Dykema Gossett PLLC Capitol View 201 Townsend Street, Suite 900 Lansing, MI 48933 WWW.DYKEMA.COM Tel: (517) 374-9100 Fax: (517) 374-9191 Richard J. Aaron Direct Fax: (855) 230-2517 Email: RAaron@dykema.com April 7, 2017 Kavita Kale Executive Secretary Michigan Public Service Commission 7109 West Saginaw Highway, 3 rd Floor Lansing MI 48909 Re: Case No. U-18092 Indiana Michigan Power Company Dear Ms. Kale: Enclosed for electronic filing in Case No. U-18092 is Indiana Michigan Power Company s Initial Brief and Proof of Service of same. If you have any questions, please contact me. Sincerely, DYKEMA GOSSETT PLLC Richard J. Aaron RJA/rlg Enclosures cc: Hon. Mark D. Eyster (w/encl.) Amit T. Singh (w/encl.) Margarethe K. Kearney (w/encl.) California Illinois Michigan North Carolina Texas Washington, D.C. 4820-6403-5125.7 ID\AARON, RICHARD - 111253\000001
STATE OF MICHIGAN BEFORE THE MICHIGAN PUBLIC SERVICE COMMISSION * * * * * In the matter, on the Commission s own motion, establishing the method and avoided cost calculation for INDIANA MICHIGAN POWER COMPANY to fully comply with Public Utilities Regulatory Act of 1978, 16 USC 2601 et seq. ) Case No. U-18092 ) ) ) ) ) INDIANA MICHIGAN POWER COMPANY S INITIAL BRIEF
TABLE OF CONTENTS Page I. INTRODUCTION... 1 II. APPLICABLE LAW... 2 III. I&M S AVOIDED COST METHODOLOGY AND STANDARD OFFER PROPOSAL8 A. I&M s Avoided Cost Methodology... 8 IV. B. I&M s Avoided Capacity/Fixed Cost Calculation... 9 C. I&M s Standard Offer Proposal... 10 STAFF AND INTERVENORS AVOIDED COST METHODOLOGIES AND STANDARD OFFER PROPOSAL... 10 A. Staff Avoided Cost Methodology... 10 B. ELPC Avoided Cost Methodology... 13 C. Staff Standard Offer Proposal... 15 D. ELPC Standard Offer Proposal... 18 V. CONCLUSION AND RELIEF REQUESTED... 19 ii
I. INTRODUCTION On May 3, 2016, the Michigan Public Service Commission ( MPSC or the Commission ) commenced a proceeding to establish a method and avoided cost calculation for Indiana Michigan Power Company ( I&M or the Company ) as well as approve a Standard Offer tariff. The Commission s May 3, 2016 Order stemmed from an October 27, 2015 Order in Case No. U-17973 in which the Commission commenced an investigation into the related subjects of the Public Utility Regulatory Policies Act of 1978, 16 USC 2601 et seq. ( PURPA ) and the avoided cost amounts that a public utility is obligated to pay certain Qualifying Facilities ( QFs ). The Commission ordered a Technical Advisory Committee to assess the continuing appropriateness of the Commission s current regulatory implementation of these matters and directed the Commission Staff ( Staff ) to report its findings and recommendations by filing a report ( PURPA Report ). In the May 3, 2016 Order in this proceeding, the Commission directed each Michiganregulated public utility to provide avoided cost calculations using: (i) the hybrid proxy plant method proposed in the PURPA report; (ii) the transfer price method developed under 2008 PA 295; (iii) another method, if any, that the company wishes to propose; and (iv) [] proposed standard rate tariffs, including applicable design capacity. Case No. U-18089 et seq., May 3, 2016 Order, pages 3-4. As directed by the MPSC, on June 30, 2016, I&M provided the required avoided cost calculations based on estimates of the fixed costs of a combustion turbine and I&M s avoided costs of energy.
