December 20, Dear Ms. Kale:

Transcription

1 A CMS Energy Company December 20, 2017 Ms. Kavita Kale Executive Secretary Michigan Public Service Commission 7109 West Saginaw Highway Post Office 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, Corporate Washington, DC Fax: (202) Secretary and Chief Compliance Officer Writer s Direct Dial Number: (517) Writer s Address: anne.uitvlugt@cmsenergy.com SHAUN M JOHNSON Vice President and Deputy General Counsel H Richard Chambers Kelly M Hall Eric V Luoma Assistant General Counsel Ashley L Bancroft Robert W Beach Don A D Amato Robert A. Farr Gary A Gensch, Jr. Gary L Kelterborn Chantez P Knowles Mary Jo Lawrie Jason M Milstone Rhonda M Morris Deborah A Moss* Mirče Michael Nestor James D W Roush Scott J Sinkwitts Adam C Smith Theresa A G Staley Janae M Thayer Bret A Totoraitis Anne M Uitvlugt Aaron L Vorce Attorney RE: Case No. U In the Matter on the Commission s own Motion, establishing the method and avoided cost calculation for CONSUMERS ENERGY to fully comply with the Public Utilities Regulatory Policy Act of 1978, 16 USC 2601 et seq. Dear Ms. Kale: Included in this electronic file in the above captioned case is Consumers Energy Company s Petition for Rehearing and Clarification. This is a paperless filing and is therefore being filed only in a PDF format. I have enclosed a Proof of Service showing electronic service upon the parties. Sincerely, Anne M. Uitvlugt cc: Hon. Mark E. Cummins, Administrative Law Judge Parties per Attachment 1 to the 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, on the Commission s own motion, ) establishing the method and avoided cost calculation ) for CONSUMERS ENERGY COMPANY to fully ) Case No. U comply with the Public Utilities Regulatory Policy ) Act of 1978, 16 USC 2601 et seq. ) ) CONSUMERS ENERGY COMPANY S PETITION FOR REHEARING AND CLARIFICATION Pursuant to Rule 437 of the Michigan Administrative Hearing System s Rules of Practice and Procedure before the Michigan Public Service Commission ( MPSC or the Commission ), Mich Admin Code R , Consumers Energy Company ( Consumers Energy or the Company ) files this Petition for Rehearing of the Commission s November 21, 2017 Order ( Rehearing Petition ), which approved new avoided cost rates for the Company. Specifically, Consumers Energy s Petition for Rehearing seeks clarification from the Commission regarding certain calculation components that form the Company s avoided cost rates. Based on a review of the Commission s November 21, 2017 Order ( November 21, 2017 Order ), Consumers Energy believes that the November 21, 2017 Order incorporates calculation errors into the approved rates. Additionally, Consumers Energy requests rehearing due to the unintended consequences arising out of the Commission s November 21, 2017 Order regarding the newly announced mechanism to relieve the Company of its capacity purchase obligation. See MPSC Case No. U-18090, November 21, 2017 Opinion and Order, page 31. In support of this Rehearing Petition, Consumers Energy states as follows: pe

3 I. STANDARDS FOR REHEARING The Commission s standards concerning rehearing petitions are well-known and have been consistently applied for many years. MPSC Rule 437(1) states the standards for filing a petition for rehearing: A petition for rehearing based on a claim of error shall specify all findings of fact and conclusions of law claimed to be erroneous with a brief statement of the basis of the error. A petition for rehearing based on a claim of newly discovered evidence, on facts or circumstances arising subsequent to the close of the record, or on unintended consequences resulting from compliance with the decision or order shall specifically set forth the matters relied upon. Mich Admin Code R (1). The Commission has indicated that an application for rehearing is not merely another opportunity for a party to argue a position or to express disagreement with the Commission s decision. MPSC Case No. U-13917, August 1, 2005 Order, page 4. Additionally, the Commission has stated that [u]nless a party can show the decision to be incorrect or improper because of errors, newly discovered evidence, or unintended consequences of the decision, the Commission will not grant a rehearing. MPSC Case No. U-13716, October 14, 2004 Order, page 2. The Commission reaffirmed the above standards in MPSC Case No. U as follows: Rule provides that a petition for rehearing may be based on claims of error, newly discovered evidence, facts or circumstances arising after the hearing, or unintended consequences resulting from compliance with the order. A petition for rehearing is not merely another opportunity for a party to argue a position or to express disagreement with the Commission s decision. Unless a party can show the decision to be incorrect or improper because of errors, newly discovered evidence, or unintended consequences of the decision, the Commission will not grant a rehearing. MPSC Case No. U-16045, April 26, 2011 Order, page 4. (Footnote omitted.) 1 MPSC Rule 403 has been replaced by Rule 437 of the Michigan Administrative Hearing System s Administrative Hearing Rules. The language of the rule has remained unchanged. pe

