10.53 10.03 9.46 10.88 11.42 11.19 11.92 12.09 12.98 13.34 14.21 15.23 16.25 17.35 BookValuepersh c 21.00 132.99 144.10 161.13 195.00 220.50 222.78 225.15 226.41 227.89 249.60 254.10 264.10 266.10 275.20 277.16 279.21 281.00 283.00 Common Shs Outst'g O 289.00 20.8 -- ·- 12.4 12.6 22.2 26.8 10.9 13.6 12.5 13.6 15.1 16.3 17.3 18.3 20.9 Bold fig res are Avg Ann'I PIE Ratio 14.5 1.07 -· ·- .66 .67 1.20 1.42 .66 .91 .80 .85 .96 .92 .91 .92 1.09 1/alue Line · Relative PIE Ratio .~0 5.5% 7.5% .. .. ·- .. 1.2% 2.7% 4.0% 4.0% 4.3% 4.2% 3.8% 3.6% 3.4% 3.0% esffn ales Avg Ann'I Div'd Yield 4.2% CAPITAL STRUCTURE as of 9/30/17 6519.0 6821.0 6205.0 6432.0 6503.0 6312.0 6566.0 7179.0 6456.0 6399.0 6450 6750 Revenues {$mill) 7500 Total Debt $10331 mill. Due in 5 Yrs $4440 mill. 168.0 300.0 231.0 356.0 384.0 413.0 454.0 479.0 525.0 553.0 610 660 Net Profit /$mill) 810 LT Debt $9121 mill. LTlnterest $401 mill. 37.6% 31.6% 34.6% 38.1% 36.8% 39.4% 39.9% 34.3% 34.0% 33.1% 33.0% 34.0% Income Tax Rate 33 0% Incl. $97 mill. capitalized leases. · 0 {LT interest earned: 2.9x) 3.6% 1.3% 13.0% 2.2% 2.6% 2.9% 2.0% 2.3% 2.7% 3.1% 3.0% 3.0% AFUDC %to Net Profit 2.0% Leases, Uncapitalized Annual rentals $20 mill. 70.5% 69.4% 67.9% 70.1% 66.9% 67.9% 67.5% 68.7% 68.3% 67.1% 66.5% 65.5% Long-Term Debt Ratio 64.5% Pension Assets-12/16 $2101 mill. 25.9% 27.4% 29.0% 29.5% 32.6% 31.6% 32.2% 31.0% 31.4% 32.6% 33.5% 34.0% Common Eauitv Ratio 35.5% Oblig $2562 mill. 8212.0 8993.0 8977.0 9473.0 9279.0 10101 10730 11846 12534 13040 13700 14450 Total Capital ($mill) 17100 Pfd Stock $37 mill. Pfd Div'd $2 mill. 8728.0 9190.0 9682.0 10069 10633 11551 12246 15715 $ Incl. 373,148 shs. $4.50 $100 par, cum., callable at t--o-=:-+--=-:.,,..+--,=:-+--=-=:-:-+-=-cc:,-+--cc-:c,-+--c-c;,,.-+-c-=-+--=.,.+-,,.,c:,-r-:13412 14705 16,...,67.,.,5-+-1...,.7..,,62,.,.5+.N=-e.,..tP_la_n_t ('=m..,.i--fll)-=--.,,....-+-, 1'""_99,,.,~¾0c-t $110.00. 4.5% 5.4% 4.7% 5.8% 6.3% 5.9% 6.0% 5.7% 5.7% 5.8% 6.0% 6.0% Return on Total Cap'I 60 Common Stock 282,083,585 shs. 6.9% 10.9% 8.0% 12.5% 12.5% 12.8% 13.0% 12.9% 13.2% 12.9% 13.0% 13.5% Return on Shr. Equity 13.5% as of 10/10/17 7.2% 11.7% 8.5% 12.5% 12.6% 12.9% 13.1% 13.0% 13.3% 13.0% 13.5% 13.5% Return on Com Equitv E 13.5% MARKET CAP: $14 billion (Large Cap) 5.1% 8.4% 4.1% 6.9% 5.6% 5.0% 5.2% 5.0% 5.2% 4.8% 5.0% 5.0% Retained to Com Eq 5.5% ELECTRIC OPERATING STATISTICS 35% 31% 54% 46% 55% 61% 60% 62% 61% 63% 61% 61% All Dlv'ds to Net Prof 61% 2014 2015 2~11t--B-U-SI-N~ES_S_:_C_M~S-E-ne-rg~y-C_o_rp_o~ra-ti-on-is~a-ho-ld-in_,_g_co_m_p_,_an_y_t_or__,__6°-¼.-Ge_,_n_e_ra-tin_g_,_s_o_urce_s_,_: -co-a-1,-2_,_7_%_; -g-as-, -1-6°_¼,_; -ot-he_r_, -'3,-¼,;_p_u_r_-1 %Change Retail Sales (KWH) +1.9 -.8 Avg. lndusl Use (MWH\ NMF 5922 :031 Consumers Energy, which supplies electricity and gas to lower chased, 54%. Fuel costs: 44% of revenues. '16 reported deprec. Avg. lndust Revs. per KWH(¢) 8.29 8.07 7.76 Michigan (excluding Detroit). Has 1.8 million electric, 1.7 million gas rates: 3.9% electric, 2.9% gas, 9.8% other. Has 7,400 employees. Capacity at Peak (Mwl 8776 8762 8331 customers. Has 1,034 megawatts of nonregulated generating capa- Chairman: John G. Russell. President & CEO: Patricia K. Poppe. Peak Load, Summer (Mw) 7498 7812 8 Annual Load Factor (%) 59.7 55.5 effl city. Sold Palisades nuclear plant in '07. Electric revenue break- Incorporated: Michigan. Address: One Energy Plaza, Jackson, Ml %Change Customera (yr..ind) -- +.6 +.5 t--do_w_n_:_re_si_de_n_tia_l,_4_5_%_;_co_m_m_e_rc_ia_l,_3_1_%_;_in_d_us_tn_·a_l,_1_8°_¼_; _ot_he_r,__ 49_2_01_._T_el_.:_51_7_-7_8_8-_05_5_0._l_nt_em_e_t:_www __.c_m_s_en_e-'rg-'-y._co_m_. __--1 Fixed Charge Cov. (%) 278 288 292 CMS Energy's utility subsidiary has ment's guidance of $2.29-$2.33 a share. ANNUAL RATES Past Past Est'd '14-'16 filed a gas rate case. Consumers Energy CMS Energy's goal for annual profit of change (per sh) 10Yrs. 5Yrs. to '20-'22 is seeking an increase of $178 million, growth is 6%-8%. Revenues -2.0% -1.5% 1.5% based on a 10.5% return on equity. The We expect a dividend increase at the "Cash Flow" 3.5% 5.0% 7.5% primary driver of the application is the board meeting in January. This has Earnings 8.5% 8.5% 6.5% Dividends -- 11.5% 6.5% need to earn a return on investments the been the typical practice since CMS Ener Book Value 3.0% 4.5% 6.5% utility has made to replace old equipment. gy restored the common dividend 10 years The utility is also seeking a regulatory me- ago. We think the directors will raise the Cal- QUARTERLY REVENUES($ mill.) Full endar Mar.31 Jun.30 Sep.30 Dec.31 Year chanism that will allow concurrent re- annual disbursement by $0.09 a share 2014 2523 1468 1430 1758 7179.0 covery of certain kinds of capital costs and (6.8%), the same as a year ago. Dividend 2015 2111 1350 1486 1509 6456.0 a mechanism to decouple gas volume and hikes are likely to come at about the same 2016 1801 1371 1587 1640 6399.0 revenues. An order is due by the end of pace as earnings increases. 2017 1829 1449 1527 1645 6450 August. The Michigan commission rejected 2018 1900 1550 1600 1700 6750 An electric rate case is pending. Con- the proposed buyout of a purchased sumers Energy filed for an increase of power contract with the owner of the Cal- EARNINGS PER SHARE A Full endar Mar.31 Jun.30 Sep.30 Dec.31 Year $173 million, based on a 10.5% ROE. The Palisades nuclear plant. The commis 2014 .75 .30 .34 .35 1.74 staff of the Michigan commission raised its sion allowed Consumers Energy recovery 2015 .73 .25 .53 .38 1.89 recommendation, and is now at about $70 of just $137 million of the $172 buyout 2016 .59 .45 .67 .28 1.98 million, based on a 9.8% ROE. The utility price. Thus, the companies agreed to can 2017 .71 .33 .61 .50 2.15 self-implemented a $130 million increase eel the deal. The above-market contract 2018 .80 .40 .65 .45 2.30 on October 1st. The final ruling is due by will continue through its expiration in Cal- QUARTERLY DIVIDENDS PAID 8 ■ Full the end of March. May of 2022. endar Mar.31 Jun.30 Seo.30 Dec. 31 Year We estimate steady earnings growth This stock is timely, but has a divi in 2017 and 2018. Rate relief and expense dend yield that is low, by utility stan 2013 .255 .255 .255 .255 1.02 2014 .27 .27 .27 .27 1.08 reductions are the key factors. Our 2017 dards. With the recent price above our 2015 .29 .29 .29 .29 1.16 estimate is at the low end of CMS Ener- 2020-2022 Target Price Range, total re 2016 .31 .31 .31 .31 1.24 gy's targeted range of $2.15-$2.18 a share, turn potential is negative. 2017 .3325 .3325 .3325 .332: and our 2018 forecast is within manage- Paul E. Debbas, CFA December 15, 2017 (A) Diluted EPS. Exel. nonrec. gains (losses): '10, (8¢); '11, 1¢; '12, 3¢. '16 EPS don't sum (C) Incl. intang. In '16: $7.49/sh. (D) In mill. (E) Company's Financial Strength B++ '05, ($1.61); '06, ($1.08); '07, ($1.26); '09, (7¢); due to rounding. Next earnings report due early Rate base: Net orig. cost. Rate allowed on Stock's Price Stability 100 '10, 3¢; '11, 12¢; '12, (14¢); gains (losses) on Feb. (B) Div'ds historically paid late Feb., May, com. eq. in '17: 10.1%; earned on avg. com. Price Growth Persistence 85 disc. ops.: '05, 7¢; '06, 3¢; '07, (40¢); '09, 8¢; Aug., & Nov.• Div'd reinvestment plan avail. eq., '16: 13.5%. Regulatory Climate: Average. Earnings Predictability 90 " 2017 Value Line, Inc. All rights reserved. Factual material is obtained from sources believed to be reliable and is provided without warranties of any kind. Ill THE PUBLISHER IS NOT RESPONSIBLE FOR ANY ERRORS OR OMISSIONS HEREIN. This publication is strictly for subscriber's own, non-commercial, internal use. No part ■ 11a.~ 11 I ~ .. 111 '-or, II ■ i,:illll\lJl of it may be reproduced, resold, stored or transmitted in any printed, electronic or other form, or used for generating or marketing any prinled or electronic publication, service or producL Attachment BEL-8 l',:,n~P No. 44988 IRECENT 87 69 IP/E 21 2crailing:22.1) RELATIVE 108 DIV'D Pag, 4 of9 CON. EDISON NYSE-ED PRICE , RATIO , Median: 15.0 PIE RATIO I YLD 3.2%- TIMELINESS 4 Lowered 8/18117 High: 49.3 52.9 49.3 46.3 51.0 62.7 66.0 64.0 68.9 72.3 81.9 87.7 Target Price Range Low: 41.2 43.1 34.1 32.6 41.5 48.6 53.6 54.2 52.2 56.9 63.5 72.1 2020 2021 2022 SAFETY 1 New 7/27/90 LEGENDS 120 TECHNICAL 5 Lowered 11117/17 - ~iJi~:d ~vi1~t~1:sr ~~le 100 • • . , Relative ~rice Strength 1------• ,I 80 BETA .50 (1.00" Market) V >-...... illl "'11 ...... indicates recession 1"11 ., 64 O~~~~~d yir!a . ·. .... "h ••'1111,11, 11111•111 -- 2020-22 PROJECTIONS .,, LA"' 48 Ann'I Total ,1,,1 lll1'" I > ,1·11 111 Price Gain Return ~I 1j·t,,1' •·•·•···· .. ~ ... .. 32 High 80 1-10%l 1% ····· .. •·· I ...... Low 65 -25% -3% ···•··· ·.... ··••·...... 24 Insider Decisions ··• ...... 20 ...... ""• ········ J F M A M J J A S ' 16 taBuy 11 7 711 9 811 8 8 12 Options 211 1 3 9 2 0 0 0 la Sell 0 0 0 0 0 0 0 1 0 •. . % TOT. RETURN 10/17 .... 8 Institutional Decisions THIS VLARITH.• , STOCK INDEX 4Q2016 1Q2017 202017 Percent 21 .. I II. 1 yr. 18.0 21.4 ... la Buy 346 322 330 shares 14 .... la Sell 330 336 323 traded ,1111 .li!IIII .11., 111, 3 yr. 52.1 27.5 .... 7 i 5 yr. 74.2 92.9 Hld's/000 167319 197947 196270 I 11111111111 111111111 111111111 2001 2002 2003 2004 2005 2006 2007 2008 2009 2010 2011 2012 20\1~111~1~!1~1111~~~~1111~~~~111 2017 2018 @ VALUE LINE PUB. LLC , 0-22 45.41 39.65 43.51 40.24 47.66 47.14 48.23 49.62 46.36 45.69 44.17 41.62 42.27 44.11 42.85 39.59 37.60 39.75 Revenues per sh 43.00 5.70 5.44 5.12 4.54 5.27 5.28 5.77 -5.99 5.86 6.24 6.61 7.15 7.45 7.30 7.93 7.89 8.40 8,80 "Cash Flow'' per sh 9.75 3.21 3.13 2.83 2.32 2.99 2.95 3.48 3.36 3.14 3.47 3.57 3.86 3.93 3.62 4.05 3.94 4.05 4.20 Earnings per sh A 4.50 2.20 2.22 2.24 2.26 2.28 2.30 2.32 2.34 2,36 2.38 2.40 2.42 2.46 2.52 2.60 2.68 2.76 2.84 Div'd Decl'd per sh 8 ■ 3.08 5.20 5.68 5.72 5.60 6.59 7.17 7.09 8.50 7.80 6.96 6.72 7.06 8.67 8.26 10.42 12.07 11.90 12.45 Cap'I Spending per sh 11,50 26.71 27.68 28.44 29.09 29.80 31.09 32.58 35.43 36.46 37.93 39.05 40.53 41.81 42.94 44.55 46.88 48.65 50, 15 Book Value per sh c 54.75 212.15 213.93 225.84 242.51 245.29 257.46 272.02 273.72 281.12 291.62 292.89 292.87 292.87 292.88 293.00 305.00 311.00 312.00 Common Shs Outst'g 0 315,00 12.0 13.3 14.3 18.2 15.1 15.5 13.8 12.3 12.5 13.3 15.1 15.4 14.7 15.9 15.6 18.8 Bold fig !Ires are Avg Ann'I PIE Ratio 16,5 .61 .73 ,82 .96 .80 .84 .73 .74 .83 .85 ,95 .98 .83 .84 .79 .98 Value Line Relative PIE Ratio 1.05 5.7% 5.3% 5.5% 5.3% 5.0% 5.0% 4.8% 5.7% 6.0% 5.2% 4.5% 4.1% 4.3% 4.4% 4.1% 3.6% estin ates Avg Ann'I Div'd Yield 4.2% CAPITAL STRUCTURE as of 9/30/17 13120 13583 13032 13325 12938 12188 12381 12919 12554 12075 11700 12400 Revenues ($mill) 13550 Total Debt $15694 mill. Due in 5 Yrs $3585 mill. 936.0 933.0 868,0 992.0 1062.0 1141.0 1157.0 1066,0 1193.0 1189.0 1285 1325 Net Profit ($mill) 1440 LT Debt $14651 mill. LT Interest $667 mill. 32,6% 36.0% 34.2% 36.0% 36.1% 34.5% 31.8% 34.0% 33.6% 35.3% 36.0% 38.0% Income Tax Rate 38.0% (LT interest earned: 3.5x) 1.9% 1.7% 2.6% 2.4% 1.6% .5% .5% .3% .7% 1.3% 1.0% 1.0% AFUDC % to Net Profit 1.0% Leases, Uncapitalized Annual rentals $61 mill. 45.6% 48.3% 48.5% 48.6% 46.5% 45.9% 46.1% 48.0% 47.9% 50.8% 50,0% 50.5% Long-Term Debt Ratio 49.0% 53.1% 50.6% 50.4% 50.4% 52.5% 54.1% 53.9% 52.0% 52.1% 49.2% 50.0% 49.5% Common Equitv Ratio 51.0% Pension Assets-12/16 $12472 mill. 16687 19160 20330 21952 21794 21933 22735 24207 25058 29033 30175 31625 Total Capital ($mill) 33800 Oblig $14095 mill. 19914 20874 22464 23863 25093 26939 28436 29827 32209 35216 37550 40025 Net Plant ($mill) 46000 Pfd Stock None 7.0% 6.2% 5.7% 5.9% 6.2% 6.5% 6.4% 5.6% 6.0% 5.3% 5.5% 5.5% Return on Total Cap'I 5.5% Common Stock 310,068,797 shs. 10.3% 9.4% 8.3% 8.8% 9.1% 9.6% 9.4% 8.5% 9.1% 8.3% 8.5% 8.5% Return on Shr. Equity 8.5% as of 10/31117 10.4% 9.5% 8.4% 8.9% 9.2% 9.6% 9.4% 