In addition to I&M, the Staff and the Environmental Law & Policy Center, the Ecology Center, the Solar Energy Industries Association, and Vote Solar (collectively referred to as ELPC ) were granted intervention in this proceeding. The record in this proceeding consists of the testimony, rebuttal testimony, and exhibits of three I&M witnesses (Matthew Nollenberger, Toby Thomas, and John Torpey), two Staff witnesses (Julie Baldwin and Jessie Harlow), and four ELPC witnesses (Douglas Jester, Karl Rabago, Adam Schumaker, and Rand Dueweke). After the filing of direct and rebuttal testimony occurred, an evidentiary hearing was conducted before presiding Administrative Law Judge Mark D. Eyster ( ALJ ) on March 2, 2017. In accordance with the schedule set by the ALJ, the Company files this Initial Brief to present its position. II. APPLICABLE LAW PURPA and relevant Michigan law establish the applicable calculation methods in this proceeding and require the ALJ and the Commission to consider: (a) what I&M s unique and company-specific incremental cost of alternative electric energy or avoided costs are, and (b) whether that calculation is just and reasonable with regard to I&M s customers who will be required to pay these costs. The Commission s decisions in this proceeding must be guided by these two fundamental principles. The PURPA provisions relevant to the instant proceeding provide as follows: (a) Cogeneration and small power production rules. Not later than 1 year after November 9, 1978, the Commission shall prescribe, and from time to time thereafter revise, such rules as it determines necessary to encourage cogeneration and small power production, and to encourage geothermal small power production facilities of not more than 80 megawatts capacity, which rules require electric utilities to offer to (1) sell electric energy to qualifying cogeneration facilities and qualifying small power production facilities and 2
(2) purchase electric energy from such facilities. Such rules shall be prescribed, after consultation with representatives of Federal and State regulatory agencies having ratemaking authority for electric utilities, and after public notice and a reasonable opportunity for interested persons (including State and Federal agencies) to submit oral as well as written data, views, and arguments. Such rules shall include provisions respecting minimum reliability of qualifying cogeneration facilities and qualifying small power production facilities (including reliability of such facilities during emergencies) and rules respecting reliability of electric energy service to be available to such facilities from electric utilities during emergencies. Such rules may not authorize a qualifying cogeneration facility or qualifying small power production facility to make any sale for purposes other than resale. (b) Rates for purchases by electric utilities. The rules prescribed under subsection (a) shall insure that, in requiring any electric utility to offer to purchase electric energy from any qualifying cogeneration facility or qualifying small power production facility, the rates for such purchase (1) shall be just and reasonable to the electric consumers of the electric utility and in the public interest, and (2) shall not discriminate against qualifying cogenerators or qualifying small power producers. No such rule prescribed under subsection (a) shall provide for a rate which exceeds the incremental cost to the electric utility of alternative electric energy. (c) Rates for sales by utilities. The rules prescribed under subsection (a) shall insure that, in requiring any electric utility to offer to sell electric energy to any qualifying cogeneration facility or qualifying small power production facility, the rates for such sale (1) shall be just and reasonable and in the public interest, and (2) shall not discriminate against the qualifying cogenerators or qualifying small power producers. (d) Incremental cost of alternative electric energy defined. For purposes of this section, the term incremental cost of alternative electric energy means, with respect to electric energy purchased from a qualifying cogenerator or qualifying small power producer, the cost to the electric utility of the electric energy which, but for the purchase from such cogenerator or small 3
power producer, such utility would generate or purchase from another source. (Public Utility Regulatory Policies Act of 1978 16 USC 824a-3) (emphasis added). The Federal Energy Regulatory Commission ( FERC ) prescribes rules to implement PURPA s goals: (a) Rates for purchases. (b) (1) Rates for purchases shall: (i) (ii) Be just and reasonable to the electric consumer of the electric utility and in the public interest; and Not discriminate against qualifying cogeneration and small power production facilities. (2) Nothing in this subpart requires any electric utility to pay more than the avoided costs 1 for purchases. Relationship to avoided costs. (1) For purposes of this paragraph, new capacity means any purchase from capacity of a qualifying facility, construction of which