4 Consumers Energy s Rehearing Petition meets the standards for rehearing as it establishes unintended consequences arising out of the change in capacity demonstration process from the Commission s May 31, 2017 Order and identifies calculation errors for the Commission s clarification. II. ARGUMENT A. Calculation Clarification In reviewing the November 21, 2017 Order, the Company believes that there are calculation errors included in the final rates approved. These errors were contained in the approved Locational Marginal Price ( LMP ) Energy Rates, the monthly capacity payment, the Standard Offer tariff Energy Rate table, the Investment Cost Attributable to Energy ( ICE ) adder, and the Proxy Plant Inputs identified on Attachment 1. The discussion below addresses the areas that the Company believes clarification is necessary regarding the rates that were approved in the Commission s November 21, 2017 Order. The attached appendix provides the corrections for the Commission s review. 1. Locational Marginal Price Energy Rates In its July 31, 2017 Order, the Commission approved levelized 5-, 10-, 15-, and 20-year LMP energy payments for run-of-the-river hydro facilities. See MPSC Case No. U-18090, July 31, 2017 Order, page 25 ( July 21, 2017 Order ). The Commission also provided avoided cost inputs and calculations for capacity and energy rates to determine Consumers Energy s avoided costs. Attachment 1 to the November 21, 2017 Order provides an overview of how the rates are to be calculated based on the Commission s Orders. However, page 2 of Attachment 1 to the November 21, 2017 Order contains an inadvertent error. On page 2 of Attachment 1 to the November 21, 2017 Order, Columns A through D and Columns E through H both indicate that they are calculated using an Annual On-Peak Average pe

5 rate. This is depicted in the labels of Columns B and F, respectively. However, Columns E through H should represent the Annual Off-Peak Average Energy Rate for Energy Rate Option 2. As such, the heading on column F should be changed to read Annual Off-Peak Average. Although Column F s heading is incorrect, the values in Column F appropriately represent the Annual Off-Peak Average Rate. Additionally, the levelized LMP Energy Rate should be reduced by a $1/MWh administrative fee. This is shown on page 2 of Attachment 1 of the November 21, 2017 Order and is included as part of the Standard Offer tariff, which is shown in Attachment 2 to the November 21, 2017 Order. Although Attachments 1 and 2 show that an administrative fee should be included with the energy payment, Columns D and H of page 2 of Attachment 1 were not correctly calculated. The rates shown in Columns D and H have not been reduced by the administrative fee as specified in Attachments 1 and 2. These corrections are shown on page 2 of the Appendix. 2. Monthly Capacity Payment In its Order, the Commission adopted an avoided capacity cost of $140,505/Zonal Resource Credit ( ZRC ) year. November 21, 2017 Order, page 25. However, Attachment 2 of the November 21, 2017 Order, in Section D on page 5, shows a monthly capacity payment of $11,709/ZRC-month. It appears that the November 21, 2017 Order rounded this number to the nearest dollar for simplicity. For the purposes of contract administration and settlement, it is important that this rate is exact. As written, 12 monthly payments of $11,709/ZRC-month would equal an annual capacity payment of $140,508/ZRC-year, which is inconsistent with the November 21, 2017 Order s determination of an annual capacity payment of $140,505/ZRC-year. For purposes of consistency with the Commission s November 21, 2017 Order, the monthly capacity payment should be shown as $11,708.75/ZRC-month on page 5 of Attachment 2. This correction is shown on page 8of the Appendix. pe

6 3. Standard Offer Tariff Energy Rate Tables When reviewing the application of line losses, the Commission indicated that because ICE recognizes the lower energy costs of an NGCC compared to an NGCT, and because ICE is a component of energy, the line loss credit should apply to both energy avoided cost and ICE. November 21, 2017 Order, page 27. However, the description of the available energy rates included on Attachment 2 of the November 21, 2017 Order is inconsistent with this determination. Attachment 2, as currently written, applies the line loss credit before adding ICE. For example, Energy Rate Option 1, as written, states Actual MISO Day Ahead Locational Marginal Price (LMP) at the Company s CONS.CETR load node multiplied by 1 plus the line loss adjustment factor of 2.37% plus Fixed ICE of $ /kWh** and less the Administrative Fee of $0.001/kWh. To be consistent with the November 21, 2017 Order, this statement should be amended as follows: Actual MISO Day Ahead Locational Marginal Price (LMP) at the Company s CONS.CETR load node plus Fixed ICE of $ /kWh** then multiplied by 1 plus the line loss adjustment factor of 2.37% and less the Administrative Fee of $0.001/kWh. This change is consistent with the Commission s determination and corresponding changes should be applied to each of the Energy Rate Options identified on the Standard Offer tariff. See Appendix, pages Investment Cost Attributable to Energy In its November 21, 2017 Order, the Commission made the following determination regarding the calculation of ICE: ICE represents the difference between the total fixed costs of an NGCC and an NGCT. The Commission has previously determined that for the NGCT, it would adopt Consumers fixed cost amounts. For the total fixed costs of an NGCC, the Commission again finds that Consumers proposed amount for an advanced NGCC is more reasonable than EIA information which, although publicly available, appears less reliable than the company s information. November 21, 2017 Order, page 27. pe

