Hon. Sharon L. Feldman, Administrative Law Judge Parties per Attachment 1 to Proof of Service

Transcription

1 A CMS Energy Company March 31, 2016 Ms. Mary Jo Kunkle Executive Secretary Michigan Public Service Commission 7109 West Saginaw Highway P.O. Box Lansing, MI General Offices: LEGAL DEPARTMENT One Energy Plaza Jackson, MI Tel: Fax: (517) (517) CATHERINE M REYNOLDS Senior Vice President and General Counsel *Washington Office: 1730 Rhode Island Ave. N.W. Tel: (202) MELISSA M GLEESPEN Suite 1007 Vice President and Washington, DC Fax: (202) Corporate Secretary Writer s Direct Dial Number: (517) Writer s Address: robert.beach@cmsenergy.com H Richard Chambers Eric V Luoma Shelley J Ruckman Kimberly C Wilson Assistant General Counsel Ashley L Bancroft Robert W Beach Don A D Amato Gary A Gensch, Jr. Kelly M Hall Gary L Kelterborn Chantez P Knowles Mary Jo Lawrie Jason M Milstone Rhonda M Morris Deborah A Moss* Mirče Michael Nestor Jeffrey D Pintar James D W Roush Scott J Sinkwitts Adam C Smith Janae M Thayer Bret A Totoraitis Anne M Uitvlugt Attorney RE: MPSC Case No. U R In the matter of the application of CONSUMERS ENERGY COMPANY for the Reconciliation of Power Supply Cost Recovery (PSCR) Costs and Revenues for the Calendar Year 2015 Dear Ms. Kunkle: Included in this electronic file for the above-captioned case are Consumers Energy Company s Application, Testimony, and Exhibits of Company witnesses Mark T. Devereaux, Stanley Hunley, Jestin M. Hunnell, David B. Kehoe, Stephen J. Nadeau, Jenny L. Rickard, Raymond T. Scaife, Keith G. Troyer, and Sara T. Walz. This is a paperless filing and is therefore being filed only in a PDF format. Also included is a Proof of Service reflecting service on the parties to Case No. U Sincerely, Robert W. Beach cc: Hon. Sharon L. Feldman, Administrative Law Judge Parties per Attachment 1 to Proof of Service fl

2 S T A T E O F M I C H I G A N BEFORE THE MICHIGAN PUBLIC SERVICE COMMISSION In the matter of the application of ) ) for the Reconciliation of Power Supply ) Case No. U R Cost Recovery (PSCR) Costs and Revenues ) for the Calendar Year 2015 ) ) APPLICATION NOW COMES Consumers Energy Company ( Consumers Energy or the Company ) and, pursuant to 1982 Public Act 304 ( Act 304 ), MCL 460.6j, as amended, and other applicable laws, orders, and regulations, hereby applies for approval of its Power Supply Cost Recovery ( PSCR ) reconciliation for the period January 2015 through December 2015 and for other relief as stated herein. In support of this Application, Consumers Energy states as follows: 1. Consumers Energy is a public utility engaged in, among other things, the generation, purchase, distribution, and sale of electric energy to approximately 1.8 million retail electric customers in the lower peninsula of the State of Michigan. 2. Consumers Energy s retail electric business is subject to the jurisdiction of the Michigan Public Service Commission ( MPSC or the Commission ) pursuant to the provisions of 1939 Public Act 3, as amended by various acts, including Act 304 and other applicable law. 3. Pursuant to Section 6j of Act 304, MCL 460.6j, on September 30, 2014, Consumers Energy filed an Application with the Commission in Case No. U for approval of a PSCR plan and PSCR factors for the 12-month period ending December 31, As of the date of this Application, an order has not been issued in Case No. U ap

3 4. Consumers Energy requests that the Commission commence a PSCR reconciliation proceeding pursuant to Section 6j(12) of Act 304, MCL 460.6j(12) for the 12-month period ending December 31, Concurrently with the filing of this Application, Consumers Energy is filing testimony and exhibits in support of its requested reconciliation of PSCR costs and revenues for the 12-month period ending December 31, The Company s 2015 power supply costs are presented in the testimony and exhibits of Company witnesses Mark T. Devereaux, Stanley Hunley, Jestin M. Hunnell, David B. Kehoe, Stephen J. Nadeau, Raymond T. Scaife, Keith G. Troyer, Jenny L. Rickard, and Sara T. Walz. The Company s filing includes a record of monthly over- and underrecovery amounts, as well as details concerning PSCR costs, revenues, and amounts subject to refund. Attachment 1 to this Application contains a list of prefiled exhibits. 6. During the 12-month period ending December 31, 2015, Consumers Energy incurred PSCR costs of approximately $1.87 billion. Consumers Energy has calculated that it has a total 2015 overrecovery of approximately $5.52 million, which is subject to the roll-in treatment as authorized by the Commission in Case No. U The calculated amount reflects an overrecovery for the PSCR period of approximately $4.87 million and the accrued interest owed by Consumers Energy to customers for the PSCR period, pursuant to Act 304, of $652, The Company requests that a hearing on this Application be initiated and concluded expeditiously. ap

4 WHEREFORE, Consumers Energy respectfully requests that the Commission: (A) Issue a Notice of Hearing of the commencement of this PSCR Reconciliation proceeding; (B) Approve the January 2015 through December 2015 PSCR Reconciliation as presented in Consumers Energy s testimony and exhibits in this filing; (C) Approve Consumers Energy s proposed methodology for rolling in the net overrecovery; and (D) Grant Consumers Energy such other and further relief as is lawful and appropriate. Respectfully submitted, Dated: March 31, 2016 By: Timothy J. Sparks Vice President Energy Supply Operations Robert W. Beach (P73112) Anne M. Uitvlugt (P71641) Gary A. Gensch, Jr. (P66912) Attorneys for Consumers Energy Company One Energy Plaza Jackson, Michigan (517) ap

