Founded in 1852 MICHIGAN: Ann Arbor by Sidney Davy Miller Detroit Grand Rapids Kalamazoo Lansing Troy FLORIDA: Tampa ILLINOIS: Chicago NEW YORK: New York SHERRI A. WELLMAN Miller, Canfield, Paddock and Stone, P.L.C. OHIO: Cincinnati TEL (517) 483-4954 One Michigan Avenue, Suite 900 CANADA: Toronto Windsor FAX (517) 374-6304 Lansing, Michigan 48933 CHINA: Shanghai E-MAIL [email protected] TEL (517) 487-2070 MEXICO: Monterrey FAX (517) 374-6304 POLAND: Gdynia www.millercanfield.com Warsaw Wrocław
December 21, 2016
Ms. Kavita Kale Executive Secretary Michigan Public Service Commission 7109 W. Saginaw Hwy. Lansing, MI 48917
Re: SEMCO Energy Gas Company 2017-18 GCR Plan and Factors MPSC Case No. U-18157
Dear Ms. Kale:
Enclosed for electronic filing on behalf of SEMCO Energy Gas Company are the following:
(i) Application; (ii) Direct Testimony and Exhibits of Walter E. Fitzgerald; (iii) Direct Testimony and Exhibits of Jennifer L. Dennis; (iv) Direct Testimony and Exhibits of Tamara L. Spencer; (v) Direct Testimony and Exhibits of James A. Van Sickle; (vi) Direct Testimony and Exhibit of Michael J. Clyne; and (vii) Appearance of Sherri A. Wellman.
Finally, a marked-up Notice of Hearing has been electronically sent to Danielle Rogers.
If you should have any questions, please kindly advise.
Very truly yours,
Sherri A. Wellman Enclosures cc: Steve McLean Walt Fitzgerald Jim Van Sickle 27955337.1\129584-00101 STATEOFMICHIGAN
BEFORE THE MICHIGAN PUBLIC SERVICE COMMISSION
*****
In the matter of the application of ) SEMCO ENERGY GAS COMPANY ) Case No. U-18157 for authority to implement a gas cost recovery plan ) and factor for the 12-month period from April 2017 ) through March 2018 and for related approvals. ) )
APPLICATION
SEMCO Energy Gas Company (“SEMCO Gas” or the “Company”), a division of
SEMCO Energy, Inc., (“SEMCO Energy”) hereby applies for approval of a Gas Cost Recovery
(“GCR”) plan and factor for a 12-month period from April 2017 through March 2018. The
Company respectfully represents to the Michigan Public Service Commission (“Commission” or
“MPSC”) as follows:
1. SEMCO Gas, with its principal office located at 1411 Third Street, Suite A, Port
Huron, Michigan, is engaged as a public utility in the business of transporting, supplying and distributing natural gas to the public in its various service areas located in the Lower and Upper
Peninsulas of Michigan.
2. SEMCO Gas’s retail natural gas sales business and its retail gas transportation business are subject to the jurisdiction of the Commission.
3. Pursuant to 1982 PA 304 (“Act 304”) and Commission orders, SEMCO Gas is authorized to incorporate a GCR Clause in its rate schedules. See Case Nos. U-7481, U-14726,
U-15129 and U-16169. 4. Section 6h(3) of Act 304 requires that a utility file a complete GCR plan in order to implement its GCR Clause. Section 6h(4) of Act 304 also requires a utility to file a five-year forecast with that GCR plan.
5. SEMCO Gas requests authority to implement a uniform base GCR factor of
$4.1943 per Dekatherm (“Dth”) for the billing months of April 2017 through March 2018.
6. The base GCR factor of $4.1943 per Dth is comprised of a Balancing and
Demand Charge of $0.8048 per Dth and a Gas Commodity Cost of $3.3895 per Dth. Pursuant to the Company’s MPSC approved tariff sheet F-16.00, the Company’s Gas Customer Choice program customers are also billed the Balancing and Demand Charge to recover costs associated with balancing services and supplier of last resort obligations.
7. Additionally, SEMCO Gas seeks to implement a Contingency Factor Matrix, which, as described in the Company’s testimony and exhibits, is based on a methodology approved in its previous GCR case. The Contingency Factor Matrix will be used to adjust the
GCR factor on a monthly basis.
8. Further, the testimony and exhibits describe all of SEMCO Gas’s major contracts and gas supply and transportation arrangements. Moreover, included in the testimony is an evaluation of the reasonableness and prudence of SEMCO Gas’s decisions to obtain gas in the manner described in the GCR plan in light of the major alternative gas supplies available to
SEMCO Gas to minimize its costs of gas. Additionally, the testimony describes the inclusion and recovery of interstate upstream capacity improvement costs. Finally, the forecasting requirements of MCL 460.6h(7) are also met.
WHEREFORE, SEMCO Energy Gas Company prays that the Commission:
A. Make and issue its notice of hearing, and after notice and hearing;
2 B. Authorize SEMCO Energy Gas Company to implement a 12-month GCR plan for the period from April 1, 2017, through March 31, 2018, as proposed in this Application and supporting testimony;
C. Determine that the decisions underlying the plan are reasonable and prudent;
D. Authorize SEMCO Energy Gas Company to implement the GCR factors, including the Balancing and Demand Charge, and the Contingency Factor Matrix for the period from April 1, 2017 through March 31, 2018, as proposed in this Application and supporting testimony;
E. Determine that the decisions underlying the five-year forecast are reasonable and prudent, and indicate any cost items in the five-year forecast that, on the basis of present evidence, this Commission would be unlikely to permit SEMCO Energy Gas Company to recover from its customers in rates, rate schedules, or gas cost recovery factors established in the future; and
F. Grant SEMCO Energy Gas Company such further relief as may be lawful and proper.
Respectfully submitted,
SEMCO ENERGY GAS COMPANY
Dated: December 21, 2016 By: One of Its Attorneys Sherri A. Wellman (P38989) Paul M. Collins (P69719) MILLER, CANFIELD, PADDOCK AND STONE, P.L.C. One Michigan Avenue, Suite 900 Lansing, MI 48933 (517) 487-2070
Attorneys for SEMCO Energy Gas Company 27956403.1\129584-00101
3 STATE OF MICHIGAN BEFORE THE MICHIGAN PUBLIC SERVICE COMMISSION *****
In the matter of application of ) SEMCO ENERGY GAS COMPANY for authority to ) Case No. U-18157 implement a gas cost recovery plan and factors for ) the 12-month period from April 2017 ) through March 2018 and for related approvals. ) )
DIRECT TESTIMONY AND EXHIBITS
OF WALTER E. FITZGERALD
ON BEHALF OF SEMCO ENERGY GAS COMPANY TESTIMONY AND EXHIBITS OF WALTER E. FITZGERALD ON BEHALF OF SEMCO ENERGY GAS COMPANY
1 Q. Please state your name, business address, and business title. 2 A. My name is Walter E. Fitzgerald. My business address is 1411 Third Street, Suite A, 3 Port Huron, MI, 48060. My current title is Director of Gas Management Services for 4 SEMCO Energy, Inc. d/b/a SEMCO Energy Gas Company (“SEMCO Gas” or the 5 “Company”). 6 7 Q. Please describe your educational background and utility experience. 8 A. In April 1983, I graduated from Oakland University, Rochester, Michigan, with a Bachelor 9 of Science degree in Mechanical Engineering. In May 1983, I accepted a position with 10 the Company as Staff Engineer after which I attained positions with increasing 11 responsibilities, including Superintendent of Gas Control, Manager of Gas Control, 12 Manager of Production, Transmission, and Storage, Manager of Engineering, and 13 Director of Engineering. Since December of 1999, I have acted as the Director of Gas 14 Supply and Gas Transportation and Director of Gas Management Services. I have 15 received comprehensive training in oil and gas reservoir engineering, natural gas 16 storage engineering, gas well testing, natural gas measurement engineering, utility rates 17 and rate design, regulator station design, along with a wide variety of additional natural 18 gas industry training including accounting, finance, forecasting, natural gas contracting 19 and purchasing strategies, natural gas physical and financial hedging, and purchasing 20 strategies for natural gas liquids (“NGLs”). 21 22 Q. What are your responsibilities as Director of Gas Management Services? 23 A. As Director, Gas Management Services, my area of responsibilities include gas supply 24 (“supply”), gas control, gas measurement, rates and regulatory functions. The supply 25 functions currently include planning and contracting for supply, gas storage, interstate 26 and intrastate pipeline transportation for the Company’s residential and general service 27 customers also known as Gas Cost Recovery (“GCR”) customers. Other supply 28 responsibilities include directing the administrative activities related to third party large 29 volume end-user transportation (“EUT”) and the Company’s Gas Customer Choice 30 (“GCC”) program. Gas control functions include directing activities associated with the 31 monitor and control of the Company’s interstate pipeline interconnections, distribution 32 systems, on-system storage reservoirs, and compressor stations. Gas measurement 33 functions include directing activities associated with ensuring accurate measurement of
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1 gas received, transported, distributed, and delivered to the Company’s customers. 2 Lastly, I provide direction to the Company’s Manager of Gas Supply and the Manager of 3 Gas Control. 4 5 Q. Have you previously testified in support of the Company’s prior GCR cases 6 brought before the Michigan Public Service Commission (the “Commission” or 7 the “MPSC” )? 8 A. Yes. Since 2001, I have either offered pre-filed direct testimony, or testified, on behalf 9 of the Company in all of the Company’s GCR cases and several tariff case filings before 10 the Commission. 11 12 Q. What is the purpose of your testimony in this proceeding? 13 A. The purpose of my testimony is to present and address the Company’s portfolio of 14 pipeline transportation and storage assets, operational constraints, fixed gas costs, 15 storage plan, supply plan, peak day plan, design day plan, and the estimated cost of gas 16 for the 2017-2018 GCR period pertaining to its service areas. 17 18 Q. Are you sponsoring any exhibits in this proceeding?
19 A. Yes, I am sponsoring the following exhibits: 20 Exhibit A-1 Supply Service Areas 21 Exhibit A-2 Pipeline Transportation, Storage, and Peaking Supply 22 Exhibit A-3 CECO Capacity Plan Cost Savings 23 Exhibit A-4 Supply Network Diagram 24 Exhibit A-5 FERC Activity Summary 25 Exhibit A-6 Storage Utilization Plan 26 Exhibit A-7 Average Day Supply Purchase Plan 27 Exhibit A-8 Design Day Supply Plan 28 Exhibit A-9 Estimated Cost of Gas 29 Exhibit A-10 NYMEX Price Forecast 30 Exhibit A-11 Basis Price Forecast 31 32 Q. Were these exhibits prepared by you or under your direction and supervision? 33 A. Yes.
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1 2 Supply Service Areas 3 Q. Please provide a description of the supply service areas served by the Company 4 and the pipeline and storage assets that serve each area. 5 A. As shown in Exhibit A-1, the Company’s six supply service areas (“service areas”) are 6 widely spread across the State of Michigan and are served by a variety of interstate 7 pipelines, intrastate pipelines, and on-system storage assets. These service areas 8 include: 9 Port Huron Service Area – The Port Huron service area has natural gas receipt 10 points with two interstate pipeline transportation providers, Great Lakes Gas 11 Transmission Company (“GLGTC”) and ANR Pipeline Company (“ANR”); three 12 intrastate pipeline transportation providers, Consumers Energy Company 13 (“CECO”), DTE Gas Company (“DTE”), and SEMCO Pipeline Company’s (“SPL”) 14 Greenwood Pipeline (“GWPL”); and on-system gas storage reservoirs, Morton gas 15 storage reservoir and Collins gas storage reservoir. This service area is also 16 served by a small amount of local production. 17 Central Service Area - The Central service area has natural gas receipt points with 18 two interstate pipeline transportation providers, Panhandle Eastern Pipeline 19 Company (“PEPL”) and ANR; one intrastate pipeline transportation provider, SPL’s 20 Eaton Rapids Pipeline (“ERPL”); and two on-system gas storage reservoirs, Lacey 21 gas storage reservoir, and the Lee gas storage reservoir. 22 Niles Service Area – The Niles service area has natural gas receipt points with one 23 interstate pipeline transportation provider, ANR, and one intrastate pipeline 24 transportation provider, CECO. 25 Holland Service Area – The Holland service area has natural gas receipt points 26 with one interstate pipeline transportation provider, ANR, and one intrastate 27 pipeline transportation provider, CECO. 28 UP West Service Area – The UP West service area has natural gas receipt points 29 with one interstate pipeline transportation provider, Northern Natural Gas Company 30 (“NNG”). 31 UP East Service Area – The UP East service area has natural gas receipt points 32 with one interstate pipeline transportation provider, GLGTC.
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1 2 Interstate Pipeline Transportation 3 Q. Does the Company have contractual agreements for interstate and intrastate 4 pipeline transportation? 5 A. Yes. The Company has firm transportation capacity agreements with four interstate 6 pipelines and five intrastate pipelines as summarized in Exhibit A-2. 7 8 Q. Please identify the Company’s interstate and intrastate pipeline transportation 9 service providers. 10 A. As described above, supply is provided to the Company’s six service areas by a variety 11 of interstate and intrastate pipeline transportation providers. The Company currently has 12 contractual agreements for firm interstate pipeline transportation capacity with ANR, 13 GLGTC, PEPL, and NNG. The Company also has contractual agreements for firm 14 intrastate pipeline transportation with CECO, DTE, Jackson Pipeline Company (“JPL”), 15 ERPL, and GWPL. 16 17 Q. What is the purpose of the Company’s interstate and intrastate pipeline 18 transportation service capacity? 19 A. The purpose of the Company’s interstate pipeline transportation capacity is to facilitate 20 the transportation of natural gas purchased from various out-of-state domestic and 21 Canadian gas production basins along with various gas pooling points to the Company’s 22 service areas on a reliable and firm basis. Similarly, the purpose of the Company’s 23 intrastate pipeline transportation capacity is to facilitate the transportation of gas from 24 off-system storage and interstate pipelines located within the State of Michigan to the 25 Company’s service areas also on a firm and reliable basis. 26 27 ANR Pipeline Company 28 Q. Please describe and explain the purpose of the Company’s ANR long-haul and 29 storage firm interstate pipeline transportation contracts. 30 A. The Company holds ANR long-haul interstate pipeline transportation capacity with 31 receipt points on ANR’s Southwest and Southeast pipeline legs each having a common 32 delivery point known as SEM Group 1 (“SG1”). For the summer and winter periods, the 33 Company holds total ANR long-haul capacity of 62,689 Dth/d and 67,000 Dth/d,
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1 respectively. The purpose of the ANR long-haul capacity is to facilitate transportation of 2 natural supply produced from the Southeast, Marcellus-Utica, and Mid-continent gas 3 production basins to the Company’s Lower Peninsula service areas. The Company also 4 holds additional ANR storage pipeline capacity associated with its 2.5 MMDth ANR 5 storage service and its Eaton Rapids Gas Storage (“ERGSS”) service. For the summer 6 and winter periods, the Company holds total ANR storage capacity for off-system 7 storage injections and withdrawals of approximately 12,727 Dth/d and 90,255 Dth/d, 8 respectively. The purpose of the ANR storage pipeline capacity is to facilitate deliveries 9 to the Company’s ANR and ERGSS storage services for injections during the summer 10 period and facilitate withdrawals for deliveries to all of the Company’s Lower Peninsula 11 service areas during the winter period. 12 13 Q. Please identify the Company’s ANR long-haul and storage pipeline capacity 14 contracts scheduled to expire during 2017. 15 A. Table 1 identifies the Company’s ANR long-haul and storage pipeline capacity 16 agreements scheduled to expire on March 31, 2017. 17 18
19 Table 1 20 SEMCO ENERGY GAS COMPANY 21 ANR Pipeline Transportation Contracts Expiring 3/31/2017 22 (MDQ Units in Dth) 23 Primary Primary 24 Contract Service Receipt Delivery Summer Winter 25 Pipeline Segment Number Type Point(s) Point(s) MDQ MDQ 26 ANR Southeast 123256 Long Haul ETS ANR SE Head Stn SG1 22,345 24,500 27 ANR Southwest 122005 Long Haul ETS ANR SW Head Stn SG1 22,345 24,500 ANR Northern 122003 Long Haul ETS ANR NO Alliance PL SG1 18,000 18,000 28 ANR Northern 125465 Storage ETS ANR Stg/SG1 SG1/ANR Stg 5,091 50,000 29 ANR Northern 125573 Storage FTS-1 GLGTC Farwell, MI ANR Stg 7,636 0 ANR Northern 125467 Storage No Notice ANR Stg/SG1 SG1/ANR Stg 2,500 2,500 30 31 32 Q. Did the Company negotiate renewals for these contracts?
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1 A. Yes. The Company was successful in negotiating renewals of the expiring ANR pipeline 2 capacity contracts. 3 4 Q. Please identify the Company’s ANR interstate pipeline capacity contracts which 5 will be effective on April 1, 2017. 6 A. Table 2 identifies the Company’s ANR pipeline capacity contracts to be effective on April 7 1, 2017. 8 9 Table 2
10 SEMCO ENERGY GAS COMPANY ANR Pipeline Transportation Contracts Effective 4/1/2017 11 12 (MDQ Units in Dth) 13 Primary Primary Contract Service Receipt Delivery Summer Winter 14 Pipeline Segment Number Type Point(s) Point(s) MDQ MDQ Term
15 ANR Southeast 123256 Long Haul ETS ANR SE Head Stn SG1 11,172 12,250 4 yrs 16 ANR Southeast 128531 Long Haul ETS ANR SE Shelbyville SG1 11,172 12,250 4 yrs ANR Southwest 122005 Long Haul ETS ANR SW Head Stn SG1 22,345 24,500 4 yrs 17 ANR Southwest 122003 Long Haul ETS ANR SW Head Stn SG1 18,000 18,000 2 yrs ANR Northern 125465 Storage ETS ANR Stg/SG1 SG1/ANR Stg 5,091 50,000 4 yrs 18 ANR Northern 125573 Storage FTS-1 GLGTC Farwell, MI ANR Stg 7,636 0 4 yrs ANR Northern 125467 Storage No Notice ANR Stg/SG1 SG1/ANR Stg 2,500 2,500 4 yrs 19 20 21 Q. Why did the Company renew its expiring ANR pipeline capacity contracts? 22 A. The expiring contracts were renewed because they are an integral component to the 23 Company’s Lower Peninsula supply portfolio. Specifically, the contracted ANR pipeline 24 capacity is necessary to serve the Company’s Lower Peninsula customers for: 25 Summer period storage injection requirements. 26 Average day demand requirements. 27 Design Day demand requirements. 28 Firm balancing tolerance for EUT customers. 29 Obligation as the supplier-of-last-resort (“SOLR”) for GCC customers.1 30
1 Design Day demand is defined as the Company’s maximum forecasted natural gas demand of its GCR customers and GCC customers on the coldest experienced winter period day over the past 15 years.
Page 7 of 57 TESTIMONY AND EXHIBITS OF WALTER E. FITZGERALD ON BEHALF OF SEMCO ENERGY GAS COMPANY
1 Q. What were the Company’s renewal goals for its ANR long-haul pipeline capacity 2 portfolio? 3 A. The Company had four specific renewal goals for its ANR long-haul pipeline 4 transportation portfolio. The goals included: 5 1. Mitigating ANR’s 34.8% rate increase as approved by the Federal Energy 6 Regulatory Commission (“FERC”) in 2016. 7 2. Reconfiguring the Company’s ANR SE contract for acquisition of supply from the 8 Marcellus/Utica supply basins. 9 3. Mitigating the commodity cost of ANR supply from Alliance Pipeline in Chicago. 10 4. Positioning the Company for greater future supply diversity.
11 Q. Was the Company able to mitigate ANR’s 34.8% rate increase as approved by the 12 FERC in 2016? 13 A. Yes. The Company was able to negotiate a $1,858,539 (19%) annual cost reduction 14 from ANR’s approved tariff rates for the Company’s new ANR contract portfolio. The 15 negotiated ANR rates also resulted in a $1,107,737 (12%) annual cost reduction from 16 the Company’s prior ANR contract portfolio at ANR’s currently effective rates. 17 18 Q. Was the Company able to reconfigure its ANR SE contract 123256 for acquisition 19 of supply from the Marcellus/Utica supply basins? 20 A. Yes. The Company reconfigured its ANR SE contract 123256 such that half of the 21 winter and summer capacity is now under new contract 128531. Contract 128531 allows 22 the Company to source supply from the Marcellus/Utica supply basins through ANR’s 23 Shelbyville receipt point on a firm basis. Contract 128531 has summer capacity of 24 11,172 Dth/d and winter capacity of 12,250 Dth/d for a four year term expiring on 25 3/31/2021. Original contract 123256 will continue to allow the Company to source 26 supply from the southeast supply basins also on a firm basis. Contract 123256 has a 27 summer capacity of 11,172 Dth/d and winter capacity of 12,250 Dth/d for a four year 28 term expiring on 3/31/2021. 29 30 Q. Why did the Company reconfigure its ANR SE pipeline transportation capacity to 31 source supply ANR’sShelbyville receipt point?
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1 A. The timing of the Company’s ANR SE contract expiration in March 2017 provided the 2 Company with the opportunity to further diversify the Company’s ANR SE supply. As 3 such, the Company chose to move half of its ANR SE receipt point capacity to the ANR- 4 Shelbyville receipt point in order to gain access to the Marcellus and Utica supply basins 5 on a firm basis. 6 7 Q. Will the Company’s GCR customers realize a cost savings as a result of moving 8 half of the Company’sANR SE receipt point capacity to Shelbyville? 9 A. Yes. The Company’s GCR and GCC customers will realize an annual demand cost 10 saving of $222,067 or a total savings of $888,268 over the four year term of the contract. 11 The Company’s GCR customers will also realize a fuel cost savings as ANR’s fuel 12 retention rate for the Shelbyville to SG1 path is 1.04% compared to 1.59% for the ANR 13 SE Head Station to SG1 path. With respect to commodity cost savings, the annual 14 forward commodity basis value forecast for supply sourced at Shelbyville was -7.2 cents 15 compared to -7.0 cents at the SE Head station for the 2017-2018 GCR period. Similarly, 16 for the 2019-2020 GCR period, the annual forward commodity basis values forecast was 17 -11.0 cents for Shelbyville and -7.9 cents for the SE Head Station. Based on these 18 forward basis values, at the time the Company was negotiating with ANR, it appears the 19 Company’s GCR customers may also realize a commodity cost savings. 20 21 Q. Why did the Company not move all of its ANR SE receipt point capacity to the 22 Shelbyville receipt point? 23 A. The Company did not move all of its ANR SE receipt point capacity to Shelbyville 24 because the Company believed it would be prudent to move forward conservatively. 25 The Company took this approach because the Company has not had much experience 26 with acquiring supply at Shelbyville and the Company does not know how the ANR SE 27 basis values will actually pan out in the future when and if other proposed 28 Marcellus/Utica supply basin pipeline projects are completed, such as the Rover pipeline 29 and the Nexus pipeline projects. Therefore, the Company believed it was best to retain 30 its options and to have a level of supply diversity on the ANR’s Southeast pipeline leg 31 which includes firm receipts from both receipt points, ANR SE Head Station and 32 Shelbyville. 33
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1 Q. How did the Company reconfigure its ANR pipeline capacity portfolio in order to 2 mitigate the commodity cost of ANR supply from Alliance Pipeline in Chicago? 3 A. In an effort to mitigate the commodity cost of ANR supply from Alliance Pipeline in 4 Chicago, the Company changed the firm receipt point on contract 122003 from ANR’s 5 Alliance Pipeline receipt point in Chicago to the ANR SW Head Station. As such, the 6 Company now holds an incremental 18,000 Dth/d of winter and summer capacity with a 7 firm receipt point at the ANR SW Head Station for a term of two years expiring 8 3/31/2019. 9 10 Q. Please explain the benefit of changing the receipt point on contract 122003 to the 11 ANR SW Head Station. 12 A. During negotiations with ANR, the Company determined that the highest forecasted 13 summer and winter period commodity cost for supply transported on ANR was supply 14 sourced from the Company’s ANR Alliance Pipeline receipt point in the Chicago area. 15 As shown in Table 3, the forward commodity basis values for the ANR SW Head Station 16 were more favorable when compared to Chicago over the next two winter and summer 17 GCR periods. Clearly, the forecasted commodity cost of ANR supply appeared to be 18 more beneficial at the ANR SW Head Station so the Company made the decision move 19 the receipt point on contract 122003 for a two year term expiring on 3/31/19. 20 21 Table 3 22 23 Receipt Point Basis Values (Cents) 24 Location Summer 2017 Summer 2018 Winter 17-18 Winter 18-19 Chicago -8.7 -19.4 10.4 9.5 25 ANR SW Head Stn -24.5 -31.8 -11.6 -12.8 26 27 28 Q. Why did the Company contract for a term of two years on contract 122003 when 29 the rest of the Company’s ANR portfolio renewals were contracted for a term of 30 four years? 31 A. As stated above in the Company’s specific ANR pipeline capacity renewal goals, the 32 Company desired to position itself for greater future supply diversity. Over the next two 33 years, the Rover pipeline and the Nexus pipeline may be approved by the FERC,
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1 completed with construction, and delivering Marcellus/Utica production into Michigan. If 2 so, it may be prudent for the Company at this time to replace some or all of its ANR SW 3 Head Station receipt point capacity on contract number 122003 with capacity from 4 another interstate pipeline capacity provider in order to achieve even greater supply 5 diversity. As such, the Company chose a term of two years on contract 122003 so the 6 Company will have the opportunity to acquire capacity from another interstate pipeline in 7 order to achieve greater future supply diversity, if such expanded diversity is prudent to 8 pursue. 9 10 Q. If Rover and NEXUS pipelines are approved by the FERC and if they are 11 constructed into Michigan, how would the Company access the supply delivered 12 by these pipelines? 13 A. The Company could have access to supply delivered by Rover and NEXUS pipelines via 14 a new interconnection constructed with DTE’s pipeline system in St. Clair County near 15 Adair, MI. Both Rover and NEXUS pipelines plan to interconnect with Vector Pipeline 16 near Northville, MI whereby both Vector and NEXUS pipelines have each leased 17 pipeline capacity on DTE’s pipeline system. DTE’s pipeline system crosses the 18 Company’s 12” transmission system in the Company’s Port Huron service area near 19 Adair, MI providing assess to supply delivered by Vector, Rover, and NEXUS pipelines. 20 21 Q. Which pipeline (Vector, Rover, or NEXUS) would provide the Company with the 22 greatest amount of supply diversity? 23 A. The Company believes an interconnection with Vector where Vector has leased capacity 24 on DTE’s pipeline system near Adair, MI would provide the Company with the greatest 25 amount of supply diversity. With Vector, the Company would be able to source supply 26 from the planned Vector-Rover interconnection, the planned Vector-NEXUS 27 interconnection, the existing Vector-ANR interconnection at Joliet Illinois, and the Dawn 28 Ontario supply hub. Furthermore, the Company would be able to source supply from the 29 Company’s ERGSS storage service if a new interconnection was constructed between 30 Vector and JPL in Jackson County’s Tompkins Township. 31 32 Q. Please explain why diversity of sourcing its supply via ANR is important to the 33 Company.
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1 A. With ANR, the Company can source supply directly from the Southeast, Marcellus, 2 Utica, Midcontinent, and indirectly from Rocky Mountain supply regions on its ANR- 3 Southeast capacity and the Midcontinent supply region on its ANR-Southwest capacity. 4 In the future, the Company believes it may be able to further diversify its supply portfolio 5 and source more supply from the Marcellus and Utica shale basins if the proposed 6 Rover and Nexus pipelines are constructed. Each supply basin or hub has its own 7 unique cost value from a supply perspective, which is, among other things, driven by 8 consumer demand, reserve estimates, production capabilities, storage inventories, 9 available pipeline transportation capacity, production, gathering, pipeline outages, 10 competitive fuel prices, energy market economics, weather, and geopolitical events. 11 These price drivers are extremely complex and very difficult to precisely predict both 12 over the short-term and long-term for industry experts and the Company. Since the 13 Company cannot precisely predict where the best future value for supply will be found, 14 the Company believes its ANR pipeline transportation capacity portfolio will achieve a 15 reasonable mix of supply diversity among all the supply basins that serve ANR and such 16 diversity will meet the supply needs of its GCR customers in a reasonable, cost-effective 17 manner. In addition, such a mix of supply basins provides the Company and its 18 customers with a level of supply reliability in the event of a supplier, pipeline, or storage 19 provider force majeure. 20 21 Q. Did the Company renew its expiring ANR storage transportation capacity 22 contracts (125465 and 125573) and the associated expiring no-notice service 23 contract (125467)? 24 A. Yes. The Company’s expiring ANR storage transportation capacity contracts and the 25 associated no-notice service contract were also renewed. These contracts were 26 renewed because they are necessary for the facilitation of injections and withdrawals of 27 gas associated with the Company’s renewed ANRPL 2.5 MMDth storage service. 28 Renewal of the Company’s ANRPL storage service is further described in the Storage 29 Assets section of my testimony. 30 31 Q. The Company’s ANR contract 122006 for 40,255 Dth/d of winter capacity expires 32 March 31, 2018. What is the purpose of this contract and what are the Company’s 33 renewal plans for this contract?
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1 A. The Company’s ANR contract 122006 allows the Company to transport withdrawals from 2 the Company’s ERGSS storage service for delivery to the Company’s Lower Peninsula 3 ANR interconnection points during the winter period. The Company plans to renew 4 some or all of the pipeline capacity under ANR contract 122006 during 2017. 5 6 Q. Does ANR contract 122006 provide the Company with all the pipeline capacity 7 necessary for withdrawals from ERGSS? 8 A. No. The Company’s ERGSS maximum daily withdrawal quantity is 66,665 Dth/d net of 9 fuel. On a January Design Day, the Company plans to withdraw approximately 13,245 10 Dth/d of this capacity into the ERPL for deliveries to the Company’s Battle Creek and 11 Albion service areas, 13,020 Dth/d is withdrawn into CECO’s intrastate pipeline system 12 for redelivery to the Company’s CECO interconnection points, and 40,400 Dth/d is 13 withdrawn into ANR for deliveries to the Company’s Lower Peninsula ANR 14 interconnection points. 15 16 Q. As will be described in more detail later, a significant quantity of the Company’s 17 firm CECO pipeline transportation contact will not likely be renewed when it 18 expires on April 30, 2018. Will the Company increase the MDQ on ANR contract 19 122006 to replace the CECO capacity reduction? 20 A. Not likely, because ANR’s northern system capacity is currently sold-out. 21 22 Q. How much firm CECO pipeline capacity will the Company retain after April 30, 23 2018? 24 A. The Company is planning to retain approximately 7,200 Dth/d (net of fuel) of CECO firm 25 capacity after April 30, 2018. 26 27 Q. If the CECO pipeline capacity is reduced after April 30, 2018, what are the 28 Company’s pipeline capacity portfolio plans in order to continue to effectuate 29 withdrawals from ERGSS? 30 A. The Company is considering maintaining the current level of capacity on ANR contract 31 122006 and contracting with PEPL for new firm pipeline capacity for withdrawals from 32 ERGSS via JPL. If the Company decides to contract with PEPL, an existing JPL-PEPL 33 interconnection point will enable gas be to be withdrawn from ERGSS and transported
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1 via, JPL and PEPL for redelivery to the Company’s PEPL SEMIC group delivery points, 2 which includes Battle Creek and Albion, in the Company’s central service area. In 3 addition, gas withdrawn from ERGSS will also be capable of being delivered to all of the 4 Company’s other Lower Peninsula service areas via ANR, ERPL, and CECO. 5 6 Q. When will the Company need to make a decision regarding its pipeline capacity 7 portfolio for withdrawals from ERGSS? 8 A. As will be described in more detail under the Storage Assets section of this testimony, 9 the Company’s ERGSS storage service expires on March 31, 2018. The Company will 10 fully evaluate and negotiate with ANR and PEPL during 2017 for the pipeline capacity 11 necessary to enable withdrawals from the ERGSS storage service. 12 13 Great Lakes Gas Transmission Company 14 Q. Please describe the Company’s firm long-haul pipeline capacity contracts held 15 with GLGTC. 16 A. The Company currently holds two firm GLGTC long-haul pipeline capacity contracts with 17 primary receipt points at Emerson, Manitoba. Contract FT17191 has a winter capacity of 18 7,500 Dth/d with a primary delivery point at Carlton, MN (NNG). Contract FT17192 has 19 a summer capacity of 10,000 Dth/d and a winter capacity of 22,500 Dth/d with delivery 20 points at Farwell, MI (ANR – summer only) Chippewa, MI (CECO – winter only), and 21 SEMCO Gas (Watersmeet, Engadine, Manistique, St. Ignace, Bauman Rd, and Trumble 22 Rd). 23 24 Q. Please describe the purpose of the Company’sGLGTC long-haul pipeline capacity 25 contract FT17191. 26 A. The purpose of GLGTC contract FT17191 is to provide the Company with firm winter 27 pipeline transportation capacity of 7,500 Dth/d from the Canadian gas production basins, 28 via the Emerson receipt point to a delivery point located at Carlton, MN (NNG). The 29 capacity provided under GLGTC contract number FT17191 is required as a result of 30 NNG’s FERC approved gas tariff requirement commonly known as the “Carlton 31 Resolution Obligation”. Under this obligation, NNG requires its shippers, such as the 32 Company, to deliver certain quantities of gas to NNG’s system at Carlton, MN via 33 GLGTC during the winter period. The use of the Carlton delivery point into NNG also
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1 provides a level of balancing flexibility in the UP West. The renewal date for this 2 contract is November 1, 2018. 3 4 Q. Please describe the purpose of the Company’sGLGTC long-haul pipeline capacity 5 contract FT17192. 6 A. The purpose of GLGTC contract FT17192 is to provide the Company with firm summer 7 and winter pipeline transportation capacity of 10,000 Dth/d and 22,500 Dth/d, 8 respectively, for supply sourced from the Canadian gas production basins. Supply 9 transported on contract FT17192 is received at Emerson and delivered to the 10 Company’s UP East and Port Huron service areas. The renewal date for this contract 11 is November 1, 2018. 12 13 Q. The Company’s GLGTC pipeline capacity contracts FT17191 and FT17192 expire 14 on November 1, 2018. Does the Company plan to renew these contracts? 15 A. During late 2017 or early 2018, the Company will negotiate with GLGTC to renew both 16 contracts because they are necessary to meet the Company’s customer demand 17 requirements on an average day and on a Design Day for the Company’s UP West, UP 18 East, and Port Huron service areas. The Company will evaluate alternative GLGTC 19 receipt points and determine an appropriate MDQ for both contracts. The Company will 20 also consider alternative pipeline capacity, if available at the time of negotiations. 21 22 Q. Does the Company contract with GLGTC for winter period pipeline capacity to 23 enable the delivery of gas storage withdrawals? 24 A. Yes. As described in the Storage Assets section of my testimony, the Company has 25 renewed its Bluewater Gas Storage, LLC (“BWGS”) 1.0 MMDth gas storage service 26 contract. To enable firm winter withdrawals from the BWGS storage service, the 27 Company has renewed its pipeline capacity on GLGTC contract FT18178 for 12,000 28 Dth/d. Under GLGTC contract FT18178, gas withdrawals from BWGS are received at 29 the BWGS/GLGTC interconnection point, known as Rattle Run, and are transported and 30 delivered to the Company’s Port Huron service area interconnection point at Trumble Rd 31 during the winter period. The renewal date for GLGTC contract FT18178 is March 31, 32 2022.
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1 2 Q. What other winter period GLGTC contracts are held by the Company to enable the 3 delivery of gas storage withdrawals? 4 A. As described in the Storage Assets section of this testimony, the Company has a 5 peaking storage service with ANR Storage Company (“ANRSC”) for 530,000 Dth. To 6 enable firm winter withdrawals from the ANRSC storage service, the Company holds 7 GLGTC pipeline capacity totaling 53,000 Dth/d on contracts FT18232 and FT18233. 8 GLGTC contract FT18232 allows for withdrawals of 7,000 Dth/d from ANRSC at 9 Deward, MI to be delivered to the Company’s Port Huron Service area at Trumble Rd. 10 In addition, GLGTC contract FT18233 allows for withdrawals of 46,000 Dth/d from 11 ANRSC at Deward, MI to be delivered to CECO at Chippewa, MI where the gas is 12 redelivered to the Company’s CECO interconnection points using the Company’s CECO 13 firm transportation. 14 15 Q. The Company’sGLGTC contracts FT18232 and FT18233 both expire on March 31, 16 2018. Does the Company plan to renew the firm capacity under these contracts? 17 A. The Company will likely renew the pipeline capacity under GLGTC contracts FT18232 18 and FT18233 if the ANRSC storage capacity is renewed. However, the delivery point for 19 GLGTC contract FT18233 will likely change due to the unlikely renewal of the 20 Company’s entire CECO pipeline capacity. The details of which have yet to be 21 determined. 22 23 Panhandle Eastern Pipeline Company 24 Q. Please describe and explain the purpose of the Company’s firm long-haul PEPL 25 pipeline capacity contract 20653. 26 A. The Company’s firm long-haul PEPL pipeline capacity contract 20653 has an annual 27 capacity of 18,500 Dth/d with a delivery point located at the Company’s PEPL group 28 point known as SEMIC. The purpose of the Company’s PEPL contract 20653 is to 29 provide the Company with firm summer and winter pipeline transportation capacity of 30 18,500 Dth/d to the Company’s Battle Creek service area, Albion service area, and 31 during the summer period, to JPL for gas injections into the Company’s ERGSS storage 32 service. Gas transported under this contract is sourced from PEPL’s southwest field 33 zone production basin. The renewal date for this contract is April 1, 2020.
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1 2 Q. Please describe and explain the purpose of the Company’s interruptible PEPL 3 pipeline capacity contract 17145. 4 A. The Company also holds interruptible pipeline capacity with PEPL under contract 17145 5 having a maximum daily quantity (“MDQ”) of 10,000 Dth/Day. The purpose of this 6 pipeline capacity is to act as the swing contract for the Company’s PEPL gate stations. 7 As the swing contract, it assists the Company in minimizing exposure to PEPL’s $15.00 8 per Dth overrun charges. The renewal date for this contract is March 31, 2020. 9 10 Q. Does the Company incur any demand charges associated with the PEPL 11 interruptible pipeline capacity contract? 12 A. No. 13 14 Northern Natural Gas Company 15 Q. Please describe the Company’s firm long-haul pipeline capacity contracts held 16 with NNG. 17 A. The Company holds two firm long-haul pipeline capacity contracts with NNG. NNG 18 contract 110024 is a NNG TFX (flexible monthly firm MDQ) service while NNG contract 19 110025 is a TF service (annual and winter MDQ). 20 21 Q. Please describe the purpose of NNG TFX contract 110024. 22 A. The purpose of NNG TFX contract 110024 is to provide the Company with pipeline 23 capacity of: (i) 4,380 Dth/d during April and October, (ii) 880 Dth/d during May through 24 September, and (iii) 7,190 Dth/d during November through March to the Company’s UP 25 West service area interconnection points. This contract has NNG receipt points at 26 NNG’s field zone/market zone demarcation point at Clifton, KS, Northern Border Pipeline 27 at Ventura, IA, GLGTC at Carlton, MN, and NNG storage at Ogden, IA. The renewal 28 date for this contract is April 1, 2018. 29 30 Q. Please describe the purpose of NNG TF contract 110025. 31 A. The purpose of NNG TF contract 110025 is to provide the Company with annual 32 interstate pipeline capacity of 31,350 Dth/d and winter capacity of 12,900 Dth/d to the 33 Company’s UP West service area interconnection points. This contract has NNG receipt
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1 points at NNG’s field zone/market zone demarcation point at Clifton, KS, Northern 2 Border Pipeline at Ventura, IA, GLGTC at Carlton, MN, and NNG storage at Ogden, IA. 3 The renewal date for this contract is November 31, 2021. 4 5 Q. Although the incremental demand rate associated with the Houghton Gate Station 6 and Houghton Branch Line improvement on NNG contract 110025 expired on 7 March 31, 2015, will the Company continue to credit the cost of gas with revenues 8 collected from the implementation of the Houghton Gate Station Upstream 9 Pipeline Facility Improvement Charge as ordered by the MPSC in Case No. U- 10 16125? 11 A. Yes. The Company filed with the MPSC on October 30, 2009, in Case No. U-16125, to 12 implement an Upstream Pipeline Facility Improvement Charge. On January 6, 2011, the 13 MPSC ordered that a transportation charge of $0.2020 per Dth for a ten-year period be 14 applied to the Company’s EUT customers electing to use capacity at the Houghton Gate 15 Station or the Houghton Branch Line. The Company estimates the GCR credit for the 16 2017-2018 GCR period will be approximately $63,815. This estimate is based on 17 average EUT volumes consumed behind the Houghton gate station over the past five 18 GCR periods ending March 31, 2016. 19 20 Q. Does the Company’s NNG contract 110025 include additional upstream capacity 21 improvement costs? 22 A. Yes. As will be explained later in this testimony, the Company’s NNG contract 110025 23 includes additional costs for upstream capacity improvements to the Marquette 1A and 24 Lake Linden interconnection facilities with NNG over the 2017-2018 and 2018-2019 25 GCR periods. 26 27 Q. Please describe and explain the purpose of the Company’s NNG system 28 management service “SMS” service contract 22566. 29 A. The Company holds a 6,000 Dth/d SMS service contract with NNG under contract 30 number 22566. The NNG SMS service is no-notice type of service used in conjunction 31 with the Company’s firm NNG TF and TFX transportation services to help the Company 32 effectively manage its daily supply nominations and actual delivery variances, while 33 minimizing penalties associated with such variances. This service is necessary because
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1 NNG expects the Company, as well as all of NNG’s shippers, to take delivery of the 2 quantity of gas nominated to NNG on a daily basis. However, daily variances between 3 the quantities of gas nominated versus the actual quantities of gas delivered to the 4 Company are a daily certainty due to the difficulty and complexity of precisely 5 forecasting the daily demand of the Company’s customers given weather unpredictability 6 along with other uncontrollable and unpredictable variables. 7 8 Intrastate Pipeline Transportation 9 10 Consumers Energy Company 11 Q. Please describe the Company’sCECO Act 9 Gas Transportation Agreement. 12 A. The CECO Act 9 Gas Transportation Agreement became effective on May 1, 2015 and 13 has a term of three years. The agreement provides the Company with annual intrastate 14 pipeline transportation service with MDQs as follows: 15 Winter Period (November through March) – up to 110,000 Dth/d of which the first 16 50,000 Dth/d is firm and 60,000 Dth/d is interruptible. 17 Months of April and October – up to 110,000 Dth/d of which the first 15,000 Dth/d 18 is firm and 95,000 Dth/d is interruptible. 19 Months of May through September – up to 110,000 Dth/d of which the first 8,000 20 Dth/d is firm and 102,000 is interruptible. 21 CECO pipeline transportation serves the Company’s Port Huron, Niles, and Holland 22 service areas with gas during the winter and summer periods. The agreement provides 23 the Company with four CECO delivery points including: (1) the Overisel interconnection 24 serving the Company’s Holland service area; (2) the Three Rivers (Ferguson Road) 25 interconnection serving the Company’s Three Rivers community (in the Niles service 26 area); (3) the New Haven interconnection serving the Company’s Port Huron service 27 area; and (4) the Akron interconnection serving the Company’s northern thumb region of 28 the Port Huron service area. The agreement allows the Company to nominate gas from 29 ANR, PEPL, DTE, ANR gas storage and ANR SC gas storage, ERGSS gas storage via 30 JPL, and BWGS into CECO’s system for redelivery to all of the Company’s CECO 31 delivery points. 32
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1 Q. Please describe the rates being charged to the Company under the Act 9 Gas 2 Transportation Agreement. 3 A. For both firm and interruptible service, the underlying rate is $0.244 per Dth. For firm 4 transportation service, the CECO annual demand charge is $2,364,116. For 5 interruptible service, the CECO volumetric rate is $0.244 per Dth for gas transported in 6 excess of the firm daily MDQ. There is no demand charge for gas transported on an 7 interruptible basis. The fuel retention rate for all quantities transported by CECO is 8 1.83%. 9 10 Q. Please describe the CECO Operational Balancing Agreement which also became 11 effective on May 1, 2015. 12 A. The CECO Operational Balancing Agreement requires the Company to resolve 13 operational imbalances through in-kind balancing during the month in which the actual 14 operational imbalance is determined. Once the Company is notified by CECO of the 15 operational imbalance, the Company has three days to reduce any operational 16 imbalance to zero. There are no balancing charges, cash-out mechanisms, or daily 17 penalty charges. There is a $10.00 per Dth penalty if an imbalance is not resolved by 18 the end of the month following the month in which the actual monthly operational 19 balance is determined. 20 21 Q. The CECO Act 9 Gas Transportation Agreement expires on April 30, 2018. Has the 22 Company attempted to negotiate with CECO for a renewal of the agreement? 23 A. Yes. The Company attempted on two occasions to negotiate with CECO for a renewal 24 to the agreement at a discounted rate. On both occasions, CECO agreed to an 25 extension of the agreement but CECO would not agree to discount the agreement due to 26 what appears to be a matter of CECO policy. 27 28 Q. What are the Company’splans with respect to the CECO Act 9 Gas Transportation 29 Agreement? 30 A. Because of CECO’s policy, the Company plans to negotiate for with CECO for a reduced 31 level of firm transportation capacity and a higher level of interruptible transportation 32 capacity for a term of five years. As will be explained below, the CECO firm capacity will 33 serve the Company’s CECO-Akron interconnection point in Tuscola County.
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1 2 Q. What operational modifications are planned by the Company in order to hold a 3 reduced level of firm CECO transportation capacity? 4 A. In order to hold a reduced level of firm CECO transportation capacity, the Company is 5 planning the following operational modifications: 6 1. Cease firm gas deliveries from the CECO-Overisel interconnection point in the 7 Company’s Holland service area. The CECO-Overisel firm gas deliveries will be 8 replaced with firm gas deliveries from a new interconnection point to be 9 constructed with ANR in Overisel Township, MI (also located in the Holland 10 service area). The new interconnection point will be known as the ANR-Rabbit 11 River interconnection point. 12 2. Cease firm gas deliveries from the CECO-New Haven interconnection point 13 located in the Company’s Port Huron service area and increase gas deliveries 14 from the Company’s Port Huron service area’s ANR-Muttonville and GLGTC- 15 Trumble Rd interconnection points. 16 3. Cease firm gas deliveries from the CECO-Three Rivers (Ferguson Rd) 17 interconnection point in the Company’s Three Rivers service area and increase 18 gas deliveries from the Company’s ANR-Three Rivers interconnection point. 19 20 Q. What operational and system modifications will be necessary by the Company in 21 order to cease firm gas deliveries to the CECO-Three Rivers interconnection 22 point? 23 A. In order to cease firm gas deliveries to the CECO-Three Rivers interconnection point the 24 Company will need to make an operating pressure adjustment and make adjustments to 25 the Company’s SCADA system pressure alarms settings for the Three Rivers distribution 26 system. The Company has made these changes on a trial basis in order to confirm the 27 predicted behavior of the Three Rivers distribution system over the upcoming winter 28 period. 29 30 Q. What operational and system modifications will be necessary by the Company in 31 order to cease firm gas deliveries to the CECO-New Haven interconnection point?
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1 A. Company witness Michael Clyne identifies the necessary operational and system 2 modifications being planned to cease firm deliveries to the CECO-New Haven 3 interconnection point. 4 5 Q. What operational and system modifications will be necessary by the Company in 6 order to cease firm gas deliveries to the CECO-Overisel interconnection point? 7 A. In order to cease firm gas deliveries to the CECO-Overisel interconnection point the 8 Company is planning to for a new interconnection point with ANR in Overisel Township, 9 MI. The new interconnection point, to be known as the ANR Rabbit River 10 interconnection, will include two taps into ANR’s parallel interstate transmission pipeline 11 system, manifold piping, gas measurement equipment, flow control equipment, pressure 12 control equipment, odorization equipment, and a tap into the Company’s 12” high 13 pressure Holland distribution system. The new interconnection point is planned to have 14 a design capacity of at least 60,000 Dth/d. 15 16 Q. Other than CECO and ANR, are there any alternative pipeline transportation 17 capacity providers capable of serving the Holland service area? 18 A. No. CECO and ANR are the only available pipeline transportation providers in the 19 Company’s Holland service area. 20 21 Q. Is it necessary for the Company to source winter supply for its Holland service 22 area from Overisel Township? 23 A. Yes. Overall supply for the Company’s Holland service area is supplemented during the 24 winter period by supply delivered from the Company’s 12” high pressure distribution 25 system. Operationally, the 12” high pressure distribution system requires supply during 26 the winter period to serve the demand requirements of the Company’s Holland service 27 area customers. The 12” high pressure distribution system is currently supplied by the 28 CECO-Overisel interconnection located in Overisel Township. Other than CECO and 29 ANR, there are no other nearby sources of supply to serve the Company’s 12” high 30 pressure distribution system. 31
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1 Q. What gas cost benefit will the Company’s customers realize through ceasing firm 2 gas deliveries to the CECO-Overisel, CECO-Three Rivers, and CECO-New Haven 3 interconnection points? 4 A. Construction of the ANR-Rabbit River interconnection point along other planned system 5 improvements described above, will enable the Company to reduce its firm winter CECO 6 transportation MDQ from 50,000 Dth/d to 7,200 Dth during the winter period and 7 eliminate the Company’s CECO summer period MDQ altogether. As shown in Exhibit A- 8 3, the annual demand cost for Company’s current CECO capacity and associated CECO 9 capacity is $3,692,826. Exhibit A-3 also shows an annual demand cost for the 10 Company’s planned CECO capacity and planned new associated CECO capacity of 11 $1,824,685 for the 2018-2019 GCR period. The planned CECO capacity and associated 12 capacity results in an annual demand cost savings of $1,868,141. Over a five-year 13 period, the total demand cost savings is $9,340,704. After netting the ANR-Rabbit River 14 facility demand cost from the five-year savings, the final demand cost savings is 15 estimated to be $2,410,704 over the five-year period. Over a ten year period, the 16 demand cost savings expected to be $11,571,407. 17 18 Q. Will the Company enter into a facilities agreement with ANR for the construction 19 of the ANR Rabbit River interconnection point? 20 A. Yes. The Company anticipates entering into a facilities agreement with ANR for 21 construction of the ANR Rabbit River interconnection point in late 2016 or early 2017. 22 23 Q. When is construction of the ANR Rabbit River interconnection point planned to 24 occur? 25 A. Construction of ANR Rabbit River interconnection point is planned to commence during 26 2018. The upstream portion of the interconnection facilities, to be owned by ANR, 27 will include pipeline taps, tapping valves, associated header and interconnection 28 piping, metering, flow control, and other miscellaneous equipment. 29 30 Q. What is the estimated cost associated with the construction of the planned ANR 31 Rabbit River interconnection?
