Justia Department Of Energy Federal Energy Regulatory Commission Before Commissioners: Norman C. Bay, Chairman; Philip D. Moeller, Cheryl A. LaFleur, Tony Clark, and Colette D. Honorable; Public Service Company of New Mexico, Order Accepting Notice of Change in Status, Rejecting, Without Prejudice, Request for Market-Based Rate Authorization and Providing Clarification on Submitting Delivered Price Test Analyses and Simultaneous Transmission Import Limit Studies, 63768-63778 [2015-26724]

Before Commissioners: Norman C. Bay, Chairman; Philip D. Moeller, Cheryl A. LaFleur, Tony Clark, and Colette D. Honorable; Public Service Company of New Mexico, Order Accepting Notice of Change in Status, Rejecting, Without Prejudice, Request for Market-Based Rate Authorization and Providing Clarification on Submitting Delivered Price Test Analyses and Simultaneous Transmission Import Limit Studies, 63768-63778 [2015-26724]

Download as PDF tkelley on DSK3SPTVN1PROD with NOTICES 63768 Federal Register / Vol. 80, No. 203 / Wednesday, October 21, 2015 / Notices Description: Notice of SelfCertification of Exempt Wholesale Generator Status of Seville Solar Two, LLC. Filed Date: 10/8/15. Accession Number: 20151008–5087. Comments Due: 5 p.m. ET 10/29/15. Take notice that the Commission received the following electric rate filings: Docket Numbers: ER10–2331–040; ER14–630–017; ER10–2319–032; ER10– 2317–032; ER13–1351–014; ER10–2330– 039. Applicants: J.P. Morgan Ventures Energy Corporation, AlphaGen Power LLC, BE Alabama LLC, BE CA LLC, Florida Power Development LLC, Utility Contract Funding, L.L.C. Description: Notice of Non-Material Change in Status of the J.P. Morgan Sellers. Filed Date: 10/7/15. Accession Number: 20151007–5156. Comments Due: 5 p.m. ET 10/28/15. Docket Numbers: ER11–4380–005; ER13–1562–004; ER13–1641–002; ER10–2434–006; ER10–2467–006; ER10–2488–012; ER12–1931–006; ER15–1045–001;ER10–2504–007; ER12– 610–007; ER13–338–006;ER12–2037– 006; ER12–2314–005; ER10–2436– 006;ER11–4381–005. Applicants: Bellevue Solar, LLC, Catalina Solar Lessee, LLC, Chestnut Flats Lessee, LLC, Fenton Power Partners I, LLC, Hoosier Wind Project, LLC, Oasis Power Partners, LLC, Pacific Wind Lessee, LLC, Pilot Hill Wind, LLC, Shiloh Wind Project 2, LLC, Shiloh III Lessee, LLC, Shiloh IV Lessee, LLC, Spearville 3, LLC, Spinning Spur Wind LLC, Wapsipinicon Wind Project, LLC, Yamhill Solar, LLC. Description: Notice of Change in Status of the EDF–RE MBR Companies. Filed Date: 10/7/15. Accession Number: 20151007–5249. Comments Due: 5 p.m. ET 10/28/15. Docket Numbers: ER15–2426–000. Applicants: Northern Indiana Public Service Company. Description: Amendment to August 12, 2015 Proposed Reactive Power Revenue Requirements of Northern Indiana Public Service Company for twelve generating facilities located in the MISO pricing zone under ER15– 2426. Filed Date: 10/7/15. Accession Number: 20151007–5243. Comments Due: 5 p.m. ET 10/13/15. Docket Numbers: ER16–34–000. Applicants: Harborside Energy, LLC. Description: Baseline eTariff Filing: Market Based Rate Tariff to be effective 11/5/2015. Filed Date: 10/8/15. VerDate Sep<11>2014 22:39 Oct 20, 2015 Jkt 238001 Accession Number: 20151008–5001. Comments Due: 5 p.m. ET 10/29/15. Docket Numbers: ER16–35–000. Applicants: Brown’s Energy Services, LLC. Description: Baseline eTariff Filing: Market Based Rate Tariff to be effective 11/5/2015. Filed Date: 10/8/15. Accession Number: 20151008–5002. Comments Due: 5 p.m. ET 10/29/15. The filings are accessible in the Commission’s eLibrary system by clicking on the links or querying the docket number. Any person desiring to intervene or protest in any of the above proceedings must file in accordance with Rules 211 and 214 of the Commission’s Regulations (18 CFR 385.211 and 385.214) on or before 5:00 p.m. Eastern time on the specified comment date. Protests may be considered, but intervention is necessary to become a party to the proceeding. eFiling is encouraged. More detailed information relating to filing requirements, interventions, protests, service, and qualifying facilities filings can be found at: https://www.ferc.gov/ docs-filing/efiling/filing-req.pdf. For other information, call (866) 208–3676 (toll free). For TTY, call (202) 502–8659. Dated: October 8, 2015. Nathaniel J. Davis, Sr., Deputy Secretary. [FR Doc. 2015–26701 Filed 10–20–15; 8:45 am] BILLING CODE 6717–01–P DEPARTMENT OF ENERGY Federal Energy Regulatory Commission [Docket No. ER10–2302–005] Before Commissioners: Norman C. Bay, Chairman; Philip D. Moeller, Cheryl A. LaFleur, Tony Clark, and Colette D. Honorable; Public Service Company of New Mexico, Order Accepting Notice of Change in Status, Rejecting, Without Prejudice, Request for Market-Based Rate Authorization and Providing Clarification on Submitting Delivered Price Test Analyses and Simultaneous Transmission Import Limit Studies 1. In this order, we accept the notice of change in status filed by Public Service Company of New Mexico (PNM) to report a transaction in which it purchased the interests in Delta Person, Limited Partnership (Delta Person).1 1 The related acquisition of jurisdictional facilities was authorized by the Commission in PO 00000 Frm 00032 Fmt 4703 Sfmt 4703 Also in this order, we reject, without prejudice, PNM’s request for marketbased rate authority in the PNM balancing authority area and we reject, without prejudice, the simultaneous transmission import limit (SIL) values submitted by PNM for the PNM balancing authority area. We take this opportunity to remind applicants seeking initial market-based rate authority or seeking to retain such authority of the type of information and analysis that is useful and appropriate for our consideration of a Delivered Price Test (DPT) and what is not. We are providing this information not only to PNM but to industry broadly with respect to several issues that arose in our review of the DPT analysis and SIL study prepared by PNM. These issues, as with others, are recurring across a myriad of applicants. Our goal in providing this clarification is to promote compliance with the Commission’s regulations and policies in an effort to more timely process requests for marketbased rate authorization and reduce delay. I. Background 2. On August 18, 2014, as amended on December 17, 2014 and February 18, 2015,2 PNM filed a notice of change in status notifying the Commission that, effective July 17, 2014, PNM purchased the interests in Delta Person, the owner of a 132 megawatt (MW) gas-fired generating facility located in the PNM balancing authority area. PNM states that the acquisition does not affect PNM’s horizontal market power because, prior to the acquisition, PNM purchased the full output of the facility under a long-term contract with Delta Person and, as such, was already deemed to control the output of that facility.3 3. Additionally, PNM requests market-based rate authorization in the PNM balancing authority area.4 PNM states that the market characteristics in the PNM balancing authority area have changed since PNM relinquished its market-based rate authority in 2010 and PNM is therefore seeking to reestablish Delta Person, Limited Partnership, 142 FERC ¶ 62,155 (2013). 2 For purposes of this order, the February 18, 2015 amendment will be referred to as ‘‘Response to the Data Request.’’ 3 August 18, 2014 Filing at 1. 4 PNM states that its tariff reflects that it relinquished its market-based rate authority in the PNM and El Paso Electric Company (El Paso Electric) balancing authority areas. Id. at 3 (citing Public Service Company of New Mexico, Docket No. ER96–1551–022 (Oct. 26, 2010) (delegated letter order)). PNM states that it only seeks to reestablish its market-based rate authority in the PNM balancing authority area and not in the El Paso Electric balancing authority area. Id. at 2 n.4. E:\FR\FM\21OCN1.SGM 21OCN1 Federal Register / Vol. 80, No. 203 / Wednesday, October 21, 2015 / Notices its market-based rate authority in that balancing authority area.5 4. PNM included an updated market power analysis with its August 18, 2014 Filing. PNM states that it passes the pivotal supplier screen and the wholesale market share screen in the summer season; however, PNM represents that it fails the wholesale market share screen in the winter, fall, and spring seasons. PNM notes that the failure of the indicative screens creates a rebuttable presumption of horizontal market power. However, PNM states it has rebutted that presumption by demonstrating that PNM passes a DPT analysis for the PNM balancing authority area.6 5. Additionally, PNM submitted historical evidence related to a request for proposal (RFP) issued by the City of Gallup, New Mexico, representing that PNM was not selected as the winner and that the results of the RFP should be considered as alternative evidence to rebut the presumption that PNM may have market power in the PNM balancing authority area.7 6. On December 19, 2014, the Director of the Division of Electric Power Regulation—West requested additional information from PNM with regard to the DPT analysis and SIL study (Data Request).8 On February 18, 2015, PNM submitted a revised DPT analysis and an additional SIL sensitivity analysis, with revised Submittal 1 and Submittal 2 results, in response to the request for additional information (Response to the Data Request). II. Notice of Filings 7. Notice of PNM’s August 18, 2014 filing, as amended on December 17, 2014 and on February 18, 2015, was published in the Federal Register,9 with interventions and protests due on or before March 11, 2015. Navopache Electric Cooperative, Inc. (Navopache) filed a timely motion to intervene. III. Discussion A. Procedural Matters 8. Pursuant to Rule 214 of the Commission’s Rules of Practice and 5 Id. at 4. December 17, 2014, PNM submitted public versions of its DPT files, explaining that it initially submitted numerous electronic files related to the DPT analysis on a confidential basis. 7 Id. at 12–13. 8 Public Service Company of New Mexico, Docket No. ER10–2302–005 (Dec. 19, 2014) (delegated letter order). We note that on January 21, 2015, PNM filed a motion for an extension of time to file its Response to the Data Request, which was granted. See Notice of Extension of Time, Docket No. ER10–2302–005 (Jan. 27, 2015). 9 79 FR 50,642; 79 FR 78,081 (2014); 80 FR 10,472 (2015). tkelley on DSK3SPTVN1PROD with NOTICES 6 On VerDate Sep<11>2014 22:39 Oct 20, 2015 Jkt 238001 Procedure, 18 CFR 385.214 (2015), Navopache’s timely, unopposed motion to intervene serves to make it a party to this proceeding. B. Substantive Matters 9. We accept PNM’s notice of change in status filing. However, as discussed below, we reject, without prejudice, PNM’s request for market-based rate authority in the PNM balancing authority area and PNM’s related SIL study. We find that PNM has failed to rebut the presumption of horizontal market power in the PNM balancing authority area, and therefore, has not supported its request for market-based rate authority in the PNM balancing authority area. Also, as discussed below, we take this opportunity to identify deficiencies in PNM’s DPT analysis and provide general clarification regarding DPT analyses and SIL studies. We note that our efforts to provide such clarification in this order are hampered by the fact that PNM’s most recent February 18, 2015 DPT analysis and SIL submittals were all filed as nonpublic.10 Thus, we often cite to earlier public versions of filings instead of the most recent non-public versions. However, unless otherwise noted, the discussion is applicable to the most recent non-public version as well. C. Market-Based Rate Authorization 10. The Commission allows power sales at market-based rates if the seller and its affiliates do not have, or have adequately mitigated, horizontal and vertical market power.11 An applicant that fails one or more of the indicative screens is provided with several procedural options including the right to challenge the market power presumption by submitting a DPT analysis.12 As discussed in the body of this order, PNM’s DPT analysis includes 10 We encourage filers to submit as much information as possible as public and only to claim confidential treatment for information that is exempt from mandatory disclosure under the Freedom of Information Act, 5 U.S.C. 552. Filers must follow the requirements in 18 CFR 388.112 (2015) when submitting requests for privileged treatment of filings. 11 See Market-Based Rates for Wholesale Sales of Electric Energy, Capacity and Ancillary Services by Public Utilities, Order No. 697, FERC Stats. & Regs. ¶ 31,252, at PP 62, 399, 408, 440, clarified, 121 FERC ¶ 61,260 (2007), order on reh’g, Order No. 697–A, FERC Stats. & Regs. ¶ 31,268, clarified, 124 FERC ¶ 61,055, order on reh’g, Order No. 697–B, FERC Stats. & Regs. ¶ 31,285 (2008), order on reh’g, Order No. 697–C, FERC Stats. & Regs. ¶ 31,291 (2009), order on reh’g, Order No. 697–D, FERC Stats. & Regs. ¶ 31,305 (2010), aff’d sub nom. Mont. Consumer Counsel v. FERC, 659 F.3d 910 (9th Cir. 2011), cert. denied, 133 S. Ct. 26 (2012). 12 Order No. 697, FERC Stats. & Regs. ¶ 31,252 at P 63. PO 00000 Frm 00033 Fmt 4703 Sfmt 4703 63769 inaccurate data and modeling errors and is inconsistent with the Commission’s regulations. The deficiencies pertain to the following: (i) Data integrity; (ii) identification of potential supply; (iii) calculation of variable costs; (iv) accounting for power purchase agreements; (v) calculation of transmission rates; (vi) calculation of available economic capacity (AEC); (vii) use of historical transaction data to corroborate results; and (viii) preparation of the SIL study. 1. Horizontal Market Power 11. The Commission adopted two indicative screens for assessing horizontal market power: the pivotal supplier screen and the wholesale market share screen.13 The Commission has stated that passage of both screens establishes a rebuttable presumption that the applicant does not possess horizontal market power, while failure of either screen creates a rebuttable presumption that the applicant has horizontal market power.14 12. PNM prepared the pivotal supplier and wholesale market share screens for the PNM balancing authority area, consistent with the requirements of Order No. 697.15 We have reviewed these and find that PNM passes the pivotal supplier screen and the wholesale market share screen in the summer season with a market share of 18.0 percent, but fails the wholesale market share screen in the other seasons with market shares ranging from 24.9 to 26.8 percent.16 As a result of failing the indicative screens in the fall, winter, and spring seasons, PNM submitted alternative evidence and performed a DPT analysis to rebut the presumption of horizontal market power in the PNM balancing authority area. 13. As the Commission has previously explained, the DPT analysis identifies potential suppliers based on market prices, input costs, and transmission availability, and calculates each supplier’s economic capacity (EC) 17 and 13 Id. P 62. PP 33, 62–63. 15 Id. PP 231–232. 16 August 18, 2014 Filing, Exhibit No. JMC–3. 17 The EC of a supplier is defined as ‘‘the amount of generating capacity owned or controlled by a potential supplier with variable costs low enough that energy from such capacity could be economically delivered to the destination market.’’ See 18 CFR 33.3(c)(4)(i)(A) (2015). 14 Id. E:\FR\FM\21OCN1.SGM 21OCN1 63770 Federal Register / Vol. 80, No. 203 / Wednesday, October 21, 2015 / Notices tkelley on DSK3SPTVN1PROD with NOTICES AEC 18 for each season/load period.19 The results of the DPT can be used for pivotal supplier, market share and market concentration analyses.20 Under the DPT analysis, applicants must also calculate market concentration using the Hirschman-Herfindahl Index (HHI).21 An HHI of less than 2,500 in the relevant market for all seasons/load periods, in combination with a demonstration that the applicants are not pivotal and do not possess more than a 20 percent market share in any of the seasons/load periods, would constitute a showing of a lack of horizontal market power, absent compelling contrary evidence from interveners. A detailed description of the mechanics of the DPT analysis is provided in Order No. 697.22 14. As with the indicative screens, applicants and interveners may present evidence, such as historical sales and transmission data, which may be used to calculate market shares and market concentration and to refute or support the results of the DPT analysis. In Order No. 697, the Commission encouraged applicants to present the most complete analysis of competitive conditions in the market as the data allow.23 15. PNM’s DPT analysis for the PNM balancing authority area indicates that PNM is not pivotal in any season/load period using either the EC measure or the AEC measure.24 Using the AEC measure, PNM reports market shares below 20 percent in all seasons/load periods and HHIs below 2,500.25 However, using the EC measure, PNM 18 The Commission’s regulations provide that AEC ‘‘means the amount of generating capacity meeting the definition of economic capacity less the amount of generating capacity needed to serve the potential supplier’s native load commitments,’’ 18 CFR 33.3(c)(4)(i)(B) (2015). 19 The seasons/load periods are as follows: superpeak, peak, and off-peak, for winter, shoulder, and summer periods and an additional highest superpeak for the summer. 20 See AEP Power Marketing, Inc., 107 FERC ¶ 61,018, at PP 106–108 (April 14 Order), order on reh’g, 108 FERC ¶ 61,026 (2004). 21 The HHI is the sum of the squared market shares. For example, in a market with five equal size firms, each would have a 20 percent market share. For that market, HHI = (20)2 + (20)2 + (20)2 + (20)2 + (20)2 = 400 + 400 + 400 + 400 + 400 = 2,000. 22 Order No. 697, FERC Stats. & Regs. ¶ 31,252 at PP 104–117. 23 Id. PP 71, 111. 24 August 18, 2014 Filing, Carey Aff. at 27, Table 4 (Delivered Price Test for the PNM BAA Destination Market Available Economic Capacity); Id., Carey Aff. at 30, Table 5 (Delivered Price Test for the PNM BAA Destination Market Economic Capacity). We note that PNM also submitted sensitivity analyses that separately analyzed what effect, if any, a 10 percent increase or decrease in market price would have on the results of its DPT analysis. Id., Carey Aff. at 30. 25 Id., Carey Aff. at 27, Table 4. VerDate Sep<11>2014 22:39 Oct 20, 2015 Jkt 238001 reports market shares above 20 percent in all seasons/load periods and HHIs below 2,500.26 a. Alternative Evidence—RFP 16. PNM states that the Commission allows a seller to present alternative evidence to rebut the results of the indicative screens. PNM requests that the RFP results be considered as additional alternative evidence to rebut the presumption that PNM may have market power in the PNM balancing authority area. 17. According to PNM, on September 26, 2013, the City of Gallup issued an RFP for long-term power supply and scheduling services for a minimum of five years. The RFP represents that the City of Gallup serves approximately 10,500 customers and averages approximately 215,000,000 kilowatthours (kWh) in annual sales provided from wholesale energy purchases of around 220,000,000 kWh bought from PNM and 15,000,000 kWh from Western Area Power Administration. PNM states that, as the City of Gallup’s existing supplier, it responded to the RFP. PNM further states that the City of Gallup received bids from five suppliers. Further, PNM represents that it was not selected as the winner in the RFP and ranked third in the competitiveness of its bid. PNM states that Continental Divide Electric Cooperative was selected as the winning bidder, having submitted a bid that was significantly lower than those submitted by either PNM or the other bidders. 18. PNM contends that the fact that there were a number of bidders in the RFP, several of whose bids were lower than the bid submitted by PNM, in and of itself, demonstrates that PNM lacks market power in the PNM balancing authority area. PNM further states that this alternative evidence is bolstered by the fact that a neighboring utility that maintains market-based rate authority in the PNM balancing authority area also underbid PNM, making it difficult to justify the notion that PNM has market power. Moreover, PNM states that the RFP is significant recent real-world evidence that corroborates the results of its DPT analysis demonstrating that PNM lacks market power in the PNM balancing authority area. Commission Determination 19. Although PNM presents this RFP as alternative evidence to rebut the results of the indicative screens, we find that this alternative evidence does not sufficiently demonstrate that PNM lacks market power in that balancing 26 Id., PO 00000 Carey Aff. at 30, Table 5. Frm 00034 Fmt 4703 Sfmt 4703 authority area. We do not believe that the City of Gallup’s load is a sufficient proxy for the load PNM served during the study period.27 Further, the results of the RFP may simply reflect that there are competitors to PNM that can provide a small amount of long-term power supply and scheduling services for a minimum of five years less expensively than PNM. However, the Commission’s analysis of horizontal market power includes other factors, such as uncommitted capacity and system operating conditions during various levels of load in a relevant geographic market, none of which is addressed by PNM’s alternative evidence. Thus, we are unable to conclude from the RFP evidence that PNM lacks horizontal market power in the PNM balancing authority area. Further, PNM does not provide historical sales or transmission data to rebut the results of the indicative screens.28 b. DPT Analysis 20. In Order No. 697, the Commission provided the option for a seller to submit a DPT analysis when that seller fails an indicative screen.29 21. The Commission, prior to Order No. 697, provided industry guidance concerning the DPT in the Merger Policy Statement.30 The Commission provided an overview of the definition of the product market studied by the DPT analysis, and specifically stated that a key part ‘‘in determining the size of the geographic market is to identify those suppliers that can compete to serve a given market or customer and how much of a competitive presence they are in the market. Alternative suppliers must be able to reach the market both economically and physically. There are two parts to this analysis. One is determining the economic capability of a supplier to reach a market. This is accomplished by a delivered price test. The second part 27 We note that the 215,000,000 kWh translates into approximately 25 MW of load at a 100 percent load factor (215,000,000 kWh ÷ 1,000 = 215,000 MWh; 215,000 MWh ÷ 8,760 hours in a year = 24.5 MW). A load factor of 60 percent would translate into approximately 41 MW of annual peak load. Either amount is significantly less than the 2,142 MW of retail requirements, wholesale load obligation plus off system sales that PNM served during the summer peak of 2013. See id., Carey Aff. at 11. It is also less than the 2,563 MW PNM balancing authority annual peak load. See id., Exhibit No. JMC–3 at 1. 