5 S T A T E O F M I C H I G A N BEFORE THE MICHIGAN PUBLIC SERVICE COMMISSION In the matter of the application of ) ) for the Reconciliation of Power Supply ) Case No. U R Cost Recovery (PSCR) Costs and Revenues ) for the Calendar Year 2015 ) ) VERIFICATION Timothy J. Sparks states that he is Vice President Energy Supply Operations of Consumers Energy Company; that he has executed the foregoing Application for and on behalf of Consumers Energy Company; that he has read the foregoing Application and is familiar with the contents thereof; that the facts contained therein are true, to the best of his knowledge and belief; and that he is duly authorized to execute such Application on behalf of Consumers Energy Company. Dated: March 31, 2016 Timothy J. Sparks Vice President Energy Supply Operations ap

6 Attachment 1

7 PREFILED EXHIBITS Attachment 1 Case No. U R March 2016 Page 1 of 2 Exhibits of Mark T. Devereaux: Exhibit A-1 (MTD-1) Exhibit A-2 (MTD-2) Exhibit A-3 (MTD-3) Exhibit A-4 (MTD-4) Purchased, Interchanged, and Renewable Power Transactions 2015 Interchange Delivered by Counterparties to MISO Purchased Power and Cogeneration Energy and Expense Purchased Power Contract Rates and MPSC Approval Orders Exhibits of Stanley Hunley: Exhibit A-5 (SH-1) 2015 Power Supply Cost Recovery Reconciliation Exhibit A-6 (SH-2) PSCR Interest Calculation 2015 Exhibit of Jestin M. Hunnell: Exhibit A-7 (JMH-1) 2015 Expense and Revenue resulting from Congestion, FTR and ARR Transactions Exhibits of David B. Kehoe: Exhibit A-8 (DBK-1) Event Summary Report, January 2015 to December 2015 Exhibit A-9 (DBK-2) Exhibit A-10 (DBK-3) Exhibit A-11 (DBK-4) Exhibit A-12 (DBK-5) Exhibit A-13 (DBK-6) Exhibit A-14 (DBK-7) Exhibits of Stephen J. Nadeau: Event Identification Outages Periodic Outage Reports 2015 Fossil and Pumped Storage Outages Occurring For Twenty-Eight Days or More Generation Performance Statistics (January 1, 2015 to December 31, 2015) Comparison of Consumers Energy and GADS Averages for Similar Units 2015 Base Load Generation Power Plant Cost Efficiency Exhibit A-15 (SJN-1) Exhibit A-16 (SJN-2) 2015 Coal Receipts Plan and Actual 2015 Projected Cost of Fuel and Actual Cost Exhibits of Jenny L. Rickard: Exhibit A-17 (JLR-1) MPSC Form P-521 Billing Adjustment Summary

8 Attachment 1 Case No. U R March 2016 Page 2 of 2 Exhibit of Raymond T. Scaife: Exhibit A-18 (RTS-1) 2015 Summary of MISO Market and Tariff Administration Charges/(Credits) Settlement Exhibit of Keith G. Troyer: Exhibit A-19 (KGT-1) PA 295 Purchased Power and New Build Renewables Exhibit of Sara T. Walz: Exhibit A-20 (STW-1) Forecasted and Actual Generation Requirements and Purchased and Interchange Expense 2015

9 S T A T E O F M I C H I G A N BEFORE THE MICHIGAN PUBLIC SERVICE COMMISSION In the matter of the application of ) ) for the Reconciliation of Power Supply ) Case No. U R Cost Recovery (PSCR) Costs and Revenues ) for the Calendar Year 2015 ) ) DIRECT TESTIMONY OF MARK T. DEVEREAUX ON BEHALF OF March 2016

10 MARK T. DEVEREAUX DIRECT TESTIMONY Q. Please state your name and business address. A. My name is Mark T. Devereaux, and my business address is 1945 West Parnall Road, Jackson, Michigan Q. By whom are you employed? A. I am employed by Consumers Energy Company ( Consumers Energy or the Company ) as a Principal Financial Analyst in the Electric Transactions and Wholesale Settlements section of the Energy Supply Operations Department. Qualifications Q. Please describe your educational background and business experience. A. I received a Bachelor of Science Degree in Electrical Engineering from Michigan State University in During my career at Consumers Energy, I have also participated in internal and external classes and seminars involving project management, economic decision making, contract negotiation, and contract litigation, among others. I began my employment in 1982 with Consumers Energy as an Associate Engineer in the Power Resources Planning section of the Power Resources and System Planning Department. This position involved long-term generation planning studies and modeling of interchange power with other utilities. In 1985, I accepted a position as a General Engineer in the Interconnected Systems and Energy Control Analysis section of the Power Resources and System Planning Department. In this position, I was responsible for transmission system load flow studies for Consumers Energy and also (with others) for the MAAC, ECAR, and NPCC reliability organizations. Except for the year 1997 and a portion of 1998, during which period I worked in various other capacities within CMS Energy, I have been working in the Energy Supply te0316-mtd 1

11 MARK T. DEVEREAUX DIRECT TESTIMONY Operations Department and its predecessor departments since In this position, I have had increasing responsibilities for the negotiation and administration of a variety of contracts including power purchase and interconnection agreements with nonutility generators, plant joint ownership agreements, interconnection agreements with other utilities, Schnabel railroad car lease agreements, wholesale power sales agreements, master power purchase and sale agreements, and transmission service agreements. In 2008, I was promoted to my current position as a Principal Financial Analyst in the Electric Transactions and Wholesale Settlements section of the Energy Supply Operations Department. Q. Have you testified in other cases? A. Yes. I provided direct and rebuttal testimony in Michigan Public Service Commission ( MPSC or the Commission ) Case No. U regarding the 2009 Renewable Energy Plan, direct and rebuttal testimony in MPSC Case No. U R regarding the reconciliation of Power Supply Cost Recovery ( PSCR ) costs and revenues for calendar year 2013, and direct testimony in MPSC Case No. U R regarding the reconciliation of PSCR costs and revenues for calendar year Purpose of Testimony Q. What is the purpose of your testimony? A. My testimony will address: (1) Purchased Power Supply Costs incurred by the Company in 2015; (2) Allocation of Costs to the Renewable Resource Fund ( RRF ); (3) Purchases and Sales with third parties in 2015 (including purchases made to enable the removal of Karn Unit Nos. 3 and 4 from service and purchases to replace the capacity of Ludington Unit No. 5); and (4) the purchase of capacity to enable the removal of Gaylord Units 1, 2, and 3 and Straits Unit 1 from service. te0316-mtd 2

