A CMS Energy Company November, 0 Ms. Kavita Kale Executive Secretary Michigan Public Service Commission 0 West Saginaw Highway Post Office Box 0 Lansing, MI 0 General Offices: LEGAL DEPARTMENT One Energy Plaza Jackson, MI 0 Tel: Fax: () -00 () - CATHERINE M REYNOLDS Senior Vice President and General Counsel *Washington Office: 0 Rhode Island Ave. N.W. Tel: (0) -0 MELISSA M GLEESPEN Suite 00 Vice President, Corporate Washington, DC 00 Fax: (0) - Secretary and Chief Compliance Officer Writer s Direct Dial Number: () - Writer s E-mail Address: anne.uitvlugt@cmsenergy.com SHAUN M JOHNSON Vice President and Deputy General Counsel 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 Robert A. Farr 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 James D W Roush Scott J Sinkwitts Adam C Smith Janae M Thayer Bret A Totoraitis Anne M Uitvlugt Attorney RE: Case No. U-00 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, USC 0 et seq. Dear Ms. Kale: Included in this electronic file in the above-captioned case is the Rebuttal Testimony and Exhibits of Consumers Energy Company witnesses Natalie N. Busack, Mark T. Devereaux, Srikanth Maddipati, Dwayne C. Parker, Priya D. Thyagarajan, and Keith G. Troyer. 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 Parties per Attachment to the Proof of Service fl--
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-00 comply with the Public Utilities Regulatory Policy ) Act of, USC 0 et seq. ) ) OF NATALIE N. BUSACK ON BEHALF OF CONSUMERS ENERGY COMPANY November 0
NATALIE N. BUSACK 0 Q. Please state your name and business address. A. My name is Natalie N. Busack. My business address is One Energy Plaza, Jackson, Michigan 0. Q. Are you the same Natalie N. Busack who previously prepared and filed testimony in this case? A. Yes. Q. What is the purpose of your rebuttal testimony? A. The purpose is to update the proposed Standard Offer Tariff to reflect the rebuttal testimony presented by Consumers Energy Company s ( Consumers Energy or the Company ) witnesses Mark T. Devereaux, Priya D. Thyagarajan, and Dwayne C. Parker. Q. Are you sponsoring any exhibits in connection with your rebuttal testimony? A. Yes. I am sponsoring the following exhibit: Exhibit A- (NNB-) Revised Standard Offer Tariff Purchased Power. 0 Q. Was this exhibit prepared by you or under your direction and supervision? A. Yes. Q. Please summarize the updates to the Standard Offer Tariff. A. The updates made to the Standard Offer include: (i) increasing the size limitation for a Qualifying Facility; (ii) removing the language identified in discovery response U-00-ELPC-CE- that was not applicable to the Standard Offer; (iii) updating the capacity and energy pricing; (iv) adding language to waive the system access fee if more than one meter is not required; (v) updating the term lengths of the contracts; (vi) adding minor wording changes proposed by Staff witness Julie K. Baldwin; (vii) removing the rte--nnb
NATALIE N. BUSACK 0 reference to the seller s generation net of any energy delivered to the seller when calculating the seller s energy; (viii) removing the Market Settlement Fee; and (ix) adding the line loss proposal as described by Company witness Parker. Q. Please explain why the Company removed the reference to the seller s generation net of any energy delivered when calculating the seller s energy. A. It has been determined after fully vetting this language that it does not apply to the Standard Offer tariff. Service taken in standby is netted against generation on the interval and would not be netted on a monthly basis. Q. Does this conclude your testimony? A. Yes. rte--nnb
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-00 comply with the Public Utilities Regulatory Policy ) Act of, USC 0 et seq. ) ) EXHIBIT OF NATALIE N. BUSACK ON BEHALF OF CONSUMERS ENERGY COMPANY November 0
Case No.: U-00 Exhibit: A- (NNB-) Witness: NNBusack Date: November 0 Page: of M.P.S.C. No. - Electric Consumers Energy Company Sheet No. C-.00 (Continued From Sheet No. C-.00) C. STANDARD OFFER PURCHASED POWER A. Availability 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 ( PURPA ) Qualifying Facility. The Qualifying Facility must meet the requirements established by the Federal Energy Regulatory Commission including but not limited to, C.F.R..0,.0, and.0. 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 an eligible generation system with design capacity of no less than kw and no more than 00 kw.mw. Any seller connecting to the Company s system is required to install and operate an eligible generation system that when combined with all other seller owned generation systems serving the seller's premises meets the eligibility criteria for net metering in Rule B of this Electric Rate Book, Electric Interconnection and Net Metering Standards, R 0.0. 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 () All facilities operated in parallel with the Company s system must meet the Parallel Operation Requirements set forth in Rule C. 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. () Energy delivered to the Company shall be alternating current, 0-hertz, single-phase or three-phase (as governed by Rule B. Electric Interconnection and Net Metering Standards) service. The Company will determine the particular nature of the voltage in each case. () 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. () 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 adjusted for billing purposes from the energy measurements thus made. (Continued on Sheet No. C-0.00)