28 Order No. 697, FERC Stats. & Regs. ¶ 31,252 at P 75. 29 Id. P 105. 30 Inquiry Concerning the Commission’s Merger Policy Under the Federal Power Act: Policy Statement, Order No. 592, FERC Stats. & Regs. ¶ 31,044 (1996) (Merger Policy Statement), reconsideration denied, Order No. 592–A, 79 FERC ¶ 61,321 (1997). E:\FR\FM\21OCN1.SGM 21OCN1 Federal Register / Vol. 80, No. 203 / Wednesday, October 21, 2015 / Notices evaluates the physical capability of a supplier to reach a market.’’31 22. The first part of the product market analysis, that is, the calculation of all potential suppliers given the prevailing market price. The EC of a supplier is the amount of generating capacity owned or controlled by a potential supplier with variable costs low enough that energy from such capacity could be economically delivered to the destination market. The EC calculation can be described as follows.32 23. The first step in calculating a potential supplier’s EC is to calculate the variable cost of each unit.33 Commission regulations state that, at a minimum, these costs include variable operation and maintenance, including both fuel and non-fuel operation and maintenance, and environmental compliance. To the extent these costs are allocated among units at the same plant, allocation methods should be fully described.34 Any generation capacity acquired under long-term firm purchase contracts (i.e., contracts with a remaining commitment of more than one year) should be added to the potential supplier’s generation capacity.35 In addition, the regulations provide that ‘‘other generating capacity may also be attributed to another supplier based on operational control criteria as deemed necessary, but the applicant must explain the reasons for doing so.’’ 36 The variable cost for contractual capacity acquired, or attributed to another supplier, should be calculated in the same way as generation owned or under the direct control of the supplier. Commission regulations also require that specific information on long-term purchase and sale data be submitted.37 31 Id. at 31,130. note that these steps are not an exhaustive list to perform a DPT analysis; however, these steps are provided as an illustration to discuss PNM’s DPT analysis. 33 Revised Filing Requirements Under Part 33 of the Commission’s Regulations, Order No. 642, FERC Stats. & Regs. ¶ 31,111, at 31,886 n.39 (2000), order on reh’g, Order No. 642–A, 94 FERC ¶ 61,289 (2001). 34 18 CFR 33.3(d)(2)(i) (2015). 35 18 CFR 33.3(c)(4)(i)(A) (2015) (specifying that the potential supplier’s capacity is adjusted by subtracting capacity committed under long-term firm sales contracts and adding capacity acquired under long-term firm purchase contracts). 36 Id. 37 18 CFR 33.3(d)(3) (2015) (‘‘Long-term purchase and sales data. For each sale and purchase of capacity, the applicant must provide the following information: (i) Purchasing entity name; (ii) Selling entity name; (iii) Duration of the contract; (iv) Remaining contract term and any evergreen provisions; (v) Provisions regarding renewal of the contract; (vi) Priority or degree of interruptibility; (vii) FERC rate schedule number, if applicable; (viii) tkelley on DSK3SPTVN1PROD with NOTICES 32 We VerDate Sep<11>2014 22:39 Oct 20, 2015 Jkt 238001 24. The second step is to add to the estimate of the unit’s variable generation cost any and all applicable transmission costs that a supplier would incur to deliver the energy into the study area. Commission regulations state that these costs include the maximum transmission rate in a transmission provider’s tariff as well as the estimated cost of supplying energy losses.38 The costs of ancillary services incurred to deliver the competing energy into the study area should also be included.39 These costs should be accumulated beginning at the source of the generation and ending where the generation sinks in the study area.40 25. The final step in calculating economically competitive capacity is to determine whether the computed generation cost of a unit is price competitive in the study area. The supplier should compare the computed cost of a generating unit (including all aforementioned generation, transmission, and other costs), to the computed market price plus five (5) percent in the study area.41 Generation with a delivered cost that meets all of the above conditions is referred to as the EC of that unit. 26. The AEC of the units and all suppliers must also be calculated. AEC includes ‘‘capacity from generating units that are not used to serve native load (or are contractually committed).’’ 42 Accordingly, AEC is the amount of generating capacity meeting Quantity and price of capacity and/or energy purchased or sold under the contract; and (ix) Information on provisions of contracts which confer operational control over generation resources to the purchaser.’’). 38 18 CFR 33.3(d)(5)(i) and 33.3(d)(5)(iii)(H) (2015). 39 18 CFR 33.3(c)(4) (2015) (‘‘Perform delivered price test. For each destination market, the applicant must calculate the amount of relevant product a potential supplier could deliver to the destination market from owned or controlled capacity at a price, including applicable transmission prices, loss factors and ancillary services costs, that is no more than five (5) percent above the pre-transaction market clearing price in the destination market.’’ (emphasis added)). 40 Merger Policy Statement, FERC Stats. & Regs. ¶ 31,044 at 31,132 (‘‘In contrast, a supplier that is three or four ‘wheels’ away from the same buyer may be an economic supplier if the sum of the wheeling charges and the effect of losses is less than the difference between the decremental cost of the buyer and the price at which the supplier is willing to sell.’’ (emphasis added)). 41 April 14 Order, 107 FERC ¶ 61,018 at Appendix F (‘‘[D]etermine the suppliers that could sell into the destination market at a price less than or equal to 5% over the market price. That is, determine which generators have costs less than or equal to 1.05 times the market price.’’); id., Appendix F n.216 (‘‘The costs include running costs, transmission charges, [operation and maintenance] and environmental adders.’’). 42 Merger Policy Statement, FERC Stats. & Regs. ¶ 31,044 at 31,132. PO 00000 Frm 00035 Fmt 4703 Sfmt 4703 63771 the definition of economic capacity less the amount of generating capacity needed to serve the potential supplier’s native load commitments, where native load commitments are ‘‘commitments to serve wholesale and retail power customers on whose behalf the potential supplier, by statute, franchise, regulatory requirement, or contract, has undertaken an obligation to construct and operate its system to meet their reliable electricity needs.’’ 43 Units that are contractually committed or needed to serve native load or meet reliable electricity needs are not available to compete in a DPT analysis. 27. Furthermore, as stated in the Merger Policy Statement, the presumption underlying the AEC measure is that the lowest running cost units are used to serve native load and other firm contractual obligations and would not be available for other sales.44 Such units are not available to compete in the DPT analysis. 28. The second part of the analysis, evaluating whether generation with AEC can reach the study area, and the use of this information to compute market shares and concentration statistics, is discussed below. 29. Turning to PNM’s calculation, we find that the analysis as presented is flawed and from it we are unable to conclude that PNM rebutted the presumption of PNM’s horizontal market power in the PNM balancing authority area. The deficiencies pertain to the following: (i) Data integrity; (ii) identification of potential supply; (iii) calculation of variable costs; (iv) accounting for power purchase agreements; (v) calculation of transmission rates; (vi) calculation of AEC; (vii) use of historical transaction data to corroborate results; and (viii) preparation of the SIL study. Each of these items is discussed further below. PNM’s Calculation of Economic Capacity i. Data Integrity 30. PNM submitted compact discs (CDs) that included its DPT model and underlying work papers with links to other data sources that are not available on its CDs. For instance, when opening some of the files on the CDs submitted on August 18, 2014 and on February 18, 2015, there is an error message that states ‘‘There are links to data sources that cannot be updated.’’ 31. We remind applicants that including workable links to data sources in the spreadsheets enables the 43 18 CFR 33.3(d)(4)(i) (2015). Policy Statement, FERC Stats. & Regs. ¶ 31,044 at 31,132. 44 Merger E:\FR\FM\21OCN1.SGM 21OCN1 63772 Federal Register / Vol. 80, No. 203 / Wednesday, October 21, 2015 / Notices Commission to verify the accuracy of the data sources and to ensure the accuracy of the submitted DPT. ii. Identification of Potential Supply tkelley on DSK3SPTVN1PROD with NOTICES 32. PNM appears to have included generating units that are no longer operational when it calculated EC. EC is the amount of generating capacity owned or controlled by a potential supplier with variable costs low enough that energy from such capacity could be economically delivered to the destination market. Including, for example, the San Onofre Nuclear Generating Station (San Onofre) as operational and reporting units 2 and 3 of this plant as having EC in all seasons of the DPT analysis is inconsistent with the definition of EC.45 Thus, the output of generating facilities, such as San Onofre, that are not in operation during the seasons studied in a DPT analysis cannot feasibly be delivered to the destination market and should not be included in EC. 33. Similarly, PNM identifies many units as having their output committed under long-term power purchase contracts, but still considers the units to have EC in the model. For example, PNM identifies Whitewater Hill Wind Partners as having EC when Whitewater Hill Wind Partners has affirmed to the Commission that the output of its facility is fully committed to an unaffiliated third party.46 An entity that does not own any uncommitted capacity or hold a long-term purchase contract should not be considered as a potential supplier of EC in a DPT analysis.47 In addition, PNM did not provide the information for these contracts as required in 18 CFR 33.3(d)(3)(i). 45 We note that the Velocity Suite database indicates that the San Onofre plant units 2 and 3 last generated electricity in January 2012, while the study period for the DPT analysis was December 2012 through November 2013. This information is sourced from the Ventyx, Velocity Suite database in September 2015. We note that the San Onofre plant is currently in the process of decommissioning. See Decommissioning of San Onofre, https:// www.songscommunity.com. 46 Response to the Data Request, Workpaper ‘‘Wkp—Suppliers Details.xlsx’’ (Tab ‘‘AEC By Suppliers—Base Prices’’). See also Whitewater Hill Wind Partners, LLC, Docket No. ER02–2309–000 at 1 (filed July 11, 2002); Whitewater Hill Wind Partners, LLC, Docket No. ER02–2309–000 (Aug. 29, 2002) (delegated letter order accepting filing). Note also that the comments in the spreadsheet submitted by PNM identify Whitewater Hill Wind Partners as being under a long-term contract. There are additional cells in PNM’s spreadsheets that identify certain generating facilities as having EC or AEC even though the spreadsheets also show those facilities as being under long-term contracts. 47 We note that here we describe Whitewater Hill Wind Partners for illustrative purposes only, and not because it is the only entity listed in PNM’s DPT analysis that lacks EC or AEC. VerDate Sep<11>2014 22:39 Oct 20, 2015 Jkt 238001 34. Commission regulations require that a potential supplier’s EC be adjusted by long-term firm contracts.48 Units that are committed to unaffiliated entities under long-term firm contracts should be attributed to the purchasing entities rather than the owners of those facilities, and should potentially be included in EC only if the purchasing entity has EC. Thus, the inclusion of nonoperational units in the DPT analysis is inappropriate and the output of facilities that are committed under long-term firm contracts should be attributed to the purchasing entities and included as EC only if the purchasing entity has EC. The inclusion of generation from such units distorts the amount of EC in the DPT analysis. This raises additional concerns that the DPT results may be inaccurate and unreliable. iii. Calculating Variable Costs 35. As mentioned above, Commission regulations state that for each generating plant or unit owned or controlled by each potential supplier in a DPT analysis, the applicant must also provide variable cost components, which must include at a minimum: (A) variable operation and maintenance, including both fuel and non-fuel operation and maintenance; and (B) environmental compliance.49 Variable Cost: Fuel 36. In its August 18, 2014 Filing, PNM states that it constructed a supply curve ‘‘in the model for each entity by estimating its unit-specific incremental dispatch costs. The incremental cost is calculated by multiplying the fuel cost for the unit by the unit’s efficiency (heat rate) and adding any additional variable costs that may apply, i.e., costs for variable operations and maintenance and costs for environmental offsets.’’ 50 48 18 CFR 33.3(c)(4)(i)(A) (2015) (‘‘Economic capacity means the amount of generating capacity owned or controlled by a potential supplier with variable costs low enough that energy from such capacity could be economically delivered to the destination market. Prior to applying the delivered price test, the generating capacity meeting this definition must be adjusted by subtracting capacity committed under long-term firm sales contracts and adding capacity acquired under long-term firm purchase contracts (i.e., contracts with a remaining commitment of more than one year.’’). 49 18 CFR 33.3(d)(2)(i) (2015). Additionally, ‘‘[t]o the extent costs described in paragraph (d)(2)(i) of this section are allocated among units at the same plant, allocation methods must be fully described.’’ 18 CFR 33.3(d)(2)(ii) (2015). 50 August 18, 2014 Filing, Carey Aff. ¶ 34. We note that ‘‘Ventyx’’ is the same database as ‘‘Velocity Suite’’ also referred to as ‘‘Velocity.’’ In this order we use the term ‘‘Velocity Suite’’, except for where the term ‘‘Ventyx’’ or ‘‘Velocity’’ is used in direct quotes from PNM’s filings. We note that the acronym ‘‘VOM’’ used above in PNM’s PO 00000 Frm 00036 Fmt 4703 Sfmt 4703 PNM further clarifies that ‘‘[t]he characteristics for all of the units included in the analysis, including their estimated incremental costs, are included in work papers.’’ 51 PNM states that incremental costs were derived by multiplying unit specific heat rates (generally from the Energy Information Administration (EIA) Form 860 or Ventyx) by fuel prices (from FERC Form 423 for the Study Period, as reported by Ventyx) and then adding VOM and any applicable environmental adders. 37. Fuel is a significant component of variable cost, and natural gas- and coalfired generation is a significant portion of the generation analyzed by PNM.52 PNM takes a number of steps to compute a fuel price for generators to determine whether they are economic in each of the 10 season/load levels. PNM appears to use natural gas price data from the ‘‘ICE10x Day Ahead Gas Prices’’ for the El Paso Gas (Permian Basin) and El Paso—South Mainline locations.53 Further, PNM appears to use EIA and Velocity Suite data to compute coal prices across the Western Electricity Coordinating Council (WECC) region. 38. For natural gas, PNM computes seasonal prices at the two locations mentioned above by averaging all of the hourly prices for each location in each season/load level. These two locations seem to be the hubs that are closest to the PNM balancing authority area. However, PNM also includes in its spreadsheets hourly gas prices for 22 locations in the WECC region.54 The summer average prices for the 22 locations range from $1.88 at ‘‘Questar North Pool’’ to $3.27 at ‘‘PG&ECitygate,’’ a variation of almost 74 percent. Although PNM submitted data for 22 locations, it only used prices from the two hubs identified above to calculate input costs for all gas-fired generators in the WECC region. 39. Additionally, PNM uses only three natural gas prices in its model, one for each of the summer, winter and shoulder seasons. To do this, for the one-hour Summer Super Peak 1 (S_SP1) description of variable costs is generally interpreted to mean ‘‘Variable Operations and Maintenance’’ costs. 51 August 18, 2014 Filing, Carey Aff. ¶ 34 n.36. 52 For instance, natural gas-fired generation accounts for 28 percent of the nameplate generation capacity in the underlying PNM dataset. See id., Workpaper ‘‘Gas Prices Final.xlsx.’’ 53 See id., Workpaper ‘‘Gas Prices Final.xlsx’’ (Tab ‘‘Wkp—Gas Prices’’); December 17, 2014 Filing, Workpaper ‘‘Wkp PNM DPT Public Inputs.xlsx’’ (Tab ‘‘Wkp—Gas Prices,’’ Tab ‘‘Wkp— Coal Spot Prices,’’ Tab ‘‘Wkp—Detailed Coal Transactions’’). 54 August 18, 2014 Filing, Workpaper ‘‘Gas Prices Final.xlsx’’ (Tab ‘‘Wkp—Gas Prices’’). E:\FR\FM\21OCN1.SGM 21OCN1 tkelley on DSK3SPTVN1PROD with NOTICES Federal Register / Vol. 80, No. 203 / Wednesday, October 21, 2015 / Notices season, PNM computes a price of $3.57/ MMBtu at El Paso Gas (Permian Basin) and $3.81/MMBtu at El Paso—South Mainline. In a similar way, PNM calculates prices for the remaining seasons/load levels at each of these locations. Next, PNM calculates the average of the El Paso Gas (Permian Basin) and El Paso—South Mainline seasonal prices in order to attain 10 average seasonal natural gas prices. PNM then calculates the average over the four summer seasons/load levels as the summer natural gas price, and uses that as the natural gas price for all four summer seasons/load levels in its model. PNM calculates Winter and Shoulder seasonal natural gas prices similarly. 40. Further, PNM submitted work papers that include an average coal price for 83 plants with unique EIA identification numbers. Only seven of these plants appear to be in the WECC region, although there are more than seven coal-fired plants in WECC. These average prices were calculated from monthly ‘‘Detailed Coal Transactions From December 2012 to November 2013,’’ 55 but not every plant has an average price for each month and some plants include more than one average price for some months. The average prices for the seven WECC plants range from $1.42 to $2.52 per MMBtu, but do not account for any seasonality in coal prices. In its generation dataset, PNM appears to attribute the calculated coal price for each of the seven plants as that plant’s input cost, but then uses the average of all seven as the input price for all other coal-fired generators in the WECC. 41. Sellers should account for some measure of regional differences in fuel price. As described above, PNM used one natural gas price for each of the three seasons’ seasonal gas price estimate for all gas-fired generation in the entire WECC, which are derived from the average prices at two hubs. That is, PNM used the same natural gas fuel costs for generators in Alberta, Northern and Southern California and New Mexico even though PNM’s own spreadsheets detail the locational variation in natural gas prices across the WECC region. As explained above, the fuel cost of each generating facility is one of the main factors in determining whether the output of that facility should be included as EC in a DPT analysis. Oversimplifying the variable cost calculations by assuming that all gas-fired generators have the same input 55 December 17, 2014 Filing, Workpaper ‘‘Wkp PNM DPT Public Inputs.xlsx’’ (Tab ‘‘Wkp—Detailed Coal Transactions’’). VerDate Sep<11>2014 22:39 Oct 20, 2015 Jkt 238001 cost regardless of their location may cause certain units, whose actual gas prices are lower than these averages, to be inappropriately considered uneconomic and may cause units whose actual gas prices are higher than these averages to be inappropriately considered economic. Thus, regional price variation for input fuels should be considered in a model that includes competing supply capacity from a large geographic footprint, and a generator’s fuel cost should be estimated from a nearby price point unless the seller explains why another methodology is reasonable. Furthermore, we note an apparent contradiction between the seven coal prices used in the generation data set and the single coal price reported for WECC of $1.97 56 in the Fuel Prices Summary worksheet. However, as with natural gas prices, we would expect a coal-fired generator’s fuel cost to be estimated from a nearby price point and not an average of several price points across a region as large as WECC. 42. For the reasons stated above, we cannot conclude that PNM has rebutted the presumption of market power because of the flaws in its analysis. Variable Cost: Operations and Maintenance 43. As mentioned above, Commission regulations state that sellers must calculate, at a minimum, variable cost for a unit used in the DPT analysis. For each such generating unit, the seller must also provide variable cost components, which include operation and maintenance costs.57 44. PNM’s DPT model contains a worksheet, ‘‘Generation Dataset,’’ that contains variable cost calculations for the WECC generators that PNM included in its model. There are 4,293 observations in this dataset and 2,118 of these observations have a zero dollar cost for VOM.58 We note that a vast majority of these observations with a zero dollar cost for VOM are from renewable resources. 