7 Based on the inputs adopted, the Commission approved a fixed ICE amount of $7.65/MWh. November 21, 2017 Order, page 27. There is a mathematical error in the calculation of a fixed ICE amount. Consistent with the November 21, 2017 Order, ICE should be calculated as the difference between the Company s calculations for the fixed cost of a Natural Gas Combine Cycle ( NGCC ) facility and a Natural Gas Combustion Turbine ( NGCT ) facility. When calculated accurately, the fixed ICE is the difference between $145,173 MW-Year and $117,203 MW-Year, divided by the annual energy produced per megawatt installed, which results in $5.17/MWh. Appendix, page 9, provides the calculation of the ICE payment consistent with the Commission s November 21, 2017 Order, 5. Proxy Plant Inputs Page 1 of Attachment 1 to the Commission s November 21, 2017 Order identifies the approved proxy plant inputs. These inputs are purported to be the Commission s NGCT and NGCC cost input findings from its May 31, 2017, July 31, 2017, and November 21, 2017 Orders. The Company has reviewed the cost inputs and has determined that the NGCT inputs correctly correspond to the Commission s determinations in its Orders. However, the inputs included as NGCC costs do not correspond with the Commission s findings. In the November 21, 2017 Order, the Commission adopted the Company s proposed NGCC fixed O&M costs. Appendix, page 1, provides the NGCC inputs as approved by the Commission. B. Capacity Obligation The Public Utilities Regulatory Policies Act of 1978 ( PURPA ) requires electric utilities to purchase energy and capacity from Qualifying Facilities ( QFs ) at the incremental costs to an electric utility, otherwise known as avoided costs. In implementing PURPA, state regulatory authorities are required to give effect to the Federal Energy Regulatory pe

8 Commission s ( FERC ) implementing regulations. See U.S.C. 824a-3(f)(1); FERC v. Mississippi, 456 US 742, 751; 102 S Ct 2126 (1982). Under this construct, the states play the primary role in calculating avoided costs and in overseeing the contractual relationship between QFs and utilities operating under the FERC regulations. Indep. Energy Producers Ass n v Ca. Pub Utilities. Comm, 36 F3d 848, 856 (CA, 1994); see also Idaho Wind Partners 1, LLC, 143 FERC 61,248 at 10 (2013). Under PURPA, however, there is a limit to the QF purchase requirements. Electric utilities are only required to purchase energy and capacity from QFs when energy and capacity costs can be avoided by the electric utility by making such a purchase. City of Ketchikan, Alaska, 94 FERC 61,293, 62,062 (2001) ( [A]n avoided cost rate need not include capacity unless the QF purchase will permit the purchasing utility to avoid building or buying future capacity. ); see also Connecticut Light & Power Co, 70 FERC 61012, n 11 (1995) ( Thus, for example, capacity payments need be made only when capacity costs will be avoided. ). Furthermore, in its Order addressing the regulations implementing PURPA, FERC elaborated on the circumstances when a utility would not need to purchase energy or capacity from a QF as follows: A qualifying facility may seek to have a utility purchase more energy or capacity than the utility requires to meet its system load. In such a case, while the utility is legally obligated to purchase any energy or capacity provided by a qualifying facility, the purchase rate should only include payment for energy or capacity which the utility can use to meet its total system load. Small Power Production and Cogeneration Facilities; Regulations Implementing Section 210 of the Public Utility Regulatory Policies Act of 1978, Order No. 69, 45 Fed Register 12214, (Feb 2, 1980), FERC Statutes and Regulations, Regulations Preambles ,128, at 30,864 (1980), order on reh'g, Order No. 69-A, 45 Fed Register (May 21, 1980), FERC Statutes and Regulations, Regulations Preambles ,160 (1980), aff'd in part and vacated in part, American Electric Power Service Corporation v FERC, 675 F2d 1226 (D.C. Cir. 1982), rev'd in part, pe

9 American Paper Institute, Inc v American Electric Power Service Corporation, 461 US 402 (1983). Thus, PURPA only requires an electric utility to pay for the energy and capacity that it avoids by purchasing electricity from a QF. This requirement safeguards electric customers from incurring unnecessary and duplicative costs. This safeguard has been recognized by the Commission. In its May 31, 2017 Order, the Commission disagreed with the claim that the utility s obligation to purchase capacity from QFs persists, even if no additional capacity need is forecasted. MPSC Case No. U-18090, May 31, 2017 Order ( May 31, 2017 Order ), page 19. Instead, the Commission recognized that the Company s avoided capacity cost should be adjusted if the Company does not need capacity. Specifically, the Commission indicated that, if no capacity is needed during the 10-year planning horizon, then Consumers shall make a filing so indicating, and the avoided cost for capacity shall be reset to the MISO PRA. Id. In the November 21, 2017 Order, the Commission again discussed the method for the Company to reset its avoided cost capacity rate to the Midcontinent Independent System Operator, Inc. ( MISO ) Planning Resource Auction ( PRA ) price. In that Order, the Commission altered the Company s obligation for demonstrating its capacity needs over a 10-year horizon, indicating that if Consumers capacity requirements are met over the subsequent 10 years, the company may make a filing so demonstrating and, after Commission approval, the capacity rate will be reset to the MISO PRA. November 21, 2017 Order, page 32. (Emphasis added.) As opposed to making a filing, as directed by the Commission in the May 31, 2017 Order, the MPSC s November 21, 2017 Order requires approval of the Company s 10-year capacity planning forecast before the Company can offer QFs the MISO PRA price for capacity. This newly articulated process has the unintended consequence of requiring the Company, and pe