was commenced on or after November 9, 1978. (2) Subject to paragraph (b)(3) of this section, a rate for purchases satisfies the requirements of paragraph (a) of this section if the rate equals the avoided costs determined after consideration of the factors set forth in paragraph (e) of this section (3) A rate for purchases (other than from new capacity) may be less than the avoided cost if the State regulatory authority (with respect to any electric utility over which it has ratemaking authority) or the nonregulated electric utility determines that a lower rate is consistent with paragraph (a) of this section, and is sufficient to encourage cogeneration and small power production. (4) Rates for purchases from new capacity shall be in accordance with paragraph (b)(2) of this section, regardless of whether the electric utility making such purchases is simultaneously making sales to the qualifying facility. 1 Avoided costs means the incremental costs to an electric utility of electric energy or capacity or both which, but for the purchase from the qualifying facility or qualifying facilities, such utility would generate itself or purchase from another source. 18 CFR 292.101(b)(6). 4
(5) In the case in which the rates for purchases are based upon estimates of avoided costs over the specific term of the contract or other legally enforceable obligation, the rates for such purchases do not violate this subpart if the rates for such purchases differ from avoided costs at the time of delivery. (c) Standard rates for purchases. (d) (1) There shall be put into effect (with respect to each electric utility) standard rates for purchases from qualifying facilities with a design capacity of 100 kilowatts or less. (2) There may be put into effect standard rates for purchases from qualifying facilities with a design capacity of more than 100 kilowatts. (3) The standard rates for purchases under this paragraph: (i) (ii) Shall be consistent with paragraphs (a) and (e) of this section; and May differentiate among qualifying facilities using various technologies on the basis of the supply characteristics of the different technologies. Purchases as available or pursuant to a legally enforceable obligation. Each qualifying facility shall have the option either: (1) To provide energy as the qualifying facility determines such energy to be available for such purchases, in which case the rates for such purchases shall be based on the purchasing utility s avoided costs calculated at the time of delivery; or (2) To provide energy or capacity pursuant to a legally enforceable obligation for the delivery of energy or capacity over a specified term, in which case the rates for such purchases shall, at the option of the qualifying facility exercised prior to the beginning of the specified term, be based on either: (e) (i) The avoided costs calculated at the time of delivery; or (ii) The avoided costs calculated at the time the obligation is incurred. Factors affecting rates for purchases. In determining avoided costs, the following factors shall, to the extent practicable, be taken into account: (1) The data provided pursuant to 292.302(b), (c), or (d), including State review of any such data; 5
(2) The availability of capacity or energy from a qualifying facility during the system daily and seasonal peak periods, including: (i) The ability of the utility to dispatch the qualifying facility; (ii) The expected or demonstrated reliability of the qualifying facility; (iii)the terms of any contract or other legally enforceable obligation, including the duration of the obligation, termination notice requirement and sanctions for non-compliance; (iv)the extent to which scheduled outages of the qualifying facility can be usefully coordinated with scheduled outages of the utility s facilities; (v) The usefulness of energy and capacity supplied from a qualifying facility during system emergencies, including its ability to separate its load from its generation; (vi)the individual and aggregate value of energy and capacity from qualifying facilities on the electric utility s system; and (vii) The smaller capacity increments and the shorter lead times available with additions of capacity from qualifying facilities; and (3) The relationship of the availability of energy or capacity from the qualifying facility as derived in paragraph (e)(2) of this section, to the ability of the electric utility to avoid costs, including the deferral of capacity additions and the reduction of fossil fuel use; and (4) The costs or savings resulting from variations in line losses from those that would have existed in the absence of purchases from a qualifying facility, if the purchasing electric utility generated an equivalent amount of energy itself or purchased an equivalent amount of electric energy or capacity. 18 CFR 292.304 (emphasis added) I&M s strategic plans recognize that customer needs and expectations are changing and it is more important than ever that I&M provides reliable service at reasonable rates for its customers. The world of energy is vastly different today than it was nearly forty years ago when PURPA was passed as part of the National Energy Act (Act) of 1978, in part as a result of implementing PURPA. See Southern California Edison Company San Diego Gas & Electric 6