45. Although the Data Request did not specifically request that PNM provide actual values for VOM costs, we take this opportunity to provide clarification to PNM and other DPT filers. Although VOM costs may be a small component of hourly costs, we do not expect these costs for most generating units to have 56 Id., Workpaper ‘‘Wkp PNM DPT Public Inputs.xlsx’’ (Tab ‘‘Wkp—Fuel Prices Summary’’). PNM used a price of $1.97 for Winter, Summer, and Shoulder season. 57 18 CFR 33.3(d)(2) (2015). 58 December 17, 2014 Filing, Workpaper ‘‘Wkp PNM DPT Public Inputs.xlsx’’ (Tab ‘‘Generation Dataset’’). PO 00000 Frm 00037 Fmt 4703 Sfmt 4703 63773 a zero value 59 because all generation technologies require maintenance or have at least some operational costs to produce electricity. PNM states that it uses Velocity Suite data in its model. We note that Velocity Suite provides cost estimates for various renewable generation technologies. PNM has not explained why it assumed a zero cost for VOM when estimates for this cost are available for most types of renewable generation from Velocity Suite.60 46. Therefore, it appears that PNM underestimates the variable cost of a significant portion of generation in its DPT model, which potentially overestimates the amount of EC calculated in its DPT analysis. iv. Accounting for Purchase Contracts 47. As mentioned above, another step in the calculation of a supplier’s EC is accounting for long-term firm purchase contracts. EC refers to ‘‘the amount of generating capacity owned or controlled by a potential supplier with variable costs low enough that energy from such capacity could be economically delivered to the destination market.’’ 61 The Commission’s regulations require that ‘‘the generating capacity meeting this definition must be adjusted by subtracting capacity committed under long-term firm sales contracts and adding capacity acquired under longterm firm purchase contracts (i.e., contracts with a remaining commitment of more than one year).’’ 62 The regulations further provide that ‘‘capacity associated with any such adjustments must be attributed to the party that has authority to decide when generating resources are available for operation’’ and notes that ‘‘other generating capacity may also be attributed to another supplier based on operational control criteria as deemed 59 We note that although EIA states that wind generation has a relatively small VOM cost, EIA uses a zero cost for all non dispatchable generation in its Annual Energy Outlook 2015 Reference Case model. See EIA, Levelized Cost and Levelized Avoided Cost of New Generation Resources in the Annual Energy Outlook 2015 (June 2015), available at https://www.eia.gov/forecasts/aeo/pdf/electricity_ generation.pdf. 60 A Velocity Suite supply curve for the PNM balancing authority area for July 31, 2013, provides a range of VOM cost estimates for most types of renewable generation. Specifically, Velocity Suite provides a VOM in $/MWh of $1.26 to $1.56 for the hydro plants; $1.90 to $2.06 for photovoltaic generation; $1.25 for energy storage devices; and $4.79 for biomass facilities. Velocity Suite does not provide a VOM cost for wind generation. Velocity Suite states that its estimates are based on many sources of unit or plant data and are calculated in an internal model. 61 See 18 CFR 33.3(c)(4)(i)(A) (2015). 62 Id. E:\FR\FM\21OCN1.SGM 21OCN1 tkelley on DSK3SPTVN1PROD with NOTICES 63774 Federal Register / Vol. 80, No. 203 / Wednesday, October 21, 2015 / Notices necessary, but the applicant must explain the reasons for doing so.’’ 63 48. As noted above, Commission regulations require information on all long-term firm purchases and sales ‘‘for each sale and purchase of capacity’’ as part of the DPT analysis.64 A seller performing a DPT analysis should account for the purchase contracts of potential suppliers because the contracts may affect the competitive situation of a supplier in a DPT analysis. A supplier with a contractual obligation to sell energy or capacity may not have any AEC to be considered as competing in the DPT analysis. Conversely, a supplier with the contractual obligation to purchase supply may have excess energy and become a potential supplier in the DPT analysis. The determination of whether a supplier with purchase contracts has EC or AEC depends on a number of factors specific to that supplier such as the supplier’s native load (if any), the amount of generation the supplier has to meet that load, including any contracts the supplier has to buy or sell energy or capacity, and the prevailing market price. These specific factors should be accounted for in a DPT analysis to determine whether a potential supplier with purchase contracts is a potential competitor. 49. The Data Request sought information from PNM concerning how certain sellers could be considered competitive suppliers for purposes of the DPT analysis when each of those seller’s native load appeared to exceed its generation capacity. Specifically, PNM was asked to explain whether one particular supplier, Tri State Generation & Transmission Association Inc. (TriState), could have any uncommitted capacity to compete with PNM given that TriState’s peak load is reported to be greater than its generation capacity. The Data Request did not specifically identify any other sellers in a similar situation to TriState. However, the Data Request directed PNM to identify every potential supplier for whom its study deducted native load obligations, the amount of those obligations and the source of their native load values.65 Finally, the Data Request directed PNM to adjust its model as needed to reflect TriState and other sellers that have load greater than their respective uncommitted capacity.66 50. In its Response to the Data Request, PNM stated that there are differences between the reporting in the data sources that the Commission used 63 Id. 64 See 18 CFR 33.3(d)(3). See also n.37 above. Data Request, Question No. 5, at 4. 66 See Data Request, Question No. 6, at 4. to formulate its questions and the data source(s) PNM used in its calculation of competitive supply. PNM further added that TriState ‘‘has substantial purchase agreements, including ownership in [WECC] output facilities that would not be tracked by Velocity.’’ 67 PNM did not mention any other sellers who might be in this similar situation. 51. We appreciate PNM’s Response to the Data Request but find that more information is necessary. While PNM provided information on TriState’s purchasing, it did not disclose the amount of power purchased under these contracts that would enable TriState to meet its native load requirements and have sufficient generation to be a competitive supplier in the DPT analysis. PNM also did not meet the reporting requirements for long-term contracts of sales and purchases in 18 CFR 33.3(d)(3) for TriState or for any other suppliers, such as Whitewater Hill Wind Partners, whose output is fully committed under long-term contract to another entity. Additionally, in its Response to the Data Request, PNM did not indicate whether there are other potential suppliers with long-term contracts or adjust its model to reflect any other potential suppliers with native load obligations greater than their respective generation capacity. 52. Generation units in a supplier’s portfolio whose output is committed under long-term firm contracts should not be considered available to compete in the study area as AEC. Including such capacity may overstate the amount of AEC that a potential supplier can contribute or inaccurately attribute that capacity to the wrong potential supplier in a DPT analysis. Additionally, incorrectly attributing capacity to sellers that have sold the output of their facilities to unaffiliated entities under purchase power agreements impacts the market concentration results of the DPT analysis. Lastly, PNM did not adjust its model as requested in the Data Request or otherwise explain that such adjustment was not required. For these reasons, we are unable to rely on PNM’s DPT analysis. v. Transmission Rates 53. As mentioned above, Commission regulations require a DPT analysis to account for any and all applicable transmission costs that a supplier would incur to deliver the energy into the study area and add these costs to the estimate of the available unit’s variable generation cost. Commission regulations state that these costs must include the maximum transmission rate in a 65 See VerDate Sep<11>2014 22:39 Oct 20, 2015 Jkt 238001 67 Response PO 00000 to the Data Request at 8. Frm 00038 Fmt 4703 Sfmt 4703 transmission provider’s tariff as well as the estimated cost of supplying energy losses.68 54. PNM did not include all applicable transmission costs in its EC calculation. In the December 17, 2014 Filing, PNM’s DPT analysis used a universal $2.00 transmission rate for all peak periods and a $1.00 transmission rate for all off-peak periods for all generators, regardless of location.69 55. In the Data Request, PNM was requested to provide the transmission rate schedule for the PNM balancing authority area and all of the balancing authority areas where competing suppliers are located, and to provide cites to the relevant open access transmission tariff(s).70 The Data Request asked PNM to explain if the transmission rates used in its DPT analysis are the maximum rates for the PNM balancing authority area and the balancing authority areas where the DPT analysis indicates there is competitively priced generation.71 Finally, the Data Request directed that, if those are not the maximum rates, PNM should re-run the AEC calculations to include the cost to traverse each balancing authority area using the maximum ‘up to’ transmission rate when PNM re-runs the DPT model.72 56. In Response to the Data Request, PNM stated that it assumed transmission rates for purposes of the model because it lacks details on specific transmission rates for some of the WECC transmission providers. PNM stated that this assumption has a de minimis impact on the results of the analyses. PNM also provided a spreadsheet that identifies the 24 individual balancing authority areas in WECC, their minimum and maximum transmission rates, information on the rate schedules for these balancing authority areas and screen snapshots of the appropriate Open Access Same Time Information System (OASIS) Web sites where PNM retrieved the maximum and minimum rates.73 57. We note that these maximum rates for the peak periods ranged from $1.26 to $10.02 and averaged $4.96. Likewise, the maximum rates for the off-peak periods ranged from $0.72 to $9.00 and averaged $3.59. In Response to the Data Request, PNM provided a sensitivity analysis that used the average of these 68 18 CFR 33.3(d)(5) (2015). 17, 2014 Filing, Workpaper ‘‘Wkp PNM DPT Public Inputs.xlsx’’ (Tab ‘‘Wkp—TTC and Tx Rates’’). 70 Data Request, Question No. 14a, at 6. 71 Id., Question No. 14b, at 6–7. 72 Id., Question No. 14c, at 7. 73 See Response to the Data Request, ‘‘WECC OATT Rates.xlsx.’’ 69 December E:\FR\FM\21OCN1.SGM 21OCN1 Federal Register / Vol. 80, No. 203 / Wednesday, October 21, 2015 / Notices maximum transmission rates to update its DPT model.74 PNM complied with the first part of Question 14 by identifying that the $2.00 and $1.00 transmission rates are not the maximum rates for the peak and off-peak periods, respectively. PNM also identified the 24 source balancing authority areas and provided a link and screen snapshots of the OASIS Web sites for these balancing authority areas that display their maximum and minimum rates. 58. However, we find the remaining portion of PNM’s Response to the Data Request to be unresponsive to the question asked and not in compliance with Commission regulations. PNM did not re-run the DPT analysis with the maximum rate for each balancing authority area as requested in the Data Request 75 and required by Commission regulations.76 Furthermore, PNM did not calculate any additional costs for transmission losses or ancillary services necessary to deliver energy into the study area, as required by Commission regulations.77 For capacity outside of the study area, PNM did not consider additional transmission charges that a competing generator would likely incur to deliver power to the destination market. Therefore, we find that PNM’s calculations underestimate the transmission cost component for most observations in its dataset and further compromise the results of the DPT analysis. vi. Calculation of AEC 59. As mentioned above, alternative suppliers should be able to reach the market both economically and physically.78 First, we discuss how to determine the AEC of a supplier. 60. After computing the EC of potential competing suppliers, an applicant should compute the AEC of those suppliers. AEC is ‘‘the amount of generating capacity meeting the definition of EC less the amount of generating capacity needed to serve the potential supplier’s native load commitments.’’ 79 We note that the Commission has relied more heavily on AEC in the DPT analysis when utilities have significant native load.80 Further, 74 See id. Request, Question No. 14c, at 7 (‘‘If the rates used in your model are not the maximum rate, please re-run your AEC calculations using the maximum ‘up to’ transmission rate to include the cost to traverse each balancing authority when you re-run your DPT model.’’). 76 18 CFR 33.3(d)(5) (2015). 77 18 CFR 33.3(d)(5) (2015). 78 Merger Policy Statement, FERC Stats. & Regs. ¶ 31,044 at 30,130. 79 18 CFR 33.3(c)(4)(i)(B) (2015). 80 Great Plains Energy, Inc., 121 FERC ¶ 61,069, at P 34 & n.44 (2007), reh’g denied, 122 FERC ¶ tkelley on DSK3SPTVN1PROD with NOTICES 75 Data VerDate Sep<11>2014 22:39 Oct 20, 2015 Jkt 238001 in Order No. 697, the Commission stated that ‘‘in markets where utilities retain significant native load obligations, an analysis of available economic capacity may more accurately assess an individual seller’s competitiveness, as well as the overall competitiveness of a market, because available economic capacity recognizes the native load obligations of the sellers.’’ 81 61. The Data Request directed PNM to explain whether its DPT model first allocated the lowest running cost units to a supplier’s native load and cited to the Merger Policy Statement.82 In Response to the Data Request, PNM stated, in part, that ‘‘[t]he model implicitly allocates PNM’s lowest running cost units to serve native load for PNM and non-PNM suppliers to their native load (non-PNM load) by the derivation of the [AEC]. The DPT model does not rank order each supplier’s generating units from lowest to highest running cost but rather aggregates all [EC] for each supplier within the seasonal/load periods analyzed.’’ 83 62. In the Merger Policy Statement, the Commission stated that the AEC measure ‘‘includes capacity from generating units that are not used to serve native load (or are contractually committed).’’ 84 However, PNM stated that ‘‘[t]he DPT model does not rank order each supplier’s generating units from lowest to highest running cost but rather aggregates all economic capacity for each supplier within the seasonal/ load periods analyzed.’’ 85 Further, it is unclear how PNM’s model might 61,177 (2008); Nat’l Grid, plc, 117 FERC ¶ 61,080, at PP 27–28 (2006), reh’g denied, 122 FERC ¶ 61,096 (2008); Westar Energy, Inc., 115 FERC ¶ 61,228, at P 72, reh’g denied, 117 FERC ¶ 61,011, at P 39 (2006); Nev. Power Co., 113 FERC ¶ 61,265, at P 15 (2005). 81 Order No. 697, FERC Stats. & Regs. ¶ 31,252 at P 112. 82 Data Request, Question No. 4, at 3 (‘‘In the [AEC] calculation, please explain whether the model first allocates PNM’s lowest running cost units to serve native load for PNM. Please explain whether the model allocates the lowest running cost units of non-PNM suppliers to their native load (non-PNM load).’’). The Data Request noted that ‘‘AEC includes ‘capacity from generating units that are not used to serve native load (or are contractually committed) and whose variable costs are such that they could deliver energy to a market at a price close to the competitive price in the market. The presumption underlying this measure is that the lowest running cost units are used to serve native load and other firm contractual obligations and would not be available for other sales.’’’ Data Request, Question No. 4 n.6, at 3 (citing Merger Policy Statement, FERC Stats. & Regs. ¶ 31,044 at 30,132). 83 Response to the Data Request at 7. 84 Merger Policy Statement, FERC Stats. & Regs. ¶ 31,044 at 30,132. 85 Response to the Data Request at 7 (emphasis added). PO 00000 Frm 00039 Fmt 4703 Sfmt 4703 63775 implicitly allocate an entity’s lowest running cost units to serve its native load. Based on this response, we conclude that PNM did not allocate the lowest cost units of itself and its competitors to serve their respective native load. Therefore, we are unable to rely on the reported results of potential competitive AEC suppliers and whether they accurately reflect the costs of the competitive generation in the market. vii. Historical Transaction Data to Corroborate Results 63. Commission regulations state that ‘‘[t]he applicant must provide historical trade data and historical transmission data to corroborate the results of the horizontal Competitive Analysis Screen.’’ 86 Commission regulations also state that the applicant must provide data and information used in calculating the EC and AEC that a potential supplier could deliver to a destination market, including transmission capability, transmission constraints and firm transmission rights.87 Further, Commission direction has been to provide a ‘‘trade data check’’ to support the results of the DPT analysis.88 64. The Data Request directed PNM to identify suppliers with AEC and document their contribution to competing supply entering the PNM study area.89 In its Response to the Data Request, PNM provided a spreadsheet that complied with the request by identifying all generation units, their location, and the identity of the suppliers with non-zero contribution to the AEC calculation.90 65. Although the Data Request did not specifically ask PNM to provide historical transaction data to corroborate the results of its DPT analysis, we take this opportunity to provide clarification for PNM and others who may file a DPT 86 18 CFR 33.3(c)(6) (2015). 18 CFR 33.3(d)(7)–(9) (2015). 88 See Merger Policy Statement, FERC Stats. & Regs. ¶ 31,044 at 30,133 (‘‘It would be expected that there be some correlation between the suppliers included in the market by the delivered price test and those actually trading in the market. As a check, actual trade data should be used to compare actual trade patterns with the results of the delivered price test. For example, it may be appropriate to include current trading partners in the relevant market even if the above analysis indicates otherwise.’’). 89 Data Request, Question No. 15, at 7 (‘‘Please provide the following information for each supplier with a non-zero contribution to the available economic capacity in the study area of your model: the full name of each supplier, the name of the unit(s) that supplied the energy, the amount of energy supplied by each unit(s) in megawatts and the balancing authority area location of the unit(s) for each of the 10 load level/study periods.’’ (footnote omitted)). 90 Response to the Data Request at 12 & Workpaper ‘‘Wkp—Suppliers Details.xlsx.’’ 87 See E:\FR\FM\21OCN1.SGM 21OCN1 63776 Federal Register / Vol. 80, No. 203 / Wednesday, October 21, 2015 / Notices analysis in a section 205 proceeding in order to rebut the presumption of market power. PNM did not submit historical transaction data or transmission data to corroborate the results of its model as required by 18 CFR 33.3(c)(6). For example, although PNM indicates in its Response to the Data Request that its model includes significant generation capacity from the California Independent System Operator Corporation (CAISO) market as available to compete in the PNM balancing authority area, PNM did not submit historical transaction data or transmission data to corroborate this. PNM could have submitted eTag data to demonstrate flows from CAISO were consistent with its DPT model. Moreover, the Commission’s review of eTag data was not able to corroborate PNM’s results. Without such information, we are concerned that the amount of competing generation capacity imported into the PNM study area in PNM’s DPT analysis is not supported by historical trade or transmission data and is overstated. We remind DPT filers that they should provide historical trade and transmission data and explain significant discrepancies between modeling results and such data. tkelley on DSK3SPTVN1PROD with NOTICES viii. SIL Study 66. As mentioned above, alternative suppliers must be able to reach the market both economically and physically. We provide clarification regarding determining the physical capability of a supplier with EC and AEC to reach the study area.91 67. The physical ability of a supplier to reach the market or study area requires the use of a SIL study as a basis for transmission access for both the indicative screens and the DPT analysis.92 In Order No. 697, the Commission clarified that the SIL study as shown in Appendix E of the April 14 Order is the only study that meets the Commission’s requirements for the DPT analysis and the indicative screens.93 In the April 14 Order, the Commission set the amount of supply that can reach the 91 In this order, we do not discuss the ultimate DPT calculations, combining the economic and physical analyses to create market share and concentration indices because we do not believe that the first two steps of the PNM DPT analysis provide a reasonable foundation to examine this final step. 92 Order No. 697, FERC Stats. & Regs. ¶ 31,252 at P 19. 