8.5% 9.1% 8.3% 8.5% 8.5% Return on Com Equity E 8.5% MARKET CAP: $27 billion (Large Cap) 3.9% 3.1% 2.5% 3.2% 3.1% 3.6% 3.6% 2.6% 3.5% 3.0% 2.5% 3.0% Retained to Com Eq 2.5% ELECTRIC OPERATING STATISTICS 63% 67% 71% 65% 66% 62% 62% 69% 61% 64% 67% 67% All Div'ds to Net Prof 67% 2014 2015 2016 %Change Relail Sales (KWH) -1.1 +1.9 -.4 BUSINESS: Consolidated Edison, Inc. is a holding company for opportunities through three wholly owned subsidiaries. Entered into Avg. Indus!. Use (MWH) NA NA NA Consolidated Edison Company of New York, Inc. (CECONY), which midstream gas joint venture 6/16. Purchases most of its power. Avg. Indus!. Revs. per KWH(¢) NA NA NA sells electricity, gas, and steam in most of New York City and Fuel costs: 26% of revenues. '16 reported depreciation rates: 2.9%- Capacily al Peak (Mwk NMF NMF NA Westchester County. Also owns Orange and Rockland Utilities 3.1%. Has 15,000 employees. Chairman, President & CEO: John Peak Load, Summer! w) 13568 13721 NA (O&R), which operates in New York and New Jersey. Has 3.6 mil- McAvoy. Inc.: New York. Address: 4 Irving Place, New York, New Annual Load Faclor (1/,/ NMF NMF NMF %Change Cuslomern yr-end) NA NA NA lion electric, 1.2 million gas customers. Pursues competitive energy York 10003. Tel.: 212-460-4600. Internet: www.conedison.com. Fixed Charge Cov. (%1 366 370 352 We think Consolidated Edison's earn- payout ratio in a range of 60%-70%. ings will advance steadily in 2017 and ConEd had a stock offering in August. ANNUAL RATES Past Past Est'd '14-'16 of change (per sh) 10 Yrs. 5Yrs, to '20-'22 2018. Each year (and in 2019, as well), the The company raised $343 million through Revenues -.5% -1.5% .5% company will benefit from electric and gas the sale of 4.1 million common shares. "Cash Flow" 4.5% 4.5% 4.0% rate increases at its largest utility subsidi- ConEd will use the proceeds for capital Earnings 3.5% 2.5% 2.5% Dividends 1.5% 2.0% 3.0% ary, Consolidated Edison Company of New spending at both the utility and nonutility Book Value 4.0% 3.5% 3.5% York. The electric hikes are $194.6 million operations. (2.6%) in 2017, $155.3 million (2.0%) in The company is installing smart Cal- QUARTERLY REVENUES($ mill.) Full endar Mar.31 Jun.30 Sep.30 Dec.31 Year 2018, and $155.2 million (1.9%) in 2019. meters in New York City and West- The gas changes are a decrease of $5.4 chester. The first ones were added in July 2014 3789 2911 3390 2829 12919 2015 3616 2788 3443 2707 12554 million in 2017, followed by increases of of 2017. The project, which is scheduled to 2016 3157 2794 3417 2707 12075 $92.3 million (5.6%) in 2018 and $89.4 mil- run through 2022, will cost an estimated 2017 3228 2633 3211 2628 11700 lion (5.1 %) in 2019. Another positive factor $ 5 .4 billion. 2018 3400 2800 3400 2800 12400 is customer conversions from oil heat to Midstream natural gas is an area of gas heat. ConEd's nonutility subsidiaries focus for ConEd. In October, the Federal Cal- EARNINGS PER SHARE A Full endar Mar.31 Jun.30 Sep.30 Dec.31 Year are expanding, too. Our 2017 profit esti- Energy Regulatory Commission granted mate is at the low end of management's approval to build a pipeline serving West 2014 1.23 .63 1.49 .28 3.62 2015 1.26 .74 1.45 .60 4.05 guidance of $4.05-$4.15 a share. We fore- Virginia and Virginia. The company's 2016 1.05 .77 1.47 .64 3.94 cast 4% earnings growth in 2018. ConEd 12.5% stake would result in a $400 million 2017 1.27 .57 1.48 .73 4,05 has not yet put forth earnings guidance for investment. The project is expected to be- 2018 1.30 ,63 1.60 .67 4,20 next year. gin service in late 2018. We expect a dividend increase at the We do not recommend this equity. It is Cal- QUARTERLY DIVIDENDS PAID 8 ■ Full endar Mar.31 Jun.30 Seo.30 Dec.31 Year board meeting in January. This would ranked unfavorably for Timeliness. The be the 44th consecutive year of dividend dividend yield is only average, by utility 2013 .615 ,615 .615 .615 2.46 growth, with reviews typically in the first standards. The recent price is so far above 2014 .63 .63 .63 .63 2.52 2015 .65 .65 .65 .65 2.60 quarter. We estimate the directors will our 2020-2022 Target Price Range that 3- 2016 .67 ,67 .67 .67 2.68 raise the quarterly disbursement by two to 5-year total return potential is negative. 2017 .69 .69 .69 cents a share (2.9%). ConEd is targeting a Paul E. Debbas, CFA November 17, 2017 (A) Diluted EPS. Exel. nonrec. gains (losses): I ing. Next earnings report due mid-Feb. (B) I mill. (E) Rate base: net orig. cost. Rate allowed Company's Financial Strength A+ '02, (11¢); '03, (45¢); '13, (32¢); '14, 9¢; '16, Div'ds historically paid in mid-Mar., June, on com. eq. for CECONY in '17: 9.0%; O&R in Stock's Price Stability 95 15¢; gain on discontinued operations: '08, Sept., and Dec. ■ Div'd reinvestment plan '15: 9.0%; earned on avg. com. eq., '16: 8.6%. Price Growth Persistence 40 $1.01. '14 & '16 EPS don't sum due to round- avail. (C) Incl. intang. In '16: $25.29/sh. (D) In Regulatory Climate: Below Average. Earnings Predictability 95 © 2017 Value Line, Inc. All rights reserved. Factual material is obtained from sources believed to be reliable and is provided without warranties of ani kind. , - THE PUBLISHER IS NOT RESPONSIBLE FOR ANY ERRORS OR OMISSIONS HEREIN. This ublication is strictly for subscriber's own, non-commercial, internal use. o part ■ ,.._, I-'" I ..,.., 111 !'l:H II a1/!1 of it may be reproduced, resold, stored or transmitted in any printed, electronic or other form, or used for generating or marketing any printed or electronic publication, service or product. Attachment BEL-8 r .. m,n xr~ 44988 EVERSOURCE ENERGY NYSE-ES l~WT 64.52 l~frio 20.1 (li:::~;ii:o ~T€~, 1.03 t 0 3.1%- Pag ◄ 5 of9 TIMELINESS 2 Raised 8111m High: 28.9 33.6 31.6 26.5 32.2 36.5 40.9 45.7 56.7 56.8 60.4 64.6 Target Price Range 1 Low: 19.1 26.2 17.2 19.0 24.7 30.0 33.5 38.6 41.3 44.6 50.0 54.1 2020 2021 2022 SAFETY Raised 5/22115 LEGENDS 120 4 - 0.80 x Dividends rsh • .• · TECHNICAL Lowered ~~~~ebPTl:~"tie,:Je ~' BETA .65 (1.00 = Market) 11117M Options·.... Yes .::•:~i:<':==~====~====~====~====~====~====~~==~~====~~===~~====~====~====~~~O. , ·•.• • • 64 t--~20=2=0.~2~2=PR~O~J=E=c=11=o~N=s-f-_sh_a_d•_iil-are_a_;n_d_ical-te_s_re_cess--+ion:,;··4,..:+,•..,;;.'f;_-i--.+--J...r-L-=t"';:~""'F.ffiii;;~j:i!µ...--.u.,,tlt!J.' q.:•::..1':.'''.:.:":.!"!f.'•_"_'"_"--+•·.:.:·:__--+---+-::_:_:_:.j.-::_:_:_:+48 Price Gain An~itJ~al : ';/,!',,,) ,L, ,,,,,, ·•' 1•11 •1" ,. .... ,, .. High 70 (+10%1 5% ,,,,, I 11 , .. ,, 32 Low 60 (-5% 2% I' 11 " 1'1 : L,d tr/I· ,,,,?-- ~ 24 I ,· "t ·, " Insider Decisions 1111 =" 20 II 0 J F M A M J J A S l--+--l-----:,l-,;;>-'-;.~-''t-·4-:,., -l---f---1---f---l---f---t---+--+---+--+---+--+16 to Buy O O O O O O O O O l--==t---===f---:...-+.:.,;c};',,;.':+, ;•:'cc-:---:-+--+---+--+---+--+---+--+---+--+---+--+---+12 Options 12 9 2 o 1 1 o o o •· ,,,,., ·'-• •O,, to Sell O 3 3 O 1 1 O O O .t,Jtct;,. .,, % TOT. RETURN 10/17 ,...8 Institutional Decisions -·· ••· •·· •· • • ~· • • ••· ·•·•· Percent-- 30 shares 20 :;11iJLl traded 10 I : .;:,11;;:~,,;-~,, ..::::::·:::,,,,,,:·,:: rn 1!t ·iir = u.2~0;0~1 ~2~0ijOi2J;2~0f0[3J:2~0~0~4i:=-~:!'12~00fil7ibJ!fi20082005 2006 2009 2010 2011 2012 2013 2014 2015 2016 2017 2018 @VALUELINEPUB.LLC 0-22 52.82 40,89 47.53 51.82 41.85 44.64 37.27 37.22 30.97 27.76 25.21 19.98 23.16 24.42 25.08 24.11 24.15 24.75 Revenues per sh 27.25 10.48 6.32 5.80 5.00 5.46 3.69 4.82 6.16 4.96 5.68 4.88 4.03 5.22 4.56 4.94 5.46 5.75 6.15 "Cash Flow'' per sh 7.50 1.37 1.08 1.24 .91 .98 .82 1.59 1.86 1.91 2.10 2.22 1.89 2.49 2.58 2.76 2.96 3.10 3.30 EamingspershA 4.00 .45 .53 ,58 .63 .68 .73 .78 .83 .95 1.03 1.10 1.32 1.47 1.57 1.67 1.78 1.90 2.02 Div'd Decl'd per sh 8 • 2.40 3.40 3.86 4.31 4.85 5.89 5.49 7.14 8.06 5.17 5.41 6.08 4.69 4.62 5.06 5.44 6.24 8.55 9.05 Cap'I Spending per sh 5.25 16.27 17.33 17.73 17.80 18.46 18.14 18.65 19.38 20.37 21.60 22.65 29.41 30.49 31.47 32.64 33.80 35.00 36.30 Book Value per sh c 40.75 130.13 127.56 127.70 129.03 131.59 154.23 156.22 155.83 175.62 176.45 177.16 314.05 315.27 316.98 317.19 316.89 316.89 316.89 Common Shs Outst'g O 316.89 14.1 16.1 13.4 20.8 19.8 27.1 18.7 13.7 12.0 13.4 15.4 19.9 16.9 17.9 18.1 18.7 Boldffg res are AvgAnn'IPIERatio 16.0 .72 .88 .76 1.10 1.05 1.46 .99 .82 .80 .85 .97 1.27 .95 .94 .91 .98 Value Une Relative PIE Ratio 1.00 2.3% 3.0% 3.5% 3.3% 3.5% 3.3% 2.6% 3.2% 4.2% 3.6% 3.2% 3.5% 3.5% 3.4% 3.3% 3.2% nlin ales Avg Ann'I Div'd Yield 3.7% CAPITAL STRUCTURE as of9/30/17 5822.2 5800.1 5439.4 4898.2 4465.7 6273.8 7301.2 7741.9 7954.8 7639.1 7650 7850 Revenues ($mill) 8650 Total Debt $11444 mill. Due in 5 Yrs $3718.4 mill. 251.5 296.2 335.6 377.8 400.3 533.0 793.7 827.1 886.0 949.8 990 1055 Net Profit ($mill) 1295 LT Debt $10468 mill. LT Interest $418.7 mill. 30.3% 29.7% 34.9% 36.6% 29.9% 34.0% 35.0% 36.2% 37.9% 36.9% 37.0% 37.0% Income Tax Rate 37.5% (LT interest earned: 4.8x) Leases, Uncapitalized Annual rentals $14.1 mill. 13.9% 15.8% 4.6% 7.1% 8.6% 2.3% 1.4% 2.4% 2.9% 3.9% 5.0% 4.0% AFUDC %to Net Profit 2.0% Pension Assets-12/16 $4076.0 mill. 59.2% 60.4% 57.2% 55.1% 53.4% 43.7% 44.3% 45.9% 45.6% 44.8% 45.5% 46.0% Long-Tenn Debt Ratio 47.5% Oblig $5242.3 mill. 39.2% 38.1% 41.5% 43.6% 45.3% 55.4% 54.8% 53.2% 53.6% 54.4% 53.5% 53.0% Common Equity Ratio 52.0% pfd Stock $155.6 mill. pfd Div'd $7.6 mill. 7431.1 7926,2 8629.5 8741.8 8856.0 16675 17544 18738 19313 19697 20675 21700 Total Capital ($mill) 24900 Incl. 2,324,000 shs $1.90-$3.28 rates ($50 par) not 7229,9 8207,9 8840.0 9567.7 10403 16605 17576 18647 19892 21351 23375 25500 Net Plant ($mill) 28700 subject to mandatory redemption, call. at $50.50- $54.00; 430,000 shs 4.25%-4.78% not subject to 5.0% 5.4% 5.4% 5.8% 5.9% 4.2% 5.5% 5.3% 5.5% 5.8% 5.5% 6.0% Return on Total Cap'I 6.0% mandatory redemption, call. at $102.80-$103.63. 8.3% 9.4% 9.1% 9.6% 9.7% 5.7% 8.1% 8.2% 8.4% 8.7% 9.0% 9.0% Return on 5hr. Equity 10.0% Common Stock 316,885,808 shs. as of 10/31/17 8.4% 9.6% 9.2% 9.8% 9.8% 5.7% 8.2% 8.2% 8.5% 8.8% 9.0% 9.0% Return on Com Equity E 10.0% MARKET CAP: $20 billion (Large Cap) 4.3% 5.3% 4.7% 5.0% 5.0% 1.6% 3.4% 3.5% 3.4% 3.5% 3.5% 3.5% Retained to Com Eq 4.0% ELECTRIC OPERATING STATISTICS 50% 45% 50% 49% 50% 72% 59% 58% 61% 6b% 61% 61% All Div'ds to Net Prof 59% %ChangeRelaUSales(KWH) 2~~: 2~~~ 2~/~ BUSINESS: Eversource Energy (formerly Northeast Utilities) is the Acquired NSTAR 4/12. Electric revenue breakdown: residential, Avg. lndust Use (MWH\ NA NA NA parent of utilities that have 3.1 million electric, 504,000 gas custom- 52%; commercial, 36%; industrial, 5%; other, 7%. Fuel costs: 33% Avg.lndusl.Revs,l)llrKWH(¢) 6.14 5.86 6.04 ers. Supplies power to most of Connecticut and gas to part of of revenues. '16 reported deprec. rate: 3.0%. Has 7,800 employ- ~~~a)'.~:~elli ~~ ~~ ~~ Connecticut; supplies power to three fourths of New Hampshire's ees. Chairman, President & CEO: James J. Judge. Inc.: Massachu- Annual LoadFacior(%) NA NA NA population; supplies power to western Massachusetts and parts of setts. Address: 300 Cadwell Drive, Springfield, Massachusetts %ChangeCuslomern(yr-end) NA NA NA eastern Massachusetts & gas to central & eastern Massachusetts. 01104. Tel.: 413-785-5871. Internet: www.eversource.com. F~edChargeCov.(%) 426 447 436 Eversource Energy is close to com- and volume. New tariffs will take effect in ANNUAL RATES Past Past Est'd'14.,16 pleting an acquisition of a water utili- early 2018. ofchange(persh) 10Yrs. 5Yrs. to'20-'22 ty. The company agreed to pay $880 mil- Eversource plans to file an electric Revenues -6.0% -2.5% 2.0% lion in cash for Aquarion Water, which rate case in Connecticut in late No- "Cash Flow" .5% -.5% 7.0% serves some 230,000 customers in Connec- vember. The utility intends to propose gf~~i~~~s 1~:g~ 1g:g~ i:g~ ticut, Massachusetts, and New Hamp- hikes of $255.8 million, $45 million, and BookValue 6.0% 8.5% 4.0% shire. Eversource would also assume $795 $36 million in May of 2018, 2019, and Cal- QUARTERLYREVENUES($mill.) Full million of debt. All approvals have been 2020, respectively. A ruling is expected endar Mar.31 Jun.30 Sep.30 Dec.31 Year received except that of the Massachusetts next spring. 