10 its customers, to purchase additional unneeded capacity and has the potential to render the Integrated Resource Planning ( IRP ) process from Act 341 of 2016 meaningless. The Commission s avoided cost proceeding has significantly increased QF interest in the Company s service territory. For the 12-year period prior to the commencement of this proceeding, the Company has signed only two contracts with QFs for the purchase of energy and/or capacity, and interest in new PURPA-based Power Purchase Agreements ( PPAs ) for QFs up to 20 MW remained low. Affidavit of Keith G. Troyer, page 2. Subsequent to the Commission s May 31, 2017 Order, which approved the methodology for determining the Company s avoided costs, the Company began receiving numerous interconnection requests from solar QFs. Since May 31, 2017, the Company received 118 interconnection requests for 296 MW of solar generation ranging in size from 0.15 MW to 20 MW. Affidavit of Keith G. Troyer, page 4. After the Commission approved avoided cost inputs for Consumers Energy, in the November 21, 2017 Order, the Company began receiving numerous inquiries from solar developers exploring the potential sale of solar generation. In total, the Company has been contacted by 80 QFs who are interested in discussing a PURPA-based PPA. Affidavit of Keith G. Troyer, page 4. About half of these contacts are from developers that are likely to pursue multiple solar projects. Under the avoided cost methodology approved by the Commission, this will lead to increased rates and costs to customers. Affidavit of Keith G. Troyer, page 4. For example, one developer has notified the Company of its interest in contracting for 70 MW of solar projects across four facilities. If half of these parties are pursuing this amount of solar capacity and the other half each have a single 2 MW project, the Company would expect to receive requests to contract for over 2.7 GW of solar capacity. This pe

11 vastly outpaces the Company s need for capacity and threatens to require the Company to purchase 2.7 GW of PURPA-based capacity at an added cost of $241 million annually with a total capacity cost expected to exceed $4.8 billion. Affidavit of Keith G. Troyer, page 4. This increase in customer cost is unreasonable and unnecessary. At this time, the Company has no capacity need over the 10-year planning horizon, and as required by the Commission, in Case No. U-18491, the Company filed a 10-year capacity position for review and requested that the Commission reset the Company s avoided capacity cost at the MISO PRA price for all new QF offers to sell capacity. Contrary to the procedure discussed in its May 31, 2017 Order, the Commission s November 21, 2017 Order implies that the Company will offer an annual capacity payment of $140,505/ZRC-year until the Commission issues an order approving the Company s 10-year capacity demonstration and resetting the capacity rate to the MISO PRA. If Commission approval is necessary before the capacity payment can change to the MISO PRA price, the Company will continue to be required to offer the higher capacity payment until the Commission has time to review and approve a filing that the Company produces. This leaves the Company in an untenable position. At the time the Company makes a capacity filing, it is signaling that it no longer has a capacity need. However, the result of this filing will lead to additional requests to contract with the Company. If Commission approval is necessary prior to resetting the capacity rate to the MISO PRA pricing, QFs will become incentivized to execute contracts as quickly as possible to attempt to obtain the higher capacity payment. This is feasible under the process in place for entering into a Standard Offer contracts. Affidavit of Keith G. Troyer, page 6. These requests to contract will only increase the Company s capacity position, which will result in the Company purchasing significant amounts of capacity during a pe

12 time when it already has determined that there is no need over its 10-year planning horizon. Affidavit of Keith G. Troyer, page 6. Entering into these contracts will have lasting implications. In the May 31, 2017 Order, the Commission determined that Standard Offer contracts could be entered into for a term of up to 20 years. May 31, 2017 Order, page 23. At this time, the Company believes there to be approximately 300 MW of solar projects in the interconnection queue. These projects are being developed to establish PURPA contracts for the next 20 years. Although the Company does not have a capacity need, if it is required to sign 300 MWs of PURPA-based solar contracts that are compensated at $140,505/ZRC-yr, the Company s customers will be obligated to pay approximately $26 million annually. This annual expense would burden the Company s customers with up to $519 million of added expense over the next 20 years for a commodity that is unnecessary. Thus, there are longer-lasting consequences arising out of the Commission s November 21, 2017 Order as customers will be forced to pay this unnecessary cost increase over a lengthy period of time. Affidavit of Keith G. Troyer, page 6. Requiring the Company to obtain Commission approval of a 10-year capacity position at this time also has the potential to diminish the IRP process. Public Act 341 of 2016 included several amendments and additions to existing law addressing electric reliability. Chief among those provisions was the addition of Section 6t, which, in part, requires electric utilities to file an integrated resource plan that provides a 5-year, 10-year, and 15-year projection of the utility's load obligations and a plan to meet those obligations, to meet the utility's requirements to provide generation reliability, including meeting planning reserve margin and local clearing requirements determined by the commission or the appropriate independent system operator, and to meet all applicable state and federal reliability and environmental regulations over the ensuing term of the plan. MCL 460.6t(3). Based on a host of factors relevant to capacity pe

13 planning, the Commission must determine whether the utility s IRP represents the most reasonable and prudent means of meeting the electric utility's energy and capacity needs. MCL 460.6t(8). Indeed, as this Commission recently recognized, the IRP is a critical component to capacity planning: In many jurisdictions around the country, regulated electric utilities use IRP to identify and evaluate options for meeting electricity needs over a specified time period. Modeling tools are used to help evaluate a combination of supply-side and demandside resources under different scenarios and assumptions related to load growth, fuel prices, emissions, and other variables. As part of comprehensive energy policy reform, Act 341 establishes a new IRP framework for electric utilities whose rates are regulated by the Commission. The IRP provisions are an important component of the new energy law, which is expected to increase affordability for customers, improve the reliability of electricity, and help protect the environment. MPSC Case No. U-18418, July 31, 2017 Opinion and Order, pages 1-2. The Commission Staff s proposed IRP filing requirements require the Company to file its IRP by June 15, See MPSC Case No. U-18461, October 11, 2017 Order, Attachment A, page 2. It seems reasonable that the Commission would, in issuing its order in the IRP, determine the Company s 10-year capacity need. By requiring the Company to obtain a separate Commission order approving the Company s capacity position over the next 10 years prior to resetting the Company s capacity avoided cost rate to the MISO PRA will make the entire IRP process irrelevant. This will be due to the approximately 300 MWs of unneeded capacity that could be added to the Company s supply portfolio. The effect of this will have drastic price impacts, and it will all occur outside of the IRP process. Moreover, this additional capacity fails to appropriately take into consideration the solar generating facilities energy production. In the IRP, the Company s modeling would determine the most appropriate resources to provide both pe