93 Id. (‘‘With regard to [SILs], the Commission adopts the requirement that the SIL study be used as a basis for transmission access for both the indicative screens and the DPT analysis. Further, the Commission clarifies that the SIL study as shown in Appendix E of the April 14 Order is the only study that meets our requirements.’’). VerDate Sep<11>2014 22:39 Oct 20, 2015 Jkt 238001 relevant market as uncommitted capacity limited by the simultaneous transmission import capability.94 In Puget Sound Energy, Inc., the Commission consolidated and clarified its direction regarding SIL studies given in previous orders and provided required formats for submitting SIL data.95 Specifically, the Commission directed filers to submit their SIL data in the format provided in Appendix B of Puget in order to properly summarize and document their SIL study results.96 68. The SIL study calculates the aggregated simultaneous transfer capability into the balancing authority area being studied. It is intended to provide a reasonable simulation of historical conditions and is not a theoretical maximum import capability or best import case scenario.97 A simplified view of the SIL study is that it simultaneously increases generator output in one area, the first-tier, and decreases generator output in another area, the study area. As the source of generation is incrementally shifted, single contingency conditions are tested in both areas while the relevant transmission elements are monitored for overloads.98 A ‘‘single contingency condition’’ is the unexpected failure of a single system component, such as a generator, transmission line, circuit breaker, switch or other electrical equipment.99 The Commission direction has been to increase or ‘‘scale up available generation in the exporting (aggregated first tier areas) and scale down the study area resources according to the same methods used historically in assessing available transmission for non-affiliate resources.’’ 100 69. The Commission recognizes that it is a complex process for a seller to estimate transmission capability using the model of its transmission system in a simplified manner so that elements are accurately accounted for in SIL studies. 94 April 14 Order, 107 FERC ¶ 61,018 at Appendix E. 95 Puget Sound Energy, Inc., 135 FERC ¶ 61,254 (2011) (Puget). 96 Submittal 1 of Appendix B of Puget contains a summary table of components used to calculate SIL values and provides a spreadsheet format with numerical examples. Submittal 2 provides a spreadsheet for identification of long-term firm transmission reservations used to import power from seller and affiliate generating resources in a first-tier area to serve native load in the study area. 97 Puget, 135 FERC ¶ 61,254 at Appendix B (citing Order No. 697, FERC Stats. & Regs. ¶ 31,252 at P 354). 98 See, e.g., Puget, 135 FERC ¶ 61,254, Appendix B, § I.D (Prior Commission Direction on Scaling). 99 Id. Appendix B (citing Carolina Power & Light Co., 128 FERC ¶ 61,039, at P 8 n.7 (2009)). 100 April 14 Order, 107 FERC ¶ 61,018 at Appendix E. PO 00000 Frm 00040 Fmt 4703 Sfmt 4703 Therefore, the Commission previously has provided guidance so that sellers can more accurately measure the amount of available transmission capability into the study area. One area of concern has been the proper modeling and scaling of jointly-owned generating plants in a SIL study, particularly when units have long-term firm transmission reservations.101 The Commission has determined that these remote plants should be dispatched at their historical output levels and should not be scaled down as doing so would be unrealistic and inconsistent with historical practices.102 70. In Pinnacle West,103 the Commission identified errors and provided guidance and clarification as to how the SIL study should be revised to satisfy the Commission’s requirements. The PNM SIL study presents issues similar to those presented by the SIL study at issue in Pinnacle West. With regard to the PNM SIL study, the Data Request noted that some units within the study area have long-term firm commitments to serve load outside of the study area. The Data Request noted that the Commission expects that any such unit’s generation that has been committed with long-term firm transmission reservations would be considered unavailable for scaling; however, it appears that some such units were scaled down during the SIL study. Therefore, the Data Request required PNM to identify all generation units within the PNM balancing authority area that have long-term firm transmission reservations (to serve study area load or to export power to the first-tier), describe whether the unit’s output level was either maintained or scaled in the SIL study, and adjust the SIL study as necessary.104 71. In its Response to the Data Request, PNM filed revised work papers and SIL information. PNM also submitted a table listing the long-term firm transmission reservations for exports out of the PNM balancing 101 A long-term firm transmission reservation is a reservation that is 28 days or longer. See Order No. 697, FERC Stats. & Regs. ¶ 31,252 at P 368 (‘‘While we find that firm transmission reservations less than or equal to 28 days in duration are usually unpredictable, we believe that firm transmission reservations of a longer duration are not related to the unpredictable nature of real time events and are based upon planned and predictable events. Therefore, the Commission will require sellers to account for firm and network transmission reservations having a duration of longer than 28 days.’’). 102 See Pinnacle West Capital Corp., 117 FERC ¶ 61,316, at P 6 (2006) (Pinnacle West). 103 Id. P 3. 104 Data Request, Question No. 2, at 2 (citing Pinnacle West, 117 FERC ¶ 61,316 at P 6; April 14 Order, 107 FERC ¶ 61,018 at Appendix E). E:\FR\FM\21OCN1.SGM 21OCN1 Federal Register / Vol. 80, No. 203 / Wednesday, October 21, 2015 / Notices tkelley on DSK3SPTVN1PROD with NOTICES authority area and the corresponding source generator within the study area. This table indicates that these generation units are jointly-owned by PNM and other entities, and that the non-PNM owned portions of these units are committed with long-term firm transmission reservations to export out of the study area (i.e., the PNM balancing authority area). However, based on the power flow models submitted by PNM in the original SIL study, it is evident that PNM scaled down these jointly-owned generation units, including portions belonging to other owners.105 In addition, PNM provided Submittal 1 and Submittal 2 tables which reported the results of two sensitivities that PNM conducted in response to the scaling guidance in the Data Request. 72. PNM’s first sensitivity study ‘‘does not scale resources with potential commitments outside of the PNM [balancing authority area].’’ 106 The second sensitivity ‘‘scales half of the resources with potential commitments outside of the PNM [balancing authority area].’’ 107 However, for both sensitivities, PNM stated that ‘‘the associated export reservations are recognized as long-term firm commitments to be consistent and reflect the equal but opposite effect to import reservations and compensate for prematurely limiting the imports below the physical limit of the transmission system or load within the study area. The export reservations are reflected in the SIL sensitivity analyses by inclusion in Table 2 [of Submittal 2].’’ 108 73. The practice of capturing longterm firm export reservations in Submittal 2 is inconsistent with the instructions and purpose of Submittal 2, which is to identify and sum the longterm firm transmission reservations from affiliated remote generating resources in the first-tier to serve native load in the study area.109 Export reservations are long-term firm transmission reservations from the study area to the first-tier to serve firsttier load; because the exports are commitments from capacity that belongs to the first-tier, these export reservations should not be captured in Submittal 2. 105 August 18, 2014 Filing, Stahlhut Aff. Exhibit JWS–3. 106 Response to the Data Request at 3. We interpret PNM’s language ‘‘resources with potential commitments’’ to mean the long-term firm transmission reservations capacity or export reservations of the units within the PNM balancing authority area that have long-term firm transmission reservations to serve load in the first tier. 107 Id. at 4. 108 Id. at 3–4. 109 Puget, 135 FERC ¶ 61,254, at Appendix B, § II.B. VerDate Sep<11>2014 22:39 Oct 20, 2015 Jkt 238001 As such, the Commission cannot utilize these sensitivities as support for PNM’s SIL study. Furthermore, while the scaling method used in the first sensitivity is consistent with guidance given in the Data Request, the ownership and commitments of the generation units was not apparent in the original August 18, 2014 Filing or the December 17, 2014 Filing. Thus, we believe that further clarification is warranted on the modeling and treatment of jointly-owned units in SIL studies. 74. In Puget, the Commission stated that ‘‘[i]n the case of jointly-owned power plants, the plant’s capacity should be allocated among the generator owners’ balancing authority areas according to its ownership percentages.’’ 110 Additionally, the Commission has stated that a seasonal benchmark case model should simulate historical seasonal conditions that were present during the modeled season. The Commission has stated that ‘‘[a]ny generating units owned by the study area utility that are located in the firsttier area, including the study area utility’s portion of jointly-owned units[,] should be modeled . . . in the first-tier area.’’ 111 In addition, ‘‘any long-term reservations from these facilities used to serve study area native load shall be included in the study area net area interchange.’’ 112 While this statement references jointly-owned generating units located in the first-tier area, we believe that it is reasonable to treat jointly-owned generating units located within the study area committed to serving first-tier load similarly. As portions of these units belong to unaffiliated entities located in the firsttier area, they should not be scaled down; doing so would misrepresent the incremental transfer capability of the study area by reducing generation that actually has commitments to first-tier load.113 This has the effect of allowing more first-tier generation into the study area than is actually available to be displaced in the study area. 75. Thus, we clarify that, for purposes of generation scaling for the SIL, the appropriate method of modeling a generation unit in the study area that is jointly-owned between the seller and one or more unaffiliated sellers in the first-tier area is to represent the unit as multiple units in the model based on ownership percentage such that the 110 Id. P 18. Appendix B, II.D at 4.3.7. 111 Id., 112 Id. 113 See id., Appendix B, § II.D (Submittal 4: Seasonal Benchmark Case) (4.3.7 and 4.3.8 discuss how jointly-owned units should be modeled according to historical dispatch). PO 00000 Frm 00041 Fmt 4703 Sfmt 4703 63777 multiple units fully represent the generation commitments and impacts on the transmission system. One unit will represent the seller’s generation capacity in the study area, and one or more additional units will represent the capacity owned by unaffiliated entities within the first-tier area.114 The seller’s unit will remain modeled within the study area balancing authority area while the portion of the unit(s) belonging to unaffiliated first-tier sellers will be given the appropriate first-tier balancing authority area number in the model. Importantly, we note that this method retains the same physical location of the unit within the transmission network as modeled; however, the portion of the unit(s) belonging to the unaffiliated first-tier sellers would not be considered a study area generator for purposes of calculating net area interchange. We also note that with this method, the seller’s generation capacity can appropriately be scaled down, and the portion of the unit(s) belonging to the unaffiliated first-tier sellers now modeled in the first-tier area can appropriately be scaled up to serve study area load if it is not committed under long-term firm transmission reservations. Additionally, any generating resources in the first-tier with long-term firm transmission reservations to serve study area load should be reported as a long-term firm transmission reservation in Submittal 2.115 Furthermore, entities are required to ‘‘[p]rovide a listing of first-tier area generating units and portions of jointlyowned first-tier area generating units to be scaled-up in the first-tier area, including any first-tier area generation or portions of jointly-owned first-tier area generating units physically located within the study area, according to the same methods used historically in assessing available transmission for non-affiliate resources.’’ 116 Entities should identify their jointly-owned units, report the ownership breakdown, and indicate what scaling, if any, was utilized for each portion of the generator. 76. Finally, we clarify that entities should complete the ‘‘Description of Remote Resources’’ column as necessary 114 In Puget, the Commission approved NorthWestern’s use of this general method to represent the jointly-owned Colstrip plant. The model represented separate generators for each owner, each with one owner’s portion of Colstrip’s total capacity. Id. P 18. 115 Id., Appendix B, II.B, Instruction 3. 116 Id., Appendix B, II.G (Submittal 7: The SubSystem File) (7.2.1). E:\FR\FM\21OCN1.SGM 21OCN1 63778 Federal Register / Vol. 80, No. 203 / Wednesday, October 21, 2015 / Notices in each row of Submittal 2.117 We expect that, at a minimum, entities will indicate the balancing authority area from which these remote resources are sourced. Conclusion 77. As described above, we are unable to validate the results of PNM’s SIL model, its calculations of EC and AEC, and its DPT analysis. Thus, we find that PNM has not adequately rebutted the presumption of horizontal market power caused by its failure of the indicative screens in the PNM balancing authority area. Therefore, we reject, without prejudice, PNM’s request for marketbased rate authorization in the PNM balancing authority area. We encourage other market-based rate applicants to make use of the guidance and clarification offered herein. tkelley on DSK3SPTVN1PROD with NOTICES D. Notice of Change in Status 78. PNM states that its purchase of Delta Person does not affect PNM’s horizontal market power because PNM was already deemed to control the output of the Delta Person facility under a long-term contract with Delta Person.118 In its most recent updated market power analysis for the Southwest region, PNM studied Delta Person’s generation in the first-tier balancing authority areas in which PNM has market-based rate authority.119 79. Based on PNM’s representations, we find that PNM satisfies the Commission’s requirements for marketbased rates regarding horizontal market power in all balancing authority areas in which PNM currently has market-based rate authority, i.e., outside of the PNM and El Paso Electric balancing authority areas. 80. PNM represents that of it and its affiliates, only PNM owns or controls transmission facilities subject to Commission jurisdiction. PNM states that open access to these transmission facilities is provided pursuant to the terms of PNM’s Open Access Transmission Tariff on file with the 117 Id., Appendix B, II.B (Submittal 2: Identification of Long-Term Firm Transmission Reservations used to Import Power for Generating Resources in the First-Tier Area to Serve Native Load in the Study Area) (Instruction 2). 118 August 18, 2014 Filing at 1. 119 Public Service Company of New Mexico, Docket No. ER10–2302–004 (Aug. 22, 2014) (delegated letter order). PNM has market-based rate authority in seven first-tier balancing authority areas to the PNM balancing authority area. These balancing authority areas are Southwestern Public Service Company, Western Area Power Administration-Colorado Missouri, Western Area Power Administration—Lower Colorado, Public Service Company of Colorado, Arizona Public Service Company, Salt River Project, and Tucson Electric Power Company. VerDate Sep<11>2014 22:39 Oct 20, 2015 Jkt 238001 Commission.120 Further, PNM represents that neither it nor any affiliate owns or controls intrastate natural gas transportation, storage, or distribution facilities. PNM represents that it owns several sites that may be used for generation capacity development including sites in which PNM has existing facilities. PNM states that it currently has plans to develop new generation at or near the San Juan Generating Station in the PNM balancing authority area. Additionally, PNM states that it holds one undeveloped site near Albuquerque, New Mexico. 81. PNM states that it purchases coal under various long-term agreements but does not currently own any coal mines or mineral rights. PNM represents that these coal purchase contracts are used exclusively to supply coal to power plants owned and operated by PNM. 82. Finally, PNM states that it has not erected barriers to entry into the relevant market, the PNM balancing authority area, and will not erect barriers to entry into the relevant market. 83. Based on PNM’s representations, we find that PNM satisfies the Commission’s requirements for marketbased rates regarding vertical market power. 84. Based on PNM’s satisfaction of the Commission’s requirements for marketbased authorization regarding horizontal and vertical market power in the markets where it has market-based rate authority, we accept PNM’s notice of change in status. E. Reporting Requirements 85. An entity with market-based rate authorization must file an Electric Quarterly Report (EQR) with the Commission, consistent with Order Nos. 2001 121 and 768,122 to fulfill its responsibility under section 205(c) 123 of the Federal Power Act to have rates on file in a convenient form and place.124 PNM must file EQRs electronically with the Commission consistent with the procedures set forth in Order No. 770.125 Failure to timely and accurately file an EQR is a violation of the Commission’s regulations for which PNM may be subject to refund, civil penalties, and/or revocation of marketbased rate authority.126 86. PNM must timely report to the Commission any change in status that would reflect a departure from the characteristics the Commission relied upon in granting market-based rate authority.127 87. Additionally, PNM must file an updated market power analysis for all regions in which it is designated as a Category 2 seller in compliance with the regional reporting schedule adopted in Order No. 697.128 The Commission also reserves the right to require such an analysis at any intervening time. The Commission orders: (A) PNM’s notice of change in status is hereby accepted for filing, as discussed in the body of this order. (B) PNM’s request for market-based authority in the PNM balancing authority area is hereby rejected, without prejudice, as discussed in the body of this order. (C) PNM’s SIL study is hereby rejected, without prejudice, as discussed in the body of this order. (D) The Secretary is hereby directed to publish a copy of this order in the Federal Register. By the Commission. Issued: October 15, 2015. Kimberly D. Bose, Secretary. [FR Doc. 2015–26724 Filed 10–20–15; 8:45 am] 120 Public Service Company of New Mexico, FERC FPA Electric Tariff, PNM Open Access Transmission Tariff. 121 Revised Public Utility Filing Requirements, Order No. 2001, FERC Stats. & Regs. ¶ 31,127, reh’g denied, Order No. 2001–A, 100 FERC ¶ 61,074, reh’g denied, Order No. 2001–B, 100 FERC ¶ 61,342, order directing filing, Order No. 2001–C, 101 FERC ¶ 61,314 (2002), order directing filing, Order No. 2001–D, 102 FERC ¶ 61,334, order refining filing requirements, Order No. 2001–E, 105 FERC ¶ 61,352 (2003), order on clarification, Order No. 2001–F, 106 FERC ¶ 61,060 (2004), order revising filing requirements, Order No. 2001–G, 120 FERC ¶ 61,270, order on reh’g and clarification, Order No. 2001–H, 121 FERC ¶ 61,289 (2007), order revising filing requirements, Order No. 2001–I, FERC Stats. & Regs. ¶ 31,282 (2008). 122 Electricity Mkt. Transparency Provisions of Section 220 of the Fed. Power Act, Order No. 768, FERC Stats. & Regs. ¶ 31,336 (2012), order on reh’g, Order No. 768–A, 143 FERC ¶ 61,054 (2013). 123 16 U.S.C. 824d(c) (2012). PO 00000 Frm 00042 Fmt 4703 Sfmt 9990 BILLING CODE 6717–01–P 124 See Revisions to Electric Quarterly Report Filing Process, Order No. 770, FERC Stats. & Regs. ¶ 31,338, at P 3 (2012) (citing Order No. 2001, FERC Stats. & Regs. ¶ 31,127 at P 31). 125 Order No. 770, FERC Stats. & Regs. ¶ 31,338. 126 The exact filing dates for these reports are prescribed in 18 CFR 35.10b (2015). Forfeiture of market-based rate authority may require a new application for market-based rate authority if the applicant wishes to resume making sales at marketbased rates. 127 Reporting Requirement for Changes in Status for Public Utilities with Market-Based Rate Authority, Order No. 652, FERC Stats. & Regs. ¶ 31,175, order on reh’g, 111 FERC ¶ 61,413 (2005); 18 CFR 35.42 (2015). 128 Order No. 697, FERC Stats. & Regs. ¶ 31,252 at PP 848–850. E:\FR\FM\21OCN1.SGM 21OCN1

