S T A T E O F M I C H I G A N BEFORE THE MICHIGAN PUBLIC SERVICE COMMISSION * * * * *

Transcription

1 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 Northern ) Case No. States Power Company, to fully comply ) with the Public Utilities Regulatory Policy ) Act of 1978, 16 USC 2601 et seq. ) NOTICE OF PROPOSAL FOR DECISION The attached Proposal for Decision is being issued and served on all parties of record in the above matter on November 21, Exceptions, if any, must be filed with the Michigan Public Service Commission, 7109 West Saginaw, Lansing, Michigan 48917, and served on all other parties of record on or before January 4, 2018, or within such further period as may be authorized for filing exceptions. If exceptions are filed, replies thereto may be filed on or before January 31, The Commission has selected this case for participation in its Paperless Electronic Filings Program. No paper documents will be required to be filed in this case. At the expiration of the period for filing exceptions, an Order of the Commission will be issued in conformity with the attached Proposal for Decision and will become effective unless exceptions are filed seasonably or unless the Proposal for Decision is reviewed by

2 action of the Commission. To be seasonably filed, exceptions must reach the Commission on or before the date they are due. MICHIGAN ADMINISTRATIVE HEARING SYSTEM For the Michigan Public Service Commission November 21, 2017 Lansing, Michigan Mark D. Eyster Administrative Law Judge

3 S T A T E O F M I C H I G A N MICHIGAN ADMINISTRATIVE HEARING SYSTEM FOR THE MICHIGAN PUBLIC SERVICE COMMISSION * * * * * In the matter, on the Commission s own ) Motion Establishing the Method and ) Avoided Cost Calculation for Northern ) Case No. States Power Company, to fully comply ) with the Public Utilities Regulatory Policy ) Act of 1978, 16 USC 2601 et seq. ) PROPOSAL FOR DECISION I. PROCEDURAL HISTORY On May 3, 2016, the Michigan Public Service Commission (Commission) issued an Order directing Northern States Power Company (NSP, NSP-W, or the Company) to file avoided cost methods and calculations to be used for the approval of avoided costs and PURPA 1 contracts. Pursuant to that Order, on June 30, 2016, NSP filed its Application. On July 21, 2016, a pre-hearing conference was held before Administrative Law Judge, Mark D. Eyster. Counsel appeared on behalf of NSP, the Michigan Public Service Commission staff (Staff), and, jointly, the Environmental Law & Policy Center, the Ecology Center, the Solar Energy Industries Association, and Vote Solar (collectively referred to 1 Public Utility Regulatory Policies Act of 1978, 16 USC 2601 et seq.

4 as Intervenors). At the pre-hearing conference, intervenor status was granted to Intervenors and a schedule was adopted. An evidentiary hearing was conducted on March 2, 2017, at which the pre-filed testimony of the witnesses was bound into the record and exhibits were admitted into evidence. On May 5, 2017, briefs were filed by NSP, Staff, and Intervenors. On May 19, 2017, reply briefs were filed by NSP and Intervenors. The record consists of testimony contained in the 227 page transcript and 16 exhibits. II. BACKGROUND Page 2 The purpose of PURPA is to encourage the conservation of energy supplied by electric utilities, to encourage the efficient use of facilities and resources by electric utilities, and to encourage equitable rates for electric consumers. 16 USC PURPA requires electric utilities to purchase the energy offered by certain Qualifying Facilities (QFs) at rates that are just and reasonable to the electric consumer of the electric utility and in the public interest and that do not discriminate against qualifying cogeneration and small power production facilities. 18 CFR (a)(1)-(2). However, electric utilities are not required to pay more than the avoided costs for purchases. 18 CFR (b)(6). As defined in PURPA, a QF is a small power production facility or cogeneration facility that has a right to be served by, and sell to, its host electric utility at the utility s avoided cost. Cogeneration QFs produce electric energy and steam or other forms of energy, which are used for industrial, commercial, or cooling purposes. There is no maximum size limitation for PURPA qualification for cogeneration facilities. Small power production facilities are defined as facilities that use biomass, waste, or renewable

5 resources, including wind, solar, and water, to produce electric power, and which, together with other facilities at the same site, have a generating capacity equal to or less than 80 megawatts (MW). 2 See 18 CFR Avoided costs are defined 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 (b)(6). In determining avoided costs, the Commission is, to the extent practicable, required to consider the following criteria, as set forth in 18 CFR (e): (1) data regarding the utility s cost structure and plans to add capacity; (2) the availability of capacity or energy from a qualifying facility during daily and seasonal peak periods, including: (i) the dispatchability and reliability of the QF; (ii) contract terms; (iii) the extent to which scheduled outages of the qualifying facility can be coordinated with scheduled outages of the utility s facilities; (iv) the usefulness of energy and capacity supplied from a qualifying facility during system emergencies; (v) the individual and aggregate value of energy and capacity from QFs on the electric utility s system; and (vi) the smaller capacity increments and the shorter lead times available with additions of capacity from QFs; (3) the relationship of the availability of energy or capacity from the QF 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 2 Pursuant to the 2005 Energy Policy Act amendments to PURPA, and Federal Energy Regulatory Commission (FERC) Order 688, QFs larger than 20 MW are presumed to have nondiscriminatory access to regional markets. Thus, a host utility may apply to the FERC to terminate its obligation to purchase from QFs with net capacity in excess of 20 MW. Page 3