2014 2290 1677 1892 1881 7741 _9 regulators. The company expects to fi- We estimate earnings growth of 5% 2015 2513 1817 1933 1691 7954.8 nance the purchase with debt and the pro- this year and 6% in 2018. This is within 2016 2056 1767 2040 1776 7639.1 ceeds of its pending sale of its generating Eversource's 5%-7% target for annual prof- 2017 2105 1763 1989 1793 7650 assets in New Hampshire. Management it growth. Increases in the transmission 2018 2200 1800 2000 1850 7850 believes the income from the Aquarion rate base, rate relief, customer conversions Cal- EARNINGS PER SHARE A Full deal will offset the lost earnings from the to gas heat from oil heat, and effective cost endar Mar.31 Jun.30 Sep.30 Dec.31 Year sale of the generating assets. Our esti- control should help. Management's guid- 2014 .74 .40 _74 _69 2_58 mates and projections will not include ance for 2017 share profits is $3.05-$3.20. 2015 .80 .65 .74 .57 2.76 Aquarion or the asset sale until these have We expect a dividend increase in the 2016 .77 .64 .83 .72 2.96 been completed. first quarter of 2018. We estimate a 2017 .82 .72 .82 .74 3.10 Orders on the company's rate cases in boost of $0.12 a share (6.3%) in the annual 2018 .90 .75 .90 .75 3.30 Massachusetts should come soon. The payout, the same as in 2017. Eversource's Cal- QUARTERLYDMDENDSPAID s. Full utilities in eastern and western Massachu- goal for dividend growth is 5%-7% annual- endar Mar.31 Jun.30 Seo.30 Dec.31 Year setts are seeking tariff hikes totaling $96 ly, the same as for earnings growth. 2013 _3675 _3675 _3675 _3675 1.47 million, based on a return of 10.5% on a This timely stock has a dividend yield 2014 .3925 .3925 .3925 .3925 1.57 common-equity ratio of 53.5%. The two and 3- to 5-year total return potential 2015 .4175 .4175 .4175 .4175 1.67 utilities also want to combine into one that are about average, by utility 2016 .445 .445 .445 .445 1.78 entity and are asking for a regulatory me- standards. 2017 .475 .475 .445 chanism that decouples electric revenues Paul E. Debbas, CFA November 17, 2017 (A) Oil. EPS. Exel. nonrec. gains (losses): '02, Div'ds historically paid late Mar., June, Sept., & '16, 9.8%; in CT: (elec.) '15, 9.02%; (gas) '15, Company's Financial Strength A 10¢; '03, (32¢); '04, (7¢); '05, ($1.36); '08, Dec. • Div'd reinvest. plan avail. (C) Incl. defd 9.5%; in NH: '10, 9.67o/o; earned on avg. com. Stock's Price Stability 100 (19¢); '10, 9¢. '14 EPS don't add due to round- chgs. In '16: $22.59 sh. (D) In mill. (E) Rate eq., '16: 9.0%. Regulatory Climate: CT, Below Price Growth Persistence 80 ing. Next earnings report due early Feb. (Bl all'd on com. eq. in MA: (elec) '11, 9.6%; (gas) Avg.; NH, Avg.; MA, Above Avg. Earnings Predictability 85 <> 2017 Value Line, Inc. All lights reserved. Factual material is obtained from sources beTieved to be reliable and is provided without warranties of any kind. - THE PUBLISHER IS NOT RESPONSIBLEFORANY ERRORS OR OMISSIONS HEREIN. This publication is strictly for subscliber's own, non-commercial, internal use. No part I I I ' • 1~:il1IP\W1lll:l!IWJ.a of it may be reproduced, resold, stored or transmitted in any plinted, electronic or other form, or used for generating or marketing any plinted or electronic publication, service or product - Attachment BEL-8 No 44988 IRECENT 64 20 IP/E 28 oerailing:29.2) RELATIVE 13 8 DIV'D ' Pag• 6 of9 MGE ENERGY INC. NDQ-MGEE PRICE , RATIO , Median: 16.0 P/E RATIO I YLD 2.0% TIMELINESS 4 lowered 8/18/17 High: 24.7 24.8 24.3 25.5 29.1 31.9 37.4 40.5 48.0 48.0 66.9 68.7 Target Price Range Low: 19.5 19.6 18.6 18.2 21.4 24.7 28.7 33.4 35.7 36.5 44.8 60.3 2020 2021 2022 SAFETY 1 New1/3/03 LEGENDS 120 , .. :' TECHNICAL 3 Lowered 12/8/17 - ai~i:d ~vi1;t~~ ~~te 100 . • • • Relative Price Strength .·. 80 BETA .75 (1.00=Marl .. "" "" 29.18 32.57 31.49 30.79 35.09 31.72 30.66 30.80 28.76 29.80 25.68 25.21 26.01 26.80 27.95 Revenues per sh 32.00 .. "" "" 3.20 4.00 3.62 -3.70 4.40 4.62 4.76 5.42 5.18 5.45 5.39 5.92 6.74 6.90 7.15 "Cash Flow'' per sh 8.25 "" "" .. d14.32 1.71 1.31 1.44 1.77 2.02 2.14 2.53 2.26 2.46 2.99 2.90 3.39 3.40 3.50 Earnings per sh A 4.00 "" "" "" "" 1.00 1.24 1.28 1.32 1.34 1.36 1.44 1.48 1.52 1.60 1.92 2.00 2.10 2.20 Div'd Decl'd per sh 6 ■ t 2.50 "" "" "" 2.25 2.26 2.81 3.00 3.47 5.26 6.30 5.20 5.89 5.95 5.76 5.89 5.96 6.15 6.60 Cap'I Spending per sh 6.75 "" "" "" 19.92 20.60 20.65 21.12 21.25 21.86 22.64 23.68 25.09 26.60 31.50 33.22 34.68 35.85 37.05 Book Value per sh c 41.00 "" "" "" 35.60 35.79 35.97 38.97 35.93 36.00 36.23 36.28 37.22 38.75 46.91 48.17 48.33 48.50 48.65 Common Shs Outst'g 0 49.10 "" "" "" "" 17.1 26.0 21.7 13.9 11.5 12.9 12.6 15.7 16.9 16.2 18.4 17.2 Bold fig res are Avg Ann'I PIE Ratio 15.0 Vslue Line "" "" "" "" .91 1.40 1.15 .84 .77 .82 .79 1.00 .95 .85 .93 .90 Relative PIE Ratio .95 esffn atu "" "" "" "" 3.4% 3.6% 4.1% 5.4% 5.7% 4.9% 4.5% 4.2% 3.7% 3.3% 3.6% 3.4% Avg Ann'I Div'd Yield 4.1% CAPITAL STRUCTURE as of 6/30/17 1200.1 1260.8 1141.9 1110.7 1117.3 1070.3 1154.5 1204.9 1214.3 1257.2 1300 1360 Revenues ($mill) 1575 Total Debt $2122.8 mill. Due in 5 Yrs $565.3 mill. 53.2 67.6 73.4 77.4 92.6 83.7 94.0 120.7 138.4 164.2 165 170 Net Profit ($mill) 200 LT Debt $1817.1 mill. LT Interest $83.6 mill. 37.8% 37.3% 17.2% 25.0% 9.8% 9.6% 13.2% .. 13.7% 13.7% 8.5% 12.0% Income Tax Rate 20.0% Incl. $23.3 mill. capitalized leases. (LT interest earned: 3.0x) 2.5% 2.3% 4.4% 14.2% 3.3% 9.4% 8.7% 8.9% 9.8% 4.3% 6.0% 6.0% AFUDC 'lo to Net Profit 5.0% 50.1% 46.8% 56.4% 57.2% 52.2% 53.8% 53.5% 53.4% 53.1% 52.0% 51.0% 47.0% Long-Term Debt Ratio 48.0% 49.9% 53.2% 43.6% 42.8% 47.8% 46.2% 46.5% 46.6% 46.9% 48.0% 49.0% 53.0% Common Eauitv Ratio 52.0% Pension Assets-12/16 $524.6 mill. 1648.4 1434.3 1803.9 1916.4 1797.1 2020.7 2215.7 3168.0 3408.6 3493.9 3530 3400 Total Capital ($mill) 3850 Oblig $646.0 mill. 1770.9 1839.7 1964.1 2118.0 2213.3 2435.6 2690.1 3758.0 4059.5 4214.9 4345 4485 Net Plant ($mill) 4875 Pfd Stock None 5.0% 7.0% 6.0% 5.9% 7.0% 5.5% 5.5% 4.8% 5.2% 5.9% 6.0% 6.0% Return on Total Cap'I 6.0% Common Stock 48,471,447 shs. 6.5% 8.9% 9.3% 9.4% 10.8% 9.0% 9.1% 8.2% 8.6% 9.8% 9.5% 9.5% Return on Shr. Equity 10.0% as of 7/21/17 6.5% 8.9% 9.3% 9.4% 10.8% 9.0% 9.1% 8.2% 8.6% 9.8% 9.5% 9.5% Return on Com Eauitv E 10.0% MARKET CAP: $2.8 billion (Mid Cap) .7% 2.3% 3.2% 3.5% 4.7% 3.2% 3.5% 3.8% 3.0% 4.1% 3.5% 3.5% Retained to Com Eq 4.0% ELECTRIC OPERATING STATISTICS 89% 74% 66% 63% 56% 65% 61% 54% 65% 58% 62% 63% All Div'ds to Net Prof 62% 2014 2015 2016 %Change Relail Sales (KWH) +.7 ·,1 ·.7 BUSINESS: NorthWestern Corporation (doing business as North- 5%; other, 4%. Generating sources: hydro, 34%; coal, 30%; other, Avg. lndusl Use (MWHl&IH 28987 30133 29784 Western Energy) supplies electricity & gas in the Upper Midwest 10%; purchased, 26%. Fuel costs: 32% of revenues. '16 reported Avg. lndusl Revs./: (¢) NA NA NA and Northwest, serving 427,000 electric customers in Montana and deprec. rate: 3.0%. Has 1,600 employees. Chainnan: Dr. E. Linn CapacilyatPeak( ) NA NA NA South Dakota and 283,000 gas customers in Montana (87% of Draper Jr. President & CEO: Robert C. Rowe. Incorporated: Dela• Peak Load, 'Mnter (Mw) 2044 2096 2138 Annual Load Factor(%/ NA NA NA gross margin), South Dakota (12%), and Nebraska (1%). Electric ware. Address: 3010 West 69th Street, Sioux Falls, South Dakota %Change Custornern yr-end) +1.0 +1.3 +1.2 revenue breakdown: residential, 40%; commercial, 51 %; industrial, 57108. Tel.: 605-978-2900. Internet: www.northwesternenergy.com. Fixed Charge Cov. (%) 217 252 253 NorthWestern received a gas rate in- The company is awaiting resolution of crease in Montana. The Montana Public two legal matters. NorthWestern ap- ANNUAL RATES Past Past Est'd '14-'16 of change (per sh) 10Yrs. 5Yrs. to '20·'22 Service Commission (MPSC) raised rates pealed an unfavorable ruling from the Revenues ·2.0% -4.0% 4.0% by $5.1 million, based on a 9.55% return Federal Energy Regulatory Commission to "Cash Flow" 5.5% 4.0% 5.5% on a 46.8% common-equity ratio. This was the U.S. Circuit Court of Appeals. The reg- Earnings "" 7.0% 4.5% Dividends 9.5% 6.0% 5.0% less than the $5.7 million the company ulators had ruled that only 4% of the cost Book Value 5.0% 8.0% 3.5% had reached in a settlement with the of a new gas-fired plant may be allocated MPSC's staff and some intervenors, and to its (federally regulated) wholesale busi- Cal- QUARTERLY REVENUES ($ mill.) Full endar Mar.31 Jun.30 Sep.30 Dec.31 Year well below the $9.4 million the utility had ness, instead of the 20% the utility re- sought in rebuttal testimony. The allowed quested. This forced the company to take a 2014 369.7 270.3 251.9 313.0 1204.9 2015 346.0 270.6 272.7 325.0 1214.3 ROE is a reduction from the previous $0.12-a-share charge in 2012. A ruling 2016 332.5 293.1 301.0 330.6 1257.2 9.8%. New tariffs took effect at the start of might come as early as the current 2017 367.3 283.9 310 338.8 1300 September. quarter. NorthWestern also appealed an 2018 375 310 325 350 1360 There is a regulatory uncertainty in unfavorable MPSC ruling to the state Montana. The MPSC changed the fuel- courts. Its dis allowance of certain costs Cal- EARNINGS PER SHARE A Full endar Mar.31 Jun.30 Sep.30 Dec.31 Year adjustment clause, which raises the risk of hurt the bottom line by $0.13 a share in the first quarter of 2016 (included in our 2014 1.17 .20 .77 .85 2.99 a disallowance of power costs for North- 2015 1.09 .38 .51 .93 2.90 Western in the state. Note that the utility earnings presentation). A decision is likely 2016 .82 .73 .92 .92 3.39 expects to file an electric rate case in the by July. 2017 1.17 .44 .76 1.03 3.40 state in 2018 . This stock's dividend yield is slightly 2018 1.15 .45 .80 1.10 3.50 We have trimmed our 2017 and 2018 above the utility average. Total return share-earnings estimates by a nickel. potential to 2020-2022 is unimpressive, Cal- QUARTERLY DMDENDS PAID 6 ■ t Full endar Mar.31 Jun.30 Sen.30 Dec.31 Year This reflects June-quarter results that but still a bit higher than the industry were below our estimate. Our revised fore- mean. As is true for most utility equities, 2013 .38 .38 .38 .38 1.52 of NorthWestern 2014 .40 .40 .40 .40 1.60 cast is at the midpoint of NorthWestern's the recent quotation 2015 .48 .48 .48 .48 1.92 targeted range of $3.30-$3.50. Earnings stock is within our 3- to 5-year Target 2016 .50 .50 .50 .50 2.00 growth in the near term is likely to be in Price Range. 2017 .525 .525 .525 the low single-digit range . Paul E. Debbas, CFA October 27, 2017 (AJ Diluted EPS. Exel. gain (loss) on disc. ops.: historically paid in late Mar., June, Sept. & Dec. cost. Rate allowed on com. eq. in MT in '14 Company's Financial Strength B+ '05, (6¢); '06, 1¢; nonrec. gains: '12, 39¢ net; • Div'd reinvest. plan avail. t Shareholder in· (elec.): 9.8%; in '17 (gas): 9.55%; in SD in '15: Stock's Price Stability 95 '15, 27¢. '15 EPS don't add due to rounding. vest. plan avail. (C) Incl. defd charges. In '16: none specified; in NE in 07: 10.4%; earned on Price Growth Persistence 85 Next earnings report due early Nov. (BJ Div'ds $19.87/sh. (DJ In mill. (EJ Rate base: Net orig. avg. com. eq., '16: 10.1%. Regul. Climate: Avg. Earnings Predictability 85 " 2017 Value Line, Inc. All ~hts reserved. Factual material is obtained from sources believed to be reliable and is provided without warranties of anfu ~nd. - , THE PUBLISHER IS NOT RESP NSIBLE FOR ANY ERRORS OR OMISSIONS HEREIN. This ublication is stJicliy forsubscriber's own, non-commercial, internal use. o pan I I I ' , l":illll'll/11111::l ■ ml:. of it may be reproduced, resold, stored or transmitted in any printed, electronic or other form, or us~ for generating or marketing any printed or elec~onic publication, service or product. Attachment BEL-8 Cause No 44988 IRECENT 68 28 IP/E 25 2crailing:25,2) RELATIVE 124 DIV'D Page 8 of9 VECTREN CORP. NYSE-WC PRICE , RATIO , Median: 16,0 P/E RATIO I YLD 2.7%_lill TIMELINESS 2 Lowered 12/8117 High: 29.3 30.5 32.2 26.9 27.8 30.7 30.8 37.9 48.3 49.5 53.3 69.9 Target Price Range Low: 25.2 24.8 19.5 18.1 21.7 23.7 27.5 29.5 34.6 37.3 39.4 51.5 2020 2021 2022 SAFETY 2 Lowered 1/5/01 LEGENDS .. 