Company, 71 FERC P61,269, at 62079 (1995). Today, there are competitive generating markets organized and managed by regional transmission operators that merchant generators and other non-utility companies are free to access. Although PURPA s goals may be laudable, the need to favor PURPA facilities to ensure resource adequacy has changed. Although the electric utility landscape has changed in the decades since PURPA s enactment, PURPA s basic mandates with respect to utility purchases have not: rates for purchases must still be just and reasonable to the electric consumer of the electric utility, in the public interest, and not discriminatory against qualifying small power production facilities or QFs. And, of course, PURPA consistently has not required an electric utility to pay more than its avoided cost for purchases from QFs. FERC has consistently explained that Congress did not intend PURPA to require utilities to pay more than they otherwise would have paid for power. Southern California Edison Company, 71 FERC P61,269, at 62079. As FERC explained in its February 23, 1995 Order, PURPA requires an electric utility to purchase power from a QF, but only if the QF sells at a price no higher than the cost the utility would have incurred for the power if it had not purchased the QF s energy and/or capacity. Southern California Edison Company; San Diego Gas & Electric Company, 70 FERC P61,215, at 61677 (1995). In other words, utilities pay the cost of energy they would have paid for energy or capacity generated themselves or purchased from another source. Id. FERC has explained that Congress intention in enacting PURPA was to make ratepayers indifferent as to whether the utility used more traditional sources of power or the newly encouraged alternatives. Southern California Edison Company, 71 FERC P61,269, at P62080. In other words, the Commission must implement PURPA s charge while striking a balance between prices paid to QFs and the costs I&M imposes upon its customers in rates. 7
III. I&M S AVOIDED COST METHODOLOGY AND STANDARD OFFER PROPOSAL A. I&M s Avoided Cost Methodology I&M s evidentiary presentation in this proceeding is summarized in the testimony of Matthew W. Nollenberger. 2 The Commission Order initiating this proceeding did not predetermine how to calculate avoided costs, instead allowing each utility to analyze its own unique avoided costs. Mr. Nollenberger explains that, in Case No. U-16801, I&M filed avoided cost data based upon estimates of the fixed costs of a combustion turbine and I&M s avoided costs of energy. (3/2/2017 Hearing Tr, p 30, lines 3-4.) Mr. Nollenberger sponsored Exhibit IM- 1 which sets forth I&M s avoided cost data and calculations. (Id., lines 15-17.) Mr. Nollenberger explains that, because I&M is required to follow that methodology in Indiana, it is efficient for a multi-state utility like I&M to use the same approach in both Indiana and Michigan. (Id., p 31, lines 4-11.) PURPA explains avoided costs as follows: The rules prescribed under subsection (a) shall insure that, in requiring any electric utility to offer to purchase electric energy from any qualifying cogeneration facility or qualifying small power production facility, the rates for such purchase (1) shall be just and reasonable to the electric consumers of the electric utility and in the public interest, and (2) shall not discriminate against qualifying cogenerators or qualifying small power producers. 2 Mr. Nollenberger is I&M s Manager of Regulated Pricing and Analysis and previously served as American Electric Power Service Corporation s Manager of Regulatory Support. He holds a Bachelor of Science degree in Technology, with a major in Construction Technology from Bowling Green State University and a Master of Business Administration Degree from the Ohio State University. Mr. Nollenberger has been employed by I&M s parent company, American Electric Power System for 19 years and has previously testified before both the Indiana Utility Regulatory Commission and the Michigan Public Service Commission. (3/2/2017 Hearing Tr, p 27 line 12 through p 28 line 9; p 28 lines 17-22.) 8