Case No.: U-00 Exhibit: A- (NNB-) Witness: NNBusack Date: November 0 Page: of M.P.S.C. No. - Electric Consumers Energy Company Sheet No. C-0.00 (Continued From Sheet No. C-.00) C. STANDARD OFFER - PURCHASED POWER (Contd) B. Distribution Requirements for Sellers Connected to Company System (Contd) () The seller must meet the Interconnection Standards referenced in Rule B of this Electric Rate Book, Electric Interconnection and Net Metering Standards, R 0. - R 0., for the class of generator installed. Per these standards, testing and utility approval of the interconnection and execution of a parallel operating agreement must be completed prior to the equipment operating in parallel with the distribution system of the utility. Additionally, the Company will confirm and ensure that an eligible electric generator installation at the seller's site meets the IEEE anti-islanding requirements. () The seller is required to obtain the characteristics of service from the Company prior to the installation of equipment. The Company shall provide the characteristics in writing upon request. In the event that the equipment proposed for connection is not compatible with these characteristics, the Company shall have no obligation to modify its distribution system or provide any monetary compensation to the seller. Any service facilities shall be dedicated to the generator and shall not be shared with those providing service to any seller. The Company shall determine the characteristics of service. Should the installation of new Company distribution facilities be necessary for the equipment, all costs for the distribution facilities installed may be charged to the applicant in advance of construction as a nonrefundable contribution. If the applicant desires underground service facilities, the difference in cost between overhead and underground service facilities shall be charged to the applicant in advance of construction as a nonrefundable contribution. () If, in the sole judgment of the Company, it appears that connection of the equipment and subsequent service through the Company's facilities may cause a safety hazard, endanger the Company facilities or the seller's equipment or to disturb the Company's service to customers and other sellers, the Company may refuse or delay connection of the equipment to its facilities. A seller taking the Standard Offer is not eligible to participate in the Company s Net Metering program. Sellers with unsatisfactory payment history on their delivery account are not eligible to participate. () The Company may discontinue purchases during system emergencies, maintenance and other operational circumstances. C. Published Avoided Cost Rates The capacity rate and cost of production energy rates caps applicable to the Standard Offer will be updated every two years based on the Company s need for capacity and the Company s avoided cost data reported to the Michigan Public Service Commission. Power Purchase Agreements with terms in excess of two years shall continue to receive the capacity rate and any applicable cost of production energy rate cap as provided in the Power Purchase Agreement. D. Monthly Rate System Access Charge - Equal to the System Access Charge of the Customer's Delivery Account but not in excess of $0, assessed per generator meter, to be paid to the Company by the customer or to be deducted from the payment to the customer by the Company. If both the generation delivered to the Company and energy delivered to the Customer can be measured with a single meter, the System Access Charge will be waived under this schedule. Energy For all energy supplied by the seller, the seller shall receive an energy payment equal to (i) the lesser of the actual Midcontinent Independent System Operator, Inc. s ( MISO s ) real-time Locational Marginal Price ( LMP ) at the Company s load node (designated at CONS.CETR as of the date of this Rate Schedule) or the actual variable costs of operating the proxy plant; or (ii) the lesser of the forecasted LMP or the forecasted variable cost of operating the proxy plant, as indicated in the table below for the year that the contract was executed, to the lower of the cost of production associated with the avoided cost capacity resource, if applicable, and the MISO Real-Time Locational Marginal Price (LMP) (as expressed in units of $/kwh) for the Company's load node (designated as "CONS.CETR" as of the date of this Rate Schedule) multiplied by the seller s generation net of any energy delivered to the seller (kwh), less the Market Settlement Fee of $0.00/kWh and Administrative Fee of $0.00/kWh. (Continued on Sheet No. C-.00)
Case No.: U-00 Exhibit: A- (NNB-) Witness: NNBusack Date: November 0 Page: of M.P.S.C. No. - Electric Consumers Energy Company Sheet No. C-.00 (Continued From Sheet No. C-0.00) C. STANDARD OFFER - PURCHASED POWER (Contd) D. Monthly Rate (Contd) Energy (Contd) - Line losses of.% shall be added to the metered energy supplied by the seller as adjusted in accordance with B() to reflect avoided line losses on the Company s distribution system. This value will be revised when line losses are updated in general electric rate cases, as approved by the Commission Capacity If at the time of contracting or the end of year five the Company requires capacity, the seller shall receive a monthly capacity payment based on and the units of capacity that the MISO determines the seller s Qualifying Facility can supply for the applicable MISO established resource planning period multiplied by the applicable equal to the proxy capacity rate as indicated below obtained under Section C of this rate schedule as expressed in such units of capacity. If at the time of contracting, the Company does not forecast required additional capacity in the next five years then the capacity payment will reflect the capacity price derived from MISO s annual planning resource auction. All capacity payments are based on the units of capacity that the MISO determines the seller s Qualifying Facility can supply for the applicable MISO established resource planning period. The current resource planning period is the planning year which runs from June st of each year through May st of the following year. Contract Execution Date Capacity Rate ($/ZRC-Day) Energy Rate ($/kwh) 0 $.0 $ 0.0 0 $. $ 0.0 0 $. $ 0.0 00 $. $ 0.00 0 $ 00.0 $ 0.00 0 $ 0. $ 0.0 0 $ 0. $ 0.000 0 $ 0. $ 0.0 0 $ 0.0 $ 0.0 0 $ 0.0 $ 0.00 Payments shall be reduced by any applicable monthly Interconnection Cost. E. Term The initial minimum term is years during which the seller agrees to fixed energy rates based on forecasted energy prices for the duration of the contract. The seller may select a contract term of 0 years during which the seller agrees to the lower of LMP or actual variable costs for operating a proxy plant or updated forecasted energy prices at the end of year of the 0 year contract term that will apply for the remainder of the contract term.. The seller may select any contract term length up to a maximum of years, but In no event shall the term of any Power Purchase Agreement expire prior to the end of a MISO planning period.