Agencies

[Federal Register Volume 80, Number 203 (Wednesday, October 21, 2015)]
[Notices]
[Pages 63768-63778]
From the Federal Register Online via the Government Publishing Office [www.gpo.gov]
[FR Doc No: 2015-26724]


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DEPARTMENT OF ENERGY

Federal Energy Regulatory Commission

[Docket No. ER10-2302-005]


Before Commissioners: Norman C. Bay, Chairman; Philip D. Moeller, 
Cheryl A. LaFleur, Tony Clark, and Colette D. Honorable; Public Service 
Company of New Mexico, Order Accepting Notice of Change in Status, 
Rejecting, Without Prejudice, Request for Market-Based Rate 
Authorization and Providing Clarification on Submitting Delivered Price 
Test Analyses and Simultaneous Transmission Import Limit Studies

    1. In this order, we accept the notice of change in status filed by 
Public Service Company of New Mexico (PNM) to report a transaction in 
which it purchased the interests in Delta Person, Limited Partnership 
(Delta Person).\1\ Also in this order, we reject, without prejudice, 
PNM's request for market-based rate authority in the PNM balancing 
authority area and we reject, without prejudice, the simultaneous 
transmission import limit (SIL) values submitted by PNM for the PNM 
balancing authority area. We take this opportunity to remind applicants 
seeking initial market-based rate authority or seeking to retain such 
authority of the type of information and analysis that is useful and 
appropriate for our consideration of a Delivered Price Test (DPT) and 
what is not. We are providing this information not only to PNM but to 
industry broadly with respect to several issues that arose in our 
review of the DPT analysis and SIL study prepared by PNM. These issues, 
as with others, are recurring across a myriad of applicants. Our goal 
in providing this clarification is to promote compliance with the 
Commission's regulations and policies in an effort to more timely 
process requests for market-based rate authorization and reduce delay.
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    \1\ The related acquisition of jurisdictional facilities was 
authorized by the Commission in Delta Person, Limited Partnership, 
142 FERC ] 62,155 (2013).
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I. Background

    2. On August 18, 2014, as amended on December 17, 2014 and February 
18, 2015,\2\ PNM filed a notice of change in status notifying the 
Commission that, effective July 17, 2014, PNM purchased the interests 
in Delta Person, the owner of a 132 megawatt (MW) gas-fired generating 
facility located in the PNM balancing authority area. PNM states that 
the acquisition does not affect PNM's horizontal market power because, 
prior to the acquisition, PNM purchased the full output of the facility 
under a long-term contract with Delta Person and, as such, was already 
deemed to control the output of that facility.\3\
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    \2\ For purposes of this order, the February 18, 2015 amendment 
will be referred to as ``Response to the Data Request.''
    \3\ August 18, 2014 Filing at 1.
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    3. Additionally, PNM requests market-based rate authorization in 
the PNM balancing authority area.\4\ PNM states that the market 
characteristics in the PNM balancing authority area have changed since 
PNM relinquished its market-based rate authority in 2010 and PNM is 
therefore seeking to reestablish

[[Page 63769]]

its market-based rate authority in that balancing authority area.\5\
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    \4\ PNM states that its tariff reflects that it relinquished its 
market-based rate authority in the PNM and El Paso Electric Company 
(El Paso Electric) balancing authority areas. Id. at 3 (citing 
Public Service Company of New Mexico, Docket No. ER96-1551-022 (Oct. 
26, 2010) (delegated letter order)). PNM states that it only seeks 
to reestablish its market-based rate authority in the PNM balancing 
authority area and not in the El Paso Electric balancing authority 
area. Id. at 2 n.4.
    \5\ Id. at 4.
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    4. PNM included an updated market power analysis with its August 
18, 2014 Filing. PNM states that it passes the pivotal supplier screen 
and the wholesale market share screen in the summer season; however, 
PNM represents that it fails the wholesale market share screen in the 
winter, fall, and spring seasons. PNM notes that the failure of the 
indicative screens creates a rebuttable presumption of horizontal 
market power. However, PNM states it has rebutted that presumption by 
demonstrating that PNM passes a DPT analysis for the PNM balancing 
authority area.\6\
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    \6\ On December 17, 2014, PNM submitted public versions of its 
DPT files, explaining that it initially submitted numerous 
electronic files related to the DPT analysis on a confidential 
basis.
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    5. Additionally, PNM submitted historical evidence related to a 
request for proposal (RFP) issued by the City of Gallup, New Mexico, 
representing that PNM was not selected as the winner and that the 
results of the RFP should be considered as alternative evidence to 
rebut the presumption that PNM may have market power in the PNM 
balancing authority area.\7\
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    \7\ Id. at 12-13.
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    6. On December 19, 2014, the Director of the Division of Electric 
Power Regulation--West requested additional information from PNM with 
regard to the DPT analysis and SIL study (Data Request).\8\ On February 
18, 2015, PNM submitted a revised DPT analysis and an additional SIL 
sensitivity analysis, with revised Submittal 1 and Submittal 2 results, 
in response to the request for additional information (Response to the 
Data Request).
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    \8\ Public Service Company of New Mexico, Docket No. ER10-2302-
005 (Dec. 19, 2014) (delegated letter order). We note that on 
January 21, 2015, PNM filed a motion for an extension of time to 
file its Response to the Data Request, which was granted. See Notice 
of Extension of Time, Docket No. ER10-2302-005 (Jan. 27, 2015).
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II. Notice of Filings

    7. Notice of PNM's August 18, 2014 filing, as amended on December 
17, 2014 and on February 18, 2015, was published in the Federal 
Register,\9\ with interventions and protests due on or before March 11, 
2015. Navopache Electric Cooperative, Inc. (Navopache) filed a timely 
motion to intervene.
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    \9\ 79 FR 50,642; 79 FR 78,081 (2014); 80 FR 10,472 (2015).
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III. Discussion

A. Procedural Matters

    8. Pursuant to Rule 214 of the Commission's Rules of Practice and 
Procedure, 18 CFR 385.214 (2015), Navopache's timely, unopposed motion 
to intervene serves to make it a party to this proceeding.

B. Substantive Matters

    9. We accept PNM's notice of change in status filing. However, as 
discussed below, we reject, without prejudice, PNM's request for 
market-based rate authority in the PNM balancing authority area and 
PNM's related SIL study. We find that PNM has failed to rebut the 
presumption of horizontal market power in the PNM balancing authority 
area, and therefore, has not supported its request for market-based 
rate authority in the PNM balancing authority area. Also, as discussed 
below, we take this opportunity to identify deficiencies in PNM's DPT 
analysis and provide general clarification regarding DPT analyses and 
SIL studies. We note that our efforts to provide such clarification in 
this order are hampered by the fact that PNM's most recent February 18, 
2015 DPT analysis and SIL submittals were all filed as non-public.\10\ 
Thus, we often cite to earlier public versions of filings instead of 
the most recent non-public versions. However, unless otherwise noted, 
the discussion is applicable to the most recent non-public version as 
well.


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    \10\ We encourage filers to submit as much information as 
possible as public and only to claim confidential treatment for 
information that is exempt from mandatory disclosure under the 
Freedom of Information Act, 5 U.S.C. 552. Filers must follow the 
requirements in 18 CFR 388.112 (2015) when submitting requests for 
privileged treatment of filings.
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C. Market-Based Rate Authorization

    10. The Commission allows power sales at market-based rates if the 
seller and its affiliates do not have, or have adequately mitigated, 
horizontal and vertical market power.\11\ An applicant that fails one 
or more of the indicative screens is provided with several procedural 
options including the right to challenge the market power presumption 
by submitting a DPT analysis.\12\ As discussed in the body of this 
order, PNM's DPT analysis includes inaccurate data and modeling errors 
and is inconsistent with the Commission's regulations. The deficiencies 
pertain to the following: (i) Data integrity; (ii) identification of 
potential supply; (iii) calculation of variable costs; (iv) accounting 
for power purchase agreements; (v) calculation of transmission rates; 
(vi) calculation of available economic capacity (AEC); (vii) use of 
historical transaction data to corroborate results; and (viii) 
preparation of the SIL study.
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    \11\ See Market-Based Rates for Wholesale Sales of Electric 
Energy, Capacity and Ancillary Services by Public Utilities, Order 
No. 697, FERC Stats. & Regs. ] 31,252, at PP 62, 399, 408, 440, 
clarified, 121 FERC ] 61,260 (2007), order on reh'g, Order No. 697-
A, FERC Stats. & Regs. ] 31,268, clarified, 124 FERC ] 61,055, order 
on reh'g, Order No. 697-B, FERC Stats. & Regs. ] 31,285 (2008), 
order on reh'g, Order No. 697-C, FERC Stats. & Regs. ] 31,291 
(2009), order on reh'g, Order No. 697-D, FERC Stats. & Regs. ] 
31,305 (2010), aff'd sub nom. Mont. Consumer Counsel v. FERC, 659 
F.3d 910 (9th Cir. 2011), cert. denied, 133 S. Ct. 26 (2012).
    \12\ Order No. 697, FERC Stats. & Regs. ] 31,252 at P 63.
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1. Horizontal Market Power
    11. The Commission adopted two indicative screens for assessing 
horizontal market power: the pivotal supplier screen and the wholesale 
market share screen.\13\ The Commission has stated that passage of both 
screens establishes a rebuttable presumption that the applicant does 
not possess horizontal market power, while failure of either screen 
creates a rebuttable presumption that the applicant has horizontal 
market power.\14\
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    \13\ Id. P 62.
    \14\ Id. PP 33, 62-63.
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    12. PNM prepared the pivotal supplier and wholesale market share 
screens for the PNM balancing authority area, consistent with the 
requirements of Order No. 697.\15\ We have reviewed these and find that 
PNM passes the pivotal supplier screen and the wholesale market share 
screen in the summer season with a market share of 18.0 percent, but 
fails the wholesale market share screen in the other seasons with 
market shares ranging from 24.9 to 26.8 percent.\16\ As a result of 
failing the indicative screens in the fall, winter, and spring seasons, 
PNM submitted alternative evidence and performed a DPT analysis to 
rebut the presumption of horizontal market power in the PNM balancing 
authority area.
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    \15\ Id. PP 231-232.
    \16\ August 18, 2014 Filing, Exhibit No. JMC-3.
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    13. As the Commission has previously explained, the DPT analysis 
identifies potential suppliers based on market prices, input costs, and 
transmission availability, and calculates each supplier's economic 
capacity (EC) \17\ and

[[Page 63770]]