No such rule prescribed under subsection (a) shall provide for a rate which exceeds the incremental cost to the electric utility of alternative electric energy. For purposes of this section, the term incremental cost of alternative electric energy means, with respect to electric energy purchased from a qualifying cogenerator or qualifying small power producer, the cost to the electric utility of the electric energy which, but for the purchase from such cogenerator or small power producer, such utility would generate or purchase from another source. (16 USC 824a-3(d)). The regulations promulgated under PURPA define avoided costs as the incremental costs to an electric utility of electric energy or capacity or both which, but for the purchase from the qualifying facility or qualifying facilities, such utility would generate itself or purchase from another source. 18 CFR 292.101(b)(6). PURPA and its regulations, therefore, make clear that avoided costs are incremental and but for any potential purchase from a QF. As such, they cannot be based on theoretical generation possibilities, but instead must be costs that the utility will actually avoid. B. I&M s Avoided Capacity/Fixed Cost Calculation At this time, I&M and its customers should not pay for QF capacity because I&M does not need additional capacity. PURPA does not require an electric utility to pay hypothetical QF capacity costs where such capacity is unnecessary. The PURPA Title II Compliance Manual states that [i]f the utility can demonstrate that it does not need capacity over its planning horizon, then the avoided cost value should include no avoided capacity charge. PURPA Title II Compliance Manual, at p 15 (Mar. 2014), available at https://pubs.naruc.org/pub/b5b60741- CD40-7598-06EC-F63DF7BB12DC. The Compliance Manual explains that it is presumed that the utility needs energy unless the additional energy from a QF puts the utility in a minimum generation situation where base load capacity is being shut-off, in which case the avoided cost is zero and purchase is not required. Id. 9
Mr. Nollenberger sponsored Exhibit IM-2 (MWN-2), which is the Company s Reliability Plan Response. Mr. Nollenberger explained that Exhibit 3, line 28, of the Company s Reliability Plan Response shows that the Company has sufficient planning resources for the next 5 years (June 2017 through May 2021). (3/2/2017 Hearing Tr, p 31, lines 18-20.) Accordingly, as explained in the PURPA Compliance Manual, I&M s avoided cost value should include no avoided capacity charge. C. I&M s Standard Offer Proposal Consistent with current practice, the Company proposes to utilize its standard offer for contracts up to 100 kw. Because the Company needs no additional capacity in the next 5 years, the Company s standard offer avoided capacity rate at this time should be zero. Nollenberger suggests that, for any potential longer-term special agreements, while initial years would also reflect a zero avoided capacity cost, future years could include an avoided capacity cost reflecting the future timing of I&M s needs for capacity. (Id., p 31 lines 20-23 through p 32 line 1.) IV. STAFF AND INTERVENORS AVOIDED COST METHODOLOGIES AND STANDARD OFFER PROPOSAL A. Staff Avoided Cost Methodology Although Staff witness Harlow testified that the Company proposed a reasonable avoided cost methodology based on the parameters of a cogeneration plant, he instead supports a methodology referred to as the Modified Proxy Plant Methodology. This generic methodology Mr. that Staff proposes to apply to all Michigan utilities is inconsistent with PURPA, PURPA s regulations, and Staff s own recommendation in its PURPA Report. See Case No U-17973, April 8, 2016 PURPA Report. 10
Specifically, the PURPA Report recognizes that avoided costs are utility specific, stating that [f]or multi-state utilities, the Commission may choose to consider the avoided cost methodologies established by other jurisdictions. (Id., p 8.) Avoided cost prices are intended to hold specific utility customers indifferent. Because each Michigan utility is differently situated from an operational and regulatory perspective, the Commission should approve a method to calculate each utility s specific avoided cost prices and develop its Standard Offer for QFs appropriate for that utility. With regard to I&M, as Mr. Thomas and Nollenberger explained, not only are 80% of I&M s customers located in Indiana, but it also operates wholly within the PJM Interconnection, LLC (PJM) market, not the MISO market in which DTE and Consumers operate. (3/2/2017 Hearing Tr, p 36, lines 9-14; p 49 lines 3-7.) Moreover, I&M s operating needs differ from other Michigan utilities. I&M is not privy to the QF development in the DTE or Consumers territory that may or may not be creating operational strains on their systems; however, applying one statewide methodology for consistency does not consider the specific conditions or needs of I&M or its operating systems. Because PURPA requires I&M to calculate its actual avoided costs, using a one-size-fits-all approach for all Michigan utilities does not comply with PURPA and is not a reasonable approach. Rather, each utility should be allowed to calculate its own actual avoided costs and develop its Standard Offer in a manner that is accurate for that company. Such an individualized approach avoids harming customers by assessing prices that do not accurately reflect the actual avoided cost of I&M and helps to achieve the goal under PURPA of just and reasonable prices. Staff proposes some avoided cost methodologies that would modify the Company s proposed methodology. First, Staff applies an effective load carrying capability ( ELCC ) based on MISO market parameters, which credits capacity based on historic on-peak availability, in 11