F. Early Termination Case No.: U-00 Exhibit: A- (NNB-) Witness: NNBusack Date: November 0 Page: of In the event that seller s Qualifying Facility ceases operations prior to the end of the term of the Power Purchase Agreement and the Company must replace the capacity supplied by seller in accordance with MISO s requirements, then seller shall reimburse the Company for the positive difference, if any, between the cost incurred by the Company to replace seller s capacity and the cost the Company would have incurred to purchase such capacity from the seller under the Power Purchase Agreement ( Replacement Cost ). Any amounts due seller at the time operations cease shall be held until such time that Replacement Cost is determined and the net amount owed shall be paid by the party that owes it within 0 days after Replacement Cost is determined. The Company shall have no obligation to enter a subsequent Power Purchase Agreement with the seller until such time that any amounts due the Company pursuant to this paragraph are paid.
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-00 comply with the Public Utilities Regulatory Policy ) Act of, USC 0 et seq. ) ) OF MARK T. DEVEREAUX ON BEHALF OF CONSUMERS ENERGY COMPANY November 0
MARK T. DEVEREAUX 0 0 Q. Please state your name and business address. A. My name is Mark T. Devereaux and my business address is West Parnall Road, Jackson, Michigan 0. Q. By whom are you employed and in what capacity? A. I am employed by Consumers Energy Company ( Consumers Energy or the Company ) as Principal Financial Analyst in the Electric Transactions and Wholesale Settlements section of the Energy Supply Operations Department. Q. Are you the same person named Mark T. Devereaux who provided direct testimony in this proceeding? A. Yes. PURPOSE OF TESTIMONY Q. What is the purpose of your rebuttal testimony? A. The purpose of my testimony is to rebut portions of the direct testimonies of Michigan Public Commission ( MPSC or the Commission ) Staff ( Staff ) witnesses Julie K. Baldwin and Jesse J. Harlow; Independent Power Producers Coalition of Michigan ( IPPC ) witnesses Kenneth Rose, Thomas V. Vine, Nelson P. Turcotte, Lee W. Mueller, and Darwin J. Baas; Great Lakes Renewable Energy Association ( GLREA ) witness Geoffrey C. Crandall; and Environmental Law and Policy Center, Ecology Center, Solar Energy Industries Association, and Vote Solar (collectively ELPC ) witnesses Karl R. Rábago and Douglas B. Jester. Q. Are you sponsoring any exhibits with your rebuttal testimony? A. Yes, I am sponsoring: Exhibit A- (MTD-) Consumers Energy Company Impact of Dispatchability on Value of Energy. rte--mtd
MARK T. DEVEREAUX 0 0 Q. Was this exhibit prepared by you or under your direction and supervision? A. Yes. I. Response to Staff Q. The direct testimony presented by Staff witnesses Baldwin and Harlow generally opposed the Company s proposed tiered avoided cost methodology. Specifically, at page of his direct testimony, Mr. Harlow states that Staff does not support the Company s [avoided cost methodology] proposal. Do you agree with Staff s opposition to the Company s proposals? A. The Company maintains that its tiered avoided cost methodology is the most reasonable method for determining the Company s true avoided costs as it represents the actual capacity sources that the Company would pursue when the Company has a capacity need. For the reasons discussed in my direct testimony and below, Staff s proposed avoided cost methodology does not represent the Company s actual avoided costs and also creates an unsupportable mismatch between the way that Qualifying Facilities ( QF ) would be compensated for energy and capacity. Notwithstanding, for the purpose of reaching a compromise in this case, the Company proposes to revise its originally-filed proposed methodology to align more closely with Staff s proposal. In order to more closely align the Company s proposal with Staff s position, modifications must be made to calculate a more reasonable representation of the Company s avoided costs and, to the extent possible within the structure of Staff s proposal, ensure that the Company s customers are protected from paying higher costs than what the Company could actually purchase capacity and energy for. As further addressed by Company witness Priya D. Thyagarajan, the Company s proposed modifications to Staff s proposal are as follows: rte--mtd
MARK T. DEVEREAUX 0 0 0 0 If there is a need for capacity within the first five years of the Company s ten-year planning horizon, QFs should be paid for capacity at the levelized cost of a Natural Gas Combined Cycle ( NGCC ) facility (note that since the fixed costs of an NGCC are being used the Investment Cost attributable to Energy ( ICE ) payment is not applicable). Otherwise, QFs should be paid for capacity at the capacity cost established by the Midcontinent Independent System Operator ( MISO ) in its annual Planning Resource Auction ( PRA ). In either event, MISO s Zonal Resource Credit ( ZRC ) capacity structure should determine the amount of capacity purchased and capacity pricing should be ZRC-based since this is how the Company is assigned capacity credit from MISO. This applies to both QFs under the Standard Offer tariff and to QFs not under the Standard Offer tariff; Whether capacity is needed or not, QFs should be paid for energy at (i) the lower of forecasted Locational Marginal Pricing ( LMP ) or the forecasted energy cost of an NGCC or (ii) the lower of LMP or the actual variable energy costs of an NGCC. This applies to both QFs under the Standard Offer tariff and to QFs not under the Standard Offer tariff. These costs should not be levelized over the term of the contract, but rather