AEC \18\ for each season/load period.\19\ The results of the DPT can be 
used for pivotal supplier, market share and market concentration 
analyses.\20\ Under the DPT analysis, applicants must also calculate 
market concentration using the Hirschman-Herfindahl Index (HHI).\21\ An 
HHI of less than 2,500 in the relevant market for all seasons/load 
periods, in combination with a demonstration that the applicants are 
not pivotal and do not possess more than a 20 percent market share in 
any of the seasons/load periods, would constitute a showing of a lack 
of horizontal market power, absent compelling contrary evidence from 
interveners. A detailed description of the mechanics of the DPT 
analysis is provided in Order No. 697.\22\
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    \17\ The EC of a supplier is defined as ``the amount of 
generating capacity owned or controlled by a potential supplier with 
variable costs low enough that energy from such capacity could be 
economically delivered to the destination market.'' See 18 CFR 
33.3(c)(4)(i)(A) (2015).
    \18\ The Commission's regulations provide that AEC ``means the 
amount of generating capacity meeting the definition of economic 
capacity less the amount of generating capacity needed to serve the 
potential supplier's native load commitments,'' 18 CFR 
33.3(c)(4)(i)(B) (2015).
    \19\ The seasons/load periods are as follows: super-peak, peak, 
and off-peak, for winter, shoulder, and summer periods and an 
additional highest super-peak for the summer.
    \20\ See AEP Power Marketing, Inc., 107 FERC ] 61,018, at PP 
106-108 (April 14 Order), order on reh'g, 108 FERC ] 61,026 (2004).
    \21\ The HHI is the sum of the squared market shares. For 
example, in a market with five equal size firms, each would have a 
20 percent market share. For that market, HHI = (20)\2\ + (20)\2\ + 
(20)\2\ + (20)\2\ + (20)\2\ = 400 + 400 + 400 + 400 + 400 = 2,000.
    \22\ Order No. 697, FERC Stats. & Regs. ] 31,252 at PP 104-117.
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    14. As with the indicative screens, applicants and interveners may 
present evidence, such as historical sales and transmission data, which 
may be used to calculate market shares and market concentration and to 
refute or support the results of the DPT analysis. In Order No. 697, 
the Commission encouraged applicants to present the most complete 
analysis of competitive conditions in the market as the data allow.\23\
---------------------------------------------------------------------------

    \23\ Id. PP 71, 111.
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    15. PNM's DPT analysis for the PNM balancing authority area 
indicates that PNM is not pivotal in any season/load period using 
either the EC measure or the AEC measure.\24\ Using the AEC measure, 
PNM reports market shares below 20 percent in all seasons/load periods 
and HHIs below 2,500.\25\ However, using the EC measure, PNM reports 
market shares above 20 percent in all seasons/load periods and HHIs 
below 2,500.\26\
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    \24\ August 18, 2014 Filing, Carey Aff. at 27, Table 4 
(Delivered Price Test for the PNM BAA Destination Market Available 
Economic Capacity); Id., Carey Aff. at 30, Table 5 (Delivered Price 
Test for the PNM BAA Destination Market Economic Capacity). We note 
that PNM also submitted sensitivity analyses that separately 
analyzed what effect, if any, a 10 percent increase or decrease in 
market price would have on the results of its DPT analysis. Id., 
Carey Aff. at 30.
    \25\ Id., Carey Aff. at 27, Table 4.
    \26\ Id., Carey Aff. at 30, Table 5.
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a. Alternative Evidence--RFP
    16. PNM states that the Commission allows a seller to present 
alternative evidence to rebut the results of the indicative screens. 
PNM requests that the RFP results be considered as additional 
alternative evidence to rebut the presumption that PNM may have market 
power in the PNM balancing authority area.
    17. According to PNM, on September 26, 2013, the City of Gallup 
issued an RFP for long-term power supply and scheduling services for a 
minimum of five years. The RFP represents that the City of Gallup 
serves approximately 10,500 customers and averages approximately 
215,000,000 kilowatt-hours (kWh) in annual sales provided from 
wholesale energy purchases of around 220,000,000 kWh bought from PNM 
and 15,000,000 kWh from Western Area Power Administration. PNM states 
that, as the City of Gallup's existing supplier, it responded to the 
RFP. PNM further states that the City of Gallup received bids from five 
suppliers. Further, PNM represents that it was not selected as the 
winner in the RFP and ranked third in the competitiveness of its bid. 
PNM states that Continental Divide Electric Cooperative was selected as 
the winning bidder, having submitted a bid that was significantly lower 
than those submitted by either PNM or the other bidders.
    18. PNM contends that the fact that there were a number of bidders 
in the RFP, several of whose bids were lower than the bid submitted by 
PNM, in and of itself, demonstrates that PNM lacks market power in the 
PNM balancing authority area. PNM further states that this alternative 
evidence is bolstered by the fact that a neighboring utility that 
maintains market-based rate authority in the PNM balancing authority 
area also underbid PNM, making it difficult to justify the notion that 
PNM has market power. Moreover, PNM states that the RFP is significant 
recent real-world evidence that corroborates the results of its DPT 
analysis demonstrating that PNM lacks market power in the PNM balancing 
authority area.
Commission Determination
    19. Although PNM presents this RFP as alternative evidence to rebut 
the results of the indicative screens, we find that this alternative 
evidence does not sufficiently demonstrate that PNM lacks market power 
in that balancing authority area. We do not believe that the City of 
Gallup's load is a sufficient proxy for the load PNM served during the 
study period.\27\ Further, the results of the RFP may simply reflect 
that there are competitors to PNM that can provide a small amount of 
long-term power supply and scheduling services for a minimum of five 
years less expensively than PNM. However, the Commission's analysis of 
horizontal market power includes other factors, such as uncommitted 
capacity and system operating conditions during various levels of load 
in a relevant geographic market, none of which is addressed by PNM's 
alternative evidence. Thus, we are unable to conclude from the RFP 
evidence that PNM lacks horizontal market power in the PNM balancing 
authority area. Further, PNM does not provide historical sales or 
transmission data to rebut the results of the indicative screens.\28\
---------------------------------------------------------------------------

    \27\ We note that the 215,000,000 kWh translates into 
approximately 25 MW of load at a 100 percent load factor 
(215,000,000 kWh / 1,000 = 215,000 MWh; 215,000 MWh / 8,760 hours in 
a year = 24.5 MW). A load factor of 60 percent would translate into 
approximately 41 MW of annual peak load. Either amount is 
significantly less than the 2,142 MW of retail requirements, 
wholesale load obligation plus off system sales that PNM served 
during the summer peak of 2013. See id., Carey Aff. at 11. It is 
also less than the 2,563 MW PNM balancing authority annual peak 
load. See id., Exhibit No. JMC-3 at 1.
    \28\ Order No. 697, FERC Stats. & Regs. ] 31,252 at P 75.
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b. DPT Analysis
    20. In Order No. 697, the Commission provided the option for a 
seller to submit a DPT analysis when that seller fails an indicative 
screen.\29\
---------------------------------------------------------------------------

    \29\ Id. P 105.
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    21. The Commission, prior to Order No. 697, provided industry 
guidance concerning the DPT in the Merger Policy Statement.\30\ The 
Commission provided an overview of the definition of the product market 
studied by the DPT analysis, and specifically stated that a key part 
``in determining the size of the geographic market is to identify those 
suppliers that can compete to serve a given market or customer and how 
much of a competitive presence they are in the market. Alternative 
suppliers must be able to reach the market both economically and 
physically. There are two parts to this analysis. One is determining 
the economic capability of a supplier to reach a market. This is 
accomplished by a delivered price test. The second part

[[Page 63771]]

evaluates the physical capability of a supplier to reach a 
market.''\31\
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    \30\ Inquiry Concerning the Commission's Merger Policy Under the 
Federal Power Act: Policy Statement, Order No. 592, FERC Stats. & 
Regs. ] 31,044 (1996) (Merger Policy Statement), reconsideration 
denied, Order No. 592-A, 79 FERC ] 61,321 (1997).
    \31\ Id. at 31,130.
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    22. The first part of the product market analysis, that is, the 
calculation of all potential suppliers given the prevailing market 
price. The EC of a supplier is the amount of generating capacity owned 
or controlled by a potential supplier with variable costs low enough 
that energy from such capacity could be economically delivered to the 
destination market. The EC calculation can be described as follows.\32\
---------------------------------------------------------------------------

    \32\ We note that these steps are not an exhaustive list to 
perform a DPT analysis; however, these steps are provided as an 
illustration to discuss PNM's DPT analysis.
---------------------------------------------------------------------------

    23. The first step in calculating a potential supplier's EC is to 
calculate the variable cost of each unit.\33\ Commission regulations 
state that, at a minimum, these costs include variable operation and 
maintenance, including both fuel and non-fuel operation and 
maintenance, and environmental compliance. To the extent these costs 
are allocated among units at the same plant, allocation methods should 
be fully described.\34\ Any generation capacity acquired under long-
term firm purchase contracts (i.e., contracts with a remaining 
commitment of more than one year) should be added to the potential 
supplier's generation capacity.\35\ In addition, the regulations 
provide that ``other generating capacity may also be attributed to 
another supplier based on operational control criteria as deemed 
necessary, but the applicant must explain the reasons for doing so.'' 
\36\ The variable cost for contractual capacity acquired, or attributed 
to another supplier, should be calculated in the same way as generation 
owned or under the direct control of the supplier. Commission 
regulations also require that specific information on long-term 
purchase and sale data be submitted.\37\
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    \33\ Revised Filing Requirements Under Part 33 of the 
Commission's Regulations, Order No. 642, FERC Stats. & Regs. ] 
31,111, at 31,886 n.39 (2000), order on reh'g, Order No. 642-A, 94 
FERC ] 61,289 (2001).
    \34\ 18 CFR 33.3(d)(2)(i) (2015).
    \35\ 18 CFR 33.3(c)(4)(i)(A) (2015) (specifying that the 
potential supplier's capacity is adjusted by subtracting capacity 
committed under long-term firm sales contracts and adding capacity 
acquired under long-term firm purchase contracts).
    \36\ Id.
    \37\ 18 CFR 33.3(d)(3) (2015) (``Long-term purchase and sales 
data. For each sale and purchase of capacity, the applicant must 
provide the following information: (i) Purchasing entity name; (ii) 
Selling entity name; (iii) Duration of the contract; (iv) Remaining 
contract term and any evergreen provisions; (v) Provisions regarding 
renewal of the contract; (vi) Priority or degree of 
interruptibility; (vii) FERC rate schedule number, if applicable; 
(viii) Quantity and price of capacity and/or energy purchased or 
sold under the contract; and (ix) Information on provisions of 
contracts which confer operational control over generation resources 
to the purchaser.'').
---------------------------------------------------------------------------

    24. The second step is to add to the estimate of the unit's 
variable generation cost any and all applicable transmission costs that 
a supplier would incur to deliver the energy into the study area. 
Commission regulations state that these costs include the maximum 
transmission rate in a transmission provider's tariff as well as the 
estimated cost of supplying energy losses.\38\ The costs of ancillary 
services incurred to deliver the competing energy into the study area 
should also be included.\39\ These costs should be accumulated 
beginning at the source of the generation and ending where the 
generation sinks in the study area.\40\
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    \38\ 18 CFR 33.3(d)(5)(i) and 33.3(d)(5)(iii)(H) (2015).
    \39\ 18 CFR 33.3(c)(4) (2015) (``Perform delivered price test. 
For each destination market, the applicant must calculate the amount 
of relevant product a potential supplier could deliver to the 
destination market from owned or controlled capacity at a price, 
including applicable transmission prices, loss factors and ancillary 
services costs, that is no more than five (5) percent above the pre-
transaction market clearing price in the destination market.'' 
(emphasis added)).
    \40\ Merger Policy Statement, FERC Stats. & Regs. ] 31,044 at 
31,132 (``In contrast, a supplier that is three or four `wheels' 
away from the same buyer may be an economic supplier if the sum of 
the wheeling charges and the effect of losses is less than the 
difference between the decremental cost of the buyer and the price 
at which the supplier is willing to sell.'' (emphasis added)).
---------------------------------------------------------------------------

    25. The final step in calculating economically competitive capacity 
is to determine whether the computed generation cost of a unit is price 
competitive in the study area. The supplier should compare the computed 
cost of a generating unit (including all aforementioned generation, 
transmission, and other costs), to the computed market price plus five 
(5) percent in the study area.\41\ Generation with a delivered cost 
that meets all of the above conditions is referred to as the EC of that 
unit.
---------------------------------------------------------------------------

    \41\ April 14 Order, 107 FERC ] 61,018 at Appendix F 
(``[D]etermine the suppliers that could sell into the destination 
market at a price less than or equal to 5% over the market price. 
That is, determine which generators have costs less than or equal to 
1.05 times the market price.''); id., Appendix F n.216 (``The costs 
include running costs, transmission charges, [operation and 
maintenance] and environmental adders.'').
---------------------------------------------------------------------------

    26. The AEC of the units and all suppliers must also be calculated. 
AEC includes ``capacity from generating units that are not used to 
serve native load (or are contractually committed).'' \42\ Accordingly, 
AEC is the amount of generating capacity meeting the definition of 
economic capacity less the amount of generating capacity needed to 
serve the potential supplier's native load commitments, where native 
load commitments are ``commitments to serve wholesale and retail power 
customers on whose behalf the potential supplier, by statute, 
franchise, regulatory requirement, or contract, has undertaken an 
obligation to construct and operate its system to meet their reliable 
electricity needs.'' \43\ Units that are contractually committed or 
needed to serve native load or meet reliable electricity needs are not 
available to compete in a DPT analysis.
---------------------------------------------------------------------------

    \42\ Merger Policy Statement, FERC Stats. & Regs. ] 31,044 at 
31,132.
    \43\ 18 CFR 33.3(d)(4)(i) (2015).
---------------------------------------------------------------------------

    27. Furthermore, as stated in the Merger Policy Statement, the 
presumption underlying the AEC measure is that the lowest running cost 
units are used to serve native load and other firm contractual 
obligations and would not be available for other sales.\44\ Such units 
are not available to compete in the DPT analysis.
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    \44\ Merger Policy Statement, FERC Stats. & Regs. ] 31,044 at 
31,132.
---------------------------------------------------------------------------

    28. The second part of the analysis, evaluating whether generation 
with AEC can reach the study area, and the use of this information to 
compute market shares and concentration statistics, is discussed below.
    29. Turning to PNM's calculation, we find that the analysis as 
presented is flawed and from it we are unable to conclude that PNM 
rebutted the presumption of PNM's horizontal market power in the PNM 
balancing authority area. The deficiencies pertain to the following: 
(i) Data integrity; (ii) identification of potential supply; (iii) 
calculation of variable costs; (iv) accounting for power purchase 
agreements; (v) calculation of transmission rates; (vi) calculation of 
AEC; (vii) use of historical transaction data to corroborate results; 
and (viii) preparation of the SIL study. Each of these items is 
discussed further below.
PNM's Calculation of Economic Capacity
i. Data Integrity
    30. PNM submitted compact discs (CDs) that included its DPT model 
and underlying work papers with links to other data sources that are 
not available on its CDs. For instance, when opening some of the files 
on the CDs submitted on August 18, 2014 and on February 18, 2015, there 
is an error message that states ``There are links to data sources that 
cannot be updated.''
    31. We remind applicants that including workable links to data 
sources in the spreadsheets enables the

[[Page 63772]]

Commission to verify the accuracy of the data sources and to ensure the 
accuracy of the submitted DPT.
ii. Identification of Potential Supply
    32. PNM appears to have included generating units that are no 
longer operational when it calculated EC. EC is the amount of 
generating capacity owned or controlled by a potential supplier with 
variable costs low enough that energy from such capacity could be 
economically delivered to the destination market. Including, for 
example, the San Onofre Nuclear Generating Station (San Onofre) as 
operational and reporting units 2 and 3 of this plant as having EC in 
all seasons of the DPT analysis is inconsistent with the definition of 
EC.\45\ Thus, the output of generating facilities, such as San Onofre, 
that are not in operation during the seasons studied in a DPT analysis 
cannot feasibly be delivered to the destination market and should not 
be included in EC.
---------------------------------------------------------------------------

    \45\ We note that the Velocity Suite database indicates that the 
San Onofre plant units 2 and 3 last generated electricity in January 
2012, while the study period for the DPT analysis was December 2012 
through November 2013. This information is sourced from the Ventyx, 
Velocity Suite database in September 2015. We note that the San 
Onofre plant is currently in the process of decommissioning. See 
Decommissioning of San Onofre, https://www.songscommunity.com.
---------------------------------------------------------------------------

    33. Similarly, PNM identifies many units as having their output 
committed under long-term power purchase contracts, but still considers 
the units to have EC in the model. For example, PNM identifies 
Whitewater Hill Wind Partners as having EC when Whitewater Hill Wind 
Partners has affirmed to the Commission that the output of its facility 
is fully committed to an unaffiliated third party.\46\ An entity that 
does not own any uncommitted capacity or hold a long-term purchase 
contract should not be considered as a potential supplier of EC in a 
DPT analysis.\47\ In addition, PNM did not provide the information for 
these contracts as required in 18 CFR 33.3(d)(3)(i).
---------------------------------------------------------------------------

    \46\ Response to the Data Request, Workpaper ``Wkp--Suppliers 
Details.xlsx'' (Tab ``AEC By Suppliers--Base Prices''). See also 
Whitewater Hill Wind Partners, LLC, Docket No. ER02-2309-000 at 1 
(filed July 11, 2002); Whitewater Hill Wind Partners, LLC, Docket 
No. ER02-2309-000 (Aug. 29, 2002) (delegated letter order accepting 
filing). Note also that the comments in the spreadsheet submitted by 
PNM identify Whitewater Hill Wind Partners as being under a long-
term contract. There are additional cells in PNM's spreadsheets that 
identify certain generating facilities as having EC or AEC even 
though the spreadsheets also show those facilities as being under 
long-term contracts.
    \47\ We note that here we describe Whitewater Hill Wind Partners 
for illustrative purposes only, and not because it is the only 
entity listed in PNM's DPT analysis that lacks EC or AEC.
---------------------------------------------------------------------------