order to account for the variability and non-dispatchability of various QF technologies. (3/2/2017 Hearing Tr, p 191, lines 7-12.) Staff acknowledges that I&M is a PJM market participant and suggests openness to alternatives provided the method is similar to its proposed ELCC. (Id. at p 191 n 1.) I&M would be open to reviewing alternative methods to the ELCC which would reasonably reflect the PJM capacity construct, if and when the Company and its customers experience a future need for capacity. For now, I&M has no need to add capacity and its standard offer should not reflect payments for capacity that is not avoided. Staff also contends that I&M should compensate QFs for capacity using Staff s preferred methodology if the Company shows any capacity need over the PURPA 10-year capacity planning horizon or whenever an existing QF renews its existing contract, regardless of the Company s capacity need. As Mr. Thomas and Mr. Torpey explain though, the Company and its customers should not compensate QFs for capacity now because its current resources are sufficient and it has no capacity needs. The Company agrees with Staff s recommendation that RECs ownership should be subject to the negotiation process between I&M and the QF for QFs not served under the Standard Offer tariff. The Company disagrees with Staff s recommendation to pay Fixed Investment Cost Attributable to Energy to QFs less than 20 MW because doing so will subject I&M s other customers to higher costs than could be achieved through an RFP or market purchases. (3/2/2017 Hearing Tr, p 43, lines 3-7.) 12
B. ELPC Avoided Cost Methodology ELPC s proposed Avoided Cost Methodology is colored by ELPC s view of the purpose of this case, which, as ELPC witness Douglas Jester explains, he believes is to encourage cogeneration and small power production. (Id., p 85, lines 16-17.) Mr. Jester s testimony clearly reflects that bias and is disconnected from the definition of avoided cost set forth in PURPA and its underlying regulations. Mr. Jester states that the Commission must require Indiana Michigan Power Company to pay full avoided cost to PURPA qualifying facilities. (Id., lines 17-18.) Mr. Jester goes on to say that I&M s proposal is unduly discriminatory against qualifying co-generators or qualifying small power producers (id., p 86) and suggests that I&M s proposal is overt and intentional discrimination against many qualifying facilities. (id., p 89, lines 12-13.) 3 First, I&M s proposal is not overtly or intentionally discriminatory against qualifying facilities under PURPA. The Conference Report to Section 210 of PURPA states that the conferees used the phrase not discriminate against cogenerators or small power producers because they were concerned that the electric utility's obligations to purchase and sell under this provision might be circumvented by the charging of unjust and non-cost based rates for power solely to discourage cogeneration or small power production. See Joint Explanatory of the Committee of Conference, P.L. 78-617, reprinted in FERC Statutes and Regulations P5151, at p. 5106. See also FERC Order No. 69 at 30,863. FERC has plainly stated that [t]he guiding principle to follow to determine if a rate is discriminatory is whether the rate charged is different than that charged to a non-generating 3 It should be noted that, as explained by Mr. Thomas, Mr. Jester s testimony on this point repeats verbatim the testimony he presented in the Consumers and DTE cases and appears to lack any analysis of I&M s specific circumstances. (3/2/2017 Hearing Tr, p 56, lines 1-3.) 13
customer unless justified on the basis of sufficient load or other cost related data. Id. at 30,888; see also Industrial Cogenerators v Florida Public Service Commission, 43 FERC P61,545, 62353 (1988). With that principle in mind, the record clearly does not contain any evidence demonstrating that I&M s proposed rate is discriminatory. In fact, because the record demonstrates that I&M s proposed rates are not different than those charged to non-generating customers, those rates are not discriminatory as FERC defines under PURPA. Furthermore, Mr. Jester s testimony appears to be based on speculation rather than facts developed in this case. In fact, I&M included two 14 MW cogeneration facilities in its 2015 IRP with the intent of pursuing opportunities with customers where cogeneration makes sense. (3/2/2017 Hearing Tr, p 69, lines 6-8.) Also, I&M has issued and will continue to issue Request for Proposals (RFP) for renewable resources recognizing the unique attributes they bring to I&M s portfolio. (Id., lines 8-10.) The problem with Mr. Jester s testimony is that it fails to account for I&M s capacity position. Mr. Jester s proposal also fails to meet PURPA s goal of determining avoided costs. Instead, Mr. Jester s full avoided costs position reflects his business purpose to advance policies and programs that promote clean energy, sustainability and the environment so that his view of full avoided costs when seen through that lens fails to be balanced. For example, Mr. Jester s avoided cost proposal fails to take into account the lesser value non-dispatchable renewable energy provides as a capacity resource when compared to a dispatchable proxy plant. Requiring I&M to pay QFs for the cost of capacity it will not actually avoid likely will promote developing more QFs, but will do so to the detriment of just and reasonable rates for I&M s customers. 14