6 purchasing electric utility generated an equivalent amount of energy itself or purchased an equivalent amount of electric energy or capacity. FERC regulations require the establishment of Standard Offer rates for utility purchases from QFs with a design capacity of 100 kilowatts (kw) or less. The 100 kw size limit is a floor for Standard Offers. Uniform contracts and rates for QFs larger than 100 kw may be established. On March 17, 1981, the Commission issued an order in Case No. U-6798 to commence implementation of the provisions of Section 210 of PURPA (16 USC 824a 3), which requires, among other things, that the Commission establish the avoided costs that an electric utility is obligated to pay to certain QFs. By 1993, the Commission had issued over 20 orders approving PURPA contracts, with avoided costs calculated on the basis of a proxy coal-fired generating unit. In 2015 and 2016, at the direction of the Commission, the PURPA Technical Advisory Committee (PURPA TAC), consisting of Staff and representatives from electric utilities, Qualifying Facilities, small power producers, and distributed generation advocates, met to identify appropriate methods for establishing avoided costs. As a product of those meetings, on April 8, 2016, Staff issued a report entitled Report on the Continued Appropriateness of the Commission s Implementation of PURPA (PURPA Report). The PURPA Report 3 provides an overview of the Commission s PURPA responsibilities, a history of PURPA implementation in Michigan, and a summary of utility obligations under PURPA. In addition, the PURPA Report addresses the various 3 The PURPA Report was entered into evidence as Exhibit S-2. Page 4

7 methods for determining avoided costs and contains Staff s recommendation that a hybrid proxy plant be used to determine avoided costs. On May 3, 2016, shortly after issuance of the PURPA Report, the Commission commenced this case, noting that it had been over two decades since the development of Michigan s avoided costs rates and, because of changes to the energy landscape, it was time to update the methods for establishing avoided costs. III. FINDINGS OF FACT, POSITIONS OF THE PARTIES, AND DISCUSSIONS A. Introduction NSP is a wholly owned subsidiary of Xcel Energy that generates, transmits, distributes, and sells electric energy to approximately 246,000 retail electric customers in northwestern Wisconsin and approximately 9,000 retail electric customers in the western tip of Michigan s Upper Peninsula. 2 Tr NSP presented the testimony of two witnesses: Michelle D. Schlosser, a Senior Pricing Analyst for NSP and Deborah E. Erwin, Manager of Regulatory Policy for NSP. Ms. Schlosser presented direct testimony to provide general information about NSP and its holding company, Xcel Energy. Additionally, she described three avoided cost methodologies, recommended NSP s preferred methodology, and presented a standard rate tariff for purchases from QFs. Ms. Schlosser presented rebuttal and surrebuttal testimony to address issues raised by Staff and Intervenors. Ms. Schlosser sponsored Exhibits A-1 and A-2. In response to Intervenors and Staff, Ms. Erwin provided rebuttal testimony to further explain how NSP serves its customers, to respond to Intervenors alternative Page 5

8 approaches to QF compensation, and to respond to claims of discrimination by NSP against QFs. She sponsored Exhibit A-3. Intervenors presented four witnesses: Douglas B. Jester, a Principal of 5 Lakes Energy LLC; Karl R. Rábago, the Principal of Rábago Energy LLC; Adam Schumaker, Director of Business development for Sustainable Power Group LLC; and Rand Dueweke, Senior Research Analyst at Sustainable Partners LLC. Mr. Jester provided direct testimony addressing methodologies for calculating avoided costs. In addition, he provided rebuttal testimony in response to Staff and NSP. He sponsored Exhibit ELP-1. In his direct testimony, Mr. Rabago offered his opinions regarding the importance of non-discriminatory policies in the implementation of PURPA and provided recommendations to the Commission regarding implementation of PURPA. He sponsored Exhibit ELP-2. Mr. Schumaker provided testimony addressing the financing of solar QFs and how PPA terms can affect the development of solar QF projects. He sponsored Exhibits ELP-6 and ELP-7. Mr. Dueweke provided similar direct testimony in reference to combined heat and power (CHP) facilities fueled with biogas and/or natural gas. He presented no exhibits. Staff presented three witness: Merideth A. Hadala, a Department Analyst in the Commission s Renewable Energy Section of the Electric Reliability Division; Julie K. Baldwin, Manager of the Commission s Renewable Energy Section of the Electric Reliability Division; and Jesse J. Harlow, Public Utilities Engineer in the Commission s Renewable Energy Section of the Electric Reliability Division. Page 6