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1 A. The total cost of ANR’s the upstream interconnection facilities is estimated to be 2 $6,930,000. This cost is based on the most recent cost estimate provided by ANR. 3 ANR will assess the total interconnection cost to the Company likely through a facility 4 demand charge payable by the Company during the April 2018 through March 2019 5 GCR period. 6 7 Q. Does the Company plan to recover the estimated $6,930,000 construction cost for 8 the ANR upstream interconnection facilities at Overisel from GCR and GCC 9 customers? 10 A. Yes. The Company plans to recover the cost for the ANR Rabbit River upstream 11 interconnection facilities through the Company’s GCR Balancing and Demand Charge. 12 13 Q. Why is the Company seeking to recover ANR Rabbit River upstream 14 interconnection facility cost for construction through the GCR Balancing and 15 Demand Charge? 16 A. The upstream facilities associated with the new interconnection will be owned by ANR. 17 Since the Company cannot capitalize facilities (plant) that it does not own, and because 18 the ANR-Rabbit River interconnection point is necessary for providing reliable natural 19 gas service to the Company’s Holland service area GCR and GCC customers, the cost 20 to reimburse ANR for its portion of the ANR Overisel upstream interconnection facilities 21 ($6,930,000) must be recovered through the Company’s rates as an incremental cost to 22 the Company’s Balancing and Demand Charge. 23 24 Q. How will ANR recover its construction costs for the Rabbit River interconnection 25 facilities? 26 A. The Company expects ANR will recover its construction costs of the upstream 27 interconnection facilities as a facility demand charge payable by the Company during the 28 April 2018 through March 2019 GCR period. 29 30 31 Q. What incremental cost will be added to the Company’s Balancing and Demand 32 Charge as a result of ANR’sfacility demand charge of $6,930,000 for the 2018-2019 33 GCR period?
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1 A. The incremental amount added to the Company’s Balancing and Demand Charge is 2 estimated at $0.0168 per Therm ($6,930,000 ÷ 41,303,813 Dth ÷ 10 Therms/Dth) or 3 $16.10 ($0.0168 x 960 Therms) for each GCR and GCC customer over the 2018-2019 4 GCR period. The Company acknowledges that while this expense relates to the 2018- 5 2019 GCR plan period, it is part of the 5-year forecast subject to review in this 6 proceeding. 7 8 Q. Does the Company anticipate a true-up of the estimated construction costs to 9 actual costs? 10 A. Yes. The cost for the ANR Rabbit River upstream interconnection facilities will be 11 subject to a true-up once the final actual costs for construction are known. 12 13 Q. If the Company is able to implement the necessary operational and system 14 modifications to cease taking firm gas deliveries at the CECO-Overisel, CECO- 15 New Haven, and CECO-Three Rivers interconnection points, does the Company 16 plan to hold interruptible CECO pipeline transportation capacity to these 17 interconnections? 18 A. Yes. In order to provide an alternative source of gas deliveries for reliability purposes, 19 the Company plans to negotiate with CECO for an appropriate level of interruptible 20 CECO pipeline transportation capacity to the Company’s CECO-Overisel, CECO-New 21 Haven and the CECO-Three Rivers interconnections. 22 23 Q. What are the Company’s capacity contracting plans for the CECO-Akron 24 interconnection point located in Tuscola County? 25 A. Given the location of the Company’s CECO Akron interconnection point, there are not 26 any nearby alternative pipeline transportation providers other than CECO. As such, the 27 Company plans to contract with CECO for firm pipeline transportation capacity of at least 28 7,200 Dth/d beginning May 1, 2018, for the following winter period. Given recent interest 29 and potential for new agricultural load developing in the Michigan thumb area, the 30 Company may increase the physical capacity of the CECO-Akron interconnection facility 31 and contract with CECO for an equivalent quantity of transportation capacity. 32
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1 DTE Gas Company 2 Q. Please explain the Company’sDTE intrastate pipeline transportation agreement. 3 For the 2017-2018 GCR period, DTE will provide the Company with firm winter (Nov- 4 Mar) and interruptible summer (Apr-Oct) intrastate pipeline transportation capacity from 5 the DTE receipt point at Willow Run (ANR) for a total of 20,000 Dth/Day of intrastate 6 pipeline transportation capacity to the Company’s SEMCO/DTE Ray 17 delivery point. 7 The agreement will provide the Company with sufficient supply for the winter period to 8 serve the western portion of its Port Huron service area. This agreement expires on 9 March 31, 2017, and the Company plans to renew it for another winter term effective 10 November 1, 2017. 11 12 Q. Please describe the purpose of the DTE firm intrastate pipeline transportation 13 agreement. 14 A. As described above, the DTE firm intrastate pipeline transportation agreement provides 15 the western portion of the Company’s Port Huron service area with supply sourced from 16 ANR. During the summer period, the Port Huron service area’s integrated distribution 17 system has the capacity to supply all portions of the Port Huron service area. During the 18 winter period, and occasionally during October and April, the western portion of the Port 19 Huron service area requires an additional source of supply to meet system demand 20 requirements. The Company’s DTE interconnection located in Section 17 of Ray 21 Township in Macomb County provides additional winter period supply for this area. The 22 Company has no other economical source of pipeline transportation service for this area. 23 24 Jackson Pipeline Company 25 Q. Please describe and explain the purpose of the Company’s firm JPL intrastate 26 pipeline transportation capacity agreement. 27 A. The Company uses the JPL agreement to transport gas to and from ERGSS on a firm 28 basis. During the winter period, JPL provides the Company with firm intrastate pipeline 29 capacity for ERGSS storage withdrawals of gas for delivery to ANR, CECO, or PEPL 30 and then redelivered to the Company’s Port Huron, Central, Niles, and Holland service 31 areas. During the summer period, JPL provides the Company with firm intrastate 32 pipeline capacity for ERGSS storage injections of gas received from ANR or PEPL. The
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1 Company can utilize a winter MDQ of 66,665 Dth/d and a summer MDQ of 36,653 Dth/d 2 under this capacity agreement. The renewal date for this contract is March 31, 2018. 3 4 Q. Please explain how gas is transported from JPL and delivered to the Company’s 5 Lower Peninsula service areas. 6 A. During the winter season, the Company withdraws gas from ERGSS and delivers gas to 7 JPL and ERPL. For gas delivered to JPL, the Company has the option to make 8 deliveries to CECO at Fowler Road and/or ANR at Hanover on a firm basis, or to PEPL 9 at Mathews Road on a secondary-firm basis. When deliveries are made to CECO, the 10 Company uses its firm CECO intrastate transportation capacity for redeliveries to the 11 Company’s Akron, Ferguson Rd, Overisel, and/or New Haven gate stations servicing the 12 Port Huron, Niles, and Holland service areas. When deliveries are made to ANR, the 13 Company uses its ANR-Hanover interstate transportation agreement (having a winter 14 capacity of 40,255 Dth/d) for transportation from the JPL/Hanover receipt point to the 15 Company’s ANR group delivery point for redeliveries to the Company’s Lower Peninsula 16 service areas. 17 18 Q. Will the Company renew the JPL pipeline capacity prior to its expiration on March 19 31, 2018? 20 A. Yes. Since JPL pipeline capacity is essential to the Company’s ERGSS storage service, 21 the Company plans to negotiate for the renewal of the JPL capacity for a term that is 22 equivalent to the renewal term of the ERGSS storage service. 23 24 Eaton Rapids Pipeline 25 Q. Please describe and explain the purpose of the Company’sfirm intrastate pipeline 26 transportation capacity agreement with ERPL. 27 A. The ERPL intrastate pipeline transportation service provides the Company’s Central 28 service area with firm intrastate pipeline transportation capacity of 13,245 Dth/d from 29 ERGSS during the winter period and Vector Pipeline during the summer period. The 30 agreement includes evergreen language allowing the contract to continue until 31 terminated. 32 33 Q. When did Vector Pipeline become a supply receipt into ERPL?
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1 A. During 2016, a large ERPL shipper contracted with Vector Pipeline for the construction 2 of a new interconnection point into ERPL in order to serve a large expansion project. 3 Construction of the ERPL-Vector interconnection was completed in December 2016. 4 5 Q. Will the Company have access to the new ERPL-Vector Pipeline interconnection 6 point to serve its ERPL summer period demand? 7 A. Yes. 8 9 Q. Will the Company hold transportation capacity on Vector Pipeline for its summer 10 period demand served via ERPL? 11 A. No. The Company will purchase supply delivered to the new ERPL-Vector Pipeline 12 interconnection point for its summer period demand. 13 14 Q. What benefits are provided by the ERPL firm intrastate pipeline transportation 15 service? 16 A. The ERPL transportation service provides the Company with firm intrastate pipeline 17 transportation service for withdrawals from the ERGSS storage field to the Company’s 18 Central service area during the winter period and will provide pipeline transportation from 19 Vector Pipeline during the summer period. ERPL serves several of the Company’s 20 interconnection points including the Brookfield interconnection point, City of Albion 21 interconnection point, Battle Creek interconnection point, and a new interconnection 22 point in Marengo Township. In addition to average day winter period and summer period 23 supply, ERPL is critical to providing Design Day supply to the Company’s Central service 24 area. 25 26 Q. From a supply and reliability perspective, is ERPL also important for serving the 27 Company’sagricultural demand in the Albion service area? 28 A. Yes. During the fall period, the ERPL interconnection points are also critical to providing 29 adequate supply and system reliability for the large demand requirements of the 30 Company’s Albion area agricultural customers. 31 32 Greenwood Pipeline
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1 Q. Please describe and explain the purpose of the Company’s GWPL firm 2 transportation agreement. 3 A. The GWPL agreement provides a portion of the Company’s Port Huron service area with 4 firm transportation to move gas from the ANR/SEMCO South Greenwood 5 interconnection to the Company’s Avoca and Kilgore regulator stations at an MDQ of 6 12,000 Dth/d. This firm capacity does not augment the Company’s other firm 7 transportation agreements that assist in serving demand on a Design Day. Rather, it 8 provides a means to transport gas delivered on ANR to the northern portion of the 9 Company’s Port Huron service area. Specifically, this capacity is used to serve the 10 community of Avoca and the Company’s 400 psig high-pressure distribution system 11 located in the northern portion of the Company’s Port Huron service area during the 12 winter period. The agreement includes evergreen language allowing the contract to 13 continue until terminated. 14 15 Storage Assets 16 On-System Storage 17 Q. Please describe the Company’sowned on-system storage facilities. 18 A. The Company owns and operates four underground on-system storage facilities. Two 19 facilities directly serve the Port Huron service area and two facilities directly serve the 20 Battle Creek distribution system within the Company’s Central service area. The total 21 working capacity for all of the Company’s on-system storage facilities is approximately 22 4.877 MMDth. 23 24 Off-System Storage 25 Q. Please describe the Company’sleased off-system storage capacity. 26 A. Referring to Exhibit A-2, the Company has five leased off-system storage capacity 27 contracts. The storage contracts include capacity held with ANR, ANRSC, ERGSS, 28 NNG, and BWGS. The NNG storage service is used to serve the Company’s UP West 29 service area. The other four storage services are used to serve the Company’s Port 30 Huron, Central, Niles, Three Rivers, Holland, and UP East service areas. The total 31 contracted capacity for all of the Company’s off-system storage services is 32 approximately 11.534 MMDth. 33
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1 Q. What benefits are provided by the Company’soff-system storage services? 2 A. The benefits provided by the Company’s off-system storage services include: 3 Providing winter period fixed priced supply and deliverability for the Company’s 4 Upper and Lower Peninsula service areas. 5 Assisting the Company with balancing daily and monthly supply and demand. 6 Assisting the Company in serving its forecasted Design Day demand. 7 Mitigating the need for incremental flowing city gate peaking services. 8 Minimizing the need for incremental interstate pipeline capacity. 9 Increasing the flexibility of the Company’s ANR group balancing point. 10 Providing supply for Colder-than-Normal (“CTN”) weather. 11 Providing a level of supply security and supply reliability. 12 Allowing the Company to provide its EUT and GCC customers with a level of firm 13 and interruptible balancing service through the Company’s associated no-notice 14 service (ANR) and system management service (NNG). 15 16 Eaton Rapids Gas Storage System 17 Q. Please describe and explain the purpose of the Company’s storage service 18 contract with ERGSS. 19 A. The Company leases 6.5 MMDth of storage capacity from ERGSS. This storage service 20 is seasonal and ratcheted in character. The maximum daily injection and withdrawal 21 quantities under this service (subject to seasonal ratchets) are 36,111 Dth/d and 67,000 22 Dth/d, respectively. The renewal date for this service is April 1, 2018. 23 24 Q. What benefits does the ERGSS storage service provide to the Company? 25 A. ERGSS provides the Company with a reliable source of winter supply strategically 26 located within Michigan enabling the Company to deliver supply to all of its service areas 27 in the Lower Peninsula. With the ERGSS storage service, the Company has the 28 flexibility to deliver gas via JPL to all of its ANR, PEPL, and CECO delivery points. The 29 Company also has the flexibility to deliver ERGSS gas via ERPL to its Battle Creek and 30 Albion service areas. For injections into ERGSS, the Company has the flexibility to take 31 gas into ERGSS from various supply regions, via JPL and the Company’s ANR receipt 32 points, via JPL and the Company’s PEPL receipt points, or via city gate gas purchased
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1 directly into JPL. Finally, the ERGSS storage service allows the Company to make 2 interruptible injection and withdrawal overruns (when authorized) at no cost. 3 4 Q. The ERGSS storage service expires on March 31, 2018. Does the Company plan 5 to renew this storage service? 6 A. Yes. The Company plans to renew the ERGSS storage agreement during 2017 for 7 another term beginning April 1, 2018. 8 9 ANR Pipeline Storage 10 Q. Please describe and explain the purpose of the Company’s 2.5 MMDth ANR 11 storage capacity service. 12 A. The Company’s ANR 2.5 MMDth storage service is annual and unratcheted in character. 13 The maximum daily injection quantity is approximately 12,500 Dth/d and the maximum 14 daily withdrawal quantity is approximately 50,000 Dth/d, unadjusted annually for fuel. 15 The renewal date for this service is April 1, 2018. 16 17 Q. Please describe and explain the purpose of the Company’s ANR No-Notice 18 agreement and how it is related to the Company’sANR storage service. 19 A. The Company’s ANR No-Notice service is a non-nominated balancing service that 20 moves gas in and out of the Company’s ANR storage service. This agreement allows 21 the Company to allocate certain imbalance quantities associated with nominated gas for 22 transportation on its ANR capacity (on a firm basis) to and from the Company’s ANR 23 storage service. Through this agreement, the Company is allowed a no-notice daily 24 nomination variance of 2,500 Dth/Day. This service provides the Company with a level 25 of supply flexibility to manage unforeseeable and unexpected variations in daily demand 26 of the Company’s GCR, GCC, and EUT customers. 27 28 Q. The ANR storage service and no-notice service expires on March 31, 2017. Did 29 the Company renew these services? 30 A. Yes. The Company renewed the ANR storage service and no-notice for a term of 4 31 years beginning April 1, 2017. The Company was able to negotiate a $932,844 (18%) 32 annual cost reduction from ANR’s approved tariff rates for the Company’s new ANR
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1 contract portfolio. Over the term of the agreement, the savings will amount to 2 $3,731,376. 3 4 Northern Natural Gas 5 Q. Describe the Company’sNNG storage service. 6 A. The Company leases approximately 1.0 MMDth of Firm Deferred Delivery Service 7 (“FDD”) from NNG. The maximum summer period injection quantity is 11,005 Dth/d and 8 the maximum winter period withdrawal quantity is 17,344 Dth/d. This storage service is 9 seasonal and ratcheted in character. There are two renewal dates for NNG FDD 10 storage service. The renewal date for the Company’s NNG FDD capacity of 614,113 11 Dth with grandfathered rollover rights is June 1, 2019, and the renewal date for the 12 Company’s NNG FDD capacity of 385,887 Dth with ROFR privileges is June 1, 2018. 13 14 Q. Are daily no-notice load swings accomplished through the NNG FDD service? 15 A. No. While intra-day nominations may be, and have been, made with regard to the FDD 16 service to assist in daily balancing, the majority of daily balancing on NNG is provided 17 through the use of NNG’s System Management Service (“SMS”). SMS allows the 18 Company to vary its demand on any given day by up to 6,000 Dth/d over or under its 19 daily nomination. 20 21 Q. A quantity (385,887 Dth) of the NNG storage service expires on May 31, 2018. 22 Does the Company plan to renew this quantity of the NNG storage service? 23 A. Yes. The Company plans to renew 387,887 Dth of the NNG storage agreement during 24 2017 for another term beginning June 1, 2018. 25 26 Bluewater Gas Storage 27 Q. Please describe and explain the purpose of the Company’s1.0 MMDth BWGS gas 28 storage service. 29 A. The Company’s 1.0 MMDth BWGS gas storage service is a 50-day storage service 30 having a maximum daily injection capacity of 5,000 Dth/d, a maximum daily withdrawal 31 capacity of 20,000 Dth/d, and is seasonal and ratcheted in character. 32 33 Q. How does the Company plan to utilize the BWGS gas storage service?
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1 A. The Company plans to use BWGS gas storage as necessary to provide base load 2 supply deliverability along with incremental deliverability on Design Days and on CTN 3 winter days over the entire winter period. The Company will attempt to make the base 4 load withdrawals from BWGS over the January through March period, weather 5 permitting. 6 7 Q. How will gas withdrawn from BWGS be delivered to the Company? 8 A. Gas withdrawn from BWGS will be delivered to the Company’s Port Huron Service area 9 via GLGTC having a receipt point at Rattle Run (BWGS) and a delivery point at Trumble 10 Rd (the Company’s GLGTC interconnection point). 11 12 Q. Does the BWGS storage service provide the Company with necessary Design Day 13 deliverability requirements? 14 A. Yes. Exhibit A-8 shows the Company utilizing 100% of its currently available Lower 15 Peninsula interstate pipeline transportation capacity and storage deliverability assets, 16 including deliverability of approximately 20,000 Dth provided by the BWGS storage 17 service. 18 19 Q. The BWGS storage service is scheduled for renewal on April 1, 2017. Did the 20 Company renew this service? 21 A. Yes. The Company issued a request for proposal for this service during the fall of 2016 22 whereby other storage service providers submitted bids. BWGS provided the most 23 competitive proposal and was awarded a contract for a 5 year renewal. The new 24 renewal date is April 1, 2022. 25 26 ANR Storage Company Storage 27 Q. Please describe the Company’s 530,000 Dth ANRSC 10-day peaking gas storage 28 service. 29 A. The ANRSC storage service provides an annual storage quantity of 530,000 Dth having 30 a maximum daily injection capacity of approximately 4,100 Dth/d and a maximum daily 31 withdrawal capacity of approximately 53,000 Dth/d. This storage service is annual and 32 ratcheted in character. 33
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1 Q. Please explain the purpose of the Company’s ANRSC 10-day peaking gas storage 2 service. 3 A. The purpose of the ANRSC storage capacity is to provide the Company with 10 days of 4 high delivery peak day supply in order to assist the Company in meeting its demand 5 requirements on Design Days or during periods of CTN weather. 6 7 Q. How will gas withdrawn from the ANRSC 10-day peaking gas storage service be 8 delivered to the Company’ssystem? 9 A. Gas withdrawn from the ANRSC peaking gas storage service will be delivered to the 10 Company via interstate pipeline capacity from GLGCT. 11 12 Q. Does the ANRSC 10-day storage service provide the Company with necessary 13 Design Day deliverability requirements? 14 A. During February, when Design Day demand is high relative to the Company’s available 15 deliverability from storage, Exhibit A-8 shows the Company utilizing 100% of its currently 16 available Lower Peninsula interstate pipeline transportation capacity and storage 17 deliverability assets, including deliverability of approximately 53,000 Dth provided by the 18 ANRSC 10-day peaking storage service. 19 20 Q. Why does the Company prefer to serve the necessary Design Day deliverability 21 requirements through a peaking storage service? 22 A. The Company prefers to serve its incremental Design Day capacity requirements with a 23 peaking storage service because it provides superior benefits over interstate pipeline 24 supply. In the Company’s view, the greatest benefit provided by a peaking storage 25 service is secure, reliable, and low cost deliverability on a Design Day compared to the 26 deliverability provided by interstate pipeline supply delivered to the Company’s pipeline 27 distribution systems. A peaking storage service provides supply security and reliability 28 because gas will be stored in Michigan and readily available for withdrawal on short 29 notice. In addition, gas residing in a peaking storage service will be injected during the 30 summer period and typically valued at lower summer prices thus avoiding premium- 31 priced winter daily spot prices as typically associated with extreme weather conditions 32 on Design Day. 33
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1 Operational Constraints 2 Q. Do all of the Company’s interstate and intrastate pipeline transportation capacity 3 providers, off-system storage providers, and the Company’s on-system storage 4 reservoirs (supply assets) serve all of the Company’sservice areas? 5 A. No. As shown in Exhibit A-4, not all of the Company’s supply assets serve all of the 6 Company’s service areas. 7 8 Q. What operational constraints affect the Company’sability to purchase and deliver 9 gas for its UP West service area? 10 A. Supply is delivered to the Company’s UP West service area solely through NNG’s Upper 11 Peninsula pipeline system. The Company currently has no other physical sources of 12 interstate pipeline transportation available to its UP West service area. As a result, the 13 Company’s customer demand in this service area must be served entirely through 14 NNG’s pipeline system. 15 16 Q. From a supply perspective, please state the Company’sconcerns with NNG being 17 its sole pipeline transportation provider of supply. 18 A. From a supply perspective, the Company has four concerns with NNG being its sole 19 pipeline transportation provider for supply to the Company’s UP West distribution 20 systems. These concerns include: (1) supply deliverability, (2) supply reliability, (3) 21 supply redundancy, and (4) supply diversity. 22 23 Q. Please explain why NNG’spipeline system presents a supply deliverability 24 concern to the Company. 25 A. NNG’s UP pipeline system presents a supply deliverability concern to the Company 26 because NNG’s Ontonagon, Lake Linden, and Marquette laterals do not have any 27 available unsubscribed capacity for supply deliverability. This situation is a concern 28 because the Company is forecasted to operate at a 92% load factor for its NNG 29 contracted capacity on a Design Day leaving limited opportunities for the Company to 30 address future customer/requirement growth. As a result of NNG’s capacity constraint, 31 the Company implemented Controlled Sales Service rules in 2009. The implementation 32 of these rules means that under Rule C2 of its Rate Book for Natural Gas Service, 33 priorities 4, 5 and 6 (generally, any commercial and industrial customer having a peak
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1 usage of 50 Dth/Day or more) are closed to new gas sales service applications received 2 on or after January 22, 2009 if the Company cannot accommodate such new loads. 3 4 Q. Please explain why NNG’sUP pipeline system presents a supply reliability and 5 supply redundancy concern to the Company. 6 A. Since NNG’s UP pipeline system is not looped or back-fed though any primary-firm 7 supply receipt points in Michigan, NNG’s UP pipeline system does not feature a level of 8 reliability necessary for the dependable delivery of supply. Such a lack of dependability 9 presents a supply reliability and supply redundancy concern for the Company and its 10 customers due to the risk of a sudden loss of supply from NNG. Specifically, in the 11 event of an upstream interruption of NNG’s UP pipeline system anyplace west of any of 12 the Company’s UP West distribution systems, all of the Company’s 34,000 UP West 13 customers would be at risk of a sudden loss of supply resulting in a mass outage. If 14 such an interruption occurred during the winter period, such a mass outage would likely 15 be a catastrophic event leaving the Company and its UP West customers without any 16 supply options for space heating, hot water, cooking, manufacturing, or power 17 generation. Since one of the highest risks of pipeline failure is due to third party 18 damage, such a risk presents a serious supply reliability concern to the Company since 19 NNG’s UP pipeline system is not looped or back-fed though a primary-firm supply receipt 20 points in Michigan. 21 22 Q. Please explain why the Company’ssole dependence upon NNG’sUP pipeline 23 system presents a supply diversity concern to the Company? 24 A. Supply diversity is important from a purchasing perspective because it provides the 25 Company with the opportunity to acquire supply from a variety of supply producers and 26 marketers at a variety of supply hubs and basins in order to optimize and capture the 27 best gas commodity value. The Company’s sole dependence on NNG’s UP pipeline 28 system presents a supply diversity concern because it currently limits the Company to 29 acquiring supply from only those producers and marketers who do business at supply 30 receipt points into NNG’s interstate pipeline system and it limits the Company to source 31 supply from only those supply hubs and supply basins that feed NNG’s interstate 32 pipeline system. Such limitations do not afford the Company the opportunity to optimize 33 and capture the best gas commodity value.
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1 2 Q. Does the Company have a plan to mitigate its supply deliverability, reliability, 3 redundancy, and diversity concerns? 4 A. Yes. In December 2016, the Company filed for authorization certificate of public 5 convenience and necessity in Case No. U-18202 to construct the Marquette Connector 6 Pipeline (“MCP”). In order to increase supply deliverability, improve reliability, create 7 system redundancy, and provide additional supply diversity the Company is proposing to 8 construct 42.6 miles of pipeline from GLGTC’s interstate pipeline near Arnold, Michigan 9 to the Company’s Marquette distribution system and NNG’s pipeline near Marquette, 10 Michigan. The pipeline will consist of two segments. The first segment will consist of 11 36.2 miles of pipeline between GLGTC’s interstate pipelines to NNG’s pipeline near 12 Marquette, Michigan, allowing NNG’s and GLGTC’s pipelines to be connected. Upon 13 certification and construction of the MCP, NNG and GLGTC will, respectively, construct 14 interconnections to the MCP. The second segment will consist of 6.4 miles of pipeline 15 from segment one into SEMCO Gas’s Marquette distribution system. The pipeline will 16 connect in the Marquette area with NNG’s pipeline and will allow the NNG UP 17 transmission system to effectively flow in a westerly direction. 18 19 Q. How does the Company plan to recover the cost of the new interconnection 20 facilities to be constructed between GLGTC and the MCP and NNG and the MCP? 21 A. The Company plans to recover the cost of the new interconnection facilities via the 22 Company’s GCR Balancing and Demand Charge beginning with the 2019-2020 GCR 23 period. The interconnection costs are, of course, separate from the capital costs to be 24 incurred by the Company in the construction of the MCP which will be recovered through 25 SEMCO Gas’s base rates in its next general rate case. 26 27 Q. Why is the Company seeking to recover the cost of the MCP interconnection 28 facilities through the Company’sGCR Balancing and Demand Charge? 29 A. The receiving MCP interconnection facility will be owned and operated by GLCTC and 30 the delivering MCP interconnection facility will be owned and operated by NNG. Since 31 neither of the MCP interconnection facilities will be owned by the Company and since 32 the Company cannot capitalize plant that it does not own, the cost to reimburse GLGTC
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1 and NNG for the MCP interconnection facilities will be recovered through the Company’s 2 GCR rates as an incremental cost to the Balancing and Demand Charge. 3 4 Q. Please describe how the MCP will increase deliverability, improve reliability, 5 create system redundancy, and provide additional supply diversity of natural 6 supply to the Company’sUP West gas distribution systems. 7 A. As more fully described in Case No. U-18202, the MCP will effectively create a loop of 8 NNG’s UP pipeline system allowing supply to back-feed into NNG’s pipeline system near 9 Marquette, MI. The MCP will create a new receipt point into NNG’s pipeline system and 10 create a new receipt point into the Company’s Marquette distribution system thus 11 allowing for increased deliverability, improved reliability, create system redundancy, and 12 provide additional diversity of natural supply to the Company’s UP West gas distribution 13 systems. 14 15 Q. If construction of the MCP is authorized by the Commission, when does the 16 Company anticipate placing the MCP into service? 17 A. The Company anticipates placing the MCP into service during mid-2020. 18 19 Q. Are there any operational constraints that affect the Company’s ability to 20 purchase and deliver gas to the Company’sUP East service area? 21 A. Yes. Supply is delivered to the Company’s UP East service area solely through 22 GLGTC’s interstate pipeline transportation network. The Company currently has no 23 other physical sources of interstate pipeline transportation available to its UP East 24 service area. As a result, the Company’s customer demand in this service area must be 25 served entirely through GLGTC’s pipeline transmission network. 26 27 Q. Is the Company concerned about the available capacity of GLGTC’s upstream 28 interstate pipeline system? 29 A. Not at this time. GLGTC has substantial upstream pipeline capacity to serve the 30 Company’s current and future GCR and GCC Design Day requirements, GLGTC’s 31 pipeline system is completely looped, can be supplied from multiple receipt points, and 32 can flow in either direction. 33
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1 Q. Since the Company does not have storage assets to manage supply challenges 2 such as balancing daily demand variations, CTN weather demand, and peak day 3 demand in the Company’s UP East service area, how does the Company provide 4 incremental supply when it is needed? 5 A. To manage these challenges, the Company displaces gas being shipped on its GLGTC 6 pipeline transportation capacity from the Port Huron service area to the UP East service 7 area delivery points. The gas being displaced from the Port Huron service area is 8 replaced with storage supply, other flowing pipeline supply, or Peaking Supply. 9 10 Q. The Company’s contracted NNG storage deliverability limits its ability to manage 11 late winter CTN weather demand and completely manage peak day demand in the 12 Company’s UP West service area. How does the Company provide incremental 13 supply to the UP West service area when it is needed? 14 A. Similar to the UP East, to manage these supply challenges in the UP West, the 15 Company displaces gas being shipped on its GLGTC pipeline transportation capacity 16 from the Port Huron service area to the GLGTC/NNG Carlton delivery point for redelivery 17 to the Company’s UP West service area’s NNG delivery points. The gas being 18 displaced from the Port Huron service area is replaced with other flowing pipeline 19 supply, storage supply, or Peaking Supply. 20 21 Q. Are there any operational constraints that affect the Company’s ability to 22 purchase and deliver gas to the Company’sPort Huron, Niles, and Holland service 23 areas? 24 A. Yes. For the Company’s Port Huron, Niles, and Holland service areas, sufficient 25 quantities of supply are currently necessary at specific locations within these service 26 areas. In order to deliver gas to these specific locations, the Company arranges for 27 delivery of gas to the Company’s CECO receipt points. This gas is then transported 28 across the CECO system and finally redelivered to the Company’s CECO delivery points 29 at Akron, Ferguson Rd, New Haven, and Overisel. As discussed above, after April 30, 30 2018, the Company will only need firm CECO transportation to the CECO-Akron 31 interconnection point. For the western portion of the Company’s Port Huron service 32 area, sufficient quantities of supply are maintained by delivering gas to the SEMCO/DTE 33 delivery point in Ray Township. Lastly, sufficient quantities of supply are maintained in
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1 the thumb region of the Company’s Port Huron service area by gas received from ANR, 2 transported on the GWPL, and redelivered to the SEMCO/Greenwood Kilgore delivery 3 point in Greenwood Township. 4 5 Q. Are there any operational constraints that affect the Company’s ability to deliver 6 on-system storage gas to the Company’sCentral service area? 7 A. Yes. The Battle Creek high pressure transmission system pipeline delivers gas from the 8 Company’s on-system storage facilities and ERGSS to the Battle Creek service area’s 9 high pressure distribution system. This pipeline is limited to a maximum experienced 10 capacity of 29,000 Dth/d. As a result, for planning purposes, the Company assumes 11 29,000 Dth is the maximum amount of storage supply that can be delivered from its 12 storage assets to the Central service area via the Battle Creek high pressure 13 transmission system on a peak day. 14 15 Federal and Non-Michigan Regulatory Activity 16 Q. How does the Company participate in the various federal and other non-Michigan 17 regulatory proceedings in which it becomes involved? 18 A. The Company is an active intervenor and participant in FERC and other non-Michigan 19 regulatory proceedings that may impact the type or cost of service the Company 20 contracts for on behalf of its customers. As issues and proceedings of interest arise, the 21 Company participates as either an individual or as a group member. The Company 22 continues to primarily utilize its own Washington, DC counsel to monitor and participate 23 in federal rate and regulatory matters of interest. The Company also participates in 24 American Gas Association (“AGA”) discussions of FERC and U.S. Commodity Futures 25 Trading Commission (“CFTC”) issues and through its membership in AGA, participates 26 in AGA filings of comments and briefs in FERC Notice of Proposed Rulemakings and 27 other federal energy forums. 28 29 Q. What else has the Company specifically done on the legal and regulatory front to 30 ensure supply reliability and minimize the cost of gas? 31 A. The Company intervenes in and monitors the progress and activities in most routine 32 pipeline filings for those pipelines with which the Company has capacity contracts and 33 generic cases such as FERC and other non-Michigan regulatory agencies in order to
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1 preserve the Company’s rights. If these cases take unexpected turns or become 2 adverse to the interest of the Company and its customers, the Company will take any 3 necessary actions to address these issues. For example, the Company actively 4 intervened in ANR’s and ANRSC’s 2016 FERC Section 4 rate proceedings. However, 5 since the Company is typically not a large player in terms of size or influence in the 6 federal arena, the Company must pick its objectives and tactics with care. 7 8 Q. Please discuss Exhibit A-5. 9 A. Exhibit A-5 shows a table of the recent FERC cases in which the Company has 10 intervened with descriptions of activities, events that have taken place and issues the 11 Company monitors within those cases. 12 13 Q. Are the Company’sfederal and non-Michigan regulatory actions reasonable and 14 prudent? 15 A. Yes. The Company has taken all reasonable actions at FERC and other regulatory 16 agencies to hold down the costs of gas and otherwise protect the interests of the 17 Company and its customers. 18 19 Storage Utilization Plan 20 Q. What are the key functions of the Company’sgas storage assets? 21 A. As stated earlier, the Company’s storage assets are critically important for balancing its 22 customers’ daily supply and demand, mitigating higher and more volatile winter supply 23 purchases with typically lower priced supply purchased during the prior summer, 24 providing supply for CTN weather, providing supply deliverability for demand on an 25 Design Day, and providing a level of supply reliability. 26 27 Q. Please describe how the Company will manage its storage assets for the 2017- 28 2018 GCR period, assuming normal weather. 29 A. Please refer to Exhibit A-6. This exhibit summarizes the Company’s on-system and off- 30 system storage utilization plan for the 2017-2018 GCR period. For this period, assuming 31 normal weather, the Company plans to inject approximately 13.882 MMDth of gas during 32 the summer period and withdraw approximately 13.882 MMDth of gas during the winter 33 period. Note that these quantities will vary due to colder-than-normal weather, warmer-
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1 than-normal weather, fluctuations in hourly and daily demand, variations of monthly GCR 2 customer demand, GCC participation, and migration of EUT customers. 3 4 Q. Under this storage plan, what percent of winter demand will be supplied from 5 storage? 6 A. Approximately 50% of the 2017-2018 normal weather winter demand will be supplied 7 from storage, resulting in a reliable source of fixed priced supply. 8 9 Q. How will the Company monitor and replace storage inventory to counter the 10 effects of CTN weather? 11 A. The Company plans to maintain 285,000 Dth of CTN weather protection for the month of 12 December and 570,000 Dth of CTN weather protection for January and February in its 13 storage inventory. During these months, the Company plans to monitor the monthly 14 storage inventory and the storage deliverability for all of its storage assets, and, if any of 15 the CTN weather supply in storage has been used, the Company will attempt to replace 16 the inventory during the following month by increasing planned monthly purchases to 17 allow the CTN weather storage supply to be replenished for the following month. For 18 example, if in December 100,000 Dth of the CTN weather protection is used, the 19 planned monthly withdrawals from storage may be reduced in January by 100,000 Dth 20 and planned purchases may be increased by 100,000 Dth. 21 22 Q. How does the Company plan to manage the CTN weather storage quantity that 23 has not been used during the December through February period? 24 A. The Company will plan its March storage withdrawals and monthly purchases to allow 25 the remaining CTN weather storage volumes to be depleted by the end of March 26 assuming the actual experienced weather for March allows for such withdrawals. 27 28 Q. In the event of warmer-than-normal (“WTN” ) winter weather, how will the 29 Company adjust its storage withdrawal plan? 30 A. If the Company experiences WTN weather, the Company will evaluate the level of its 31 storage inventory, storage deliverability, and the level of its monthly flowing supply 32 requirements for the next month. If the Company believes it is reasonable to do so, it 33 may reduce the monthly supply purchases and increase storage withdrawals over the
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1 remaining future winter month(s) of the plan period while maintaining the necessary 2 storage deliverability and flowing supply requirements to meet the Company’s forecasted 3 Design Day demand. For example, if December weather is WTN, January purchases 4 may be decreased and storage withdrawals increased if storage deliverability will allow 5 the Company to meet a Design Day for January and future winter months. 6 7 Q. Does the Company plan to make injections into storage during the November 8 through March winter period? 9 A. No. The Company does not plan to make winter injections into storage. However, it is 10 likely that winter storage injections may occur due to periods of WTN weather and the 11 necessity of balancing of the Company’s hourly and daily GCR supply, demand, EUT 12 customer activity, and GCC activity. 13 14 Supply Purchase Plan 15 Q. What is the Company’s average day supply purchase plan for the five-year period 16 beginning April 1, 2017? 17 A. The Company’s average day supply purchase plan for the five-year period beginning 18 April 1, 2017 is shown in Exhibit A-7. This exhibit provides a summary of the Company’s 19 forecasted monthly GCR customer demand for the 2017-2018 GCR period (including the 20 five-year forecast) assuming normal weather, as described in witness Jim Van Sickle’s 21 pre-filed direct testimony, and how that demand is planned to be served. For the 2017- 22 2018 GCR period, the Company plans to serve its GCR demand with gas supplied from 23 its storage assets, fixed price term purchases (if purchased by the Company), index 24 priced term purchases, and monthly spot purchases, consistent with the Company’s 25 available firm pipeline transportation capacities and available gas storage inventories. 26 27 Q. Could the Company’s supply plan change if its GCR demand, GCC participation, 28 EUT participation, or future natural gas market conditions change? 29 A. Yes. The Company’s supply plan, as described in this GCR Plan, reflects the 30 Company’s current forecasted GCR demand, existing level of GCC and EUT 31 participation, and present natural gas market conditions including but not limited to the 32 cost of gas. Should any of these variables change, the Company’s supply plan may be 33 revised to reflect the future GCR demand or future market conditions.
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1 2 Q. What is the Company’spurchasing strategy for its planned supply requirements? 3 A. Please refer to the pre-filed direct testimony of Witness Tamara L. Spencer for testimony 4 on this subject. 5 6 Asset Management 7 Q. Please explain the Asset Management Agreement (“AMA” ) to which the Company 8 and BP Canada Energy Marketing Corp. (“BP” ) are parties. 9 A. Under the AMA, the Company receives a share of any positive value created by BP 10 through supply commodity optimization activities involving the Company’s flowing 11 supply. All revenue received by the Company for capacity release and AMA activities is 12 credited to the cost of gas. 13 14 Q. Please explain optimization of flowing supply. 15 A. Supply optimization is a technique, performed here by a third party (BP), to create value 16 (when available in the natural gas marketplace) from Company-owned flowing supply 17 that’s being transported on its interstate pipeline capacity. Specifically, supply 18 commodity optimization value may be created through AMA transactions such as 19 utilization of alternative supply receipt points, alternative supply delivery points, or 20 alternative delivered supply. Alternative supply receipt point commodity optimization 21 value can sometimes be created through the sale of the Company’s supply at its original 22 receipt point and purchase of replacement supply at an alternative receipt point. 23 24 Q. Please explain why BP should receive a share of all positive values relating to 25 AMA activities. 26 A. It is important to understand the Company does not have the same capabilities as BP 27 has to create value from commodity optimization of flowing supply because the 28 Company is not in the gas trading business and does not sell gas into other markets on 29 a wholesale basis. In addition to traditional capacity release activities, commodity 30 optimization of flowing supply is another method to create value from the Company’s 31 flowing supply that would otherwise not be available to benefit the GCR customers if the 32 Company did not have the AMA agreement with BP. In the Company’s view, BP is 33 entitled to its share of the value it creates through commodity optimization because BP is
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1 performing all the work and taking on all the risk associated with AMA transactions. It is 2 also important to understand that value is created by BP taking on the risk that 3 commodity optimization values will be positive when such AMA transactions are 4 performed. 5 6 Q. How will the Company’sGCR customers benefit from the AMA? 7 A. The Company’s share of positive values captured by the AMA will benefit the Company’s 8 GCR customers through a reduction of the cost of gas. 9 10 Q. How much value did the AMA provided to the Company’sGCR customers over the 11 2015-2016 GCR period? 12 A. Over the 2015-2016 GCR period, the AMA resulted in commodity credits offsetting the 13 cost of gas by approximately $156,145. 14 15 Q. Can the Company estimate the annual revenue it expects to receive from AMA 16 supply optimization activities over the 2017-2018 GCR period? 17 A. No. The Company cannot estimate the annual revenue it expects to receive AMA 18 supply optimization activities because it is not possible to predict what future 19 optimization opportunities may or may not exist or the value associated with those 20 opportunities. 21 22 Q. Why is an AMA beneficial to the Company’sGCR customers? 23 A. The AMA is beneficial to the Company’s GCR customers because it directly reduces the 24 commodity cost of gas for the Company’s GCR customers. 25 26 Q. Please explain the Operational Agency Agreement (“OAA” ) to which the Company 27 and BP are parties. 28 A. Under the OAA, BP performs all administrative activities necessary to post the 29 Company’s available interstate pipeline capacity so the Company can ascertain and, as 30 appropriate, realize the market value of its available capacity for release. The postings 31 are made on the applicable interstate pipeline’s capacity release posting system. Using 32 that system, the interstate pipeline manages the bid and award process associated with 33 capacity that is available for release. When such capacity is released and acquired by
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1 other shippers, the Company receives 100% of any value obtained through the capacity 2 release process. That amount is credited to the Company’s fixed cost of gas. 3 4 Q. What value does the Company estimate to receive from capacity release activity 5 over the 2017-2018 GCR period? 6 A. The Company is estimating capacity release value of approximately $520,000 over the 7 2017-2018 GCR period. This value is based on the actual value attained for capacity 8 release through the twelve month GCR period ending March 31, 2016. 9 10 Design Day Supply Plan 11 Q. How is the Company’sDesign Day demand defined? 12 A. The Company’s Design Day demand is defined as the maximum forecasted natural gas 13 demand of both its GCR and GCC customers on the coldest experienced winter period 14 day over the past 15 years. 15 16 Q. What quantities is the Company estimating for its GCR and GCC Design Day 17 demand for the 2017-2018 winter GCR period? 18 A. Please see the pre-filed direct testimony of Witness Jennifer Dennis. 19 20 Q. What is the Company’s supply plan for serving its forecasted GCR and GCC 21 Design Day demand requirements during the months of January, February, and 22 March of 2017? 23 A. Please refer to Exhibit A-8. For CTN weather days (those days above a normal weather 24 day and up to the Company’s Design Day) the Company expects its forecasted GCR 25 and GCC Design Day demand will be served by supply provided under monthly 26 purchases and Peaking Supply purchases along with utilization of the Company’s on- 27 system and off-system storage deliverability assets. 28 29 Q. Please explain Peaking Supply purchases. 30 A. Peaking Supply purchases described in this GCR plan include supply that is purchased 31 into one or more of the Company’s interstate or intrastate pipeline receipt points for 32 redelivery into the Company’s pipeline transmission or distribution systems under colder- 33 than-normal weather conditions.
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1 2 Q. Will Peaking Supply purchases be transported to the Company’s city gate receipt 3 points on interstate or intrastate pipeline transportation capacity owned by the 4 Company? 5 A. Yes. Where the Company has interstate and intrastate pipeline capacity available, 6 Peaking Supply purchases will be transported on the Company’s firm interstate or 7 intrastate pipeline transportation capacity to the Company’s city gate receipt points. 8 9 Q. Please explain how Peaking Supply will likely be structured from a contractual 10 perspective. 11 A. The Company plans to acquire Peaking Supply that will feature an optional take 12 arrangement. Pricing for Peaking Supply will likely be structured to include a demand 13 cost component and a commodity cost component. The commodity cost component will 14 likely be priced at the then-effective natural gas spot market price. The Company will 15 only be charged the commodity cost component when it is necessary for the Company 16 to use the contracted Peaking Supply. 17 18 Q. Will the Company’s available interstate pipeline capacity be released into the 19 marketplace on days when Peaking Supply is not being called upon? 20 A. Yes. The Company’s available interstate pipeline capacity will be released into the 21 marketplace on a recallable basis such that the capacity can be used when needed to 22 transport Peaking Supply. 23 24 Q. Why does the Company’s Design Day supply plan have the Company contracting 25 for Design Day Peaking Supply? 26 A. The Company plans to contract for Design Day Peaking Supply because the Company 27 cannot guarantee Design Day Peaking Supply will be available, on short notice, in the 28 marketplace to meet its GCR and GCC demand requirements. The availability of such 29 supply for purchase in the market place is necessary in order to acquire the required 30 Design Day Peaking Supply. On a Design Day, the Company, other Michigan gas and 31 electric utilities, and large end users will likely all be in the market place at once seeking 32 to make daily spot purchases of gas. This sudden coincidence of buyers all seeking to 33 make daily spot purchases of gas could create an enormous level of demand for gas on
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1 the day. During such Design Days, gas for Design Day Peaking Supply may not be 2 available in the Michigan gas marketplace, on short notice, to meet its GCR and GCC 3 demand requirements. Furthermore, as a public utility, the Company must take 4 reasonable steps to serve its GCR and GCC customers, including arranging for 5 appropriate quantities of supply, upstream pipeline capacity, and storage deliverability. 6 Assuring perfect reliability is not possible, of course, because providing gas utility service 7 is dependent on systems designed and run by human beings and events beyond the 8 Company's control (such as the weather and conditions in production basins and on 9 interstate and intrastate pipelines). 10 11 Q. How much Peaking Supply does the Company plan to acquire for its forecasted 12 Design Day demand for the 2017-2018 winter period? 13 A. To serve the Company’s forecasted Design Day demand for the 2017-2018 winter 14 period, the Company will likely acquire maximum Design Day Peaking Supply of 15 approximately 78,000 Dth/Day for seven days or a maximum total quantity of 546,000 16 Dth. 17 18 Q. What does the Company expect with respect to the commodity cost of gas on a 19 Design Day compared to the cost of gas on non-Design Days during the winter? 20 A. Based on supply and demand fundamentals, the Company expects the commodity cost 21 of gas on a Design Day to be priced at a premium compared to the commodity cost of 22 gas on non-Design Days. History has repeatedly demonstrated that colder-than-normal 23 weather events typically result in premium prices of natural gas when compared to daily 24 spot market prices of natural gas on non-critical days. 25 26 Q. What are the Company’s total estimated demand costs for its planned Peaking 27 Supply for the 2017-2018 GCR period? 28 A. The Company’s total estimated demand costs for its planned Peaking Supply for the 29 2017-2018 GCR period are shown in Exhibit A-9. 30 31 Q. Does the Company’s forecasted Design Day demand also include demand for its 32 GCC customers?
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1 A. Yes. The Company’s forecasted Design Day demand includes demand for GCC 2 customers. The Company serves as the SOLR for these customers in the event 3 alternative gas suppliers are unable to deliver gas to the Company’s GCC customers at 4 any time, including CTN weather as well as Design Day weather. 5 6 Q. How was the Company’srole as the SOLR for its GCC customers established? 7 A. The Company’s role as the SOLR for GCC customers was established in Case No. U- 8 12550. Among others, the MPSC Staff, Michigan local distribution companies (“LDCs”), 9 and the Michigan Attorney General participated in that case. In Case No. U-12550, the 10 MPSC’s order adopted the “Staff Report and Recommendations regarding Mid-sized 11 LDC Permanent Gas Customer Choice Programs.” This report recommended that the 12 LDCs serve as the SOLR. Subsequently, in Case No. U-15929, in which the MPSC 13 addressed the gas supplier choice tariffs of all participating LDCs, the SOLR duty was 14 established as a uniform rule (see, e.g., Rule F1.15 of the Company’s currently effective 15 tariff sheets). 16 17 Q. Could the Company’sDesign Day supply plan change if its GCR and GCC demand 18 or future natural gas market conditions change? 19 A. Yes. The Company’s Design Day supply plan, as described in this GCR Plan, reflects 20 the Company’s current GCR and GCC demand along with present natural gas market 21 conditions. Should any of these demand variables materially change the Company’s 22 Design Day supply plan may be revised to reflect the future GCR and GCC demand or 23 future market conditions. 24 25 Fixed Cost of Gas 26 Q. What are the Company’s total estimated pipeline transportation, storage, and 27 Peaking Supply fixed costs of gas for the 2017-2018 GCR period? 28 A. Referring to Exhibit A-2, the Company’s total estimated pipeline transportation, storage, 29 and Peaking Supply fixed cost of gas is expected to be $32,824,812 for the 2017-2018 30 GCR period. 31 32 Q. What amount did the Company estimate for its pipeline transportation, storage, 33 and Peaking Supply fixed cost of gas over the 2016-2017 GCR period?