14 energy and capacity needs. Adding 300 MWs of solar capacity does not take into consideration the energy value of the most reasonable generating resource that would have been selected in an IRP to serve the same 300 MW of demand. See Affidavit of Keith G. Troyer, page 7. This result should be avoided. At the time in which the Company s capacity obligations have been fully met over the 10-year demonstration period, as seen in Case No. U-18491, the capacity payment made under new PURPA contracts should be based on the MISO PRA price. Therefore, the Company should begin offering PURPA contracts at the MISO PRA price immediately after filing the 10-year capacity demonstration, rather than at some future time when the Commission issues an Order approving the Company s capacity demonstration. The Commission s May 31, 2017 Order recognized this and the capacity demonstration procedure previously provided for a method to prevent the situation that is now arising. As such, the Commission should grant rehearing on this issue to clarify that the Company is only required to make a filing showing its 10-year capacity position before the capacity rate is reset to the MISO PRA price, which will alleviate the significant burden the alternative will have on the Company and its customers. pe

15 III. CONCLUSION AND REQUEST FOR RELIEF Therefore, Consumers Energy Company respectfully requests the Michigan Public Service Commission to grant rehearing of the November 21, 2017 Order and clarify its Order to avoid the potential unintended consequences that will result from it. Specifically, the Company requests that the Commission correct the calculation errors incorporated into the approved rates and grant rehearing to clarify that the Company is only required to make a filing showing its 10-year capacity position before the capacity rate is reset to the MISO PRA, consistent with the Commission s May 31, 2017 Order or grant the Company any other relief the Commission deems appropriate. Respectfully submitted, CONSUMERS ENERGY COMPANY Dated: December 20, 2017 By: Anne M. Uitvlugt (P71641) Robert W. Beach (P73112) One Energy Plaza Jackson, Michigan Attorneys for Consumers Energy Company (517) pe

16 S T A T E O F M I C H I G A N BEFORE THE MICHIGAN PUBLIC SERVICE COMMISSION In the matter, on the Commission s own motion, ) establishing the method and avoided cost calculation ) for CONSUMERS ENERGY COMPANY to fully ) Case No. U comply with the Public Utilities Regulatory Policy ) Act of 1978, 16 USC 2601 et seq. ) ) STATE OF MICHIGAN ) ) COUNTY OF JACKSON ) AFFIDAVIT OF KEITH G. TROYER Keith G. Troyer, being duly sworn, deposes and states as follows: 1. I am a Senior Engineer II in the Transactions and Wholesale Settlements, Electric Contract Strategy Section of the Electric Grid Integration Department for Consumers Energy Company ( Consumers Energy or the Company ). My responsibilities include, in part, supervisory and direct responsibilities for administering Power Purchase Agreements ( PPAs ), issuing solicitations for energy and capacity, and managing the Company s capacity position with the Midcontinent Independent System Operator, Inc. ( MISO ). I am a registered professional engineer with the State of Michigan. 2. I testified as a witness on behalf of Consumers Energy in the Company s avoided cost proceeding, which occurred in this Michigan Public Service Commission ( MPSC or the Commission ) case docket, MPSC Case No. U The information provided in this Affidavit is based on my first-hand knowledge of the Company s avoided costs related to the Public Utility Regulatory Policies Act of 1978 ( PURPA ), the Company s avoided cost proceeding in MPSC Case No. U-18090, and my role af

17 administrating PPAs and managing the Company s capacity position. 4. With this filing, Consumers Energy is requesting that the Commission review its November 21, 2017 Order and grant the Company s request for rehearing in light of the unintended consequences that will arise from the Commission s modified capacity demonstration process. The 10-year capacity demonstration process approved serves as the basis for determining if the Company is required to pay Qualifying Facilities ( QFs ) the full avoided capacity costs approved under the Commission s avoided cost methodology or MISO s Planning Resource Auction ( PRA ) price. The method approved in the Commission s November 21, 2017 Order will result in excessive costs and unnecessary capacity purchases. 5. For the 12-year period prior to the commencement of the proceeding in MPSC Case No. U-18090, the Company signed only two contracts with QFs for the purchase of energy and/or capacity that are still in effect as of December As evidenced by this small quantity of newly executed, long-term PURPA-based contracts, interest in new PURPA-based PPAs for QFs up to 20 MW has historically remained low. 6. Over the course of this proceeding, the Commission approved an avoided cost methodology based on a natural gas combustion turbine for capacity costs and a natural gas combined cycle for energy costs. Within this methodology, the Commission approved a capacity rate that provides for capacity to be compensated based on the demonstrable capability available from the resource to meet the Company s demand. This methodology provided a significant change in financial benefits for potential solar QF resources. While the Company supports the utilization of Zonal Resource Credit ( ZRC ) methodology for capacity compensation, this new method provides more attractive economics for technologies, like solar, that have a higher capacity credit and a lower capacity factor. For illustrative purposes, the af