128 TECHNICAL Raised 11/17117 - di~i~:d ~vif;re~~sr ~~te 3 , • • • Relative ~rice Strength 96 BETA .75 (1.00 • Market) 0 -- 80 ff~~~~~yir!a indicates recession 1/ ...... - - ,. 2020-22 PROJECTIONS ...... 64 •I•· .. .. --- .... ' ...... - Ann'I Total / ... ' ----- Price Gain Return ,, ,,, r, I ...... 48 ·1 ----- 40 High 60 Nil 1•1 II ti I 45 1-10%!-35% -6% 32 Law .... ,,_,,, ,,u~I ll!ll .. 1f11 11J11 '11,--11 " 11,i•:1. 111 11l'1l1!J'J Insider Decisions .. , ,, 24 .... : 111! ... F M A M J J A S 0 .... ······ ...... , .... to Buy 0 0 0 0 0 0 0 1 O ·······-- . - ...... 16 Options 0 0 0 0 0 0 0 0 0 ··-· . ······ .... ····· ······ .. ·•···· ... ·...... ··• ,...12 to Sell 0 0 0 0 0 0 0 0 0 % TOT, RETURN 11/17 Institutional Decisions THIS VLARITH.* 1Q2017 2Q2017 3Q2017 I J, ·" I I STOCK INDEX Percent 12 h,I , .. II 1 yr. 45.7 16.8 to Buy 152 153 147 8 - "'"~ shares 11111 1111 .1111 1= TTTTTITlll 3yr. 73.4 30.2 to Sell 130 146 141 traded 4 ~ Hld's/000\ 60445 59555 60216 I 11111 1111111111 ll[TITTTTI TTTJTHIII IIIITnITT,,l1111111111111IIII 5 yr. 183.3 96.6 Vectren was formed on March 31, 2000 2007 2008 2009 2010 2011 2012 2013 2014 2015 2016 2017 2018 @ VALUE LINE PUB. LLC 1, 0-22 through the merger of Indiana Energy and 29.88 30.67 25.76 26.06 28.39 27.16 30.23 31.62 29.40 29.53 31.75 32,75 Revenues per sh 38.95 SIGCORP. The merger was consummated 4.29 3.97 4.40 4.44 4.71 5.03 5.03 5.33 5.48 5.69 5.85 6.20 "Cash Flow'' per sh 7.75 with a tax-free exchange of shares and has 1.83 1.63 1.79 1.65 1.73 1.94 1.66 2.02 2.39 2.55 2.65 2.80 Earnings per sh A 3.35 been accounted for as a pooling of interests. 1.27 1.31 1.35 1.37 1.39 1.41 1.43 1.46 1.54 1.62 1.71 1.83 Div'd Decl'd per sh 8■t 2.10 Indiana Energy common stockholders 4.38 4.83 5.33 3.39 3.92 4.45 4.77 5.43 5.76 6.54 7.20 7.60 Cap'I Spending per sh 9.30 received one Vectren common share for 16.16 16.68 17.23 17.61 17.89 18.57 18.86 19.45 20.34 21.33 22.05 23.10 Book Value per sh c 27.90 each share held. SIGCORP stockholders 76.36 81.03 81.10 81.70 81.90 82.20 82.40 82.60 82.80 82.90 83.50 84.00 Common Shs Outst'g 0 86.00 exchanged each common share for 1.333 15.3 16.8 12.9 15.0 15.8 15.0 20.7 20.0 17.9 19.2 Bold fig res are Avg Ann'I PIE Ratio 16.0 common shares of Vectren. .81 1.01 .86 .95 .99 .95 1.16 1.05 .90 1.01 Value Line Relative PIE Ratio 1.00 estin ates CAPITAL STRUCTURE as of 9/30117 4.5% 4.8% 5.9% 5.5% 5.1% 4.8% 4.2% 3.6% 3.6% 3.3% Avg Ann'I Div'd Yield 3.9% Total Debt $2040.0 mill. Due in 5 Yrs $633.5 mill. 2281.9 2484.7 2088.9 2129.5 2325.2 2232.8 2491.2 2611.7 2434.7 2448.3 2650 2750 Revenues ($mill) 3350 LT Debt $1639.1 mill. LT Interest $75.0 mill. 143.1 129.0 145.0 133.7 141.6 159.0 136.6 166.9 197.3 211.6 220 235 Net Profit ($mill) 290 (LT interest earned: 5.0x) 34.7% 37.1% 26.5% 35.8% 37.9% 34.2% 32.9% 32.7% 33.6% 34.8% 35.0% 35.0% Income Tax Rate 35.0% Pension Assets-12116 $304.5 mill. 2.8% 2.9% 4.1% ------4.1% 4.0% 4.0% 4.0% AFUDC % to Net Profit 4.0% Oblig. $350.4 mill. 50.2% 48.0% 52.4% 49.9% 51.6% 50.4% 53.3% 46.7% 50.6% 47.3% 47.5% 47.5% Long-Term Debt Ratio 45.5% Pfd Stock None 49.8% 52.0% 47.6% 50.1% 48.4% 49.6% 46.7% 53.3% 49.4% 52.7% 52.5% 52.5% Common Equity Ratio 54.5% 2479.1 2599.5 2937.7 2874.1 3025.1 3079.5 3331.4 3013.9 3406.6 3358.0 3490 3690 Total Capital ($mill) 4400 Common Stock 83,002,391 shs. 2539.7 2720.3 2878.8 2955.4 3032.6 3119.6 3224.3 3439.0 4089.5 4406.8 4700 4950 Net Plant ($mill) 5750 as of 10131/17 7.2% 6.5% 6.3% 6.1% 6.2% 6.4% 5.4% 6.8% 7.0% 7.4% 7.5% 7.5% Return on Total Cap'I 7.5% 11.6% 9.5% 10.4% 9.3% 9.7% 10.4% 8.8% 10.4% 11.7% 12.0% 12.0% 12.0% Return on Shr. Equity 12.0% MARKET CAP: $5.7 billion (Large Cap) 11.6% 9.5% 10.4% 9.3% 9.7% 10.4% 8.8% 10.4% 11.7% 12.0% 12.0% 12.0% Return on Cam Equity E 12.0% ELECTRIC OPERATING STATISTICS 3.8% 2.0% 2.6% 1.6% 1.9% 2.9% 1.2% 2.9% 4.2% 4.4% 4.0% 4.5% Retained to Com Eq 5.0% 2014 2015 2016 67% 80% 75% 83% 80% 73% 86% 72% 65% 63% 65% 65% All Div'ds to Net Prof 62% %Change Relail Sales (KWH) +2.0 -2.4 +.3 Avg. Indus!. Use (MWH~ NA NA NA BUSINESS: Vectren Corp. is a holding company formed through 67%; commercial, 23%; other, 10%. Non utility operations include Avg. Indus!. Revs. per H(¢) NA NA NA the merger of Indiana Energy and SIGCORP. Supplies electricity Infrastructure Services and Energy Services. Est'd plant age: elec- Capaci~ al Peak (Mw~ 1407 1357 1360 and gas to an area nearly two-thirds of the state of Indiana. Owns tric, 10 years. '16 depreciation rate: 4.0%. Has about 5,800 employ- Peak Load, Summer! w) 1095 1088 1096 Annual Load Factor I¼/ NA NA NA gas distribution assets in Ohio. Has a customer base exceeding 1.1 ees. Chairman, President, & CEO: Carl L. Chapman. Incorporated: %Change Cuslomern yr-end) +.6 +.7 +.8 million. 2016 Electricity revenues: residential, 37%; commercial, Indiana. Address: One Vectren Square, Evansville, Indiana 47708. 27%; industrial, 34%; other, 2%. 2016 Gas revenues: residential, Telephone: 812-491-4000. Internet: www.vectren.com. Fixed Charge Gov.(%) 363 428 446 ward. Performance at the utility group ANNUAL RATES Past Past Est'd '14-'16 Shares of Vectren have traded in a of change (per sh) 10 Yrs. 5Yrs. ta '20-'22 fairly narrow range over the past ought to be supported by investment in Revenues 2.0% 2.5% 4.5% three months. This has followed a nice gas infrastructure programs in both Indi- "Cash Flow" 4.5% 4.0% 6.0% rally that began in late 2016. The compa- ana and Ohio. Meanwhile, the nonutility Earnings 4.0% 6.0% 6.5% Dividends 2.5% 2.5% 5.5% ny reported solid top-line growth for the group should further benefit from healthy Book Value 3.0% 3.0% 5.5% September period. Performance at the demand for distribution services, as gas nonutility group benefited from strong re- utilities continue to make significant in- Cal- QUARTERLY REVENUES($ mill.)F Full endar Mar.31 Jun. 30 Sep. 30 Dec. 31 Year sults at the infrastructure services opera- vestments in their infrastructure systems. tion, reflecting large pipeline projects this The transmission business will likely be 2014 796.8 542.5 595.6 676.8 2611.7 2015 706.2 551.0 573.5 604.0 2434.7 year. But the utility group fared less well, able to capitalize on high demand due to 2016 584.8 533.7 631.0 699.0 2448.3 owing to a decline in usage from a large the need to replace aging infrastructure, 2017 624.5 630.7 691.2 703,6 2650 electric customer that completed its transi- though we do expect a measure of uneven- 2018 655 655 710 730 2750 tion to a co-generation facility and lower ness here going forward. electric margins. Moreover, growth in total Short-term traders may want to take Cal- EARNINGS PER SHARE A Full endar Mar.31 Jun. 30 Sep. 30 Dec. 31 Year operating expenses outstripped that of rev- a closer look. This issue is well ranked for Timeliness. Moreover, Vectren earns 2014 .62 .14 .57 .69 2.02 enue, and share net advanced just mod- 2015 .69 .43 .48 .79 2.39 estly, to $0.75. Looking forward, we expect good marks for Safety, Financial Strength, 2016 .58 .39 .74 .84 2.55 solid performance will continue in the Price Stability, and Earnings Predictabili- 2017 .67 .45 .75 .78 2.65 fourth quarter, but earnings per share will ty. Volatility is subdued, as well . 2018 .70 .48 ,76 ,86 2.80 probably not match the impressive figure But patient investors can probably find more-suitable choices elsewhere. Cal- QUARTERLY DIVIDENDS PAID 8■t Full generated in the year-ago period. endar Mar.31 Jun.30 Seo.30 Dec.31 Year The board of directors has raised the The stock presently trades at a price-to- dividend by 7%. Starting with the De- earnings multiple that is well in excess of 2013 .355 .355 ,355 .360 1.43 historical As result, this 2014 .360 .360 ,360 .380 1.46 cember payout, the quarterly dividend is its average. a 2015 .380 .380 .380 .400 1.54 now $0.45 per share. Healthy dividend equity lacks long-term appreciation poten- 2016 .400 .400 .400 .420 1.62 growth will probably continue. tial at this time. Also, the dividend yield 2017 .420 .420 .420 .450 Revenues and earnings should in- does not stand out for a utility. crease at a good pace from 2018 on- Michael Napoli, CPA December 15, 201 7 (A) Diluted EPS. Exel. nonrecur. gain (loss): vest. plan avail. t Shareholder invest. plan equity range from 10.15% to 10.4%. Regu- Company's Financial Strength A '09, 15¢. Next egs report due late February. avail. (C) Incl. intang. In '16, $7.27/sh. (D) In latory Climate: Above Average. (Fl Totals may Stock's Price Stability 90 (8) Div'ds historically paid in early March, millions. (E) Electric rate base determination: not sum due to rounding. Price Growth Persistence 70 June, September, and December. •Div'd rein- fair value. Rates allowed on elect. common Earnings Predictability 75 © 2017 Value Line, Inc. Al! rights reserved. Factual material is obtained from sources believed to be reliable and is provided without warranties of any kind. THE PUBLISHER IS NOT RESPONSIBLE FOR ANY ERRORS OR OMISSIONS HEREIN. This Jublication is strictly for subscriber's own, non-commercial, internal use. No part ■ 11•• 11 11..~MIII ••~. lla~:il\ll'lf/111 I 1:11 I 1,11 a of it may be reproduced, resold, stored or transmitted in any printed, electronic or other form, or use for generating or marketing any printed or electronic publication, service or product. Attachment BEL-8 C\rnsP No. 44988 IRECENT 68 24 IPIE 211 crailing:22.4) RELATIVE 104 DIV'D Pag1 9 of9 WEC ENERGY GROUP NYSE-WEC PRICE , RATIO , Median: 16.0 PIE RATIO I YLD 3.2%11ri TIMELINESS 4 Lowered 11/24n7 High: 24.3 25.2 24.8 25.3 30.5 35.4 41.5 45.0 55.4 58.0 66.1 70.1 Target Price Range Low: 19.1 20.5 17.4 18.2 23.4 27.0 33.6 37.0 40.2 44.9 50.4 56.1 2020 2021 2022 LEGENDS SAFETY 1 Raise Summary of Discounted Cash Flow Analysis (DCF) DCF formula: K = (D 1 IP 0) + g Gas Utility Proxy Group: Dividend Yield (D 1/P0): 2.9% see page 2 and 3 Dividend Growth (g): 5.9% see page 4 and 5 IDCF Cost of Equity (K): I 8.8%1 Attachment BEL-9 Cause No. 44988 Page 2 of6 Value Line Dividend Yield Data (December 1, 2017) Value Line Forward Yield D1/P0 (December 1, Gas Utility Group Companies: 2017) Atmos Energy Corp. (ATO) 2.2% New Jersey Resources (NJR) 2.5% Northwest Natural Gas (NWN) 2.9% South Jersey Industries (SJI) 3.5% Southwest Gas (SWX) 2.5% Spire, Inc. (SR) 2.9% Gas Utility Group Average 2.8% Forward Dividend Yields: Average Dividend Yield, adjusted for growth by (1 + 0. 