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1 A. The Company’s estimated pipeline transportation, storage, and Peaking Supply fixed 2 cost of gas over the 2016-2017 GCR period was expected to be $37,748,318. 3 4 Q. Please describe what items contributed to the net change of the Company’s 5 estimated pipeline transportation, storage, and Peaking Supply fixed gas costs for 6 the 2017-2018 GCR period when compared to the prior GCR period. 7 A. The net pipeline transportation, storage, and Peaking Supply fixed gas cost decrease of 8 approximately $4,923,506 includes a net of increases and decreases compared to the 9 prior GCR period estimate. The pipeline transportation, storage, and Peaking Supply 10 fixed gas cost increases (+$646,057) are attributable to: (1) the annual realignment of 11 NNG’s TF service base and variable MDQs, (2) renewal of the ANR 2.5 MMDth gas 12 storage service, and (3) renewal of the BWGS 1.0 MMDth gas storage service. The 13 pipeline transportation, storage, and Peaking Supply fixed gas cost decreases (- 14 $5,569,563) are attributable to: (1) renewal of the ANR pipeline transportation portfolio, 15 and (2) lower level of demand charges for Design Day Peaking Supply. 16 17 Q. Does the Company’s total fixed costs include facility demand costs for upstream 18 capacity improvements? 19 A. Yes. As shown in Exhibit A-9, the Company’s total fixed costs include facility demand 20 costs for capacity improvements to NNG’s upstream facilities at the Marquette 1A and 21 Lake Linden interconnections points. 22 23 Q. Please explain the increase to the Company’s fixed cost of gas associated with 24 upstream Marquette 1A interconnection point capacity improvements. 25 A. Upstream capacity improvements to the NNG Marquette 1A interconnection facilities are 26 necessary and are planned for the summer of 2017. Subject to final true-up, the total 27 cost for NNG Marquette 1A upstream capacity improvements is estimated at 28 $1,294,866. 29 30 Q. Please explain why upstream capacity improvements are necessary to NNG’s 31 facilities at the Marquette 1A interconnection? 32 A. Please refer to the testimony of Company witness Michael Clyne. 33
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1 Q. Does the Company plan to execute a Facilities Reimbursement Agreement with 2 NNG for the necessary upstream capacity improvements at Marquette 1A? 3 A. Yes. The Company and NNG plan to execute a Facilities Reimbursement Agreement 4 for the upstream capacity improvements at Marquette 1A prior to April 1, 2017. 5 6 Q. When are the NNG upstream capacity improvements planned for Marquette 1A? 7 A. NNG upstream capacity improvements for Marquette 1A are planned to be performed 8 during the summer of 2017. 9 10 Q. What cost for the Marquette 1A upstream capacity improvements is the Company 11 seeking to recover through the Balancing and Demand Charge? 12 A. Subject to final true-up, the Company is seeking to recover $1,294,866 through the 13 Company’s Balancing and Demand Charge over the 2017-2018, 2018-2019, and 2019- 14 2020 GCR periods. 15 16 Q. Why is the Company seeking to recover the Marquette 1A upstream capacity 17 improvements cost of $1,294,866 through the GCR the Balancing and Demand 18 Charge? 19 A. The amount of $1,294,866 represents the cost for NNG to perform the upstream 20 capacity improvements at Marquette 1A. All the improved facilities are owned by NNG. 21 Since the Company cannot capitalize plant that it does not own, the cost to reimburse 22 NNG for the upstream capacity improvements at Marquette 1A will be recovered through 23 the Company’s GCR rates as an incremental cost to the Balancing and Demand Charge. 24 25 Q. How will NNG recover its cost for the Marquette 1A upstream capacity 26 improvements from the Company? 27 A. The Company will amend its NNG TF interstate pipeline transportation contract 110025 28 during 2017. The amendment will indicate that NNG will recover its Marquette 1A 29 capacity improvement costs as an incremental cost to the Company’s NNG pipeline 30 transportation demand charge over a 24 month period beginning November 1, 2017. 31
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1 Q. What will be NNG’s estimated incremental TF demand rate for the Marquette 1A 2 upstream capacity improvements for the 2017-2018, 2018-2019, and 2019-2020 3 GCR periods? 4 A. NNG’s incremental TF demand rate for Marquette 1A upstream capacity improvements 5 for the 2017-2018 period is estimated to be approximately $1.4691/Dth effective 6 November 1, 2017. Once all of NNG’s capacity improvement costs are finalized, NNG 7 will notify the Company of the final trued-up cost and resulting demand rate for the 2018- 8 2019 GCR period. NNG’s final trued-up demand rate are planned to become effective 9 on April 1, 2018. 10 11 Q. What will NNG’s estimated incremental demand rate of $1.4691/Dth add to the 12 Company’s Balancing and Demand Charge for the 2017-2018 GCR period for the 13 Marquette 1A upstream capacity improvements? 14 A. The incremental cost to the Balancing and Demand Charge for the Marquette 1A 15 upstream capacity improvements is estimated to be $.000798 per Therm or $0.77 16 annually for each GCR and GCC customer over the 2017-2018 GCR period. 17 18 Q. Did the Company conduct a “cost/benefit analysis” in connection with the 19 Marquette 1A upstream capacity improvement? 20 A. Not in the true sense. This is so because there is no alternative to NNG and the 21 improvement is mandated by the absolute need for the Company to meet its duty to 22 serve its customers. As I have expressed, the maximum capacity of NNG’s upstream 23 facilities is inadequate, with an expected Design Day capacity deficiency of 274 Dth. In 24 this case, the “benefit” of serving the customers clearly outweighs the “cost”. 25 26 Q. Please explain the increase to the Company’s fixed cost of gas associated with 27 upstream Lake Linden interconnection point capacity improvements. 28 A. Upstream capacity improvements to the NNG Lake Linden interconnection facilities are 29 necessary and are planned for the summer of 2017. Subject to final true-up, the cost for 30 NNG Lake Linden upstream capacity improvements is estimated at $868,620. 31 32 Q. Please explain why upstream capacity improvements are necessary to NNG’s 33 facilities at the Lake Linden interconnection?
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1 A. Please refer to the testimony of Company witness Michael Clyne. 2 3 Q. Does the Company plan to execute a Facilities Reimbursement Agreement with 4 NNG for the necessary upstream capacity improvements at Lake Linden? 5 A. Yes. The Company and NNG plan to execute a Facilities Reimbursement Agreement 6 for the upstream capacity improvements at Lake Linden prior to April 1, 2017. 7 8 Q. When are the NNG upstream capacity improvements planned for Lake Linden? 9 A. NNG upstream capacity improvements for Lake Linden are planned to be performed 10 during the summer of 2017. 11 12 Q. What cost for the Lake Linden upstream capacity improvements is the Company 13 seeking to recover through the Balancing and Demand Charge? 14 A. Subject to final true-up, the Company is seeking to recover $868,620 through the 15 Company’s Balancing and Demand Charge over the 2017-2018, 2018-2019, and 2019- 16 2020 GCR periods. 17 18 Q. Why is the Company seeking to recover the Lake Linden upstream capacity 19 improvements cost of $868,620 through the GCR the Balancing and Demand 20 Charge? 21 A. The amount of $868,620 represents the cost for NNG to perform the upstream capacity 22 improvements at Lake Linden. All the improved facilities are owned by NNG. Since the 23 Company cannot capitalize plant that it does not own, the cost to reimburse NNG for the 24 upstream capacity improvements at Lake Linden will be recovered through the 25 Company’s GCR rates as an incremental cost to the Balancing and Demand Charge. 26 27 Q. How will NNG recover its cost for the Lake Linden upstream capacity 28 improvements from the Company? 29 A. The Company will amend its NNG TF interstate pipeline transportation contract 110025 30 during 2017. The amendment will indicate that NNG will recover its Lake Linden 31 capacity improvement costs as an incremental cost to the Company’s NNG pipeline 32 transportation demand charge over a 24 month period beginning November 1, 2017. 33
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1 Q. What will be NNG’s estimated incremental TF demand rate for the Lake Linden 2 upstream capacity improvements for the 2017-2018, 2018-2019, and 2019-2020 3 GCR periods? 4 A. NNG’s incremental TF demand rate for Lake Linden upstream capacity improvements 5 for the 2017-2018 period is estimated to be approximately $0.9855/Dth effective 6 November 1, 2017. Once all of NNG’s capacity improvement costs are finalized, NNG 7 will notify the Company of the final trued-up cost and resulting demand rate for the 2018- 8 2019 GCR period. NNG’s final trued-up demand rate are planned to become effective 9 on April 1, 2018. 10 11 Q. What will NNG’s estimated incremental demand rate of $0.9855/Dth add to the 12 Company’s Balancing and Demand Charge for the 2017-2018 GCR period for the 13 Lake Linden upstream capacity improvements? 14 A. The incremental cost to the Balancing and Demand Charge for the Lake Linden 15 upstream capacity improvements is estimated to be $0.000535 per Therm or $0.51 16 annually for each GCR and GCC customer over the 2017-2018 GCR period. 17 18 Q. Did the Company conduct a “cost/benefit analysis” in connection with the Lake 19 Linden upstream capacity improvement? 20 A. Not in the true sense. This is so because there is no alternative to NNG and the 21 improvement is mandated by the absolute need for the Company to meet its duty to 22 serve its customers. As I have expressed, the maximum capacity of NNG’s upstream 23 facilities is inadequate, with an expected Design Day capacity deficiency of 735 Dth. In 24 this case, the “benefit” of serving the customers clearly outweighs the “cost”. 25 26 27 Total Cost of Gas 28 Q. What is the Company’sestimated total cost for each of the GCR periods over the 29 five-year period beginning April 1, 2017? 30 A. The Company’s estimated total cost for each of the GCR periods over the five-year 31 period beginning April 1, 2017, is shown in Exhibit A-9. This exhibit summarizes the 32 Company’s estimated commodity costs, storage inventory values, and fixed costs of gas
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1 expected to be purchased by the Company to meet its forecasted supply requirements 2 for the 2017-2018 GCR plan. 3 4 Q. Please describe how the Company estimated the cost of gas for each of the five 5 years of the plan forecast. 6 A. The forecasted GCR demand, the required supply, corresponding fuel, and storage 7 quantities were determined as shown in the Average Day Supply Purchase Plan, Exhibit 8 A-7. Using the Average Day Supply Purchase Plan, the monthly purchases were priced 9 at the NYMEX-based market price forecast and adjusted for the applicable basis value 10 for each month of the plan. 11 12 Q. How is the NYMEX-based market price forecast determined? 13 A. The NYMEX-based market price forecast is determined from the five-day average of the 14 NYMEX futures settlement prices ending December 7, 2016, and adjusted for basis. 15 16 Q. What NYMEX futures settlement prices were used in this plan and why was the 17 five-day average of the NYMEX futures settlement prices ending December 7, 2016 18 used? 19 A. The NYMEX futures settlement values used in this plan are shown in Exhibit A-10. The 20 five-day average of the NYMEX futures settlement prices ending December 7, 2017 21 were chosen because they were the most recent five-day settlements at the time this 22 plan was finalized. 23 24 Q. Why does the Company use NYMEX futures settlement prices in determining the 25 NYMEX-based market price forecast? 26 A. The Company uses the NYMEX futures settlement prices for its NYMEX-based market 27 price forecast because the NYMEX is the industry-wide recognized price reference point 28 for natural gas. 29 30 Q. Please explain the basis price values reflected in Exhibit A-11. 31 A. Natural Gas futures traded on the NYMEX are based on gas delivered at the Henry Hub 32 in Louisiana. The Henry Hub is the nexus of 16 interstate and intrastate natural gas 33 pipeline systems that draw supplies from that region's prolific gas deposits. These
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1 pipeline systems serve markets throughout the U.S. East Coast, the Gulf Coast, the 2 Midwest, and up to the Canadian border. The price of gas supplied at geographic 3 locations other than the Henry Hub is measured through basis prices. Basis prices, as 4 used in this plan, represent the difference in the price for gas delivered at the indicated 5 geographic location and the price for gas at the Henry Hub as traded on the NYMEX. 6 7 Q. What basis price values were used to develop this plan? 8 A. The basis price values used to develop this plan are shown in Exhibit A-11. 9 10 Q. How does the Company forecast basis prices and the resulting price it will pay for 11 gas at its various supply receipt points? 12 A. For the development of this plan, the Company acquired the basis values from supplier 13 provided data for each of its supply receipt points. 14 15 Q. Using the NYMEX-based market rates described above, what total cost of gas is 16 the Company estimating for the 2017-2018 GCR period? 17 A. The Company is estimating a total cost of gas of $161,332,377. This amount includes a 18 total commodity cost of gas of $128,548,301 and total fixed costs of $32,784,076. 19 20 Q. What will be the Company’s resulting GCR factor from the estimated cost of gas 21 for the 2017-2018 GCR period? 22 A. The resulting GCR factor for the 2017-2018 GCR period is discussed in the direct 23 testimony of Witness Jim Van Sickle. 24 25 Q. Is the Company’ssupply plan reasonable and prudent? 26 A. Yes, the Company’s supply plan is reasonable and prudent. The Company maintains a 27 diversity of firm pipeline transportation capacity assets, firm leased storage assets, and 28 its own on-system storage assets, thus assuring its customers reliable sources of supply 29 at a reasonable cost. The Company has an overall supply acquisition plan that will 30 provide its GCR customers with ample diversity from various gas production basins so 31 that the resulting cost of gas will be reasonably reflective of market prices. As evidenced 32 through the Company’s diverse supply sources, level of working storage, and pipeline 33 transportation assets, this plan is reasonable and prudent.
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1 2 Q. Does this conclude your pre-filed direct testimony at this time? 3 A. Yes.
Page 57 of 57 SEMCO ENERGY GAS COMPANY Exhibit A-1 GAS SUPPLY SERVICE AREAS Page 1 of 1 Case No. U-18157 Exhibit A-2 Page 1 of 1 Case No. U-18157
SEMCO ENERGY GAS COMPANY Pipeline Transportation, Storage, and Peaking Supply
(MDQ and ACQ Units in Dth) - Effective 4/1/2017 Summer Summer Winter Winter (Effective Monthly Daily Monthly Daily 10/1/16) Primary Primary Contract Contract Fixed Res Fixed Res Fixed Res Fixed Res Utilization FERC Contract Service [1] Receipt Delivery Start End Summer Winter Annual (Demand) (Demand) (Demand) (Demand) (Commodity) ACA Annual Pipeline Services Number Type Point(s) Point(s) Date Date MDQ MDQ ACQ Rate Rate Rate Rate Rate Rate Fixed Cost
1 Interstate Providers 2 ANR (Southeast) 123256 ETS ANR SE Head Stn SG1 04/01/17 03/31/21 11,172 12,250 $10.5000 $0.3452 $10.5000 $0.3452 $0.01890 $0.0013 $1,464,267 3 ANR (Southeast) 128531 ETS ANR SE Shelbyville SG1 04/01/17 03/31/21 11,172 12,250 $8.9076 $0.2929 $8.9076 $0.2929 $0.01890 $0.0013 $1,242,200 4 ANR (Southwest) 122005 ETS ANR SW Head Stn SG1 04/01/17 03/31/21 22,345 24,500 $10.5090 $0.3455 $10.5090 $0.3455 $0.02160 $0.0013 $2,931,118 5 ANR (Southwest) 122003 ETS ANR SW Head Stn SG1 04/01/17 03/31/19 18,000 18,000 $10.5090 $0.3455 $10.5090 $0.3455 $0.02160 $0.0013 $2,269,944 6 ANR (Northern) 122006 ETS Hanover, MI SG1 11/01/13 03/13/18 0 40,255 $4.5630 $0.1500 $0.01010 $0.0013 $918,418 7 ANR (Northern) 125465 ETS ANR Stg/ANR Grp1 SG1/ANR Stg 04/01/17 03/31/21 5,091 50,000 $6.5486 $0.2153 $6.5486 $0.2153 $0.01010 $0.0013 $1,870,522 8 ANR (Northern) 125573 FTS-1 Farwell, MI ANR Stg 04/01/17 03/31/21 7,636 0 $5.7290 $0.1884 $0.01010 $0.0013 $306,227 9 ANR 125467 NNS NA NA 04/01/17 03/31/21 2,500 2,500 $6.8750 $0.2260 $6.8750 $0.2260 $0.01650 $0.0013 $206,250 10 Great Lakes FT17191 FT Emerson, MB Carlton, MN 11/01/12 03/31/18 0 7,500 $3.1810 $0.1046 $0.00326 $0.0013 $119,288 11 Great Lakes FT17192 FT Emerson, MB Trumble Rd 11/01/12 10/31/18 10,000 22,500 $5.7800 $0.1900 $5.7800 $0.1900 $0.01080 $0.0013 $1,054,850 12 Great Lakes FT18233 FT Deward, MI Chippewa, MI 11/01/15 03/31/18 0 46,000 $2.4330 $0.0806 $0.00464 $0.0013 $559,590 13 Great Lakes FT18232 FT Deward, MI Trumble Rd 11/01/15 03/31/18 0 7,000 $2.4330 $0.0806 $0.00464 $0.0013 $85,155 14 Great Lakes FT18178 FT Rattle Run Trumble Rd 04/01/17 03/31/22 0 12,000 $4.5630 $0.1500 $0.00464 $0.0013 $273,780 15 Great Lakes IT18199 IT All All 02/21/15 100,000 100,000 $0.01307 $0.0013 $0 16 Panhandle 20653 EFT PEPL Fld Zone SEMIC Group 04/01/16 03/31/20 8,500 18,500 $13.4300 $0.4415 $13.4300 $0.4415 $0.04510 $0.0013 $2,041,360 17 Panhandle 20653 EFT PEPL Fld Zone JACPL Group 04/01/16 03/31/20 10,000 0 $13.4300 $0.4415 $0.04260 $0.0013 $940,100 18 Panhandle 17145 IT CECO/Moultrie/Bourbon All Points 04/01/16 03/31/20 10,000 10,000 $0.40000 $0.0013 $0 19 Northern Natural Gas 110025 TF12 B Dem/Vent/Og/Cltn NNG Zone EF 02/01/16 10/31/21 10,314 10,314 $5.6830 $0.1868 $10.2300 $0.3363 $0.03690 $0.0013 $937,862 20 Northern Natural Gas 110025 TF12 V Dem/Vent/Og/Cltn NNG Zone EF 02/01/16 10/31/21 21,036 21,036 $5.6830 $0.1868 $13.8660 $0.4559 $0.03690 $0.0013 $2,295,259 21 Northern Natural Gas 110025 TF5 Dem/Vent/Og/Cltn NNG Zone EF 02/01/16 10/31/21 0 12,900 $15.1530 $0.4982 $0.03690 $0.0013 $977,369 22 Northern Natural Gas 110024 TFX Dem/Vent NNG Zone EF 02/01/16 10/31/18 [2] 7,190 $5.6830 $0.1868 $15.1530 $0.4982 $0.03690 $0.0013 $619,539 23 Northern Natural Gas 22566 SMS NA NA 11/01/13 10/31/16 6,000 6,000 $2.1800 $0.0717 $2.1800 $0.0717 $0.02080 $0.0013 $156,960 24 25 26 Intrastate Providers 27 Consumers Energy Co. None FT Various Various 05/01/15 04/30/18 [4] 50,000 $7.4217 $0.2440 $7.4217 $0.2440 $0.00000 $0.0000 $2,364,116 28 Consumers Energy Co. None IT Various Various 05/01/15 04/30/18 [5] 60,000 $0.24400 $0.0000 $0 29 DTE Energy 4016 FT BWGS, ANR Willow Rn Ray Twp, MI 11/01/15 03/31/17 0 20,000 1,500,000 $2.4333 $0.0800 $0.00000 $0.0000 $120,000 30 Jackson Pipeline MJK001200 FT ERGSS/ANR ANR/ERGSS 04/01/10 03/31/18 36,653 66,665 11,356,300 $2.8896 $0.0950 $2.8896 $0.0950 $0.00000 $0.0000 $1,078,849 31 Eaton Rapids Pipeline None FT ERGSS Harris/Albion 10/01/90 Evergreen 0 13,245 4,000,000 $3.0052 $0.0988 $3.0052 $0.0988 $0.00000 $0.0000 $395,200 32 Greenwood Pipeline None FT ANR S Greenwood Kilgore Rd 06/01/91 Evergreen 12,000 12,000 $0.0000 $0.0000 $0.0000 $0.0000 $0.00000 $0.0000 $0 33 $25,228,223 34 35 36 Maximum Maximum 37 Primary Primary Contract Contract Annual Daily Daily Injection Withdrawal 38 Contract Service [1] Receipt Delivery Start End Contract Injection Withdraw Cap Deliv Comm Comm Inj Wdl Annual 39 Storage Services Number Type Point Point Date Date Quantity Quantity Quantity Rate Rate Rate Rate Fuel Fuel Fixed Cost 40 ANR Pipeline Co 125464 FSS, 50 day, A/U ANR Storage ANR Storage 04/01/15 03/31/17 2,521,200 12,606 50,424 $0.3300 $1.7500 $0.0126 $0.0126 0.85% 0.00% $1,890,900 41 ANR Storage Co 10000123 FSS, 10 day, A/R Deward Deward 05/01/15 03/31/18 533,925 4,108 53,393 $0.0133 $1.0924 $0.0323 $0.0323 1.30% 0.20% $784,812 42 Eaton Rapids Storage 20000025 FSS, 123 day, S/R Eaton Rapids, MI JPL, ERPL 11/01/08 03/31/18 6,500,000 36,111 67,000 $0.0207 $2.2993 $0.0000 $0.0000 1.50% 0.50% $3,463,237 43 Northern Natural Gas 22305 FDD, 58 day, S/R Ogden, IA Ogden, IA 06/01/13 [3] 1,000,000 11,005 17,345 $0.3567 $1.7140 $0.0149 $0.0149 1.76% 0.00% $713,452 44 Bluewater Gas Storage SEI01312S FSS, 50 day, A/U Bluewater Gas Storage GL Rattle Run 04/01/15 03/31/17 1,000,000 5,000 20,000 $0.7200 $0.0000 $0.0160 $0.0000 1.45% 0.00% $720,000 45 $7,572,401 46 47 48 Peaking Supply Daily Total Estimated 49 Quantity Quantity Demand Annual 50 Dth/Day Days Dth Rate Fixed Cost 51 Design Day Peaking Supply 78,000 7 546,000 $0.0443 $24,188 52 53 Notes: 54 [1] ETS - Enhanced Transportation Service, FT - Firm Transportation Service, EIT - Enhanced Interuptible Transportation, IT - Interuptible Transportation, NNS - No Notice Service, SMS - System Management Service. $32,824,812 55 FSS - Firm Storage Service, FDD - Firm Defered Delivery, S - Seasonal, R - Ratcheted, U - Unratcheted 56 [2] 4,380 Dth/day Apr and Oct, 880 Dth/day May to Sep, 7,190 Dth/day Nov to Mar 880 57 [3] 614,113 Dth expires on 5/31/2019 and 385,887 Dth terminates on 5/31/2018 3500 58 [4] 15,000 Dth/day Apr and Oct, 8,000 Dth/day May to Sep 59 [5] 95,000 Dth/day Apr and Oct, 102,000 Dth/day May to Sep
WEF 17-18 GCR Exhibits v0 Dec Filing Exhibit A-3 Page 1 of 1 Case No. U-18157
SEMCO ENERGY GAS COMPANY 2018-2019 CECO Capacity Plan Cost Savings
(MDQ and ACQ Units in Dth) Monthly Daily Primary Primary Fixed Res Fixed Res Summer Winter Contract Service Receipt Delivery Summer Winter (Demand) (Demand) Fixed Fixed Annual Pipeline ServicesNumber Type Point(s) Point(s) MDQ MDQ Rate Rate Costs Costs Fixed Cost
2018-2019 CECO Associated Capacity - Existing CECO None FT Various Akron 8,000 50,000 $7.4217 $0.2440 $521,916 $1,842,200 $2,364,116 Great Lakes FT18233 FT Deward, MI Chippewa 0 46,000 $5.7770 $0.1913 $0 $1,328,710 $1,328,710 Total $0 $3,170,910 $3,692,826
2018-2019 CECO Associated Capacity - Planned CECO None FT Various Akron 0 7,200 $7.4217 $0.2440 $0 $265,277 $265,277 PEPL New FT JPL SEMIC 0 5,700 $3.9000 $0.13 $0 $111,150 $111,150 Great Lakes FT18233 FT Deward, MI Farwell 0 23,500 $5.7770 $0.1913 $0 $678,798 $678,798 ANR New ETS Farwell SG1 0 23,500 $6.5486 $0.2153 $0 $769,461 $769,461 Total $0 $1,824,685 $1,824,685
Annual Demand Cost Savings $1,868,141
5 Yr Demand Cost Savings $9,340,704
Rabbit River Facility Demand Cost $6,930,000
Net 5 Yr Savings $2,410,704
10 Yr Savings $11,751,407 Gas Supply Network Diagram Exhibit A-4 Page 1 of 1 Case No. U-18157
NNG GLGTC DTE ANR SW ANR SE BWGS Ventura Willow 1.0 MMDth Emerson SW HS SE HS Run Demarc Storage Farwell Shelby
Great Lakes FT ANR SW EFT DTE FT Great Lakes FT ANR PL ANR SE EFT 2.5 MMDth Storage
ANR Hanover EFT Jackson PL FT ERGSS ANR Stg EFT & FTS1 6.5 MMDth Vector Storage NNG WDL from DTE Stg Marengo to CECO to/from PEPL NNG SEMCO PL FT 1.0 MMDth NNG FT DTE FT Storage
NNG INJ
UP West UP East Port Huron Niles Holland Albion Battle Creek Service Area Service Area Service Area Service Area Service Area Service Area Service Area Abbreviation Key: ANR - ANR Pipeline Company PEPL - Panhandle Eastern Pipeline Company GLGTC - Great Lakes Gas Transmission Company NNG - Northern Natural Gas Company CECO - Consumers Energy Company to/from JPL DTE - DTE Energy Company
from JPL - Interstate and Intrastate Pipeline Supply Receipt Points ANRSC - Off-System Storage Points 0.530 MMDth PEPL EFT Great Lakes FT Storage - On-System Storage Points Collin Morton 1.5 MMDth 2.0 MMDth - SEMCO Service Areas Storage Storage CECO FT Lacey Lee 0.175 Dth 0.12 MMDth Storage Storage PEPL CECO CIG Various Elk Cty Rec ENOGEX Points Exhibit A-5 Page 1 of 3 Case No. U-18157
SEMCO Energy Gas Company FERC Activity Summary December 2015 through November 2016
Docket Date of Item # Pipeline Filing Issue Title of Filing FERC Orders Number Filing
ANR Section 4 rate case filing seeking a Motion to Intervene Dec 16, 2016: Letter order approving ANR ANR Pipeline system-wide general increase in ANR’s rates 1 RP16-440-000 2/10/2016 of SEMCO Energy Pipeline Company's Stipulation and Agreement Co. and changes to ANR’s rate schedules and Gas Co. of Settlement. GT&Cs.
Tariff sheets establishing the Field Area and Storage fuel percentages to be in effect for the April 1, 2016 through March 31, 2017 annual period, based on actual data for the Motion to Intervene Northern Natural 2 RP16-535-000 twelve-month period January 1, 2015 through 2/12/2016 of SEMCO Energy Feb. 23, 2016: Letter Order Approving Filing. Gas Co. December 31, 2015. The filing also Gas Co. establishes the Market Area fuel percentage to be in effect for the Summer Season April 1, 2016 through October 31, 2016.
Northern Natural’s report of the penalty and daily delivery variance charge revenues for Motion to Intervene Northern Natural the period November 1, 2014 through 3 RP16-610-000 3/14/2016 of SEMCO Energy Pending Gas Co. October 31, 2015, that have been credited to Gas Co. shippers in accordance with GT&C Section 57.
Revised tariff sections to comply with the Motion to ANR Pipeline annual fuel and electric power cost Intervene of 4 RP16-650-000 Mar. 14, 2016 Mar. 22, 2016: Letter Order Approving Filing. Co. redetermination provisions of Sections 6.1.86 SEMCO Energy and 6.34 of the GT&Cs of ANR’s Tariff. Gas Co.
Panhandle Revised tariff records reflecting changes to Motion to Intervene 5 RP16-655-000 Eastern Pipe Line Panhandle’s Fuel Reimbursement 3/14/2016 of SEMCO Energy Mar. 24, 2016: Letter Order Approving Filing. Co., LP Percentages. Gas Co. Exhibit A-5 Page 2 of 3 Case No. U-18157
SEMCO Energy Gas Company FERC Activity Summary December 2015 through November 2016
Docket Date of Item # Pipeline Filing Issue Title of Filing FERC Orders Number Filing
Revised tariff sections to comply with the Deferred Transportation Cost Adjustment Motion to Intervene ANR Pipeline provisions in Section 6.26 of the GT&Cs of 6 RP16-763-000 4/12/2016 of SEMCO Energy Apr. 22, 2016: Letter Order Approving Filing. Co. ANR’s tariff and the related settlement Gas Co. approved by the Commission on October 15, 2015, in Doc. No. RP13-743-000, et al.
Revised tariff records to reflect changes to Panhandle’s currently-effective Maximum Panhandle Reservation Rates under Rate Schedules FT, Motion to Intervene 7 RP16-768-000 Eastern Pipe Line EFT, LFT, and HFT, currently-effective one- Apr. 12, 2016 of SEMCO Energy Apr. 14, 2016: Letter Order Approving Filing. Co., LP part rate under Rate Schedule SCT, and Gas Co. currently-effective Maximum Commodity rates under Rate Schedules IT and EIT.
Panhandle’s Annual Report of Flow Through Panhandle of Penalty Revenues for the twelve-month Motion to Intervene 8 RP16-769-000 Eastern Pipe Line period March 2015 through February 2016, 4/12/2016 of SEMCO Energy Pending Co., LP crediting to firm shippers penalty revenues Gas Co. totaling $687,169.40. Form 552 of FERC Form 552 Annual Report of Natural 9 N/A N/A 4-May-16 SEMCO Energy N/A Gas Transactions for year ended 2015. Gas Company
Revised tariff sheets to establish the Market Area fuel percentage to be in effect for the Motion to Intervene Northern Natural Winter Season November 1, 2016 through 10 RP16-879-000 10-May-16 of SEMCO Energy June 14, 2016: Letter Order Approving Filing. Gas Co. March 31, 2017, based on actual data for the Gas Co. Winter Season November 1, 2015 through March 31, 2016. Exhibit A-5 Page 3 of 3 Case No. U-18157
SEMCO Energy Gas Company FERC Activity Summary December 2015 through November 2016
Docket Date of Item # Pipeline Filing Issue Title of Filing FERC Orders Number Filing
Tariff filing to revise the applicable cashout Motion to Intervene ANR Pipeline 11 RP16-886-000 surcharge, effective June 1, 2016, pursuant to 11-May-16 of SEMCO Energy May 25, 2016: Letter Order Approving Filing. Co. ANR’s System Cashout Mechanism. Gas Co.
Great Lakes Gas Great Lakes Revenue Cap and Revenue Motion to Intervene Transmission Sharing Mechanism Rider True-Up Report 12 RP16-913-000 11-May-16 of SEMCO Energy Pending Limited for the twelve-month period ending Gas Co. Partnership December 31, 2015.
ANR’s report of Operational Purchases and Motion to Intervene ANR Pipeline 13 RP16-924-000 Sales of gas for the twelve-month period 11-May-16 of SEMCO Energy Pending Co. ending December 31, 2015. Gas Co.
Petition for Approval of Settlement and Motion to Intervene ANR Storage Request for Shortened Comment Period and 14 RP16-1030-000 16-Jun-16 of SEMCO Energy Jul 28, 2016: Letter order approving filing Company Stipulation and Agreement of ANR Storage Gas Co. Company Exhibit A-6 Page 1 of 2 Case No. U-18157
SEMCO Energy Gas Company 2017-2018 Storage Utilization Plan (Quantities in Dth) Apr May Jun Jul Aug Sep Oct Nov Dec Jan Feb Mar Total
1 Collins Beginning Inv Vol 240,000 298,400 481,300 658,300 841,200 1,024,100 1,201,100 1,384,000 1,289,139 1,059,485 744,374 455,421 2 Injected Vol Rec 58,400 182,900 177,000 182,900 182,900 177,000 182,900 0 0 0 0 0 1,144,000 3 Injected Fuel Loss 0 0 0 0 0 0 0 0 0 0 0 0 0 4 Injected Vol Del 58,400 182,900 177,000 182,900 182,900 177,000 182,900 0 0 0 0 0 1,144,000 5 Withdrawn Vol Rec 0 0 0 0 0 0 0 94,861 229,653 315,111 288,953 215,421 1,144,000 6 Withdrawn Fuel Loss 0 0 0 0 0 0 0 0 0 0 0 0 0 7 Withdrawn Vol Del 0 0 0 0 0 0 0 94,861 229,653 315,111 288,953 215,421 1,144,000 8 Ending Inv Vol 298,400 481,300 658,300 841,200 1,024,100 1,201,100 1,384,000 1,289,139 1,059,485 744,374 455,421 240,000 9 10 Morton Field Beginning Inv Vol 240,000 337,400 597,800 849,800 1,110,200 1,370,600 1,622,600 1,883,000 1,746,761 1,416,936 964,377 549,385 11 Injected Vol Rec 97,400 260,400 252,000 260,400 260,400 252,000 260,400 0 0 0 0 0 1,643,000 12 Injected Fuel Loss 0 0 0 0 0 0 0 0 0 0 0 0 0 13 Injected Vol Del 97,400 260,400 252,000 260,400 260,400 252,000 260,400 0 0 0 0 0 1,643,000 14 Withdrawn Vol Rec 0 0 0 0 0 0 0 136,239 329,826 452,559 414,992 309,385 1,643,000 15 Withdrawn Fuel Loss 0 0 0 0 0 0 0 0 0 0 0 0 0 16 Withdrawn Vol Del 0 0 0 0 0 0 0 136,239 329,826 452,559 414,992 309,385 1,643,000 17 Ending Inv Vol 337,400 597,800 849,800 1,110,200 1,370,600 1,622,600 1,883,000 1,746,761 1,416,936 964,377 549,385 240,000 18 19 Lee Beginning Inv Vol 181,000 246,290 405,400 561,400 722,600 883,800 1,039,800 1,201,000 1,115,796 911,140 630,672 373,383 20 Injected Vol Rec 65,290 159,110 156,000 161,200 161,200 156,000 161,200 0 0 0 0 0 1,020,000 21 Injected Fuel Loss 0 0 0 0 0 0 0 0 0 0 0 0 0 22 Injected Vol Del 65,290 159,110 156,000 161,200 161,200 156,000 161,200 0 0 0 0 0 1,020,000 23 Withdrawn Vol Rec 0 0 0 0 0 0 0 85,204 204,657 280,468 257,288 192,383 1,020,000 24 Withdrawn Fuel Loss 0 0 0 0 0 0 0 0 0 0 0 0 0 25 Withdrawn Vol Del 0 0 0 0 0 0 0 85,204 204,657 280,468 257,288 192,383 1,020,000 26 Ending Inv Vol 246,290 405,400 561,400 722,600 883,800 1,039,800 1,201,000 1,115,796 911,140 630,672 373,383 181,000 27 28 Lacey Beginning Inv Vol 67,000 67,000 67,000 67,000 98,750 137,500 175,000 175,000 175,000 175,000 175,000 121,000 29 Injected Vol Rec 0 0 0 31,750 38,750 37,500 0 0 0 0 0 0 108,000 30 Injected Fuel Loss 0 0 0 0 0 0 0 0 0 0 0 0 0 31 Injected Vol Del 0 0 0 31,750 38,750 37,500 0 0 0 0 0 0 108,000 32 Withdrawn Vol Rec 0 0 0 0 0 0 0 0 0 0 54,000 54,000 108,000 33 Withdrawn Fuel Loss 0 0 0 0 0 0 0 0 0 0 0 0 0 34 Withdrawn Vol Del 0 0 0 0 0 0 0 0 0 0 54,000 54,000 108,000 35 Ending Inv Vol 67,000 67,000 67,000 98,750 137,500 175,000 175,000 175,000 175,000 175,000 121,000 67,000 36 37 Eaton Rapids Beginning Inv Vol 1,047,000 1,347,138 2,263,000 3,343,000 4,180,000 5,017,000 5,827,000 6,230,000 5,880,000 4,765,000 3,205,000 1,890,000 38 Injected Vol Rec 304,708 929,810 1,096,447 849,746 849,746 822,335 409,137 0 0 0 0 0 5,261,929 39 Injected Fuel Loss 4,571 13,947 16,447 12,746 12,746 12,335 6,137 0 0 0 0 0 78,929 40 Injected Vol Del 300,138 915,862 1,080,000 837,000 837,000 810,000 403,000 0 0 0 0 0 5,183,000 41 Withdrawn Vol Rec 0 0 0 0 0 0 0 350,000 1,115,000 1,560,000 1,315,000 843,000 5,183,000 42 Withdrawn Fuel Loss 0 0 0 0 0 0 0 1,750 5,575 7,800 6,575 4,215 25,915 43 Withdrawn Vol Del 0 0 0 0 0 0 0 348,250 1,109,425 1,552,200 1,308,425 838,785 5,157,085 44 Ending Inv Vol 1,347,138 2,263,000 3,343,000 4,180,000 5,017,000 5,827,000 6,230,000 5,880,000 4,765,000 3,205,000 1,890,000 1,047,000 45 46 ANR Pipeline Beginning Inv Vol 50,000 237,658 500,496 871,911 1,256,499 1,642,431 2,017,431 2,400,000 2,205,137 1,733,383 1,086,084 492,517 47 Co Storage Injected Vol Rec 189,457 265,359 374,978 388,276 389,633 378,597 386,239 0 0 0 0 0 2,372,539 48 Injected Fuel Loss 1,800 2,521 3,562 3,689 3,702 3,597 3,669 0 0 0 0 0 22,539 49 Injected Vol Del 187,658 262,838 371,415 384,588 385,932 375,000 382,570 0 0 0 0 0 2,350,000 50 Withdrawn Vol Rec 0 0 0 0 0 0 0 194,864 471,753 647,300 593,567 442,517 2,350,000 51 Withdrawn Fuel Loss 0 0 0 0 0 0 0 0 0 0 0 0 0 52 Withdrawn Vol Del 0 0 0 0 0 0 0 194,864 471,753 647,300 593,567 442,517 2,350,000 53 Ending Inv Vol 237,658 500,496 871,911 1,256,499 1,642,431 2,017,431 2,400,000 2,205,137 1,733,383 1,086,084 492,517 50,000 54
WEF 17-18 GCR Exhibits v0 Dec Filing Exhibit A-6 Page 2 of 2 Case No. U-18157
SEMCO Energy Gas Company 2017-2018 Storage Utilization Plan (Quantities in Dth) Apr May Jun Jul Aug Sep Oct Nov Dec Jan Feb Mar Total
55 ANR Storage Beginning Inv Vol 0 79,783 163,483 241,331 320,979 399,275 473,521 533,926 533,926 533,926 533,926 266,963 56 Co Storage Injected Vol Rec 80,834 84,802 78,874 80,697 79,328 75,224 61,200 0 0 0 0 0 540,958 57 Injected Fuel Loss 1,051 1,102 1,025 1,049 1,031 978 796 0 0 0 0 0 7,032 58 Injected Vol Del 79,783 83,700 77,848 79,648 78,297 74,246 60,405 0 0 0 0 0 533,926 59 Withdrawn Vol Rec 0 0 0 0 0 0 0 0 0 0 266,963 266,963 533,926 60 Withdrawn Fuel Loss 0 0 0 0 0 0 0 0 0 0 534 534 1,068 61 Withdrawn Vol Del 0 0 0 0 0 0 0 0 0 0 266,429 266,429 532,858 62 Ending Inv Vol 79,783 163,483 241,331 320,979 399,275 473,521 533,926 533,926 533,926 533,926 266,963 0 63 64 Northern Beginning Inv Vol 50,000 50,000 50,000 230,000 416,000 602,000 782,000 950,000 885,000 721,000 446,000 224,000 65 Natural Gas Injected Vol Rec 0 0 183,225 189,332 189,332 183,225 171,010 0 0 0 0 0 916,124 66 Injected Fuel Loss 0 0 3,225 3,332 3,332 3,225 3,010 0 0 0 0 0 16,124 67 Injected Vol Del 0 0 180,000 186,000 186,000 180,000 168,000 0 0 0 0 0 900,000 68 Withdrawn Vol Rec 0 0 0 0 0 0 0 65,000 164,000 275,000 222,000 174,000 900,000 69 Withdrawn Fuel Loss 0 0 0 0 0 0 0 0 0 0 0 0 0 70 Withdrawn Vol Del 0 0 0 0 0 0 0 65,000 164,000 275,000 222,000 174,000 900,000 71 Ending Inv Vol 50,000 50,000 230,000 416,000 602,000 782,000 950,000 885,000 721,000 446,000 224,000 50,000 72 73 Bluewater Beginning Inv Vol 0 141,000 280,900 421,900 567,600 713,300 854,300 1,000,000 1,000,000 1,000,000 720,000 440,000 74 Gas Storage Injected Vol Rec 143,075 141,958 143,075 147,844 147,844 143,075 147,844 0 0 0 0 0 1,014,713 75 Injected Fuel Loss 2,075 2,058 2,075 2,144 2,144 2,075 2,144 0 0 0 0 0 14,713 76 Injected Vol Del 141,000 139,900 141,000 145,700 145,700 141,000 145,700 0 0 0 0 0 1,000,000 77 Withdrawn Vol Rec 0 0 0 0 0 0 0 0 0 280,000 280,000 440,000 1,000,000 78 Withdrawn Fuel Loss 0 0 0 0 0 0 0 0 0 0 0 0 0 79 Withdrawn Vol Del 0 0 0 0 0 0 0 0 0 280,000 280,000 440,000 1,000,000 80 Ending Inv Vol 141,000 280,900 421,900 567,600 713,300 854,300 1,000,000 1,000,000 1,000,000 720,000 440,000 0 81 82 Storage Total Beginning Inv Vol 1,875,000 2,804,668 4,809,378 7,244,642 9,513,827 11,790,006 13,992,752 15,756,926 14,830,759 12,315,870 8,505,433 4,812,669 83 Injected Vol Rec 939,164 2,024,339 2,461,597 2,292,145 2,299,134 2,224,955 1,779,929 0 0 0 0 0 14,021,264 84 Injected Fuel Loss 9,496 19,629 26,334 22,960 22,955 22,209 15,755 0 0 0 0 0 139,338 85 Injected Vol Del 929,668 2,004,711 2,435,264 2,269,185 2,276,179 2,202,746 1,764,174 0 0 0 0 0 13,881,926 86 Withdrawn Vol Rec 0 0 0 0 0 0 0 926,167 2,514,889 3,810,437 3,692,763 2,937,670 13,881,926 87 Withdrawn Fuel Loss 0 0 0 0 0 0 0 1,750 5,575 7,800 7,109 4,749 26,983 88 Withdrawn Vol Del 0 0 0 0 0 0 0 924,417 2,509,314 3,802,637 3,685,654 2,932,921 13,854,943 89 Ending Inv Vol 2,804,668 4,809,378 7,244,642 9,513,827 11,790,006 13,992,752 15,756,926 14,830,759 12,315,870 8,505,433 4,812,669 1,875,000
WEF 17-18 GCR Exhibits v0 Dec Filing Exhibit A-7 Page 1 of 5 Case No. U-18157
1 SEMCO Energy Gas Company 2 Average Day Supply Purchase Plan 3 (Quantities in Dth) 4 5 2017-2018 Apr May Jun Jul Aug Sep Oct Nov Dec Jan Feb Mar Total 6 GCR Demand 2,857,800 1,514,288 849,480 747,007 720,843 916,290 2,254,010 3,954,480 5,958,324 6,990,097 6,110,160 4,936,254 37,809,033 7 8 Fuel Consumed 9 Pipeline Transport 94,893 95,663 90,939 89,227 89,051 88,242 99,617 97,816 109,500 108,081 83,568 67,256 1,113,853 10 Storage Injections 9,496 19,629 26,334 22,960 22,955 22,209 15,755 0 0 0 0 0 139,338 11 Storage Withdrawals 0 0 0 0 0 0 0 1,750 5,575 7,800 7,109 4,749 26,983 12 Total Fuel 104,389 115,292 117,273 112,187 112,006 110,451 115,372 99,566 115,075 115,881 90,677 72,005 1,280,173 13 14 Storage Injections 15 ANR PL STG 187,658 262,838 371,415 384,588 385,932 375,000 382,570 0 0 0 0 0 2,350,000 16 ANR STG CO 79,783 83,700 77,848 79,648 78,297 74,246 60,405 0 0 0 0 0 533,926 17 BWGS 141,000 139,900 141,000 145,700 145,700 141,000 145,700 0 0 0 0 0 1,000,000 18 COLLINS 58,400 182,900 177,000 182,900 182,900 177,000 182,900 0 0 0 0 0 1,144,000 19 ERGS 300,138 915,862 1,080,000 837,000 837,000 810,000 403,000 0 0 0 0 0 5,183,000 20 LACEY 0 0 0 31,750 38,750 37,500 0 0 0 0 0 0 108,000 21 LEE 65,290 159,110 156,000 161,200 161,200 156,000 161,200 0 0 0 0 0 1,020,000 22 MORTON 97,400 260,400 252,000 260,400 260,400 252,000 260,400 0 0 0 0 0 1,643,000 23 NNG 0 0 180,000 186,000 186,000 180,000 168,000 0 0 0 0 0 900,000 24 Total Injections 929,668 2,004,711 2,435,264 2,269,185 2,276,179 2,202,746 1,764,174 0 0 0 0 0 13,881,926 25 26 Total Requirements 3,891,857 3,634,290 3,402,016 3,128,379 3,109,028 3,229,487 4,133,556 4,054,046 6,073,399 7,105,978 6,200,837 5,008,259 52,971,132 27 28 Supply 29 ANR CG GRP1 260,496 70,257 0 0 0 0 238,395 0 0 0 0 0 569,149 30 ANRSE HS 340,575 351,928 152,824 0 0 0 351,928 373,438 385,886 385,886 348,542 385,886 3,076,891 31 ANRSE SHELBY 338,682 349,972 338,682 151,323 134,746 300,417 349,972 371,362 383,741 383,741 346,605 383,741 3,832,983 32 ANRSW HS 1,256,854 1,298,749 1,256,854 1,298,749 1,298,749 1,256,854 1,298,749 1,323,988 1,185,396 809,520 420,116 540,734 13,245,309 33 BWGS CG 143,075 141,958 143,075 147,844 147,844 143,075 147,844 0 0 0 0 0 1,014,713 34 GLGT CG 220,553 239,456 303,000 313,100 313,100 303,000 298,627 0 0 0 0 0 1,990,836 35 GLGTC 308,960 319,259 308,960 319,259 319,259 308,960 319,259 309,966 954,569 954,569 862,191 351,841 5,637,049 36 LOCAL PR 8,400 8,680 8,400 8,680 8,680 8,400 8,680 8,400 8,680 8,680 7,840 8,680 102,200 37 NNG 429,067 249,814 305,927 285,953 283,179 324,386 516,286 235,468 399,881 380,859 320,616 237,811 3,969,248 38 PEPL 579,695 599,018 579,695 598,772 598,772 579,695 599,018 505,259 240,358 372,286 202,164 161,897 5,616,628 39 VECTOR CG 5,500 5,200 4,600 4,700 4,700 4,700 4,800 0 0 0 0 0 34,200 40 Total Supply 3,891,857 3,634,290 3,402,016 3,128,379 3,109,028 3,229,487 4,133,556 3,127,879 3,558,510 3,295,541 2,508,073 2,070,589 39,089,206 41 42 Storage Withdrawals 43 ANR PL STG 0 0 0 0 0 0 0 194,864 471,753 647,300 593,567 442,517 2,350,000 44 ANR STG CO 0 0 0 0 0 0 0 0 0 0 266,963 266,963 533,926 45 BWGS 0 0 0 0 0 0 0 0 0 280,000 280,000 440,000 1,000,000 46 COLLINS 0 0 0 0 0 0 0 94,861 229,653 315,111 288,953 215,421 1,144,000 47 ERGS 0 0 0 0 0 0 0 350,000 1,115,000 1,560,000 1,315,000 843,000 5,183,000 48 LACEY 0 0 0 0 0 0 0 0 0 0 54,000 54,000 108,000 49 LEE 0 0 0 0 0 0 0 85,204 204,657 280,468 257,288 192,383 1,020,000 50 MORTON 0 0 0 0 0 0 0 136,239 329,826 452,559 414,992 309,385 1,643,000 51 NNG 0 0 0 0 0 0 0 65,000 164,000 275,000 222,000 174,000 900,000 52 Total Withdrawals 0 0 0 0 0 0 0 926,167 2,514,889 3,810,437 3,692,763 2,937,670 13,881,926 53 54 Total Supply 3,891,857 3,634,290 3,402,016 3,128,379 3,109,028 3,229,487 4,133,556 4,054,046 6,073,399 7,105,978 6,200,837 5,008,259 52,971,132