9 Page 7 Ms. Hadala presented direct testimony to provide background on PURPA, avoided costs, and avoided costs methodologies. She sponsored no exhibits. Ms. Baldwin presented direct testimony to propose a review schedule for updating NSP avoided costs and to recommend Commission approval of a Standard Offer tariff for certain QFs. She sponsored Exhibit S-1. Mr. Harlow testified in support of Staffs proposed avoided costs methodology. Mr. Harlow sponsored Exhibits S-2 through S-6. No witness was subject to cross-examination. B. Contested Matters In their evidentiary presentations and briefs, NSP and Staff presented incompatible proposals for the calculation of avoided costs. Intervenors supported Staff s proposal, with amendments. As a consequence, there are a number of contested issues that will be discussed individually below. Most notably, the parties disagreed on the proper method for calculating avoided costs, the term of the Standard Offer, and the size of QFs eligible to take service under the Standard Offer. 1. Avoided Cost Methodology a. Findings of Fact i. Staff s Proposal Staff proposed the Modified Proxy Plant Methodology that it first presented in the PURPA Report. As explained by Staff, at 2 Tr : The methodology combines a combustion turbine proxy unit methodology for capacity and market based pricing for energy. In addition, a component is included that represents the cheaper market energy cost that is attributable to a combined cycle natural gas plant when the capacity proxy used is a combustion turbine. Staff calls this component the fixed investment cost attributable to energy (ICE). It is Staff s belief that this

10 method currently provides the most accurate valuation of the Company s avoided cost as it utilizes a market based approach and a proxy plant method for capacity that does not rely on [MISO 4 planning resource auctions (PRA)] that... [do] not accurately value long term capacity and does not send appropriate market signals. 5 Explaining further, for capacity, Staff proposes utilizing a natural gas combustion turbine (CT) value as shown in Exhibit S-4 (JJH-3). 2 Tr 221. Staff concludes that this method much better aligns with the actual capacity value the QF is providing through a long-term contact. 2 Tr 221. To account for intermittency and non-dispatchability of certain types of renewables, staff explains, at 2 Tr : A factor would need to be applied to the capacity payment based on the [effective load carrying capability (ELCC)] of the QF and the proxy plant. The ELCC recognizes the historical availability and output of the intermittent generation type during on-peak periods. After a period of actual generation characteristics have been analyzed, individual units are assigned an ELCC. 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. Staff recommends that MISO s ELCC ratios be applied to intermittent generator resources (solar and wind). 4 MidContinent Independent System Operator 5 At 2 Tr , Staff explained that: MISO s PRA treats capacity as annual, excess rate-regulated utility capacity since the PRA currently serves only as a market for differences. Using the PRA to value a QF s long-term capacity undervalues the capacity of the QF as the QF s capacity is long term, firm capacity. Utilities in the MISO footprint forecast capacity needs well into the future and build or enter into long-term contracts to meet these capacity requirements. The PRA was established for balancing functions to make up small zonal resource credit shortfalls in the upcoming or following year and is not intended to support resource investment decisions. It would be prudent for a regulated utility to plan to build a plant or enter into a long term contract should a large long term capacity need exist, not purchase this capacity shortfall from the PRA. The PRA prices tend to be especially low compared to the cost of adding new capacity given that over 85% of the utilities in the MISO footprint are rateregulated and are able to recover generation plant costs through traditional rate making. The PRA was never intended for an unregulated market as a mechanism for generation plants to recover capacity costs. Due to these market characteristics, the PRA does not function as a true market as it will likely never produce price signals that prompt capacity build-outs and the utility itself would never utilize the PRA as the sole source of capacity cost recovery for long-lived generation plant investments absent traditional regulated cost recovery. Page 8

11 For the energy component of avoided costs, Staff proposes three options for the QF to choose from; the Locational Marginal Price (LMP) at the time of delivery, a utility forecast of LMPs over the contract period, and the forecasted variable cost of a natural gas combined cycle plant (NGCC). 6 2 Tr For all three options, Staff proposes inclusion of the fixed investment cost attributable to energy (ICE) component. 7 2 Tr 223. ii. NSP s Proposal follows: At 2 Tr 37, Company witness, Ms. Schlosser, succinctly stated NSP s proposal as NSP... recommends an avoided cost capacity component... equal to zero because NSP-W s current and approved capacity resources adequately meet the NSP System s needs through the planning horizon. The Company recommends an energy component... equal to the hourly Real-Time LMP at the UPPC.ONTONAGON load zone node expressed in $/kwh less an administrative fee of $0.001/kWh less other applicable charges incurred under MISO market rules. 6 At 2 Tr , Staff provided the following explanation of the three energy options: The first is LMP at the time of delivery. The second is a utility forecast of LMPs over the contract period. Energy would be compensated on an hourly or monthly average basis according to the forecast. 18 C.F.R (b)(5) provides that 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. [Staff] calculated the levelized payments for 5 and 10-year contracts and attached this as... Exhibit S Staff... also utilized this schedule for [its] LMP Energy Rate Forecast [in] Exhibit S The third option would be for the Company to pay an energy price based on the forecasted variable cost of a [NGCC] as presented in... Exhibit S [This is the] Proxy Plant Variable Rate Forecast in... Exhibit S-1. 7 At 2 Tr 224, Staff provided the following explanation of its ICE proposal: [Staff recommends] that energy payments to the QF include a fixed investment cost attributable to energy in addition to the LMP, LMP forecast, or the NGCC operating cost forecast. The rationale is that in order to realize a cheaper energy price on the market, additional capital costs to build an NGCC are incurred over and above the cost to build a CT as a CT would generally be built to provide cheap capacity while an NGCC would be built to provide cheap energy. [An] NGCC provides for lower energy costs, but results in higher capacity costs when compared to a CT. The NGCC fixed ICE is calculated using the fixed capacity cost difference between an NGCC and a CT, as shown in Exhibit S-4 (JJH-3), Page 2 of 2. Staff calculated this value by subtracting the fixed costs to construct a CT from the fixed costs to construct an NGCC. This difference in cost is paid on a volumetric basis and is added to the energy payment to represent a market energy value. Similarly to the capacity component in Staff s calculation, Staff utilized the Company s inputs to update the fixed ICE calculation. Page 9