18 following table demonstrates average annual compensation for 1 MW of generation over a 20-year contract term for several generating technologies. Capacity Credit Capacity Rate Capacity Payment Capacity Factor Generation Energy Rate Energy Payment Total Payment Total Rate Technology ($/ZRC) ($) (MWh) ($/MWh) ($) ($) ($/MWh) Solar 50.0% 140,505 70, % 1, , , Wind 15.2% 140,505 21, % 2, , , ROR Hydro 51.7% 140,505 72, % 4, , , States across the country have seen an increase in solar QFs. As PURPA is federally mandated, individual states across the country, like in Michigan, have determined specific avoided cost calculations, standard offer contract terms, and the minimum capacity thresholds. In the State of North Carolina, utilities were required to establish up to 15-year fixed-cost contracts for eligible solar QFs up to 5 MW based on the utilities avoided costs. With the availability of long-term contracts, solar developers were able to secure project financing, making North Carolina attractive to solar developers. This situation caused a boom of solar in North Carolina catapulting it to become the state with the second-highest amount of installed utility-scale solar capacity owned by independent power producers in See North Carolina has more PURPA-qualifying solar facilities than any other state, U.S. Energy Information Administration, August 23, In 2016, 1,173 MW, or 92%, of North Carolina's 1,271 MW utility-scale solar capacity is certified to have QF small power producer status under PURPA, which is more than any state in both absolute and percentage terms. Id. 8. Currently, in North Carolina, around 3.5 GW of PURPA solar projects are either online or in the queue for development. See North Carolina governor signs PURPA overhaul bill, PV Magazine, July 27, If 3.5 GW of PURPA solar is installed in Consumers Energy s territory, which is consistent with North Carolina s experience, the Company would expect to receive about 2,188 ZRCs at an annual capacity cost of approximately $307.5 million. af

19 Assuming that each of these solar facilities select 20-year contracts, the total capacity cost alone would exceed $6.1 billion. 9. The media attention surrounding this proceeding has driven the interest of solar developers since the May 31, 2017 Order. Subsequent to the Commission s May 31, 2017 Order in this case, the Company began receiving numerous interconnection requests from potential solar QFs due to updating the avoided cost methodology. Between May 31, 2017 and November 31, 2017, the Company received 118 interconnection requests for 296 MW of solar generation ranging in size from 0.15 MW to 20 MW. 10. Furthermore, subsequent to the Commission s November 21, 2017 Order, the Company began receiving numerous inquiries and offers from solar developers exploring the potential sale of solar generation to the Company. To date, the Company has been contacted by 80 parties interested in establishing a PURPA-based PPA. About half of these contacts are from developers that are likely to pursue multiple solar projects. For example, one developer has notified the Company of its interest in contracting for 70 MW of solar projects across four facilities. If half of these parties are pursuing this amount of solar capacity and the other half each have a single 2 MW project, the Company would expect to receive requests to contract for over 2.7 GW of solar capacity. Thus, the number of inquiries from potential solar QFs has vastly outpaced the Company s need for capacity and threatens to require the Company and its customers to purchase unneeded capacity. The added cost of 2.7 GW of PURPA-based capacity payments would be $241 million annually with a total capacity cost expected to exceed $4.8 billion over a 20-year period. 11. In addition to the unexpected influx of solar interconnection requests received by the Company, the Commission has approved a 10-year capacity demonstration mechanism that af

20 does not protect customers from excessive costs. In its May 31, 2017 Order, the Commission indicated that if no capacity is needed during the 10-year planning horizon, then Consumers shall make a filing so indicating, and the avoided cost for capacity shall be reset to the MISO PRA. MPSC Case No. U-18090, May 31, 2017 Order, page 19. The Commission also specifically rejected a claim that the utility s obligation to purchase capacity from QFs persists, even if no additional capacity need is forecasted. However, in the Commission s November 31, 2017 Order, the Commission found that [i]n the meantime, if Consumers capacity requirements are met over the subsequent 10 years, the company may make a filing so demonstrating and, after Commission approval, the capacity rate will be reset to the MISO PRA. MPSC Case No. U-18090, November 21, 2017 Order, page 32. (Emphasis added.) By requiring approval of the Company s 10-year capacity forecast before the Company can offer QFs the MISO PRA price for capacity, the Commission has placed the Company and its customers in a situation that will require, unless otherwise indicated by the Commission, the purchase of capacity which is not needed. This change in the capacity demonstration process fails to protect the Company s customers from unnecessary and excessive capacity costs. 12. The Commission s November 21, 2017 Order implies that the Company will be required to offer an annual capacity payment of $140,505/ZRC-year until the Commission issues an order agreeing with a 10-year capacity demonstration. This procedure will result in unintended consequences as it will cause the Company s customers to incur unnecessary expense over an extended period of time. Once the Company s capacity needs over the next 10-Planning Years have been secured, the Company no longer has a need to purchase capacity. However, if Commission approval is necessary before the capacity payment can change to the MISO PRA price, the Company will continue to be required to offer the higher capacity af