12 MARK T. DEVEREAUX DIRECT TESTIMONY 1 2 Q. Are you sponsoring any exhibits? A. Yes. I am sponsoring the following exhibits: Exhibit A-1 (MTD-1) Exhibit A-2 (MTD-2) Exhibit A-3 (MTD-3) Exhibit A-4 (MTD-4) Purchased, Interchanged, and Renewable Power Transactions; 2015 Interchange Delivered by Counterparties to MISO; Purchased Power and Cogeneration Energy and Expense; and Purchased Power Contract Rates and MPSC Approval Orders Q. Were these exhibits created by you or under your supervision? A. Yes Purchased, Interchange, and Renewable Power Transactions Q. Please describe Exhibit A-1 (MTD-1). A. Exhibit A-1 (MTD-1) provides a summary of the Company s Purchased, Interchanged, and Renewable Power Transactions booked for Q. Please describe line 1 of Exhibit A-1 (MTD-1). A. Line 1 of Exhibit A-1 (MTD-1) Purchased Power provides volumes and costs for capacity and energy that was purchased by Consumers Energy from cogenerators, small power producers, and independent power producers who had agreements to sell capacity and energy to Consumers Energy on a long-term basis. For purchases from the Company s Renewable Resource Program ( RRP ) suppliers, only the average PSCR cost associated with those purchases is included in line 1, which is described in more detail later in my testimony. te0316-mtd 3

13 MARK T. DEVEREAUX DIRECT TESTIMONY Q. Please describe line 2 of Exhibit A-1 (MTD-1). A. Line 2 of Exhibit A-1 (MTD-1) Purchased Power PA 295 provides volumes and costs for capacity and energy that was purchased under Power Purchase Agreements ( PPAs ) that provided Renewable Energy Credits in accordance with MCL (i)(b) and from purchases under the Company s Experimental Advanced Renewable Pilot Program. Consumers Energy witness Keith G. Troyer discusses renewable transfer costs associated with Public Act 295 of 2008 in more detail in his testimony. Q. Please explain line 3, Interchange Received Non-MISO and line 8, Interchange Delivered Non-MISO, of Exhibit A-1 (MTD-1). A. The entry for Interchange Received Non-MISO, shown on line 3 of Exhibit A-1 (MTD-1) provides the volumes and costs for the purchase of energy and capacity from a counterparty other than purchases from the Company s long-term contract suppliers (shown on line 1). The entry Interchange Delivered Non-MISO, shown on line 8 of Exhibit A-1 (MTD-1) provides the volumes and revenues for sales of energy and capacity to a counterparty, other than sales to the energy market operated by the Midcontinent Independent System Operator, Inc. ( MISO ). With the exception of the capacity sale revenue discussed below, Company witness Raymond T. Scaife discusses the energy expenses and revenues in more detail in his testimony. Q. Can you describe the capacity sale revenues shown on line 8, column (g)? A. Yes. The Company purchased replacement capacity in 2015 for Ludington Unit No. 5 on behalf of both Consumers Energy and DTE Electric, the joint owners of the Ludington Plant, and these revenues are the result of providing DTE Electric with its share of the purchased replacement capacity. I will discuss these transactions later in my testimony. te0316-mtd 4

14 MARK T. DEVEREAUX DIRECT TESTIMONY Q. Please explain line 4, Interchange Received MISO and line 9, Interchange Delivered MISO of Exhibit A-1 (MTD-1). A. The entry for Interchange Received MISO, shown on line 4 of Exhibit A-1 (MTD-1), includes the purchase of energy from MISO in column (e) and the MISO capacity purchases described later in my testimony in column (g). The entry for Interchange Delivered MISO, shown on line 9 of Exhibit A-1 (MTD-1) includes the sale of energy to the MISO energy market in column (e) and the MISO capacity sales described later in my testimony in column (g). The amount of Interchange Energy Received and Delivered is a result of the operation of the MISO energy market and the Security Constrained Economic Dispatch that is performed by MISO. Company witness Scaife discusses the net of lines 4 and 9, column (h), as shown on line 16, column (h), of Exhibit A-1 (MTD-1) in greater detail in his testimony. Q. Please describe the transmission expenses included in Exhibit A-1 (MTD-1), line 5. A. The transmission expenses included in Exhibit A-1 (MTD-1), line 5 are charges to transmission customers based on the MISO tariff approved by the Federal Energy Regulatory Commission. Company witness Scaife provides more detail on this topic in his testimony. Q. Please describe line 6 of Exhibit A-1 (MTD-1). A. Line 6 of Exhibit A-1 (MTD-1), Short-Term Capacity Purchases, includes bilateral purchases made to meet or maintain Consumers Energy s reserve margin requirements for the MISO 2014 Planning Year that ended on May 31, 2015 and for the MISO 2015 Planning Year that began on June 1, te0316-mtd 5

15 MARK T. DEVEREAUX DIRECT TESTIMONY Q. What is the total short-term bilateral capacity expense associated with the MISO 2014 and 2015 Planning Years for which recovery is sought in this proceeding? A. That expense is described later in my testimony in connection with: (1) the removal of Karn Unit Nos. 3 and 4 from service for an eight-month period ending May 31, 2015; (2) purchases from a reverse capacity auction that the Company conducted in September 2014; and (3) the purchase of capacity to replace Ludington Unit No. 5 due to a catastrophic outage of that unit. Q. Please describe line 10, Interchange Delivered by Counter-parties MISO, of Exhibit A-1 (MTD-1). A. Line 10 of Exhibit A-1 (MTD-1) includes energy sales to MISO executed on behalf of the Company by the Company s Renewable Energy Counter-Parties for 2015 and is discussed in detail below. Q. Please describe line 11, Schedule 2 Reactive, of Exhibit A-1 (MTD-1). A. Line 11 of Exhibit A-1 (MTD-1) includes the revenue received pursuant to MISO s Schedule 2 for reactive service which the Company provides as a service necessary for the transmission of power. Q. Please describe line 13, PA 295 New Build Renewables, of Exhibit A-1 (MTD-1). A. Line 13 of Exhibit A-1 (MTD-1), includes the transfer costs calculated in accordance with MCL (2)(b)(iv) associated with provider-owned renewable energy systems as provided by MCL (1)(a). Consumers Energy witness Troyer discusses this item in more detail in his testimony. te0316-mtd 6