12 Should it s capacity position change, NSP proposed that the capacity credit reflect the most recent MISO capacity auction market results in the relevant Local Resource Zone, which at present is Zone 1. 2 Tr 33. In addition, NSP proposed that QFs have the right to request a negotiated buy back rate. 2 Tr 36. NSP indicated that it understands that all negotiated rates are required to adhere to MPSC s Electric Interconnection and Net Metering Standard Rules (R a ) and the Company s Michigan Utility Generator Interconnection Requirements. 2 Tr 36. NSP s proposed Tariff is found in Exhibit A-1. In rebuttal and in the interest of reaching agreement in this case, NSP s witness, Ms. Schlosser, proposed a modified version of Staff s proposal, as follows, at 2 Tr 42: (i) a capacity component that utilizes either a market-based or competitive bidding process approach, dependent on when, within the PURPA ten year planning horizon, capacity is needed; and (ii) an energy component that, at the QF s option, is either based on Real Time [LMP]... or a 5-Year LMP Energy Rate Forecast. iii. Intervenors Proposal Intervenors witness, Mr. Jester voiced support for Staff s proposal by recommending that the Commission adopt the proxy plant methodology to determine avoided costs, to use a combined cycle natural gas plant as the proxy plant, and to use the costs of a natural gas combustion turbine as the avoided cost of capacity, with the Page 10

13 remaining costs of a combined cycle natural gas plant as the avoided cost of energy generation. 8 2 Tr 94. To Staff s proposal, Mr. Jester recommends several refinements. First, noting that NSP is obliged to meet a number of renewable energy standards 9, Mr. Jester proposed that, [t]o the extent that a qualifying facility contributes to [NSP s] compliance with any of these requirements and [NSP] avoids costs of compliance by some other means, the avoided costs for the qualifying facility must include such costs. 2 Tr 95. In other words, when a QF satisfies customer demand or portfolio standards for renewable energy, Mr. Jester believes the QF is entitled to the larger of the avoided cost of compliance with the renewable portfolio standard [or customer demand] and the avoided cost of [NSP s] general obligation to serve its customers with energy and capacity. 2 Tr Next, Mr. Jester proposed that, when a QF is interconnected to serve load without using transmission facilities, the Commission should recognize reduced losses in both capacity and energy delivery and any reduction of payments... for transmission and other 8 At 2 Tr 101, Jester explained his support for the Proxy Plant Method by stating: The Proxy Plant Methodology is most consistent with the way in which the Commission regulates Michigan utilities. The Commission decides whether a utility s investments and other expenditures are prudent and reasonable and then authorizes recovery of those costs through costof-service regulation.... It determines whether the plant contributes to the welfare of the Michigan utility s customers and, for larger investments, that the investment is the most prudent and reasonable available option. The Proxy Plant Methodology reflects this decision-making process. Mr. Jester went on to explain that he favors use of the combined cycle proxy plant because of the clear evidence that MISO s market prices are so distorted that they do not even approximately cover Michigan generators embedded costs of production. 2 Tr Thus, he concluded Staff s use of a combined cycle proxy plant with avoided cost of capacity based on a combustion turbine and remaining costs attributed to energy is the most appropriate method to be adopted by the Commission. 2 Tr At 2 Tr 95, Mr. Jester noted that: [P]ursuant to 2016 PA 342 Northern States Power Company is obligated to meet a 10% renewable energy standard in 2017 and 2018, 12.5% renewable energy standard in 2019 and 2020, and 15% renewable energy standard in 2021 and thereafter. Northern States Power Company is also obligated to pursue a 35% clean energy goal, combining energy waste reduction and renewable generation, in 2025 and thereafter. Northern States Power Company also is required by 2016 PA 342 to offer customer-requested renewable energy. Page 11