21 payment on an ongoing basis. Even if the Commission conducted its review on an expedited basis, the act of requiring Commission approval of the Company s 10-year capacity demonstration filing will allow QFs to continue to enter into contracts to purchase capacity at the Commission-determined full avoided cost rate. Once final rates are approved, subject to the Company s receipt of the necessary documentation, the process in place for entering into Standard Offer contracts allows for developers of projects under 2 MW to enter into agreements quickly. Under the May 31, 2017 Order, the term of these Standard Offer contracts can be up to 20 years. Thus, at the time in which the Company s capacity obligations have been fully met over the 10-year demonstration period, the capacity payment made under new PURPA contracts should be based on the MISO PRA price. The Company should be permitted to begin offering PURPA contracts at the MISO PRA price immediately after filing the 10-year capacity demonstration. The Commission s May 31, 2017 Order recognized this timing issue, and the capacity demonstration procedure previously provided for correctly set forth a method to prevent the situation that is now arising. 13. The requirement of Commission approval of the 10-year capacity demonstration will create a cycle of boom and bust. At the time when the Company files a capacity demonstration showing no capacity need, QFs will become incentivized to execute contracts as quickly as possible to attempt to lock in the higher capacity payment. These requests to execute contracts will only increase the Company s capacity position which will cause the Company to purchase significant amounts of capacity during a time when it already has determined that there is no need over its 10-year planning horizon. 14. Without Commission intervention, there will be a significant unnecessary financial obligation to the Company s customers. The Company believes the roughly 300 MW af

22 of solar projects in the interconnection queue are being developed to establish PURPA contracts for the next 20 years. If the Company does not have a capacity need, but is required to sign 300 MWs of PURPA-based solar contracts that are compensated at $140,505/ZRC-yr, the Company s customers will be obligated to pay approximately $26 million annually. This annual expense would burden the Company s customers with up to $519 million of added expense over the next 20 years for a commodity that is unnecessary. 15. Requiring the Company to obtain Commission approval of a 10-year capacity position will also have the potential to diminish the Integrated Resource Planning ( IRP ) process. The Commission Staff s proposed IRP filing requirements require the Company to file its IRP by June 15, See MPSC Case No. U-18461, October 11, 2017 Order, Attachment A, page 2. The IRP proceeding will review the Company s capacity need. By requiring the Company to obtain a separate Commission order approving the Company s capacity position over the next 10 years before the Company can offer PURPA capacity prices on the MISO PRA rate, the entire IRP process may be irrelevant as up to approximately 300 MWs of unneeded capacity could be added to the Company s supply portfolio. Furthermore, the characteristics of PURPA solar generating facilities result in additional focus on the capacity value that is provided, without consideration of its energy production. In the IRP, the Company s modeling would determine the most appropriate resources to provide both energy and capacity needs. Adding 300 MWs of solar capacity does not take into consideration the energy value of the most reasonable generating resource that would have been selected in an IRP to serve the same 300 MW of demand. 16. Granting of the Company s requested relief in this Petition for Rehearing would allow the Commission the opportunity for a meaningful review of the Company s capacity position in the Company s 2018 IRP filing. At the outcome of that proceeding, the Commission af

23 would have the ability to determine the Company s capacity need and how much capacity the Company is required to purchase before the Company s avoided capacity cost is reset to the MISO PRA price. Thus, the Commission should permit the Company to begin offering PURPA contracts at the MISO PRA rate immediately after filing the 10-year capacity demonstration, which is consistent with the MPSC s May 31, 2017 Order. If sworn as a witness, I would testify as set forth above. Subscribed and sworn to before me this 20th day of December, Keith G. Troyer Melissa K. Harris, Notary Public State of Michigan, County of Jackson My Commission Expires: 06/11/20 Acting in the County of Jackson af

24 APPENDIX

25 Attachment 1 Page 1 of 3 Proxy Plant Inputs Natural Gas Combustion Turbine Natural Gas Combined Cycle Input Source Input Source Discount Rate 7.55% A-40 Discount Rate 7.55% S-16 Fixed Charge Rate 12.33% A-40 Fixed Charge Rate 12.37% A-16 Winter NDC 210 A-40 Capacity 1062 A-16 Summer NDC 186 A-40 Heat Rate Btu/kWh 6600 S-16 Zonal Resource Credits 175 A-40 Capital Costs (2017 $K) A-16 Operating Life (Yrs) 30 A-40 Capital Costs ($/KW) A-16 Capital Costs (2017 $K) A-40 Fixed O&M (Annual $K) 9,780 A-16 Capital Costs ($/KW) A-40 $/MW-yr $145,173 A-16 Fixed O&M (Annual $K) $3,030 A-40 $/ZRC-yr $161,560 A-16 $/MW-yr $117,203 A-40 Fixed ICE $5.17 Calculated $/ZRC-yr $140,505 A-40

26 Attachment 1 Page 2 of 3 Option 2: Forecasted Locational Marginal Prices A B C D E F G H Year Annual On- Peak Average LMP + Fixed Ice and Line Loss Factor Less $1 Administrative Fee ($/MWh) Levelized LMP + Fixed Ice and Line Loss Factor Less $1 Administrative Fee ($/MWh)* Year LMP + Fixed Ice Annual Off- and Line Loss Peak Factor Less $1 Average Administrative Fee ($/MWh) Levelized LMP + Fixed Ice and Line Loss Factor Less $1 Administrative Fee ($/MWh)* 2017 $34.89 $ $27.74 $ $32.49 $ $27.30 $ $32.14 $ $27.43 $ $33.31 $ $28.18 $ /5 Year $34.55 $42.20 $ /5 Year $29.11 $36.63 $ $36.26 $ $30.19 $ $37.19 $ $31.03 $ $38.97 $ $32.86 $ $40.15 $ $34.07 $ /10 Year $41.19 $49.00 $ /10 Year $34.99 $42.65 $ $43.04 $ $36.33 $ $44.76 $ $37.63 $ $46.45 $ $38.98 $ $48.48 $ $40.42 $ /15 Year $49.78 $57.79 $ /15 Year $41.76 $49.58 $ $51.15 $ $43.05 $ $52.65 $ $44.34 $ $54.79 $ $45.99 $ $55.93 $ $47.17 $ /20 Year $57.66 $65.86 $ /20 Year $48.48 $56.46 $41.25 Source A-46 DISCOUNT RATE 7.55% Fixed Ice $7.65 Line Loss Factor 2.37% *Only applicable to run-of-river hydro facilities.