16 MARK T. DEVEREAUX DIRECT TESTIMONY Interchange Delivered by Counterparties to MISO Q. Please describe Exhibit A-2 (MTD-2). A. Exhibit A-2 (MTD-2) details the production delivered to the MISO energy market and revenue received from each of the Company s Renewable Energy contract generators for The Renewable Energy purchase agreements applicable to these generators are designed to limit the Company s exposure to market participation risks, while providing the economic benefits to the Company s customers. The contracts require the generator owners to be the Market Participant for their generators. The generator owner sells the energy produced into the MISO energy market on behalf of the Company. The Company receives the revenue for these sales at the Day Ahead locational marginal prices. Exhibit A-2 (MTD-2) details the revenue received from these suppliers. The totals from lines 8 and 16 of Exhibit A-2 (MTD-2) are reported on line 10 of Exhbit A-1 (MTD-1). Allocation of Costs to the RRF Q. Please explain the RRP. A. In MPSC Case No. U-13843, the Commission directed the Company to develop an RRP in which the Company purchases renewable energy from various suppliers and recovers the cost of such purchases through several funding mechanisms, including the PSCR, voluntary contributions from customers, and an RRF. Q. How will the purchase of renewable energy for this program be treated for purposes of the PSCR reconciliation? A. In MPSC Case No. U-13843, the Commission authorized Consumers Energy to implement a renewable resource funding mechanism to recover Green Power Program te0316-mtd 7

17 MARK T. DEVEREAUX DIRECT TESTIMONY costs. The Commission established a RRF to be used exclusively for compensating Consumers Energy for costs associated with offering the program as follows: The fund will be used to compensate Consumers Energy for costs that are not recovered from customers who voluntarily choose the Green Power Program or are not recovered through the PSCR process. Renewable energy contracts entered into by Consumers Energy will be included in its PSCR factor at the average PSCR cost so that inclusion of these contracts will have no effect on the PSCR factor. The difference between the contract price and the average PSCR cost will be recovered through the fund, except for those costs that are being recovered from customers who voluntarily choose the Green Power Program. Consumers Energy should enter into renewable contracts commensurate with the anticipated amount of the fund. May 18, 2004 Order in MPSC Case No. U-13843, at The energy purchased for the RRP is recognized as part of the total mix of energy supplied by Consumers Energy to its customers. However, the purchase cost of the renewable energy in excess of the average PSCR costs will not have any impact on the PSCR because the cost of the energy purchased for the RRP is included in this reconciliation at the average PSCR cost. Q. How have the Company s RRF credits been reflected in the calculation of the Company s Purchased and Interchange ( P&I ) Power Expense? A. The cost of energy delivered by suppliers under this program consists of two components: (1) the average PSCR cost, which is booked as P&I Power expense and (2) the cost in excess of average PSCR costs, which are paid from the RRF and are not booked as P&I Power expense. Q. Did any new generating facilities associated with the RRP s PPAs commence operations in 2015? A. No. te0316-mtd 8

18 MARK T. DEVEREAUX DIRECT TESTIMONY Q. How many facilities are currently operating to supply energy for the RRP? A. The Company has six Green Generation Program supply facilities in operation with total contracted annual output of approximately 241,600 megawatt-hours ( MWh ) in These facilities are identified on Exhibit A-4 (MTD-4) page 3 of 5. Q. How much energy was delivered from operating RRP facilities during 2015? A. There were 214,526 MWh of energy purchases received by Consumers Energy under the RRP agreements during Expense for RRP deliveries during the year totaled $16,478,462. Q. How is the cost of energy purchased under these agreements handled so that the PSCR is not impacted, as directed by the Commission? A. The RRP PPAs are structured such that payment occurs in two parts: (1) an energy purchase expense and (2) a renewable purchase expense. The renewable purchase expense of $5,347,458 is offset by the RRF and is not a PSCR expense. The energy purchase expense of $11,131,004 is based on the estimated average PSCR cost of energy. The PSCR will not be impacted by the energy purchase expenses under these agreements since these expenses are equal to the average PSCR expense that would have been incurred absent these expenses. Q. You stated that the energy purchase expense is based on the estimated average PSCR cost of energy. How is Consumers Energy proposing to handle the difference between the actual average PSCR cost of energy and the estimated average PSCR cost of energy? A. Since the actual average PSCR cost of energy for 2015 is being determined by this proceeding, Consumers Energy cannot reconcile the difference between estimated and actual until the Commission issues an order in this case and the actual cost has been te0316-mtd 9

19 MARK T. DEVEREAUX DIRECT TESTIMONY established. Any reconciled amount will be booked in the year that the Commission s order is issued and reconciliation occurs. Purchases and Sales With Third Parties in 2015 Q. Please describe Exhibit A-3 (MTD-3). A. Exhibit A-3 (MTD-3) summarizes the capacity and energy charges recoverable as PSCR costs in accordance with prior Commission orders paid to each Purchased Power and Cogeneration entity in Additionally, Exhibit A-3 (MTD-3) line 50 includes the booked expense associated with payments invoiced or expected to be invoiced by the Biomass Merchant Plants for certain expenses as explained by Consumers Energy witness Jenny L. Rickard s testimony. Lines 10 and 27 from the same exhibit show expenses for incidental energy produced from the Elk Rapids and WM Renewable Energy (Northern Oaks) facilities which are not included in the renewable transfer costs because these expenses are associated with energy delivered that is in excess of the contracted quantity of renewable energy. In addition, line 20 shows a credit for administrative charges for the Scenic View Dairy (Fennville) facility which is not included in the renewable transfer costs because this revenue is germane to PSCR. Q. How much replacement capacity and energy did the Company receive under its PPA with Entergy Nuclear Power Marketing ( ENPM )? A. The Company received a total of 6,909,654 MWh under its PPA with ENPM. Of that total, 726,929 MWh (or 10.5%) were replacement capacity and energy provided during periods when ENPM s facility was derated. te0316-mtd 10