    34. Commission regulations require that a potential supplier's EC 
be adjusted by long-term firm contracts.\48\ Units that are committed 
to unaffiliated entities under long-term firm contracts should be 
attributed to the purchasing entities rather than the owners of those 
facilities, and should potentially be included in EC only if the 
purchasing entity has EC. Thus, the inclusion of nonoperational units 
in the DPT analysis is inappropriate and the output of facilities that 
are committed under long-term firm contracts should be attributed to 
the purchasing entities and included as EC only if the purchasing 
entity has EC. The inclusion of generation from such units distorts the 
amount of EC in the DPT analysis. This raises additional concerns that 
the DPT results may be inaccurate and unreliable.
---------------------------------------------------------------------------

    \48\ 18 CFR 33.3(c)(4)(i)(A) (2015) (``Economic capacity means 
the amount of generating capacity owned or controlled by a potential 
supplier with variable costs low enough that energy from such 
capacity could be economically delivered to the destination market. 
Prior to applying the delivered price test, the generating capacity 
meeting this definition must be adjusted by subtracting capacity 
committed under long-term firm sales contracts and adding capacity 
acquired under long-term firm purchase contracts (i.e., contracts 
with a remaining commitment of more than one year.'').
---------------------------------------------------------------------------

iii. Calculating Variable Costs
    35. As mentioned above, Commission regulations state that for each 
generating plant or unit owned or controlled by each potential supplier 
in a DPT analysis, the applicant must also provide variable cost 
components, which must include at a minimum: (A) variable operation and 
maintenance, including both fuel and non-fuel operation and 
maintenance; and (B) environmental compliance.\49\
---------------------------------------------------------------------------

    \49\ 18 CFR 33.3(d)(2)(i) (2015). Additionally, ``[t]o the 
extent costs described in paragraph (d)(2)(i) of this section are 
allocated among units at the same plant, allocation methods must be 
fully described.'' 18 CFR 33.3(d)(2)(ii) (2015).
---------------------------------------------------------------------------

Variable Cost: Fuel
    36. In its August 18, 2014 Filing, PNM states that it constructed a 
supply curve ``in the model for each entity by estimating its unit-
specific incremental dispatch costs. The incremental cost is calculated 
by multiplying the fuel cost for the unit by the unit's efficiency 
(heat rate) and adding any additional variable costs that may apply, 
i.e., costs for variable operations and maintenance and costs for 
environmental offsets.'' \50\ PNM further clarifies that ``[t]he 
characteristics for all of the units included in the analysis, 
including their estimated incremental costs, are included in work 
papers.'' \51\ PNM states that incremental costs were derived by 
multiplying unit specific heat rates (generally from the Energy 
Information Administration (EIA) Form 860 or Ventyx) by fuel prices 
(from FERC Form 423 for the Study Period, as reported by Ventyx) and 
then adding VOM and any applicable environmental adders.
---------------------------------------------------------------------------

    \50\ August 18, 2014 Filing, Carey Aff. ] 34. We note that 
``Ventyx'' is the same database as ``Velocity Suite'' also referred 
to as ``Velocity.'' In this order we use the term ``Velocity 
Suite'', except for where the term ``Ventyx'' or ``Velocity'' is 
used in direct quotes from PNM's filings. We note that the acronym 
``VOM'' used above in PNM's description of variable costs is 
generally interpreted to mean ``Variable Operations and 
Maintenance'' costs.
    \51\ August 18, 2014 Filing, Carey Aff. ] 34 n.36.
---------------------------------------------------------------------------

    37. Fuel is a significant component of variable cost, and natural 
gas- and coal-fired generation is a significant portion of the 
generation analyzed by PNM.\52\ PNM takes a number of steps to compute 
a fuel price for generators to determine whether they are economic in 
each of the 10 season/load levels. PNM appears to use natural gas price 
data from the ``ICE10x Day Ahead Gas Prices'' for the El Paso Gas 
(Permian Basin) and El Paso--South Mainline locations.\53\ Further, PNM 
appears to use EIA and Velocity Suite data to compute coal prices 
across the Western Electricity Coordinating Council (WECC) region.
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    \52\ For instance, natural gas-fired generation accounts for 28 
percent of the nameplate generation capacity in the underlying PNM 
dataset. See id., Workpaper ``Gas Prices Final.xlsx.''
    \53\ See id., Workpaper ``Gas Prices Final.xlsx'' (Tab ``Wkp--
Gas Prices''); December 17, 2014 Filing, Workpaper ``Wkp PNM DPT 
Public Inputs.xlsx'' (Tab ``Wkp--Gas Prices,'' Tab ``Wkp--Coal Spot 
Prices,'' Tab ``Wkp--Detailed Coal Transactions'').
---------------------------------------------------------------------------

    38. For natural gas, PNM computes seasonal prices at the two 
locations mentioned above by averaging all of the hourly prices for 
each location in each season/load level. These two locations seem to be 
the hubs that are closest to the PNM balancing authority area. However, 
PNM also includes in its spreadsheets hourly gas prices for 22 
locations in the WECC region.\54\ The summer average prices for the 22 
locations range from $1.88 at ``Questar North Pool'' to $3.27 at 
``PG&E-Citygate,'' a variation of almost 74 percent. Although PNM 
submitted data for 22 locations, it only used prices from the two hubs 
identified above to calculate input costs for all gas-fired generators 
in the WECC region.
---------------------------------------------------------------------------

    \54\ August 18, 2014 Filing, Workpaper ``Gas Prices Final.xlsx'' 
(Tab ``Wkp--Gas Prices'').
---------------------------------------------------------------------------

    39. Additionally, PNM uses only three natural gas prices in its 
model, one for each of the summer, winter and shoulder seasons. To do 
this, for the one-hour Summer Super Peak 1 (S_SP1)

[[Page 63773]]

season, PNM computes a price of $3.57/MMBtu at El Paso Gas (Permian 
Basin) and $3.81/MMBtu at El Paso--South Mainline. In a similar way, 
PNM calculates prices for the remaining seasons/load levels at each of 
these locations. Next, PNM calculates the average of the El Paso Gas 
(Permian Basin) and El Paso--South Mainline seasonal prices in order to 
attain 10 average seasonal natural gas prices. PNM then calculates the 
average over the four summer seasons/load levels as the summer natural 
gas price, and uses that as the natural gas price for all four summer 
seasons/load levels in its model. PNM calculates Winter and Shoulder 
seasonal natural gas prices similarly.
    40. Further, PNM submitted work papers that include an average coal 
price for 83 plants with unique EIA identification numbers. Only seven 
of these plants appear to be in the WECC region, although there are 
more than seven coal-fired plants in WECC. These average prices were 
calculated from monthly ``Detailed Coal Transactions From December 2012 
to November 2013,'' \55\ but not every plant has an average price for 
each month and some plants include more than one average price for some 
months. The average prices for the seven WECC plants range from $1.42 
to $2.52 per MMBtu, but do not account for any seasonality in coal 
prices. In its generation dataset, PNM appears to attribute the 
calculated coal price for each of the seven plants as that plant's 
input cost, but then uses the average of all seven as the input price 
for all other coal-fired generators in the WECC.
---------------------------------------------------------------------------

    \55\ December 17, 2014 Filing, Workpaper ``Wkp PNM DPT Public 
Inputs.xlsx'' (Tab ``Wkp--Detailed Coal Transactions'').
---------------------------------------------------------------------------

    41. Sellers should account for some measure of regional differences 
in fuel price. As described above, PNM used one natural gas price for 
each of the three seasons' seasonal gas price estimate for all gas-
fired generation in the entire WECC, which are derived from the average 
prices at two hubs. That is, PNM used the same natural gas fuel costs 
for generators in Alberta, Northern and Southern California and New 
Mexico even though PNM's own spreadsheets detail the locational 
variation in natural gas prices across the WECC region. As explained 
above, the fuel cost of each generating facility is one of the main 
factors in determining whether the output of that facility should be 
included as EC in a DPT analysis. Oversimplifying the variable cost 
calculations by assuming that all gas-fired generators have the same 
input cost regardless of their location may cause certain units, whose 
actual gas prices are lower than these averages, to be inappropriately 
considered uneconomic and may cause units whose actual gas prices are 
higher than these averages to be inappropriately considered economic. 
Thus, regional price variation for input fuels should be considered in 
a model that includes competing supply capacity from a large geographic 
footprint, and a generator's fuel cost should be estimated from a 
nearby price point unless the seller explains why another methodology 
is reasonable. Furthermore, we note an apparent contradiction between 
the seven coal prices used in the generation data set and the single 
coal price reported for WECC of $1.97 \56\ in the Fuel Prices Summary 
worksheet. However, as with natural gas prices, we would expect a coal-
fired generator's fuel cost to be estimated from a nearby price point 
and not an average of several price points across a region as large as 
WECC.
---------------------------------------------------------------------------

    \56\ Id., Workpaper ``Wkp PNM DPT Public Inputs.xlsx'' (Tab 
``Wkp--Fuel Prices Summary''). PNM used a price of $1.97 for Winter, 
Summer, and Shoulder season.
---------------------------------------------------------------------------

    42. For the reasons stated above, we cannot conclude that PNM has 
rebutted the presumption of market power because of the flaws in its 
analysis.
Variable Cost: Operations and Maintenance
    43. As mentioned above, Commission regulations state that sellers 
must calculate, at a minimum, variable cost for a unit used in the DPT 
analysis. For each such generating unit, the seller must also provide 
variable cost components, which include operation and maintenance 
costs.\57\
---------------------------------------------------------------------------

    \57\ 18 CFR 33.3(d)(2) (2015).
---------------------------------------------------------------------------

    44. PNM's DPT model contains a worksheet, ``Generation Dataset,'' 
that contains variable cost calculations for the WECC generators that 
PNM included in its model. There are 4,293 observations in this dataset 
and 2,118 of these observations have a zero dollar cost for VOM.\58\ We 
note that a vast majority of these observations with a zero dollar cost 
for VOM are from renewable resources.
---------------------------------------------------------------------------

    \58\ December 17, 2014 Filing, Workpaper ``Wkp PNM DPT Public 
Inputs.xlsx'' (Tab ``Generation Dataset'').
---------------------------------------------------------------------------

    45. Although the Data Request did not specifically request that PNM 
provide actual values for VOM costs, we take this opportunity to 
provide clarification to PNM and other DPT filers. Although VOM costs 
may be a small component of hourly costs, we do not expect these costs 
for most generating units to have a zero value \59\ because all 
generation technologies require maintenance or have at least some 
operational costs to produce electricity. PNM states that it uses 
Velocity Suite data in its model. We note that Velocity Suite provides 
cost estimates for various renewable generation technologies. PNM has 
not explained why it assumed a zero cost for VOM when estimates for 
this cost are available for most types of renewable generation from 
Velocity Suite.\60\
---------------------------------------------------------------------------

    \59\ We note that although EIA states that wind generation has a 
relatively small VOM cost, EIA uses a zero cost for all non 
dispatchable generation in its Annual Energy Outlook 2015 Reference 
Case model. See EIA, Levelized Cost and Levelized Avoided Cost of 
New Generation Resources in the Annual Energy Outlook 2015 (June 
2015), available at https://www.eia.gov/forecasts/aeo/pdf/electricity_generation.pdf.
    \60\ A Velocity Suite supply curve for the PNM balancing 
authority area for July 31, 2013, provides a range of VOM cost 
estimates for most types of renewable generation. Specifically, 
Velocity Suite provides a VOM in $/MWh of $1.26 to $1.56 for the 
hydro plants; $1.90 to $2.06 for photovoltaic generation; $1.25 for 
energy storage devices; and $4.79 for biomass facilities. Velocity 
Suite does not provide a VOM cost for wind generation. Velocity 
Suite states that its estimates are based on many sources of unit or 
plant data and are calculated in an internal model.
---------------------------------------------------------------------------

    46. Therefore, it appears that PNM underestimates the variable cost 
of a significant portion of generation in its DPT model, which 
potentially overestimates the amount of EC calculated in its DPT 
analysis.
iv. Accounting for Purchase Contracts
    47. As mentioned above, another step in the calculation of a 
supplier's EC is accounting for long-term firm purchase contracts. EC 
refers to ``the amount of generating capacity owned or controlled by a 
potential supplier with variable costs low enough that energy from such 
capacity could be economically delivered to the destination market.'' 
\61\ The Commission's regulations require that ``the generating 
capacity meeting this definition must be adjusted by subtracting 
capacity committed under long-term firm sales contracts and adding 
capacity acquired under long-term firm purchase contracts (i.e., 
contracts with a remaining commitment of more than one year).'' \62\ 
The regulations further provide that ``capacity associated with any 
such adjustments must be attributed to the party that has authority to 
decide when generating resources are available for operation'' and 
notes that ``other generating capacity may also be attributed to 
another supplier based on operational control criteria as deemed

[[Page 63774]]

necessary, but the applicant must explain the reasons for doing so.'' 
\63\
---------------------------------------------------------------------------

    \61\ See 18 CFR 33.3(c)(4)(i)(A) (2015).
    \62\ Id.
    \63\ Id.
---------------------------------------------------------------------------

    48. As noted above, Commission regulations require information on 
all long-term firm purchases and sales ``for each sale and purchase of 
capacity'' as part of the DPT analysis.\64\ A seller performing a DPT 
analysis should account for the purchase contracts of potential 
suppliers because the contracts may affect the competitive situation of 
a supplier in a DPT analysis. A supplier with a contractual obligation 
to sell energy or capacity may not have any AEC to be considered as 
competing in the DPT analysis. Conversely, a supplier with the 
contractual obligation to purchase supply may have excess energy and 
become a potential supplier in the DPT analysis. The determination of 
whether a supplier with purchase contracts has EC or AEC depends on a 
number of factors specific to that supplier such as the supplier's 
native load (if any), the amount of generation the supplier has to meet 
that load, including any contracts the supplier has to buy or sell 
energy or capacity, and the prevailing market price. These specific 
factors should be accounted for in a DPT analysis to determine whether 
a potential supplier with purchase contracts is a potential competitor.
---------------------------------------------------------------------------

    \64\ See 18 CFR 33.3(d)(3). See also n.37 above.
---------------------------------------------------------------------------

    49. The Data Request sought information from PNM concerning how 
certain sellers could be considered competitive suppliers for purposes 
of the DPT analysis when each of those seller's native load appeared to 
exceed its generation capacity. Specifically, PNM was asked to explain 
whether one particular supplier, Tri State Generation & Transmission 
Association Inc. (TriState), could have any uncommitted capacity to 
compete with PNM given that TriState's peak load is reported to be 
greater than its generation capacity. The Data Request did not 
specifically identify any other sellers in a similar situation to 
TriState. However, the Data Request directed PNM to identify every 
potential supplier for whom its study deducted native load obligations, 
the amount of those obligations and the source of their native load 
values.\65\ Finally, the Data Request directed PNM to adjust its model 
as needed to reflect TriState and other sellers that have load greater 
than their respective uncommitted capacity.\66\
---------------------------------------------------------------------------

    \65\ See Data Request, Question No. 5, at 4.
    \66\ See Data Request, Question No. 6, at 4.
---------------------------------------------------------------------------

    50. In its Response to the Data Request, PNM stated that there are 
differences between the reporting in the data sources that the 
Commission used to formulate its questions and the data source(s) PNM 
used in its calculation of competitive supply. PNM further added that 
TriState ``has substantial purchase agreements, including ownership in 
[WECC] output facilities that would not be tracked by Velocity.'' \67\ 
PNM did not mention any other sellers who might be in this similar 
situation.
---------------------------------------------------------------------------

    \67\ Response to the Data Request at 8.
---------------------------------------------------------------------------

    51. We appreciate PNM's Response to the Data Request but find that 
more information is necessary. While PNM provided information on 
TriState's purchasing, it did not disclose the amount of power 
purchased under these contracts that would enable TriState to meet its 
native load requirements and have sufficient generation to be a 
competitive supplier in the DPT analysis. PNM also did not meet the 
reporting requirements for long-term contracts of sales and purchases 
in 18 CFR 33.3(d)(3) for TriState or for any other suppliers, such as 
Whitewater Hill Wind Partners, whose output is fully committed under 
long-term contract to another entity. Additionally, in its Response to 
the Data Request, PNM did not indicate whether there are other 
potential suppliers with long-term contracts or adjust its model to 
reflect any other potential suppliers with native load obligations 
greater than their respective generation capacity.
    52. Generation units in a supplier's portfolio whose output is 
committed under long-term firm contracts should not be considered 
available to compete in the study area as AEC. Including such capacity 
may overstate the amount of AEC that a potential supplier can 
contribute or inaccurately attribute that capacity to the wrong 
potential supplier in a DPT analysis. Additionally, incorrectly 
attributing capacity to sellers that have sold the output of their 
facilities to unaffiliated entities under purchase power agreements 
impacts the market concentration results of the DPT analysis. Lastly, 
PNM did not adjust its model as requested in the Data Request or 
otherwise explain that such adjustment was not required. For these 
reasons, we are unable to rely on PNM's DPT analysis.
v. Transmission Rates
    53. As mentioned above, Commission regulations require a DPT 
analysis to account for any and all applicable transmission costs that 
a supplier would incur to deliver the energy into the study area and 
add these costs to the estimate of the available unit's variable 
generation cost. Commission regulations state that these costs must 
include the maximum transmission rate in a transmission provider's 
tariff as well as the estimated cost of supplying energy losses.\68\
---------------------------------------------------------------------------

    \68\ 18 CFR 33.3(d)(5) (2015).
---------------------------------------------------------------------------

    54. PNM did not include all applicable transmission costs in its EC 
calculation. In the December 17, 2014 Filing, PNM's DPT analysis used a 
universal $2.00 transmission rate for all peak periods and a $1.00 
transmission rate for all off-peak periods for all generators, 
regardless of location.\69\
---------------------------------------------------------------------------