I&M supports the economical and efficient development of QFs, but that development must be balanced with the impact on customers by ensuring that I&M does not incur costs any greater than they would have incurred in lieu of purchasing QF power. (3/2/2017 Hearing Tr, p 56, lines 7-10.) Such an approach is neither discriminatory nor anti-competitive and is consistent with the plain language. C. Staff Standard Offer Proposal Staff witness Julie Baldwin recommends I&M s Standard Offer tariff QF size cap be raised from the proposed 100 kw level to between 1 and 5 MW, depending upon the Company s capacity needs. (Id., p 213, lines 14-23 through p 214, lines 1-12.) Although Ms. Baldwin admits I&M s proposal to provide Standard Offers to 100 kw or smaller customers complies with PURPA, she nonetheless supports extending the Standard Offer to larger customers, arguing that doing so will not negatively impact customers. As Mr. Nollenberger explains in his Rebuttal Testimony, although Ms. Baldwin s assertion may be true in many cases, a Standard Offer size cap as high as 5 MW would allow the inclusion of facilities larger than a number of recent utility-scale solar facilities added by I&M and would expose other I&M customers to significant purchase costs that would be better reviewed as part of a comprehensive negotiation process. (Id., p 37, line 16 through p 38, line 5.) I&M s participation in the PJM market also is relevant in this discussion because PJM market requirements directly influence the value of QFs to I&M and its customers and make it necessary for I&M to be able to negotiate individual contracts with QFs over 100kW. I&M is subject to the rules and regulations of both the PJM capacity and energy market structures. (Id., p 50, lines 8-9.) Although the energy market has been largely the same for several years now, the capacity market has not. (Id., lines 9-10.) 15
Specifically, PJM developed new penalties and enhanced performance requirements for generators following the 2014 Polar Vortex. (Id., lines 11-15.) Those performance requirements apply to all generators participating in the PJM capacity market as well as those electing the Fixed Resource Requirement option chosen by I&M, which allows the Company to self-supply its capacity obligation rather than participate in the auction. (Id., lines 16-19.) To qualify as a CP product, a generating resource has to be capable of sustained, predictable, 24x7 operation and be available to provide energy and reserves whenever PJM determines an emergency condition exists. (Id., p 50, line 19 through p 51, line 2.) PJM indicated that they expect auction clearing prices for a CP resource to rise as generators price in the risks associated with generator performance. (Id., p 51, lines 3-4.) Generating resources will also be exposed to significant penalties, however, if the generating resource is not available when called upon by PJM during an emergency condition. (Id., lines 5-7.) These penalties are approximately $1,900/MWH in 2016/17, $2,400/MWH in 2017/18 and $3,200/MWH in 2018/19. (Id., lines 7-8.) As a result, I&M needs to be able to negotiate performance penalties for QFs because, absent such an ability, I&M is forced to assume all of the risk related to the QF s failure to perform. If I&M s customers are paying for capacity from QF facilities, the price being paid must reflect the value and risk of the capacity being provided. It is important to understand and recognize that the PJM market requirements directly influence the value of QFs to I&M and its customers. For these reasons, it is important for I&M to be able to negotiate individual contracts with QFs over 100kW. Staff recommends that QFs taking service under the Company s Standard Offer tariff have the option to select from 5, 10 or 15 year contract terms. (Id., p 216, lines 18-19.) To 16
support that recommendation, Ms. Baldwin points to Act 295 power purchase agreements involving Consumers Energy and DTE Energy, noting that those agreements generally are in the 20-year range. (Id., p 216 line 23 through p 217 lines 1-3.) As Mr. Nollenberger explains in his rebuttal testimony, however, although Ms. Baldwin s statements may be factually correct with regard to Consumers Energy and DTE, the analysis is not specific to I&M and its agreements with QFs. (Id., p 38, lines 11-13.) For example, I&M s only Michigan QF customer operates under a negotiated agreement that remains in effect until either party provides notice to discontinue service. That contract compensates the customer for energy, but excludes compensation for QF capacity. (Id., lines 13-16.) Ms. Baldwin also testifies that long-term contracts could result in either positive or negative impacts on utility customers depending on the actual and forecasted energy rates