27 Attachment 1 Page 3 of 3 A B C D E F G H I Year Natural Gas Price Forecast Start-Up Fuel NGCC Plant Heat Rate Option 3: Proxy Pant Variable Price Forecast Variable O & M Base Energy Price Base Energy Price Plus Fixed Ice Energy Payment + ICE and Line Loss Factor Less $1 Administrative Fee Levelized Energy Payment + ICE and Line Loss Factor Less $1 Administrative Charge* Col (B+C)*D/1,000+( E*1000) Col F + ICE Col G * Line Loss -1 Col H Levelized Source ELP-17 A-45 A-45 $ $ per $ per MMBtu MMBtu Btu/kWh $ per kwh $ per MWh $ per Mwh $ per Mwh $ per Mwh 2017 $3.50 $0.10 6, $26.01 $33.66 $ $3.83 $0.10 6, $28.25 $35.90 $ $4.21 $0.09 6, $30.79 $38.44 $ $4.69 $0.09 6, $33.98 $41.63 $ $4.91 $0.09 6, $35.49 $43.14 $43.16 $ $5.01 $0.09 6, $36.26 $43.91 $ $5.18 $0.10 6, $37.52 $45.17 $ $5.45 $0.11 6, $39.41 $47.06 $ $5.72 $0.11 6, $41.29 $48.94 $ $6.02 $0.12 6, $43.34 $50.99 $51.20 $ $6.41 $0.13 6, $46.07 $53.72 $ $6.82 $0.14 6, $48.92 $56.57 $ $7.15 $0.15 6, $51.25 $58.90 $ $7.40 $0.15 6, $52.92 $60.57 $ $7.60 $0.16 6, $54.40 $62.05 $62.52 $ $7.78 $0.17 6, $55.74 $63.39 $ $7.86 $0.17 6, $56.33 $63.98 $ $8.11 $0.17 6, $58.06 $65.71 $ $8.56 $0.18 6, $61.16 $68.81 $ $8.74 $0.19 6, $62.47 $70.12 $70.78 $48.31 *Only applicable to run-of-river hydro facilities.

28 Attachment 2 M.P.S.C. No Electric Consumers Energy Company Sheet No. C C18. STANDARD OFFER PURCHASED POWER A. Availability (Continued From Sheet No. C-58.00) The Standard Offer is available for the purchase of electrical energy and capacity, as needed, supplied by a seller s eligible Public Utility Regulatory Policies Act of 1978 ( PURPA ) Qualifying Facility. The Qualifying Facility must meet the requirements established by the Federal Energy Regulatory Commission including but not limited to, 18 C.F.R , , and The Standard Offer is not available for electric service supplied by the Company to a seller who has negotiated rate credits or conditions with the Company which are different from those below. To qualify for the Standard Offer, a seller shall execute a standard Power Purchase Agreement with the Company. The participating seller is required to install and operate a generation system with design capacity of no less than 1 kw and no more than 2 MWac. Service hereunder shall be restricted to the Company s purchase of energy or energy and capacity from the seller s generating facilities up to the Contract Capacity specified in the Power Purchase Agreement which may be operated in parallel with the Company s system. Power delivered to the Company shall not offset or be substituted for power contracted for, or which may be contracted for, under any other schedule of the Company. If a seller requires supplemental, back-up, or standby services, the seller shall enter into a separate service agreement with the Company in accordance with the Company's applicable electric rates and Service Regulations approved by the Michigan Public Service Commission. B. Distribution Requirements for Sellers Connected to Company System (1) All facilities operated in parallel with the Company s system must meet the Parallel Operation Requirements set forth in Rule C1.6 B. The Company shall install own, operate, and maintain all metering and auxiliary devices (including any telecommunication links, if applicable) connected to the Company System. Meters furnished, installed, and maintained by the Company shall meter generation equipment. (2) Energy delivered to the Company shall be alternating current, 60-hertz, single-phase or three-phase (as governed by Rule B8. Electric Interconnection and Net Metering Standards) service. The Company will determine the particular nature of the voltage in each case. (3) If the seller s generating facility is connected to a distribution line serving other Company customers, then the point of delivery for energy measurement purposes shall be at the high voltage side of the generating facility s isolation transformer connecting the seller s generating facility to the Company s distribution system. If the seller s generating facility is not connected to a distribution line serving other Company customers, then the point of delivery for energy measurement purposes shall be at the point at which the radial line connecting the seller s generating facility to the Company s distribution system terminates at the first substation beyond the generating facility s isolation transformer. (4) Hourly Interval Registering Meters are required for each generating unit served under this rate. For a seller in which the measurement of energy delivered to the Company is not located at the point of delivery, then electric losses as determined by the Company for losses between the energy measurement location and the point of delivery shall be deducted for billing purposes from the energy measurements thus made. (Continued on Sheet No. C-60.00) Corrections Reflect a Fixed ICE of $7.65/MWh