20 MARK T. DEVEREAUX DIRECT TESTIMONY Q. Have you prepared a summary of the purchased power contract rates and the MPSC approval orders for facilities that were in operation during 2015? A. Yes. Exhibit A-4 (MTD-4) summarizes the capability, energy, and capacity rates for each of the Company s purchased power contracts along with the MPSC orders which approved the capacity rates for each facility. Q. During 2015 were there any capacity charges paid to third parties under transactions with terms exceeding six months in duration that have not been previously approved by the Commission? A. Yes. These transactions include: (1) purchases of Zonal Resource Credits ( ZRCs ) in MISO s annual Planning Resource Auctions ( PRAs ); (2) a bilateral purchase of ZRCs to mothball Karn Unit Nos. 3 and 4, and (3) bilateral purchases of ZRCs to replace capacity that was being supplied by Ludington Unit No. 5. Q. Has Consumers Energy entered into any other contracts which have not yet been approved by the Commission? A. Yes. The Company has entered into a new Reduced Dispatch Agreement ( RDA ) with Ada Cogeneration Limited Partnership ( Ada ). Ada terminated a prior RDA with the Company that was previously approved by the Commission because of significant deviations between the natural gas index price that served as a proxy for Ada s actual fuel costs and Ada s actual fuel costs during the 2014 polar vortex. The new RDA uses Ada s actual fuel costs instead of an index. te0316-mtd 11

21 MARK T. DEVEREAUX DIRECT TESTIMONY Purchases and Sales of ZRCs in MISO s Annual PRAs Q. Please describe the purchases and sales of ZRCs made by the Company in MISO s annual PRAs. A. Only purchases of ZRCs from MISO s annual PRA for Planning Year held in March 2014 resulted in capacity payments to MISO during This purchase was a net purchase of ZRCs (i.e., 1,098.4 ZRCs purchased less ZRCs sold) and was 7 described in my testimony in MPSC Case No. U R. 2 The Company also sold ZRCs in the PRA for Planning Year 2015 from ZRCs the Company had in excess of its Planning Reserve Margin Requirement ( PRMR ). The 2015 expense associated with the purchase of 1,098.4 ZRCs from the Planning Year 2014 PRA was expected to be approximately $2,778,128. The actual cost of these purchases was $2,339,002 as shown on line 4, column (g) of Exhibit A-1 (MTD-1). The approximate 2015 revenue from the sale of ZRCs from the Planning Year 2014 PRA and ZRCs from the Planning Year 2015 PRA during 2015 was expected to be approximately $2,022,479. The actual revenue from these sales was $2,194,656 as shown on line 9, column (g) of Exhibit A-1 (MTD-1). Q. Can you explain the difference between the expected expenses and revenues and the actual expenses and revenues? A. In nonretail load switching states, the cost of purchases by a Load Serving Entity ( LSE ) in the PRA are determined on a daily basis by multiplying the PRA s Auction Clearing Price ( ACP ) times the ZRC difference (if any) between the LSE s PRMR and the ZRCs 1 A Planning Year runs from June 1 of the year named through May 31 of the following year. 2 As of the filing of this case, the Commission has not yet issued a final order in Case No. U R. te0316-mtd 12

22 MARK T. DEVEREAUX DIRECT TESTIMONY included in its Fixed Resource Adequacy Plan ( FRAP ) (i.e., the LSE s daily resource capacity cost = [PRMR FRAP] x ACP). Similarly, the revenues obtained by an LSE from sales in the PRA are determined on a daily basis by multiplying the ACP times the ZRC difference (if any) between ZRCs cleared in the PRA by the LSE and the ZRCs included in its FRAP (i.e., the LSE s daily resource capacity revenue = [PRA Cleared ZRCs FRAP] x ACP). These daily expenses and revenues would be the same for each day of the applicable Planning Year. In a retail load switching state such as Michigan, the formula for calculating daily expense is essentially the same as a nonretail load switching state except that the PRMR changes. If the Electric Distribution Company ( EDC ) has adopted the daily peak load default method (as Consumers Energy did in Planning Year 2014) for assigning LSE obligations related to the meeting of each LSE s PRMR, MISO allocates PRMR on a daily basis by multiplying each LSE s percentage of the load served by the EDC during MISO s daily peak times the PRMR for the EDC s Coincident Peak Demand. As a result, the PRMR used to determine capacity costs can be higher or lower than the PRMR that the Company was required to meet in the PRA and, therefore, the Company s capacity cost can be higher or lower than the cost it would have incurred had the settlement been based on a fixed PRMR. Prior to the start of Planning Year 2015, MISO advised the Company that the daily peak load default method would no longer be an applicable method for determining the PRMR for capacity cost calculations in retail load switching states after the end of Planning Year As a result, MISO began using the preferred default method of determining PRMR for the LSEs in Michigan at the start of the 2015 Planning Year that te0316-mtd 13