WEF 17-18 GCR Exhibits v0 Dec Filing Exhibit A-7 Page 2 of 5 Case No. U-18157
1 SEMCO Energy Gas Company 2 Average Day Supply Purchase Plan 3 (Quantities in Dth) 4 5 2018-2019 Apr May Jun Jul Aug Sep Oct Nov Dec Jan Feb Mar Total 6 GCR Demand 2,969,130 1,568,228 856,680 753,858 738,389 903,090 2,262,752 4,037,460 6,022,246 7,064,714 6,183,184 4,972,989 38,332,720 7 8 Fuel Consumed 9 Pipeline Transport 95,596 95,980 91,045 89,280 89,188 88,058 98,861 98,892 111,228 109,422 85,762 66,575 1,119,886 10 Storage Injections 10,334 19,288 26,334 22,969 22,974 22,233 15,207 0 0 0 0 0 139,338 11 Storage Withdrawals 0 0 0 0 0 0 0 1,750 5,575 7,800 7,109 4,749 26,983 12 Total Fuel 105,930 115,268 117,379 112,249 112,162 110,290 114,068 100,642 116,803 117,222 92,871 71,324 1,286,206 13 14 Storage Injections 15 ANR PL STG 259,436 294,348 371,415 382,123 380,779 368,503 293,396 0 0 0 0 0 2,350,000 16 ANR STG CO 57,493 68,511 77,848 82,124 83,475 80,775 83,700 0 0 0 0 0 533,926 17 BWGS 141,000 139,900 141,000 145,700 145,700 141,000 145,700 0 0 0 0 0 1,000,000 18 COLLINS 67,600 177,060 177,000 182,900 182,900 177,000 179,540 0 0 0 0 0 1,144,000 19 ERGS 329,219 886,781 1,080,000 837,000 837,000 810,000 403,000 0 0 0 0 0 5,183,000 20 LACEY 0 0 0 31,750 38,750 37,500 0 0 0 0 0 0 108,000 21 LEE 63,200 161,200 156,000 161,200 161,200 156,000 161,200 0 0 0 0 0 1,020,000 22 MORTON 97,400 260,400 252,000 260,400 260,400 252,000 260,400 0 0 0 0 0 1,643,000 23 NNG 0 0 180,000 186,000 186,000 180,000 168,000 0 0 0 0 0 900,000 24 Total Injections 1,015,348 1,988,200 2,435,264 2,269,197 2,276,204 2,202,778 1,694,936 0 0 0 0 0 13,881,926 25 26 Total Requirements 4,090,407 3,671,696 3,409,322 3,135,304 3,126,755 3,216,158 4,071,756 4,138,102 6,139,049 7,181,936 6,276,055 5,044,313 53,500,852 27 28 Supply 29 ANR CG GRP1 421,941 81,860 0 0 0 0 168,177 0 0 0 0 0 671,978 30 ANRAL FPP 340,575 351,928 159,135 0 0 0 351,928 373,438 385,886 385,886 348,542 385,886 3,083,201 31 ANRAL SPOT 338,682 349,972 338,682 157,212 149,951 289,140 349,972 371,362 383,741 383,741 346,605 383,741 3,842,800 32 ANRSE FPP 1,256,854 1,298,749 1,256,854 1,298,749 1,298,749 1,256,854 1,298,749 1,323,988 1,321,216 1,086,642 542,541 573,330 13,813,271 33 ANRSE SPOT 143,075 141,958 143,075 147,844 147,844 143,075 147,844 0 0 0 0 0 1,014,713 34 ANRSW SPOT 241,159 256,377 303,000 313,100 313,100 303,000 305,736 0 0 0 0 0 2,035,472 35 BWGS CG 308,960 319,259 308,960 319,259 319,259 308,960 319,259 233,392 954,569 954,569 862,191 233,135 5,441,769 36 GLGT CG 8,400 8,680 8,400 8,680 8,680 8,400 8,680 8,400 8,680 8,680 7,840 8,680 102,200 37 GLGTC SPOT 445,566 258,697 306,922 286,795 285,455 322,335 517,595 360,206 408,172 390,085 329,343 359,976 4,271,147 38 LOCAL PROD 579,695 599,018 579,695 598,966 599,018 579,695 599,018 541,149 161,897 161,897 146,229 161,897 5,308,175 39 NNG SPOT 5,500 5,200 4,600 4,700 4,700 4,700 4,800 0 0 0 0 0 34,200 42 Total Supply 4,090,407 3,671,696 3,409,322 3,135,304 3,126,755 3,216,158 4,071,756 3,211,934 3,624,160 3,371,499 2,583,291 2,106,643 39,618,927 43 44 Storage Withdrawals 45 ANR PL STG 0 0 0 0 0 0 0 194,864 471,753 647,300 593,567 442,517 2,350,000 46 ANR STG CO 0 0 0 0 0 0 0 0 0 0 266,963 266,963 533,926 47 BWGS 0 0 0 0 0 0 0 0 0 280,000 280,000 440,000 1,000,000 48 COLLINS 0 0 0 0 0 0 0 94,861 229,653 315,111 288,953 215,421 1,144,000 49 ERGS 0 0 0 0 0 0 0 350,000 1,115,000 1,560,000 1,315,000 843,000 5,183,000 50 LACEY 0 0 0 0 0 0 0 0 0 0 54,000 54,000 108,000 51 LEE 0 0 0 0 0 0 0 85,204 204,657 280,468 257,288 192,383 1,020,000 52 MORTON 0 0 0 0 0 0 0 136,239 329,826 452,559 414,992 309,385 1,643,000 53 NNG 0 0 0 0 0 0 0 65,000 164,000 275,000 222,000 174,000 900,000 54 Total Withdrawals 0 0 0 0 0 0 0 926,167 2,514,889 3,810,437 3,692,763 2,937,670 13,881,926 55 56 Total Supply 4,090,407 3,671,696 3,409,322 3,135,304 3,126,755 3,216,158 4,071,756 4,138,102 6,139,049 7,181,936 6,276,055 5,044,313 53,500,853
WEF 17-18 GCR Exhibits v0 Dec Filing Exhibit A-7 Page 3 of 5 Case No. U-18157
1 SEMCO Energy Gas Company 2 Average Day Supply Purchase Plan 3 (Quantities in Dth) 4 5 2019-2020 Apr May Jun Jul Aug Sep Oct Nov Dec Jan Feb Mar Total 6 GCR Demand 2,968,590 1,588,440 854,880 774,349 745,395 904,380 2,279,213 4,038,000 6,042,613 7,089,731 6,247,789 4,969,331 38,502,711 7 8 Fuel Consumed 9 Pipeline Transport 94,906 95,998 91,001 89,563 89,220 88,096 99,513 98,913 111,933 110,288 87,172 66,464 1,123,066 10 Storage Injections 10,572 18,394 26,341 22,966 22,958 22,222 15,884 0 0 0 0 0 139,338 11 Storage Withdrawals 0 0 0 0 0 0 0 1,750 5,575 7,800 7,109 4,749 26,983 12 Total Fuel 105,478 114,392 117,342 112,529 112,178 110,318 115,397 100,663 117,508 118,088 94,281 71,213 1,289,387 13 14 Storage Injections 15 ANR PL STG 178,834 294,406 369,399 382,795 385,036 371,415 368,115 0 0 0 0 0 2,350,000 16 ANR STG CO 57,485 77,413 79,874 81,449 79,197 77,848 80,660 0 0 0 0 0 533,926 17 BWGS 141,000 139,900 141,000 145,700 145,700 141,000 145,700 0 0 0 0 0 1,000,000 18 COLLINS 62,400 178,900 177,000 182,900 182,900 177,000 182,900 0 0 0 0 0 1,144,000 19 ERGS 395,640 820,360 1,080,000 837,000 837,000 810,000 403,000 0 0 0 0 0 5,183,000 20 LACEY 0 0 0 38,750 31,750 37,500 0 0 0 0 0 0 108,000 21 LEE 63,200 161,200 156,000 161,200 161,200 156,000 161,200 0 0 0 0 0 1,020,000 22 MORTON 97,400 260,400 252,000 260,400 260,400 252,000 260,400 0 0 0 0 0 1,643,000 23 NNG 0 0 180,000 186,000 186,000 180,000 168,000 0 0 0 0 0 900,000 24 Total Injections 995,959 1,932,578 2,435,274 2,276,194 2,269,183 2,202,764 1,769,975 0 0 0 0 0 13,881,926 25 26 Total Requirements 4,070,026 3,635,411 3,407,496 3,163,072 3,126,756 3,217,461 4,164,585 4,138,663 6,160,121 7,207,819 6,342,070 5,040,544 53,674,024 27 28 Supply 29 ANR CG GRP1 448,789 42,065 0 0 0 0 251,273 0 0 0 0 0 742,126 30 ANRAL FPP 340,575 351,928 157,580 0 0 0 351,928 373,438 385,886 385,886 360,990 385,886 3,094,095 31 ANRAL SPOT 338,682 349,972 338,682 182,310 149,080 290,322 349,972 371,362 383,741 383,741 358,983 383,741 3,880,588 32 ANRSE FPP 1,256,854 1,298,749 1,256,854 1,298,749 1,298,749 1,256,854 1,298,749 1,323,988 1,339,919 1,109,626 547,338 570,531 13,856,956 33 ANRSE SPOT 143,075 141,958 143,075 147,844 147,844 143,075 147,844 0 0 0 0 0 1,014,713 34 ANRSW SPOT 194,112 256,676 303,000 313,100 313,100 303,000 313,100 0 0 0 0 0 1,996,088 35 BWGS CG 308,960 319,259 308,960 319,259 319,259 308,960 319,259 233,824 954,569 954,569 892,984 232,975 5,472,834 36 GLGT CG 8,400 8,680 8,400 8,680 8,680 8,400 8,680 8,400 8,680 8,680 8,120 8,680 102,480 37 GLGTC SPOT 445,385 261,907 306,651 289,413 286,327 322,456 519,964 360,116 410,541 392,984 329,440 359,165 4,284,349 38 LOCAL PROD 579,695 599,018 579,695 599,018 599,018 579,695 599,018 541,369 161,897 161,897 151,452 161,897 5,313,669 39 NNG SPOT 5,500 5,200 4,600 4,700 4,700 4,700 4,800 0 0 0 0 0 34,200 42 Total Supply 4,070,026 3,635,411 3,407,496 3,163,072 3,126,756 3,217,461 4,164,585 3,212,496 3,645,232 3,397,382 2,649,307 2,102,874 39,792,098 43 44 Storage Withdrawals 45 ANR PL STG 0 0 0 0 0 0 0 194,864 471,753 647,300 593,567 442,517 2,350,000 46 ANR STG CO 0 0 0 0 0 0 0 0 0 0 266,963 266,963 533,926 47 BWGS 0 0 0 0 0 0 0 0 0 280,000 280,000 440,000 1,000,000 48 COLLINS 0 0 0 0 0 0 0 94,861 229,653 315,111 288,953 215,421 1,144,000 49 ERGS 0 0 0 0 0 0 0 350,000 1,115,000 1,560,000 1,315,000 843,000 5,183,000 50 LACEY 0 0 0 0 0 0 0 0 0 0 54,000 54,000 108,000 51 LEE 0 0 0 0 0 0 0 85,204 204,657 280,468 257,288 192,383 1,020,000 52 MORTON 0 0 0 0 0 0 0 136,239 329,826 452,559 414,992 309,385 1,643,000 53 NNG 0 0 0 0 0 0 0 65,000 164,000 275,000 222,000 174,000 900,000 54 Total Withdrawals 0 0 0 0 0 0 0 926,167 2,514,889 3,810,437 3,692,763 2,937,670 13,881,926 55 56 Total Supply 4,070,026 3,635,411 3,407,496 3,163,072 3,126,756 3,217,461 4,164,585 4,138,663 6,160,121 7,207,819 6,342,070 5,040,544 53,674,024
WEF 17-18 GCR Exhibits v0 Dec Filing Exhibit A-7 Page 4 of 5 Case No. U-18157
1 SEMCO Energy Gas Company 2 Average Day Supply Purchase Plan 3 (Quantities in Dth) 4 5 2020-2021 Apr May Jun Jul Aug Sep Oct Nov Dec Jan Feb Mar Total 6 GCR Demand 2,982,720 1,592,284 861,930 767,064 742,543 875,850 2,286,901 4,010,310 6,034,677 7,126,993 6,259,428 4,984,614 38,525,314 7 8 Fuel Consumed 9 Pipeline Transport 94,666 96,127 91,142 89,505 89,250 87,719 99,633 98,125 111,675 111,580 88,403 66,969 1,124,794 10 Storage Injections 9,157 19,657 26,326 22,961 22,965 22,233 16,040 0 0 0 0 0 139,338 11 Storage Withdrawals 0 0 0 0 0 0 0 1,750 5,575 7,800 7,109 4,749 26,983 12 Total Fuel 103,823 115,785 117,467 112,465 112,215 109,952 115,673 99,875 117,250 119,380 95,512 71,718 1,291,114 13 14 Storage Injections 15 ANR PL STG 149,575 309,224 373,656 384,364 383,227 368,503 381,451 0 0 0 0 0 2,350,000 16 ANR STG CO 64,233 69,635 75,597 79,873 81,014 80,775 82,799 0 0 0 0 0 533,926 17 BWGS 141,000 139,900 141,000 145,700 145,700 141,000 145,700 0 0 0 0 0 1,000,000 18 COLLINS 58,400 182,900 177,000 182,900 182,900 177,000 182,900 0 0 0 0 0 1,144,000 19 ERGS 315,316 900,684 1,080,000 837,000 837,000 810,000 403,000 0 0 0 0 0 5,183,000 20 LACEY 0 0 0 38,750 38,750 30,500 0 0 0 0 0 0 108,000 21 LEE 63,200 161,200 156,000 161,200 161,200 156,000 161,200 0 0 0 0 0 1,020,000 22 MORTON 97,400 260,400 252,000 260,400 260,400 252,000 260,400 0 0 0 0 0 1,643,000 23 NNG 0 0 180,000 186,000 186,000 180,000 168,000 0 0 0 0 0 900,000 24 Total Injections 889,124 2,023,943 2,435,253 2,276,186 2,276,192 2,195,778 1,785,451 0 0 0 0 0 13,881,926 25 26 Total Requirements 3,975,667 3,732,012 3,414,650 3,155,716 3,130,950 3,181,580 4,188,025 4,110,185 6,151,927 7,246,373 6,354,940 5,056,332 53,698,354 27 28 Supply 29 ANR CG GRP1 359,646 137,355 0 0 0 0 273,559 0 0 0 0 0 770,560 30 ANRAL FPP 340,575 351,928 163,799 0 0 0 351,928 373,438 385,886 385,886 348,542 385,886 3,087,866 31 ANRAL SPOT 338,682 349,972 338,682 175,920 153,647 258,845 349,972 371,362 383,741 383,741 346,605 383,741 3,834,909 32 ANRSE FPP 1,256,854 1,298,749 1,256,854 1,298,749 1,298,749 1,256,854 1,298,749 1,323,988 1,333,158 1,143,910 612,643 584,192 13,963,446 33 ANRSE SPOT 143,075 141,958 143,075 147,844 147,844 143,075 147,844 0 0 0 0 0 1,014,713 34 ANRSW SPOT 186,905 257,488 303,000 313,100 313,100 303,000 313,100 0 0 0 0 0 1,989,693 35 BWGS CG 308,960 319,259 308,960 319,259 319,259 308,960 319,259 213,402 954,569 954,569 862,191 233,294 5,421,939 36 GLGT CG 8,400 8,680 8,400 8,680 8,680 8,400 8,680 8,400 8,680 8,680 7,840 8,680 102,200 37 GLGTC SPOT 447,376 262,406 307,586 288,447 285,953 318,052 521,117 356,165 409,107 397,254 338,127 360,973 4,292,562 38 LOCAL PROD 579,695 599,018 579,695 599,018 599,018 579,695 599,018 537,264 161,897 161,897 146,229 161,897 5,304,341 39 NNG SPOT 5,500 5,200 4,600 4,700 4,700 4,700 4,800 0 0 0 0 0 34,200 42 Total Supply 3,975,667 3,732,012 3,414,650 3,155,716 3,130,950 3,181,580 4,188,025 3,184,017 3,637,038 3,435,935 2,662,177 2,118,663 39,816,429 43 44 Storage Withdrawals 45 ANR PL STG 0 0 0 0 0 0 0 194,864 471,753 647,300 593,567 442,517 2,350,000 46 ANR STG CO 0 0 0 0 0 0 0 0 0 0 266,963 266,963 533,926 47 BWGS 0 0 0 0 0 0 0 0 0 280,000 280,000 440,000 1,000,000 48 COLLINS 0 0 0 0 0 0 0 94,861 229,653 315,111 288,953 215,421 1,144,000 49 ERGS 0 0 0 0 0 0 0 350,000 1,115,000 1,560,000 1,315,000 843,000 5,183,000 50 LACEY 0 0 0 0 0 0 0 0 0 0 54,000 54,000 108,000 51 LEE 0 0 0 0 0 0 0 85,204 204,657 280,468 257,288 192,383 1,020,000 52 MORTON 0 0 0 0 0 0 0 136,239 329,826 452,559 414,992 309,385 1,643,000 53 NNG 0 0 0 0 0 0 0 65,000 164,000 275,000 222,000 174,000 900,000 54 Total Withdrawals 0 0 0 0 0 0 0 926,167 2,514,889 3,810,437 3,692,763 2,937,670 13,881,926 55 56 Total Supply 3,975,667 3,732,012 3,414,650 3,155,716 3,130,950 3,181,580 4,188,025 4,110,185 6,151,927 7,246,373 6,354,940 5,056,332 53,698,355
WEF 17-18 GCR Exhibits v0 Dec Filing Exhibit A-7 Page 5 of 5 Case No. U-18157
1 SEMCO Energy Gas Company 2 Average Day Supply Purchase Plan 3 (Quantities in Dth) 4 5 2021-2022 Apr May Jun Jul Aug Sep Oct Nov Dec Jan Feb Mar Total 6 GCR Demand 3,028,950 1,600,530 866,820 761,856 743,814 887,490 2,296,728 4,051,410 6,097,669 7,166,580 6,273,624 5,033,222 38,808,693 7 8 Fuel Consumed 9 Pipeline Transport 95,179 96,289 91,209 89,450 89,282 87,872 98,953 99,310 113,906 112,948 88,901 68,569 1,131,868 10 Storage Injections 10,718 19,142 26,326 22,961 22,956 22,215 15,020 0 0 0 0 0 139,338 11 Storage Withdrawals 0 0 0 0 0 0 0 1,750 5,575 7,800 7,109 4,749 26,983 12 Total Fuel 105,897 115,431 117,534 112,411 112,237 110,087 113,973 101,060 119,481 120,748 96,010 73,317 1,298,188 13 14 Storage Injections 15 ANR PL STG 205,290 327,354 373,656 384,140 385,708 373,432 300,420 0 0 0 0 0 2,350,000 16 ANR STG CO 78,661 77,171 75,597 80,098 78,522 75,822 68,056 0 0 0 0 0 533,926 17 BWGS 135,200 145,700 141,000 145,700 145,700 141,000 145,700 0 0 0 0 0 1,000,000 18 COLLINS 58,400 182,900 177,000 182,900 182,900 177,000 182,900 0 0 0 0 0 1,144,000 19 ERGS 375,853 843,297 1,080,000 837,000 837,000 810,000 399,850 0 0 0 0 0 5,183,000 20 LACEY 0 0 0 38,750 38,750 30,500 0 0 0 0 0 0 108,000 21 LEE 63,200 161,200 156,000 161,200 161,200 156,000 161,200 0 0 0 0 0 1,020,000 22 MORTON 97,500 260,300 252,000 260,400 260,400 252,000 260,400 0 0 0 0 0 1,643,000 23 NNG 0 0 180,000 186,000 186,000 180,000 168,000 0 0 0 0 0 900,000 24 Total Injections 1,014,104 1,997,922 2,435,253 2,276,187 2,276,180 2,195,754 1,686,526 0 0 0 0 0 13,881,926 25 26 Total Requirements 4,148,951 3,713,883 3,419,607 3,150,455 3,132,231 3,193,330 4,097,227 4,152,470 6,217,150 7,287,328 6,369,634 5,106,539 53,988,807 27 28 Supply 29 ANR CG GRP1 486,585 96,040 0 0 0 0 204,871 0 0 0 0 0 787,496 30 ANRAL FPP 340,575 351,928 167,640 0 0 0 351,928 373,438 385,886 385,886 348,542 385,886 3,091,707 31 ANRAL SPOT 338,682 349,972 338,682 170,970 154,368 268,243 349,972 371,362 383,741 383,741 346,605 383,741 3,840,078 32 ANRSE FPP 1,256,854 1,298,749 1,256,854 1,298,749 1,298,749 1,256,854 1,298,749 1,323,988 1,368,121 1,180,221 625,901 627,267 14,091,053 33 ANRSE SPOT 137,189 147,844 143,075 147,844 147,844 143,075 147,844 0 0 0 0 0 1,014,713 34 ANRSW SPOT 232,349 273,542 303,000 313,100 313,100 303,000 288,684 0 0 0 0 0 2,026,776 35 BWGS CG 308,960 319,259 308,960 319,259 319,259 308,960 319,259 241,610 954,569 954,569 862,191 234,380 5,451,232 36 GLGT CG 8,400 8,680 8,400 8,680 8,680 8,400 8,680 8,400 8,680 8,680 7,840 8,680 102,200 37 GLGTC SPOT 454,162 263,653 308,702 288,135 286,514 320,405 523,423 362,408 418,551 401,898 339,562 367,020 4,334,434 38 LOCAL PROD 579,695 599,018 579,695 599,018 599,018 579,695 599,018 545,098 182,714 161,897 146,229 161,897 5,332,992 39 NNG SPOT 5,500 5,200 4,600 4,700 4,700 4,700 4,800 0 0 0 0 0 34,200 42 Total Supply 4,148,952 3,713,883 3,419,607 3,150,455 3,132,231 3,193,331 4,097,227 3,226,303 3,702,261 3,476,891 2,676,871 2,168,870 40,106,882 43 44 Storage Withdrawals 45 ANR PL STG 0 0 0 0 0 0 0 194,864 471,753 647,300 593,567 442,517 2,350,000 46 ANR STG CO 0 0 0 0 0 0 0 0 0 0 266,963 266,963 533,926 47 BWGS 0 0 0 0 0 0 0 0 0 280,000 280,000 440,000 1,000,000 48 COLLINS 0 0 0 0 0 0 0 94,861 229,653 315,111 288,953 215,421 1,144,000 49 ERGS 0 0 0 0 0 0 0 350,000 1,115,000 1,560,000 1,315,000 843,000 5,183,000 50 LACEY 0 0 0 0 0 0 0 0 0 0 54,000 54,000 108,000 51 LEE 0 0 0 0 0 0 0 85,204 204,657 280,468 257,288 192,383 1,020,000 52 MORTON 0 0 0 0 0 0 0 136,239 329,826 452,559 414,992 309,385 1,643,000 53 NNG 0 0 0 0 0 0 0 65,000 164,000 275,000 222,000 174,000 900,000 54 Total Withdrawals 0 0 0 0 0 0 0 926,167 2,514,889 3,810,437 3,692,763 2,937,670 13,881,926 55 56 Total Supply 4,148,952 3,713,883 3,419,607 3,150,455 3,132,231 3,193,331 4,097,227 4,152,470 6,217,150 7,287,328 6,369,634 5,106,539 53,988,808
WEF 17-18 GCR Exhibits v0 Dec Filing Exhibit A-8 Page 1 of 1 Case No. U-18157
SEMCO Energy Gas Company Design Day Supply Plan (Quantities in Dth)
2016-2017 Planned Average Day Supply (GCR) Design Day Supply Plan (GCR+GCC)
1 31 28 31 31 28 31 2 Supply Source Jan Feb Mar Supply Source Jan Feb Mar 3 4 Pipeline Source Pipeline Source 5 GLGTC 29,994 29,835 10,931 GLGTC 30,000 30,000 30,000 6 ANR - SE Shelby 12,250 12,250 12,250 ANR - SE Shelby 12,250 12,250 12,250 7 ANR - SE HS 12,250 12,250 12,250 ANR - SE HS 12,250 12,250 12,250 8 ANR - SW HS 25,147 14,449 16,798 ANR - SW HS 42,500 42,500 42,500 9 PEPL 11,498 6,913 5,000 PEPL 18,500 18,500 18,500 10 NNG 12,131 11,305 7,559 NNG 24,425 26,258 32,628 11 LOCAL PRODUCTION 280 280 280 LOCAL PRODUCTION 280 280 280 Design Day Peaking Supply 31 28 31 12 GLGTC CG 0 0 0 GLGTC CG 0 1,908 0 Jan Feb Mar 13 Total Delivered 103,550 87,282 65,067 Total Delivered 140,205 143,946 148,408 Peaking Supply Requirements 36,655 56,665 83,341 14 Less NNG SMS (6,000) (6,000) (6,000) 15 Adj Peaking Requirements 30,655 50,665 77,341 16 Storage Source Storage Source 17 SEMCO Collins Storage 10,165 10,320 6,949 SEMCO Collins Storage 18,500 14,800 12,000 DesignDay Qty 78,000 18 SEMCO Morton Storage 14,599 14,821 9,980 SEMCO Morton Storage 60,000 57,000 49,700 Days 7 19 SEMCO Lee Storage 9,047 9,189 6,206 SEMCO Lee Storage 12,600 12,600 12,600 Rate $0.0443 20 SEMCO Lacey Storage 0 1,929 1,742 SEMCO Lacey Storage 6,300 6,300 6,300 Total Cost $24,188 21 Eaton Rapids Storage 50,323 46,964 27,194 Eaton Rapids Storage 67,000 53,000 41,000 22 Bluewater Gas Stg 9,032 10,000 14,194 Bluewater Gas Stg 20,000 20,000 8,681 23 ANR Pipeline Storage 20,881 21,199 14,275 ANR Pipeline Storage 50,000 50,000 50,000 24 ANR Storage Co 0 9,534 8,612 ANR Storage Co 38,692 52,875 51,631 25 NNG 8,871 7,929 5,613 NNG 15,700 13,800 7,400 26 Total Received 122,917 131,884 94,764 Total Received 288,792 280,375 239,312 27 28 Fuel Adjustment (980) (946) (597) Fuel Adjustment (2,217) (2,282) (2,057) 29 30 Total Delivered Supply 225,487 218,220 159,234 Total Delivered Supply 426,780 422,039 385,663 31 32 GCR Daily Demand 225,487 218,220 159,234 Design Day Demand 426,780 422,039 385,663 33 check 0 0 0 check 0 0 0 34 35 Avg Day to Exp PD Swing 1.89 1.93 2.42 36 Weighted Avg Heating Degree Days 0.0 0.0 0.0
WEF 17-18 GCR Exhibits v0 Dec Filing Exhibit A-9 Page 1 of 3 Case No. U-18157
SEMCO Energy Gas Company Estimated Cost of Gas
2017-2018 Apr May Jun Jul Aug Sep Oct Nov Dec Jan Feb Mar Total 1 2 Supply Commodity Cost $12,456,489 $11,447,506 $10,760,378 $9,930,753 $9,839,203 $10,178,730 $13,221,204 $10,434,828 $12,462,162 $11,831,190 $8,907,957 $7,067,837 $128,538,236 3 Storage Commodity Cost $4,941 $6,015 $9,876 $10,190 $10,163 $9,805 $9,275 $3,424 $8,388 $12,253 $19,392 $16,774 $120,497 4 Transportation Comm. Cost $87,738 $84,102 $81,442 $77,097 $76,776 $78,612 $95,604 $92,419 $104,576 $112,828 $89,695 $75,614 $1,056,501 5 Total Commodity Costs $12,549,168 $11,537,623 $10,851,696 $10,018,040 $9,926,142 $10,267,147 $13,326,082 $10,530,671 $12,575,126 $11,956,271 $9,017,044 $7,160,225 $129,715,235 6 7 Wdl Storage Value $0 $0 $0 $0 $0 $0 $0 $2,970,572 $8,053,456 $12,282,132 $11,979,466 $9,610,462 $44,896,088 8 Inj Storage Value $3,130,402 $6,576,214 $8,053,370 $7,570,496 $7,571,852 $7,280,981 $5,879,708 $0 $0 $0 $0 $0 $46,063,022 9 Total Storage Inventory Value ($3,130,402) ($6,576,214) ($8,053,370) ($7,570,496) ($7,571,852) ($7,280,981) ($5,879,708) $2,970,572 $8,053,456 $12,282,132 $11,979,466 $9,610,462 ($1,166,934) 10 11 Storage Fixed Cost $631,033 $631,033 $631,033 $631,033 $631,033 $631,033 $631,033 $631,033 $631,033 $631,033 $631,033 $631,033 $7,572,401 12 Pipeline Transport Fixed Cost $1,490,106 $1,420,928 $1,418,976 $1,420,928 $1,420,928 $1,418,976 $1,493,766 $3,026,283 $3,038,483 $3,038,483 $3,001,883 $3,038,483 $25,228,221 13Est. Peaking Supply Fixed Cost $0 $0 $0 $0 $0 $0 $0 $0 $0 $8,063 $8,063 $8,063 $24,188 14 ANR Rabbit River Facility Demand Cost $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 15 NNG Marquette 1A Facility Demand Cost $0 $0 $0 $0 $0 $0 $0 $65,008 $65,008 $65,008 $65,008 $65,008 $325,038 16NNG Lake Linden Facility Demand Cost $0 $0 $0 $0 $0 $0 $0 $43,608 $43,608 $43,608 $43,608 $43,608 $218,042 17 Est. Capacity Release Credits ($43,333) ($43,333) ($43,333) ($43,333) ($43,333) ($43,333) ($43,333) ($43,333) ($43,333) ($43,333) ($43,333) ($43,333) ($520,000) 18 Est. UPFIC Credit (1) ($5,318) ($5,318) ($5,318) ($5,318) ($5,318) ($5,318) ($5,318) ($5,318) ($5,318) ($5,318) ($5,318) ($5,318) ($63,815) 19 Total Fixed Costs $2,072,489 $2,003,310 $2,001,358 $2,003,310 $2,003,310 $2,001,358 $2,076,149 $3,717,281 $3,729,481 $3,737,544 $3,700,944 $3,737,544 $32,784,076 20 21 Commodity Cost of Gas $9,418,766 $4,961,409 $2,798,326 $2,447,545 $2,354,290 $2,986,166 $7,446,375 $13,501,243 $20,628,581 $24,238,403 $20,996,510 $16,770,687 $128,548,301 22 Fixed Cost of Gas $2,072,489 $2,003,310 $2,001,358 $2,003,310 $2,003,310 $2,001,358 $2,076,149 $3,717,281 $3,729,481 $3,737,544 $3,700,944 $3,737,544 $32,784,076 23 Total Cost of Gas $11,491,255 $6,964,719 $4,799,684 $4,450,855 $4,357,600 $4,987,524 $9,522,523 $17,218,524 $24,358,062 $27,975,946 $24,697,453 $20,508,231 $161,332,377
(1) UPFIC - Upstream Pipeline Facility Improvement Charge Credit
SEMCO Energy Gas Company Estimated Cost of Gas
2018-2019 Apr May Jun Jul Aug Sep Oct Nov Dec Jan Feb Mar Total 1 2 Supply Commodity Cost $10,979,474 $9,539,412 $8,874,165 $8,168,814 $8,136,796 $8,337,684 $10,764,077 $9,154,099 $11,016,593 $10,603,381 $8,069,244 $6,341,884 $109,985,624 3 Storage Commodity Cost $5,126 $5,922 $9,876 $10,239 $10,265 $9,934 $8,904 $3,424 $8,388 $12,253 $19,392 $16,774 $120,497 4 Transportation Comm. Cost $89,191 $84,802 $81,605 $77,192 $77,026 $78,302 $94,627 $94,623 $104,400 $109,943 $90,241 $75,840 $1,057,793 5 Total Commodity Costs $11,073,791 $9,630,136 $8,965,646 $8,256,245 $8,224,088 $8,425,921 $10,867,608 $9,252,146 $11,129,381 $10,725,577 $8,178,878 $6,434,498 $111,163,913 6 7 Wdl Storage Value $0 $0 $0 $0 $0 $0 $0 $2,571,986 $6,986,366 $10,598,067 $10,292,771 $8,201,190 $38,650,379 8 Inj Storage Value $2,846,493 $5,373,161 $6,635,220 $6,213,862 $6,225,959 $5,987,908 $4,664,260 $0 $0 $0 $0 $0 $37,946,863 9 Total Storage Inventory Value ($2,846,493) ($5,373,161) ($6,635,220) ($6,213,862) ($6,225,959) ($5,987,908) ($4,664,260) $2,571,986 $6,986,366 $10,598,067 $10,292,771 $8,201,190 $703,517 10 11 Storage Fixed Cost $631,033 $631,033 $631,033 $631,033 $631,033 $631,033 $631,033 $631,033 $631,033 $631,033 $631,033 $631,033 $7,572,401 12 Pipeline Transport Fixed Cost $1,490,106 $1,420,928 $1,418,976 $1,420,928 $1,420,928 $1,418,976 $1,493,766 $3,262,439 $3,274,639 $3,274,639 $3,238,039 $3,274,639 $26,409,001 13Est. Peaking Supply Fixed Cost $0 $0 $0 $0 $0 $0 $0 $0 $0 $8,063 $8,063 $8,063 $24,188 14 ANR Rabbit River Facility Demand Cost $577,500 $577,500 $577,500 $577,500 $577,500 $577,500 $577,500 $577,500 $577,500 $577,500 $577,500 $577,500 $6,930,000 15 NNG Marquette 1A Facility Demand Cost $46,056 $46,056 $46,056 $46,056 $46,056 $46,056 $46,056 $65,008 $65,008 $65,008 $65,008 $65,008 $647,432 16 NNG Lake Linden Facility Demand Cost $30,895 $30,895 $30,895 $30,895 $30,895 $30,895 $30,895 $43,608 $43,608 $43,608 $43,608 $43,608 $434,310 17 Est. Capacity Release Credits ($43,333) ($43,333) ($43,333) ($43,333) ($43,333) ($43,333) ($43,333) ($43,333) ($43,333) ($43,333) ($43,333) ($43,333) ($520,000) 18 Est. UPFIC Credit (1) ($5,318) ($5,318) ($5,318) ($5,318) ($5,318) ($5,318) ($5,318) ($5,318) ($5,318) ($5,318) ($5,318) ($5,318) ($63,815) 19 Total Fixed Costs $2,726,940 $2,657,762 $2,655,810 $2,657,762 $2,657,762 $2,655,810 $2,730,600 $4,530,937 $4,543,137 $4,551,200 $4,514,600 $4,551,200 $41,433,518 20 21 Commodity Cost of Gas $8,227,298 $4,256,975 $2,330,426 $2,042,383 $1,998,129 $2,438,013 $6,203,347 $11,824,132 $18,115,747 $21,323,644 $18,471,649 $14,635,688 $111,867,430 22 Fixed Cost of Gas $2,726,940 $2,657,762 $2,655,810 $2,657,762 $2,657,762 $2,655,810 $2,730,600 $4,530,937 $4,543,137 $4,551,200 $4,514,600 $4,551,200 $41,433,518 23 Total Cost of Gas $10,954,238 $6,914,737 $4,986,235 $4,700,145 $4,655,891 $5,093,822 $8,933,948 $16,355,069 $22,658,884 $25,874,844 $22,986,248 $19,186,887 $153,300,948
(1) UPFIC - Upstream Pipeline Facility Improvement Charge Credit
WEF 17-18 GCR Exhibits v0 Dec Filing Exhibit A-9 Page 2 of 3 Case No. U-18157
SEMCO Energy Gas Company Estimated Cost of Gas
2019-2020 Apr May Jun Jul Aug Sep Oct Nov Dec Jan Feb Mar Total 1 2 Supply Commodity Cost $10,200,872 $8,991,312 $8,507,276 $7,958,540 $7,906,592 $8,153,311 $10,793,707 $9,016,979 $10,948,947 $10,607,477 $8,221,282 $6,273,886 $107,580,180 3 Storage Commodity Cost $4,110 $6,210 $9,916 $10,225 $10,181 $9,876 $9,747 $3,424 $8,388 $12,253 $19,392 $16,774 $120,497 4 Transportation Comm. Cost $88,256 $84,924 $81,541 $77,651 $77,096 $78,357 $95,577 $94,636 $104,903 $110,560 $91,452 $75,747 $1,060,701 5 Total Commodity Costs $10,293,238 $9,082,447 $8,598,733 $8,046,416 $7,993,869 $8,241,544 $10,899,031 $9,115,038 $11,062,238 $10,730,291 $8,332,126 $6,366,407 $108,761,378 6 7 Wdl Storage Value $0 $0 $0 $0 $0 $0 $0 $2,450,973 $6,654,013 $10,104,938 $9,826,061 $7,841,273 $36,877,257 8 Inj Storage Value $2,601,770 $4,972,881 $6,366,099 $6,018,371 $6,033,356 $5,853,977 $4,770,730 $0 $0 $0 $0 $0 $36,617,184 9 Total Storage Inventory Value ($2,601,770) ($4,972,881) ($6,366,099) ($6,018,371) ($6,033,356) ($5,853,977) ($4,770,730) $2,450,973 $6,654,013 $10,104,938 $9,826,061 $7,841,273 $260,073 10 11 Storage Fixed Cost $631,033 $631,033 $631,033 $631,033 $631,033 $631,033 $631,033 $631,033 $631,033 $631,033 $631,033 $631,033 $7,572,401 12 Pipeline Transport Fixed Cost $1,490,106 $1,420,928 $1,418,976 $1,420,928 $1,420,928 $1,418,976 $1,493,766 $3,262,439 $3,274,639 $3,274,639 $3,238,039 $3,274,639 $26,409,001 13Est. Peaking Supply Fixed Cost $0 $0 $0 $0 $0 $0 $0 $0 $0 $8,063 $8,063 $8,063 $24,188 14 ANR Rabbit River Facility Demand Cost $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 15 NNG Marquette 1A Facility Demand Cost $46,056 $46,056 $46,056 $46,056 $46,056 $46,056 $46,056 $0 $0 $0 $0 $0 $322,394 16 NNG Lake Linden Facility Demand Cost $30,895 $30,895 $30,895 $30,895 $30,895 $30,895 $30,895 $0 $0 $0 $0 $0 $216,268 17 Est. Capacity Release Credits ($43,333) ($43,333) ($43,333) ($43,333) ($43,333) ($43,333) ($43,333) ($43,333) ($43,333) ($43,333) ($43,333) ($43,333) ($520,000) 18 Est. UPFIC Credit (1) ($5,318) ($5,318) ($5,318) ($5,318) ($5,318) ($5,318) ($5,318) ($5,318) ($5,318) ($5,318) ($5,318) ($5,318) ($63,815) 19 Total Fixed Costs $2,149,440 $2,080,262 $2,078,310 $2,080,262 $2,080,262 $2,078,310 $2,153,100 $3,844,821 $3,857,021 $3,865,084 $3,828,484 $3,865,084 $33,960,438 20 21 Commodity Cost of Gas $7,691,468 $4,109,566 $2,232,634 $2,028,046 $1,960,513 $2,387,567 $6,128,300 $11,566,011 $17,716,250 $20,835,229 $18,158,187 $14,207,680 $109,021,451 22 Fixed Cost of Gas $2,149,440 $2,080,262 $2,078,310 $2,080,262 $2,080,262 $2,078,310 $2,153,100 $3,844,821 $3,857,021 $3,865,084 $3,828,484 $3,865,084 $33,960,438 23 Total Cost of Gas $9,840,908 $6,189,827 $4,310,944 $4,108,307 $4,040,775 $4,465,877 $8,281,401 $15,410,832 $21,573,271 $24,700,312 $21,986,670 $18,072,763 $142,981,889
(1) UPFIC - Upstream Pipeline Facility Improvement Charge Credit
SEMCO Energy Gas Company Estimated Cost of Gas
2020-2021 Apr May Jun Jul Aug Sep Oct Nov Dec Jan Feb Mar Total 1 2 Supply Commodity Cost $9,895,192 $9,240,510 $8,527,536 $7,949,909 $7,975,380 $8,139,204 $10,976,572 $9,049,731 $11,103,199 $10,970,065 $8,443,100 $6,473,462 $108,743,860 3 Storage Commodity Cost $3,959 $6,145 $9,832 $10,194 $10,217 $9,934 $9,984 $3,424 $8,388 $12,253 $19,392 $16,774 $120,497 4 Transportation Comm. Cost $87,995 $85,114 $81,749 $77,544 $77,125 $77,717 $95,775 $94,018 $104,699 $111,478 $92,121 $76,095 $1,061,430 5 Total Commodity Costs $9,987,146 $9,331,769 $8,619,116 $8,037,647 $8,062,722 $8,226,855 $11,082,331 $9,147,173 $11,216,286 $11,093,797 $8,554,614 $6,566,331 $109,925,787 6 7 Wdl Storage Value $0 $0 $0 $0 $0 $0 $0 $2,444,519 $6,634,201 $10,080,238 $9,806,131 $7,830,984 $36,796,074 8 Inj Storage Value $2,312,523 $5,210,603 $6,367,175 $6,026,415 $6,095,140 $5,893,905 $4,865,040 $0 $0 $0 $0 $0 $36,770,801 9 Total Storage Inventory Value ($2,312,523) ($5,210,603) ($6,367,175) ($6,026,415) ($6,095,140) ($5,893,905) ($4,865,040) $2,444,519 $6,634,201 $10,080,238 $9,806,131 $7,830,984 $25,273 10 11 Storage Fixed Cost $631,033 $631,033 $631,033 $631,033 $631,033 $631,033 $631,033 $631,033 $631,033 $631,033 $631,033 $631,033 $7,572,401 12 Pipeline Transport Fixed Cost $1,490,106 $1,420,928 $1,418,976 $1,420,928 $1,420,928 $1,418,976 $1,493,766 $3,262,439 $3,274,639 $3,274,639 $3,238,039 $3,274,639 $26,409,001 13Est. Peaking Supply Fixed Cost $0 $0 $0 $0 $0 $0 $0 $0 $0 $8,063 $8,063 $8,063 $24,188 14 ANR Rabbit River Facility Demand Cost $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 15 NNG Marquette 1A Facility Demand Cost $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 16NNG Lake Linden Facility Demand Cost $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 17 Est. Capacity Release Credits ($43,333) ($43,333) ($43,333) ($43,333) ($43,333) ($43,333) ($43,333) ($43,333) ($43,333) ($43,333) ($43,333) ($43,333) ($520,000) 18 Est. UPFIC Credit (1) ($5,318) ($5,318) ($5,318) ($5,318) ($5,318) ($5,318) ($5,318) ($5,318) ($5,318) ($5,318) ($5,318) ($5,318) ($63,815) 19 Total Fixed Costs $2,072,489 $2,003,310 $2,001,358 $2,003,310 $2,003,310 $2,001,358 $2,076,149 $3,844,821 $3,857,021 $3,865,084 $3,828,484 $3,865,084 $33,421,776 20 21 Commodity Cost of Gas $7,674,623 $4,121,167 $2,251,941 $2,011,232 $1,967,582 $2,332,950 $6,217,291 $11,591,692 $17,850,488 $21,174,034 $18,360,745 $14,397,316 $109,951,060 22 Fixed Cost of Gas $2,072,489 $2,003,310 $2,001,358 $2,003,310 $2,003,310 $2,001,358 $2,076,149 $3,844,821 $3,857,021 $3,865,084 $3,828,484 $3,865,084 $33,421,776 23 Total Cost of Gas $9,747,111 $6,124,477 $4,253,299 $4,014,542 $3,970,892 $4,334,308 $8,293,440 $15,436,513 $21,707,508 $25,039,118 $22,189,229 $18,262,399 $143,372,836
(1) UPFIC - Upstream Pipeline Facility Improvement Charge Credit
WEF 17-18 GCR Exhibits v0 Dec Filing Exhibit A-9 Page 3 of 3 Case No. U-18157
SEMCO Energy Gas Company Estimated Cost of Gas
2021-2022 Apr May Jun Jul Aug Sep Oct Nov Dec Jan Feb Mar Total 1 2 Supply Commodity Cost $10,437,235 $9,268,761 $8,610,324 $7,997,131 $8,045,788 $8,238,842 $10,816,847 $9,261,915 $11,424,905 $11,260,965 $8,615,923 $6,727,716 $110,706,350 3 Storage Commodity Cost $5,127 $6,617 $9,832 $10,199 $10,168 $9,836 $8,487 $3,424 $8,388 $12,253 $19,392 $16,774 $120,497 4 Transportation Comm. Cost $88,894 $85,370 $81,868 $77,460 $77,185 $77,994 $94,930 $94,997 $106,754 $112,456 $92,468 $77,211 $1,067,586 5 Total Commodity Costs $10,531,256 $9,360,749 $8,702,023 $8,084,789 $8,133,140 $8,326,672 $10,920,263 $9,360,336 $11,540,046 $11,385,674 $8,727,783 $6,821,701 $111,894,433 6 7 Wdl Storage Value $0 $0 $0 $0 $0 $0 $0 $2,460,183 $6,676,274 $10,145,378 $9,868,246 $7,881,382 $37,031,463 8 Inj Storage Value $2,661,363 $5,187,403 $6,418,981 $6,072,386 $6,145,824 $5,942,770 $4,631,573 $0 $0 $0 $0 $0 $37,060,300 9 Total Storage Inventory Value ($2,661,363) ($5,187,403) ($6,418,981) ($6,072,386) ($6,145,824) ($5,942,770) ($4,631,573) $2,460,183 $6,676,274 $10,145,378 $9,868,246 $7,881,382 ($28,836) 10 11 Storage Fixed Cost $631,033 $631,033 $631,033 $631,033 $631,033 $631,033 $631,033 $631,033 $631,033 $631,033 $631,033 $631,033 $7,572,401 12 Pipeline Transport Fixed Cost $1,490,106 $1,420,928 $1,418,976 $1,420,928 $1,420,928 $1,418,976 $1,493,766 $3,262,439 $3,274,639 $3,274,639 $3,238,039 $3,274,639 $26,409,001 13Est. Peaking Supply Fixed Cost $0 $0 $0 $0 $0 $0 $0 $0 $0 $8,063 $8,063 $8,063 $24,188 14 ANR Rabbit River Facility Demand Cost $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 15 NNG Marquette 1A Facility Demand Cost $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 16NNG Lake Linden Facility Demand Cost $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 17 Est. Capacity Release Credits ($43,333) ($43,333) ($43,333) ($43,333) ($43,333) ($43,333) ($43,333) ($43,333) ($43,333) ($43,333) ($43,333) ($43,333) ($520,000) 18 Est. UPFIC Credit (1) ($5,318) ($5,318) ($5,318) ($5,318) ($5,318) ($5,318) ($5,318) ($5,318) ($5,318) ($5,318) ($5,318) ($5,318) ($63,815) 19 Total Fixed Costs $2,072,489 $2,003,310 $2,001,358 $2,003,310 $2,003,310 $2,001,358 $2,076,149 $3,844,821 $3,857,021 $3,865,084 $3,828,484 $3,865,084 $33,421,776 20 21 Commodity Cost of Gas $7,869,893 $4,173,346 $2,283,042 $2,012,404 $1,987,316 $2,383,902 $6,288,690 $11,820,519 $18,216,320 $21,531,052 $18,596,029 $14,703,083 $111,865,597 22 Fixed Cost of Gas $2,072,489 $2,003,310 $2,001,358 $2,003,310 $2,003,310 $2,001,358 $2,076,149 $3,844,821 $3,857,021 $3,865,084 $3,828,484 $3,865,084 $33,421,776 23 Total Cost of Gas $9,942,381 $6,176,656 $4,284,400 $4,015,714 $3,990,626 $4,385,260 $8,364,838 $15,665,340 $22,073,340 $25,396,136 $22,424,513 $18,568,167 $145,287,372
(1) UPFIC - Upstream Pipeline Facility Improvement Charge Credit
WEF 17-18 GCR Exhibits v0 Dec Filing Exhibit A-10 Page 1 of 1 Case No. U-18157
SEMCO Energy Gas Company 2017-2022 NYMEX Price Forecast
1 Apr May Jun Jul Aug Sep Oct Nov Dec 2 Date 2017 2017 2017 2017 2017 2017 2017 2017 2017 3 12/7/2016 3.4340 3.3900 3.4050 3.4300 3.4200 3.3960 3.4140 3.4470 3.5670 4 12/6/2016 3.3790 3.3390 3.3570 3.3830 3.3740 3.3540 3.3720 3.4070 3.5320 5 12/5/2016 3.4040 3.3600 3.3770 3.4010 3.3920 3.3720 3.3900 3.4260 3.5530 6 12/2/2016 3.4280 3.3890 3.4050 3.4280 3.4190 3.4000 3.4190 3.4570 3.5830 7 12/1/2016 3.2920 3.2720 3.2940 3.3210 3.3130 3.2950 3.3150 3.3560 3.4870 8 Average 3.3874 3.3500 3.3676 3.3926 3.3836 3.3634 3.3820 3.4186 3.5444 9 10 Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec 11 Date 2018 2018 2018 2018 2018 2018 2018 2018 2018 2018 2018 2018 12 12/7/2016 3.6510 3.5890 3.4800 2.9240 2.8520 2.8640 2.8800 2.8780 2.8610 2.8860 2.9370 3.0660 13 12/6/2016 3.6190 3.5660 3.4570 2.9180 2.8440 2.8570 2.8750 2.8720 2.8540 2.8810 2.9320 3.0600 14 12/5/2016 3.6380 3.5860 3.4720 2.9050 2.8300 2.8430 2.8610 2.8580 2.8420 2.8710 2.9220 3.0510 15 12/2/2016 3.6660 3.6150 3.5030 2.9320 2.8570 2.8700 2.8890 2.8860 2.8710 2.8970 2.9470 3.0740 16 12/1/2016 3.5730 3.5230 3.4220 2.8840 2.8160 2.8320 2.8520 2.8490 2.8340 2.8600 2.9120 3.0400 17 Average 3.6294 3.5758 3.4668 2.9126 2.8398 2.8532 2.8714 2.8686 2.8524 2.8790 2.9300 3.0582 18 19 Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec 20 Date 2019 2019 2019 2019 2019 2019 2019 2019 2019 2019 2019 2019 21 12/7/2016 3.1620 3.1190 3.0580 2.7230 2.6980 2.7280 2.7620 2.7760 2.7750 2.8050 2.8690 3.0050 22 12/6/2016 3.1530 3.1110 3.0500 2.7150 2.6900 2.7200 2.7540 2.7680 2.7670 2.7970 2.8610 2.9970 23 12/5/2016 3.1760 3.1340 3.0760 2.7560 2.7310 2.7610 2.7950 2.8090 2.8080 2.8380 2.9000 3.0350 24 12/2/2016 3.1440 3.1040 3.0460 2.7360 2.7260 2.7570 2.7910 2.8050 2.8040 2.8340 2.8960 3.0320 25 12/1/2016 3.1450 3.1060 3.0530 2.7480 2.7380 2.7690 2.8030 2.8170 2.8160 2.8460 2.9080 3.0440 26 Average 3.1560 3.1148 3.0566 2.7356 2.7166 2.7470 2.7810 2.7950 2.7940 2.8240 2.8868 3.0226 27 28 Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec 29 Date 2020 2020 2020 2020 2020 2020 2020 2020 2020 2020 2020 2020 30 12/7/2016 3.1200 3.0780 3.0150 2.7150 2.7080 2.7400 2.7770 2.8060 2.8120 2.8450 2.9170 3.0650 31 12/6/2016 3.1090 3.0690 3.0060 2.7010 2.6940 2.7260 2.7630 2.7920 2.7980 2.8310 2.9020 3.0500 32 12/5/2016 3.1450 3.1030 3.0380 2.7280 2.7210 2.7530 2.7900 2.8190 2.8250 2.8580 2.9290 3.0770 33 12/2/2016 3.1420 3.1030 3.0380 2.7280 2.7230 2.7550 2.7920 2.8210 2.8270 2.8600 2.9310 3.0790 34 12/1/2016 3.1540 3.1160 3.0510 2.7360 2.7310 2.7630 2.8000 2.8290 2.8350 2.8680 2.9390 3.0870 35 Average 3.1340 3.0938 3.0296 2.7216 2.7154 2.7474 2.7844 2.8134 2.8194 2.8524 2.9236 3.0716 36 37 Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec 38 Date 2021 2021 2021 2021 2021 2021 2021 2021 2021 2021 2021 2021 39 12/7/2016 3.2020 3.1620 3.0990 2.7510 2.7440 2.7760 2.8120 2.8430 2.8490 2.8830 2.9570 3.1120 40 12/6/2016 3.1840 3.1440 3.0810 2.7260 2.7190 2.7510 2.7870 2.8180 2.8240 2.8580 2.9330 3.0880 41 12/5/2016 3.2100 3.1700 3.1050 2.7400 2.7330 2.7650 2.8010 2.8320 2.8380 2.8720 2.9480 3.1050 42 12/2/2016 3.2120 3.1730 3.1080 2.7430 2.7370 2.7690 2.8050 2.8360 2.8420 2.8760 2.9520 3.1090 43 12/1/2016 3.2200 3.1820 3.1170 2.7520 2.7460 2.7780 2.8140 2.8450 2.8510 2.8850 2.9610 3.1180 44 Average 3.2056 3.1662 3.1020 2.7424 2.7358 2.7678 2.8038 2.8348 2.8408 2.8748 2.9502 3.1064 45 46 Jan Feb Mar 47 Date 2022 2022 2022 48 12/7/2016 3.2560 3.2160 3.1530 49 12/6/2016 3.2350 3.1960 3.1330 50 12/5/2016 3.2520 3.2130 3.1480 51 12/2/2016 3.2560 3.2180 3.1530 52 12/1/2016 3.2650 3.2270 3.1620 53 Average 3.2528 3.2140 3.1498 Exhibit A-11 Page 1 of 1 Case No. U-18157
SEMCO Energy Gas Company 2017-2022 Basis Price Forecast
Basis Value (US$/Dth)
2017 2018 2019 2020 2021 2017-2018 2018-2019 2019-2020 2020-2021 2021-2022 Receipt Point Summer Summer Summer Summer Summer Winter Winter Winter Winter Winter
1 Northern Natural Gas -0.1532 -0.2282 -0.2282 -0.2282 -0.2282 0.0836 0.0584 0.0584 0.0584 0.0584 2 Great Lakes - Emerson -0.3000 -0.2650 -0.2650 -0.2650 -0.2650 0.0050 0.1300 0.1300 0.1300 0.1300 3 Great Lakes - Deward/Farwell 0.0675 -0.0750 -0.0750 -0.0750 -0.0750 0.2650 0.2000 0.2000 0.2000 0.2000 5 ANR - Southeast - Headstation -0.0780 -0.0876 -0.0876 -0.0876 -0.0876 -0.0665 -0.0709 -0.0709 -0.0709 -0.0709 6 ANR - Southeast - Shelbyville -0.1000 -0.1375 -0.1375 -0.1375 -0.1375 -0.0425 -0.0500 -0.0500 -0.0500 -0.0500 7 ANR - Southwest - Headstation -0.2867 -0.3176 -0.3176 -0.3176 -0.3176 -0.1177 -0.1313 -0.1313 -0.1313 -0.1313 8 ANR - Northern ML7 0.0325 -0.0900 -0.0900 -0.0900 -0.0900 0.1700 0.1375 0.1375 0.1375 0.1375 9 Bluewater Storage 0.0475 -0.0875 -0.0875 -0.0875 -0.0875 0.1625 0.1250 0.1250 0.1250 0.1250 10 Panhandle - Field Zone -0.3060 -0.3525 -0.3525 -0.3525 -0.3525 -0.1643 -0.1650 -0.1650 -0.1650 -0.1650 11 Vector - Marengo 0.0825 -0.0700 -0.0700 -0.0700 -0.0700 0.3050 0.2300 0.2300 0.2300 0.2300 12 Local Production -0.0964 -0.2149 -0.2149 -0.2149 -0.2149 0.0106 -0.0086 -0.0086 -0.0086 -0.0086 S T AT EO FM ICHIGAN
BEFO R ETHEM ICHIGAN P U BLICSER VICECO M M ISSION
Inthem atterofapplicationof ) SEM CO EN ERGYGAS CO M PAN Y forauthorityto ) CaseN o.U -18157 implementagascostrecoveryplanandfactorsfor ) the12-monthperiodfrom April2017 ) throughM arch2018andforrelatedapprovals. )
DIRECT T EST IM O N Y AN D EX HIBITS O FJEN N IFER L .DEN N IS
O N BEHAL FO F
SEM CO EN ERGYGAS CO M PAN Y DirectT estimonyofJenniferL .Dennis O nBehalfof S EM CO EN ER GY GasCompany 1 Q . P leasestateyournameandbusinessaddress.