5 g) D 1/P0 = D0/P0 * (1 + 0.5g) = 2.8% * [I+ 0.5(0.059)] = 2.9% Value Line Forward Yield (Di/P0) = 2.8% Use for forward yield (D 1/P 0): 2.9% Attachment BEL-9 Cause No. 44988 Page 3 of6 Summary of Discounted Cash Flow Analysis (DCF) Growth Estimates Gas Utility Group: From Standard Edition Value Line: Average of Value Line forecasted growth rates 5.2% Average of 5 year historical growth 5.3% Average 10 year historical growth: 5.4% Earnings Per Share (Value Line Forecasted) 6.1% Earnings Per Share (Past 5 Years) 5.6% Earnings Per Share (Past 10 Years) 5.6% Dividends Per Share (Value Line Forecasted) 4.6% Dividends Per Share (Past 5 Years) 5.8% Dividends Per Share (Past 10 Years) 5.5°/4 Book Value Per Share (Value Line Forecasted) 4.8% Book Value Per Share (Past 5 Years) 6.4% Book Value Per Share (Past 10 years) 6.1% Nominal GDP Growth From Federal Reserve Bank o{St. Louis Average% Growth in Nominal GDP (1948 to 2016) 6.5% Average% Growth in Nominal GDP (1980 to 2016) 5.4% Projected Growth in Nominal GDP Congressional Budget Office (2017 to 2027) 3.9% IUse DCF Growth Rate 5.9%1 Value Line Growth Rates STANDARD VALUE LINE COMPANIES- Gas Utility Group Annual Growth - Past 10 Years Annual Growth - Past 5 Years Annual Growth - Value Line Projected Average Growth Rates Book Book Value Earnings Dividends Value Per Earnings Dividends Value Per Earnings Per Dividends Book Value Past 10 Past5 Line Company Name Per Share Per Share Share Per Share Per Share Share Share Per Share Per Share Years Years Projected Atmos Energy Corp. (ATO) 6.0% 2.5% 5.0% 8.0% 3.5% 5.5% 6.0% 6.5% 3.5% 4.5% 5.7% 5.3% New Jersey Resources (NJR) 7.5% 7.5% 7.5% 8.0% 6.5% 7.5% 2.0% 3.5% 6.0% 7.5% 7.0% 3.8% Northwest Natural Gas (NWN) 0.0% 3.5% 3.0% -4.5% 2.0% 2.0% 7.0% 1.0% 2.0% 2.2% -0.2% 3.3% South Jersey Industries (SJI) 4.0% 9.0% 8.0% 1.5% 8.5% 9.0% 5.5% 4.0% 6.0% 7.0% 6.3% 5.2% Southwest Gas (SWX) 6.5% 7.0% 5.5% 6.5% 10.0% 5.5% 8.0% 7.5% 7.0% 6.3% 7.3% 7.5% Spire, Inc. (SR) 4.0% 3.5% 7.5% 4.0% 4.0% 9.0% 8.0% 5.0% 4.5% 5.0% 5.7% 5.8% Gas Utility Group Average 5.6% 5.5% 6.1% 5.6% 5.8% 6.4% 6.1% 4.6% 4.8% 5.4% 5.3% 5.2% Source: Value Line Investment Survey, December 1, 2017. Note: Zero and negative growth rates removed from calculations. > (".);:I: ~ ~ "'d;= s=- ~ ~ ~ ~ 0 .... n, • = .,:.. :!: t_,rj O IC t"' .... QO I O'I QO IC ,, Attachment BEL-9 Cause No. 44988 Page 5 of6 Growth in Nominal Gross Domestic Product, 1948 to 2016 % Change % Change in Nominal in Nominal Year GDP Year GDP 1948 7.90% 1980 9.90% 1949 -3.40% 1981 9.90% 1950 18.30% 1982 3.80% 1951 11.50% 1983 11.40% 1952 7.10% 1984 9.30% 1953 1.50% 1985 7.40% 1954 3.60% 1986 4.90% 1955 9.40% 1987 7.60% 1956 5.40% 1988 7.80% 1957 3.20% 1989 6.50% 1958 5.50% 1990 4.60% 1959 5.90% 1991 4.30% 1960 2.40% 1992 6.70% 1961 7.60% 1993 5.00% 1962 5.50% 1994 6.30% 1963 6.80% 1995 4.30% 1964 6.70% 1996 6.30% 1965 10.70% 1997 6.10% 1966 8.00% 1998 6.10% 1967 5.80% 1999 6.50% 1968 9.90% 2000 5.50% 1969 7.30% 2001 2.20% 1970 4.90% 2002 3.80% 1971 9.50% 2003 6.50% 1972 11.60% 2004 6.30% 1973 11.10% 2005 6.50% 1974 8.40% 2006 5.10% 1975 10.20% 2007 4.40% 1976 9.80% 2008 -0.90% 1977 11.90% 2009 0.20% 1978 14.60% 2010 4.60% 1979 10.00% 2011 3.70% 2012 3.30% 2013 4.30% 2014 4.10% 2015 3.00% 2016 3.50% Avg.% Change 1948 to 2016 6.51% Avg.% Change 1980 to 2016 5.43% Source: Federal Reserve Economic Data, https:/lfred.stlouisfed.org, Federal Reserve Bank ofSt. Louis, Economic Research Division Attachment BEL-9 Cause No. 44988 Page 6 of6 Forecasted Annual Percentage Growth in Nominal GDP Congressional Budget Office, June 2017 % Nominal Calendar GDP Year Growth 2017 4.0% 2018 4.2% 2019 3.6% 2020 3.4% 2021 3.8% 2022 4.0% 2023 4.0% 2024 4.0% 2025 4.0% 2026 4.0% 2027 4.0% Average Growth 3.9% Source: Congressional Budget Office, Budget and Economic Outlook 2017-2027, June 2017 Update Attachment BEL-10 Cause No. 44988 Page 1 of6 Summary of Discounted Cash Flow Analysis (DCF) DCFformula: K = (D 1 IP 0) + g Combination Utility Group: Dividend Yield (DifP0): 3.1% see page 2 and 3 Dividend Growth (g): 5.9% see page 4 and 5 IDCF Cost of Equity (K): I 9.0%1 Attachment BEL-10 Cause No. 44988 Page 2 of6 Value Line Dividend Yield Data (December 15, 2017) Value Line Forward Yield D1/P0 (December 15, Combination Utility Group Companies: 2017) Alliant Energy (LNT) 3.0% Black Hills Corp.(BKH) 2.8% CMS Energy Corp. (CMS) 2.9% Consolidated Edison (ED) 3.2% Eversource Energy (ES) 3.1% MGE Energy, Inc. (MGEE) 2.0% Northwestern (NEW) 3.7% Vectren Corp. (VVC) 2.7% WEC Energy Group (WEC) 3.2% Gas Group Average 3.0% Forward Dividend Yields: Average Dividend Yield, adjusted for growth by (1 + 0.5g) Di/P0 = D0/P0 * (1 + 0.5g) = 3.0% * [1 + 0.5(0.059)] = --3.1% Value Line Forward Yield (Di/P0) = IUse for forward yield (D1/P0): I 3.1 %1 Attachment BEL-10 Cause No. 44988 Page 3 of6 Summary of Discounted Cash Flow Analysis (DCF) Growth Estimates Combination Utility Group: From Standard Edition Value Line: Average of Value Line forecasted growth rates 5.2% Average of 5 year historical growth 6.4% Average 10 year historical growth: 5.8% Earnings Per Share (Value Line Forecasted) 5.8% Earnings Per Share (Past 5 Years) 6.7% Earnings Per Share (Past 10 Years) 6.4% Dividends Per Share (Value Line Forecasted) 5.2% Dividends Per Share (Past 5 Years) 6.7% Dividends Per Share (Past 10 Years) 6.3% Book Value Per Share (Value Line Forecasted) 4.7% Book Value Per Share (Past 5 Years) 5.3% Book Value Per Share (Past 10 years) 4.6% Nominal GDP Growth From Federal Reserve Bank o{St. Louis Average% Growth in Nominal GDP (1948 to 2016) 6.5% Average% Growth in Nominal GDP (1980 to 2016) 5.4% Projected Growth in Nominal GDP Congressional Budget Office (2017 to 2027) 3.9% IUse DCF Growth Rate 5.9%1 Value Line Growth Rates STANDARD VALUE LINE COMPANIES-- Combination Utility Group Annual Growth - Past 10 Years Annual Growth - Past 5 Years Annual Growth - Value Line Projected Average Growth Rates Book Book Value Earnings Dividends Value Per Earnings Dividends Value Per Earnings Per Dividends Book Value Past 10 Past 5 Line Company Name Per Share Per Share Share Per Share Per Share Share Share Per Share Per Share Years Years Projected Alliant Energy (LNT) 5.0% 7.5% 4.0% 6.5% 6.5% 4.5% 6.0% 4.5% 4.0% 5.5% 5.8% 4.8% Black Hills Corp.(BKH) 3.5% 2.5% 2.5% 11.0% 2.5% 1.5% 7.5% 5.0% 5.5% 2.8% 5.0% 6.0% CMS Energy Corp. (CMS) 8.5% 0.0% 3.0% 8.5% 11.5% 4.5% 6.5% 6.5% 6.5% 5.8% 8.2% 6.5% Consolidated Edison (ED) 3.5% 1.5% 4.0% 2.5% 2.0% 3.5% 2.5% 3.0% 3.5% 3.0% 2.7% 3.0% Eversource Energy (ES) 12.0% 9.5% 6.0% 6.0% 10.5% 8.5% 6.5% 6.0% 4.0% 9.2% 9.5% 5.5% MGE Energy, Inc. (MGEE) 6.0% 2.5% 6.0% 6.0% 3.0% 5.5% 6.5% 4.5% 5.0% 4.8% 4.8% 5.3% Northwestern (NEW) 0.0% 9.5% 5.0% 7.0% 6.0% 8.0% 4.5% 5.0% 3.5% 7.3% 7.0% 4.3% Vectren Corp. (VVC) 4.0% 2.5% 3.0% 6.0% 2.5% 3.0% 6.5% 5.5% 5.5% 3.2% 3.8% 5.8% WEC Energy Group (WEC) 8.5% 15.0% 8.0% 6.5% 16.0% 9.0% 6.0% 6.5% 4.5% 10.5% 10.5% 5.7% Combination Utility Group Average 6.4% 6.3% 4.6% 6.7% 6.7% 5.3% 5.8% 5.2% 4.7% 5.8% 6.4% 5.2% Source: Value Line Investment Survey, December 15, 2017. Note: Negative growth rates removed from calculations. ~ (j ~ ~ =- ~ s ""C ~ § ~ z .... ~ ? 0:, ...... t,,j 0 ,I. t"' ..., ~ ,!.. 0\ Q0 0 Attachment BEL-10 Cause No. 44988 Page 5 of6 Growth in Nominal Gross Domestic Product, 1948 to 2016 % Change % Change in Nominal in Nominal Year GDP Year GDP 1948 7.90% 1980 9.90% 1949 -3.40% 1981 9.90% 1950 18.30% 1982 3.80% 1951 11.50% 1983 11.40% 1952 7.10% 1984 9.30% 1953 1.50% 1985 7.40% 1954 3.60% 1986 4.90% 1955 9.40% 1987 7.60% 1956 5.40% 1988 7.80% 1957 3.20% 1989 6.50% 1958 5.50% 1990 4.60% 1959 5.90% 1991 4.30% 1960 2.40% 1992 6.70% 1961 7.60% 1993 5.00% 1962 5.50% 1994 6.30% 1963 6.80% 1995 4.30% 1964 6.70% 1996 6.30% 1965 10.70% 1997 6.10% 1966 8.00% 1998 6.10% 1967 5.80% 1999 6.50% 1968 9.90% 2000 5.50% 1969 7.30% 2001 2.20% 1970 4.90% 2002 3.80% 1971 9.50% 2003 6.50% 1972 11.60% 2004 6.30% 1973 11.10% 2005 6.50% 1974 8.40% 2006 5.10% 1975 10.20% 2007 4.40% 1976 9.80% 2008 -0.90% 1977 11.90% 2009 0.20% 1978 14.60% 2010 4.60% 1979 10.00% 2011 3.70% 2012 3.30% 2013 4.30% 2014 4.10% 2015 3.00% 2016 3.50% Avg.% Change 1948 to 2016 6.51% Avg.% Change 1980 to 2016 5.43% Source: Federal Reserve Economic Data, https://fred.stlouisfed.org, Federal Reserve Bank ofSt. Louis, Economic Research Division Attachment BEL-10 Cause No. 44988 Page 6 of6 Forecasted Annual Percentage Growth in Congressional Budget Office, June 2017 % Nominal Calendar GDP Year Growth 2017 4.0% 2018 4.2% 2019 3.6% 2020 3.4% 2021 3.8% 2022 4.0% 2023 4.0% 2024 4.0% 2025 4.0% 2026 4.0% 2027 4.0% Average Growth 3.9% Source: Congressional Budget Office, Budget and Attachment BEL-11 Cause No. 44988 Page 1 of 4 CAPM Cost of Equity Summary-- Gas Utility Group CAPM Formula: K = Rf+ b(Rm - Rf) Risk Free Rate (Rf) 3.50% Beta W) 0.76 Risk Premium (Geometric Approach - Long Term Bonds) 4.50% Klsk Premmm (Arithmetic Approach - Long Term Bonds) 6.00% Risk Premium (Long Term Bonds) 5.25% Required Return (K) (Long Term Bonds) 7.48% Attachment BEL-11 Canse No. 44988 Page2 of4 Yields on U.S. Treasury Securities Recent Months 5Year 10 Year Treasury 20 Year Treasury 30 Year Treasury Month Treasury Bonds Bonds Bonds Bonds December 2016 1.96% 2.49% 2.84% 3.11% January 2017 1.92% 2.43% 2.75% 3.02% February 2017 1.90% 2.42% 2.76% 3.03% March 2017 2.01% 2.48% 2.83% 3.08% April2017 1.82% 2.30% 2.67% 2.94% May 2017 1.84% 2.30% 2.70% 2.96% June 2017 1.77% 2.19% 2.54% 2.80% July 2017 1.87% 2.32% 2.65% 2.88% August 2017 1.78% 2.21% 2.55% 2.80% September 2017 1.80% 2.20% 2.53% 2.78% Octobert 2017 1.98% 2.36% 2.65% 2.88% November 2017 2.05% 2.35% 2.60% 2.80% Average Last 3 months 1.94% 2.30% 2.59% 2.82% Average Last 6 months 1.88% 2.27% 2.59% 2.82% Average Last 12 months 1.89% 2.34% 2.67% 2.92% Source: www.federalreserve.gov. IDuff and Phelps Normalized Risk Free Rate = 3.50%1 Risk Free Rate (Rr) Range and Estimate Yield Calculations Range 2.67% to 3.5% Risk Free Rate (Ri:) 3.50% Attachment BEL-11 Cause No. 44988 Page 3 of 4 Beta for Gas Utility Group Value Line Forward Betas (December 1, Company Name 2017) Atmos Energy Corp. (ATO) 0.70 New Jersey Resources (NJR) 0.80 Northwest Natural Gas (NWN) 0.70 South Jersey Industries (SJI) 0.85 Southwest Gas (SWX) 0.80 Spire, Inc. (SR) 0.70 Gas Utility Group Average 0.76 Attachment BEL-11 Cause No. 44988 Page 4 of4 Market Risk Premiums Total Returns, 1926-2014 Stocks Long-term Bonds Geometric Mean 10.00% 5.50% Arithmetic Mean 12.00% 6.00% Market Risk Premiums (Rm - Rr) Long-term Bonds Geometric Mean 4.50% Arithmetic Mean 6.00% Average Market Risk Premium 5.25% Source: Duff & Phelps, SBBI Classic Ibbotson Yearbook, 2017, p. 2-6. Attchment BEL-12 Cause No. 44988 Page 1 of 4 CAPM Cost of Equity Summary -- Combination Utility Group CAPM Formula: K = Rf+ b(Rm - Rf) Risk Free Rate (Rf) 3.50% Beta (13) 0.69 Risk Premium (Geometric Approach - Long Term Bonds) 4.50% Risk l'remmm (Arithmetic Approach - Long Term Bonds) 6.00% Risk Premium (Long Term Bonds) 5.25% Required Return (K) (Long Term Bonds) 7.12% Attchment BEL-12 Cause No. 44988 Page 2 of 4 Yields on U.S. Treasury Securities Recent Months Treasury I u Year Treasury 20 Year Treasury 30 Year Treasury Month Bonds Bonds Bonds Bonds December 2016 1.96% 2.49% 2.84% 3.11% January 2017 1.92% 2.43% 2.75% 3.02% February 2017 1.90% 2.42% 2.76% 3.03% March 2017 2.01% 2.48% 2.83% 3.08% April 2017 1.82% 2.30% 2.67% 2.94% May 2017 1.84% 2.30% 2.70% 2.96% June 2017 1.77% 2.19% 2.54% 2.80% July 2017 1.87% 2.32% 2.65% 2.88% August 2017 1.78% 2.21% 2.55% 2.80% September 2017 1.80% 2.20% 2.53% 2.78% Octobert 2017 1.98% 2.36% 2.65% 2.88% November 2017 2.05% 2.35% 2.60% 2.80% Average Last 3 months 1.94% 2.30% 2.59% 2.82% Average Last 6 months 1.88% 2.27% 2.59% 2.82% Average Last 12 months 1.89% 2.34% 2.67% 2.92% Source: wwwfederalreserve.gov. Duff and Phelps Normalized Risk Free Rate= 3.50% Risk Free Rate (Rr) Range and Estimate Yield Calculations Range 2.67% to 3.50% Risk Free Rate (Rf) 3.50% Attchment BEL-12 Cause No. 44988 Page 3 of 4 Beta for Combination Utility Group Value Line Forward Betas (December 1, Company Name 2017) Alliant Energy (LNT) 0.70 Black Hills Corp.