14 services Tr 96. Third, in computing the avoided cost of capacity, the Commission should use the avoided cost per unit of useful capacity in the proxy plant and not the avoided cost per unit of nameplate capacity. 2 Tr 96. Fourth, the Commission must allow for the case-by-case determination of avoided costs of transmission and distribution capacity and any other cost categories not included in the Commission s basic methods. 2 Tr 96. Finally, Mr. Jester recommended inclusion of any avoided costs to comply with carbon regulation. 2 Tr 96. stating: At 2 Tr 98-99, Jester recommended against using market based pricing methods, Most participants in the MISO market are cost-of-service regulated utilities who have access to generation revenues through cost recovery in excess of the implicit market revenues they would receive for generation capacity and energy. Equilibrium in such a market cannot be expected to reflect the full costs of generation nor the full avoided costs of forgoing that generation. In such a market, use of market prices to compensate [QFs] while allowing [NSP] to receive full cost recovery for its own investments.. would be grossly discriminatory against the [QFs] At 2 Tr , Mr. Jester explained: A qualifying facility might be interconnected to the subtransmission, primary distribution, or secondary distribution network and its capacity and energy used to serve local load. There will still be line losses between the qualifying facility and the load that it serves but these will be less than the line losses between a combined cycle proxy plant and that same load, so the avoided costs of the qualifying facility should be adjusted for the difference in such line losses. This can be done simply and with reasonable accuracy if the Commission multiplies the avoided cost of capacity by Northern States Power Company s line loss factor for demand at the voltage level to which the qualifying facility is interconnected and multiplies the avoided cost of energy by Northern States Power Company s line loss factor for load at the voltage level to which the qualifying facility is interconnected. This will understate avoided costs because marginal line losses change with the square of current and that factor isn t incorporated into the line loss factors used in the Commission s general rate cases and power supply cost recovery cases. 11 At 2 Tr 100, Mr. Jester added that he finds persuasive the PURPA Report s analysis on this topic and, citing to page 17 of the PURPA Report, stated: [The MISO Planning Resource Auction (PRA)] provides a balancing function and according to a MISO Staff Draft Proposal dated March 18, 2016 titled Competitive Retail Solution, the existing PRA was not designed to meet the need to maintain existing and/or invest in new resources necessary to assure resource adequacy in competitive retail areas that rely exclusively on markets (citations omitted). It is therefore clear that MISO staff do not consider the MISO capacity auction as a measurement of the cost of capacity. Page 12

15 At 2 Tr , Mr. Jester found fault with NSP s proposed competitive bidding methodology, stating: Competitive Bidding is not a viable method to determine... avoided costs unless the competitive bidding process is used to obtain all capacity and energy required by the Company or the terms of the competitive bidding process are substantially similar to the terms available to [NSP] for recovery of costs for its own facilities through the Commission s rate-setting process. [NSP] has not demonstrated either of these to be true.... The competitive bidding process would also have to include methods that account for all categories of avoided cost. None of these conditions apply to competitive bidding [as proposed by NSP]. Like Mr. Jester, Intervenors witness Mr. Carl Rábago supported Staff s capacity payment methodology and, at 2 Tr 135, states: 2 Tr 136: [A] capacity payment based on the cost of a natural gas combustion turbine, discounted by ELCC, is consistent and compliant with the definition of avoided costs and the obligation under PURPA for just and reasonable and non-discriminatory rates. The capacity cost of a natural gas combustion turbine reflects a reasonable estimation of the but for costs to obtain capacity that the Company would face in the absence of a purchase from a qualifying facility. The adjustment for ELCC accounts for the real avoided costs associated with intermittent resources. Mr. Rábago also supported Staff s energy payment methodology, explaining, at The cost of energy from an NGCC unit is a reasonable starting point for calculating avoided energy costs. The ICE adjustment is appropriate to reflect the fact that, but for the purchase of energy from the qualifying facility, in order to avail itself of the cost of energy from a NGCC the Company would also face the capacity investment costs associated with a NGCC. The fixed investment cost associated with obtaining low-priced energy from an NGCC is a real cost avoided by the purchase from the qualifying facility. To ignore the ICE in setting the avoided cost would advance a fiction about the full costs of that energy that are avoided and would reflect improper discrimination against qualifying facilities and small power producers. Page 13

16 As an exception to Staff s capacity payment methodology, Mr. Rábago proposed that, when integrated resource plans, customer demand, or renewable procurement requirements drive the Company to plan for a particular kind of generation, the resource costs of the particular technology type should be used to set the avoided costs. 2 Tr 136. To accomplish this, Mr. Rábago proposed that the Commission determine technology-specific ELCC values that consider avoided transmission costs, line loss mitigation, hedging value, avoided emissions/environmental compliance costs, and avoided costs revealed through a comprehensive Value of Solar analysis. 2 Tr 137. With regard to Value of Solar (VOS), Mr. Rábago recommended that the Commission build on extensive Staff work already done 12 by directing Staff to conduct, complete, and incorporate values from its study of the full range of costs avoided by distributed solar. 2 Tr 149. At 2 Tr 152, he explains: [VOS] analysis is a method to determine the long-term avoided costs of solar generation. In a VOS analysis, the benefits and costs are first identified and grouped, then quantified. VOS results vary depending on specific methodologies, local energy markets, and other factors, but a growing body of VOS research consistently demonstrates that solar energy has value that significantly exceeds more narrowly calculated avoided costs At 2 Tr , Rábago explained: The Commission Staff started the process of recognizing that different technology types have different avoided costs in its recommendation to adjust the avoided capacity cost according to MISO ELCC values for different kinds of generators. However, more work is needed to understand the full range of avoided costs associated with different generation technologies. As a very simple example, a biogas-fired engine at a landfill not only has a different capacity factor than a solar panel on top of the very same landfill, but also a very different emissions profile, dispatchability profile, reliability and availability profile, outage scheduling capability, and others. These types of differences should be accounted for in accurately characterizing the full range of costs avoided by the distributed generators [and] must be reflected in avoided cost rates. 13 For a more thorough explanation of VOS analysis, See 2 Tr Page 14