selected by the QF. (Id., p 217, lines 21-16.) Although such certainty could benefit the QF, there does not appear to be any benefit to I&M s other customers for taking on that risk. Smaller (less than 100 kw) customers do not need lengthy contracts because they will be compensated under Commission-approved tariffs 4, so they are in the same position as a utility that cannot adjust compensation for generation absent Commission approval. (Id., p 39, lines 1-6.) Larger (greater than 100 kw) customers could negotiate longer terms, but such benefits are speculative compared to what a QF would receive in the PJM market, which is the proper forum for all QFs over 20 MW in I&M s service territory. (Id., lines 7-10.) As Mr. Nollenberger explains, larger QFs are compensated through the Reliability Pricing Model (RPM) construct in the PJM market, which is a three-year forward looking 4 Tariffs are legally enforceable obligations under FERC rules. See Public Util Dist No 1 v Dynergy Power Mktg, Inc, 384 F3d 756, 762 (CA 9, 2004) (noting tariffs are an area reserved to FERC to enforce and to seek remedy ). 17
mechanism that does not set pricing or obligations beyond that term. (Id., lines 12-14.) Large QFs would receive day-ahead and real-time location marginal prices, so it would not only be odd, but inconsistent to make longer term commitments to smaller QFs than the PJM market provides them, particularly for MW scale QFs that are similarly sized to facilities already in the PJM market. Staff also proposes to revise I&M s proposed energy rates by offering QFs the choice between three energy rate options: As Available Rate, LMP Energy Rate Forecast, and a Proxy Plant Variable Rate. (Id., p 218, lines 4-5.) The Company does not disagree with an As Available Rate option, consistent with the energy prices that a large QF would receive in the PJM energy market, however, there is no reason to have multiple energy rate forecasts for the QF to select from because the QF presumably will always choose whichever forecast is higher at a cost to all other I&M customers. (Id., p 40, lines 9-15.) Staff also proposes to include a capacity rate equal to the capacity cost of a hypothetical natural gas combustion turbine plant. As Mr. Torpey explains, however, because I&M currently has sufficient capacity to meet its customers needs, I&M should not include a capacity rate at this time. Mr. Thomas recommends that the calculation of avoided costs should include the fixed costs of a combustion turbine if I&M later finds itself with resource deficiencies. (Id., lines 16-22.) Finally, I&M supports Staff s recommendation that any renewable energy credits should be transferred to I&M when QFs take service under the Standard Offer tariff. (Id., p 41, lines 1-3.) D. ELPC Standard Offer Proposal ELPC proposes that the Commission require I&M to utilize Standard Offer contracts up to at least 5 MW capacity. As discussed regarding Staff s parallel proposal, using a Standard 18
Offer size cap as high as 5 MW would allow the inclusion of facilities larger than a number of recent utility-scale solar facilities added by I&M and would expose other I&M customers to significant purchase costs that would be better reviewed as part of a comprehensive negotiation process. (Id., p 38 lines 1-5.) V. CONCLUSION AND RELIEF REQUESTED Based on the evidence introduced into the record in this proceeding, together with the arguments set forth herein, I&M respectfully requests the Michigan Public Service Commission issue an Order approving I&M s revised avoided cost methodology and revised Standard Offer tariff. 4839-4482-4388.7 111253\000001 Respectfully submitted, INDIANA MICHIGAN POWER COMPANY By Richard J. Aaron (P35605) Jason T. Hanselman (P61813) Dykema 201 Townsend Street, Suite 900 Lansing, Michigan 48933 517-374-9198 Direct 517-374-9100 Main RAaron@dykema.com jhanselman@dykema.com Attorneys for Indiana Michigan Power Company 19
STATE OF MICHIGAN BEFORE THE MICHIGAN PUBLIC SERVICE COMMISSION * * * * * In the matter, on the Commission s own motion, establishing the method and avoided cost calculation for INDIANA MICHIGAN POWER COMPANY to fully comply with Public Utilities Regulatory Act of 1978, 16 USC 2601 et seq. PROOF OF SERVICE Case No. U-18092 Becky Grenawalt states that she is an employee of Dykema Gossett, PLLC and that, on April 7, 2017, she served Indiana Michigan Power Company s Initial Brief and this Proof of Service upon the following parties via electronic mail: Michigan Public Service Commission Staff Amit T. Singh Michigan Public Service Commission 7109 W. Saginaw Hwy., 3 rd Floor Lansing, MI 48917 singha9@michigan.gov Administrative Law Judge Hon. Mark D. Eyster Michigan Public Service Commission 7109 W. Saginaw Hwy., 3 rd Floor Lansing, MI 48917 eysterm@mi.gov Environmental Law & Policy Center, Ecology Center, Solar Energy Industries Association and Vote Solar Margarethe K. Kearney 1514 Wealthy Street, SE, Ste. 256 Grand Rapids, MI 49506 MKearney@elpc.org I declare that the statements above are true to the best of my information, knowledge, and belief. Becky Grenawalt