(BKH) 0.90 CMS Energy Corp. (CMS) 0.65 Consolidated Edison (ED) 0.50 Eversource Energy (ES) 0.65 MGE Energy, Inc. (MGEE) 0.75 Northwestern (NEW) 0.70 Vectren Corp. (VVC) 0.75 WEC Energy Group (WEC) 0.60 Group Average 0.69 Attchment BEL-12 Cause No. 44988 Page 4 of 4 Market Risk Premiums Total Returns, 1926-2016 Stocks Long-term Bonds Geometric Mean 10.00% 5.50% Arithmetic Mean 12.00% 6.00% Market Risk Premiums (Rm - Rr) Long-term Bonds Geometric Mean 4.50% Arithmetic Mean 6.00% Average Market Risk Premium 5.25% Source: Duff & Phelps, SBBI Classic Ibbotson Yearbook, 2017, p. 2-6. Attachment BEL-13 Cause No. 44988 Page 1 ofl JUNE 2017 AN UPDATE ro TIIE BUDGET .AND ECONOMIC OTITLOOK: 2017 'rO 2027 21 Table 7. CB0's Economic Projections for Calendar Years 2017 to 2027 Actual, Annual Average 2016 2017 2018 2019-2020 2021-2027 Percentage Change From Fourth Quarter to Fourth Quarter Gross Domestic Product Real' 2.0 2.2 2.0 1.5 1.9 Nominal 3.5 4.0 4.0 3.5 4.0 Inflation PCE price lndel< 1.4 1.8 2.0 2.0 2.0 Core PCE price lndel Fourth-Quarter Level Unemployment Rate (Percent) 4.7 4.3 4.2 4.8 t 4.9 9 Percentage Change From Year to Year Gross Domestic Product Real" 1.6 2.1 2.2 1.6 1.9 Nominal 3.0 4.0 4.2 3.5 3.9 Inflation PCE price Index 1.1 1.8 1.9 2.0 2.0 Core PCE price lndel 1.7 1.6 1.9 2.0 2.0 Consumer price lndexc 1.3 2.3 2.2 2.4 2.4 Core consumer price lndei 2.2 2.1 2.3 2.4 2.4 GDP price Index 1.3 1.8 2.0 1.9 2.0 Employment Cost Index• 2.4 2.8 3.2 3.3 3.1 Annual Average Unemployment Rate (Percent) 4.9 4.4 4.2 4.6 4.9 Payroll Employment (Monthly change, In thousandst 194 170 107 23 61 Interest Rates (Percent) Three-month Treasury bills 0.3 0.9 1.5 2.4 2.8 Ten-year Treasury notes 1.8 2.4 2.8 3.4 3.7 Tax Bases (Percentage of GDP) Wages and salaries 44.1 44.4 44.5 44.6 44.5 Domestlc economic profits 9,0 8.6 8.4 8.0 7.5 Sources: Congressional Budget Office; Bureau of Economic Analysis; Bureau of Labor Statistics; Federal Reserve. GDP= gross domestic product; PCE = personal consumption expenditures. a. Nominal GDP adjusted to remove the effects of Inflation. b. El Geometric Arithmetic Standard Series Mean(%) Mean(%) Deviation(%) _Distribution(%) __;___ _,_.,_.., ______Large-Cap Stocks 10.0 12.0 19.9 Small-Cap Stocks* 12.l 16.6 31.9 Long-term Corp Bonds 6.0 6.3 8.4 Long-term Gov't Bonds 5.5 6.0 9.9 Inter-term Gov't Bonds 5.1 5.3 5.6 U.S. Treasury Bills 3.4 3.4 3.1 Inflation 2.9 3.0 4.1 *rhe 1933 small-oap stocks total return was 142.9%, and is not shown here. -90 0 90 2-6 Chapter 2: The Long-Run Perspective 2017 SBBI Yearbook Appendix C-7 (49) AE_IJ_endix C-7 Inflation: Percent per annum total returns for all historical periods From 1926 to 201 6 Start Date EndDate 1926 1927 1928 1929 1930 1931 1932 1933 1934 1935 1936 1937 1938 1939 1940 1941 1942 1943 1944 1945 1926 «··••""'"""Y'~' 1927 1928 1929 1930 1931 1932 -8.6 1933 -6,4 1934 -4.8 · 1935 1936 1937 1938 1939 1940 7941 1942 1943 1944 1945· 1946 1947 1948 1949 1950 1951 1952 1953 1954 1955 1956 1957 1958 1959 1960 1961 1962 1963 ·> 1964 ;:i: 1965 ("') ~ =-> i::r 1966 ~ e 1967 '"Cl~ ~ 1968 =-- z a 1969 ~? t:,:; 1970 ,... .i;:.. t,,j o~t;'" ..., 00 ..... 00 00 t/1 --~=.... "--••...,; ...... -~~-=-• MPQ,...:.U.,;;.s;:;;;;:: - == ;:;..pm:..;..;,.,:.....;. ,...... ,,.,¥1'0,w:m,.;::;w;,,i!fflWNIWJGiJ(\:.U,o.:,;,.,m n...t;tl$ili,l,,:,,lll)llmw,-.o;ra, AiiWMWiiilil&WWil,iJ4,.l¾iW,iU:,.W~-~------= A0'_endix c-7" Inflation: Percent per annum total returns for all historical periods From 1926 to 2016 Start Date End Date 1926 ll927 1928 1929 1980 1981 1982 1983 1984 1935 1936 1937 1988 1939 1940 1941 1942 1943 1944 1945 1971 1.8 1.9 2.0 2.1 2.1 2.3 2.6 a.a a.a 8.1 3.1 3.1 3.1 a.a 3.4 3.5 8.3 3.1 S.1 3.1 1972 1.9 1,9 2.0 2.1 2.1 2.3 2.6 3.0 8.1 S.1 3.1 3.1 3.1 a.a 3.4 3.5 3.3 3.1 3.1 3.2 1973 2.0 2.1 2.2 2.2 2.3 2.5 2.8 3.1 3.2 3.2 3.2 3.3 3.3 3.5 3.6 3,7 3.6 3.3 a.a 3.3 1974 2.2 2.3 2.4 2.4 2.5 2.7 3.0 3.3 3.4 3.4 3.4 3.5 3.5 3.7 3.8 3.9 8.7 3,6 3.6 3.6 1975 2.3 2.4 2.5 2.5 2.6 2.8 3.1 3.4 3.5 3.5 3.5 3.6 3.6 3.8 3.9 4.0 3.8 3.7 8.7 3.7 1976 1977 1978 1979 1980 1981 1982 1983 1984 1985 1986 1987. 1988 1989 1990 1991 1992 1993 1994 1995 1996 1997 1998 1999 2000 2001 2002 2003 2004 2005 2006 2007 2008 ~ 2009 ,.,(":) =-~ 2010 1;1 s 2011 M M ~ U U U M li li V V U U M U ~ M U U M '"= (I) (I) 2012 M M ~ ~ U U U U V V V U U U M ~ U U U U ,.,za 2013 M M -~ ~ U U M U V V V V V U U U U U U U ~ !=) = 2014 U M M ~ ~ U M U U U V V V U U U U V V U N ,!:a,. t,,j 2015 ~ M M ~ ~ U M U U U U U V V U U U V V V 0 ,IO""t'"' 1 ..... 00 ,... 2016 00 00 t'.JI 2017 SBBI Yearbook Appendix c-7 (50) ~c:.n.a:m.:;;u.m.,:..;...w;;.;;;;;,;;a,,;;.;m,_,;:;.;;;.;;.;.,,.unaa•;...m...... µ,,.,,;,,...... ;~iM/,\ ....-;;;.;:;..,;.;.,;..:;:;w,,:4,....&yu;.,.:u;:....;.;; 4 ,..::rnz:qa,c,, - ~~~1rw;:,..;.w,w ...: .;.;.i ,.,.,_,_..,..... _~~ 2017 SBBI Yearbook Appendix C-7 (51) Appendix C-7 Inflation: Percent per annum total returns for all historical periods From 1926 to 2016 start Date End Date 1946 1947 1948 1949 1960 1951 1952 1963 1954 1955 1956 1957 1958 1959 1960 1961 1962 1963 1964 1965 1926 1927 1928 1929 7930 1937 1932 7933 1934 1935 1936 1937 1938 1939 1940 1941 1942 1943 1944 1945· 1946 1947 ..... 1948 1949 1950 1951 1952 1953 1954 1955 1956 1957 1958 1959 1960 1961 0.7 1962 0.9 1963 1.2 1964 1.2 ~ 1965 ("".l~ ~ =- 1966 ; a 1967 ""cl ~ ~ 1968 ~za 1969 ~? e,:; 1970 (;. .i,.. i:"'l 0 -~ t;"' .... QO ~ QO QO UI =~-'i~"'1l~.:.~...... -~-,.,,,..~1~~--=__,,=:tnll':mlllli!A.-.:mw+=,,ili✓.A"lYI ---~~~~••1'- "<71"<\_.... __, 'I Appendix c-7 Inflation: Percent per annum total returns for all hist\)rical periods From 1926 to 201 6 Start Date End Date 1946 1947 1948 1949 1950 1951 1952 1953 1954 1955 1956 1957 1958 1959 1960 1951 1962 1963 1964 1965 1971 3.2 2.6 2.4 2.4 2.5 2.4 2.2 2.3 2.4 2.6 . 2.7 2.7 2.7 2.7 2.8 3.0 3.2 3.4 3.6 4.0 1972 3.2 2.7 2.4 2.4 2.6 2.4 2.3 2.3 2.4 2.6 2.7 2.7 2.7 2.8 2.9 3.0 3.2 3.4 8.6 3.9 1973 3.4 2.9 2.6 2.6 2.8 2.7 2.6 2.6 2.8 2.9 3.1 3.1 3.1 3.2 3.3 3.4 3.7 3.9 4.1 4.4 1974 3.7 3.2 3.0 3.0 3.2 3.1 3.0 3.1 3.2 3.4 3.5 3.6 3.6 3.7 3.9 4.0 4.3 4.6 4.8 5.2 1975 1976 1977 1978 1979 1980 1981 1982 1983 1984 1985 1986 1987 1988 1989. 1990 1991 1992 1993 1994 1995 7996 1997 1998 1999 2000 2001 2002 2003 2004 2005 2006 2007 2008 ~ 2009 ..... 2010 ('i ~ 2011 i:,, =-- 1;] = 2012 "=' ~ ~ 2013 i:,, :z a 2014 ~ ? ~ 2015 +-- +-- tzj 0 +-- t"" 2016 ...., \0 I 00,... 00 00 Ul -•} 2017 SBBI Yearbook Appendix C-7 (52) ..==-__:::::::::.::.: ::.-::-- _., ____ --·--··-·- - 2017 SBBI Yearbook Appendix C-7 (53) ) J\i:}ll_endbc C-7 Inflation: Percent per annum total returns for all historical periods From 1926 to 2016 Start Date End Date 1966 1967 1968 1969 1970 1971 197.2 1973 1974 1975 1976 1977 1978 1979 1980 1981 1982 1983 1984 1985 1926 1927 1928 1929 1930 1931 1932 1933 1934 1935 1936 1937 1938 1939 1940 1941 1942 194:l 1944 1945 1946 1947 1948 1949 1950 1951 1952 1953 1954 1955 1956 1957 7958 1959 1960 1961 1962 1963 ~ 1964 n~ 1965 ;:., =- ~ 8 1966 '"d I!) I!) 1967 ::.a :z a 7968 ~ :=, 0:, 7969 t/l ""' tzj 1970 o~t;"' ..., 00 .... 00 00 t/l Appendix C-7 Inflation: Percent per annum total returns for all historical periods From 1926 to 201 6 start Date End Date 1966 1967 1968 1969 1970 1971 ,1972 1973 1974 1975 1976 1977 1978 1979 7980 1981 1982 1983 1984 1985 1971 4.3 4.5 4.9 5.0 4.4 3.4 1972 4.2 4.3 4.6 4.6 4.1 3.4 3.4 1973 4.8 5.0 5.3 5.4 5.2 5.2 6.1 8.8 1974 5.6 5.9 6.3 6.5 6.6 6.9 8.1 10.5 12.2 7975 5.7 6.0 6.4 6.6 6.7 6.9 7.8 9.3 . 9.6 7.0 1976 1977 1978 7979 1980 1981 1982 1983 1984 1986 1986 19B7 1988 1989. 1990 1991 1992 1993 1994 1995 1996 1997 1998 1999 2000 2001 2002 2003 2004 2005 2006 2007 2008 2009 ~ 2010 (J l=; 2011 U « « « « U « « U ~ ~ M M V U U M ~ ~ ll ~ =- 2012 U U U U U U U U U ~ M U U V U ~ U U ~ U I;] s "ti ti) g . 2013 U U U U U U U U ~ U U U V U U ~ U U U ll ~z~ 2014 U ~ U U ~ ~ ~ ~ ~ M M U V U U M U ll TI TI ~? 2015 ~ ~ ~ ~ ~ ~ ~ ~ ~ V V ~ U V V = U U U U ll 0\ ""' t,ej 2016 o~t;"" .... 00 ""' 00 00 UI 2017 SBB! Yearbook Appendix C-7 (54) ·-·----·~-- ·-- ---··---- - ~ .. ··- ..... ~-~-~~ i ,, 2017 SBBI Yearbook Appendix C-7 (5~) Appendix c-7 -- -- Inflation: Percent per annum total returns for all historical periods From 1926 to 201 5 Start Date End Date 1986 1987 1988 1989 1990 1991 1992 1993 1994 1995 1996 1997 1998 1999 2000 2001 2002 2003 2004 2005 1971 1972 1973 1974 1975 1976 19n 1978 1979 1980 1981 1982 1988 1984 1985 7986 1987 1988 1989 7990· 1991 1992 1993 1994 1995 1996 1997 1998 1999 2000 2001 2002 2003 2004 2005 2006 2007 > 2008 n;:;~ 2009 I') 2010 ~ =-3 2011 '"C ~ ~ 2012 2.8 2.9 2.8 2.7 2.6 2.5 2.5 2.4 2.4 2.4 2.4 2.3 2.4 2.4 2.4 2.3 2.4 2.4 2.5 2.4 I') ,:,,: a 2013 2.7 2.8 2.7 2.7 2.6 2.4 2.4 2.4 - 2.4 2.4 2.3 2.3 2.3 2.4 2.4 2.3 2.3 2.3 2.4 2.3 ~ ::l ~ 2014 2.7 2.7 2.7 2.6 2.5 2.4 2.3 2.3 2.3 2.3 2.3 2.2 2.2 2.3 2.2 2.2 2.2 2.2 2.2 2.1 ---l +"- t,,j 2015 0 ~ t;"' .... 00 .... 2016 00 00 U1 Appendix c-7 Inflation: Percent per annum total returns for all historical periods From 1926 to 2016 start Date End Date 2006 2007 2008 2009 2010 2011 2012 2013 2014 2015 2016 1971 1972 1973 1974 1975 1976 1977 1978 1979 1980 1981 1982 1983. 1984 1986 1986 1987 1988 1989 1990 1991. 1992 1993 1994 1995 1996 1997 1998 1999 2000 2001 2002 2003 2004 2005 2006 2007 2008 2009 t 2010 ('") ~ 2011 2.3 2.3 1,8 2.4 2.2 3.0 I» =- 2012 2.2 2.2 1.8 2.2 2.1 2.3 1.7 SJ 51 2013 2.1 2.1 1.7 2.1 1.9 2.1 1.6 1.5 '"C (I> (I> 2014 2.0 1,9 1.6 1.9 1.7 1.7 1.3 1.1 0.8 I» z s. 2015 1.9 1.8 1.5 1.7 1.5 1.5 1.2 1.0 0.7 0.7 ~ ~ = QC ""' ~ 2016 f@11Ff'~l~l!l11~1!Sk~il~~mw:gslttfti1~~\f&IWBJB~~-r,a1B11V&~i1?JXlfi~g,-g1,m1ne o~t;"' ..., QC .... QC QC Ul 2017 SBBI Yearbook Appendix c-7 (56) ~~-~~~,.~-~i""'l..::,;,,n~,=-m,.;,,,.~::-~~~~~~~,$!1:l!;i:IJII;~~~....,.~ Attachment BEL-16 Cause No. 44988 Release Date: November 13, 2017 FOURTH QUARTER 2017 Forecasters See Stronger Outlook for Growth over the Next Two Quarters The outlook for growth in the U.S. economy over the next two quarters looks slightly stronger overall than that of three months ago, according to 41 forecasters surveyed by the Federal Reserve Bank of Philadelphia. The panel expects real GDP to grow at an annual rate of 2.6 percent this quarter and 2.4 percent next quarter, marking upward revisions from the previous survey. On an annual-average over annual-average basis, the forecasters see real GDP growing 2.2 percent in 2017, compared with 2.1 percent from the previous survey. The forecasters predict real GDP will grow 2.5 percent in 2018, 2.1 percent in 2019, and 1.9 percent in 2020. The projections for annual unemployment rates were either unchanged or revised slightly downward in comparison with the third quarter 2017 survey. The forecasters predict the unemployment rate will be an annual average of 4.4 percent in 2017, before falling to 4.1 percent in 2018, and then decreasing to 4.0 percent in 2019 and 4.1 percent in 2020. On the employment front, the forecasters have revised downward their estimates for job gains in 2017 and in 2018. The forecasters' projections for the annual-average level of nonfarm payroll employment suggest job gains at a monthly rate of 178,000 in 2017, down from the previous estimate of180,400, and 163,400 in 2018, down from the previous estimate of 165,800. (These annual-average estimates are computed as the year-to-year change in the annual-average level ofnonfarm payroll employment, converted to a monthly rate.) Median Forecasts for Selected Variables in the Current and Previous Surveys Real GDP(%) Unemployment Rate (%) Payrolls (000s/month) Previous New Previous New Previous New Quarterly data: 2017:Q4 2.3 2.6 4.2 4.2 161.0 183.0 2018:Ql 2.2 2.4 4.2 4.1 155.6 164.9 2018:Q2 2.4 2.4 4.1 4.1 162.5 167.0 2018:Q3 2.4 2.1 4.1 4.1 165.4 157.1 2018:Q4 N.A. 2.3 N.A. 4.0 N.A. 155.6 Annual data (projections are based on annual-average levels): 2017 2.1 2.2 4.4 4.4 180.4 178.0 2018 2.4 2.5 4.2 4.1 165.8 163.4 2019 2.2 2.1 4.3 4.0 N.A. N.A. 2020 2.0 1.9 4.3 4.1 N.A. N.A. E~✓ T fEDERAL RESERVE BANK UF PHILADELPHIA Attachment BEL-16 Cause No. 44988 Page 2 of16 The charts below provide some insight into the degree of uncertainty the forecasters have about their projections for the rate of growth in the annual-average level ofreal GDP. Each chart presents the forecasters' previous and current estimates of the probability that growth will fall into each of 11 ranges. For 2017, the panelists are more certain now than they were in the previous survey that real GDP growth would fall between 2.0 percent and 2.9 percent. For 2018 and 2019, the probabilities are also slightly higher now than they were in the survey of three months ago for real GDP growth between 2.0 percent and 2.9 percent. The probabilities for growth in 2020 are about the same now as they were in the previous survey. Mean Probabilities for Real GDP Growth in 2017 Mean Probabilities for Real GDP Growth in 2018 ill Previous Current Ill Previous !ill Current so~------so~------~ I 70 70 60 60 50 50 40 40 30 30 20 ::1 ~- ____ LL I l!lll'Ji:! . : ol - ---·· •" ~ .. •3.0 -3.0 -2.0 -1.0 0.0 1.0 2.0 3.0 4.0 5.0 ,6.0 ·-3.0 -3.0 -2.0 -1.0 o.o 1.0 2.0 3.0 4.0 5.0 :c6.0 ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ -2.1 -1.1 -0.1 0.9 1.9 2.9 3.9 4.9 5.9 -2.1 -1.1 -0.1 0.9 1.9 2.9 3.9 4.9 5.9 Real Growth Ranges (Year over Year) Real Growth Ranges (Year over Year) Mean Probabilities for Real GDP Growth in 2019 Mean Probabilities for Real GDP Growth in 2020 II Previous Cum,nt Ill Previous Current 80 70 60 so :at .., 401 e"' 0.. l " 30j .