23 MARK T. DEVEREAUX DIRECT TESTIMONY began on June 1, Whereas the daily peak load default method allocated PRMR on a daily basis by using each LSE s percentage of the load served by the EDC during MISO s daily peak times the PRMR for the EDC s Coincident Peak Demand (i.e., LSE PRMR = LSE actual load at MISO daily peak / EDC actual load at MISO daily peak x EDC PRA PRMR), the preferred default method simply applies the percentage that each LSE s Coincident Peak Demand is of the EDC s Coincident Peak Demand to the EDC s PRMR on a daily basis (i.e., LSE forecasted coincident peak demand / EDC forecasted coincident peak demand x EDC PRA PRMR). Thus, instead of an LSE percentage that changes daily, the new method only involves percentage changes when retail load switching occurs among the LSEs. As a result, I expect that there will be much less volatility in the day-to-day amounts and that actual costs in the future will be much closer to the expected amount. Thus, based on the foregoing, the primary reason that the Company s actual capacity expense was less than expected was that the PRMR used in the calculation of daily capacity cost was more often lower than the PRMR that the Company was required to meet in the PRA. The reason that revenues from capacity sales were more than expected, is due to the receipt of Zonal Deliverability Benefits. Market Participants receive Zonal Deliverability Benefits when the ACPs among the Local Resource Zones are not all the same. When this happens MISO may collect more payments from LSEs than it pays to the owners of the ZRCs, resulting in a distributionof the surplus to LSEs on a pro-rata basis. te0316-mtd 14

24 MARK T. DEVEREAUX DIRECT TESTIMONY Procurement of ZRCs to Remove Karn Unit Nos. 3 and 4 From Service Q. Please describe the procurement of ZRCs to remove Karn Unit Nos. 3 and 4 from Service. A. As I testified in MPSC Case No. U R, the Company estimated that customer benefits in labor, material, and fuel pipeline reservation expenses could be realized during Planning Year 2014 if sufficient capacity could be purchased to replace the ZRCs provided by the Karn Unit Nos. 3 and 4 generating units, at a cost of approximately $5.9 million ( Breakeven Cost ) or less. (See the Company s Application in MPSC Case No. U and the testimony and exhibit A-4 (DFR-4) of Company witness David F. Ronk, Jr. in that case.) Accordingly, the Company offered the 965 ZRCs associated with Karn Unit Nos. 3 and 4 into the Planning Year 2014 PRA at the Breakeven Cost so that if the PRA cleared at less than this cost, then none of these 965 ZRCs would clear, the capacity to replace Karn Unit Nos. 3 and 4 would be purchased from the market, and Karn Unit Nos. 3 and 4 could be removed from service. The PRA, however, did not clear at a price less than the Breakeven Cost and as a result only 210 ZRCs of the 965 ZRCs associated with Karn Unit Nos. 3 and 4 did not clear the PRA. Because less than 965 ZRCs did not clear the PRA, the Company was unable to remove Karn Unit Nos. 3 and 4 from service at the start of Planning Year 2014 and obtain the above-described savings. As a result, the Company incurred approximately $1.284 million in expense to replace the 210 ZRCs that did not clear the PRA. The actual expense was estimated to be about $1.022 million due to the effect of MISO s capacity settlement process for retail load switching states, as described previously in my testimony. te0316-mtd 15

25 MARK T. DEVEREAUX DIRECT TESTIMONY Q. Did anything change relative to the projected customer benefits? A. Yes. Subsequent to development of the original plan, the Company determined that additional benefits may be derived from the removal from service of Karn Unit 3 by repairing a hydrogen cooler leak that had inhibited the unit s annual capacity test for Planning Year The result of that annual capacity test coupled with the unit s equivalent forced outage rate was 98.9 ZRCs for Planning Year The Company estimated that repair of the hydrogen cooler leak would result in ZRCs becoming available from Karn Unit 3 for Planning Year The Company estimated the value of the additional ZRCs (i.e., ZRCs 98.9 ZRCs) from Karn Unit 3 to be $9.742 million. This projected ZRC value increase for Planning Year 2015 would not have been obtained unless Karn Unit 3 was removed from service, since the MISO Tariff does not allow re-testing of capacity after August 31, 2014 for Planning Year 2015 unless a unit is returning from extended reserve shutdown status 3. Q. What actions did the Company take to secure the additional expected benefits from the repair of the hydrogen cooler leak at Karn Unit 3? A. The Company made a bilateral purchase that began on October 1, 2014 of 755 ZRCs so that Karn Unit Nos. 3 and 4 could be removed from service for the remainder of the 2014 Planning Year. This purchase was made at a total cost of $2.385 million, of which $1.482 million was booked for calendar year 2015, and is included in the $9,029,402 of seasonal capacity expense shown on line 6, column (g) of Exhibit A-1 (MTD-1). As a result, the Company estimated that customers will receive approximately $6.335 million 3 Extended Reserve Shutdown status is sometimes referred to as mothball status. te0316-mtd 16

26 MARK T. DEVEREAUX DIRECT TESTIMONY (i.e., $9.742 million $ million $2.385 million) in net benefits over the course of Planning Years 2014 and Q. Why did the Company also remove Karn Unit 4 from service when only the repair of Karn Unit 3 was necessary to obtain the benefits of incremental ZRCs? A. Karn Unit 4 was also removed from service so that the benefits of the original plan could also be realized. Q. Has the Company previously requested approval from the Commission for the capacity purchased to obtain the savings described above from the removal from service of the Karn 3 and 4 generating units? A. Yes. The Company previously submitted the 210 ZRC purchase described above in the direct and supplemental testimony of Company witness Ronk in MPSC Case No. U and the 755 ZRC bilateral capacity purchase in my direct testimony in MPSC Case No. U R. 4 Reverse Capacity Auction Q. Did Consumers Energy purchase any ZRCs during 2015 to meet its PRMR for Planning Year 2015? A. Yes. The Company purchased 350 ZRCs through a reverse capacity auction that was conducted in September Q. Did the Company receive approval from the Commission for these purchases? A. Yes, the Commission approved the purchases made in that auction in its January 27, 2015 order in MPSC Case No. U The MPSC has not yet issued orders in Case Nos. U and U R. te0316-mtd 17