paid based on Exhibit A- (PDT-0) provided in Company witness Thyagarajan s rebuttal testimony and supporting exhibit; The term lengths of contracts should be five years if a QF elects to be paid on the basis of forecasted energy prices for the term of the contract. Otherwise, a ten-year contract could be available for QFs choosing actual energy pricing and for QFs that prefer forecasted energy pricing and who are willing to accept an updated forecast of such pricing at the end of year five. If a ten-year contract began with MISO PRA based pricing for capacity and the Company showed a need for capacity during the first five years of its ten-year planning horizon at the time of the energy price update, then the capacity price under the contract can change to the NGCC capacity rate. Furthermore, if the Commission were to approve QF contracts longer than ten years, which the Company does not agree with, the Company still maintains that those contracts using forecasted energy pricing should have an update to energy pricing at the end of every five-year period. All of the aforementioned contract term length conditions would apply to both QFs under the Standard Offer tariff and to QFs not under the Standard Offer tariff; and The Company will pay for other avoided costs such as transmission costs, line loss mitigation, hedging value, avoided emissions, and environmental compliance costs to the extent that such costs can be directly quantified and actual costs can be directly calculated (i.e., not theoretical or merely possible). The reverse is also true in that if QF power results in increased transmission costs, line losses, hedging costs, emission costs, and environmental compliance costs to the extent that such costs can be directly quantified and actual costs can be directly calculated (i.e., not theoretical or merely possible) to customers, the QF should reimburse customers for such costs. The rte--mtd
MARK T. DEVEREAUX 0 0 payment for such costs should not be based on a per-unit of capacity or on per-unit of energy unless such costs are actually incurred on such a basis. This applies to both QFs under the Standard Offer tariff and to QFs not under the Standard Offer tariff; however, the applicability to QFs under the Standard Offer tariff is limited of the ability of that portion of the criteria above that can be standardized. Notwithstanding the foregoing, with respect to line loss mitigation and the Standard Offer tariff, the Company is willing to agree to a line loss credit to QFs of.%, which is consistent with the Company s approach for its Solar Gardens program, as long as the limit of applicability under the Standard Offer tariff is. MW or lower as discussed below. With the above-discussed modifications, the Company supports Staff s proposed approach to calculating avoided costs. If these modifications to Staff s position are not accepted, the Commission should reject Staff s proposal because it would result in an unreasonable and inaccurate calculation of the Company s avoided costs. Furthermore, the Commission should reject Staff s calculations of the Company s avoided costs for reasons described in the rebuttal testimony of Ms. Thyagarajan. Staff Witness Baldwin Q. Ms. Baldwin recommends that the Commission review the Company s avoided cost and Standard Offer tariff on a biennial basis. Do you agree with this recommendation? A. Yes. Q. Ms. Baldwin further recommends that the Commission consider the capacity needs of the Company during each biennial cost update filing to set a Standard Offer tariff size cap in the range of to MW. Do you agree with this recommendation? A. To base the cap on the Company s need is generally reasonable; however, the Standard Offer tariff range extends to developers who have significant experience and resources that do not need to have their contracting facilitated through a Standard Offer tariff and who are of a size that tends to have contracting needs that are not capable of being standardized (e.g., special metering arrangements, ability to relocate, etc.). rte--mtd
MARK T. DEVEREAUX 0 0 Q. Please explain. A. Granger Electric Company and its affiliates ( Granger ), for example, have five contracts with the Company ranging in size from kw to. MW. All of these facilities could qualify for the Standard Offer tariff under certain circumstances under Ms. Baldwin s recommendation, but Granger has significant experience and resources, with generating facilities located around the country (e.g., Michigan, Ohio, Pennsylvania, Alabama, and Utah) and customers other than Consumers Energy even in Michigan. Similarly, North American Natural Resources, Inc. ( NANR ) has four contracts with the Company which would qualify for the Standard Offer tariff under certain circumstances under the Staff s recommendation, but NANR, too, has other generating facilities and other customers in Michigan besides Consumers Energy and one generating facility in Kentucky. The Company has two contracts each with WM Renewable Energy and C&C Energy that would qualify for the Standard Offer tariff under certain circumstances under the Staff s recommendation, and the parent company of both of these companies have a national (and to some extent, international) presence with respect to electric generating facilities. Thus, there are a number of companies with significant experience and resources involved with small projects that do not need their contracting facilitated through a Standard Offer tariff. In addition, the above contracts are all supplied by landfill gas-fueled facilities which have shown a need to relocate their facilities as landfill gas production wanes and for which special contract provisions are needed. Q. What would you recommend as an alternative to Ms. Baldwin s recommendation? A. The Company believes that its original recommendation of 00 kw as described in my direct testimony is reasonable; however, in the interest of reaching a compromise for the rte--mtd