· ~ a 20! fe;J, 10; .,, 1, I; o: ----~ !Bil Ir! ' ~· ' · -3.0 -3.0 -2.0 -1.0 0.0 1.0 2.0 3.0 4.0 5.0 >6.0 -3.0 -3.0 _ -2.0 ••-1.0 0.0 I1.0 I2.0 •---3.0 4.0 5.0 >6.0 ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ -2.1 -1.1 -0.1 0.9 1.9 2.9 3.9 4.9 5.9 -2.1 -1.1 -0.1 0.9 1.9 2.9 3.9 4.9 5.9 Rea! Growth Ranges (Year over Year) Real Growth Ranges (Year over Year) 2 Attachment BEL-16 Cause No. 44988 Page3 of16 The forecasters' density projections for unemployment, shown below, shed light on uncertainty about the labor market over the next four years. Each chart presents the forecasters' current estimates of the probability that unemployment will fall into each of 10 ranges. The forecasters are more certain now than they were three months ago that unemployment over 2017 will average between 4.0 percent and 4.9 percent. The forecasters are less certain now than they were three months ago that unemployment will average between 4.0 percent and 4.9 percent over 2018, 2019, and 2020. In addition, forecasters notably raised their probability estimates for an unemployment rate below 4.0 percent over 2018, 2019, and 2020. Mean Probabilities for Unemployment Rate in 2017 Mean Probabilities for Unemployment Rate in 2018 ■ Previous ■ Current ■ Previous ■ Current 100 100 90 90 BO 80 e- 70 l 70 60 ~ 60 I :i ..... 50 ..... so l l .. 40 .. 40 j 30 j 30 20 20 10 .. 10 0 L 0 <4.0 '-0 5.0 5.5 6.0 6.5 7.0 7.5 8.0 ,9.0 <4.0 4.0 s.o 5.5 6.0 6.5 7.0 7.S 8.0 "9.0 to to to to to to to to to •--to to to to to to to '-9 5.4 5.9 6.4 6.9 7.4 7.9 8.9 4.9 5.4 5.9 6.4 6.9 7.4 7.9 8.9 (Annual Average) (Annual Average) Mean Probabilities for Unemployment Rate In 2019 Mean Probabilities for Unemployment Rate In 2020 ■ Previous ■ Current ■ Previous ■ Current 100 100 90 90 80 80 e 70 "'t, 70 t 60 t 60 :;;.. :;;., ... so ...e so l 40 D. 40 .." ..C ~ 30 I 30 20 20 10 11 .. _ 10 0 0 <4.0 4.0 s.o S.5 6.0 6.5 7.0 7.5 8.0 ~9.0 <4.0 4.0 5.0 5.5 6.0 6.5 7.0 7.5 8.0 >9.0 to to to to to to to to to to to to to to to to 4.9 5.4 5.9 6.4 6.9 7.4 7.9 8.9 4.9 ••---5.4 5.9 6.4 6.9 7.4 7.9 8.9 (Annual Average) (Annual Average) 3 Attachment BEL-16 Cause No. 44988 Page 4 of16 Short-Term CPI and PCE Inflation Projections Are Holding Steady Measured on a fourth-quarter over fourth-quarter basis, the CPI and PCE inflation forecasts are about the same now as they were three months ago, particularly for core inflation measures. Core CPI inflation is expected to average 1. 7 percent in 2017, 2.1 percent in 2018, and 2.2 percent in 2019. The projections for core PCE inflation are 1.4 percent for the current year, 1.8 percent for 2018, and 2.0 percent for 2019. Over the next 10 years, 2017 to 2026, the forecasters expect headline CPI inflation to average 2.20 percent at an annual rate, down slightly from their previous estimate of 2.25 percent. The corresponding estimate for 10-year annual-average PCE inflation is 2.00 percent, unchanged from the previous estimate three months ago. Median Short-Run and Long-Run Projections for 1-riflation (Annualized Percentage Points) Headline CPI Core CPI Headline PCE CorePCE Previous Current Previous Current Previous Current Previous Current Quarterly 2017:Q4 2.3 2.3 2.1 1.9 2.0 1.9 1.8 1.6 2018:Ql 2.2 2.1 2.2 2.0 1.9 1.7 1.8 1.7 2018:Q2 2.1 2.0 2.1 2.1 1.9 1.8 1.8 1.8 2018:Q3 2.2 2.2 2.2 2.1 1.9 1.9 1.9 1.8 2018:Q4 N.A. 2.1 N.A. 2.2 N.A. 1.9 N.A. 1.9 Q4/Q4 Annual Averages 2017 1.7 1.8 1.7 1.7 1.5 1.5 1.5 1.4 2018 2.2 2.1 2.1 2.1 1.9 1.8 1.8 1.8 2019 2.3 2.3 2.2 2.2 2.0 2.0 2.0 2.0 Long-Term Annual Averages 2017-2021 2.20 2.20 N.A. N.A. 1.94 1.90 N.A. N.A. 2017-2026 2.25 2.20 N.A. N.A. 2.00 2.00 N.A. N.A. 4 Attachment BEL-16 Cause No. 44988 Page 5 of16 The charts below show the median projections (red line) and the associated interquartile ranges (gray areas around the red line) for the projections for 10-year annual-average CPI and PCE inflation. The charts highlight a marginally lower level of the long-term projection for CPI inflation and an unchanged long-term projection for PCE inflation. Projections for the 10-Year Annual-Average Rate of CPI Inflation (Median and Interquartile Range) Percent s.o~------~ 4.5 4.0 . 3.5 3.0 2.5 2.0 1.S 1.0 · ~~~~~,,. ~, ~~~----~~~,~-r~,--T"'"TT-·-. ~~·~.~--,~- 1H1 92 93 94 95 96 97 98 99 00 01 02 03 04 05 06 07 01 09 10 11 12 13 14 15 16 17 18 Q1 Q1 Q1 Q1 Q1 Q1 Q1 Ql Q1 Q1 Q1 Q1 Q1 Q1 Q1 Q1 Q1 Q1 Q1 Q1 Q1 Q1 Q1 Ql Q1 Q1 Q1 Q1 Survey Date Projections for the 10-Year Annual-Average Rate of PCE Inflation (Median and Interquartile Range) Percent 5.0 4.5 4.0 3.5 3.0 2.5 2.0 1.S 1.0 +------,---~~-.------~-,-~-~-,..,..-----~-..-~----,~--~ 2007 DI 09 10 11 12 13 14 15 16 17 18 Q1 Q1 Q1 Q1 Q1 Q1 Q1 Q1 Q1 Q1 Q1 Q1 Survey Date 5 Attachment BEL-16 Cause No. 44988 Page 6 of16 The charts below show the probabilities that the forecasters are assigning to the possibility that fourth-quarter over fourth quarter core PCE inflation in 2017 and 2018 will fall into each of 10 ranges. For 2017, the forecasters assign a higher chance than they previously predicted that core PCE inflation will be between 1.0 percent to 1.4 percent. For 2018, the forecasters assign a higher chance that core PCE inflation will be between 1.5 percent and 1.9 percent than they previously predicted. Mean Probabilities for Core PCE Inflation in 2017 Mean Probabilities for Core PCE Inflation in 2018 ■ Previous ■ Current ■ Previous ■ Current so~------so 45 45 40 40 ..... 35 c 35 30 ~ 30 :a~ :a 11 25 ... 25 e e"' CL 20 CL 20 C C "' "' 15 ~ 15 :!:"' 10 10 s 5 o ___ II __ .I 0 <0.0 0.0 O.S 1.0 1.S 2.0 2.S 3.0 3.S ~.O ,o.o 0.0 o.s 1.0 1.5 2.0 2.5 3.0 3.5 .:4.0 to to to to to to to to to to to to to ~---- to to to 0.4 0.9 1.4 1.9 2.4 2.9 3.4 3.9 0.4 0.9 1.4 1.9 2.4 2.9 3.4 3.9 Inflation Ranges (Q4 over Q4) Inflation Ranges (Q4 over Q4) Reduced Risk ofDecline in Real GDP in 2017 and 2018 The forecasters see only a small chance of a contraction in real GDP in any of the next five quarters. For the current quarter, they predict a 6.3 percent chance of negative growth, down from 10.5 percent in the survey of three months ago. Notably, the forecasters see a lower probability of a negative quarter in 2017 and 2018 than they estimated three months ago. Risk ofa Negative Quarter (%) Survey Means Quarterly data: Previous New 2017: Q4 10.5 6.3 2018: Ql 14.2 10.4 2018: Q2 15.9 12.6 2018: Q3 18.1 14.7 2018: Q4 N.A. 17.0 6 Attachment BEL-16 Cause No. 44988 Page 7 of16 Technical Notes Moody's Aaa and Baa Historical Rates The historical values of Moody's Aaa and Baa rates are proprietary and, therefore, not available in the data files on the Bank's website or on the tables that accompany the survey's complete write-up in the PDF. New File Format On May 12, 2017, the survey's data files on the Bank's website were changed to a .xlsx extension instead of .xls. The Federal Reserve Bank of Philadelphia thanks the following forecasters for their participation in recent surveys: Lewis Alexander, Nomura Securities; Scott Anderson, Bank of the West (BNP Paribas Group); Robert J. Barbera, Johns Hopkins University Center for Financial Economics; Peter Bernstein, RCF Economic and Financial Consulting, Inc.; Christine Chmura, Ph.D., and Xiaobing Shuai, Ph.D., Chmura Economics & Analytics; Gary Ciminero, CFA, GLC Financial Economics; Nathaniel Curtis, Navigant Consulting; Gregory Daco, Oxford Economics USA, Inc.; Rajeev Dhawan, Georgia State University; Gabriel Ehrlich, Daniil Manaenkov, Ben Meiselman, Owen Nie, and Aditi Thapar, RSQE, University of Michigan; Michael R. Englund, Action Economics, LLC; J.D. Foster, U.S. Chamber of Commerce; Michael Gapen, Barclays Capital; Sacha Gelfer, Bentley University; James Glassman, JPMorgan Chase & Co.; Jan Hatzius, Goldman Sachs; Keith Hembre, Nuveen Asset Management; Peter Hooper, Deutsche Bank Securities, Inc.; Sam Kahan, Kahan Consulting Ltd. (ACT Research LLC); N. Karp, BBVA Research USA; Walter Kemmsies, Jones Lang LaSalle; Jack Kleinhenz, Kleinhenz & Associates, Inc.; Thomas Lam, Independent Economist; L. Douglas Lee, Economics from Washington; John Lonski, Moody's Capital Markets Group; Macroeconomic Advisers, LLC; R. Anthony Metz, Pareto Optimal Economics; Michael Moran, Daiwa Capital Markets America; Joel L. Naroff, NaroffEconomic Advisors; Michael Neal, National Association of Home Builders; Mark Nielson, Ph.D., MacroEcon Global Advisors; Luca Noto, Anima Sgr; Brendon Ogmundson, BC Real Estate Association; Arun Raha and Maira Trimble, Eaton Corporation; Philip Rothman, East Carolina University; Chris Rupkey, MUFG Union Bank; John Silvia, Wells Fargo; Sean M. Snaith, Ph.D., University of Central Florida; Constantine G. Soras, Ph.D., CGS Economic Consulting; Stephen Stanley, Amherst Pierpont Securities; Charles Steindel, Ramapo College of New Jersey; Susan M. Sterne, Economic Analysis Associates, Inc.; James Sweeney, Credit Suisse; Thomas Kevin Swift, American Chemistry Council; Richard Yamarone, Bloomberg, LP; Mark Zandi, Moody's Analytics; Ellen Zentner, Morgan Stanley. This is a partial list of participants. We also thank those who wish to remain anonymous. 7 Attachment BEL-16 Cause No. 44988 Page 8 of16 SUMMARY TABLE SURVEY OF PROFESSIONAL FORECASTERS MAJOR MACROECONOMIC INDICATORS 2017 2018 2018 2018 2018 2017 2018 2019 2020 Q4 Ql Q2 Q3 Q4 (YEAR-OVER-YEAR) PERCENT GROWTH AT ANNUAL RATES 1. REAL GDP 2.6 2.4 2.4 2.1 2.3 2.2 2.5 2.1 1. 9 (BILLIONS, CHAIN WEIGHTED) 2. GDP PRICE INDEX 1.8 1. 9 1. 9 2.1 2.1 1.8 1. 9 N.A. N.A. (PERCENT CHANGE) 3. NOMINAL GDP 4.5 4.5 4.3 4.3 4.3 4.0 4.5 N.A. N.A. ($ BILLIONS) 4. NONFARM PAYROLL EMPLOYMENT (PERCENT CHANGE) 1.5 1.4 1.4 1.3 1.3 1.5 1.3 N.A. N.A. (AVG MONTHLY CHANGE) 183.0 164.9 167.0 157.1 155.6 178.0 163.4 N.P).. N.A. VARIABLES IN LEVELS 5. UNEMPLOYMENT RATE 4.2 4.1 4.1 4.1 4.0 4.4 4.1 4. 0 4.1 (PERCENT) 6. 3-MONTH TREASURY BILL 1.2 1. 3 1.5 1. 7 1.8 0.9 1. 6 2.2 2.5 (PERCENT) 7. 10-YEAR TREASURY BOND 2.4 2.6 2.7 2.8 3.0 2.3 2.8 3.3 3.4 (PERCENT) 2017 2018 2018 2018 2018 2017 2018 2019 Q4 Ql Q2 Q3 Q4 (Q4-OVER-Q4) INFLATION INDICATORS 8. CPI 2.3 2.1 2.0 2.2 2.1 1.8 2.1 2.3 (ANNUAL RATE) 9. CORE CPI 1. 9 2.0 2.1 2.1 2.2 1. 7 2.1 2.2 (ANNUAL RATE) 10. PCE 1. 9 1. 7 1. 8 1. 9 1. 9 1.5 1.8 2.0 (ANNUAL RATE) 11. CORE PCE 1. 6 1. 7 1.8 1. 8 1. 9 1. 4 1. 8 2.0 (ANNUAL RATE) THE FIGURES ON EACH LINE ARE MEDIANS OF 41 INDIVIDUAL FORECASTERS. SOURCE: RESEARCH DEPARTMENT, FEDERAL RESERVE BANK OF PHILADELPHIA. SURVEY OF PROFESSIONAL FORECASTERS, FOURTH QUARTER 2017. 8 Attachment BEL-16 Cause No. 44988 Page 9 of16 SURVEY OF PROFESSIONAL FORECASTERS Fourth Quarter 2017 Tables Note: Data in these tables listed as "actual" are the data that were available to the forecasters when they were sent the survey questionnaire on October 30, 2017; the tables do not reflect subsequent revisions to the data. All forecasts were received on or before November 7, 2017. 