2 A. JenniferL .Dennis,1411 T hirdS treet,SuiteA,PortHuronM ichigan48060.
3
4 Q . By w hom areyou employedandw hatisyourpresentposition?
5 A. IamemployedbyS EM CO EN ER GY GasCompany(“S EM CO Gas”orthe“ Company” ),adivisionof
6 S EM CO EnergyInc.,astheGasSupplyR esourceP lanner.
7
8 Q . P leasedescribeyoureducationalbackgroundandbusinessexperience.
9 A. Igraduatedfrom GrandValleyS tateU niversityinApril2002 w ithaBachelorofS ciencedegree.In
10 December2010,Igraduatedfrom CentralM ichiganU niversityw ithaM asterofP ublic
11 Administrationdegree.BetweenFebruary2003 andAugust2015IworkedfortheS t.ClairCounty
12 FriendoftheCourt,initiallyasaJudicialServiceO fficerIIthenasaJudicialServiceCoordinator.In
13 April2007,IwaspromotedtoaP rogramS upervisor/P rojectS pecialist,overseeingtheJail
14 AlternativeS entencingP rogramandlatertheArrearsM anagementP rogramS tateP ilot,which
15 w asreclassifiedtoP rojectS pecialist.InAugust2015,IwashiredbyS EM CO GasastheCustomer
16 EnergyM anagementCoordinatorinAugust2015,managingtheimplementationoftheCompany’s
17 energyoptimizationandresidentialappliancew arranteeprograms.InJuly2016,Ibecamethe
18 GasSupplyR esourceP lanner.
19
20 Q . W hatareyourresponsibilitiesasGasSupplyR esourceP lanner?
21 A. AsGasSupplyR esourceP lanner,my responsibilitiesincludetheoveralladministration,monitoring
22 anddevelopmentoftheCompany’senergyoptimizationplan.Additionally,my responsibilities
23 includem onthlygassupplyandpurchaseplanning,designdayplanning,andservingasaresource
24 totheCompany’sgassupplyandratesandregulatoryaffairsdepartments.
-2- DirectT estimonyofJenniferL .Dennis O nBehalfof S EM CO EN ER GY GasCompany 1
2 Q . Haveyou previouslyfiledtestimonyw iththeM P S C?
3 A. Yes.IhavesubmittedtestimonyandexhibitsinthereconciliationofS EM CO Gas’s2015energy
4 optimizationreconciliationCaseN o.U -18016andtheamendmenttotheCompany’s2016-2017
5 energyoptimizationplaninCaseN o.U -18179.
6
7 Q . W hatisthepurposeofyourtestimonyinthisproceeding?
8 A. T hepurposeofmy testimonyistosupporttheCompany’s2017-2018GCR planfilingby:
9 1. P rovidingtheDesignDay(“DesignDay” )demandforecastforJanuary,February,andM arch.
10 2. Explainingthem ethodologyusedincalculatingtheDesignDaydemandforecast.
11
12 Q . W hatexhibitsareyou sponsoringinthiscase?
13 A. Iamsponsoringthefollowingexhibits:
14 ExhibitA-12 DesignDayS um m ary
15 ExhibitA-13 DesignDayForecast
16
17 Q . W heretheseexhibitspreparedbyyou orunderyourdirection?
18 A. Yes.
19
20 2017-2018DesignDayDemandForecast
21 Q . How istheCompany’sDesignDaydemanddefined?
22 A. T heCompany’sDesignDaydemandisdefinedasthem aximum forecastednaturalgasdemandof
23 bothitsGCR andGCC customersonthecoldestexperiencedw interperioddayoverthepast15
24 years.
-3- DirectT estimonyofJenniferL .Dennis O nBehalfof S EM CO EN ER GY GasCompany 1
2 Q . How didtheCompanyestimateitsGCR andGCC DesignDaydemandforthe2017-2018w inter
3 GCR period?
4 A. U singthesamem ethodasagreeduponandapprovedbytheComm issioninthe2016-2017GCR
5 planCaseN o.U -17942,the2017-2018designdayplanusesanon-linearthirdorderregression
6 analysis.ForeachoftheCompany’sserviceareasoneachdayw ithanaveragedailytemperature
7 below 50 degreesduringthew interperiodsbetweenN ovember2014 andM arch2016,theGCR
8 andGCC retailsalesvolum esandheatingdegreedayswereusedtocalculatethethirdorder
9 regressionequationforthem ean.T herecentlyexperiencedDesignDaytemperatureswerethen
10 usedtocalculatetheheatingdegreedaysandw ereappliedtothethirdorderequation.A
11 standarddeviationfrom them eanoftwoandonehalfwasthenapplied.ActualGCR andGCC
12 customercountsforJanuary,February,andM archof2016w ereusedtocalculatetheaverageuse
13 percustomerduringaDesignDayandappliedtotheprojectedGCR andGCC customercountfor
14 the2017-2018w interseasontodeterminethenecessaryvolum erequiredtoeffectivelyservea
15 2017-2018DesignDay.
16
17 Q . W hydidtheCompanyincludeboth2014-2015and2015-2016w interdataintheanalysis?
18 A. InS EM CO Gas’smostrecentlycompletedGCR planfiling,theDesignDaydemandforecastused
19 thesamem ethodtocalculatetheforecastbutonlyuseddatafrom them ostrecentw inter,2014-
20 2015.T he2017-2018DesignDaydemandforecastusesthetwom ostrecentw intersbothto
21 capturethem ostrecentcustom usagepatternsin2015-2016andtocounterbalancethew armer
22 thanaverage2015-2016w interw iththecolderthanaverage2014-2015w inter.
23
-4- DirectT estimonyofJenniferL .Dennis O nBehalfof S EM CO EN ER GY GasCompany 1 Q . Explainw hythe2017-2018DesignDayplanforecastsvolumeslessthanthe2016-2017Design
2 DayplanforbothFebruaryandM arch.
3 A. T hetwoplansusedthesame2014-2015rawdata.T heproposedplanincludedadditionalraw
4 datafrom awarmerthanaverage2015-2016w inter.T hisalonew ouldaccountforadropin
5 forecast.T hedropisnotsignificantineitherFebruaryorM archandtheplanreflectsaslight
6 increaseforJanuaryduetotheforecastedincreaseincustomercountandtheeliminationof
7 averagetemperaturedayat50 andabove.T heCompanybelievestheforecastisreasonableto
8 m eettheneedsoftheincreasedGCR andGCC customerbasew iththeapplicationofthetwoand
9 onehalfstandarddeviation.
10
11 Q . DidtheCompanyusecoincidentheatingdegreedaystodeveloptheCompany’sDesignDay
12 demandforecast?
13 A. Yes.Consistentw iththecurrentDesignDayplan,the2017-2018planutilizedcoincidentheating
14 degreedaysforJanuary,February,andM arch.ExhibitA-12 showsthecoldestcoincidentdayfor
15 boththeU pperP eninsulaandtheL owerP eninsulatohaveoccurredinthelast15years.Itshould
16 benoted,thedatesusedinthe2017-2018planarethesameasthoseusedinthecurrentDesign
17 Dayplan.IntheL owerP eninsulathosedateswereJanuary6,2014,February19,2015,andM arch
18 2,2014. T heU pperP eninsula,however,experienceditscoldestcoincidentdayonM arch3,2003.
19 BecauseJanuaryistypicallythecoldestm onth,andm ostlikelytoexperiencethecoldestDesign
20 Day,followedbyFebruarythenM arch,theheatingdegreedaysfrom M arch3,2003,wasusedto
21 forecasttheU pperP eninsula’sDesignDaydemandforJanuary,FebruaryandM arch.S imilarly,
22 theP ortHuronareaexperiencedacolderdayinFebruary2015thantheydidinJanuary2014. T he
23 heatingdegreedaysfrom theFebruaryDesignDayw erethenusedtoforecastforbothJanuary
24 andFebruaryforthatservicearea.
-5- DirectT estimonyofJenniferL .Dennis O nBehalfof S EM CO EN ER GY GasCompany 1
2 Q . W hydidtheCompanyadd2.5standarddeviationstothem eanofitsGCR andGCC retailsales
3 datasettodeterminetheequationdescribingthedatasetunderDesignDaydemandconditions?
4 A. Consistentw iththem ethodologyusedincalculatingtheDesignDaydemandforecastforU -17942,
5 theCompanyapplied2.5standarddeviationstoallow forareasonablem arginofDesignDay
6 supplyandcapacityprotectionforitscustomers.
7
8 Q . U singthethirdorderregression+2.5standarddeviationsmethodology,whatistheCompany’s
9 resultingDesignDaydemandforecastforJanuary,February,andM archof2016?
10 A. ExhibitA-12,DesignDayS um m ary,demonstratesacum ulativeDesignDaydemandforecastfor
11 January,February,andM archof426,780 Dth,422,039 Dth,and385,663 Dthrespectively.
12
13 Q . Doesthisconcludeyourpre-fileddirecttestimonyatthistime?
14 A. Yes.
-6- SEMCO Energy Gas Company Exhibit A-12 Design Day Summary Page 1 of 1 Case No. U-18157
Dths Service Area January February March 1 Port Huron 178,677 178,428 158,707 2 Central 63,562 62,583 55,552 3 Niles 56,669 52,845 47,597 4 Holland 72,197 72,586 68,246 5 UP West 47,481 47,414 47,384 6 UP East 8,194 8,183 8,177 7 Total Design Day 426,780 422,039 385,663 8 9 10 Temps 11 Service Area January February March 12 Port Huron (6) (6) 5 13 Central (8) (5) 8 14 Niles (11) (1) 8 15 Holland 0 (1) 6 16 UP West (11) (11) (11) 17 UP East (18) (18) (18) 18 19 20 HDDs 21 Service Area January February March 22 Port Huron 71 71 60 23 Central 73 70 57 24 Niles 76 66 57 25 Holland 65 66 59 26 UP West 76 76 76 27 UP East 83 83 83 28 29 Lower Pen WAHDDs 71 69 59 30 Upper Pen WAHDDs 77 77 77 31 Total Company WAHDDs 72 70 61 32 33 34 Peak Day Dates January February March 35 Lower Peninsula 01/06/14 02/19/15 03/02/14 36 Upper Peninsula 03/03/03 03/03/03 03/03/03 SEMCO Energy Gas Company Exhibit A-13 Port Huron Service Area GCR+GCC Page 1 of 6 17-18 Design Day forecast Case No. U-18157
Std Deviation 2.5
January February March GCR+GCC Design Day Design Day Design Day Temperature -6 -6 5 Heating Degree Days 71 71 60 Forecast, Dth 176,784 176,784 157,346 15-16 Actual GCR+GCC Customers 123,446 123,589 123,678 15-16 Use per Customer 1.432 1.430 1.272 17-18 GCR+GCC Customer Forecast 124,767 124,738 124,747 17-18 GCR+GCC Forecast, Dth 178,677 178,428 158,707
Winter 14/15-15/16 GCR+GCC Retail Sales vs HDDs 200000 180000 160000 140000 120000 100000
80000 Quantity, Dth Quantity, 60000 y = -0.2456x3 + 26.754x2 + 1430.8x + 13394 40000 20000 0 0 10 20 30 40 50 60 70 80 Heating Degree Days
Actual Mean + Std Dev Mean - Std Dev Mean Dth SEMCO Energy Gas Company Exhibit A-13 Central Service Area GCR+GCC Page 2 of 6 17-18 Design Day forecast Case No. U-18157
Std Deviation 2.5
January February March Design Day Design Day Design Day Temperature -8 -5 8 Heating Degree Days 73 70 57 Forecast, Dth 62,889 62,007 55,076 15-16 Actual GCR+GCC Customers 44,849 44,892 44,942 15-16 Use per Customer 1.402 1.381 1.225 17-18 GCR+GCC Customer Forecast 45,329 45,309 45,331 17-18 GCR+GCC Forecast, Dth 63,562 62,583 55,552
Winter 14/15-15/16 GCR+GCC Retail Sales vs HDDs 70000
60000
50000
40000
30000
Quantity, Dth Quantity, y = -0.1621x3 + 17.461x2 + 283.38x + 7045.6 20000
10000
0 0 10 20 30 40 50 60 70 80 Heating Degree Days
Actual Mean + Std Dev Mean - Std Dev Mean Dth SEMCO Energy Gas Company Exhibit A-13 Niles Service Area GCR+GCC Page 3 of 6 17-18 Design Day forecast Case No. U-18157
Std Deviation 2.5
January February March Design Day Design Day Design Day Temperature -11 -1 8 Heating Degree Days 76 66 57 Forecast, Dth 56,068 52,358 47,189 15-16 Actual GCR+GCC Customers 42,358 42,434 42,439 15-16 Use per Customer 1.324 1.234 1.112 17-18 GCR+GCC Customer Forecast 42,811 42,828 42,806 17-18 GCR+GCC Forecast, Dth 56,669 52,845 47,597
Winter 14/15-15/16 GCR+GCC Retail Sales vs HDDs 60000
50000
40000
30000 Quantitiy, Dth Quantitiy, 20000 y = -0.1226x3 + 13.69x2 + 284.16x + 4463.3 10000
0 0 10 20 30 40 50 60 70 Heating Degree Days
Actual Mean + Std Dev Mean - Std Dev Mean Dth SEMCO Energy Gas Company Exhibit A-13 Holland Service Area GCR+GCC Page 4 of 6 17-18 Design Day forecast Case No. U-18157
Std Deviation 2.5
January February March Design Day Design Day Design Day Temperature 0 -1 6 Heating Degree Days 65 66 59 Forecast, Dth 71,432 71,918 67,661 15-16 Actual GCR+GCC Customers 49,765 49,883 49,925 15-16 Use per Customer 1.435 1.442 1.355 16-17 GCR+GCC Customer Forecast 50,298 50,347 50,357 16-17 GCR+GCC Forecast, Dth 72,197 72,586 68,246
Winter 14/15-15/16 GCR+GCC Retail Sales vs HDDs 80000
70000
60000
50000
40000
Quantity, Dth Quantity, 30000 y = -0.2633x3 + 29.521x2 + 6.7683x + 12463 20000
10000
0 0 10 20 30 40 50 60 70 Heating Degree Days
Actual Mean + Std Dev Mean - Std Dev Mean Dth SEMCO Energy Gas Company Exhibit A-13 UP West Service Area GCR+GCC Page 5 of 6 17-18 Design Day forecast Case No. U-18157
Std Deviation 2.5
January February March Design Day Design Day Design Day Temperature -11 -11 -11 Heating Degree Days 76 76 76 Forecast, Dth 46,978 46,978 46,978 15-16 Actual GCR+GCC Customers 32,563 32,596 32,598 15-16 Use per Customer 1.443 1.441 1.441 17-18 GCR+GCC Customer Forecast 32,912 32,899 32,880 17-18 GCR+GCC Forecast, Dth 47,481 47,414 47,384
Winter 14/15-15/16 GCR+GCC Retail Sales vs HDDs 50000 45000 40000 35000 30000 25000
20000 Quantity, Dth Quantity, 15000 y = 0.0037x3 - 0.4846x2 + 564.62x + 1994.1 10000 5000 0 0 10 20 30 40 50 60 70 80 Heating Degree Days
Actual Mean + Std Dev Mean - Std Dev Poly. (Actual) SEMCO Energy Gas Company Exhibit A-13 UP East Service Area GCR+GCC Page 6 of 6 17-18 Design Day forecast Case No. U-18157
Std Deviation 2.5
January February March Design Day Design Day Design Day Temperature -18 -18 -18 Heating Degree Days 83 83 83 Forecast, Dth 8,107 8,107 8,107 15-16 Actual GCR+GCC Customers 4,920 4,923 4,927 15-16 Use per Customer 1.648 1.647 1.645 17-18 GCR+GCC Customer Forecast 4,973 4,969 4,970 17-18 GCR+GCC Forecast, Dth 8,194 8,183 8,177
Winter 14/15-15/16 GCR+GCC Retail Sales vs HDDs 9000
8000
7000
6000
5000
4000
3000 Quantity, Dth Quantity, y = 0.0019x3 - 0.5931x2 + 124.73x - 352.29 2000
1000
0 0 10 20 30 40 50 60 70 80 90 Heating Degree Days
Actual Mean + Std Dev Mean - Std Dev Poly. (Actual)
STATE OF MICHIGAN
BEFORE THE MICHIGAN PUBLIC SERVICE COMMISSION
* * * * *
In the matter of the application of ) SEMCO ENERGY GAS COMPANY for authority to ) implement a gas cost recovery plan and factors for ) Case No. U-18157 the 12-month period from April 2017 through March 2018 ) and for related approvals. ) ______)
DIRECT TESTIMONY AND EXHIBITS
OF TAMARA L. SPENCER
ON BEHALF OF SEMCO ENERGY GAS COMPANY DIRECT TESTIMONY AND EXHIBITS OF TAMARA L. SPENCER ON BEHALF OF SEMCO ENERGY GAS COMPANY
1 Q. Please state your name, business address, and present business position.
2 A. My name is Tamara L. Spencer. My business address is 1411 Third Street, Suite A,
3 Port Huron, MI, 48060. I am the Manager of Gas Supply for SEMCO Energy Gas
4 Company (“SEMCO Gas” or the “Company”), a division of SEMCO Energy, Inc.
5 Q. Please state your utility experience.
6 A. In September 1987, I was hired by Southeastern Michigan Gas Enterprises, SEMCO
7 Energy, Inc.’s predecessor, as a clerk in the Rates and Gas Supply Department. In July
8 1993, I became the Company’s Supply Acquisition Administrator, responsible for the
9 procurement and scheduling of gas supply, and the daily monitoring of storage activity.
10 In addition, I was involved in the monthly planning of supply purchasing and storage
11 utilization. These responsibilities continued, and my involvement increased, through my
12 years as Senior Volume Analyst and Scheduler, and promotion to Supervisor Gas
13 Supply Acquisition in October 1997. In 1998, I was promoted to Manager of Gas Supply
14 and Transportation. My current position is Manager of Gas Supply.
15 Q. What are your primary responsibilities as Manager of Gas Supply?
16 A. Under the direction of the Director of Gas Supply, I am responsible for the
17 implementation of the Company’s GCR Plan, including the management of the monthly
18 and annual storage plan, the purchase of the Company’s gas supply requirements, and
19 the development of the fixed price purchase program. In addition, I have the
20 responsibility of managing the activities of the Company’s Gas Customer Choice
21 (“GCC”) program, and providing testimony as necessary in filings with the Michigan
22 Public Service Commission (“Commission”).
23 Q. Have you previously testified before the Commission?
Page 2 of 14 DIRECT TESTIMONY AND EXHIBITS OF TAMARA L. SPENCER ON BEHALF OF SEMCO ENERGY GAS COMPANY
1 A. Yes. I have submitted pre-filed testimony and exhibits and testified in the Company’s
2 prior annual GCR reconciliation cases beginning with the Company’s 2002-2003 filing;
3 prior annual GCR plan cases beginning with the Company’s 2004-2005 filing; and base
4 rate case U-14338.
5 Q. What is the purpose of your testimony in this proceeding?
6 A. The purpose of my testimony is to address the Company’s gas supply purchase strategy
7 as it relates to its Fixed Price Purchase (“FPP”) program, term and monthly purchases
8 and Peaking Supply.
9 Q. Are you sponsoring any exhibits in this proceeding?
10 A. Yes. I am sponsoring the following exhibits:
11 Exhibit A-14 Summary of Term Supply
12 Exhibit A-15 2017-2022 FPP Plan
13 Exhibit A-16 2017-2018 FPP Guidelines
14 Q. Were these exhibits prepared by you or under your direction or supervision?
15 A. Yes.
16 17 SUPPLY PURCHASE STRATEGY
18 Q. Please describe the Company’s overall purchase strategy.
19 A. The Company strives to provide a reliable source of natural gas supply at a reasonable
20 cost to the GCR customer. As discussed by Witness Fitzgerald, the Company holds firm
21 transportation capacity with the pipelines, both interstate and intrastate, which provide
22 firm, reliable service to the Company’s demand areas. The Company purchases its
23 supply to effectively utilize its firm pipeline transportation, and supplements its
24 transportation with city gate supply services when necessary. Witness Fitzgerald also
Page 3 of 14 DIRECT TESTIMONY AND EXHIBITS OF TAMARA L. SPENCER ON BEHALF OF SEMCO ENERGY GAS COMPANY
1 discusses the Company’s leased and on-system storage assets. The Company
2 purchases supply for injection into storage during the summer using diverse pricing to
3 provide a reasonable average cost of gas in storage for withdrawal during the winter
4 months.
5 Q. Please discuss the Company’s planned term supply purchases.
6 A. As in previous GCR periods, the Company plans to acquire fixed price gas supply for the
7 2017-2018 GCR plan period. The fixed price supply will be acquired using its FPP
8 program, which utilizes the Moving Average Relative Strength Index (“MARSI”) method
9 as approved in Case No. U-17333.
10 In addition to purchasing term fixed price supply, the Company will likely enter
11 into Index priced term supply of up to one year in length. The locking in of the Index
12 premium for a portion of the Company’s gas supply requirements provides additional
13 stability to its supply pricing during the GCR period by fixing the premium related to First
14 of the Month (“FOM”) Index supply purchases.
15 Q. Regarding the Index priced term gas supply, where does the Company plan to
16 source the supply?
17 A. SEMCO Gas reconfigured its ANR Pipeline (“ANR”) transportation portfolio beginning
18 with the April 2017-2018 GCR Period. As discussed by Walt Fitzgerald, the Company
19 split its ANR Southeast transportation capacity between the Southeast Headstation and
20 Rex Shelbyville receipt points. In the past, the Company has had a limited number of
21 bidders in response to its monthly Request for Proposal (“RFP”) for supply at the Rex
22 Shelbyville receipt point. Through discussions with various suppliers, the Company
23 believes an Index based, longer term supply agreement will be more attractive to
24 suppliers thus garnering a higher number of offers. SEMCO Gas will likely issue an RFP
Page 4 of 14 DIRECT TESTIMONY AND EXHIBITS OF TAMARA L. SPENCER ON BEHALF OF SEMCO ENERGY GAS COMPANY
1 in early 2017 for an Index priced supply package of 5,000 Dth/day sourced at Rex
2 Shelbyville, for the one year period April 1, 2017 - March 31, 2018.
3 Q. How will the Company secure any additional supply purchase requirements?
4 A. The remaining purchase requirements will likely be secured in the monthly spot market,
5 priced at the end of month NYMEX settlement and the FOM Index. The use of both
6 pricing mechanisms to purchase monthly supply, in addition to a level of fixed pricing,
7 provides supply that is typically priced between the highest and lowest pricing options,
8 thereby resulting in a reasonable cost of gas. In addition, the Company may make
9 purchases priced in the daily cash market.
10 Q. What process does the Company utilize to purchase its supply?
11 A. SEMCO Gas typically utilizes a competitive bidding process for securing its supply. For
12 each purchase, the Company issues an RFP to a list of approved suppliers with which
13 the Company has executed NAESB gas purchase agreements. The RFP may be in
14 written or oral form and specifies the quantity of natural gas to be purchased, required
15 location of the supply, and the effective term.
16 Q. How does the Company define swing supply?
17 A. Swing supply is purchased with the option of taking the entire contracted Maximum Daily
18 Quantity (“MDQ”) each day of the contract term, or less than the MDQ, including the
19 option to take none of the supply. This provides the Company with the ability to flow the
20 supply during periods where forecasted demand is higher than that of an average day,
21 as well as allowing the Company to shut-off the supply during periods when forecasted
22 demand is less than that of an average day, thus reducing the potential impact to
23 storage injection/withdrawal activity. Swing supply can be particularly beneficial during
24 the shoulder months of April and October.
Page 5 of 14 DIRECT TESTIMONY AND EXHIBITS OF TAMARA L. SPENCER ON BEHALF OF SEMCO ENERGY GAS COMPANY
1 Q. Does the Company expect to purchase swing supply services during the 2017-
2 2018 GCR plan year?
3 A. Yes, if it is determined that the added flexibility is warranted.
4 Q. What is the Company’s definition of intra-month purchases?
5 A. The Company may purchase supply which does not flow the entire month, but does
6 require the Company to take the full daily purchase quantity, unlike a swing service.
7 Q. Please provide an example of an instance in which the Company may make an
8 intra-month purchase.
9 A. SEMCO Gas may make intra-month purchases to increase injections into storage or to
10 maintain certain levels of storage inventory, if colder than normal weather has hindered
11 the ability to meet storage inventory requirements, due to increased demand. In
12 addition, there may be times when additional supply is required at various SEMCO Gas
13 interconnects during the month for operational reasons, such as the Company’s CECO
14 Overisel gate station in the Holland operating area. An example may be the variable
15 demand experienced during shoulder months for which storage withdrawals are not
16 available to supplement additional weather or operational related demand.
17 SUPPLY AGREEMENTS
18 Q. Does the Company have term supply agreements in place for the 2017-2018 GCR
19 plan year?
20 A. Yes. Exhibit A-14 is a list of the term supply agreements currently in place for the 2017-
21 2018 GCR period. Lines 1 through 3 reflect agreements with three small local
22 production wells in the Company’s Port Huron demand area. Two of these wells are
23 currently under contract to sell their supply to BP Canada Energy Marketing Corporation
24 (“BP”). SEMCO Gas expects to purchase a maximum of 2,300 Dth/day of this supply
Page 6 of 14 DIRECT TESTIMONY AND EXHIBITS OF TAMARA L. SPENCER ON BEHALF OF SEMCO ENERGY GAS COMPANY
1 from BP through the existing NAESB agreement in place between SEMCO Gas and BP.
2 The supply is priced at the MichCon FOM Index plus ($0.08). The third local production
3 supply, shown on line 3 of Exhibit A-14, will be purchased from Sinclair Oil and is also
4 priced at the MichCon FOM Index plus ($0.08).
5 Q. Has the Company secured any FPP for the 2017-2018 GCR period?
6 A. No. In accordance with the FPP Guidelines, approved in Case No. U-17942, the
7 Company utilized the MARSI method for securing FPP. The FPP Guidelines delineate
8 specific requirements that must be met to indicate a purchase opportunity. As of the
9 date of this filing, the purchase indicators for the 2017-2018 Summer FPP have not been
10 reached.
11
12 FPP PROGRAM
13 Q. Please discuss the objective of the Company’s FPP program?
14 A. The Company has advocated the use of fixed price purchases as a mechanism of
15 stabilizing gas costs and providing a hedge for potential run-ups in prices. These run-
16 ups may occur as a result of many factors, such as hurricane activity, national storage
17 inventory levels and financial and other worldwide events over which the Company has
18 no control. A level of fixed price supply was part of the Company’s gas supply portfolio
19 prior to the development of the first formal FPP program, Dollar Cost Averaging, and the
20 Company plans to continue including fixed price supply as a part of its diverse gas
21 supply portfolio.
22 Q. Why does the Company believe fixed price supply should be included in its
23 supply portfolio?
Page 7 of 14 DIRECT TESTIMONY AND EXHIBITS OF TAMARA L. SPENCER ON BEHALF OF SEMCO ENERGY GAS COMPANY
1 A. The intent of fixed price purchases has never been to beat the market, but rather to add
2 a layer of price stability to the Company’s gas supply portfolio, and provide some
3 protection against run-up in natural gas prices. The Company characterizes FPP as an
4 insurance policy that serves as a physical price hedge against seasonal price increases
5 due to the natural gas market’s periodic reaction to bullish technical drivers and
6 fundamental drivers of natural gas prices. As with any insurance policy, and as
7 addressed in prior GCR cases, there is a premium cost for that insurance. The
8 Company has maintained a level of fixed price supply in its portfolio since 1995. Since
9 that time the Company has received support from the Commission in the form of
10 approval of its FPP plans and reconciliation of those plans in its GCR plan cases. The
11 MPSC Staff (“Staff”) has also supported a continuing fixed price purchasing program in
12 the MichCon 2012-13 GCR plan case, Case No. U-16921, stating that “there is, and
13 likely always be, some degree of uncertainty with respect to future natural gas market
14 prices”. In addition, Staff stated that market uncertainty and variables in the market
15 suggest “a level of fixed price/forward purchases would be reasonable”.
16 Q. Please discuss the Company’s FPP program for the 2017-2018 GCR period.
17 A. The Company’s current approved FPP program, utilizing the MARSI method, has not
18 changed for the 2017-2018 GCR period. The FPP Guidelines call for the purchase of
19 20% of annual purchase requirements, which leaves the remaining purchase
20 requirements available for acquisition in the spot market at the monthly NYMEX and
21 Index prices. Exhibit A-16 reflects the FPP Guidelines which outline the parameters for
22 utilization of the MARSI method of acquiring FPP. The parameters include a brief
23 explanation of the moving averages and strength index applicable to the MARSI method,
24 Price Targets and execution of FPP.
Page 8 of 14 DIRECT TESTIMONY AND EXHIBITS OF TAMARA L. SPENCER ON BEHALF OF SEMCO ENERGY GAS COMPANY
1 Q. What is the 2017-2018 Summer FPP quantity for the 2017-2018 GCR period?
2 A. As reflected on Exhibit A-15, page 1, column F, line 22, the FPP quantity applicable to
3 the summer of 2017-2018 is approximately 5.35 Bcf, 22% of summer purchase
4 requirements.
5 Q. What is the 2017-2018 Winter FPP quantity?
6 A. Referring to Exhibit A-15, page 1, line 22, column G, the FPP quantity applicable to the
7 winter 2017-2018 GCR period is approximately 2.49 Bcf, 17% of winter purchase
8 requirements.
9 Q. What is the total FPP quantity for the 2017-2018 GCR period?
10 A. The total FPP quantity applicable to the 2017-2018 GCR period is approximately 7.84
11 Bcf, 20% of the Company’s 2017-2018 Annual supply purchase requirements.
12 Q. Are the quantities reflected on Exhibit A-15 receipt or delivered quantities?
13 A. The FPP quantities reflected on Exhibit A-15 are receipt quantities, meaning the
14 quantities are the actual purchase quantities, inclusive of estimated transportation fuel.
15 The receipt point quantities reflected on Exhibit A-15 allow for the purchases to be made
16 at daily quantities which are more attractive to suppliers, i.e. 5,000 Dth/day, without
17 needing to estimate the resulting delivered quantities required to meet the FPP quantity.
18 The fuel loss on each pipeline is different, and some change twice per year. One
19 pipeline, GLGT, changes its fuel rate monthly. Therefore, the fuel loss associated with a
20 purchased quantity will result in the delivered quantities varying month to month for the
21 same package of gas flowing during the GCR period. To allow for ease is reconciling
22 quantities purchased with planned purchases, the FPP quantities reflected on Exhibit A-
23 15 are planned receipt quantities.
Page 9 of 14 DIRECT TESTIMONY AND EXHIBITS OF TAMARA L. SPENCER ON BEHALF OF SEMCO ENERGY GAS COMPANY
1 Q. Exhibit A-15 designates four purchase layers for Summer FPP and three purchase
2 layers for Winter FPP. Please explain the purpose of the purchase layers.
3 A. The layers reflect the quantities of the Summer FPP and Winter FPP that will be
4 purchased when a Price Target is reached. The purpose of the layers is to provide for
5 the purchase of FPP at multiple Price Targets and various points in time, thus providing
6 a level of dollar cost averaging to the FPP.
7 Q. The FPP Guidelines, Exhibit A-16, state that there are two Price Targets: a 3rd
8 Standard Deviation Price Target and a 4th Standard Deviation Price Target. Do the
9 FPP Guidelines specify the number of layers that may be purchased at each Price
10 Target?
11 A. Yes. The Company’s FPP acquired at the 3rd Standard Deviation Price Target will be
12 limited to two purchase layers for the Summer FPP and two Winter FPP purchase
13 layers. If the 3rd Standard Deviation Price Target is reached, the Company may
14 purchase no more than one purchase layer at that time for each of the Summer FPP and
15 the Winter FPP. In other words, while a total of two Summer FPP may be purchased at
16 the 3rd Standard Deviation Price Target, they may not be acquired as part of single
17 purchase opportunity. The remaining FPP layers would be purchased only if the 4th
18 Standard Deviation Price Target is reached.
19 Q. If the Price Targets for the Summer FPP and Winter FPP are reached at the same
20 time, allowing for a purchase opportunity for each, does the Company plan to
21 acquire both the Summer FPP and Winter FPP layer(s) at the same time?
22 A. Yes. The Summer FPP and the Winter FPP layers are separate in terms of the flow
23 period and are based on two different NYMEX Price Strips. Therefore, if a buy
24 opportunity occurs for each on the same day, the Company plans to purchase a layer for
Page 10 of 14 DIRECT TESTIMONY AND EXHIBITS OF TAMARA L. SPENCER ON BEHALF OF SEMCO ENERGY GAS COMPANY
1 the Summer FPP and a layer for the Winter FPP. In addition, the purchase parameters
2 regarding the limit on 4th Standard Deviation Price Target purchases are applicable to
3 each the Summer FPP and the Winter FPP, meaning the Company may purchase two
4 Summer FPP layers at the 4th Standard Deviation Price Target and two Winter FPP
5 layers at the 4th Standard Deviation Price Target.
6 Q. Does the Company plan to purchase more than one layer at one time if the 4th
7 Standard Deviation Price Target is reached?
8 A. If the 4th Standard Deviation Price Target is reached, the Company may acquire two of
9 the applicable purchase layers. For example, if the 4th Standard Deviation Price Target
10 is reached for the Summer FPP, two purchase layers may be acquired at one time. The
11 same would apply to the Winter FPP.
12 Q. If the Price Targets are not reached during the applicable period such that no FPP
13 buying opportunities arise for one or both of the Summer and/or Winter FPP, will
14 the Company purchase any FPP?
15 A. No. If Price Targets are not reached during the applicable purchase periods, no FPP will
16 be acquired for the GCR period.
17 Q. The FPP Guidelines state that “unanticipated market volatility may prevent
18 purchase quantities from being achieved at the designated price targets”. Please
19 discuss how market volatility may impact FPP.
20 A. According to the FPP Guidelines, four technical market indicators much be reached to
21 achieve a “Buying Opportunity”:
22 The applicable winter or summer strip is at or below the 3rd standard deviation Price 23 Target or the 4th standard deviation Price Target. 24 The applicable winter or summer strip is less than the 10 DMA, 20 DMA, and the 40 25 DMA. 26 The applicable winter or summer strip’s 10 DMA is less than the 20 DMA.
Page 11 of 14 DIRECT TESTIMONY AND EXHIBITS OF TAMARA L. SPENCER ON BEHALF OF SEMCO ENERGY GAS COMPANY
1 The applicable winter or summer strip’s 20 DMA is less than the 40 DMA. 2 The applicable winter or summer strip’s Relative Strength Index (“RSI”) 14 day index 3 value crosses below 30.
4 As stated in the Guidelines, of one of the requirements for FPP is that the 14 Day RSI
5 must be below 30, which reflects a weakening price environment. The natural gas
6 market indicators, such as prices and RSI, are not static. As a result, while the NYMEX
7 settlement on one day may signal a Buy Opportunity, it will likely change between the
8 time the Company is receiving offers for the supply, and the time the Company would
9 purchase the supply. If such market movement occurs, the RSI-14 day value for
10 example, may rise above the required value of 30, reflecting a strengthening of the
11 market. The Buy Opportunity would no longer remain and the FPP may not be acquired.
12
13 MONTHLY SUPPLY PURCHASES
14 Q. Please describe the Company’s monthly purchase process.
15 A. As with the fixed price and term purchases, the Company uses a competitive bidding
16 process for purchasing monthly supply. Each month the Company issues a RFP for
17 monthly purchases during bid week. Bid week is typically a five day period prior to the
18 day the NYMEX closes for the next month.
19 Q. Does the Company always purchase the supply with the lowest bid?
20 A. While the Company attempts to secure the supply at the lowest bid received, it is not
21 always possible. The offers received from the Company’s suppliers are subject to
22 revision due to continually changing market conditions. Typically suppliers indicate that
23 supply offers are subject to market refresh. If a supplier is contacted and the bid is no
24 longer valid, the Company may attempt to contact the supplier with the next lowest bid.
25 Other reasons why the Company may not select the lowest bid include the offer is from a
Page 12 of 14 DIRECT TESTIMONY AND EXHIBITS OF TAMARA L. SPENCER ON BEHALF OF SEMCO ENERGY GAS COMPANY
1 new supplier with which SEMCO Gas does not yet have a NAESB purchase contract,
2 credit limit thresholds, supplier diversity, or the inability to contact the supplier at the time
3 of purchase.
4 Q. Please discuss the pricing strategy for the Company’s monthly purchases.
5 A. The Company typically provides price diversity by purchasing its monthly supply utilizing
6 FOM Index based pricing and pricing tied to the monthly NYMEX settlement, in addition
7 to purchasing fixed price supply at various times throughout the month if necessary.
8 This provides different pricing structures allowing the GCR customer to benefit from the
9 lower pricing structure available each month for at least a portion of the monthly supply,
10 and does not risk the entire monthly purchase costs on an estimate of which option will
11 result in the lowest cost of gas. The outcome of this strategy has been a reasonable
12 average cost of gas for the Company’s monthly purchases.
13
14 PEAKING SUPPLY
15 Q. Witness Fitzgerald discusses the Company’s Design Day scenario which includes
16 the Company’s plan to secure Peaking Supply to meet the forecasted demand on
17 those days. Please discuss how the Peaking Supply will be structured.
18 A. The Company plans to purchase Peaking Supply to meet a Design Peak Day in the
19 months of January through March 2018. The supply will be structured with a maximum
20 quantity for the period, a defined MDQ, and will flow on the Company’s interstate
21 pipeline transportation. The Company will require a maximum Peaking Supply of
22 approximately 78,000 Dth/Day for Design Peak Day. The purchased Peaking Supply
23 will be available for a maximum of 7 days over the January through March period, with
Page 13 of 14 DIRECT TESTIMONY AND EXHIBITS OF TAMARA L. SPENCER ON BEHALF OF SEMCO ENERGY GAS COMPANY
1 no minimum take requirement. The total Peaking Supply acquired will total a maximum
2 of approximately 546,000 Dth.
3 Q. How will the Peaking Supply be priced?
4 A. The Peaking Supply is expected to be priced at the Gas Daily daily price on the day the
5 supply is called upon. In addition, the Peaking Supply will likely include a demand
6 charge which ensures that the supply will be available on the day it is called upon, at the
7 operational locations required.
8 Q. Is the supply plan proposed by the Company reasonable and prudent?
9 A. Yes. SEMCO Gas’s 2017-2018 supply plan consists of the average day supply plan,
10 and a peak day supply plan for serving a Design peak day. The supply plan includes
11 purchases utilizing firm pipeline transportation from multiple receipt locations to the
12 Company’s city gates ensuring a reliable source of supply flowing to its city gates. The
13 Company holds significant storage assets for managing colder and warmer than normal
14 temperatures, meeting peak day requirements, and load variations such as that
15 experienced with GCC participation, and the Company’s 2017-2018 plan also contains a
16 strategy for managing colder and warmer than normal weather as described in Witness
17 Fitzgerald’s testimony.
18 Q. Does this conclude your pre-filed direct testimony at this time?
19 A. Yes.
20
Page 14 of 14 A B C D E F G H I J K SEMCO ENERGY GAS COMPANY Exhibit A-14 Summary of Term Supply Agreements Case No. U-18157 For the Period April 2017 - March 2018 Page 1 of 1
Annual Daily Contract Contract NYMEX Line Quantity Quantity Effective Expiration Receipt Transporting Price Fixed No. Supplier (Dth) (Dth) Date Date Point Pipeline Basis or FOM Index Price
1 BP Canada Energy Marketing Corp * 730,000 2,000 9/1/2001 Evergreen Klingler Local Production $ (0.0800) Michcon Index
2 BP Canada Energy Marketing Corp * 109,500 300 9/1/2001 Evergreen Pilat Well Local Production $ (0.0800) Michcon Index
3 Sinclair Oil * 730,000 2,000 12/1/2010 Evergreen Rapley Well Local Production $ (0.0800) Michcon Index
* Daily volume varies. Stated daily contract quantity reflects the maximum daily quantity. A B C D E F G H I SEMCO Energy Gas Company Exhibit A-15 2017-2018 Fixed Priced Purchase Plan Case No. U-18157 For the Period April 2017 - March 2018 Page 1 of 5
Summer Winter Annual Total Total Total 2017-2018 Dth Dth Dth 1 GCR Demand 9,859,718 27,949,315 37,809,033 2 Injections 13,881,926 0 13,881,926 3 Withdrawals 0 (13,881,926) (13,881,926) 4 Fuel Requirements 784,805 500,452 1,285,257 5 Supply Req (Purchases) 24,526,449 14,567,841 39,094,290 6 7 8 Summer Winter Annual 9 Fixed Price Purchase Total Total Total 10 Tier Schedule Purchase Indicator Dth Dth Dth 11 12 Summer October 1 - March 20 MARSI Indicators 1st Purchase Layer 1,284,000 13 2nd Purchase Layer 1,284,000 14 3rd Purchase Layer 1,391,000 15 4th Purchase Layer 1,391,000 16 17 Winter May 1 - October 20 MARSI Indicators 1st Purchase Layer 830,500 18 2nd Purchase Layer 830,500 19 3rd Purchase Layer 830,500 20 21 Exhibit A-15 22 Total 5,350,000 2,491,500 7,841,500 23 24 Annual/Seasonal % 22% 17% 20% 25 26 27 28 A B C D E F G H I SEMCO Energy Gas Company Exhibit A-15 2018-2019 Fixed Priced Purchase Plan Case No. U-18157 Page 2 of 5
Summer Winter Annual Total Total Total 2018-2019 Dth Dth Dth 1 GCR Demand 10,052,127 28,280,593 38,332,720 2 Injections 13,881,926 0 13,881,926 3 Withdrawals 0 (13,881,926) (13,881,926) 4 Fuel Requirements 768,293 511,606 1,279,899 5 Supply Req (Purchases) 24,702,346 14,910,273 39,612,619 6 7 8 Summer Winter Annual 9 Fixed Price Purchase Total Total Total 10 Tier Schedule Purchase Indicator Dth Dth Dth 11 12 Summer October 1 - March 20 MARSI Indicators 1st Purchase Layer 1,284,000 13 2nd Purchase Layer 1,284,000 14 3rd Purchase Layer 1,391,000 15 4th Purchase Layer 1,391,000 16 17 Winter May 1 - October 20 MARSI Indicators 1st Purchase Layer 830,500 18 2nd Purchase Layer 830,500 19 3rd Purchase Layer 830,500 20 21 Exhibit A-15 22 Total 5,350,000 2,491,500 7,841,500 23 24 Annual/Seasonal % 22% 17% 20% 25 26 27 28 A B C D E F G H I SEMCO Energy Gas Company Exhibit A-15 2019-2020 Fixed Priced Purchase Plan Case No. U-18157 Page 3 of 5
Summer Winter Annual Total Total Total 2019-2020 Dth Dth Dth 1 GCR Demand 10,115,247 28,387,464 38,502,711 2 Injections 13,881,926 0 13,881,926 3 Withdrawals 0 (13,881,926) (13,881,926) 4 Fuel Requirements 768,702 515,224 1,283,926 5 Supply Req (Purchases) 24,765,875 15,020,762 39,786,637 6 7 8 Summer Winter Annual 9 Fixed Price Purchase Total Total Total 10 Tier Schedule Purchase Indicator Dth Dth Dth 11 12 Summer October 1 - March 20 MARSI Indicators 1st Purchase Layer 1,284,000 13 2nd Purchase Layer 1,284,000 14 3rd Purchase Layer 1,391,000 15 4th Purchase Layer 1,391,000 16 17 Winter May 1 - October 20 MARSI Indicators 1st Purchase Layer 830,500 18 2nd Purchase Layer 830,500 19 3rd Purchase Layer 830,500 20 21 Exhibit A-15 22 Total 5,350,000 2,491,500 7,841,500 23 24 Annual/Seasonal % 22% 17% 20% 25 26 27 28 A B C D E F G H I SEMCO Energy Gas Company Exhibit A-15 2020-2021 Fixed Priced Purchase Plan Case No. U-18157 Page 4 of 5
Summer Winter Annual Total Total Total 2020-2021 Dth Dth Dth 1 GCR Demand 10,109,292 28,416,022 38,525,314 2 Injections 13,881,926 13,881,926 3 Withdrawals (13,881,926) (13,881,926) 4 Fuel Requirements 768,336 516,606 1,284,942 5 Supply Req (Purchases) 24,759,554 15,050,702 39,810,256 6 7 8 Summer Winter Annual 9 Fixed Price Purchase Total Total Total 10 Tier Schedule Purchase Indicator Dth Dth Dth 11 12 Summer October 1 - March 20 MARSI Indicators 1st Purchase Layer 1,284,000 13 2nd Purchase Layer 1,284,000 14 3rd Purchase Layer 1,391,000 15 4th Purchase Layer 1,391,000 16 17 Winter May 1 - October 20 MARSI Indicators 1st Purchase Layer 830,500 18 2nd Purchase Layer 830,500 19 3rd Purchase Layer 830,500 20 21 Exhibit A-15 22 Total 5,350,000 2,491,500 7,841,500 23 24 Annual/Seasonal % 22% 17% 20% 25 26 27 28 A B C D E F G H I SEMCO Energy Gas Company Exhibit A-15 2021-2022 Fixed Priced Purchase Plan Case No. U-18157 Page 5 of 5
Summer Winter Annual Total Total Total 2021-2022 Dth Dth Dth 1 GCR Demand 10,186,188 28,622,505 38,808,693 2 Injections 13,881,926 13,881,926 3 Withdrawals (13,881,926) (13,881,926) 4 Fuel Requirements 768,599 523,407 1,292,006 5 Supply Req (Purchases) 24,836,713 15,263,986 40,100,699 6 7 8 Summer Winter Annual 9 Fixed Price Purchase Total Total Total 10 Tier Schedule Purchase Indicator Dth Dth Dth 11 12 Summer October 1 - March 20 MARSI Indicators 1st Purchase Layer 1,284,000 13 2nd Purchase Layer 1,284,000 14 3rd Purchase Layer 1,391,000 15 4th Purchase Layer 1,391,000 16 17 Winter May 1 - October 20 MARSI Indicators 1st Purchase Layer 830,500 18 2nd Purchase Layer 830,500 19 3rd Purchase Layer 830,500 20 21 22 Total 5,350,000 2,491,500 7,841,500 23 24 Annual/Seasonal % 22% 16% 20% 25 26 27 28
Exhibit A-16 Case No. U-18157
Fixed Price Purchase Guidelines
The program provides a mechanism, referred to as the Moving Average Relative Strength Index (“MARSI”) Method, for the purchase of winter and summer fixed price supply based on the use of technical indicators as a signal for an opportune time to purchase designated levels of winter and summer flowing supply requirements.