27 MARK T. DEVEREAUX DIRECT TESTIMONY Q. How much expense did the Company incur for the purchase of these ZRCs during 2015? A. The Company booked $6,365,503 for the purchase of these ZRCs during 2015, which is included in the $9,029,402 of seasonal capacity expense shown on line 6, column (g) of Exhibit A-1 (MTD-1). Procurement of ZRCs to Replace Ludington Unit No. 5 Q. Please describe the procurement of ZRCs to replace the capacity of Ludington Unit No. 5. A. On June 9, 2015 Ludington Unit No. 5 experienced a forced outage due to a thrust bearing failure. Under most circumstances MISO does not require that capacity supplied by a generating unit be replaced as a result of a forced outage, but the Company concluded that declaring a catastrophic outage in accordance with the provisions of the MISO tariff and business practice manuals and replacing the capacity from Ludington Unit No. 5 that cleared in the 2015 PRA was in the best interest of its customers. Q. What were the primary issues the Company had to address to reach its conclusion? A. There were two primary issues to be considered: (1) the longer the unit is on a forced outage the more its Equivalent Forced Outage Rate on demand ( EFORd ) increases which means that a significant reduction in capacity credit could be expected during the next three Planning Years since EFORd is measured over a three-year rolling period; and (2) unless the unit returns to service from a catastrophic outage prior to the planned overhaul of the unit, then scheduled to begin in January 2016 and be completed in December 2016, MISO could determine that no capacity credit should be allocated to the unit for Planning Year 2016 since units returning from a catastrophic outage are required to conduct a capacity test. te0316-mtd 18

28 MARK T. DEVEREAUX DIRECT TESTIMONY Q. Why were these two issues of primary importance? A. The Company had three options to deal with this situation: (1) allow the unit to remain in a forced outage until the overhaul could be completed in December 2016; (2) repair the unit and return it to service before the planned overhaul; and (3) declare a catastrophic outage, reset the unit s EFORd to the MISO class average, and replace the unit s capacity for the remainder of Planning Year As I indicated previously, the problem with the first option is that it would result in a significant deterioration in the unit s EFORd and consequently the unit s available capacity credit going forward for three years. The problem with the second option was that while it would mitigate some of the EFORd deterioration, it would have only returned the unit to service for a few weeks before the planned overhaul, and the unit would have incurred significant logistical effort and expense for parts that would be used for onlay a few months due to the planned overhaul and upgrade of the unit. The problem with the third option was the risk of losing all of the unit s capacity credit for Planning Year Q. How did the Company eventually reach its conclusion? A. After several extended discussions with MISO, MISO eventually agreed that the appropriate application of the current rules would be to allow the Company to transition from a catastrophic outage to the planned overhaul without conducting a capacity test until the planned outage was complete. As a result, we evaluated the three options described above based on MISO s agreement. Our evaluation (conducted on a total unit basis; i.e., including both the Company s and DTE Electric s shares of the unit) indicated that the third option provided an estimated $40 million in additional capacity credit te0316-mtd 19

29 MARK T. DEVEREAUX DIRECT TESTIMONY versus the first option, and $11 million in additional capacity credit versus the second option. Q. How did the Company go about replacing Ludington Unit No. 5 s capacity? A. We reviewed the results of the 2015 PRA and were able to identify MISO Local Resource Zones that had surplus ZRCs that did not clear the PRA. We then used a calculator available from MISO to determine if there was sufficient transmission capability from those zones to Michigan s Zone 7. Finally, we called several entities in these zones to determine if any of them had surplus ZRCs. The Company then negotiated, on behalf of itself and DTE Electric, the purchase of the ZRCs needed to replace Ludington Unit No. 5 from August 21, 2015 through the remainder of Planning Year The 2015 calendar year portion of these costs was $1,103,732 and that amount is included in the $9,029,402 of seasonal capacity expense shown on line 6, column (g) of Exhibit A-1 (MTD-1). The Company sold DTE Electric its share of the replacement ZRCs at the applicable purchase prices for a total cost of $603,762 for calendar year Such revenue amount is shown on line 8, column (g) of Exhibit A-1 (MTD-1). Gaylord and Straits Capacity Purchase Q. Why did the Company make a capacity purchase associated with its Gaylord Units 1, 2, and 3 and Straits Unit 1B peaking units for MISO Planning Year 2014? A. As described in the supplemental testimony of Company witness Ronk in MPSC Case No. U and in my testimony in MPSC Case No. U R, the 37.2 ZRCs were 5 The Company had some surplus ZRCs in inventory which it used to reduce the amount of ZRCs it was required to purchase on its behalf. te0316-mtd 20

30 MARK T. DEVEREAUX DIRECT TESTIMONY purchased to allow the Company to remove these units from service when their MISO System Support Resource Agreements expired at the end of September Q. Why did Consumers Energy remove these units from service? A. These units are aero-derivative combustion turbine generating units that are approaching the end of their economic life. The Company was able to purchase ZRCs through the PRA to replace the capacity of the Gaylord and Straits units for the remainder of the 2014 MISO Planning Year at a lower cost than keeping the generating units operating and available. Conclusion Q. Please summarize your testimony. A. In this testimony, I have presented the basis for recovery of $1,396,764,826 in net P&I and Renewable power supply expense for My testimony has identified the parties with whom the Company has long-term supply contracts, the amount of power received from each party, and the amount paid to each party. For those contracts for which Commission approval is required, I have identified the case in which approval was received. I have accounted for the treatment of expense associated with the RRP as approved by the Commission in MPSC Case No. U-13843, resulting in the as-booked supply of 214,526 MWh of certified renewable energy at no incremental cost to customers, except the contributions customers elected to provide on a voluntary basis. Q. Do you believe that all of the expenses and revenues summarized on Exhibit A-1 (MTD-1) were prudently incurred? A. Yes. te0316-mtd 21

31 MARK T. DEVEREAUX DIRECT TESTIMONY 1 2 Q. Does this complete your testimony? A. Yes, it does. te0316-mtd 22

32 S T A T E O F M I C H I G A N BEFORE THE MICHIGAN PUBLIC SERVICE COMMISSION In the matter of the application of ) ) for the Reconciliation of Power Supply ) Case No. U R Cost Recovery (PSCR) Costs and Revenues ) for the Calendar Year 2015 ) ) EXHIBITS OF MARK T. DEVEREAUX ON BEHALF OF March 2016