9 Attachment BEL-16 Cause No. 44988 Page 10 of16 TABLE ONE MAJOR MACROECONOMIC INDICATORS MEDIANS OF FORECASTER PREDICTIONS ACTUAL FORECAST ACTUAL FORECAST NUMBER OF 2017 2017 2018 2018 2018 2018 2016 2017 2018 2019 2020 FORECASTERS Q3 Q4 Ql Q2 Q3 Q4 ANNUAL ANNUAL ANNUAL ANNUAL ANNUAL 1. GROSS DOMESTIC PRODUCT (GDP) 39 19496 19711 19927 20139 20349 20564 18624 19379 20244 N.A. N.A. ( $ BILLIONS) 2. GDP PRICE INDEX 39 113. 65 114 .16 114. 70 115. 24 115. 84 116.44 111. 42 113. 40 115. 55 N.A. N.A. (2009=100) 3. CORPORATE PROFITS AFTER TAXES 17 N.A. 1697.0 1718. 7 1721. 5 1727.7 1744.9 1602.4 1663.6 1733 .1 N.A. N.A. ( $ BILLIONS) 4. UNEMPLOYMENT RATE 39 4.3 4.2 4.1 4.1 4.1 4.0 4. 9 4. 4 4.1 4.0 4.1 (PERCENT) 5. NONFARM PAYROLL EMPLOYMENT 35 146625 14 717 4 147669 148170 148641 149108 144306 146442 148403 N.A. N.A. (THOUSANDS) 6. INDUSTRIAL PRODUCTION 34 104.7 105.4 106.l 106.6 107.2 107.8 103.1 104. 7 107.0 N.A. N.A. (2012=100) 7. NEW PRIVATE HOUSING STARTS 36 1.17 1.21 1.25 1. 26 1. 27 1.28 1.18 1.19 1.27 N.A. N.A. (ANNUAL RATE, MILLIONS) 8. 3-MONTH TREASURY BILL RATE 37 1.04 1.15 1.30 1.49 1. 67 1. 81 0.32 0. 92 1.59 2.20 2.50 (PERCENT) 9. MOODY'S AAA CORP BOND YIELD* 22 · N.A. 3.75 4.00 4.15 4.30 4.34 N.A. 3.79 4.22 N.A. N.A. (PERCENT) 10. MOODY'S BAA CORP BOND YIELD* 24 N.A. 4.40 4.60 4.76 4. 93 5.03 N.A. 4.49 4. 84 N.A. N.A. (PERCENT) 11. 10-YEAR TREASURY BOND YIELD 38 2.24 2.42 2.56 2.69 2.79 2.95 1. 84 2.34 2.75 3.28 3.38 (PERCENT) 12. REAL GDP 40 17157 17267 17370 17472 17564 17667 16716 17089 17517 17886 18224 (BILLIONS, CHAIN WEIGHTED) 13. TOTAL CONSUMPTION EXPENDITURE 39 11922 .1 11998.8 12070.2 12144.1 12220.1 12287.2 11572.1 11884.3 12180.7 N.A. N.A. (BILLIONS, CHAIN WEIGHTED) 14. NONRESIDENTIAL FIXED INVESTMENT 38 2322.7 2348.0 2370.8 2394.7 2419.2 2441. 8 2210.4 2308.6 2406.9 N.A. N.A. (BILLIONS, CHAIN WEIGHTED) 15. RESIDENTIAL FIXED INVESTMENT 38 585.0 589.3 596. 2 602.1 608.7 613.1 587.5 593.4 605.8 N.A. N.A. (BILLIONS, CHAIN WEIGHTED) 16. FEDERAL GOVERNMENT C & I 38 1116.9 1119 .1 1121.3 1123. 8 1126. 2 1130. 3 1114. 6 1114. 5 1124. 6 N.A. N.A. (BILLIONS, CHAIN WEIGHTED) 17. STATE AND LOCAL GOVT C & I 38 1775.7 1779. 7 1785.0 1790. 4 1795. 9 1800.7 1783. 7 1780.2 1793.6 N.A. N.A. (BILLIONS, CHAIN WEIGHTED) 18. CHANGE IN PRIVATE INVENTORIES 37 35.8 34.1 34.1 35.0 36.5 43.2 33.4 19.1 36. 4 N.A. N.A. (BILLIONS, CHAIN WEIGHTED) 19. NET EXPORTS 38 -595.5 -600.9 -611.0 -619.2 -624.4 -629. 3 -586.3 -608.l -621.6 N.A. N.A. (BILLIONS, CHAIN WEIGHTED) * THE HISTORICAL VALUES OF MOODY'S AAA AND BAA RATES ARE PROPRIETARY AND THEREFORE NOT AVAILABLE TO THE GENERAL PUBLIC. SOURCE: RESEARCH DEPARTMENT, FEDERAL RESERVE BANK OF PHILADELPHIA. SURVEY OF PROFESSIONAL FORECASTERS, FOURTH QUARTER 2017. 10 Attachment BEL-16 Cause No. 44988 Page 11 of16 TABLE TWO MAJOR MACROECONOMIC INDICATORS PERCENTAGE CHANGES AT ANNUAL RATES NUMBER Q3 2017 Q4 2017 Ql 2018 Q2 2018 Q3 2018 2016 2017 2018 2019 OF TO TO TO TO TO TO TO TO TO FORECASTERS Q4 2017 Ql 2018 Q2 2018 Q3 2018 Q4 2018 2017 2018 2019 2020 1. GROSS DOMESTIC PRODUCT (GDP) 39 4.5 4.5 4.3 4.3 4.3 4.0 4.5 N.A. N.A. ( $ BILLIONS) 2. GDP PRICE INDEX 39 1.8 1. 9 1. 9 2.1 2.1 1.8 1. 9 N.A. N.A. (2009=100) 3. CORPORATE PROFITS AFTER TAXES 17 5.5 5.2 0.6 1.5 4.0 3.8 4.2 N.A. N.A. ($ BILLIONS) 4 . UNEMPLOYMENT RATE 39 -0.1 -0.1 -0.0 -0.0 -0.0 -0.5 -0.3 -0.1 0.1 (PERCENT) 5. NONFARM PAYROLL EMPLOYMENT (PERCENT CHANGE) 35 1.5 1. 4 1.4 1.3 1.3 1.5 1.3 N.A. N.A. (AVG MONTHLY CHANGE) 35 183.0 164.9 167 .0 157.1 155.6 178.0 163.4 N.A. N.A. 6. INDUSTRIAL PRODUCTION 34 2.9 2.4 2.1 2.2 2.1 1. 6 2.1 N.A. N.A. (2012=100) 7. NEW PRIVATE HOUSING STARTS 36 15.4 13.6 3.8 3.8 4.7 1.5 6.3 N.A. N.A. (ANNUAL RATE, MILLIONS) 8. 3-MONTH TREASURY BILL RATE 37 0.11 0.15 0.19 0.18 0.14 0.60 0. 67 0. 62 0.30 (PERCENT) 9. MOODY'S AAA CORP BOND YIELD* 22 N.A. 0.25 0.15 0.15 0.04 N.A. 0.43 N.A. N.A. (PERCENT) 10. MOODY'S BAA CORP BOND YIELD* 24 N.A. 0.20 0.16 0.16 0.10 N.A. 0.35 N.A. N.A. (PERCENT) 11. 10-YEAR TREASURY BOND YIELD 38 0.18 0.14 0.13 0.11 0.16 0.50 0.41 0.53 0.11 (PERCENT) 12. REAL GDP 40 2.6 2.4 2.4 2.1 2.3 2.2 2.5 2.1 1. 9 (BILLIONS, CHAIN WEIGHTED) 13. TOTAL CONSUMPTION EXPENDITURE 39 2.6 2.4 2.5 2.5 2.2 2.7 2.5 N.A. N.A. (BILLIONS, CHAIN WEIGHTED) 14. NONRESIDENTIAL FIXED INVESTMENT 38 4. 4 3.9 4.1 4.2 3.8 4.4 4.3 N.A. N.A. (BILLIONS, CHAIN WEIGHTED) 15. RESIDENTIAL FIXED INVESTMENT 38 3.0 4.7 4.0 4.5 2.9 1. 0 2.1 N.A. N.A. (BILLIONS, CHAIN WEIGHTED) 16. FEDERAL GOVERNMENT C & I 38 0.8 0.8 0.9 0.9 1.5 -0.0 0.9 N.A. N.A. (BILLIONS, CHAIN WEIGHTED) 17. STATE AND LOCAL GOVT C & I 38 0.9 1.2 1.2 1.2 1.1 -0.2 0.8 N.A. N.A. (BILLIONS, CHAIN WEIGHTED) 18. CHANGE IN PRIVATE INVENTORIES 37 -1. 7 -0.1 1.0 1. 4 6.7 -14.3 17 .3 N.A. N.A. (BILLIONS, CHAIN WEIGHTED) 19. NET EXPORTS 38 -5.4 -10.1 -8.2 -5.2 -4.9 -21. 8 -13.5 N.A. N.A. (BILLIONS, CHAIN WEIGHTED) * THE HISTORICAL VALUES OF MOODY'S AAA AND BAA RATES ARE PROPRIETARY AND THEREFORE NOT AVAILABLE TO THE GENERAL PUBLIC. NOTE: FIGURES FOR UNEMPLOYMENT RATE, 3-MONTH TREASURY BILL RATE, MOODY'S AAA CORPORATE BOND YIELD, MOODY'S BAA CORPORATE BOND YIELD, AND 10-YEAR TREASURY BOND YIELD ARE CHANGES IN THESE RATES, IN PERCENTAGE POINTS. FIGURES FOR CHANGE IN PRIVATE INVENTORIES AND NET EXPORTS ARE CHANGES IN BILLIONS OF CHAIN-WEIGHTED DOLLARS. ALL OTHERS ARE PERCENTAGE CHANGES AT ANNUAL RATES. SOURCE: RESEARCH DEPARTMENT, FEDERAL RESERVE BANK OF PHILADELPHIA. SURVEY OF PROFESSIONAL FORECASTERS, FOURTH QUARTER 2017. 11 Attachment BEL-16 Cause No. 44988 Page 12 of16 TABLE THREE MAJOR PRICE INDICATORS MEDIANS OF FORECASTER PREDICTIONS ACTUAL FORECAST(Q/Q) ACTUAL FORECAST(Q4/Q4) NUMBER OF 2017 2017 2018 2018 2018 2018 2016 2017 2018 2019 FORECASTERS Q3 Q4 Ql Q2 Q3 Q4 ANNUAL ANNUAL ANNUAL ANNUAL 1. CONSUMER PRICE INDEX 40 2.0 2.3 2.1 2.0 2.2 2.1 1.8 1.8 2.1 2.3 (ANNUAL RATE) 2. CORE CONSUMER PRICE INDEX 38 1. 7 1. 9 2.0 2.1 2.1 2.2 2.2 1. 7 2.1 2.2 (ANNUAL RATE) 3. PCE PRICE INDEX 37 1.5 1. 9 1. 7 1.8 1.9 1. 9 1. 6 1.5 1.8 2.0 (ANNUAL RATE) 4. CORE PCE PRICE INDEX 36 1.3 1. 6 1. 7 1.8 1.8 1. 9 1. 9 1. 4 1.8 2.0 (ANNUAL RATE) SOURCE: RESEARCH DEPARTMENT, FEDERAL RESERVE BANK OF PHILADELPHIA. SURVEY OF PROFESSIONAL FORECASTERS, FOURTH QUARTER 2017. 12 Attachment BEL-16 Cause No. 44988 Page 13 of16 TABLE FOUR ESTIMATED PROBABILITY OF DECLINE IN REAL GDP ESTIMATED Q3 2017 Q4 2017 Ql 2018 Q2 2018 Q3 2018 PROBABILITY TO TO TO TO TO (CHANCES IN 100) Q4 2017 Ql 2018 Q2 2018 Q3 2018 Q4 2018 NUMBER OF FORECASTERS 10 OR LESS 29 19 15 11 7 11 TO 20 2 13 16 17 20 21 TO 30 1 0 2 5 4 31 TO 40 0 0 0 0 1 41 TO 50 0 0 0 0 0 51 TO 60 0 0 0 0 0 61 TO 70 0 0 0 0 0 71 TO 80 0 0 0 0 0 81 TO 90 0 0 0 0 0 91 AND OVER 0 0 0 0 0 NOT REPORTING 9 9 8 8 9 MEAN AND MEDIAN MEDIAN PROBABILITY 5.00 10.00 12.00 15.00 15.00 MEAN PROBABILITY 6.29 10.44 12.64 14.69 17.05 NOTE: TOTAL NUMBER OF FORECASTERS REPORTING IS 32. SOURCE: RESEARCH DEPARTMENT, FEDERAL RESERVE BANK OF PHILADELPHIA. SURVEY OF PROFESSIONAL FORECASTERS, FOURTH QUARTER 2017. 13 Attachment BEL-16 Cause No. 44988 Page 14 of16 TABLE FIVE MEAN PROBABILITIES MEAN PROBABILITY ATTACHED TO POSSIBLE CIVILIAN UNEMPLOYMENT RATES: (ANNUAL AVERAGE) 2017 2018 2019 2020 9.0 PERCENT OR MORE 0.03 0.03 0.00 0.01 8.0 TO 8.9 PERCENT 0.03 0.03 0.00 0.06 7.5 TO 7.9 PERCENT 0.03 0.03 0.01 0.14 7.0 TO 7.4 PERCENT 0.03 0.03 0.09 0.85 6.5 TO 6.9 PERCENT 0.07 0.03 0.75 2.09 6.0 TO 6.4 PERCENT 0.13 0.26 1.85 4.60 5.5 TO 5.9 PERCENT 0.28 1. 61 5.53 8.28 5.0 TO 5.4 PERCENT 2.69 7.45 13.56 15.45 4.0 TO 4.9 PERCENT 89.76 57.20 45.17 41. 94 LESS THAN 4.0 PERCENT 6.94 33.30 33.03 26.57 MEAN PROBABILITY ATTACHED TO POSSIBLE PERCENT CHANGES IN REAL GDP: (ANNUAL-AVERAGE OVER ANNUAL-AVERAGE) 2016-2017 2017-2018 2018-2019 2019-2020 6.0 OR MORE 0.03 0. 26 0.34 0.32 5.0 TO 5.9 0.06 0.75 0.87 1.14 4.0 TO 4.9 0.52 2.79 3.94 4.38 3.0 TO 3.9 4.50 19.84 17.25 15.79 2.0 TO 2.9 77. 71 49.62 39.17 33.69 1.0 TO 1. 9 14.55 17.60 21. 55 23.74 0.0 TO 0.9 1. 59 6.03 10 .11 11. 99 -1.0 TO -0.1 0.65 1. 77 4.47 6.03 -2.0 TO -1.1 0.12 0.69 1. 54 1. 97 -3.0 TO -2.1 0.24 0.58 0.48 0.61 LESS THAN -3.0 0.03 0.06 0.26 0.35 MEAN PROBABILITY ATTACHED TO POSSIBLE PERCENT CHANGES IN GDP PRICE INDEX: (ANNUAL-AVERAGE OVER ANNUAL-AVERAGE) 2016-2017 2017-2018 4.0 OR MORE 0.03 0.26 3.5 TO 3.9 0.18 0.90 3.0 TO 3.4 1. 43 3.33 2.5 TO 2.9 4.61 11. 42 2.0 TO 2.4 16.60 32.69 1. 5 TO 1. 9 66.12 36.61 1.0 TO 1. 4 10.12 10.69 0.5 TO 0.9 0.70 2.94 0.0 TO 0.4 0.15 0.74 WILL DECLINE 0.06 0.43 SOURCE: RESEARCH DEPARTMENT, FEDERAL RESERVE BANK OF PHILADELPHIA. SURVEY OF PROFESSIONAL FORECASTERS, FOURTH QUARTER 2017. 14 Attachment BEL-16 Cause No. 44988 Page 15 of16 TABLE SIX MEAN PROBABILITY OF CORE CPI AND CORE PCE INFLATION (Q4/Q4) MEAN PROBABILITY ATTACHED TO CORE CPI INFLATION: 16Q4 TO 17Q4 17Q4 TO 18Q4 4 PERCENT OR MORE 0.03 0.10 3.5 TO 3.9 PERCENT 0.03 0.48 3.0 TO 3.4 PERCENT 0.91 2.79 2.5 TO 2.9 PERCENT 4.58 16.25 2.0 TO 2.4 PERCENT 22.95 37.99 1.5 TO 1. 9 PERCENT 60.76 29.92 1.0 TO 1. 4 PERCENT 9.33 8.73 0.5 TO 0.9 PERCENT 1.21 2.92 0.0 TO 0.4 PERCENT 0.16 0.63 WILL DECLINE 0.03 0.18 MEAN PROBABILITY ATTACHED TO CORE PCE INFLATION: 16Q4 TO 17Q4 17Q4 TO 18Q4 4 PERCENT OR MORE 0.04 0.15 3.5 TO 3.9 PERCENT 0.04 0.34 3.0 TO 3.4 PERCENT 0.49 1. 93 2.5 TO 2.9 PERCENT 2.16 8.70 2.0 TO 2.4 PERCENT 13.97 29.75 1.5 TO 1. 9 PERCENT 46.48 39.97 1.0 TO 1.4 PERCENT 33.00 13. 89 0.5 TO 0.9 PERCENT 3.63 4.44 0.0 TO 0.4 PERCENT 0.16 0. 71 WILL DECLINE 0.04 0 .11 SOURCE: RESEARCH DEPARTMENT, FEDERAL RESERVE BANK OF PHILADELPHIA. SURVEY OF PROFESSIONAL FORECASTERS, FOURTH QUARTER 2017. 15 Attachment BEL-16 Cause No. 44988 Page 16 of16 TABLE SEVEN LONG-TERM (5-YEAR AND 10-YEAR) FORECASTS ANNUAL AVERAGE OVER THE NEXT 5 YEARS: 2017-2021 CPI INFLATION RATE PCE INFLATION RATE MINIMUM 1. 95 MINIMUM 1. 73 LOWER QUARTILE 2.00 LOWER QUARTILE 1. 82 MEDIAN 2.20 MEDIAN 1. 90 UPPER QUARTILE 2.25 UPPER QUARTILE 2.00 MAXIMUM 2.80 MAXIMUM 2.50 MEAN 2.17 MEAN 1. 94 STD. DEVIATION 0.20 STD. DEVIATION 0.15 N 35 N 34 MISSING 6 MISSING 7 ANNUAL AVERAGE OVER THE NEXT 10 YEARS: 2017-2026 CPI INFLATION RATE PCE INFLATION RATE ------MINIMUM 1. 87 MINIMUM 1. 75 LOWER QUARTILE 2.00 LOWER QUARTILE 1. 90 MEDIAN 2.20 MEDIAN 2.00 UPPER QUARTILE 2.30 UPPER QUARTILE 2.10 MAXIMUM 2.70 MAXIMUM 2.30 MEAN 2.20 MEAN 2.00 STD. DEVIATION 0.19 STD. DEVIATION 0.14 N 34 N 33 MISSING 7 MISSING 8 SOURCE: RESEARCH DEPARTMENT, FEDERAL RESERVE BANK OF PHILADELPHIA. SURVEY OF PROFESSIONAL FORECASTERS, FOURTH QUARTER 2017. 16 CERTIFICATE OF SERVICE This is to certify that a copy of the foregoing Indiana Office of Utility Consumer Counselor Public's Exhibit No. 7, Testimony of OUCC Witness Bradley E. Lorton has been served upon the following counsel of record in the captioned proceeding by electronic service on March 2, 2018. Claudia J. Earls Kay E. Pashos Christopher C. Earle Steven W. Krohne NISOURCE CORPORATE SERVICES - LEGAL ICE MILLER, LLP [email protected] [email protected] [email protected] [email protected] Todd A. Richardson Courtesy copy to: Aaron A. Schmoll Timothy R. Caister LEWIS & KAPPES, P.C. Erin E. Whitehead [email protected] Debi McCall [email protected] NORTHERN INDIANA PUBLIC SERVICE C0MPANY,LLC [email protected] [email protected] [email protected] Jennifer A. Washburn Nikki G. Shoultz Margo L. Tucker Kristina Kem Wheeler CITIZENS ACTION COALITION BOSE MCKINNEY & EVANS LLP [email protected] [email protected] [email protected] [email protected] Joseph P. Rompala Robert K. Johnson Tabitha L. Blazer rj [email protected] LEWIS & KAPPES, P.C. [email protected] [email protected] Nicholas K. Kile Antonia Domingo BARNES & THORNBURG LLP Anthony Alfano [email protected] UNITED STEELWORKERS [email protected] [email protected] Scott Franson Deputy Consumer Counselor INDIANA OFFICE OF UTILITY CONSUMER COUNSELOR 115 West Washington Street Suite 1500 South Indianapolis, IN 46204 [email protected] 317/232-2494-Phone 317/232-5923 - Facsimile