For purposes of the Fixed Price Purchases (“FPP”) made under these guidelines, a gas commodity purchase is deemed to have a fixed price if the price has been fixed or set as a stated amount in dollars and cents per Dth; the NYMEX natural gas price strip (“Price Strip”) and applicable basis price components are both set as stated amounts in dollars and cents per Dth.
The Purchase Periods will apply to FPP for the upcoming GCR Period. For purposes of the example below, the April 2015-March 2016 GCR Period is applicable.
a) Summer FPP – The FPP purchase period for the April 2015-October 2015 summer period will be the prior six month period; i.e. October 1 2014-March 20, 2015.
b) Winter FPP –The FPP purchase period for the November 2015-March 2016 winter period will be the prior six month period; i.e. May 1, 2015-October 20, 2015.
MARSI Method for Fixed Price Purchases
The MARSI methodology applies four technical indicators which assist in identifying the existence of a favorable natural gas buying environment and a buying opportunity. In addition to the use of moving averages and relative strength of the market, the Company will utilize FPP price targets based on the 3rd and 4th standard deviations from a defined mean Price Strip.
Moving Averages
The moving average of a Price Strip is a trend following mechanism. Its purpose is to identify when a new trend has begun or that an old trend has ended or reversed. It also tracks the progress of a trend. The ten day moving average (“10 DMA”), twenty day moving average (“20 DMA”) and the forty day moving average (“40 DMA”) are the simple averages of the prior ten, twenty, and forty trading days of closing prices for an applicable Price Strip. The 10 DMA, 20 DMA and 40 DMA are updated each trading day of the NYMEX by replacing the oldest closing price with the most recent closing price and recalculating the simple average. The moving averages indicate a rising or falling trend of an applicable winter or summer Price Strip. For example, if the 10 DMA becomes less than the 20 DMA, the futures Price Strip is trending toward a falling market environment. When the 20 DMA becomes less than the 40 DMA, the falling trend of the futures Price Strip is becoming more entrenched.
1
For purposes of acquiring fixed price supply, the ten day moving average (“10 DMA”), twenty day moving average (“20 DMA”) and the forty day moving average (“40 DMA”) will be utilized, in conjunction with the Relative Strength Index.
Relative Strength Index (“RSI”)
RSI provides an indication of the relative strength of the natural gas market environment for a NYMEX futures Price Strip. The Company will utilize the RSI-14 indicator which provides an indication of the relative strength of the price environment of an applicable Price Strip over a 14 day period. An RSI-14 value between 30 and 70 provides indicators of favorable and unfavorable buying environments. A RSI-14 value of 70 or greater is said to indicate that the futures market is overbought, seen as an unfavorable buy indicator. Conversely, a RSI-14 value less than 30 indicates the futures market is oversold, a strong buy indicator. A buy opportunity is the period during which the RSI value falls below 30 and continues until the RSI rises above 30.
Price Targets
The Company will utilize price targets to be used in conjunction with the MARSI methodology in the acquisition of FPP. The price targets will be based on standard deviations from the mean value of the applicable winter or summer NYMEX futures Price Strip occurring during the four month period prior to the applicable purchase period defined above. There are two target prices for FPP: a 3rd standard deviation target and a 4th standard deviation target.
Winter FPP
The applicable Price Strip used for winter FPP is the simple average of the settlement prices for the natural gas NYMEX futures first winter month contract plus the next consecutive four winter months for the winter period for which the purchase is being made. If purchases are being made for the winter period November 2015 – March 2016 for example, the applicable Price Strip would be the simple average of the NYMEX prices for the winter period November 2015 – March 2016.
Summer FPP
The applicable Price Strip used for summer FPP is the simple average of the settlement prices for the natural gas NYMEX futures first summer month contract plus the next consecutive six summer months for the summer period for which the purchase is being made. If purchases are being made for the summer April 2015 – October 2016 period, for example, the applicable strip would be the simple average of the NYMEX prices for the summer period April 2015 – October 2016.
Quantities
The maximum percentages for annual, summer and winter targets are updated and filed annually in the GCR Plan case with corresponding testimony and exhibits. See Attachment 1.
The Company will purchase no more than two purchase layers for the Summer FPP and two Winter FPP purchase layers at a single buying opportunity. Purchase layers are typically a minimum of 5,000 Dth a day, and a maximum quantity up to 10,000-15,000 Dth a day.
If the 3rd Standard Deviation Price Target is reached, and subsequently a buy opportunity, the Company may purchase no more than one purchase layer at that time for each of the Summer FPP and the Winter FPP. The Company may purchase no more than two layers of Summer FPP and two layers of Winter FPP, at two separate buying opportunities, at the 3rd Standard
2
Deviation Price. Any FPP layers not purchased at the 3rd Standard Deviation Price Target will be purchased only if the 4th Standard Deviation Price Target is reached. If the 4th Standard Deviation Price Target is reached, the Company may acquire two layers at a single buy opportunity.
If a buy opportunity is achieved for both the Summer FPP and Winter FPP on the same day, the Company may purchase a layer, or layers if applicable, of Summer FPP, and a layer, or layers if applicable, of Winter FPP.
If specified Price Targets are not reached during the applicable purchase periods, no FPP will be acquired for the GCR period.
If changes are required to the demand forecast on which purchase percentages are based, quantities not yet secured may be adjusted to ensure annual, summer and winter targets do not exceed the established purchase percentages.
Execution
SEMCO Gas may purchase a defined quantity of winter or summer fixed price supply when all of the following occur:
The applicable winter or summer strip is at or below the 3rd standard deviation Price Target or the 4th standard deviation Price Target. The applicable winter or summer strip is less than the 10 DMA, 20 DMA, and the 40 DMA. The applicable winter or summer strip’s 10 DMA is less than the 20 DMA. The applicable winter or summer strip’s 20 DMA is less than the 40 DMA. The applicable winter or summer strip’s RSI-14 day index value crosses below 30.
FPP purchases may be executed immediately upon reaching the Price Target; however such immediate execution is not required. Unanticipated market volatility may prevent purchase quantities from being achieved at the designated price targets.
Quotes may be gathered from suppliers utilizing an oral or written Request For Proposal (“RFP”) process. The Company shall ensure quotes, using either RFP process, are gathered in a prudent manner taking into account market volatility.
3
STATE OF MICHIGAN
BEFORE THE MICHIGAN PUBLIC SERVICE COMMISSION
*****
In the matter of the application of ) SEMCO ENERGY GAS COMPANY for authority to ) implement a gas cost recovery plan and factors for ) Case No. U-18157 the 12-month period from April 2017 ) through March 2018 and for related approvals. ) )
DIRECT TESTIMONY AND EXHIBITS OF JAMES A. VAN SICKLE
ON BEHALF OF
SEMCO ENERGY GAS COMPANY Direct Testimony of James A. Van Sickle On Behalf of SEMCO Energy Gas Company
1 Q. Please state your name and business address.
2 A. My name is James Van Sickle, and my business address is 1411 Third Street, Port Huron,
3 Michigan 48060.
4
5 Q. By whom are you employed and what is your position with that employer?
6 A. My present position is Rates Analyst in the Rates and Regulatory Department at
7 SEMCO Energy Gas Company (“SEMCO Gas” or the “Company”), a division of
8 SEMCO Energy, Inc.
9
10 Q. What are your responsibilities as Rates Analyst?
11 A. Under the supervision of the Manager of Regulatory Affairs, I have responsibility for
12 participating in Michigan Public Service Commission (“Commission” or “MPSC”)
13 proceedings, including preparing exhibits and workpapers, writing testimony,
14 submitting to cross-examination, and otherwise representing the Company before the
15 Commission. I am also responsible for the communication of Company tariff changes
16 and any other regulatory requirements as assigned. My additional responsibilities
17 include researching regulatory topics that arise at the Company from time to time.
18 Q. Please summarize your academic background.
19
20 A. In 1981, I graduated from St. Clair County Community College with an Associate
21 degree in Arts. In 1984, I graduated from Michigan State University with a Bachelor
22 of Arts Humanities/Pre-Law degree. In 1990, I received an Associate degree in
23 Paralegal Studies from Mountain West Junior College.
2 Direct Testimony of James A. Van Sickle On Behalf of SEMCO Energy Gas Company
1
2 Q. Please summarize your relevant employment and professional experience.
3 A. In 1997, I joined SEMCO Gas as a Marketing Analyst. While with the Marketing
4 Department, I reviewed processes and developed and implemented procedural
5 changes that streamlined several aspects of that department. In 1999, I moved into
6 the position of Manager of Process and Analysis with SEMCO Energy Ventures, an
7 unregulated division of SEMCO Energy, Inc. I then transferred and worked in the
8 Training Department for SEMCO Gas, tracking documentation and developing
9 various processes. I have been in the Rates and Regulatory Department since June
10 2004 and have been involved in data gathering and presentation, reporting, and
11 various support roles.
12
13 Q. Have you previously testified, or caused to have your testimony filed, in proceedings
14 before the Commission on behalf of the Company?
15 A. Yes.
16
17 Q. What is the purpose of your testimony in this proceeding?
18 A. The purpose of my testimony is to sponsor: (1) the Gas Cost Recovery (“GCR”) factor,
19 which is a composite of the Commodity Gas Charge and Balancing and Demand Charge,
20 (2) the five-year forecast of GCR requirements, (3) the proposed contingency matrix, (4)
21 costs of other fuels available to customers, and (5) tariff sheets that reflect the Company’s
22 proposals in this proceeding.
23
24 Q. Please identify the exhibits which you are sponsoring in this case.
3 Direct Testimony of James A. Van Sickle On Behalf of SEMCO Energy Gas Company
1 A. I am sponsoring the following exhibits:
2 Exhibit A-17 Base GCR Factor Calculation
3 Exhibit A-18 Five-Year Forecast of GCR Requirements
4 Exhibit A-19 Proposed Tariff Sheets
5 Exhibit A-20 Single Contingency Factor Determinations
6
7 Q. Were these exhibits prepared by you or under your direction?
8 A. Yes.
9
10 GCR Factor
11 Q. Please describe your Exhibit A-17, Base GCR Factor Calculation
12 A. Exhibit A-17 is used to calculate the proposed base GCR factor and the slope for the
13 Contingency Factor Matrix.
14
15 Q. Please describe the Company’sproposed base GCR factor.
16 A. The Company’s proposed base GCR factor is $4.1943 per Dekatherm (“Dth”) and is made
17 up of a Balancing and Demand charge and a Gas Commodity Charge. The Gas Commodity
18 Charge is intended to recover the commodity cost of the natural gas purchased for and
19 delivered to GCR customers and is recovered from GCR customers only. The Balancing and
20 Demand charge is intended to recover fixed costs related to pipeline transport, storage and
21 other fixed costs of gas as developed by Witness Fitzgerald. These fixed costs are
22 recovered from both GCR and Gas Customer Choice (“GCC”) customers.
23
24 Q. Please describe the calculation of the Balancing and Demand charge.
4 Direct Testimony of James A. Van Sickle On Behalf of SEMCO Energy Gas Company
1 The proposed Balancing and Demand charge is calculated on Page 1 of Exhibit A-17. To
2 calculate the Balancing and Demand charge the total fixed cost on line 29, is divided by the
3 total sales and GCC Dth on line 30. The resulting maximum Balancing and Demand charge
4 of $0.8048 as reflected on lines 31 and 49.
5
6 Q. Please discuss treatment of the Balancing and Demand charge as directed in Case
7 No. U-17333.
8 A. The Order in Case No. U-17333 was issued June 30, 2015. In it, SEMCO was directed to
9 reconcile its Commodity costs and Balancing and Demand costs separately. These two
10 elements combine to create the base GCR factor. In addition to reconciling these two gas
11 costs separately, SEMCO was ordered to recognize that the Balancing and Demand charge
12 as filed/ordered is the maximum rate that may be charged to its GCR and GCC customers.
13
14 Q. Was a methodology developed for the Balancing and Demand charge to allow the
15 Company to charge enough to cover its costs in the event of rising costs or
16 decreasing volumes?
17 A. No. In Case No. U-17333, the Attorney General posited, and the Commission agreed, that
18 a maximum volumetric charge would be proper to collect these costs and that the Company
19 would be free to lower this charge to its customers in order to avoid an over-recovery.
20 However, the Attorney General did not present a way for the Company to increase the
21 Balancing and Demand charge during the plan year.
22
5 Direct Testimony of James A. Van Sickle On Behalf of SEMCO Energy Gas Company
1 Q. What would be the practical result of this restriction in the event that either the
2 Company’s costs were higher than projected or the actual volumes realized during
3 the plan year were lower than projected?
4 A. The practical result of the Company experiencing higher costs and/or lower volumes without
5 having an opportunity to appropriately raise the Balancing and Demand charge above its
6 filed/ordered amount would be a forced under-recovery of this cost. This under-recovery
7 would then be rolled into the next plan year’s Balancing and Demand costs.
8
9 Q. Is the Company proposing a method to reduce the risk of an under-recovery specific
10 to its Balancing and Demand charge?
11 A. Not in the current plan case.
12
13 Q. Is the Company including any forecasted over or under-recovered Commodity or
14 Balancing and Demand costs in this GCR filing?
15 A. No. It has not been the practice of the Company to include an over or under-recovery in its
16 GCR forecast in its December filing. If a substantial over or under-recovery in either of the
17 Commodity or Balancing and Demand costs occur early in the contention of this case, the
18 Company may choose to file an amended GCR forecast and implement the new charges
19 after the mandated time has elapsed.
20
21 Q. Please describe the calculation of the proposed Gas Commodity Charge.
6 Direct Testimony of James A. Van Sickle On Behalf of SEMCO Energy Gas Company
1 A. The proposed Gas Commodity Charge is calculated on Page 1 of Exhibit A-17. To calculate
2 the Gas Commodity Charge the total cost of gas on line 36 is divided by the total Sales
3 customer Dth on line 10. The resulting Gas Commodity Charge of $3.3895 is illustrated on
4 lines 38 and 50.
5
6 Q. Please discuss pages 2 and 3 of Exhibit A-17.
7 A. In conjunction with page 1, pages 2 and 3 of Exhibit A-17 are used to develop the slope as
8 determined in Exhibit A-20. The slope is used in the Company’s Contingency Factor Matrix.
9
10 Five-year Forecast of GCR Requirements
11 Q. Please discuss Exhibit A-18.
12 A. This exhibit shows the forecasted customers and their Dth requirements for the next five
13 years on a calendar month basis. Please note on each page that the months are shown
14 ordered left to right from January to December, but that the year for each month of January
15 through March are dated a year later than the months April through December.
16
17 Q. Please discuss the forecast methodology used for forecasting volumes.
18 A. The forecasted future volumes are developed from normalized volumes and customer counts
19 by month, from previous years. The forecasted monthly volumes are determined by
20 multiplying the forecasted monthly use per customer by the projected monthly customer
21 count.
22
23 Q. Please describe the weather normalization methodology utilized.
7 Direct Testimony of James A. Van Sickle On Behalf of SEMCO Energy Gas Company
1 A. The historical period calendar month volumes, November 2015 through October 2016 in this
2 case, are recorded by rate class. A monthly base load volume, identified as the average
3 volumes for July and August 2016 for each rate class, is deducted from the historical
4 volumes of each month of the year. The months of June through September are not adjusted
5 since there are no effective heating related volumes occurring in these months. During these
6 summer months, very small deviations from the monthly norms can lead to unsupportable
7 results. After removing the base load, the remaining heat sensitive volumes are adjusted by
8 the ratio of the actual degree days for each month to a 15-year degree day average for that
9 month. The base load volumes are then added back into the adjusted heat sensitive
10 volumes to derive a normalized volume by month. The weather normalized historic volumes
11 are divided by the historic number of customers to derive a weather-normalized consumption
12 per customer which is then multiplied by the forecasted customers to derive the forecasted
13 volumes.
14 The total forecasted monthly demand for GCR and GCC customers for the 2017-2018
15 plan year is shown on line 22, page 2 of 10, on Exhibit A-18.
16
17 Q. Has the Company included a forecast of GCC customer participation and if so, how
18 was it developed?
19 A. Yes, there are seven marketers currently active in the Company’s territory, and others are
20 inquiring about marketing behind the Company’s system. Because GCC in SEMCO Gas’s
21 territory has not matured, forecasting specific numbers of GCC customers and volumes at
22 this time is difficult. Due to an uncertain amount of growth, the Company has chosen to
23 forecast a participation rate by taking the number of participating customers through October
24 2016 and maintaining that number for this GCR period. Assuming the Company’s use per
25 customer by rate, SEMCO Gas is forecasting GCC customers to use about 3,374,845Dth in
8 Direct Testimony of James A. Van Sickle On Behalf of SEMCO Energy Gas Company
1 the 2017-2018 plan year. This volume is subtracted from the Total Small Customers
2 Volumes to develop the GCR volumes.
3
4 Q. How were LAUF, CU, and GIK forecasted?
5 A. A five-year average (September 2004 through August 2009) percentage was used to develop
6 Lost and Unaccounted for (“LAUF”) gas volumes. Company Use (“CU”) was derived from
7 calendar year 2009 data. LAUF and CU factors are applied to total customer requirements,
8 including GCC and Large Transportation. The Gas in Kind (“GIK”) percentage used is the
9 percentage used in the Company’s last general rate case, U-16169. A forecast of the Large
10 Transportation volumes provides an estimate of GIK volumes, which are charged to the
11 transportation rates.
12
13 Contingency Factor
14 Q. Please discuss Exhibit A-19.
15 A. Exhibit A-19 shows the components of the 2017-2018 GCR factor and the Contingency
16 Factor Mechanism (“CFM”).
17
18 Q. Does the Company intend to use the CFM to recover increases in the cost of gas over
19 the prices used to develop the GCR factor in this proceeding?
20 A. Yes.
21
22 Q. Does the CFM allow the Company to make monthly pricing adjustments?
23 A. Yes, it does. The ability to make a monthly adjustment, based on NYMEX pricing, is a
24 practical way to assess pricing requirements since SEMCO Gas purchases gas on a monthly
25 basis.
9 Direct Testimony of James A. Van Sickle On Behalf of SEMCO Energy Gas Company
1
2 Q. How was the single fractional multiplier calculated?
3 A. The single fractional multiplier was calculated by assuming a $1.00 and a $2.00 increase in
4 NYMEX prices above those used to develop the Base GCR factor. The slope of the three
5 resulting calculated annualized GCR amounts is .9903 for the 2017-2018 plan year. See
6 Exhibit A-17 pages 1, 2, and 3, as well as Exhibit A-20.
7
8 Q. How will the single fractional multiplier be used?
9 A. The single fractional multiplier is implemented when an increase in NYMEX occurs compared
10 to the base NYMEX. That difference is multiplied by the single fractional multiplier. The
11 results are then added to SEMCO Gas’s base GCR factor and become the Maximum
12 Authorized GCR factor the Company could bill its customers for the following month. If the
13 monthly review shows that there is no increase over the base NYMEX, no increase is
14 available and the base GCR factor is the Maximum Authorized GCR Factor allowed.
15
16 Q. When does the Company review the GCR year NYMEX pricing to determine if an
17 increase is appropriate?
18 A. SEMCO Gas reviews the average of the first five trading days in the month prior to the
19 implementation month. That review determines if an increase to its Maximum Authorized
20 GCR factor is warranted based on increases in the NYMEX prices over those used to
21 develop the base GCR factor in this proceeding. The months that would be reviewed are the
22 months that directly precede the months in the GCR year, that is, March 2017 through
23 February 2018.
10 Direct Testimony of James A. Van Sickle On Behalf of SEMCO Energy Gas Company
1 As the GCR year progresses, the months that have closed will be fixed at their closing
2 prices, and months that have not closed will be set using a five-day average determined by
3 the first five trading days of the month.
4
5 Q. Why does the Company propose using the CFM?
6 A. The CFM was developed to be used in a rising market only. It is not required in a falling
7 market. The purpose of the CFM was to protect the Company and its customers from under
8 recoveries that would certainly occur if the NYMEX market rose and the Company had no
9 reasonable way of timely charging the increased cost for natural gas supply to its customers
10 who ultimately benefit from appropriately priced natural gas.
11
12 Alternative Fuels
13 Q. What alternative fuels are available in SEMCO Gas’sservice areas and what are their
14 costs compared to the cost of natural gas?
15 A. Other heating fuels available to the Company’s customers include #2 fuel oil, propane and
16 electricity. They are listed below, with the comparison to natural gas in costs per unit and
17 equivalent costs per therm.
18 Fuel Type Cost/Unit Conversion Cost/Therm
19 #2 Fuel Oil $2.05/gallon 1.3890 $1.476
20 Propane $1.48gallon 0.9550 $1.549
21 Electricity $0.1425/Kwh 0.03413 $4.1752
22 Natural Gas $4.1943/Dth 10.000 $0.41943
11 Direct Testimony of James A. Van Sickle On Behalf of SEMCO Energy Gas Company
1 This Cost/Unit data is based on information taken from the eia.gov website. The Fuel Oil and
2 Propane information was from the week of November 1, 2016. The Electricity information is
3 from the month of November 2016. The Natural Gas cost per therm is based on the
4 Company’s proposed rate of $4.1943 per Dth, as filed in this case.
5
6 Q. Does this complete your pre-filed direct testimony at this time?
7 A. Yes.
12 SEMCO Energy Gas Company Case No: U-18157 Calculation of the Base GCR Factor Exhibit A-17 MPSC Page 1 of 3 2017 2017 2017 2017 2017 2017 2017 2017 2017 2018 2018 2018 Line April May June July August September October November December January February March Total 1 2 Delivered Supply - Dth 2,857,800 1,514,288 849,480 747,007 720,843 916,290 2,254,010 3,954,480 5,958,324 6,990,097 6,110,160 4,936,254 37,809,033 3 Less Volumes For 4 Company Use 15,397 9,995 7,250 6,698 7,025 8,192 13,802 19,721 26,918 31,064 31,950 28,310 206,323 5 Lost and Unaccounted For 34,136 22,161 16,075 14,850 15,575 18,162 30,600 43,725 59,682 68,872 70,838 62,768 457,443 6 Gas in Kind (17,134) (14,972) (13,644) (12,993) (14,364) (15,901) (18,725) (18,529) (19,211) (22,426) (23,770) (21,956) (213,624) 7 Total GCR Supplies - Dth 2,825,401 1,497,104 839,798 738,452 712,608 905,837 2,228,333 3,909,562 5,890,935 6,912,587 6,031,141 4,867,132 37,358,891 8 9 Sales Dth 10 Rate Schedule Sales (Billed and Unbilled) 2,825,401 1,497,104 839,798 738,452 712,608 905,837 2,228,333 3,909,562 5,890,935 6,912,587 6,031,141 4,867,132 37,358,891 11 GCC Volumes 255,929 137,697 81,776 75,912 71,503 89,191 214,151 361,874 516,555 602,334 531,490 436,433 3,374,845 12 Total Sales and Choice Volumes 3,081,330 1,634,801 921,574 814,364 784,110 995,028 2,442,484 4,271,437 6,407,490 7,514,921 6,562,632 5,303,565 40,733,736 13 14 Cost of Gas Sold ($) 15 Purchased and Produced - Fixed Costs $2,072,489 $2,003,310 $2,001,358 $2,003,310 $2,003,310 $2,001,358 $2,076,149 $3,717,281 $3,729,481 $3,737,544 $3,700,944 $3,737,544 $32,784,076 16 Net Fixed Costs 2,072,489 2,003,310 2,001,358 2,003,310 2,003,310 2,001,358 2,076,149 3,717,281 3,729,481 3,737,544 3,700,944 3,737,544 32,784,076 17 18 Purchased and Produced - Volumetric Costs 12,549,168 11,537,623 10,851,696 10,018,040 9,926,142 10,267,147 13,326,082 10,530,671 12,575,126 11,956,271 9,017,044 7,160,225 129,715,235 19 Net (to) From Storage - Volumetric Costs (3,130,402) (6,576,214) (8,053,370) (7,570,496) (7,571,852) (7,280,981) (5,879,708) 2,970,572 8,053,456 12,282,132 11,979,466 9,610,462 (1,166,934) 20 Total Cost of Gas $11,491,255 $6,964,719 $4,799,684 $4,450,855 $4,357,600 $4,987,524 $9,522,523 $17,218,524 $24,358,062 $27,975,946 $24,697,453 $20,508,231 $161,332,377 21 22 Less Cost of Gas For 23 Company Use (65,698) (42,650) (30,938) (28,580) (29,975) (34,954) (58,892) (84,152) (114,862) (132,550) (136,333) (120,802) (880,385) 24 Lost and Unaccounted For (145,661) (94,560) (68,593) (63,364) (66,458) (77,497) (130,572) (186,576) (254,663) (293,880) (302,267) (267,833) (1,951,924) 25 Gas in Kind 73,109 63,886 58,218 55,440 61,293 67,849 79,898 79,063 81,976 95,692 101,425 93,688 911,538 26 Total Cost of Gas Sold $11,353,005 $6,891,395 $4,758,371 $4,414,351 $4,322,460 $4,942,922 $9,412,957 $17,026,859 $24,070,512 $27,645,209 $24,360,278 $20,213,284 $159,411,606 27 28 GCR Revenues ($) $ 0.6726 $ 1.2254 $ 2.1717 $ 2.4600 $ 2.5549 $ 2.0114 $ 0.8500 $ 0.8703 $ 0.5821 $ 0.4973 $ 0.5639 $ 0.7047 $ 0.8048 29 Net Total Fixed Costs $2,072,489 $2,003,310 $2,001,358 $2,003,310 $2,003,310 $2,001,358 $2,076,149 $3,717,281 $3,729,481 $3,737,544 $3,700,944 $3,737,544 $32,784,076 30 Total Sales & Choice Dth 3,081,330 1,634,801 921,574 814,364 784,110 995,028 2,442,484 4,271,437 6,407,490 7,514,921 6,562,632 5,303,565 40,733,736 31 Balancing and Demand Charge $0.8048 $0.8048 $0.8048 $0.8048 $0.8048 $0.8048 $0.8048 $0.8048 $0.8048 $0.8048 $0.8048 $0.8048 $0.8048 32 Capacity Demand Revenues $2,479,854 $1,315,688 $741,683 $655,400 $631,052 $800,798 $1,965,711 $3,437,652 $5,156,748 $6,048,008 $5,281,606 $4,268,309 $32,782,510.61 33 34 Total Cost of Gas Sold $11,353,005 $6,891,395 $4,758,371 $4,414,351 $4,322,460 $4,942,922 $9,412,957 $17,026,859 $24,070,512 $27,645,209 $24,360,278 $20,213,284 $159,411,606 35 Less Capacity Demand Charge Revenues (2,479,854) (1,315,688) (741,683) (655,400) (631,052) (800,798) (1,965,711) (3,437,652) (5,156,748) (6,048,008) (5,281,606) (4,268,309) (32,782,511) 36 Commodity Cost of Gas Sold $8,873,151 $5,575,707 $4,016,688 $3,758,951 $3,691,408 $4,142,123 $7,447,246 $13,589,207 $18,913,764 $21,597,201 $19,078,672 $15,944,976 $126,629,096 37 38 Gas Commodity Cost $3.3895 $3.3895 $3.3895 $3.3895 $3.3895 $3.3895 $3.3895 $3.3895 $3.3895 $3.3895 $3.3895 $3.3895 $3.3895 39 Commodity Revenues $9,576,695 $5,074,435 $2,846,496 $2,502,984 $2,415,384 $3,070,335 $7,552,934 $13,251,462 $19,967,325 $23,430,214 $20,442,554 $16,497,144 $126,627,961 40 41 Total GCR Factor Billed $4.1943 $4.1943 $4.1943 $4.1943 $4.1943 $4.1943 $4.1943 $4.1943 $4.1943 $4.1943 $4.1943 $4.1943 42 43 Total Cost of Gas Revenues $12,056,550 $6,390,122 $3,588,179 $3,158,384 $3,046,436 $3,871,134 $9,518,645 $16,689,114 $25,124,073 $29,478,222 $25,724,160 $20,765,452 $159,410,472 44 Incremental Over / (Under) Recovery $703,544 ($501,273) ($1,170,193) ($1,255,967) ($1,276,024) ($1,071,788) $105,688 ($337,745) $1,053,561 $1,833,013 $1,363,881 $552,168 45 Cumulative Over / (Under) Recovery $703,544 $202,272 ($967,921) ($2,223,888) ($3,499,912) ($4,571,700) ($4,466,013) ($4,803,758) ($3,750,197) ($1,917,184) ($553,302) ($1,135) 46 47 Dth 48 System Avg. Cost of Gas 49 Total Cost of Gas $161,332,377 Line 21 Balancing and Demand Charge $0.8048 50 Total Supply 37,809,033 Line 2 Gas Commodity Charge $3.3895 51 System Avg. Cost of Gas $ 4.2670 Base GCR Factor $4.1943 SEMCO Energy Gas Company NYMEX + $1.00 Case No: U-18157 Calculation of the Base GCR Factor Exhibit A-17 MPSC Page 2 of 3 2017 2017 2017 2017 2017 2017 2017 2017 2017 2018 2018 2018 Line April May June July August September October November December January February March Total 1 2 Delivered Supply - Dth 2,857,800 1,514,288 849,480 747,007 720,843 916,290 2,254,010 3,954,480 5,958,324 6,990,097 6,110,160 4,936,254 37,809,033 3 Less Volumes For 4 Company Use 15,397 9,995 7,250 6,698 7,025 8,192 13,802 19,721 26,918 31,064 31,950 28,310 206,323 5 Lost and Unaccounted For 34,136 22,161 16,075 14,850 15,575 18,162 30,600 43,725 59,682 68,872 70,838 62,768 457,443 6 Gas in Kind (17,134) (14,972) (13,644) (12,993) (14,364) (15,901) (18,725) (18,529) (19,211) (22,426) (23,770) (21,956) (213,624) 7 Total GCR Supplies - Dth 2,825,401 1,497,104 839,798 738,452 712,608 905,837 2,228,333 3,909,562 5,890,935 6,912,587 6,031,141 4,867,132 37,358,891 8 9 Sales Dth 10 Rate Schedule Sales (Billed and Unbilled) 2,825,401 1,497,104 839,798 738,452 712,608 905,837 2,228,333 3,909,562 5,890,935 6,912,587 6,031,141 4,867,132 37,358,891 11 GCC Volumes 255,929 137,697 81,776 75,912 71,503 89,191 214,151 361,874 516,555 602,334 531,490 436,433 3,374,845 12 Total Sales and Choice Volumes 3,081,330 1,634,801 921,574 814,364 784,110 995,028 2,442,484 4,271,437 6,407,490 7,514,921 6,562,632 5,303,565 40,733,736 13 14 Cost of Gas Sold ($) 15 Purchased and Produced - Fixed Costs $2,072,489 $2,003,310 $2,001,358 $2,003,310 $2,003,310 $2,001,358 $2,076,149 $3,717,281 $3,729,481 $3,737,544 $3,700,944 $3,737,544 $32,784,076 16 Net Fixed Costs 2,072,489 2,003,310 2,001,358 2,003,310 2,003,310 2,001,358 2,076,149 3,717,281 3,729,481 3,737,544 3,700,944 3,737,544 32,784,076 17 18 Purchased and Produced - Volumetric Costs 16,444,216 15,168,749 14,253,713 13,146,419 13,035,170 13,496,634 17,459,642 13,658,550 16,133,507 15,251,362 11,525,015 9,230,815 168,803,791 19 Net (to) From Storage - Volumetric Costs (4,096,717) (8,663,008) (10,589,992) (9,930,547) (9,939,161) (9,571,801) (7,708,080) 3,817,650 10,344,469 15,784,384 15,389,133 12,352,776 (2,810,893) 20 Total Cost of Gas $14,419,988 $8,509,050 $5,665,078 $5,219,183 $5,099,319 $5,926,191 $11,827,711 $21,193,481 $30,207,457 $34,773,290 $30,615,092 $25,321,135 $198,776,973 21 22 Less Cost of Gas For 23 Company Use (80,946) (52,549) (38,118) (35,213) (36,932) (43,067) (72,561) (103,683) (141,521) (163,314) (167,975) (148,839) (1,084,719) 24 Lost and Unaccounted For (179,468) (116,507) (84,513) (78,071) (81,883) (95,484) (160,877) (229,879) (313,770) (362,088) (372,422) (329,995) (2,404,958) 25 Gas in Kind 90,078 78,714 71,731 68,308 75,519 83,597 98,443 97,413 101,002 117,902 124,966 115,433 1,123,103 26 Total Cost of Gas Sold $14,249,652 $8,418,708 $5,614,177 $5,174,207 $5,056,023 $5,871,237 $11,692,715 $20,957,331 $29,853,168 $34,365,790 $30,199,660 $24,957,733 $196,410,400 27 28 GCR Revenues ($) 29 Net Total Fixed Costs $2,072,489 $2,003,310 $2,001,358 $2,003,310 $2,003,310 $2,001,358 $2,076,149 $3,717,281 $3,729,481 $3,737,544 $3,700,944 $3,737,544 $32,784,076 30 Total Sales & Choice Dth 3,081,330 1,634,801 921,574 814,364 784,110 995,028 2,442,484 4,271,437 6,407,490 7,514,921 6,562,632 5,303,565 40,733,736 31 Balancing and Demand Charge $0.8048 $0.8048 $0.8048 $0.8048 $0.8048 $0.8048 $0.8048 $0.8048 $0.8048 $0.8048 $0.8048 $0.8048 $0.8048 32 Capacity Demand Revenues $2,479,854 $1,315,688 $741,683 $655,400 $631,052 $800,798 $1,965,711 $3,437,652 $5,156,748 $6,048,008 $5,281,606 $4,268,309 $32,782,510.61 33 34 Total Cost of Gas Sold $14,249,652 $8,418,708 $5,614,177 $5,174,207 $5,056,023 $5,871,237 $11,692,715 $20,957,331 $29,853,168 $34,365,790 $30,199,660 $24,957,733 $196,410,400 35 Less Capacity Demand Charge Revenues (2,479,854) (1,315,688) (741,683) (655,400) (631,052) (800,798) (1,965,711) (3,437,652) (5,156,748) (6,048,008) (5,281,606) (4,268,309) (32,782,511) 36 Commodity Cost of Gas Sold $11,769,797 $7,103,021 $4,872,494 $4,518,807 $4,424,971 $5,070,438 $9,727,004 $17,519,679 $24,696,419 $28,317,782 $24,918,054 $20,689,424 $163,627,889 37 38 Gas Commodity Cost $4.3799 $4.3799 $4.3799 $4.3799 $4.3799 $4.3799 $4.3799 $4.3799 $4.3799 $4.3799 $4.3799 $4.3799 $4.3799 39 Commodity Revenues $12,374,972 $6,557,167 $3,678,232 $3,234,347 $3,121,150 $3,967,477 $9,759,875 $17,123,492 $25,801,708 $30,276,440 $26,415,796 $21,317,551 $163,628,207 40 41 Total GCR Factor Billed $5.1847 $5.1847 $5.1847 $5.1847 $5.1847 $5.1847 $5.1847 $5.1847 $5.1847 $5.1847 $5.1847 $5.1847 42 43 Total Cost of Gas Revenues $14,854,827 $7,872,854 $4,419,915 $3,889,747 $3,752,203 $4,768,275 $11,725,586 $20,561,145 $30,958,456 $36,324,449 $31,697,402 $25,585,860 $196,410,717 44 Incremental Over / (Under) Recovery $605,175 ($545,854) ($1,194,262) ($1,284,460) ($1,303,820) ($1,102,962) $32,871 ($396,187) $1,105,288 $1,958,658 $1,497,743 $628,127 45 Cumulative Over / (Under) Recovery $605,175 $59,321 ($1,134,941) ($2,419,401) ($3,723,221) ($4,826,182) ($4,793,312) ($5,189,498) ($4,084,210) ($2,125,552) ($627,810) $318 46 47 Dth 48 System Avg. Cost of Gas 49 Total Cost of Gas $198,776,973 Line 21 Balancing and Demand Charge $0.8048 50 Total Supply 37,809,033 Line 2 Gas Commodity Charge $4.3799 51 System Avg. Cost of Gas $ 5.2574 Base GCR Factor $5.1847 SEMCO Energy Gas Company NYMEX + $2.00 Case No: U-18157 Calculation of the Base GCR Factor Exhibit A-17 MPSC Page 3 of 3 2017 2017 2017 2017 2017 2017 2017 2017 2017 2018 2018 2018 Line April May June July August September October November December January February March Total 1 2 Delivered Supply - Dth 2,857,800 1,514,288 849,480 747,007 720,843 916,290 2,254,010 3,954,480 5,958,324 6,990,097 6,110,160 4,936,254 37,809,033 3 Less Volumes For 4 Company Use 15,397 9,995 7,250 6,698 7,025 8,192 13,802 19,721 26,918 31,064 31,950 28,310 206,323 5 Lost and Unaccounted For 34,136 22,161 16,075 14,850 15,575 18,162 30,600 43,725 59,682 68,872 70,838 62,768 457,443 6 Gas in Kind (17,134) (14,972) (13,644) (12,993) (14,364) (15,901) (18,725) (18,529) (19,211) (22,426) (23,770) (21,956) (213,624) 7 Total GCR Supplies - Dth 2,825,401 1,497,104 839,798 738,452 712,608 905,837 2,228,333 3,909,562 5,890,935 6,912,587 6,031,141 4,867,132 37,358,891 8 9 Sales Dth 10 Rate Schedule Sales (Billed and Unbilled) 2,825,401 1,497,104 839,798 738,452 712,608 905,837 2,228,333 3,909,562 5,890,935 6,912,587 6,031,141 4,867,132 37,358,891 11 GCC Volumes 255,929 137,697 81,776 75,912 71,503 89,191 214,151 361,874 516,555 602,334 531,490 436,433 3,374,845 12 Total Sales and Choice Volumes 3,081,330 1,634,801 921,574 814,364 784,110 995,028 2,442,484 4,271,437 6,407,490 7,514,921 6,562,632 5,303,565 40,733,736 13 14 Cost of Gas Sold ($) 15 Purchased and Produced - Fixed Costs $2,072,489 $2,003,310 $2,001,358 $2,003,310 $2,003,310 $2,001,358 $2,076,149 $3,717,281 $3,729,481 $3,737,544 $3,700,944 $3,737,544 $32,784,076 16 Net Fixed Costs 2,072,489 2,003,310 2,001,358 2,003,310 2,003,310 2,001,358 2,076,149 3,717,281 3,729,481 3,737,544 3,700,944 3,737,544 32,784,076 17 18 Purchased and Produced - Volumetric Costs 20,341,516 18,806,203 17,655,733 16,274,800 16,144,198 16,726,120 21,584,560 16,784,856 19,691,561 18,545,680 14,032,763 11,299,687 207,887,677 19 Net (to) From Storage - Volumetric Costs (5,065,484) (10,755,693) (13,126,385) (12,290,350) (12,306,223) (11,862,388) (9,527,668) 4,664,624 12,635,244 19,286,311 18,798,497 15,094,859 (4,454,657) 20 Total Cost of Gas $17,348,520 $10,053,820 $6,530,705 $5,987,760 $5,841,285 $6,865,090 $14,133,040 $25,166,761 $36,056,286 $41,569,534 $36,532,203 $30,132,090 $236,217,096 21 22 Less Cost of Gas For 23 Company Use (96,193) (62,446) (45,298) (41,845) (43,888) (51,178) (86,228) (123,212) (168,177) (194,075) (199,614) (176,874) (1,289,028) 24 Lost and Unaccounted For (213,271) (138,451) (100,432) (92,776) (97,306) (113,469) (191,178) (273,177) (372,869) (430,288) (442,569) (392,151) (2,857,937) 25 Gas in Kind 107,044 93,540 85,241 81,174 89,743 99,342 116,984 115,761 120,026 140,109 148,503 137,175 1,334,642 26 Total Cost of Gas Sold $17,146,101 $9,946,462 $6,470,217 $5,934,313 $5,789,834 $6,799,785 $13,972,618 $24,886,132 $35,635,266 $41,085,281 $36,038,524 $29,700,240 $233,404,773 27 28 GCR Revenues ($) 29 Net Total Fixed Costs $2,072,489 $2,003,310 $2,001,358 $2,003,310 $2,003,310 $2,001,358 $2,076,149 $3,717,281 $3,729,481 $3,737,544 $3,700,944 $3,737,544 $32,784,076 30 Total Sales & Choice Dth 3,081,330 1,634,801 921,574 814,364 784,110 995,028 2,442,484 4,271,437 6,407,490 7,514,921 6,562,632 5,303,565 40,733,736 31 Balancing and Demand Charge $0.8048 $0.8048 $0.8048 $0.8048 $0.8048 $0.8048 $0.8048 $0.8048 $0.8048 $0.8048 $0.8048 $0.8048 $0.8048 32 Capacity Demand Revenues $2,479,854 $1,315,688 $741,683 $655,400 $631,052 $800,798 $1,965,711 $3,437,652 $5,156,748 $6,048,008 $5,281,606 $4,268,309 $32,782,510.61 33 34 Total Cost of Gas Sold $17,146,101 $9,946,462 $6,470,217 $5,934,313 $5,789,834 $6,799,785 $13,972,618 $24,886,132 $35,635,266 $41,085,281 $36,038,524 $29,700,240 $233,404,773 35 Less Capacity Demand Charge Revenues (2,479,854) (1,315,688) (741,683) (655,400) (631,052) (800,798) (1,965,711) (3,437,652) (5,156,748) (6,048,008) (5,281,606) (4,268,309) (32,782,511) 36 Commodity Cost of Gas Sold $14,666,247 $8,630,774 $5,728,534 $5,278,913 $5,158,782 $5,998,987 $12,006,907 $21,448,480 $30,478,517 $35,037,273 $30,756,918 $25,431,931 $200,622,262 37 38 Gas Commodity Cost $5.3701 $5.3701 $5.3701 $5.3701 $5.3701 $5.3701 $5.3701 $5.3701 $5.3701 $5.3701 $5.3701 $5.3701 $5.3701 39 Commodity Revenues $15,172,684 $8,039,599 $4,509,800 $3,965,562 $3,826,775 $4,864,437 $11,966,370 $20,994,741 $31,634,912 $37,121,284 $32,387,832 $26,136,985 $200,620,981 40 41 Total GCR Factor Billed $6.1749 $6.1749 $6.1749 $6.1749 $6.1749 $6.1749 $6.1749 $6.1749 $6.1749 $6.1749 $6.1749 $6.1749 42 43 Total Cost of Gas Revenues $17,652,538 $9,355,287 $5,251,483 $4,620,962 $4,457,827 $5,665,235 $13,932,081 $24,432,393 $36,791,660 $43,169,292 $37,669,438 $30,405,294 $233,403,491 44 Incremental Over / (Under) Recovery $506,437 ($591,175) ($1,218,734) ($1,313,350) ($1,332,007) ($1,134,550) ($40,537) ($453,739) $1,156,394 $2,084,011 $1,630,915 $705,054 45 Cumulative Over / (Under) Recovery $506,437 ($84,738) ($1,303,471) ($2,616,822) ($3,948,829) ($5,083,379) ($5,123,916) ($5,577,656) ($4,421,261) ($2,337,250) ($706,335) ($1,281) 46 47 Dth 48 System Avg. Cost of Gas 49 Total Cost of Gas $236,217,096 Line 21 Balancing and Demand Charge $0.8048 50 Total Supply 37,809,033 Line 2 Gas Commodity Charge $5.3701 51 System Avg. Cost of Gas $ 6.2476 Base GCR Factor $6.1749 SEMCO Energy Gas Company Exhibit A-18 Five Year Forecast of GCR Requirements Page 1 of 10 Case No: U-18157 1 Forecast Month End Customers 2018 2018 2018 2017 2017 2017 2017 2017 2017 2017 2017 2017 2 Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec Average 3 Sales Customers - Net 4 Residential 259,334 259,522 259,536 256,657 255,513 254,720 254,300 254,171 254,650 255,676 257,230 258,692 256,667 5 GS-1 20,059 20,092 20,084 19,944 19,845 19,783 19,748 19,737 19,736 19,772 19,878 20,003 19,890 6 GS-2 2,837 2,835 2,836 2,822 2,814 2,810 2,805 2,809 2,809 2,821 2,835 2,839 2,823 7 GS-3 668 666 668 661 662 659 662 663 663 667 672 668 665 8 Total 282,897 283,115 283,124 280,084 278,834 277,972 277,515 277,380 277,858 278,935 280,615 282,201 280,044 9 10 11 Residential Choice 17,134 17,134 17,134 17,134 17,134 17,134 17,134 17,134 17,134 17,134 17,134 17,134 17,134 12 GS-1 Choice 2,017 2,017 2,017 2,017 2,017 2,017 2,017 2,017 2,017 2,017 2,017 2,017 2,017 13 GS-2 Choice 425 425 425 425 425 425 425 425 425 425 425 425 425 14 GS-3 Choice 105 105 105 105 105 105 105 105 105 105 105 105 105 15 Total Choice 19,681 19,681 19,681 19,681 19,681 19,681 19,681 19,681 19,681 19,681 19,681 19,681 19,681 16 17 Total Small Customers 18 Residential 276,468 276,656 276,670 273,791 272,647 271,854 271,434 271,305 271,784 272,810 274,364 275,826 273,801 19 GS-1 22,076 22,109 22,101 21,961 21,862 21,800 21,765 21,754 21,753 21,789 21,895 22,020 21,907 20 GS-2 3,262 3,260 3,261 3,247 3,239 3,235 3,230 3,234 3,234 3,246 3,260 3,264 3,248 21 GS-3 773 771 773 766 767 764 767 768 768 772 777 773 770 22 Total Small Customers 302,578 302,796 302,805 299,765 298,515 