MARK T. DEVEREAUX 0 0 purpose of this case, the Company recommends up to a. MW Standard Offer tariff size cap. A size cap of. MW should be large enough to capture all of the smaller developers that lack the resources and experience of developers like Granger, NANR, C&C Energy, and WM Renewable Energy, and yet small enough to exclude most of these more sophisticated developers. Q. Ms. Baldwin recommends that the Standard Offer tariff capacity rate be set at the MISO PRA if the Company s ten-year planning horizon capacity becomes full before its next biennial Public Utility Regulatory Policies Act of ( PURPA ) avoided cost case. Do you agree with this recommendation? A. The Company is not certain what is meant by 0-year planning horizon capacity becomes full, as described by Ms. Baldwin. Nevertheless, the Company would be agreeable to a framework that sets the Standard Offer tariff capacity rate equal to the MISO PRA if at the time a QF takes service under the Standard Offer tariff the Company s most current ten-year capacity forecast did not show any capacity needs during the first five years of that forecast period. Q. Ms. Baldwin recommends that QFs taking service under the Standard Offer tariff be given the option to select -, 0-, or -year terms. Do you agree with this recommendation? A. Not entirely. Ms. Baldwin bases her recommendation on four factors: (i) the term lengths of the Company s 00 Public Act ( Act ) based contracts; (ii) the uncertainty of continued capacity purchases after a five-year contract expires; (iii) the length of the Company s existing PURPA contracts; and (iv) traditional utility cost recovery based on the expected life of a generation project. I will address why the first, rte--mtd
MARK T. DEVEREAUX 0 0 third, and fourth underlying reasons for her recommendation do not justify her recommendation and then I will address the second of her underlying reasons last. The first of Ms. Baldwin s underlying reasons is the term lengths of the Company s Act based contracts. The term lengths of these contracts are not relevant for the purposes of determining a necessary term length since the Company had a long-term need for Renewable Energy Credits ( RECs ) and hence sought longer-term contracts to fulfill that need. It is unknown what term lengths could have been negotiated if long-term contracts were not needed. The third of Ms. Baldwin s underlying reasons is that existing PURPA contracts have terms that are longer than five years. The term lengths of these contracts are also not relevant for a similar reason since the Company had significant, long-term needs when these contracts were entered into and did not seek shorter-term agreements. The fourth of Ms. Baldwin s underlying reasons is that a five-year contract term is inconsistent with traditional utility cost recovery based on the expected life of a generation project. This reason is also not relevant since PURPA avoided costs are not based upon utility cost recovery or a utility s existing sources of generation. Rather, avoided costs are to be based on the future or incremental costs which the utility avoids by purchasing electricity from a QF. The forward-looking approach to setting avoided costs was acknowledged at pages and of Staff witness Kevin S. Krause s direct testimony which explained that the Federal Energy Regulatory Commission ( FERC ) accepted methods of determining avoided costs look at the different types of increments: the next plant, the next peaker plant, the incremental revenue requirement rte--mtd
MARK T. DEVEREAUX 0 0 The second of Ms. Baldwin s underlying reasons for her recommendation is the uncertainty of continued capacity purchases after a five-year contract expires. If a QF elects to be paid on the basis of forecasted energy prices for the term of the contract, then the Company believes that such contracts must be limited to five years to protect customers from potential significant deviations from actual energy costs. Otherwise, a ten-year contract should be available for QFs choosing actual energy pricing and for QFs that prefer forecasted energy pricing and who are willing to accept an updated forecast of such pricing at the end of year five. In summary, the Company would support Ms. Baldwin s recommendation if it were modified to be consistent with the discussion above. Q. Ms. Baldwin proposes that the Company receive all the RECs associated with energy produced by QFs under the Standard Offer tariff. Do you agree with this proposal? A. Yes. Q. Ms. Baldwin recommends that the Company request ex parte processing when filing contracts based on the Standard Offer tariff for Commission approval. Do you agree with that recommendation? A. Yes. Staff Witness Harlow Q. Mr. Harlow states that the Company s proposal has tiers that are based on MISO s PRA and that using the PRA undervalues the capacity of a QF. Do you agree with this statement? A. No. First, Mr. Harlow erroneously suggests that all of the tiers in the Company s initially proposed avoided cost methodology are based on the PRA. This is simply not the case. rte--mtd