17 b. Positions of the Parties i. Staff Staff proposes a modified proxy plant methodology that combines a combustion turbine proxy unit methodology for capacity and market based pricing for energy. Staff Br, p 5. In addition, Staff includes a component... using the fixed cost difference between a combustion turbine plant and a combined cycle plant that represents the cheaper market energy cost that is from the utilization of a combined cycle natural gas plant when the capacity proxy used is a combustion turbine. Staff Br, p 5. Staff believes its proposal provides the most accurate valuation of [NSP s] avoided cost as it utilizes a market based approach and a proxy plant method for capacity that does not rely on [MISO] capacity auctions. Staff Br, p 5. Staff argues that its capacity costs model resembles MISO s calculation of the cost of new entry ( CONE ) and coincides with the actual capacity value that the QF is providing through a long-term contract. 14 Staff Br, p 7. Staff adds that it accounts for the variability and nondispatchability of various QFs by use of MISO s effective load carrying capability to determine the amount of a QF s capacity credit. Staff Br, p 6. Staff proposes three options for the energy component: the LMP at the time of delivery; a utility forecast LMP over the contract period; and the forecasted variable cost of a natural gas combined cycle plant. Staff Br, p 7. All three options include a fixed 14 At Staff Br, p 7, Staff explains that: [Its capacity] model differs from the one Staff presented in the [PURPA] Report, in that the model outlined in Exhibit S-4 uses the inputs from DTE Electric s filing in Case No. U for a natural gas combined cycle plant and then applies a ratio comparing a natural gas combined cycle plant and combustion turbine based on Consumers Energy s avoided cost filing in Case No. U Id. Considering that NSP-W did not provide this data in its filing, this was the most comprehensive data that Staff had available. Page 15

18 investment cost attributable to energy. Staff Br, p 7. As for its third option, Staff finds it appropriate because it believes utilities will rely increasingly on natural gas combined cycle plants to meet rising energy demand and offset lost generation from retiring fossil fuel plants. Staff Br, p 8. Staff argues in favor of its ICE proposal because, in order to realize a cheaper energy price on the market, additional capital costs to build a natural gas combined cycle plants are incurred over and above the cost to build a combustion turbine. Staff Br, p 8. that: At Staff Br, p 6 (citations omitted), Staff takes issue with NSP s proposal, arguing [U]nder the guise of recommending the modified proxy plant method, NSP-W proposes to subject QFs to MISO s market that does not provide for a reasonable capacity price. This method is faulty... because MISO capacity auctions do not accurately value long-term capacity and fails to send appropriate market signals. More specifically, NSP-W s approach undervalues a QF s capacity by ignoring the fact that this is long-term, firm capacity (as opposed to less valuable interruptible capacity). ii. NSP NSP argues that, if capacity is not required within the first five years of the ten year planning horizon 15, the capacity payment [should] be zero. NSP Init Br, p 12. [I]f capacity is needed within the first five years of the ten year planning horizon, NSP proposes that QFs be compensated using, the greater of: (a) the MISO PRA at the relevant Local Resource Zone ( LRZ ) or (b) the capacity value as determined through the Company s most recent relevant competitive bidding process adjusted with an ELCC factor. NSP Init Br, p 12. This proposal is based on NSP s position that it will make 15 All parties agree to a ten-year planning horizon, however, as explained in its briefs, NSP proposes to establish avoided costs based on only the first five years of the planning horizon. Page 16

19 purchases to meet any capacity needs and that the purchased capacity would truly be the cost it would avoid but for the purchase of capacity from the QF. NSP Init Br, p 12. For the energy component of avoided costs, NSP argues, that the QF should be given the option of either the Real-Time LMP or a 5-Year LMP Energy Rate Forecast. NSP Init Br, p NSP does not support Staff s proposed option to set energy costs based upon the forecasted variable cost of an NGCC plant, because, they consider such a forecast to be based on estimated long-run avoided costs and not reflective of the true avoided costs as exhibited by the MISO market. NSP Init Br, p 13. NSP opposes staff s ICE proposal arguing that using the NGCC proxy and ICE is not necessarily reflective of NSP-W s actual avoided costs and that it artificially inflates the payment at the expense of its customers. NSP Init Br, p 13. iii. Intervenors Page 17 Intervenors oppose NSP s proposal. At Int Br, p 9, arguing that to base avoided costs solely on market prices fails to capture all costs avoided by QF purchases, Intervenors explain that: Due to the fundamental difference between avoided costs and market prices, use of market prices to compensate [QFs] while allowing [NSP] to receive full cost recovery for its own investments... would be grossly discriminatory against the [QFs]. Further, at Int Br, p 6, Intervenors add that: MISO LMP is an artifact of market operations, the bidding strategies of numerous market participants, the influence of tax incentives, and a structure designed to address very short-term congestion price conditions. The full avoided cost includes a broader category of costs, and [markets] are not designed to reveal these costs. Intervenors support Staff s proposal with some slight adjustments to the methodology. Int Br, p 2. As explained, at Int Br, p 2:

20 Staff s recommendation a proxy plant method, with the cost of a [CT] as proxy for avoided capacity cost, and the variable cost of a [NGCC] plant adjusted for [ICE] as proxy for avoided energy cost is consistent with PURPA s goals However, the Commission must also establish a process to quantify and include other real costs that are avoided by the purchase from a QF, including avoided cost reductions in line losses, avoided environmental costs, hedging value, and other quantifiable costs avoided by the [NSP]. Thus, for this contested case, Intervenors recommend that the Commission adopt Staff s proposed tariff with respect to the methodology for calculating avoided capacity and avoided energy payments, as found in Exhibit S-1. Int Br, p 3. Further, Intervenors recommend that the Commission order a study to quantify other avoided costs, such as line losses and other quantifiable costs, so that they can be included in the tariff approved by the Commission in the next biennial review of avoided cost. 18 Int Br, p At Int Rep Br, p 6-7 (citations omitted), Intervenors explain that: Staff s proposal to base NSP s avoided energy costs on the forecasted variable costs of an NGCC unit and [ICE]... is the best measure of the Company s avoided cost of energy.... An NGCC is the best proxy plant for NSP s avoided energy costs because it is representative of what a Michigan electric provider would pay had it obtained the energy through a long-term power purchase agreement. Staff s opinion that an NGCC is the best proxy plant for the Company s avoided energy costs is reasonable and prudent because an NGCC is the type of plant most likely used to generate energy for a large generating utility. 17 Addressing Staff s three options for the cost of avoided energy, Intevenors add, at Int Br, p 17-18, that: The Commission should set the cost of avoided energy at the forecasted variable cost of an NGCC plant plus ICE... While the Commission could adopt Staff s proposal to provide QFs with three options for avoided cost of energy, that proposal complies with PURPA only if the NGCC plus ICE option is retained as one of the options. Intervenors add, at Int Br, p 15: Staff s proposal of three alternative measures of the Company s avoided cost of energy complies with PURPA as long as the QF retains the right to choose which method it prefers. See 18 C.F.R (d) (requiring rates for purchase at the option of the qualifying facility to be based either on avoided costs calculated at the time of delivery or avoided costs calculated at the time the obligation is incurred). PURPA regulations require that QFs, and only QFs, have the authority and option to select whether the avoided cost payments are based on the price at the time of delivery or the forecasted price at the time the obligation is incurred. See 18 C.F.R (d)(2). 18 At Int Rep Br, p 8, Intervenors add: The Commission should also establish a procedure to calculate avoided costs not included in Staff s recommendation, such as reduced transmission costs, line loss mitigation, hedging value, avoided emissions, and environmental compliance costs. These costs are part of the full-avoided costs required by PURPA. Page 18

21 To support its position, Intervenors argue, at Int Br, p 20, that the full avoided cost of energy is not simply the marginal energy cost or price and add: [T]ransportation, distribution, delivery, and system costs are real costs that are or can be avoided when distributed generation operates. Distributed generation, particularly renewable generation, also helps hedge and avoid costs related to resource diversification, risk reduction, resilience, and complying with environmental regulations. To the extent practicable, all of these factors must be taken into account when determining the full and fair avoided cost of QF purchases. See 18 C.F.R (e). Intervenors also propose that the Commission adopt a methodology for calculating technology specific avoided capacity and avoided energy payments when the utility can defer planned capacity additions of such specific technology, such as planned solar energy facilities. 19 Int Br, p 3. As explained at Int Br, p 18 (citations omitted): When Michigan s renewable portfolio standards ( RPS ), integrated resource plans, or customer demand require the Company to build or acquire renewable energy,... Staff s proxy plant approach should be modified to meet these renewable energy requirements. In such a case, the avoided cost should be technology-specific, and the rate should be set at Company s cost of building and generating renewable energy to meet the state requirements. In other words, the rate would be based on a technology-specific, renewable energy proxy plant. 20 Intervenors note that PURPA regulation 18 CFR (c)(3)(ii) expressly permits such treatment of differing technologies and that it is consistent with the ruling, in 19 For Solar technology, at Int Br, p 21, Intervenors recommend that: The Commission should direct Staff to build on the work already done [by the Commission s Solar Working Group] to develop a full and complete solar valuation study and require the Company to participate in this process and provide all information necessary to complete the analysis. The results can then be incorporated into the Commission s next biennial adjustment of avoided costs. 20 At Int Br, p 18, Intervenors add: As noted by FERC, where a state requires a utility to procure a certain percentage of energy from generators with certain characteristics, generators with those characteristics constitute the sources that are relevant to the determination of the utility s avoided cost for that procurement requirement, and therefore a state may appropriately recognize procurement segmentation by making separate avoided cost calculations. California Public Utilities Commission, 133 F.E.R.C. P61,059, 26, fn. 53 (2010). Page 19