297,653 297,196 297,061 297,539 298,616 300,296 301,882 299,725 23 24 25 Total Large Transport 257 256 258 258 259 257 258 259 254 255 255 256 257 26 27 28 Total Customers 302,835 303,052 303,063 300,023 298,774 297,910 297,454 297,320 297,793 298,871 300,551 302,138 299,982 SEMCO Energy Gas Company Exhibit A-18 Five Year Forecast of GCR Requirements Page 2 of 10 Case No: U-18157 1 Forecast Volumes - Dth 2018 2018 2018 2017 2017 2017 2017 2017 2017 2017 2017 2017 2 Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec Total 3 GCR Volumes - Net 4 Residential 4,713,227 4,068,265 3,210,291 1,879,325 998,559 517,481 405,681 405,286 537,066 1,360,971 2,473,738 4,006,164 24,576,054 5 GS-1 882,311 764,424 608,344 304,530 127,056 64,821 64,812 70,382 83,253 216,747 448,182 727,710 4,362,572 6 GS-2 631,697 561,207 481,232 269,224 143,154 81,455 77,952 78,526 95,188 237,753 423,977 546,593 3,627,959 7 GS-3 683,854 647,137 580,521 372,326 228,327 176,029 190,008 158,423 190,347 412,871 563,637 610,481 4,813,960 8 Total GCR Dth 6,911,089 6,041,033 4,880,388 2,825,405 1,497,097 839,786 738,453 712,617 905,853 2,228,342 3,909,534 5,890,948 37,380,544 9 10 Choice Volumes 11 Residential Choice 311,399 268,592 211,936 125,461 66,961 34,809 27,334 27,321 36,136 91,205 164,775 265,341 1,631,270 12 GS-1 Choice 88,722 76,740 61,096 30,798 12,914 6,609 6,620 7,193 8,508 22,112 45,478 73,379 440,167 13 GS-2 Choice 94,640 84,132 72,117 40,549 21,621 12,322 11,810 11,881 14,401 35,816 63,554 81,840 544,681 14 GS-3 Choice 107,573 102,026 91,284 59,122 36,201 28,036 30,149 25,109 30,145 65,019 88,068 95,995 758,726 15 Total Choice Dth 602,334 531,490 436,433 255,929 137,697 81,776 75,912 71,503 89,191 214,151 361,874 516,555 3,374,845 16 17 GCR & Choice Volumes 18 Residential 5,024,626 4,336,857 3,422,228 2,004,786 1,065,520 552,290 433,015 432,607 573,202 1,452,176 2,638,513 4,271,505 26,207,324 19 GS-1 971,032 841,164 669,439 335,328 139,970 71,430 71,432 77,575 91,761 238,858 493,659 801,089 4,802,739 20 GS-2 726,337 645,339 553,349 309,774 164,775 93,777 89,762 90,407 109,588 273,569 487,530 628,433 4,172,640 21 GS-3 791,427 749,163 671,805 431,447 264,529 204,065 220,156 183,532 220,492 477,890 651,706 706,476 5,572,687 22 Total Small Customers Dth 7,513,422 6,572,523 5,316,821 3,081,334 1,634,794 921,562 814,365 784,119 995,043 2,442,493 4,271,408 6,407,503 40,755,389 23 24 25 Total Large Transport - Dth 2,257,313 2,085,115 2,010,139 1,627,116 1,421,843 1,295,702 1,233,878 1,364,129 1,510,048 1,778,214 1,759,613 1,824,441 20,167,551 26 27 28 Total Volume - Dth 9,770,735 8,657,639 7,326,960 4,708,450 3,056,637 2,217,265 2,048,243 2,148,248 2,505,091 4,220,708 6,031,021 8,231,944 60,922,940 29 30 U-16169 31 Co Use 0.00327 31,950 28,310 23,959 15,397 9,995 7,250 6,698 7,025 8,192 13,802 19,721 26,918 199,218 32 LAUF 0.00725 70,838 62,768 53,120 34,136 22,161 16,075 14,850 15,575 18,162 30,600 43,725 59,682 441,691 33 GIK (0.01053) (23,770) (21,956) (21,167) (17,134) (14,972) (13,644) (12,993) (14,364) (15,901) (18,725) (18,529) (19,211) (212,364) 34 Total 79,019 69,122 55,913 32,399 17,184 9,682 8,555 8,235 10,453 25,677 44,918 67,389 428,545 35 36 Delivered Supply - Dth 6,990,107 6,110,155 4,936,301 2,857,804 1,514,281 849,468 747,008 720,852 916,305 2,254,019 3,954,451 5,958,337 37,809,089 SEMCO Energy Gas Company Exhibit A-18 Five Year Forecast of GCR Requirements Page 3 of 10 Case No: U-18157 1 Forecast Month End Customers 2019 2019 2019 2018 2018 2018 2018 2018 2018 2018 2018 2018 2 Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec Average 3 Sales Customers - Net 4 Residential 261,482 261,670 261,684 258,804 257,660 256,868 256,447 256,319 256,797 257,823 259,378 260,840 258,814 5 GS-1 20,143 20,176 20,168 20,029 19,929 19,868 19,833 19,822 19,820 19,856 19,962 20,087 19,974 6 GS-2 2,846 2,844 2,845 2,831 2,823 2,819 2,815 2,818 2,819 2,831 2,845 2,848 2,832 7 GS-3 667 666 668 661 662 659 662 662 663 667 672 668 665 8 Total 285,138 285,356 285,365 282,325 281,075 280,213 279,756 279,621 280,099 281,176 282,856 284,442 282,285 9 10 11 Residential Choice 17,134 17,134 17,134 17,134 17,134 17,134 17,134 17,134 17,134 17,134 17,134 17,134 17,134 12 GS-1 Choice 2,017 2,017 2,017 2,017 2,017 2,017 2,017 2,017 2,017 2,017 2,017 2,017 2,017 13 GS-2 Choice 425 425 425 425 425 425 425 425 425 425 425 425 425 14 GS-3 Choice 105 105 105 105 105 105 105 105 105 105 105 105 105 15 Total Choice 19,681 19,681 19,681 19,681 19,681 19,681 19,681 19,681 19,681 19,681 19,681 19,681 19,681 16 17 Total Small Customers 18 Residential 278,616 278,804 278,818 275,938 274,794 274,002 273,581 273,453 273,931 274,957 276,512 277,974 275,948 19 GS-1 22,160 22,193 22,185 22,046 21,946 21,885 21,850 21,839 21,837 21,873 21,979 22,104 21,991 20 GS-2 3,271 3,269 3,270 3,256 3,248 3,244 3,240 3,243 3,244 3,256 3,270 3,273 3,257 21 GS-3 772 771 773 766 767 764 767 767 768 772 777 773 770 22 Total Small Customers 304,819 305,037 305,046 302,006 300,756 299,894 299,437 299,302 299,780 300,857 302,537 304,123 301,966 23 24 25 Total Large Transport 257 256 258 258 259 257 258 259 254 255 255 256 257 26 27 28 Total Customers 305,076 305,293 305,304 302,264 301,015 300,151 299,695 299,561 300,034 301,112 302,792 304,379 302,223 SEMCO Energy Gas Company Exhibit A-18 Five Year Forecast of GCR Requirements Page 4 of 10 Case No: U-18157 1 Forecast Volumes - Dth 2019 2019 2019 2018 2018 2018 2018 2018 2018 2018 2018 2018 2 Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec Total 3 GCR Volumes - Net 4 Residential 4,761,055 4,117,927 3,237,126 1,955,837 1,026,833 523,954 409,072 411,545 529,307 1,359,424 2,520,310 4,042,389 24,894,780 5 GS-1 890,484 777,213 616,997 321,146 133,952 63,624 64,848 72,474 81,770 216,053 459,197 746,434 4,444,191 6 GS-2 635,489 566,808 482,881 277,105 149,891 81,117 79,971 80,529 94,798 238,535 436,261 554,928 3,678,314 7 GS-3 697,830 651,317 579,724 381,394 239,719 178,225 191,342 165,412 186,907 422,972 575,885 610,415 4,881,142 8 Total GCR Dth 6,984,858 6,113,266 4,916,727 2,935,481 1,550,396 846,920 745,233 729,960 892,783 2,236,983 3,991,653 5,954,166 37,898,427 9 10 Choice Volumes 11 Residential Choice 311,976 269,640 211,954 129,485 68,283 34,950 27,331 27,510 35,316 90,343 166,487 265,536 1,638,811 12 GS-1 Choice 89,168 77,697 61,705 32,341 13,557 6,459 6,595 7,375 8,321 21,947 46,398 74,951 446,515 13 GS-2 Choice 94,899 84,695 72,129 41,600 22,564 12,230 12,076 12,144 14,295 35,816 65,182 82,818 550,448 14 GS-3 Choice 109,812 102,724 91,193 60,584 38,022 28,397 30,372 26,226 29,612 66,635 90,016 96,020 769,612 15 Total Choice Dth 605,855 534,756 436,981 264,011 142,426 82,036 76,374 73,255 87,544 214,740 368,083 519,325 3,405,386 16 17 GCR & Choice Volumes 18 Residential 5,073,031 4,387,567 3,449,080 2,085,322 1,095,116 558,904 436,403 439,055 564,624 1,449,767 2,686,797 4,307,925 26,533,591 19 GS-1 979,651 854,910 678,702 353,487 147,509 70,083 71,444 79,848 90,092 238,000 505,596 821,385 4,890,705 20 GS-2 730,388 651,503 555,010 318,705 172,455 93,347 92,046 92,673 109,093 274,351 501,444 637,746 4,228,762 21 GS-3 807,642 754,041 670,916 441,978 277,741 206,622 221,714 191,639 216,518 489,606 665,901 706,436 5,650,755 22 Total Small Customers Dth 7,590,712 6,648,022 5,353,708 3,199,492 1,692,822 928,957 821,607 803,215 980,327 2,451,723 4,359,736 6,473,491 41,303,813 23 24 25 Total Large Transport - Dth 2,257,313 2,085,115 2,010,139 1,627,116 1,421,843 1,295,702 1,233,878 1,364,129 1,510,048 1,778,214 1,759,613 1,824,441 20,167,551 26 27 28 Total Volume - Dth 9,848,025 8,733,137 7,363,846 4,826,608 3,114,664 2,224,659 2,055,485 2,167,344 2,490,375 4,229,938 6,119,350 8,297,932 61,471,364 29 30 U-16169 31 Co Use 0.00327 32,203 28,557 24,080 15,783 10,185 7,275 6,721 7,087 8,144 13,832 20,010 27,134 201,011 32 LAUF 0.00725 71,398 63,315 53,388 34,993 22,581 16,129 14,902 15,713 18,055 30,667 44,365 60,160 445,667 33 GIK (0.01053) (23,770) (21,956) (21,167) (17,134) (14,972) (13,644) (12,993) (14,364) (15,901) (18,725) (18,529) (19,211) (212,364) 34 Total 79,832 69,916 56,301 33,642 17,794 9,760 8,631 8,436 10,298 25,774 45,847 68,083 434,314 35 36 Delivered Supply - Dth 7,064,690 6,183,182 4,973,028 2,969,124 1,568,190 856,680 753,864 738,396 903,081 2,262,758 4,037,500 6,022,249 38,332,741 SEMCO Energy Gas Company Exhibit A-18 Five Year Forecast of GCR Requirements Page 5 of 10 Case No: U-18157 1 Forecast Month End Customers 2020 2020 2020 2019 2019 2019 2019 2019 2019 2019 2019 2019 2 Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec Average 3 Sales Customers - Net 4 Residential 263,629 263,817 263,831 260,952 259,808 259,015 258,595 258,466 258,945 259,971 261,525 262,987 260,962 5 GS-1 20,228 20,261 20,253 20,113 20,014 19,952 19,917 19,906 19,905 19,941 20,047 20,172 20,059 6 GS-2 2,855 2,854 2,855 2,840 2,833 2,828 2,824 2,828 2,828 2,840 2,854 2,857 2,841 7 GS-3 667 666 667 661 662 659 661 662 663 666 672 667 664 8 Total 287,379 287,597 287,606 284,566 283,316 282,454 281,997 281,862 282,340 283,417 285,097 286,683 284,526 9 10 11 Residential Choice 17,134 17,134 17,134 17,134 17,134 17,134 17,134 17,134 17,134 17,134 17,134 17,134 17,134 12 GS-1 Choice 2,017 2,017 2,017 2,017 2,017 2,017 2,017 2,017 2,017 2,017 2,017 2,017 2,017 13 GS-2 Choice 425 425 425 425 425 425 425 425 425 425 425 425 425 14 GS-3 Choice 105 105 105 105 105 105 105 105 105 105 105 105 105 15 Total Choice 19,681 19,681 19,681 19,681 19,681 19,681 19,681 19,681 19,681 19,681 19,681 19,681 19,681 16 17 Total Small Customers 18 Residential 280,763 280,951 280,965 278,086 276,942 276,149 275,729 275,600 276,079 277,105 278,659 280,121 278,096 19 GS-1 22,245 22,278 22,270 22,130 22,031 21,969 21,934 21,923 21,922 21,958 22,064 22,189 22,076 20 GS-2 3,280 3,279 3,280 3,265 3,258 3,253 3,249 3,253 3,253 3,265 3,279 3,282 3,266 21 GS-3 772 771 772 766 767 764 766 767 768 771 777 772 769 22 Total Small Customers 307,060 307,278 307,287 304,247 302,997 302,135 301,678 301,543 302,021 303,098 304,778 306,364 304,207 23 24 25 Total Large Transport 257 256 258 258 259 257 258 259 254 255 255 256 257 26 27 28 Total Customers 307,317 307,534 307,545 304,505 303,256 302,392 301,936 301,802 302,275 303,353 305,033 306,620 304,464 SEMCO Energy Gas Company Exhibit A-18 Five Year Forecast of GCR Requirements Page 6 of 10 Case No: U-18157 1 Forecast Volumes - Dth 2020 2020 2020 2019 2019 2019 2019 2019 2019 2019 2019 2019 2 Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec Total 3 GCR Volumes - Net 4 Residential 4,777,646 4,175,037 3,249,519 1,953,047 1,042,675 520,925 417,809 415,102 531,480 1,370,860 2,522,453 4,065,264 25,041,816 5 GS-1 888,637 782,516 617,348 317,550 136,755 64,628 66,398 72,908 82,554 218,408 454,114 749,440 4,451,256 6 GS-2 636,892 568,474 480,549 279,211 148,774 82,545 81,709 80,694 96,044 240,660 432,907 558,677 3,687,136 7 GS-3 706,500 651,168 565,682 385,156 242,216 177,072 199,589 168,194 183,987 423,307 582,695 600,977 4,886,544 8 Total GCR Dth 7,009,674 6,177,195 4,913,098 2,934,964 1,570,420 845,170 765,506 736,898 894,066 2,253,234 3,992,168 5,974,358 38,066,752 9 10 Choice Volumes 11 Residential Choice 310,513 271,154 211,034 128,236 68,763 34,459 27,683 27,518 35,167 90,350 165,260 264,858 1,634,996 12 GS-1 Choice 88,611 77,901 61,483 31,845 13,782 6,533 6,724 7,387 8,365 22,092 45,691 74,937 445,353 13 GS-2 Choice 94,800 84,668 71,548 41,780 22,323 12,405 12,298 12,129 14,435 36,017 64,472 83,107 549,983 14 GS-3 Choice 111,218 102,739 89,017 61,205 38,432 28,224 31,693 26,677 29,160 66,712 91,114 94,571 770,764 15 Total Choice Dth 605,142 536,462 433,081 263,066 143,301 81,622 78,398 73,711 87,128 215,172 366,537 517,474 3,401,095 16 17 GCR & Choice Volumes 18 Residential 5,088,158 4,446,191 3,460,553 2,081,284 1,111,439 555,384 445,492 442,620 566,647 1,461,210 2,687,713 4,330,122 26,676,812 19 GS-1 977,248 860,417 678,831 349,394 150,537 71,161 73,122 80,295 90,920 240,500 499,805 824,377 4,896,608 20 GS-2 731,692 653,143 552,097 320,991 171,097 94,950 94,007 92,823 110,479 276,677 497,379 641,785 4,237,119 21 GS-3 817,718 753,906 654,699 446,361 280,648 205,296 231,282 194,872 213,148 490,019 673,809 695,549 5,657,307 22 Total Small Customers Dth 7,614,817 6,713,657 5,346,180 3,198,030 1,713,721 926,792 843,904 810,610 981,194 2,468,406 4,358,705 6,491,832 41,467,847 23 24 25 Total Large Transport - Dth 2,257,313 2,085,115 2,010,139 1,627,116 1,421,843 1,295,702 1,233,878 1,364,129 1,510,048 1,778,214 1,759,613 1,824,441 20,167,551 26 27 28 Total Volume - Dth 9,872,130 8,798,773 7,356,318 4,825,146 3,135,563 2,222,494 2,077,782 2,174,739 2,491,242 4,246,621 6,118,318 8,316,273 61,635,398 29 30 U-16169 31 Co Use 0.00327 32,282 28,772 24,055 15,778 10,253 7,268 6,794 7,111 8,146 13,886 20,007 27,194 201,548 32 LAUF 0.00725 71,573 63,791 53,333 34,982 22,733 16,113 15,064 15,767 18,062 30,788 44,358 60,293 446,857 33 GIK (0.01053) (23,770) (21,956) (21,167) (17,134) (14,972) (13,644) (12,993) (14,364) (15,901) (18,725) (18,529) (19,211) (212,364) 34 Total 80,085 70,607 56,222 33,627 18,014 9,737 8,866 8,514 10,307 25,950 45,836 68,276 436,040 35 36 Delivered Supply - Dth 7,089,760 6,247,801 4,969,320 2,968,591 1,588,434 854,907 774,371 745,412 904,373 2,279,184 4,038,004 6,042,634 38,502,792 SEMCO Energy Gas Company Exhibit A-18 Five Year Forecast of GCR Requirements Page 7 of 10 Case No: U-18157 1 Forecast Month End Customers 2021 2021 2021 2020 2020 2020 2020 2020 2020 2020 2020 2020 2 Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec Average 3 Sales Customers - Net 4 Residential 265,777 265,965 265,979 263,099 261,955 261,163 260,742 260,614 261,092 262,118 263,673 265,135 263,109 5 GS-1 20,312 20,345 20,337 20,198 20,098 20,037 20,002 19,991 19,989 20,025 20,131 20,256 20,143 6 GS-2 2,865 2,863 2,864 2,850 2,842 2,837 2,833 2,837 2,837 2,849 2,863 2,866 2,850 7 GS-3 667 665 667 661 662 659 661 662 662 666 671 667 664 8 Total 289,620 289,838 289,847 286,807 285,557 284,695 284,238 284,103 284,581 285,658 287,338 288,924 286,767 9 10 11 Residential Choice 17,134 17,134 17,134 17,134 17,134 17,134 17,134 17,134 17,134 17,134 17,134 17,134 17,134 12 GS-1 Choice 2,017 2,017 2,017 2,017 2,017 2,017 2,017 2,017 2,017 2,017 2,017 2,017 2,017 13 GS-2 Choice 425 425 425 425 425 425 425 425 425 425 425 425 425 14 GS-3 Choice 105 105 105 105 105 105 105 105 105 105 105 105 105 15 Total Choice 19,681 19,681 19,681 19,681 19,681 19,681 19,681 19,681 19,681 19,681 19,681 19,681 19,681 16 17 Total Small Customers 18 Residential 282,911 283,099 283,113 280,233 279,089 278,297 277,876 277,748 278,226 279,252 280,807 282,269 280,243 19 GS-1 22,329 22,362 22,354 22,215 22,115 22,054 22,019 22,008 22,006 22,042 22,148 22,273 22,160 20 GS-2 3,290 3,288 3,289 3,275 3,267 3,262 3,258 3,262 3,262 3,274 3,288 3,291 3,275 21 GS-3 772 770 772 766 767 764 766 767 767 771 776 772 769 22 Total Small Customers 309,301 309,519 309,528 306,488 305,238 304,376 303,919 303,784 304,262 305,339 307,019 308,605 306,448 23 24 25 Total Large Transport 257 256 258 258 259 257 258 259 254 255 255 256 257 26 27 28 Total Customers 309,558 309,775 309,786 306,746 305,497 304,633 304,177 304,043 304,516 305,594 307,274 308,861 306,705 SEMCO Energy Gas Company Exhibit A-18 Five Year Forecast of GCR Requirements Page 8 of 10 Case No: U-18157 1 Forecast Volumes - Dth 2021 2021 2021 2020 2020 2020 2020 2020 2020 2020 2020 2020 2 Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec Total 3 GCR Volumes - Net 4 Residential 4,823,172 4,183,600 3,262,269 1,960,644 1,049,104 528,491 414,062 412,488 515,672 1,366,477 2,518,301 4,080,151 25,114,432 5 GS-1 891,060 783,148 611,868 318,284 136,213 64,823 65,394 72,734 79,753 220,827 449,888 733,096 4,427,090 6 GS-2 637,012 570,002 480,160 281,103 149,343 82,091 80,667 80,011 93,282 245,028 428,781 546,804 3,674,284 7 GS-3 695,333 651,954 573,923 388,930 239,599 176,744 198,131 168,816 177,196 428,557 567,855 606,497 4,873,537 8 Total GCR Dth 7,046,577 6,188,705 4,928,221 2,948,961 1,574,259 852,148 758,254 734,050 865,904 2,260,890 3,964,826 5,966,549 38,089,343 9 10 Choice Volumes 11 Residential Choice 310,939 269,516 210,151 127,684 68,620 34,673 27,209 27,119 33,841 89,323 163,645 263,675 1,626,394 12 GS-1 Choice 88,483 77,640 60,684 31,785 13,670 6,525 6,595 7,339 8,047 22,243 45,076 72,997 441,084 13 GS-2 Choice 94,512 84,622 71,259 41,926 22,335 12,297 12,101 11,987 13,974 36,552 63,651 81,079 546,295 14 GS-3 Choice 109,501 102,901 90,348 61,828 38,032 28,182 31,473 26,786 28,095 67,565 88,827 95,476 769,014 15 Total Choice Dth 603,435 534,680 432,442 263,224 142,657 81,677 77,378 73,231 83,957 215,683 361,198 513,227 3,382,787 16 17 GCR & Choice Volumes 18 Residential 5,134,110 4,453,116 3,472,421 2,088,328 1,117,724 563,164 441,271 439,607 549,513 1,455,801 2,681,946 4,343,826 26,740,826 19 GS-1 979,544 860,788 672,552 350,069 149,883 71,348 71,989 80,073 87,801 243,069 494,964 806,094 4,868,173 20 GS-2 731,524 654,624 551,419 323,029 171,678 94,387 92,768 91,998 107,256 281,580 492,432 627,882 4,220,579 21 GS-3 804,835 754,856 664,271 450,759 277,630 204,926 229,604 195,602 205,291 496,123 656,682 701,973 5,642,551 22 Total Small Customers Dth 7,650,012 6,723,385 5,360,663 3,212,185 1,716,915 933,825 835,632 807,280 949,860 2,476,573 4,326,024 6,479,775 41,472,130 23 24 25 Total Large Transport - Dth 2,257,313 2,085,115 2,010,139 1,627,116 1,421,843 1,295,702 1,233,878 1,364,129 1,510,048 1,778,214 1,759,613 1,824,441 20,167,551 26 27 28 Total Volume - Dth 9,907,325 8,808,500 7,370,801 4,839,300 3,138,758 2,229,528 2,069,511 2,171,409 2,459,908 4,254,787 6,085,637 8,304,216 61,639,681 29 30 U-16169 31 Co Use 0.00327 32,397 28,804 24,103 15,825 10,264 7,291 6,767 7,101 8,044 13,913 19,900 27,155 201,562 32 LAUF 0.00725 71,828 63,862 53,438 35,085 22,756 16,164 15,004 15,743 17,834 30,847 44,121 60,206 446,888 33 GIK (0.01053) (23,770) (21,956) (21,167) (17,134) (14,972) (13,644) (12,993) (14,364) (15,901) (18,725) (18,529) (19,211) (212,364) 34 Total 80,456 70,709 56,374 33,776 18,048 9,811 8,779 8,479 9,977 26,036 45,492 68,149 436,085 35 36 Delivered Supply - Dth 7,127,033 6,259,414 4,984,595 2,982,737 1,592,307 861,959 767,033 742,529 875,881 2,286,925 4,010,318 6,034,698 38,525,428 SEMCO Energy Gas Company Exhibit A-18 Five Year Forecast of GCR Requirements Page 9 of 10 Case No: U-18157 1 Forecast Month End Customers 2022 2022 2022 2021 2021 2021 2021 2021 2021 2021 2021 2021 2 Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec Average 3 Sales Customers - Net 4 Residential 267,924 268,112 268,126 265,247 264,103 263,310 262,890 262,761 263,240 264,266 265,820 267,282 265,257 5 GS-1 20,397 20,430 20,422 20,282 20,183 20,121 20,086 20,075 20,074 20,110 20,216 20,341 20,228 6 GS-2 2,874 2,872 2,873 2,859 2,851 2,847 2,842 2,846 2,846 2,858 2,872 2,876 2,860 7 GS-3 667 665 667 660 661 658 661 662 662 666 671 667 664 8 Total 291,861 292,079 292,088 289,048 287,798 286,936 286,479 286,344 286,822 287,899 289,579 291,165 289,008 9 10 11 Residential Choice 17,134 17,134 17,134 17,134 17,134 17,134 17,134 17,134 17,134 17,134 17,134 17,134 17,134 12 GS-1 Choice 2,017 2,017 2,017 2,017 2,017 2,017 2,017 2,017 2,017 2,017 2,017 2,017 2,017 13 GS-2 Choice 425 425 425 425 425 425 425 425 425 425 425 425 425 14 GS-3 Choice 105 105 105 105 105 105 105 105 105 105 105 105 105 15 Total Choice 19,681 19,681 19,681 19,681 19,681 19,681 19,681 19,681 19,681 19,681 19,681 19,681 19,681 16 17 Total Small Customers 18 Residential 285,058 285,246 285,260 282,381 281,237 280,444 280,024 279,895 280,374 281,400 282,954 284,416 282,391 19 GS-1 22,414 22,447 22,439 22,299 22,200 22,138 22,103 22,092 22,091 22,127 22,233 22,358 22,245 20 GS-2 3,299 3,297 3,298 3,284 3,276 3,272 3,267 3,271 3,271 3,283 3,297 3,301 3,285 21 GS-3 772 770 772 765 766 763 766 767 767 771 776 772 769 22 Total Small Customers 311,542 311,760 311,769 308,729 307,479 306,617 306,160 306,025 306,503 307,580 309,260 310,846 308,689 23 24 25 Total Large Transport 257 256 258 258 259 257 258 259 254 255 255 256 257 26 27 28 Total Customers 311,799 312,016 312,027 308,987 307,738 306,874 306,418 306,284 306,757 307,835 309,515 311,102 308,946 SEMCO Energy Gas Company Exhibit A-18 Five Year Forecast of GCR Requirements Page 10 of 10 Case No: U-18157 1 Forecast Volumes - Dth 2022 2022 2022 2021 2021 2021 2021 2021 2021 2021 2021 2021 2 Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec Total 3 GCR Volumes - Net 4 Residential 4,646,795 3,981,482 3,158,361 1,977,841 1,033,438 514,352 385,291 392,949 457,957 1,268,877 2,438,832 3,963,520 24,219,693 5 GS-1 863,977 743,501 588,389 332,403 152,030 65,102 62,283 68,671 80,337 222,472 437,857 715,224 4,332,246 6 GS-2 622,713 548,635 469,476 292,199 148,817 78,535 78,255 76,605 90,030 256,441 417,975 544,097 3,623,778 7 GS-3 674,915 644,372 571,886 461,735 248,426 191,128 193,141 184,493 148,270 464,584 556,277 616,034 4,955,261 8 Total GCR Dth 6,808,400 5,917,989 4,788,112 3,064,178 1,582,711 849,117 718,970 722,718 776,593 2,212,373 3,850,941 5,838,876 37,130,978 9 10 Choice Volumes 11 Residential Choice 310,896 265,056 210,248 132,096 68,858 34,151 25,403 26,043 30,635 85,754 163,817 264,714 1,617,672 12 GS-1 Choice 87,245 74,955 59,341 34,962 15,708 6,648 6,357 6,999 8,191 22,793 44,620 72,426 440,246 13 GS-2 Choice 93,600 82,516 70,585 45,806 23,010 11,981 11,962 11,611 13,599 38,758 62,859 81,732 548,019 14 GS-3 Choice 106,127 101,552 89,892 72,510 38,874 30,661 31,414 30,144 23,813 73,135 86,886 96,832 781,840 15 Total Choice Dth 597,868 524,079 430,067 285,375 146,450 83,441 75,136 74,797 76,239 220,440 358,182 515,705 3,387,778 16 17 GCR & Choice Volumes 18 Residential 4,957,692 4,246,538 3,368,608 2,109,937 1,102,295 548,503 410,694 418,992 488,592 1,354,630 2,602,649 4,228,234 25,837,365 19 GS-1 951,222 818,455 647,730 367,365 167,739 71,750 68,640 75,670 88,528 245,265 482,477 787,651 4,772,492 20 GS-2 716,312 631,152 540,062 338,005 171,827 90,516 90,217 88,216 103,629 295,199 480,833 625,830 4,171,798 21 GS-3 781,042 745,924 661,779 534,245 287,300 221,789 224,555 214,637 172,083 537,719 643,163 712,866 5,737,101 22 Total Small Customers Dth 7,406,268 6,442,069 5,218,179 3,349,553 1,729,161 932,558 794,106 797,515 852,832 2,432,813 4,209,123 6,354,580 40,518,756 23 24 25 Total Large Transport - Dth 2,257,313 2,085,115 2,010,139 1,627,116 1,421,843 1,295,702 1,233,878 1,364,129 1,510,048 1,778,214 1,759,613 1,824,441 20,167,551 26 27 28 Total Volume - Dth 9,663,581 8,527,184 7,228,317 4,976,668 3,151,004 2,228,260 2,027,984 2,161,644 2,362,880 4,211,028 5,968,736 8,179,021 60,686,307 29 30 U-16169 31 Co Use 0.00327 31,600 27,884 23,637 16,274 10,304 7,286 6,632 7,069 7,727 13,770 19,518 26,745 198,444 32 LAUF 0.00725 70,061 61,822 52,405 36,081 22,845 16,155 14,703 15,672 17,131 30,530 43,273 59,298 439,976 33 GIK (0.01053) (23,770) (21,956) (21,167) (17,134) (14,972) (13,644) (12,993) (14,364) (15,901) (18,725) (18,529) (19,211) (212,364) 34 Total 77,891 67,750 54,875 35,221 18,177 9,798 8,342 8,376 8,957 25,575 44,262 66,832 426,056 35 36 Delivered Supply - Dth 6,886,291 5,985,739 4,842,987 3,099,399 1,600,887 858,914 727,312 731,094 785,550 2,237,949 3,895,203 5,905,708 37,557,033 M.P.S.C. - No. 1 – Gas Case No. U-18157 SEMCO ENERGY GAS COMPANY Exhibit A-19 (To revise Gas Cost Recovery Factors) Page 1 of 2
The Gas Cost Recovery Factors
The following maximum Gas Cost Recovery Factors for the April 2017 through March 2018 GCR plan period are authorized pursuant to the Gas Cost Recovery Clause:
Billing Months Maximum Authorized Actual Factor Factor $/Dth Billed / Dth
April, 2017 $4.1943/Dth May, 2017 June, 2017 July, 2017 August, 2017 September, 2017 October, 2017 November, 2017 December, 2017 January, 2018 February, 2018 March, 2018
The current month’s Gas Cost Recovery factor is composed of the following cost components:
Balancing and Demand Charge $0.8048/Dth Gas Commodity Charge $3.3895/ Dth
Issued Effective for bills rendered on and after the Colleen Starring first billing cycle . Issued under President authority of 1982 PA 304, Section 6h and the Port Huron, MI Michigan Public Service Commission for Self-implementation in Case No. U-18157. M.P.S.C. - No. 1 – Gas Case No. U-18157 SEMCO ENERGY GAS COMPANY Exhibit A-19 (To revise Gas Cost Recovery Factors) Page 2 of 2
Contingency Factor Matrix April '17 April '17 March '18 March '18 Fractional Mult.
Fractional Mult. Fm 0.9903 Fm 0.9903 Plan NYMEX
Plan NYMEX (Xplan) $3.4224 (Xplan) $3.4224 Base GCR
Base GCR Factor $4.1943 Factor $4.1943
Resulting Resulting NYMEX Increase Incremental NYMEX Increase Incremental maximum maximum Contingent Contingent allowable allowable GCR Factor GCR Factor GCR GCR Factor / Dth / Dth Factor / / Dth Dth ≥ < ≥ <
$0.00 $0.05 $0.0000 $4.1943 $1.50 $1.55 $1.4855 $5.6798 $0.05 $0.10 $0.0495 $4.2438 $1.55 $1.60 $1.5350 $5.7293 $0.10 $0.15 $0.0990 $4.2933 $1.60 $1.65 $1.5845 $5.7788 $0.15 $0.20 $0.1485 $4.3428 $1.65 $1.70 $1.6340 $5.8283 $0.20 $0.25 $0.1981 $4.3924 $1.70 $1.75 $1.6835 $5.8778 $0.25 $0.30 $0.2476 $4.4419 $1.75 $1.80 $1.7330 $5.9273 $0.30 $0.35 $0.2971 $4.4914 $1.80 $1.85 $1.7825 $5.9768 $0.35 $0.40 $0.3466 $4.5409 $1.85 $1.90 $1.8321 $6.0264 $0.40 $0.45 $0.3961 $4.5904 $1.90 $1.95 $1.8816 $6.0759 $0.45 $0.50 $0.4456 $4.6399 $1.95 $2.00 $1.9311 $6.1254 $0.50 $0.55 $0.4952 $4.6895 $2.00 $2.05 $1.9806 $6.1749 $0.55 $0.60 $0.5447 $4.7390 $2.05 $2.10 $2.0301 $6.2244 $0.60 $0.65 $0.5942 $4.7885 $2.10 $2.15 $2.0796 $6.2739 $0.65 $0.70 $0.6437 $4.8380 $2.15 $2.20 $2.1291 $6.3234 $0.70 $0.75 $0.6932 $4.8875 $2.20 $2.25 $2.1787 $6.3730 $0.75 $0.80 $0.7427 $4.9370 $2.25 $2.30 $2.2282 $6.4225 $0.80 $0.85 $0.7922 $4.9865 $2.30 $2.35 $2.2777 $6.4720 $0.85 $0.90 $0.8418 $5.0361 $2.35 $2.40 $2.3272 $6.5215 $0.90 $0.95 $0.8913 $5.0856 $2.40 $2.45 $2.3767 $6.5710 $0.95 $1.00 $0.9408 $5.1351 $2.45 $2.50 $2.4262 $6.6205 $1.00 $1.05 $0.9903 $5.1846 $2.50 $2.55 $2.4758 $6.6701 $1.05 $1.10 $1.0398 $5.2341 $2.55 $2.60 $2.5253 $6.7196 $1.10 $1.15 $1.0893 $5.2836 $2.60 $2.65 $2.5748 $6.7691 $1.15 $1.20 $1.1388 $5.3331 $2.65 $2.70 $2.6243 $6.8186 $1.20 $1.25 $1.1884 $5.3827 $2.70 $2.75 $2.6738 $6.8681 $1.25 $1.30 $1.2379 $5.4322 $2.75 $2.80 $2.7233 $6.9176 $1.30 $1.35 $1.2874 $5.4817 $2.80 $2.85 $2.7728 $6.9671 $1.35 $1.40 $1.3369 $5.5312 $2.85 $2.90 $2.8224 $7.0167 $1.40 $1.45 $1.3864 $5.5807 $2.90 $2.95 $2.8719 $7.0662 $1.45 $1.50 $1.4359 $5.6302 $2.95 $3.00 $2.9214 $7.1157 $3.00 $2.9709 $7.1652
Continued on Sheet Issued , Effective for service rendered on Colleen Starring and after . Issued under President authority of the Michigan Public Service Port Huron, MI Commission dated in Case No. U-18157. SEMCO Energy Gas Company Case No: U-18157 SEMCO Gas's Proposed Contingency Mechanism Exhibit: A-20 Single Factor Calculation Methodology Page 1 of 1
Calculated NYMEX GCR Factor Increase Slope Source:
GCR Base Factor $ 4.1943 $ - 0.9903 A-17 Page 1 GCR Base Factor + $1.00 NYMEX Increase $ 5.1847 $ 1.00 0.9903 A-17 Page 2 GCR Base Factor + $2.00 NYMEX Increase $ 6.1749 $ 2.00 0.9903 A-17 Page 3
Realised Single Factor 0.9903 Filed Single Factor 0.9903 STATE OF MICHIGAN
BEFORE THE MICHIGAN PUBLIC SERVICE COMMISSION
*****
In the matter of the application of ) SEMCO ENERGY GAS COMPANY for authority to ) Case No. U-18157 implement a gas cost recovery plan and factors for ) the 12-month period from April 2017 ) through March 2018 and for related approvals. ) )
DIRECT TESTIMONY AND EXHIBIT
OF MICHAEL J. CLYNE
ON BEHALF OF SEMCO ENERGY GAS COMPANY DIRECT TESTIMONY AND EXHIBIT OF MICHAEL J. CLYNE ON BEHALF OF SEMCO ENERGY GAS COMPANY
1 Q. Please state your full name and business address.
2 A. Michael J. Clyne, 1411 Third Street, Suite A, Port Huron, Michigan 48060.
3
4 Q. What is your title?
5 A. My title is Supervisor of Engineering for SEMCO Energy Gas Company (“SEMCO Gas”
6 or the “Company”), a division of SEMCO Energy, Inc.
7
8 Q. Please state your educational background and business experience.
9 A. I graduated from Michigan State University in May 1999 with a Bachelor of Science
10 Degree in Civil Engineering. Upon graduation I worked in the Civil/Structural Engineering
11 field. In 2006 I became a licensed professional Engineer. My natural gas industry
12 related experience began in March 2014 when I accepted an engineering position at
13 SEMCO Gas. In August 2016, I attained the position of Engineering Supervisor.
14
15 Q. What is the purpose of your testimony in this proceeding?
16 A. The purpose of my testimony is to describe the SEMCO Gas system, including the Port
17 Huron, Central, Holland, Niles, and U.P. East and West areas of the system. The
18 description will include pipeline interconnects, storage facilities, active local production
19 interconnects, and an operational overview of SEMCO Gas’s transmission and
20 distribution systems.
21
22 Q. Are you sponsoring any exhibits in this proceeding?
23 A. Yes. I am sponsoring Exhibit A-21 System Gate Stations.
24
25 Q. Was this exhibit prepared by you or under your direction?
Page 2 of 36 DIRECT TESTIMONY AND EXHIBIT OF MICHAEL J. CLYNE ON BEHALF OF SEMCO ENERGY GAS COMPANY
1 A. Yes.
2
3 Q. Please explain Exhibit A-21.
4 A. This five page map exhibit displays SEMCO Gas’s service territory, its pipeline
5 interconnects, storage facilities, local production interconnects, and transmission and
6 distribution system. This exhibit segments SEMCO Gas’s service area into the Port
7 Huron, Central, Holland, Niles, and UP East and West areas.
8
9 Port Huron Service Area
10 Q. Please identify SEMCO Gas’spipeline interconnects and storage supply points for
11 the Port Huron area gas system from Exhibit A-21.
12 A. The Port Huron area gas system, on page 1 of 5 of Exhibit A-21, has active pipeline
13 interconnects with Consumers Energy Company (“CECO”) at the New Haven
14 Interchange and the Akron Interchange, ANR Pipeline Company (“ANR”) at the ANR
15 Interchange, and Great Lakes Gas Transmission Company (“GLGTC”) at two Great
16 Lakes Interchanges. The Port Huron gas system has two active pipeline interconnects
17 with SEMCO Pipeline Company’s Greenwood Pipeline (“GWPL”.) They include the
18 Avoca Station and Kilgore Rd Station. The Port Huron gas system has one pipeline
19 interconnect with DTE Energy Pipeline Company (“DTE”.) The interconnect is at the
20 Ray 17 Interchange. The Port Huron gas system has two storage supply points located
21 at SEMCO Gas’s Collin Gas Storage Field in Cottrellville Township and Morton Gas
22 Storage Field in Marysville. There are four active interconnects with local producers in
23 the Port Huron area. These local production interconnects include the Rapley, Klingler,
24 Pilat, and Tiger facilities.
25
Page 3 of 36 DIRECT TESTIMONY AND EXHIBIT OF MICHAEL J. CLYNE ON BEHALF OF SEMCO ENERGY GAS COMPANY
1 Q. Please describe SEMCO Gas’spipeline interconnect facilities where supply is
2 received from ANR at the ANR Interchange in Port Huron.
3 A. The ANR Interchange facility delivers gas from ANR's 20" - 975 psig Maximum
4 Allowable Operating Pressure (“MAOP”) transmission line into SEMCO Gas’s 12" - 465
5 psig MAOP transmission line on Bauman Rd near the City of Richmond as part of the
6 Port Huron gas system. This station is utilized year round for transport gas and
7 transmission system supply. The interconnect is continuously monitored and controlled
8 by SEMCO Gas’s SCADA system.
9
10 Q. Please describe SEMCO Gas’spipeline interconnect facilities where supply is
11 received from GLGTC at the Trumble Rd - GLGTC Interchange in the Port Huron
12 area.
13 A. The GLGTC interconnection facility at Trumble Rd delivers gas from GLGTC’s 2-36”,
14 974 MAOP lines into SEMCO Gas’s 12" - 465 psig MAOP transmission line on Trumble
15 Rd in St. Clair Township as part of the Port Huron gas system. This station is utilized
16 year round for transport gas and transmission system supply. The interconnect is
17 continuously monitored and controlled by SEMCO Gas’s SCADA system.
18
19 Q. Please describe SEMCO Gas’spipeline interconnect facilities where supply is
20 received from GLGTC at the Bauman Rd - GLGTC Interchange in the Port Huron
21 area.
22 A. The GLGTC Interchange facility delivers gas from GLGTC's 36" - 974 psig MAOP
23 transmission line into SEMCO Gas’s 12" - 465 psig MAOP transmission line on Bauman
24 Road near the City of Richmond as part of the Port Huron gas system. This station is
Page 4 of 36 DIRECT TESTIMONY AND EXHIBIT OF MICHAEL J. CLYNE ON BEHALF OF SEMCO ENERGY GAS COMPANY
1 utilized year round for transport gas and transmission system supply. The interconnect
2 is continuously monitored and controlled by SEMCO Gas’s SCADA system.
3
4 Q. Please describe SEMCO Gas’spipeline interconnect facilities where supply is
5 received from CECO at the New Haven Interchange in the Port Huron area.
6 A. The New Haven Interchange facility delivers gas from CECO's 12" - 960 psig MAOP
7 transmission line into SEMCO Gas’s 12" - 465 psig MAOP transmission line on 25 Mile
8 Road near the City of New Haven as part of the Port Huron gas system. This station is
9 utilized during winter months to transport gas and for transmission system supply. The
10 interconnection is continuously monitored and controlled by SEMCO Gas’s SCADA
11 system.
12
13 Q. As described in the testimony of Company witness Water Fitzgerald, SEMCO Gas
14 plans to cease firm gas deliveries to the CECO-New Haven interconnection point.
15 What operational and system modifications will be necessary by the Company in
16 order to do this?
17 A. The CECO-New Haven interconnection point is a key location for winter gas supply to
18 the Company’s Port Huron Service Area. With the absence of this interconnection
19 during the winter period, additional supply will be required from the Company’s other
20 existing supply interconnection points. In order to move the additional supply received
21 from the Company’s other existing supply points into the area currently supplied by the
22 CECO-New Haven interconnection, improvements to the Company’s Port Huron Service
23 Area distribution system are necessary. The required distribution system improvements
24 being planned by the Company include increasing the capacity of an existing district
Page 5 of 36 DIRECT TESTIMONY AND EXHIBIT OF MICHAEL J. CLYNE ON BEHALF OF SEMCO ENERGY GAS COMPANY
1 pressure regulator station and the construction a new district pressure regulator station
2 in the area currently served by the CECO-New Haven interconnection.
3
4 Q. What is the estimated cost for the necessary distribution system improvements?
5 A. The Company has not finalized the design of the necessary distribution system
6 improvements however, the current cost estimate is approximately $973,000.
7
8 Q. Will the cost of the necessary distribution system improvements be recovered as
9 a cost of gas?
10 A. No. The cost for the necessary distribution system improvements will be treated as a
11 capital expense to be recovered in base rates in the Company’s next general rate case.
12
13 Q. Does the Company plan to perform these modifications prior to the expiration of
14 the CECO Act 9 Gas Transportation Agreement?
15 A. Yes. The Company plans to complete the necessary distribution system improvements
16 prior to the expiration of the CECO Act 9 Gas Transportation Agreement.
17
18 Q. Please describe SEMCO Gas’spipeline interconnect facilities where supply is
19 received from CECO at the Akron Interchange in the Port Huron area.
20 A. The Akron Interchange delivers gas from CECO's 12" - 400 psig MAOP pipeline into
21 SEMCO Gas’s 6" - 400 psig MAOP distribution line on Elmwood Road near the Village
22 of Cass City as part of the Port Huron gas system. This station is utilized during the
23 winter months for additional gas supply to the Sandusky area gas system. The
24 interconnect is continuously monitored by SEMCO Gas’s SCADA system.
25
Page 6 of 36 DIRECT TESTIMONY AND EXHIBIT OF MICHAEL J. CLYNE ON BEHALF OF SEMCO ENERGY GAS COMPANY
1 Q. Please describe SEMCO Gas’spipeline interconnect facilities where supply is
2 received from the GWPL at the Kilgore Road. Station in the Port Huron area.
3 A. The Kilgore Rd Station delivers gas from GWPL’s 18" - 1164 psig MAOP transmission
4 line into SEMCO Gas’s 6" - 400 psig MAOP distribution line on Kilgore Road near the
5 Village of Avoca as part of the Port Huron gas system. This station is utilized during the
6 winter months for additional gas supply to the Sandusky area gas system. The
7 interconnect is continuously monitored and controlled by SEMCO Gas’s SCADA system.
8
9 Q. Please describe SEMCO Gas’spipeline interconnect facilities where supply is
10 received from the GWPL at the Avoca Station in the Port Huron area.
11 A. The Avoca Station delivers gas from GWPL's 18" - 1164 psig MAOP transmission line
12 into SEMCO Gas’s 6" - 60 psig MAOP distribution line on Avoca Road near the Village
13 of Avoca as part of the Port Huron gas system. This station is utilized year round for
14 system supply for the Village of Avoca. The interconnect is continuously monitored by
15 SEMCO Gas’s SCADA system.
16
17 Q. Please describe SEMCO Gas’spipeline interconnect facilities with DTE at the Ray
18 17 Interchange in the Port Huron area.
19 A. The Ray 17 Interchange delivers gas from DTE's 36" - 1000 psig MAOP transmission
20 line into SEMCO Gas’s 6" - 300 psig MAOP distribution line on Romeo Plank Road near
21 the Village of Ray Center as part of the Port Huron gas system. This station is utilized
22 when necessary for system supply for the Romeo area gas system. The interconnect is
23 continuously monitored and controlled by SEMCO Gas’s SCADA system.
24
25
Page 7 of 36 DIRECT TESTIMONY AND EXHIBIT OF MICHAEL J. CLYNE ON BEHALF OF SEMCO ENERGY GAS COMPANY
1 Q. Please describe SEMCO Gas’sMorton storage supply point facilities in the Port
2 Huron area.
3 A. The Morton storage facility delivers gas into SEMCO Gas’s 12" - 465 psig MAOP high
4 pressure distribution line on Gratiot Ave in the City of Marysville as part of the Port
5 Huron gas system. The gas storage field is comprised of five solution mined,
6 interconnected salt caverns and includes five injection/withdrawal wells, as well as a
7 separate salt cavern with its own injection/withdrawal well. SEMCO Gas operates and
8 maintains two compressors for gas injection. SEMCO Gas also operates and maintains
9 gas heating equipment, turbine meter measuring equipment, telemetry equipment, flow
10 control equipment, over-pressure protection equipment, and odorization equipment. The
11 storage field is totally automated and continuously monitored by SEMCO Gas’s SCADA
12 system.
13
14 Q. Please describe SEMCO Gas’sCollin storage supply point facilities in the Port
15 Huron area.
16 A. The Collin storage facility delivers gas into SEMCO Gas’s 8" - 465 psig MAOP
17 transmission line on Starville Road near Marine City as part of the Port Huron gas
18 system. The gas storage field is comprised of a Niagaran reef and includes two
19 injection/withdrawal wells. SEMCO Gas operates and maintains two compressors for
20 gas injection. SEMCO Gas also operates and maintains gas heating equipment,
21 ultrasonic meter measuring equipment, telemetry equipment, flow control equipment,
22 over pressure protection equipment, and odorization equipment. The storage field is
23 totally automated and continuously monitored by SEMCO Gas’s SCADA system.
24
Page 8 of 36 DIRECT TESTIMONY AND EXHIBIT OF MICHAEL J. CLYNE ON BEHALF OF SEMCO ENERGY GAS COMPANY
1 Q. Please describe SEMCO Gas’spipeline interconnect facilities with local
2 production at the Klingler facility.
3 A. The Klingler Station delivers gas from the Klingler #3 well into SEMCO Gas’s 6" - 250
4 psig MAOP distribution line on Marsh Road near Marine City as part of the Port Huron
5 gas system. This station is utilized year round for transport gas and system supply.
6
7 Q. Please describe SEMCO Gas’spipeline interconnect facilities with local
8 production at the Pilat facility.
9 A. The Pilat Station delivers gas from the Pilat 1-24 well into SEMCO Gas’s 12" - 465 psig
10 MAOP transmission line on Lindsey Rd in Lenox Township as part of the Port Huron gas
11 system. This station is utilized year round for transport gas and system supply.
12
13 Q. Please describe SEMCO Gas’spipeline interconnect facilities with local
14 production at the Tiger facility.
15 A. The Tiger Station (Lelowicz #2 well) delivers gas into SEMCO Gas’s 12" - 465 psig
16 MAOP transmission line on Dolan Road in Columbus Township as part of the Port Huron
17 gas system. This station is utilized year round for transport gas and system supply.
18
19 Q. Please describe SEMCO Gas’spipeline interconnect facilities with local
20 production at the Rapley facility.
21 A. The Rapley Station delivers gas into SEMCO Gas’s 4" - 400 psig MAOP distribution line
22 on Speaker Road in Lynn Township, near the City of Yale as part of the Port Huron gas
23 system. This station is utilized year round for transport gas and system supply.
24
25 Central Service Area
Page 9 of 36 DIRECT TESTIMONY AND EXHIBIT OF MICHAEL J. CLYNE ON BEHALF OF SEMCO ENERGY GAS COMPANY
1 Q. Please identify SEMCO Gas’spipeline interconnects and storage supply points for
2 the Central area of the system from Exhibit A-21.