MARK T. DEVEREAUX 0 0 The Company s proposal only has one tier that is based on the PRA. Tier is based on a circumstance where the Company has no capacity need and Tiers and are based on the various generation technologies which the Company would use to address larger capacity needs. Second, Mr. Harlow does not explain how the use of the PRA undervalues QF capacity. Under the Company s initially proposed methodology, the value of a QF s capacity is determined by the cost of capacity that the Company would avoid by purchasing the QF s capacity. If the Company s long-term load and capacity situation is such that it is short of capacity, but that the economics do not justify building new generation facilities, then the PRA represents exactly the value of the QF s capacity since the PRA is where the Company will go to purchase the shortfall. The Company s tiered approach was intended to simplify the issue of determining the most economic means of filling capacity needs by establishing ZRC ranges of capacity shortfall that would likely justify the cost of the capacity resource assigned to each range. As a result, QF capacity would receive the value it should receive depending on the amount of capacity that the Company needs. Q. Mr. Harlow states that the Company s method discriminates against QFs in Tiers and because the compensation in these tiers is inconsistent with the way the Company recovers costs for its own generation plants. Do you agree with this statement? A. No. The Company s method is based on the principal that it would not build a generation plant if its need for capacity falls within the ZRC ranges of Tiers and. Tier represents the situation where the Company does not need capacity at all and Tier represents the situation where the Company has a small capacity need for which the rte--mtd
MARK T. DEVEREAUX 0 0 building of a generation plant cannot be justified. What the Company proposed as compensation to QFs under Tier and conditions is exactly how the Company recovers the costs it incurs to obtain capacity under these conditions. Moreover, the way the Company recovers costs from its own generating units has nothing to do with its incremental avoided cost at issue in this case. Q. Mr. Harlow implies on page of his direct testimony that avoided costs should not be based on the PRA because the PRA does not function as a true market as it will likely never produce price signals that prompt capacity build-outs. Do you agree with this implication? A. No. While much of what Mr. Harlow says about the PRA is correct, his characterization of the Company s tiered proposal and his conclusion are incorrect. The Company s tiered proposal does not employ the PRA to fill large capacity needs. Tiers and are designed specifically to address large capacity needs and neither uses the PRA. Moreover, it is irrelevant as to whether or not the PRA functions as a true market or whether or not it produces price signals that prompt capacity build-outs. In developing the Company s avoided costs, the primary consideration should be whether the Company would actually purchase capacity from the PRA under a Tier condition, and the Company s position is that yes, it would. Therefore, in this condition, purchasing from the PRA would be a purchase at the Company s true avoided cost. Q. Mr. Harlow states that Staff s proposed method agrees with the Company s ZRC capacity structure. Do you agree with this statement? A. No. Staff s proposed method is not consistent with MISO s ZRC capacity structure. Mr. Harlow references Effective Load Carrying Capability ( ELCC ) and an rte--mtd 0
MARK T. DEVEREAUX 0 0 approximate % capacity credit for wind and a 0% capacity credit for solar, but these factors do not tell the entire story. As stated on page 0 of my direct testimony, MISO s ZRC capacity structure does not use ELCC exclusively nor does it use the percentages Mr. Harlow quotes for the life of such resources. For example, MISO does not use ELCC at all for landfill gas facilities, anaerobic digester facilities, or wood waste fueled facilities. For these facilities, MISO applies a historical forced outage rate ( XEFORd ) against an annual capacity test to determine the facilities ZRCs. The wind and solar percentages, while updated by MISO annually, only apply to the nameplate capacity of new facilities that do not have any operating history. Once an operating history is obtained, the ZRCs awarded to wind and solar are based on actual energy production during peak periods. While Mr. Harlow asserts that the foregoing is consistent with Staff s proposal, he has not established that such is the case. By not using ZRCs to determine the Company s avoided costs, the Company would be unreasonably forced to purchase capacity that is not recognized by MISO in meeting the MISO reliability requirements. If all capacity purchased from QFs is not recognized by MISO, the Company and its customers could be forced to purchase additional capacity due to the QF providing less capacity in actuality than what was contracted for pursuant to avoided cost rates. To avoid this unreasonable result where customers pay capacity costs for capacity they do not get credit for, the Commission should use the ZRC capacity structure, as utilized by MISO, when determining the Company s avoided costs because this is the capacity structure that the Company, and its customers, must use to meet reliability requirements. rte--mtd