33 MICHIGAN PUBLIC SERVICE COMMISSION Case No.: U R Exhibit: A-1 (MTD-1) Witness: MTDevereaux Page: 1 of 1 Purchased, Interchanged, and Renewable Power Transactions Total Year 2015 (a) (b) (c) (d) (e) (f) (g) (h) (i) (j) Variable Net Fixed Energy Cost Total Cost Line Description MWH Energy Admin Fees Energy $ Energy $ Capacity $ Total $ $/Mwh $/Mwh Purchased & Interchange Power Received 1 Purchased Power 13,005, ,943,012 (969,888) 265,603,575 82,189, ,842, ,635, Purchased Power - PA ,196 63,447,059-63,447,059-8,843,161 72,290, Interchange Received - Non-MISO , , Interchange Received - MISO 4,341, ,492,684-2,339, ,831, Transmission ,911, ,911, Short-Term Capacity Purchases ,029,402 9,029, Total P & I Received 18,224, ,390,071 (969,888) 801,804,779 82,189, ,053,708 1,465,047, Purchased & Interchange Power Delivered 8 Interchange Delivered - Non-MISO , , , Interchange Delivered - MISO 2,185, ,832,426-2,194,656 70,027, Interchange Delivered by Counter-parties - MISO 829, ,850, ,850, Schedule 2 Reactive ,007, ,007, Total P & I Delivered 3,014, ,772,131-2,798, ,570, Non PPA PA 295 PSCR Cost 13 PA 295 New Build Renewables 628,339 45,676,712-45,676,712-2,610,817 48,287, Total PA 295 New Build Renewables 628,339 45,676,712-45,676,712-2,610,817 48,287, Total Net Purchased & Interchanged Power 15,838, ,066,783 (969,888) 733,709,360 82,189, ,866,107 1,396,764, Net MISO Interchange (line 4 - line 9) 2,155, ,660, ,346 52,804,604 (3.28) (3.75)

34 MICHIGAN PUBLIC SERVICE COMMISSION Case No.: U R Exhibit: A-2 (MTD-2) CONSUMERS POWER COMPANY Witness: MTDevereaux Page: 1 of Interchange Delivered by Counterparties to MISO (a) (b) (c) (d) (e) (f) (g) (h) (i) (j) (k) (l) (m) (n) Revenue Received ($) line January February March April May June July August September October November December Total By Counterparty 1 Beebe Renewable Energy $ (721,056) $ (702,929) $ (547,181) $ (677,947) $ (497,497) $ (390,089) $ (282,961) $ (435,732) $ (276,445) $ (702,716) $ (211,084) $ - $ (5,445,637) 2 Harvest II $ (705,726) $ (771,605) $ (521,459) $ (500,877) $ (442,444) $ (361,451) $ (239,382) $ (386,881) $ (266,860) $ (618,169) $ (161,511) $ - $ (4,976,363) 3 Heritage Garden $ (217,011) $ (187,898) $ (181,210) $ (139,326) $ (132,320) $ (78,100) $ (105,882) $ (93,667) $ (123,357) $ (178,631) $ (141,982) $ (136,278) $ (1,715,663) 4 Heritage Stoney Corners I Phase 2 $ (101,722) $ (104,591) $ (98,670) $ (79,967) $ (85,215) $ (46,727) $ (59,466) $ (57,520) $ (61,179) $ (104,619) $ (71,855) $ 31 $ (871,501) 5 Heritage Stoney Corners I Phase 3 $ (69,533) $ (69,539) $ (66,598) $ (53,251) $ (55,757) $ (31,600) $ (33,102) $ (37,064) $ (38,754) $ (65,176) $ (58,773) $ (12,741) $ (591,889) 6 Michigan Wind 2 $ (1,088,590) $ (1,261,383) $ (868,257) $ (777,981) $ (692,911) $ (520,756) $ (417,185) $ (630,729) $ (468,576) $ (741,318) $ 8,640 $ - $ (7,459,045) 7 WM Renewable Pine Tree Acres $ (254,926) $ (316,495) $ (273,121) $ (236,797) $ (261,343) $ (235,366) $ (110,055) $ (376,521) $ (94,483) $ (347,599) $ (202,093) $ (81,817) $ (2,790,615) 8 Total $ (3,158,565) $ (3,414,439) $ (2,556,495) $ (2,466,145) $ (2,167,486) $ (1,664,089) $ (1,248,032) $ (2,018,116) $ (1,329,654) $ (2,758,228) $ (838,659) $ (230,805) $ (23,850,713) Energy Delivered (MWh) January February March April May June July August September October November December Total By Counterparty 9 Beebe Renewable Energy (23,503) (16,762) (19,753) (25,626) (16,491) (15,167) (9,952) (14,700) (10,276) (26,004) (8,471) (186,704) 10 Harvest II (23,298) (19,555) (19,117) (20,161) (15,158) (14,319) (8,493) (13,873) (10,156) (23,355) (6,559) (174,045) 11 Heritage Garden (6,344) (4,958) (5,954) (5,472) (4,653) (2,574) (3,283) (3,455) (4,005) (6,045) (6,126) (5,946) (58,816) 12 Heritage Stoney Corners I Phase 2 (3,279) (2,639) (3,344) (3,150) (3,056) (1,791) (1,965) (2,166) (2,292) (3,980) (3,083) 1 (30,746) 13 Heritage Stoney Corners I Phase 3 (2,242) (1,773) (2,264) (2,095) (1,988) (1,204) (1,093) (1,392) (1,438) (2,475) (2,520) (524) (21,009) 14 Michigan Wind 2 (35,667) (31,931) (31,816) (30,917) (24,276) (21,174) (15,583) (22,971) (18,310) (27,919) 342 (260,223) 15 WM Renewable Pine Tree Acres (8,098) (8,213) (9,247) (8,995) (9,210) (8,612) (9,017) (8,485) (8,219) (7,860) (8,206) (3,415) (97,577) 16 Total (102,433) (85,832) (91,495) (96,417) (74,832) (64,841) (49,387) (67,041) (54,697) (97,640) (34,622) (9,885) (829,120)