3 A. The Central area gas system, on page 2 of 5 of Exhibit A-21, has active pipeline
4 interconnects with Panhandle Eastern Pipeline Company (“PEPL”) at the Albion Town
5 Border Station, PEPL #1, and PEPL #2, with ANR at the Litchfield Interchange and the
6 ANR Main St city gate station, and with SEMCO Pipeline Company’s Eaton Rapids
7 Pipeline (“ERPL”) at the Eaton Rapids Interchange, Brookfield Interchange, and SEMCO
8 Gas Interconnect. The Central area gas system also has three storage supply points
9 located at SEMCO Gas’s Lee 2 and Lee 11 Gas Storage Fields in Lee Township and
10 Lacey Gas Storage Field in Johnstown Township.
11
12 Q. Please describe SEMCO Gas’spipeline interconnect facilities where supply is
13 received from PEPL at the Albion Town Border Station in the Central area.
14 A. The Albion Town Border Station delivers gas from PEPL's 12" - 250 psig MAOP pipeline
15 into SEMCO Gas’s 6" - 250 psig MAOP distribution line on M-99 in the City of Albion.
16 This station is utilized year round for transport gas and system supply for the Central
17 area gas system. The interconnect is continuously monitored and controlled by SEMCO
18 Gas’s SCADA system.
19
20 Q. Please describe SEMCO Gas’sinterconnect facilities where supply is received
21 from PEPL at the PEPL #1 city gate station.
22 A. The PEPL #1 city gate station delivers gas from Panhandle’s 12” – 800 psig MAOP
23 transmission line into SEMCO Gas’s 16” – 275 psig MAOP high pressure distribution line
24 that supplies the City of Battle Creek. This station is utilized year-round for transport and
Page 10 of 36 DIRECT TESTIMONY AND EXHIBIT OF MICHAEL J. CLYNE ON BEHALF OF SEMCO ENERGY GAS COMPANY
1 system supply gas. The interconnect is continuously monitored and controlled by
2 SEMCO Gas’s SCADA system.
3
4 Q. Please describe SEMCO Gas’sinterconnect facilities where supply is received
5 from PEPL at the PEPL #2 city gate station.
6 A. The PEPL #2 city gate station delivers gas from Panhandle’s 12” – 800 psig MAOP
7 transmission line into SEMCO Gas’s 8” – 275 psig MAOP high pressure distribution line
8 that supplies the City of Battle Creek. This station is utilized year-round for transport and
9 system supply gas. The interconnect is continuously monitored and controlled by
10 SEMCO Gas’s SCADA system.
11
12 Q. Please describe SEMCO Gas’spipeline interconnect facilities where supply is
13 received from ANR at the Litchfield Interchange in the Central area gas system.
14 A. The Litchfield Interchange facility delivers gas from ANR's 12" - 858 psig MAOP
15 transmission line into SEMCO Gas’s 6" - 250 psig MAOP distribution line on route M-99
16 near the City of Litchfield. The interconnect is continuously monitored and controlled by
17 SEMCO Gas’s SCADA system.
18
19 Q. Please describe SEMCO Gas’sinterconnect facilities where supply is received
20 from ANR at the Main St. city gate station.
21 A. The Main Street city gate station delivers gas from ANR’s 10” - 858 psig MAOP
22 transmission line into SEMCO Gas’s 16” – 275 psig MAOP high pressure distribution line
23 that supplies the City of Battle Creek. This station is utilized year-round for transport and
24 system supply gas. The interconnect is continuously monitored and controlled by
25 SEMCO Gas’s SCADA system.
Page 11 of 36 DIRECT TESTIMONY AND EXHIBIT OF MICHAEL J. CLYNE ON BEHALF OF SEMCO ENERGY GAS COMPANY
1
2 Q. Please describe SEMCO Gas’spipeline interconnect facilities where supply is
3 received from ERPL at the Eaton Rapids Interchange in the Central area gas
4 system.
5 A. The Eaton Rapids Interchange delivers gas from ERPL’s 6" - 960 psig MAOP pipeline
6 into SEMCO Gas’s 6" - 60 psig MAOP distribution line on Michigan Road near the City of
7 Albion. This station is utilized during the winter months for system supply for the City of
8 Albion. The interconnect is continuously monitored and controlled by SEMCO Gas’s
9 SCADA system.
10
11 Q. Please describe SEMCO Gas’spipeline interconnect facilities where supply is
12 received from ERPL at the Brookfield Interchange in the Central area gas system.
13 A. The Brookfield Interchange delivers gas from ERPL's 6" - 960 psig MAOP pipeline into
14 SEMCO Gas’s 4" - 60 psig MAOP distribution line on Brookfield Road in Brookfield
15 Township. This station is utilized during the winter months for system supply for
16 Brookfield Township. The interconnect is continuously monitored by SEMCO Gas’s
17 SCADA system.
18
19 Q. Please describe SEMCO Gas’spipeline interconnect facilities where supply is
20 received from ERPL at the Kilbourn Interchange in the Central area gas system.
21 A. The Kilbourn Interchange delivers gas from ERPL's 6" - 960 psig MAOP pipeline into
22 SEMCO Gas’s 6" - 60 psig MAOP distribution line on J Drive North in Marengo
23 Township. This station is utilized during the winter months for system supply for
24 Marengo Township. The interconnect is continuously monitored by SEMCO Gas’s
25 SCADA system.
Page 12 of 36 DIRECT TESTIMONY AND EXHIBIT OF MICHAEL J. CLYNE ON BEHALF OF SEMCO ENERGY GAS COMPANY
1
2 Q. Please describe SEMCO Gas’sinterconnect facilities where supply is received
3 from ERPL at the SEMCO Interconnect.
4 A. The SEMCO Gas Interconnect delivers gas from ERPL’s 6” – 960 psig MAOP pipeline
5 into SEMCO Gas’s 6” – 1440 psig MAOP transmission line that connects SEMCO Gas’s
6 Lee 2 and Lee 11 Gas Storage Fields to the City of Battle Creek’s high pressure
7 distribution system. This station is utilized during the winter months for additional gas
8 supply from the Eaton Rapids Storage Field to the Central area gas system. The
9 interconnect is continuously monitored and controlled by SEMCO Gas’s SCADA system.
10
11 Q. Please describe SEMCO Gas’sLee 2 storage supply point facilities in the Central
12 area gas system.
13 A. The Lee 2 storage facility delivers gas into SEMCO Gas’s 6" - 1440 psig MAOP
14 transmission line on Baseline Road in Lee Township as part of the Central area gas
15 system. The gas storage field is comprised of a Niagaran reef and includes one
16 injection/withdrawal well. SEMCO Gas operates and maintains two compressors for gas
17 injection at the nearby Harris Compressor Station, which is also utilized for the Lee 11
18 storage facility. SEMCO Gas also operates and maintains gas heating equipment,
19 ultrasonic meter measuring equipment, telemetry equipment, and flow control
20 equipment. Overpressure protection and odorization is performed at the Cal-Lee station.
21 The storage field is continuously monitored and controlled by SEMCO Gas’s SCADA
22 system.
23
24 Q. Please describe SEMCO Gas’sLee 11 storage supply point facilities in the Central
25 area gas system.
Page 13 of 36 DIRECT TESTIMONY AND EXHIBIT OF MICHAEL J. CLYNE ON BEHALF OF SEMCO ENERGY GAS COMPANY
1 A. The Lee 11 storage facility delivers gas into SEMCO Gas’s 4" - 1440 psig MAOP
2 transmission line on V Drive North Road in Lee Township as part of the Central area gas
3 system. The gas storage field is comprised of a Niagaran reef and includes one
4 injection/withdrawal well. SEMCO Gas operates and maintains two compressors for gas
5 injection at the nearby Harris Compressor Station. SEMCO Gas also operates and
6 maintains gas heating equipment, ultrasonic meter measuring equipment, telemetry
7 equipment, and flow control equipment. Overpressure protection and odorization is
8 performed at the Cal-Lee station. The storage field is continuously monitored and
9 controlled by SEMCO Gas’s SCADA system.
10
11 Q. Please describe SEMCO Gas’sLacey storage supply point facilities in the Central
12 area gas system.
13 A. The Lacey storage facility delivers gas into SEMCO Gas’s 8" - 720 psig MAOP high
14 pressure distribution line on North Ave in Johnstown Township as part of the Central
15 area gas system. The gas storage field is comprised of two solution mined salt caverns
16 and includes two injection/withdrawal wells. SEMCO Gas operates and maintains one
17 compressor for gas injection. SEMCO Gas also operates and maintains gas heating
18 equipment, ultrasonic meter measuring equipment, telemetry equipment, flow control
19 equipment, over pressure protection equipment, and odorization equipment. The storage
20 field is continuously monitored and controlled by SEMCO Gas’s SCADA system.
21
22 Holland Service Area
23
24 Q. Please identify SEMCO Gas’spipeline interconnects and storage supply points for
25 the Holland area gas system from Exhibit A-21.
Page 14 of 36 DIRECT TESTIMONY AND EXHIBIT OF MICHAEL J. CLYNE ON BEHALF OF SEMCO ENERGY GAS COMPANY
1 A. The Holland area gas system, on page 3 of 5 of Exhibit A-21, shows the three
2 interconnects with ANR at the North and South Holland city gate stations, and the North
3 Zeeland city gate station, and the single interconnect with CECO at the Overisel city
4 gate station.
5
6 Q. Please describe SEMCO Gas’sinterconnect facilities where supply is received
7 from CECO at the Overisel city gate station.
8 A. The Overisel city gate station delivers gas from CECO's 8" - 960 psig MAOP
9 transmission line at the CECO Overisel compressor station into SEMCO Gas’s 12" - 960
10 psig MAOP, 329 psig Maximum Operating Pressure (“MOP”) high pressure distribution
11 line that runs into the City of Holland. This station is utilized throughout the year as
12 required for system supply for the southern Holland gas system. The interconnect is
13 continuously monitored and controlled by SEMCO Gas’s SCADA system.
14
15 Q. Please describe SEMCO Gas’sinterconnect facilities where supply is received
16 from ANR at the South Holland city gate station.
17 A. The South Holland city gate station, located on 16th Street in the City of Holland,
18 delivers gas from ANR's two (2) 6" - 858 psig MAOP transmission lines into SEMCO
19 Gas’s three (3) 6" - 200 psig MAOP high pressure distribution lines as part of the Holland
20 gas system. This station is utilized year-round for transport gas and system supply gas.
21 The interconnect is continuously monitored and controlled by SEMCO Gas’s SCADA
22 system.
23
24 Q. Please describe SEMCO Gas’sinterconnect facilities where supply is received
25 from ANR at the North Holland city gate station.
Page 15 of 36 DIRECT TESTIMONY AND EXHIBIT OF MICHAEL J. CLYNE ON BEHALF OF SEMCO ENERGY GAS COMPANY
1 A. The North Holland city gate station, located on New Holland Street - north of the City of
2 Holland, delivers gas from ANR's 12" - 858 psig MAOP transmission line into SEMCO
3 Gas’s 10" and 8" - 200 psig MAOP high pressure distribution lines on New Holland St as
4 part of the Holland gas system. This station is utilized year-round for transport gas and
5 system supply gas. The interconnect is continuously monitored and controlled by
6 SEMCO Gas’s SCADA system.
7
8 Q. Please describe SEMCO Gas’sinterconnect facilities where supply is received
9 from ANR at the North Zeeland city gate station.
10 A. The North Zeeland city gate station, located on 88th Street - north of the City of Zeeland,
11 delivers gas from ANR's 12" - 858 psig MAOP transmission line into SEMCO Gas’s 6" -
12 200 psig MAOP high pressure distribution line on 88th St as part of the Holland gas
13 system. The interconnect is continuously monitored and controlled by SEMCO Gas’s
14 SCADA system.
15
16 Niles Service Area
17
18 Q. Please identify SEMCO Gas’spipeline interconnects for the Three Rivers portion
19 of the Niles area gas system from Exhibit A-21.
20 A. The Three Rivers portion of the Niles gas system, on page 4 of 5 of Exhibit A-21, shows
21 the interconnect with ANR and the interconnect with CECO. The two city gate stations
22 supplying the Three Rivers area are the Ferguson Rd and Three Rivers stations. The
23 Ferguson Road city gate station is supplied by CECO, while the Three Rivers city gate
24 station is supplied by ANR. Both stations are interconnected through the Three Rivers
25 portion of the Niles area gas distribution system.
Page 16 of 36 DIRECT TESTIMONY AND EXHIBIT OF MICHAEL J. CLYNE ON BEHALF OF SEMCO ENERGY GAS COMPANY
1
2 Q. Please describe SEMCO Gas’sinterconnect facilities where supply is received
3 from ANR at the Three Rivers city gate station.
4 A. The Three Rivers city gate station delivers gas from ANR's 8" - 858 psig MAOP
5 transmission line into SEMCO Gas’s 6" - 150 psig MAOP high pressure distribution line
6 on Jensen Road. This station is utilized year-round for transport gas and system supply
7 gas. The interconnect is continuously monitored and controlled by SEMCO Gas’s
8 SCADA system.
9
10 Q. Please describe SEMCO Gas’sinterconnect facilities where supply is received
11 from CECO at the Ferguson Road city gate station.
12 A. The Ferguson Road city gate station delivers gas from CECO's 20" - 960 psig MAOP
13 transmission line into SEMCO Gas’s 6" - 150 psig MAOP high pressure distribution line
14 on Hoffman Road as part of the Three Rivers portion of the Niles area gas system. This
15 station is utilized only when necessary for system supply for the Three Rivers area. The
16 interconnect is continuously monitored and controlled by SEMCO Gas’s SCADA system.
17
18 Q. Please identify SEMCO Gas’spipeline interconnect in the Constantine/White
19 Pigeon portion of the Niles area gas system.
20 A. The Constantine/White Pigeon portion of the Niles gas system, as shown on page 4 of 5
21 of Exhibit A-21, is supplied by two city gate stations - both interconnected with ANR.
22 The Constantine city gate station is located on Florence Rd and the White Pigeon city
23 gate station is located on Kalamazoo Street. Both stations are interconnected through
24 SEMCO Gas’s distribution system.
25
Page 17 of 36 DIRECT TESTIMONY AND EXHIBIT OF MICHAEL J. CLYNE ON BEHALF OF SEMCO ENERGY GAS COMPANY
1 Q. Please describe SEMCO Gas’sinterconnect facilities where supply is received
2 from ANR at the White Pigeon city gate station.
3 A. The White Pigeon city gate station delivers gas from ANR's 4" - 858 psig MAOP
4 transmission line into SEMCO Gas’s 6" - 150 psig MAOP, 6” – 275 psig MAOP, and 4" -
5 60 psig MAOP distribution lines as part of the Constantine/White Pigeon portion of the
6 Niles gas system. This station is utilized year-round for transport gas and system supply
7 gas. The interconnect is continuously monitored by SEMCO Gas’s SCADA system.
8
9 Q. Please describe SEMCO Gas’sinterconnect facilities where supply is received
10 from ANR at the Constantine city gate station.
11 A. The Constantine city gate station delivers gas from ANR's 4" - 858 psig MAOP
12 transmission line into SEMCO Gas’s 4" - 60 psig MAOP distribution line on Florence
13 Road as part of the Constantine/White Pigeon portion of the Niles gas system. This
14 station is utilized year-round for transport gas and system supply gas. The interconnect
15 is continuously monitored by SEMCO Gas’s SCADA system.
16
17 Q. Please identify SEMCO Gas’spipeline interconnect for the Union area of the Niles
18 area gas system.
19 A. The Union area of the Niles gas system, on page 4 of 5 of Exhibit A-21, has an active
20 interconnect with ANR at the Baldwin Lake city gate station.
21
22 Q. Please describe SEMCO Gas’sinterconnect facilities where supply is received
23 from ANR at the Baldwin Lake city gate station.
24 A. The Baldwin Lake city gate station delivers gas from ANR's 4" - 858 psig MAOP
25 transmission line into SEMCO Gas’s 4" - 60 psig MAOP distribution line on Hill Top
Page 18 of 36 DIRECT TESTIMONY AND EXHIBIT OF MICHAEL J. CLYNE ON BEHALF OF SEMCO ENERGY GAS COMPANY
1 Street. This station is utilized year-round for system supply gas. The interconnect is
2 continuously monitored by SEMCO Gas’s SCADA system.
3
4 Q. Please identify SEMCO Gas’spipeline interconnect for the
5 Edwardsburg/Cassopolis portion of the Niles gas system.
6 A. The Edwardsburg/Cassopolis portion of the Niles gas system, on page 4 of 5 of Exhibit
7 A-21, has an active interconnect with ANR at the Edwardsburg city gate station.
8
9 Q. Please describe SEMCO Gas’sinterconnect facilities where supply is received
10 from ANR at the Edwardsburg city gate station.
11 A. The Edwardsburg city gate station, on M-62 just to the north of Edwardsburg, delivers
12 gas from ANR's 4" - 858 psig MAOP transmission line into SEMCO Gas’s 4" - 250 psig
13 MAOP high pressure distribution line to the Cassopolis gas system and SEMCO Gas’s
14 4" - 175 psig MAOP high pressure distribution line to the Edwardsburg gas system. This
15 station is utilized year-round for transport gas and system supply gas. The interconnect
16 is continuously monitored by SEMCO Gas’s SCADA system.
17
18 Q. Please identify SEMCO Gas’spipeline interconnect for the Niles, Buchanan, and
19 Dowagiac portions of the Niles area gas system.
20 A. The Niles, Buchanan, and Dowagiac portions of the Niles area gas system, on page 4 of
21 5 of Exhibit A-21, have active interconnects with ANR at the Barron Lake, Niles,
22 Dowagiac, and Buchanan city gate stations.
23
24 Q. Please describe SEMCO Gas’sinterconnect facilities where supply is received
25 from ANR at the Barron Lake city gate station.
Page 19 of 36 DIRECT TESTIMONY AND EXHIBIT OF MICHAEL J. CLYNE ON BEHALF OF SEMCO ENERGY GAS COMPANY
1 A. The Barron Lake city gate station delivers gas from ANR's 6" - 858 psig MAOP
2 transmission line into SEMCO Gas’s 6" - 200 psig MAOP high pressure distribution line
3 on Barron Lake Road. This station is utilized year-round for transport gas and system
4 supply gas. The interconnect is continuously monitored by SEMCO Gas’s SCADA
5 system.
6
7 Q. Please describe SEMCO Gas’sinterconnect facilities where supply is received
8 from ANR at the Niles city gate station.
9 A. The Niles city gate station delivers gas from ANR's 6" - 858 psig MAOP transmission line
10 into SEMCO Gas’s 6" - 175 psig MAOP high pressure distribution line on Pucker Street.
11 This station is utilized year-round for transport gas and system supply gas. The
12 interconnect is continuously monitored by SEMCO Gas’s SCADA system.
13
14 Q. Please describe SEMCO Gas’sinterconnect facilities where supply is received
15 from ANR at the Dowagiac city gate station.
16 A. The Dowagiac city gate station delivers gas from ANR's 6" - 858 psig MAOP
17 transmission line that continues from the Barron Lake city gate station into SEMCO
18 Gas’s 6" - 175 psig MAOP high pressure distribution line on M-62. This station is utilized
19 year-round for transport gas and system supply gas. The interconnect is continuously
20 monitored by SEMCO Gas’s SCADA system.
21
22 Q. Please describe SEMCO Gas’sinterconnect facilities where supply is received
23 from ANR at the Buchanan city gate station.
24 A. The Buchanan city gate station delivers gas from ANR's 6" - 858 psig MAOP
25 transmission line into SEMCO Gas’s 6" - 175 psig MAOP high pressure distribution line
Page 20 of 36 DIRECT TESTIMONY AND EXHIBIT OF MICHAEL J. CLYNE ON BEHALF OF SEMCO ENERGY GAS COMPANY
1 on Red Bud Trail. This station is utilized year-round for transport gas and system supply
2 gas. The interconnect is continuously monitored by SEMCO Gas’s SCADA system.
3
4 Q. Please identify SEMCO Gas’spipeline interconnect for the New Buffalo, Three
5 Oaks, Sawyer, and Galien portions of the Niles area gas system.
6 A. The New Buffalo, Three Oaks, Sawyer, and Galien portions of the Niles area gas
7 system, on page 4 of 5 of Exhibit A-21, have active interconnects with ANR at the Three
8 Oaks and New Buffalo city gate stations. Both stations are interconnected through
9 SEMCO Gas’s distribution system.
10
11 Q. Please describe SEMCO Gas’sinterconnect facilities where supply is received
12 from ANR at the Three Oaks city gate station.
13 A. The Three Oaks city gate station delivers gas from ANR's 4" - 858 psig MAOP
14 transmission line into SEMCO Gas’s 6" - 120 psig MAOP high pressure distribution line
15 on Three Oaks Road. This station is utilized year-round for transport gas and system
16 supply gas. The interconnect is continuously monitored by SEMCO Gas’s SCADA
17 system.
18
19 Q. Please describe SEMCO Gas’sinterconnect facilities where supply is received
20 from ANR at the New Buffalo city gate station.
21 A. The New Buffalo city gate station delivers gas from ANR's 4" - 858 psig MAOP
22 transmission line into SEMCO Gas’s 4" - 175 psig MAOP high pressure distribution line
23 on LaPorte Road. This station is utilized year-round for transport gas and system supply
24 gas. The interconnect is continuously monitored by SEMCO Gas’s SCADA system.
25
Page 21 of 36 DIRECT TESTIMONY AND EXHIBIT OF MICHAEL J. CLYNE ON BEHALF OF SEMCO ENERGY GAS COMPANY
1 Q. Please identify SEMCO Gas’spipeline interconnect for the Sister Lakes portion of
2 the Niles area gas system.
3 A. The Sister Lakes portion of the Niles system is supplied by a single city gate station by
4 ANR, and is shown on page 4 of 5 of Exhibit A-21. The Sister Lakes city gate station is
5 located on Townhall Road south of M-152.
6
7 Q. Please describe SEMCO Gas’sinterconnect facilities where supply is received
8 from ANR at the Sister Lakes city gate station.
9 A. The Sister Lakes city gate station delivers gas from ANR's 6" - 858 psig MAOP
10 transmission line that continues from the Barron Lake city gate station, into the 6" - 60
11 psig MAOP distribution line on Townhall Rd. The station is utilized year-round for
12 transport gas and system supply gas. The interconnect is continuously monitored by
13 SEMCO Gas’s SCADA system.
14
15 Q. Are there any system constraints that would require continued firm gas deliveries
16 to the CECO Three Rivers Interconnection Point?
17 A. No. Given the Three River area’s current demand and growth expectations, at this time
18 SEMCO Gas does not anticipate the need for firm gas delivery. System pressures will
19 be monitored during this heating season to verify that the Three Rivers area is
20 sufficiently supplied with gas.
21
22 U.P. East Service Area
23 Q. Please identify SEMCO Gas’spipeline interconnect for the St. Ignace portion of
24 the U.P. East area gas system.
Page 22 of 36 DIRECT TESTIMONY AND EXHIBIT OF MICHAEL J. CLYNE ON BEHALF OF SEMCO ENERGY GAS COMPANY
1 A. The St. Ignace portion of the UP East gas system, on page 5 of 5 of Exhibit A-21, has an
2 active interconnect with GLGTC at the St. Ignace city gate station.
3
4 Q. Please describe SEMCO Gas’sinterconnect facilities where supply is received
5 from GLGTC at the St. Ignace city gate station.
6 A. The St. Ignace city gate station delivers gas from GLGTC's 36" - 974 psig MAOP
7 transmission line into SEMCO Gas’s 4" - 275 psig MAOP, 200 psig MOP, high pressure
8 distribution line on Old Gros Gap Road. This station is utilized year-round for system
9 supply gas. The interconnect is continuously monitored by SEMCO Gas’s SCADA
10 system.
11
12 Q. Please identify SEMCO Gas’spipeline interconnect for the Engadine and
13 Newberry portions of the U.P. East gas system.
14 A. The Engadine and Newberry portions of the U.P. East gas system, on page 5 of 5 of
15 Exhibit A-21, have an active interconnect with GLGTC at the Engadine city gate station.
16
17 Q. Please describe SEMCO Gas’sinterconnect facilities where supply is received
18 from GLGTC at the Engadine city gate station.
19 A. The Engadine city gate station located on M-117 delivers gas from GLGTC's 36" - 974
20 psig MAOP transmission line into SEMCO Gas’s 6" - 475 psig MAOP, 250 psig MOP,
21 high pressure distribution line on M-117. This station is utilized year-round for transport
22 gas and system supply gas. The interconnect is continuously monitored by SEMCO
23 Gas’s SCADA system.
24
Page 23 of 36 DIRECT TESTIMONY AND EXHIBIT OF MICHAEL J. CLYNE ON BEHALF OF SEMCO ENERGY GAS COMPANY
1 Q. Please identify SEMCO Gas’spipeline interconnect for the Manistique portion of
2 the U.P. East gas system.
3 A. The Manistique portion of the UP East gas system, on page 5 of 5 of Exhibit A-21, has
4 an active interconnect with GLGTC at the Manistique city gate station.
5
6 Q. Please describe SEMCO Gas’sinterconnect facilities where supply is received
7 from GLGTC at the Manistique city gate station.
8 A. The Manistique city gate station delivers gas from GLGTC's 36" - 974 psig MAOP
9 transmission line into SEMCO Gas’s 4" - 250 psig MAOP high pressure distribution line
10 on M-94. This station is utilized year-round for system supply gas. The interconnect is
11 continuously monitored by SEMCO Gas’s SCADA system.
12
13
14 U.P. West Service Area
15
16 Q. Please identify SEMCO Gas’spipeline interconnects for the Marquette, Negaunee,
17 and Ishpeming portions of the U.P. West area gas system.
18 A. The Marquette, Negaunee, and Ishpeming portions of the U.P. West gas system, on
19 page 5 of 5 of Exhibit A-21, have active interconnects with Northern Natural Gas
20 Company (“NNG”) at the Marquette #1, Marquette #2, Marquette Energy Center,
21 Negaunee, and Ishpeming city gate stations. All of these stations are interconnected
22 through their respective distribution systems.
23
24 Q. Please describe SEMCO Gas’sinterconnect facilities where supply is received
25 from NNG at the Marquette #1 city gate station.
Page 24 of 36 DIRECT TESTIMONY AND EXHIBIT OF MICHAEL J. CLYNE ON BEHALF OF SEMCO ENERGY GAS COMPANY
1 A. The Marquette #1 city gate station delivers gas from NNG's 6"- 575 psig MAOP
2 transmission line into SEMCO Gas’s 10" - 60 psig MAOP distribution line on Pioneer
3 Street. This station is utilized year-round for transport gas and system supply gas. The
4 interconnect is continuously monitored by SEMCO Gas’s SCADA system.
5
6 Q. Please describe SEMCO Gas’sinterconnect facilities where supply is received
7 from NNG at the Marquette #2 city gate station.
8 A. The Marquette #2 city gate station delivers gas from NNG's 6" - 575 psig MAOP
9 transmission line into SEMCO Gas’s 10" - 60 psig MAOP distribution line on Wright
10 Street. The Marquette #2 city gate also delivers gas from NNG’s 6” – 575 MAOP
11 transmission line into SEMCO Gas’s 6” – 575 psig MAOP high pressure distribution line
12 on Wright Street. This station is utilized year-round for transport gas and system supply
13 gas. The interconnect is continuously monitored by SEMCO Gas’s SCADA system.
14
15 Q. Please describe SEMCO Gas’sinterconnect facilities where supply is received
16 from NNG at the Marquette Energy Center gate.
17 A. The Marquette Energy Center gate is a new NNG interconnection metering point that
18 was constructed in 2016 to serve new power generation load for the Marquette Board of
19 Light and Power. The gate delivers gas from NNG’s 6” – 575 MAOP transmission line
20 into SEMCO Gas’s 6” – 575 psig MAOP high pressure distribution line on Wright Street.
21 This station is utilized year-round for transportation of to the Marquette Board of Light
22 and Power and for system supply gas. The interconnection is continuously monitored by
23 SEMCO Gas’s SCADA system.
24
Page 25 of 36 DIRECT TESTIMONY AND EXHIBIT OF MICHAEL J. CLYNE ON BEHALF OF SEMCO ENERGY GAS COMPANY
1 Q. Please describe SEMCO Gas’sinterconnect facilities where supply is received
2 from NNG at the Negaunee city gate station.
3 A. The Negaunee city gate station delivers gas from NNG's 4" - 575 psig MAOP
4 transmission line into SEMCO Gas’s 8" - 60 psig MAOP distribution line on County Road
5 492. This station is utilized year-round for transport gas and system supply gas. The
6 interconnect is continuously monitored by SEMCO Gas’s SCADA system.
7
8 Q. Please describe SEMCO Gas’sinterconnect facilities where supply is received
9 from NNG at the Ishpeming city gate station.
10 A. The Ishpeming city gate station delivers gas from NNG's 6" - 575 psig MAOP
11 transmission line into SEMCO Gas’s 10" - 60 psig MAOP distribution line on Saginaw
12 Street. This station is utilized year-round for transport gas and system supply gas. The
13 interconnect is continuously monitored by SEMCO Gas’s SCADA system.
14
15 Q. Please identify SEMCO Gas’spipeline interconnect for the K. I. Sawyer portion of
16 the U.P. West gas system.
17 A. The K. I. Sawyer portion of the UP West gas system, on page 5 of 5 of Exhibit A-21, has
18 an active interconnect with NNG at the Sands city gate station.
19
20 Q. Please describe SEMCO Gas’sinterconnect facilities where supply is received
21 from NNG at the Sands city gate station.
22 A. The Sands city gate station delivers gas from NNG's 6"- 575 psig MAOP transmission
23 line into SEMCO Gas’s 6" - 830 psig MAOP, 250 psig MOP, high pressure distribution
24 line on County Road NB. The interconnect is continuously monitored by SEMCO Gas’s
25 SCADA system.
Page 26 of 36 DIRECT TESTIMONY AND EXHIBIT OF MICHAEL J. CLYNE ON BEHALF OF SEMCO ENERGY GAS COMPANY
1
2 Q. Please identify SEMCO Gas’spipeline interconnect for the Palmer portion of the
3 U.P. West gas system.
4 A. The Palmer portion of the UP West gas system, on page 5 of 5 of Exhibit A-21, has an
5 active interconnect with NNG at the Palmer city gate station.
6
7 Q. Please describe SEMCO Gas’sinterconnect facilities where supply is received
8 from NNG at the Palmer city gate station.
9 A. The Palmer city gate station delivers gas from NNG's 2"- 575 psig MAOP transmission
10 line into SEMCO Gas’s 4" - 60 psig MAOP distribution line on County Road MMC. This
11 station is utilized year-round for system supply gas. The interconnect is continuously
12 monitored by SEMCO Gas’s SCADA system.
13
14 Q. Please identify SEMCO Gas’spipeline interconnect for the L'Anse portion of the
15 U.P. West gas system.
16 A. The L'Anse portion of the UP West gas system, on page 5 of 5 of Exhibit A-21, has an
17 active interconnect with NNG at the L'Anse city gate station.
18
19 Q. Please describe SEMCO Gas’sinterconnect facilities where supply is received
20 from NNG at the L'Anse city gate station.
21 A. The L'Anse city gate station delivers gas from NNG's 6" - 970 psig MAOP transmission
22 line into SEMCO Gas’s 8" - 275 psig MAOP, 120 psig MOP, high pressure distribution
23 line on Celotex Drive. This station is utilized year-round for transport gas and system
24 supply gas. The interconnect is continuously monitored by SEMCO Gas’s SCADA
25 system.
Page 27 of 36 DIRECT TESTIMONY AND EXHIBIT OF MICHAEL J. CLYNE ON BEHALF OF SEMCO ENERGY GAS COMPANY
1
2 Q. Please identify SEMCO Gas’spipeline interconnect for the Baraga portion of the
3 U.P. West gas system.
4 A. The Baraga portion of the U.P. West gas system, on page 5 of 5 of Exhibit A-21, has an
5 active interconnect with NNG at the Baraga city gate station.
6
7 Q. Please describe SEMCO Gas’sinterconnect facilities where supply is received
8 from NNG at the Baraga city gate station.
9 A. The Baraga city gate station delivers gas from NNG's 3" - 830 psig MAOP transmission
10 line into SEMCO Gas’s 4" - 60 psig MAOP distribution line on Osterman Road. This
11 station is utilized year-round for transport gas and system supply gas. The interconnect
12 is continuously monitored by SEMCO Gas’s SCADA system.
13
14 Q. Please identify SEMCO Gas’spipeline interconnect for the Chassell portion of the
15 U.P. West gas system.
16 A. The Chassell portion of the U.P. West gas system, on page 5 of 5 of Exhibit A-21, has
17 an active interconnect with NNG at the Chassell city gate station.
18
19 Q. Please describe SEMCO Gas’sinterconnect facilities where supply is received
20 from NNG at the Chassell city gate station.
21 A. The Chassell city gate station delivers gas from NNG's 2" - 830 psig MAOP transmission
22 line into SEMCO Gas’s 4" - 60 psig MAOP distribution line on Seventh Street. This
23 station is utilized year-round for system supply gas. The interconnect is continuously
24 monitored by SEMCO Gas’s SCADA system.
25
Page 28 of 36 DIRECT TESTIMONY AND EXHIBIT OF MICHAEL J. CLYNE ON BEHALF OF SEMCO ENERGY GAS COMPANY
1 Q. Please identify SEMCO Gas’spipeline interconnect for the Houghton portion of
2 the U.P. West gas system.
3 A. The Houghton portion of the UP West gas system, on page 5 of 5 of Exhibit A-21, has
4 an active interconnect with NNG at the Houghton city gate station.
5
6 Q. Please describe SEMCO Gas’sinterconnect facilities where supply is received
7 from NNG at the Houghton city gate station.
8 A. The Houghton city gate station delivers gas from NNG's 3" and 6” - 830 psig MAOP
9 transmission line into SEMCO Gas’s 6" - 150 psig MAOP high pressure distribution line
10 on Sharon Ave. This station is utilized year-round for transport gas and system supply
11 gas. The interconnect is continuously monitored by SEMCO Gas’s SCADA system.
12
13 Q. Please identify SEMCO Gas’spipeline interconnect for the Hancock and Ripley
14 portions of the U.P. West gas system.
15 A. The Hancock and Ripley portion of the UP West gas system, on page 5 of 5 of Exhibit A-
16 21, has an active interconnect with NNG at the Hancock #1 city gate station.
17
18 Q. Please describe SEMCO Gas’sinterconnect facilities where supply is received
19 from NNG at the Hancock #1 city gate station.
20 A. The Hancock #1 city gate station delivers gas from NNG's 4" - 830 psig MAOP
21 transmission line into SEMCO Gas’s 8" - 60 psig MAOP distribution line on Ingot St.
22 This station is utilized year-round for system supply gas. The interconnect is
23 continuously monitored by SEMCO Gas’s SCADA system.
24
Page 29 of 36 DIRECT TESTIMONY AND EXHIBIT OF MICHAEL J. CLYNE ON BEHALF OF SEMCO ENERGY GAS COMPANY
1 Q. Please identify SEMCO Gas’spipeline interconnect for the Houghton County
2 Airport and Dollar Bay portion of the UP West gas system.
3 A. The Houghton County Airport and Dollar Bay portion of the UP West gas system, on
4 page 5 of 5 of Exhibit A-21, has an active interconnect with NNG at the Hancock #2 city
5 gate station.
6
7 Q. Please describe SEMCO Gas’sinterconnect facilities where supply is received
8 from NNG at the Hancock #2 city gate station.
9 A. The Hancock #2 city gate station delivers gas from NNG's 4" - 830 psig MAOP
10 transmission line into SEMCO Gas’s 4" - 60 psig MAOP distribution line and SEMCO
11 Gas’s 6” - 10 psig MAOP distribution line on Arcadia Road. The Hancock #2 city gate
12 station is utilized year-round for system supply gas. The interconnect is continuously
13 monitored by SEMCO Gas’s SCADA system.
14
15 Q. Please identify SEMCO Gas’spipeline interconnect for the Calumet portion of the
16 U.P. West gas system.
17 A. The Calumet portion of the U.P. West gas system, on page 5 of 5 of Exhibit A-21, has an
18 active interconnect with NNG at the Calumet city gate station.
19
20 Q. Please describe SEMCO Gas’sinterconnect facilities where supply is received
21 from NNG at the Calumet city gate station.
22 A. The Calumet city gate station delivers gas from NNG's 4" - 830 psig MAOP transmission
23 line into SEMCO Gas’s 4" - 60 psig MAOP distribution line on Hancock Street. This
24 station is utilized year-round for system supply gas. The interconnect is continuously
25 monitored by SEMCO Gas’s SCADA system.
Page 30 of 36 DIRECT TESTIMONY AND EXHIBIT OF MICHAEL J. CLYNE ON BEHALF OF SEMCO ENERGY GAS COMPANY
1
2 Q. Please identify SEMCO Gas’spipeline interconnect for the Lake Linden portion of
3 the UP West gas system.
4 A. The Lake Linden portion of the UP West gas system, on page 5 of 5 of Exhibit A-21, has
5 an active interconnect with NNG at the Lake Linden city gate station.
6
7 Q. Please describe SEMCO Gas’sinterconnect facilities where supply is received
8 from NNG at the Lake Linden city gate station.
9 A. The Lake Linden city gate station delivers gas from NNG's 4" - 830 psig MAOP
10 transmission line into SEMCO Gas’s 6" - 60 psig MAOP distribution line on M-26. This
11 station is utilized year-round for system supply gas. The interconnect is continuously
12 monitored by SEMCO Gas’s SCADA system.
13
14 Q. Is SEMCO Gas planning upstream capacity improvements of any NNG
15 interconnection facilities?
16 A. Yes. The Company is planning upstream capacity improvements at NNG’s Lake Linden
17 interconnection and NNG’s Marquette 1A interconnection.
18
19 Q. Please explain why upstream capacity improvements are necessary to NNG’s
20 facilities at the Lake Linden interconnection?
21 A. Upstream capacity improvements are necessary to NNG’s facilities at the Lake Linden
22 interconnection due to an upstream capacity deficiency. Specifically, the Company’s
23 forecasted Design Day demand is anticipated to be approximately 2,076 Dth/day while
Page 31 of 36 DIRECT TESTIMONY AND EXHIBIT OF MICHAEL J. CLYNE ON BEHALF OF SEMCO ENERGY GAS COMPANY
1 the maximum capacity of NNG’s upstream facilities is 1,341 Dth/day resulting in a
2 Design Day capacity deficiency of 735 Dth/day.
3
4 Q. What capacity improvements are necessary at the NNG Lake Linden
5 interconnection point?
6 A. The planned capacity improvements necessary to increase the design capacity of NNG’s
7 upstream facilities at the Lake Linden interconnection point include (1) installation of a
8 new gas filter, (2) installation of a new gas line heater, (3) replacement of pipe upstream
9 of the pressure regulators, (4) replacement of pipe downstream of the pressure
10 regulators, (5) installation of higher capacity meters, (6) installation of a new meter and
11 regulator building, and (7) installation of upgraded electronic flow measurement
12 equipment.
13
14 Q. Please explain why upstream capacity improvements are necessary to NNG’s
15 facilities at the Marquette 1A interconnection?
16 A. Upstream capacity improvements are necessary to NNG’s facilities at the Marquette 1A
17 interconnection due to an upstream capacity deficiency. Specifically, the Company’s
18 forecasted Design Day demand is anticipated to be approximately 11,274 Dth/day while
19 the maximum capacity of NNG’s upstream facilities is 11,000 Dth/day resulting in a
20 Design Day capacity deficiency of 274 Dth/day.
21
22 Q. What capacity improvements are necessary at the NNG Marquette 1A
23 interconnection point?
Page 32 of 36 DIRECT TESTIMONY AND EXHIBIT OF MICHAEL J. CLYNE ON BEHALF OF SEMCO ENERGY GAS COMPANY
1 A. The planned improvements necessary to increase the design capacity of NNG’s
2 upstream facilities at the Marquette 1A interconnection point include (1) installation of a
3 new meter run and piping, (2) installation of a new gas line heater and piping, (3)
4 installation of new pressure regulators and piping, and (4) installation of a new meter
5 and regulator building.
6
7 Q. When does NNG plan to have the upstream capacity improvements for the Lake
8 Linden and the Marquette 1A interconnection points completed?
9 A. NNG plans to have the upstream capacity improvements for the Lake Linden and the
10 Marquette 1A interconnection points completed prior to November 1, 2017.
11
12 Q. Please identify SEMCO Gas’spipeline interconnect for the Ontonagon portion of
13 the U.P. West gas system.
14 A. The Ontonagon portion of the UP West area gas system, on page 5 of 5 of Exhibit A-21,
15 has an active interconnect with NNG at the Noble Road city gate station.
16
17 Q. Please describe SEMCO Gas’sinterconnect facilities where supply is received
18 from NNG at the Ontonagon city gate station.
19 A. The Ontonagon city gate station delivers gas from NNG's 6" - 945 psig MAOP
20 transmission line into SEMCO Gas’s 10" - 60 psig MAOP distribution line on Noble
21 Road. This station is utilized year-round for transport gas and system supply gas. The
22 interconnect is continuously monitored by SEMCO Gas’s SCADA system.
23
Page 33 of 36 DIRECT TESTIMONY AND EXHIBIT OF MICHAEL J. CLYNE ON BEHALF OF SEMCO ENERGY GAS COMPANY
1 Q. Please identify SEMCO Gas’spipeline interconnect for the Silver City portion of
2 the U.P. West gas system.
3 A. The Silver City portion of the U.P. West gas system, on page 5 of 5 of Exhibit A-21, has
4 an active interconnect with NNG at the Silver City city gate station.
5
6 Q. Please describe SEMCO Gas’sinterconnect facilities where supply is received
7 from NNG at the Silver City gate station.
8 A. The Silver City gate station delivers gas from NNG's 2" - 945 psig MAOP transmission
9 line into SEMCO Gas’s 3" - 60 psig MAOP distribution line on M-107. This station is
10 utilized year-round for system supply gas. Due to its small size, this interconnect is not
11 monitored by SEMCO Gas’s SCADA system.
12
13
14 Q. Please identify SEMCO Gas’spipeline interconnect for the White Pine Copper
15 Mine portion of the U.P. West gas system.
16 A. The White Pine city gate station gas system, on page 5 of 5 of Exhibit A-21, has an
17 active interconnect with NNG at the White Pine Mine city gate station.
18
19 Q. Please describe SEMCO Gas’sinterconnect facilities where supply is received
20 from NNG at the White Pine Mine city gate station.
21 A. The White Pine Mine city gate station delivers gas from NNG's 6" - 945 psig MAOP
22 transmission line into SEMCO Gas’s 4” – 60 psig MAOP distribution line which serves
23 White Pine Village and into SEMCO Gas’s 4" - 250 psig MAOP high pressure distribution
24 line which serves the White Pine generating plant. This station is utilized year-round for
Page 34 of 36 DIRECT TESTIMONY AND EXHIBIT OF MICHAEL J. CLYNE ON BEHALF OF SEMCO ENERGY GAS COMPANY
1 transport gas and system supply gas. The interconnect is continuously monitored by
2 SEMCO Gas’s SCADA system.
3
4 Q. Please identify SEMCO Gas’spipeline interconnect for the Bruce Crossing portion
5 of the U.P. West gas system.
6 A. The Bruce Crossing portion of the U.P. West gas system, on page 5 of 5 of Exhibit A-21,
7 has an active interconnect with NNG at the Bruce Crossing city gate station.
8
9 Q. Please describe SEMCO Gas’sinterconnect facilities where supply is received
10 from NNG at the Bruce Crossing city gate station.
11 A. The Bruce Crossing city gate station delivers gas from NNG's 4" - 945 psig MAOP
12 transmission line into SEMCO Gas’s 4" - 60 psig MAOP distribution line on US-28. This
13 station is utilized year-round for system supply gas. The interconnect is continuously
14 monitored by SEMCO Gas’s SCADA system.
15
16 Q. Please identify SEMCO Gas’spipeline interconnect for the Watersmeet portion of
17 the U.P. West gas system.
18 A. The Watersmeet portion of the U.P. West gas system, on page 5 of 5 of Exhibit A-21,
19 has an active interconnect with GLGTC at the Watersmeet city gate station.
20
21 Q. Please describe SEMCO Gas’sinterconnect facilities where supply is received
22 from GLGTC at the Watersmeet city gate station.
23 A. The Watersmeet city gate station delivers gas from GLGTC's 36" - 974 psig MAOP
24 transmission line into SEMCO Gas’s 4" - 60 psig MAOP distribution line on M-45. This
Page 35 of 36 DIRECT TESTIMONY AND EXHIBIT OF MICHAEL J. CLYNE ON BEHALF OF SEMCO ENERGY GAS COMPANY
1 station is utilized year-round for system supply gas. The interconnect is continuously
2 monitored by SEMCO Gas’s SCADA system.
3
4 Q. Does that conclude your pre-filed direct testimony at this time?
5 A. Yes.
Page 36 of 36 ELKLAND AKRON COLUMBIA ELMWOOD
1. ANR Interchange (F) SYSTEM GATE STATIONS 2. GLGTC Interchange Bauman Rd (F) 9 3. Kilgore Road (F) PORT HURON AREA 4. Morton Wells (F) (I) 5. Collins Field (F) (I) 3 13 BROCKWAY GREENWOOD 6. Avoca 7. New Haven Interchange (F) (I) 8. Ray #17 (F) (I) 9. Akron Interchange 6 10. Klingler 11. Tiger/Lelowicz Well KENOCKEE 12. Pilat Well 13. Rapley Well (F) 14. GLGTC Interchange Trumble Rd (F)
Control - NO WALES Control - YES RILEY 11 4 Greenwood Pipeline 1 2 DTE MARYSVILLE SEMCO ENERGY Gas 14 Consumers Energy ST. CLAIR
Great Lakes Gas Transmission RICHMOND ST. CLAIR ANR Pipeline COLUMBUS
(F) - Remote Flow Valve 8 COTTRELLVILLE (I) - Remote Isolation Valve RAY CHINA 12 CASCO 10 COTTERVILLE 5 CHESTERFIELD 7 SYSTEM GATE STATIONS CENTRAL AREA
1 11 ASSYRIA JOHNSTOWN 12 BROOKFIELD
PENNFIELD BEDFORD 2 1. Lacey (F) (I) CONVIS 2. Lee 02 (F) (I) LEE 7 3. Lee 11 (F) (I) 3 CLARENCE 4. PEPL #2 (F) 5. ANR Main St (F) 13 6. PEPL #1 (F) EMMETT 7. SEMCO Interconnect (F) SPRINGFIELD SHERIDAN 8. Albion Town Border Station (F) (I) 5 9. Eaton Rapids Interchange (F)(I) 9 10. Litchfield Interchange (I) 11. Brookfield Interchange 4 6 12. Eaton Rapids Storage 13. Kilbourn Interchange LEROY 8 ALBION Control - NO NEWTON Control - YES
ANR PIpeline Panhandle Eastern Pipeline Co. HOMER Eaton Rapids Pipeline SEMCO Gas
10 (I) - Remote Isolation Valve (F) - Remote Flow Valve
LITCHFIELD SYSTEM GATE STATIONS HOLLAND AREA
1. South Holland (F) 2. North Holland (F) 3. Overisel (I) 4. North Zeeland (F) OTTAWA
BLENDON Control - NO OLIVE TWP. Control - YES TWP. ANR Pipeline Consumers Energy 4 SEMCO Gas (F) - Remote Flow Valve 2 ZEELAND TWP. (I) - Remote Isolation Valve HOLLAND KENT TWP. 1
JAMESTOWN TWP. 3 OVERISEL TWP.
FILLMORE TWP.
ALLEGAN SYSTEM GATE STATIONS NILES AREA
VAN BUREN KALAMAZOO 10
SILVER CREEK BERRIEN TWP. ST. JOSEPH 1. Ferguson Road (F) 8 1 2. Three Rivers 2 3. White Pigeon POKAGON FABIUS TWP. CASS LOCKPORT 4. Constantine TWP. TWP. 5. Baldwin Lake CHIKAMING TWP. HOWARD 6. Edwardsburg WEESAW TWP. JEFFERSON 4 12 TWP. BUCHANAN TWP. 7. Niles TWP. 13 NILES CONSTANTINE 8. Dowagiac 11 TWP. 7 9 NEW TWP. 9. Barron Lake BUFFALO 5 TWP. MASON TWP. 10. Sister Lakes 6 ONTWA MOTTVILLE TWP. 3 TWP. 11. New Buffalo 12. Three Oaks 13. Buchanan Control - NO Control - YES
ANR Pipeline Consumers Energy
(F) - Remote Flow Valve (I) - Remote Isolation Valve SYSTEM GATE STATIONS U.P. EAST AND WEST AREAS
Control - NO 21 ALLQUEZ Control - YES CALUMET SCHOOL CRAFT 14 OSCEOLA Northern Natural Gas
FRANKLIN 22 TORCH LAKE Great Lakes Gas Transmission HOUGHTON 15 13 SEMCO Gas 16 12 CHASSELL (F) - Remote Flow Valve
19 (I) - Remote Isolation Valve 17 ONTONAGON 11
CARP LAKE
BARAGA L'ANSE 10 STANNARD 18 6 7 MARQUETTE 5 8
NEGAUNEE ISHPEMING SANDS RICHMOND 20 GARFIELD 9 ELY TILDEN 4
GARFIELD2 MANISTIQUE
HIAWATHA 3
MORAN
1
1. St. Ignace 12. Chassel 2. Engadine 13. Houghton 3. Manistique 14. Hancock #1 4. Sands 15. Hancock #2 5. Marquette #1 16. Ontonagon 6. Marquette #2 17. Silver City 7. Negaunee 18. Bruce's Crossing 8. Ishpeming 19. White Pine Mine (I-2nd Run) 9. Palmer 20. Watersmeet 10. L'anse (I-2nd Run) 21. Calumet 11. Baraga 22. Lake Linden