MARK T. DEVEREAUX 0 0 Q. On page of his direct testimony, Staff witness Harlow states that dispatchability (the ability to cycle a unit based on need) does not play a role in the energy price paid. The QF would only be paid for energy that is produced and delivered to the utility. Do you have concerns with Mr. Harlow s position? A. Yes. Mr. Harlow s position oversimplifies the issue. The Company s concern regarding dispatchability is related to the differences between when energy would be produced from the avoided plant compared to when energy is actually produced by the QF. If, in the absence of the QF, the Company would have constructed an NGCC, then the operating characteristics of that facility would be notably different from the operating characteristics of many of the QFs. First, an NGCC is designed to be cycled, meaning the facility can be shut down completely if market economics fail to provide sufficient customer value to justify energy generation. This means that in certain hours customers would pay zero variable costs associated with the facility and would purchase energy from the MISO energy market at a price that is less than the variable cost associated with the NGCC. Similarly, an NGCC is dispatchable once it is cycled on, meaning that the unit can move between 0% and 00% of its maximum capability, again, based on market economics. In this scenario, customers would again be purchasing energy from the MISO market at a price less than the variable cost of the NGCC. Paying for energy only when it is delivered, as stated in Mr. Harlow s position, fails to address the Company s primary concern of controlling when the energy is produced. Consider the simple example provided in Exhibit A- (MTD-). This example assumes the Company has an agreement with a 0 MW QF to which it pays the variable cost of an NGCC of $./MWh (Exhibit A- (PDT-), line, column (c)) for all energy produced and rte--mtd
MARK T. DEVEREAUX 0 0 delivered. Assume the 0 MW facility is non-dispatchable and therefore produces 0 MW in every hour of the day. If the LMPs from a typical day (June, 0 in this example) are considered, customers pay more for energy than they would if the Company constructed the avoided plant in of the hours, as indicated by the negative values found in column (g), lines through and lines and. All of the hours in which the QF provided positive value for customers would have been captured by the avoided plant as well, as evident in column (g), lines 0 through. Therefore, using the construct proposed by Staff results in customer costs increasing by $.00 over the costs expected if the Company had constructed and operated the avoided NGCC facility. That is over 0% of the total variable payment made to the QF in this example. By ignoring the time of delivery, it is impossible to ensure that customers are paying the true avoided cost for energy. This issue is further exacerbated by the use of levelized variable costs as proposed by Staff that are based on projected fuel and Operation and Maintenance ( O&M ) expenses. In some circumstances, this issue could result in customers paying more for energy from the QF than they would have if the Company had simply bought energy entirely from the MISO market. At the very least, these losses reduce the value of the energy produced from these facilities which makes it less likely that customers will recover the higher capacity payments proposed to be made to these facilities through the combination of the capacity payments and ICE payment as proposed by Staff. Thus, the dispatchability of the avoided unit as well as the dispatchability of the QF (and, to the extent the QF is not dispatchable) should be considered in any avoided cost proposal. Furthermore, any compensation method that relies on average payments for variable costs rte--mtd
MARK T. DEVEREAUX 0 0 is likely to aggravate this issue resulting in further deviation from the Company s true avoided cost. Q. Mr. Harlow states that the Company should compensate QFs for capacity utilizing Staff s proposed methodology if the Company shows any capacity need over the PURPA ten-year capacity planning horizon, up to the point that the projected capacity need is met. Once the need is met, the Company should apply to the Commission to have the capacity rate adjusted to be equivalent to the PRA. Do you agree with this statement? A. Not entirely. As I indicated in my direct testimony and in the discussion above, Staff s proposed methodology results in rates which are not equivalent to the costs that the Company is actually avoiding by purchasing from a QF. The Company would, however, support compensating QFs for capacity if the Company shows any capacity need during the first five years of its PURPA ten-year capacity planning horizon as discussed above in response to Staff. It does not make sense, for example, to make capacity payments beginning in year one if the Company does not need capacity until year nine or ten. A capacity need nine or ten years into the future may justify some preliminary activities (e.g., the securing of an air permit) in the early stages, but forecasts that far out may be fairly unpredictable and a more prudent approach would reserve material commitments until a point in time where the need becomes clearer and more certain. Staff s approach also assumes a more than five-year lead-time for plant construction which is unlikely. Moreover, if the capacity need is at a Tier level, there is no avoided plant-related benefits to be gained by advancing the payment that far forward. rte--mtd