22 California Public Utilities Commission, 133 F.E.R.C. P61,059, 26 (2010), allowing state public utility commission to take into account obligations imposed by the state that require utilities to purchase energy from particular sources of energy such as through a renewable energy standard or other state policy. Int Br, p Intervenors add, at Int Br, p 19-20: Page 20 The Company faces and will continue to face obligations both imposed by the State of Michigan and by customer demand to provide renewable energy. The Commission should take into account obligations created by two recently passed bills in Michigan, 2016 PA 341 and 2016 PA 342, which contain a number of provisions related to renewable energy. Most relevant to this proceeding are the increase in Michigan s [RPS] from 10 percent to 15 percent by 2021 with an interim standard of 12.5 percent by 2019, a goal of 35 percent from renewable sources and energy efficiency by 2025, and the requirement that utilities provide renewable energy options to customers. See MICH. COMP. LAWS (1)(c), (3) (effective April 20, 2017).... Where a purchase from a QF satisfies statutory or customer requirements for more costly renewable energy, avoided cost should... be the larger of the Company s actual cost of generation from that technology when owned by the Company using a technology-specific proxy plant or the default proxy plant method using an NGCC plus ICE for energy and an NGCT for capacity, as recommended by Staff and as amended by Joint Intervenors proposals. To facilitate the proposal, Intervenors call for a Commission order requiring NSP to provide its projected costs of compliance with state renewable energy requirements and its customers demand for renewable energy products at the biennial PURPA reviews. c. Discussion 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 (b)(6) (2017).

23 Pursuant to 16 USCA 824a-3(b), 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. Staff s avoided cost methodology complies with these PURPA requirements. It is based on a proxy CT unit to determine capacity pricing and adopts a market based approach for energy pricing. Staff includes ICE to account for lower energy costs associated with a NGCC when the capacity proxy is a CT. To account for intermittency and variable non-dispatchability of QFs, Staff included the ELCC factor. For the energy component of its avoided cost methodology, Staff proposes three options: LMP at the time of delivery, forecasted LMP, and forecasted variable cost of an NGCC. Staff s avoided cost methodology proposal is well-reasoned and is supported by the evidentiary record. It is consistent with, and supported by, the PURPA Report. Further, Staff s proposal was supported by the convincing evidence and arguments presented by Intervenors. Staff s avoided cost methodology and results are adopted. In addition to voicing support for Staff s positions, Intervenors proposed modifications to Staff s methodology to refine and better estimate avoided costs. Intervenors presented evidence to support establishment of a process to better quantify and/or include other avoided costs, including line losses, environmental costs, and hedging value. Further, Intervenors presented evidence to support their argument that, for QFs that meet the company s renewable energy needs, the avoided cost should be Page 21

24 technology-specific. As with Staff s presentation, Intervenors proposals are wellreasoned, are supported by the evidentiary record, and are adopted. Page 22 To that end, the parties shall begin a review of avoided costs associated with, among other things, line losses, environmental costs, and hedging value. Additionally, the parties shall evaluate NSP s renewable energy needs, and projected costs, and shall prepare technology-specific avoided cost calculations, including a solar valuation study. The results shall be included in NSP s next Biennial Review. 2 Tr Biennial Review of Avoided Costs a. Findings of Fact In its testimony, Staff recommended biennial review of NSP s avoided costs. NSP considers a biennial contested case review of avoided costs to be a costly and unnecessary [regulatory] burden. 2 Tr 43. NSP proposed an annual report to update the LMP forecast, and a biennial requirement to update the avoided capacity cost calculations. 2 Tr 44. To avoid, what it calls, unnecessary administrative costs, NSP requested the ability to obtain a waiver from updating the avoided capacity cost calculations until such time that the Company s capacity needs change. 2 Tr 44. At many portions of Intervenors evidentiary presentation, Intervenors assumed the biennial review of avoided costs. However, Intervenors witness, Mr. Jester, contended that Staff s proposed two-year review is barely sufficient for expeditious development of most qualifying facilities and insufficient for some types of projects. 2 Tr 181. At 2 Tr 181, after noting that the development of QFs takes time he added that: If the terms of a potential contract are subject to adverse revision during the development process, then the developer incurs the risk that

25 investments must be abandoned until the revision is announced, or that the remaining investment is still worthwhile given revised terms but that the sunk costs cannot be recovered. Mr. Jester suggested that, should the Commission adopt Staff s proposal, the Commission will need to establish a queueing process for projects that commits terms when a project enters the queue rather than making it subject to subsequent revision. 2 Tr 181. b. Positions of the Parties Staff believes it would be prudent for the Commission [to review] the Company s avoided cost data and calculations during biennial contested case proceedings. Staff Br, p 8. NSP agrees to make avoided cost data available to the Commission at least every two years. NSP Init Br, p 15. However, NSP does not agree that the data provided needs to be reviewed in a contested case. NSP Init Br, p 15. NSP recommends an annual report to update the LMP forecast, and a biennial requirement to update the avoided capacity cost calculations. NSP Init Br, p 16. However, NSP adds, at NSP Init Br, p 16: [T]o avoid unnecessary administrative costs, the Company also requests the ability to obtain a waiver from updating the avoided capacity cost calculations until such time that the Company s capacity needs change. This would not preclude any party (i.e. Company, Commission Staff, or QF), that believes there are new issues that need to be resolved formally prior to the next biennial review, from initiating a formal process. While not directly addressing this issue in its briefs, Intervenors positions on various issues are premised upon a biennial contested case to review avoided costs. See Int Br, p 3, 19, 21, 23, 25. See Int Rep Br, p 11, 13. Page 23