MARK T. DEVEREAUX 0 0 Q. Mr. Harlow recommends that ownership and sale of RECs should be subject to negotiation between the Company and the QF. Do you agree? A. No. The Company continues to maintain the position that RECs are part of the value that the Company is purchasing from a QF and should be owned by the utility. Q. Mr. Harlow states that the ELCC is multiplied by the yearly capacity value to account for actual availability and is especially critical for determining the capacity value of intermittent resources such as solar and wind. Do you agree with this statement? A. No. Unless Mr. Harlow is using ELCC to also mean XEFORd, his statement does not make sense. MISO does not use ELCC in the manner suggested by Mr. Harlow. The capacity value (i.e., ZRCs) of a non-intermittent resource is determined by multiplying a resource s annual capacity test by the quantity -XEFORd. The capacity value of wind with an operating history is determined by multiplying the wind resource s nameplate capacity, the historical capacity factor of the wind resource during MISO s eight highest summer peaks for each summer of operation, and then the ELCC. The capacity value of solar with an operating history is determined by taking the average output of the solar resource between the hours of and p.m. during the months of June through August during a period of at least three years, so there is no multiplication by an ELCC in this case. Similarly, the capacity value of hydro with an operating history is determined by taking the median output of the hydro resource between the hours of and p.m. during the months of June through August during a period of at least three years, so again there is no multiplication by an ELCC in this case. rte--mtd
MARK T. DEVEREAUX 0 Q. Do you agree with Mr. Harlow s recommendation that MISO s ELCC ratios be applied to intermittent generator resources such as solar and wind? A. No, because of the confusion and potential misapplication of ELCC presented in his testimony. Q. What would you recommend with regard to the ELCC? A. MISO s ZRCs should be used in all instances, as they reflect ELCC or XEFORd as applicable and represent the capacity credit load serving entities can count toward meeting their Planning Reserve Margin Requirements and Local Clearing Requirements. Q. Do you agree with Mr. Harlow s suggested capacity and energy pricing methodology for payments to QFs? A. No. However, for reasons stated above in my rebuttal to Staff and the reasons in the rebuttal testimony of Company witness Thyagarajan rebutting Staff s proposal, the Company proposes to simplify the approach suggested by Mr. Harlow with a couple of modifications as detailed in my rebuttal of Ms. Baldwin. II. Response to IPPC 0 IPPC Witness Rose Q. Mr. Rose states that the Company s originally proposed tiered avoided cost methodology is faulty because it makes no distinction between QFs greater than 0 MW and those that do not have access to markets which are deemed to be those QFs at or less than 0 MW. Do you agree with this statement? A. No. The Company s originally proposed tiered avoided cost methodology would be appropriate for a QF of any size, so the distinction is irrelevant. Furthermore, although the Company s originally proposed tiered avoided cost methodology is applicable to QF rte--mtd
MARK T. DEVEREAUX 0 0 generators of all sizes, it should be noted that the FERC has relieved the Company of its obligation to purchase from QFs greater than 0 MW. Therefore, the Company had no reason to create an avoided cost methodology that would distinguish between generators above and below 0 MW since the Company is currently only obligated to purchase from generators below 0 MW. Q. Does access to markets by QFs have any bearing on the avoided costs to be paid to QFs? A. No. Access to markets is only relevant in determining whether a utility has a mandatory purchase obligation. Q. Do you agree with Mr. Rose s contention that if the Company were to supply NGCC capacity itself that the energy costs incurred would not just consist of the lesser of the actual LMP and the incremental cost of production of the NGCC, and Mr. Rose s contention that the Company s proposal does not include avoided O&M costs? A. No. Mr. Rose has failed to establish any evidence to the contrary of the Company s position. Mr. Rose s testimony appears to suggest that the Company s incremental cost of production consists solely of fuel cost. This assumption is incorrect. The Company s original proposal accounted for O&M costs. Fixed O&M costs were included in the avoided capacity payments proposed by the Company for the NGCC and NGCT. Variable O&M costs were reflected in the NGCC and NGCT variable energy payments, and would be included in the actual LMP, which represents the incremental variable cost (fuel and variable O&M) of purchasing the next unit of energy from the market. rte--mtd
MARK T. DEVEREAUX 0 0 Q. Do you agree with Mr. Rose s contention that the Company s avoided cost methodology is based solely on MISO s market pricing for energy and capacity and that by using the MISO capacity construct, the Company is proposing to have the QFs fill in the residual needs of the Company when capacity is needed? A. No. The Company has presented a methodology that incorporates both (i) market pricing for energy and capacity (Tier ) and (ii) actual generation facility build costs with accompanying energy costs (Tiers and ), as appropriate. The QFs would fill residual needs when the Company has residual needs and the QFs would fill new generation capacity needs when the Company has new generation capacity needs. Q. Mr. Rose states that it is the Company s assertion that costs should not be forecasted. Is his statement correct? A. No. The Company is of the position that actual pricing provides the most accurate means of ensuring that the Company s customers pay no more than avoided costs for energy provided from a QF. The Company understands that forecasted costs are an option that the QF may elect to be used; however, the Company believes that if the QF elects to use forecasted costs the terms of the agreements should be no more than five years to prevent harm to customers. The Company would consider a ten-year contract if the QF would accept an update to the forecasted energy price after the end of year five or if the QF would agree to use actual energy pricing. Q. Mr. Rose implies on page of his testimony that Consumers Energy owns biomass plants. Is that correct? A. No. The Company does not own any biomass plants. rte--mtd