    \69\ December 17, 2014 Filing, Workpaper ``Wkp PNM DPT Public 
Inputs.xlsx'' (Tab ``Wkp--TTC and Tx Rates'').
---------------------------------------------------------------------------

    55. In the Data Request, PNM was requested to provide the 
transmission rate schedule for the PNM balancing authority area and all 
of the balancing authority areas where competing suppliers are located, 
and to provide cites to the relevant open access transmission 
tariff(s).\70\ The Data Request asked PNM to explain if the 
transmission rates used in its DPT analysis are the maximum rates for 
the PNM balancing authority area and the balancing authority areas 
where the DPT analysis indicates there is competitively priced 
generation.\71\ Finally, the Data Request directed that, if those are 
not the maximum rates, PNM should re-run the AEC calculations to 
include the cost to traverse each balancing authority area using the 
maximum `up to' transmission rate when PNM re-runs the DPT model.\72\
---------------------------------------------------------------------------

    \70\ Data Request, Question No. 14a, at 6.
    \71\ Id., Question No. 14b, at 6-7.
    \72\ Id., Question No. 14c, at 7.
---------------------------------------------------------------------------

    56. In Response to the Data Request, PNM stated that it assumed 
transmission rates for purposes of the model because it lacks details 
on specific transmission rates for some of the WECC transmission 
providers. PNM stated that this assumption has a de minimis impact on 
the results of the analyses. PNM also provided a spreadsheet that 
identifies the 24 individual balancing authority areas in WECC, their 
minimum and maximum transmission rates, information on the rate 
schedules for these balancing authority areas and screen snapshots of 
the appropriate Open Access Same Time Information System (OASIS) Web 
sites where PNM retrieved the maximum and minimum rates.\73\
---------------------------------------------------------------------------

    \73\ See Response to the Data Request, ``WECC OATT Rates.xlsx.''
---------------------------------------------------------------------------

    57. We note that these maximum rates for the peak periods ranged 
from $1.26 to $10.02 and averaged $4.96. Likewise, the maximum rates 
for the off-peak periods ranged from $0.72 to $9.00 and averaged $3.59. 
In Response to the Data Request, PNM provided a sensitivity analysis 
that used the average of these

[[Page 63775]]

maximum transmission rates to update its DPT model.\74\ PNM complied 
with the first part of Question 14 by identifying that the $2.00 and 
$1.00 transmission rates are not the maximum rates for the peak and 
off-peak periods, respectively. PNM also identified the 24 source 
balancing authority areas and provided a link and screen snapshots of 
the OASIS Web sites for these balancing authority areas that display 
their maximum and minimum rates.
---------------------------------------------------------------------------

    \74\ See id.
---------------------------------------------------------------------------

    58. However, we find the remaining portion of PNM's Response to the 
Data Request to be unresponsive to the question asked and not in 
compliance with Commission regulations. PNM did not re-run the DPT 
analysis with the maximum rate for each balancing authority area as 
requested in the Data Request \75\ and required by Commission 
regulations.\76\ Furthermore, PNM did not calculate any additional 
costs for transmission losses or ancillary services necessary to 
deliver energy into the study area, as required by Commission 
regulations.\77\ For capacity outside of the study area, PNM did not 
consider additional transmission charges that a competing generator 
would likely incur to deliver power to the destination market. 
Therefore, we find that PNM's calculations underestimate the 
transmission cost component for most observations in its dataset and 
further compromise the results of the DPT analysis.
---------------------------------------------------------------------------

    \75\ Data Request, Question No. 14c, at 7 (``If the rates used 
in your model are not the maximum rate, please re-run your AEC 
calculations using the maximum `up to' transmission rate to include 
the cost to traverse each balancing authority when you re-run your 
DPT model.'').
    \76\ 18 CFR 33.3(d)(5) (2015).
    \77\ 18 CFR 33.3(d)(5) (2015).
---------------------------------------------------------------------------

vi. Calculation of AEC
    59. As mentioned above, alternative suppliers should be able to 
reach the market both economically and physically.\78\ First, we 
discuss how to determine the AEC of a supplier.
---------------------------------------------------------------------------

    \78\ Merger Policy Statement, FERC Stats. & Regs. ] 31,044 at 
30,130.
---------------------------------------------------------------------------

    60. After computing the EC of potential competing suppliers, an 
applicant should compute the AEC of those suppliers. AEC is ``the 
amount of generating capacity meeting the definition of EC less the 
amount of generating capacity needed to serve the potential supplier's 
native load commitments.'' \79\ We note that the Commission has relied 
more heavily on AEC in the DPT analysis when utilities have significant 
native load.\80\ Further, in Order No. 697, the Commission stated that 
``in markets where utilities retain significant native load 
obligations, an analysis of available economic capacity may more 
accurately assess an individual seller's competitiveness, as well as 
the overall competitiveness of a market, because available economic 
capacity recognizes the native load obligations of the sellers.'' \81\
---------------------------------------------------------------------------

    \79\ 18 CFR 33.3(c)(4)(i)(B) (2015).
    \80\ Great Plains Energy, Inc., 121 FERC ] 61,069, at P 34 & 
n.44 (2007), reh'g denied, 122 FERC ] 61,177 (2008); Nat'l Grid, 
plc, 117 FERC ] 61,080, at PP 27-28 (2006), reh'g denied, 122 FERC ] 
61,096 (2008); Westar Energy, Inc., 115 FERC ] 61,228, at P 72, 
reh'g denied, 117 FERC ] 61,011, at P 39 (2006); Nev. Power Co., 113 
FERC ] 61,265, at P 15 (2005).
    \81\ Order No. 697, FERC Stats. & Regs. ] 31,252 at P 112.
---------------------------------------------------------------------------

    61. The Data Request directed PNM to explain whether its DPT model 
first allocated the lowest running cost units to a supplier's native 
load and cited to the Merger Policy Statement.\82\ In Response to the 
Data Request, PNM stated, in part, that ``[t]he model implicitly 
allocates PNM's lowest running cost units to serve native load for PNM 
and non-PNM suppliers to their native load (non-PNM load) by the 
derivation of the [AEC]. The DPT model does not rank order each 
supplier's generating units from lowest to highest running cost but 
rather aggregates all [EC] for each supplier within the seasonal/load 
periods analyzed.'' \83\
---------------------------------------------------------------------------

    \82\ Data Request, Question No. 4, at 3 (``In the [AEC] 
calculation, please explain whether the model first allocates PNM's 
lowest running cost units to serve native load for PNM. Please 
explain whether the model allocates the lowest running cost units of 
non-PNM suppliers to their native load (non-PNM load).''). The Data 
Request noted that ``AEC includes `capacity from generating units 
that are not used to serve native load (or are contractually 
committed) and whose variable costs are such that they could deliver 
energy to a market at a price close to the competitive price in the 
market. The presumption underlying this measure is that the lowest 
running cost units are used to serve native load and other firm 
contractual obligations and would not be available for other 
sales.''' Data Request, Question No. 4 n.6, at 3 (citing Merger 
Policy Statement, FERC Stats. & Regs. ] 31,044 at 30,132).
    \83\ Response to the Data Request at 7.
---------------------------------------------------------------------------

    62. In the Merger Policy Statement, the Commission stated that the 
AEC measure ``includes capacity from generating units that are not used 
to serve native load (or are contractually committed).'' \84\ However, 
PNM stated that ``[t]he DPT model does not rank order each supplier's 
generating units from lowest to highest running cost but rather 
aggregates all economic capacity for each supplier within the seasonal/
load periods analyzed.'' \85\ Further, it is unclear how PNM's model 
might implicitly allocate an entity's lowest running cost units to 
serve its native load. Based on this response, we conclude that PNM did 
not allocate the lowest cost units of itself and its competitors to 
serve their respective native load. Therefore, we are unable to rely on 
the reported results of potential competitive AEC suppliers and whether 
they accurately reflect the costs of the competitive generation in the 
market.
---------------------------------------------------------------------------

    \84\ Merger Policy Statement, FERC Stats. & Regs. ] 31,044 at 
30,132.
    \85\ Response to the Data Request at 7 (emphasis added).
---------------------------------------------------------------------------

vii. Historical Transaction Data to Corroborate Results
    63. Commission regulations state that ``[t]he applicant must 
provide historical trade data and historical transmission data to 
corroborate the results of the horizontal Competitive Analysis 
Screen.'' \86\ Commission regulations also state that the applicant 
must provide data and information used in calculating the EC and AEC 
that a potential supplier could deliver to a destination market, 
including transmission capability, transmission constraints and firm 
transmission rights.\87\ Further, Commission direction has been to 
provide a ``trade data check'' to support the results of the DPT 
analysis.\88\
---------------------------------------------------------------------------

    \86\ 18 CFR 33.3(c)(6) (2015).
    \87\ See 18 CFR 33.3(d)(7)-(9) (2015).
    \88\ See Merger Policy Statement, FERC Stats. & Regs. ] 31,044 
at 30,133 (``It would be expected that there be some correlation 
between the suppliers included in the market by the delivered price 
test and those actually trading in the market. As a check, actual 
trade data should be used to compare actual trade patterns with the 
results of the delivered price test. For example, it may be 
appropriate to include current trading partners in the relevant 
market even if the above analysis indicates otherwise.'').
---------------------------------------------------------------------------

    64. The Data Request directed PNM to identify suppliers with AEC 
and document their contribution to competing supply entering the PNM 
study area.\89\ In its Response to the Data Request, PNM provided a 
spreadsheet that complied with the request by identifying all 
generation units, their location, and the identity of the suppliers 
with non-zero contribution to the AEC calculation.\90\
---------------------------------------------------------------------------

    \89\ Data Request, Question No. 15, at 7 (``Please provide the 
following information for each supplier with a non-zero contribution 
to the available economic capacity in the study area of your model: 
the full name of each supplier, the name of the unit(s) that 
supplied the energy, the amount of energy supplied by each unit(s) 
in megawatts and the balancing authority area location of the 
unit(s) for each of the 10 load level/study periods.'' (footnote 
omitted)).
    \90\ Response to the Data Request at 12 & Workpaper ``Wkp--
Suppliers Details.xlsx.''
---------------------------------------------------------------------------

    65. Although the Data Request did not specifically ask PNM to 
provide historical transaction data to corroborate the results of its 
DPT analysis, we take this opportunity to provide clarification for PNM 
and others who may file a DPT

[[Page 63776]]

analysis in a section 205 proceeding in order to rebut the presumption 
of market power. PNM did not submit historical transaction data or 
transmission data to corroborate the results of its model as required 
by 18 CFR 33.3(c)(6). For example, although PNM indicates in its 
Response to the Data Request that its model includes significant 
generation capacity from the California Independent System Operator 
Corporation (CAISO) market as available to compete in the PNM balancing 
authority area, PNM did not submit historical transaction data or 
transmission data to corroborate this. PNM could have submitted eTag 
data to demonstrate flows from CAISO were consistent with its DPT 
model. Moreover, the Commission's review of eTag data was not able to 
corroborate PNM's results. Without such information, we are concerned 
that the amount of competing generation capacity imported into the PNM 
study area in PNM's DPT analysis is not supported by historical trade 
or transmission data and is overstated. We remind DPT filers that they 
should provide historical trade and transmission data and explain 
significant discrepancies between modeling results and such data.
viii. SIL Study
    66. As mentioned above, alternative suppliers must be able to reach 
the market both economically and physically. We provide clarification 
regarding determining the physical capability of a supplier with EC and 
AEC to reach the study area.\91\
---------------------------------------------------------------------------

    \91\ In this order, we do not discuss the ultimate DPT 
calculations, combining the economic and physical analyses to create 
market share and concentration indices because we do not believe 
that the first two steps of the PNM DPT analysis provide a 
reasonable foundation to examine this final step.
---------------------------------------------------------------------------

    67. The physical ability of a supplier to reach the market or study 
area requires the use of a SIL study as a basis for transmission access 
for both the indicative screens and the DPT analysis.\92\ In Order No. 
697, the Commission clarified that the SIL study as shown in Appendix E 
of the April 14 Order is the only study that meets the Commission's 
requirements for the DPT analysis and the indicative screens.\93\ In 
the April 14 Order, the Commission set the amount of supply that can 
reach the relevant market as uncommitted capacity limited by the 
simultaneous transmission import capability.\94\ In Puget Sound Energy, 
Inc., the Commission consolidated and clarified its direction regarding 
SIL studies given in previous orders and provided required formats for 
submitting SIL data.\95\ Specifically, the Commission directed filers 
to submit their SIL data in the format provided in Appendix B of Puget 
in order to properly summarize and document their SIL study 
results.\96\
---------------------------------------------------------------------------

    \92\ Order No. 697, FERC Stats. & Regs. ] 31,252 at P 19.
    \93\ Id. (``With regard to [SILs], the Commission adopts the 
requirement that the SIL study be used as a basis for transmission 
access for both the indicative screens and the DPT analysis. 
Further, the Commission clarifies that the SIL study as shown in 
Appendix E of the April 14 Order is the only study that meets our 
requirements.'').
    \94\ April 14 Order, 107 FERC ] 61,018 at Appendix E.
    \95\ Puget Sound Energy, Inc., 135 FERC ] 61,254 (2011) (Puget).
    \96\ Submittal 1 of Appendix B of Puget contains a summary table 
of components used to calculate SIL values and provides a 
spreadsheet format with numerical examples. Submittal 2 provides a 
spreadsheet for identification of long-term firm transmission 
reservations used to import power from seller and affiliate 
generating resources in a first-tier area to serve native load in 
the study area.
---------------------------------------------------------------------------

    68. The SIL study calculates the aggregated simultaneous transfer 
capability into the balancing authority area being studied. It is 
intended to provide a reasonable simulation of historical conditions 
and is not a theoretical maximum import capability or best import case 
scenario.\97\ A simplified view of the SIL study is that it 
simultaneously increases generator output in one area, the first-tier, 
and decreases generator output in another area, the study area. As the 
source of generation is incrementally shifted, single contingency 
conditions are tested in both areas while the relevant transmission 
elements are monitored for overloads.\98\ A ``single contingency 
condition'' is the unexpected failure of a single system component, 
such as a generator, transmission line, circuit breaker, switch or 
other electrical equipment.\99\ The Commission direction has been to 
increase or ``scale up available generation in the exporting 
(aggregated first tier areas) and scale down the study area resources 
according to the same methods used historically in assessing available 
transmission for non-affiliate resources.'' \100\
---------------------------------------------------------------------------

    \97\ Puget, 135 FERC ] 61,254 at Appendix B (citing Order No. 
697, FERC Stats. & Regs. ] 31,252 at P 354).
    \98\ See, e.g., Puget, 135 FERC ] 61,254, Appendix B, Sec.  I.D 
(Prior Commission Direction on Scaling).
    \99\ Id. Appendix B (citing Carolina Power & Light Co., 128 FERC 
] 61,039, at P 8 n.7 (2009)).
    \100\ April 14 Order, 107 FERC ] 61,018 at Appendix E.
---------------------------------------------------------------------------

    69. The Commission recognizes that it is a complex process for a 
seller to estimate transmission capability using the model of its 
transmission system in a simplified manner so that elements are 
accurately accounted for in SIL studies. Therefore, the Commission 
previously has provided guidance so that sellers can more accurately 
measure the amount of available transmission capability into the study 
area. One area of concern has been the proper modeling and scaling of 
jointly-owned generating plants in a SIL study, particularly when units 
have long-term firm transmission reservations.\101\ The Commission has 
determined that these remote plants should be dispatched at their 
historical output levels and should not be scaled down as doing so 
would be unrealistic and inconsistent with historical practices.\102\
---------------------------------------------------------------------------

    \101\ A long-term firm transmission reservation is a reservation 
that is 28 days or longer. See Order No. 697, FERC Stats. & Regs. ] 
31,252 at P 368 (``While we find that firm transmission reservations 
less than or equal to 28 days in duration are usually unpredictable, 
we believe that firm transmission reservations of a longer duration 
are not related to the unpredictable nature of real time events and 
are based upon planned and predictable events. Therefore, the 
Commission will require sellers to account for firm and network 
transmission reservations having a duration of longer than 28 
days.'').
    \102\ See Pinnacle West Capital Corp., 117 FERC ] 61,316, at P 6 
(2006) (Pinnacle West).
---------------------------------------------------------------------------

    70. In Pinnacle West,\103\ the Commission identified errors and 
provided guidance and clarification as to how the SIL study should be 
revised to satisfy the Commission's requirements. The PNM SIL study 
presents issues similar to those presented by the SIL study at issue in 
Pinnacle West. With regard to the PNM SIL study, the Data Request noted 
that some units within the study area have long-term firm commitments 
to serve load outside of the study area. The Data Request noted that 
the Commission expects that any such unit's generation that has been 
committed with long-term firm transmission reservations would be 
considered unavailable for scaling; however, it appears that some such 
units were scaled down during the SIL study. Therefore, the Data 
Request required PNM to identify all generation units within the PNM 
balancing authority area that have long-term firm transmission 
reservations (to serve study area load or to export power to the first-
tier), describe whether the unit's output level was either maintained 
or scaled in the SIL study, and adjust the SIL study as necessary.\104\
---------------------------------------------------------------------------

    \103\ Id. P 3.
    \104\ Data Request, Question No. 2, at 2 (citing Pinnacle West, 
117 FERC ] 61,316 at P 6; April 14 Order, 107 FERC ] 61,018 at 
Appendix E).
---------------------------------------------------------------------------

    71. In its Response to the Data Request, PNM filed revised work 
papers and SIL information. PNM also submitted a table listing the 
long-term firm transmission reservations for exports out of the PNM 
balancing

[[Page 63777]]

authority area and the corresponding source generator within the study 
area. This table indicates that these generation units are jointly-
owned by PNM and other entities, and that the non-PNM owned portions of 
these units are committed with long-term firm transmission reservations 
to export out of the study area (i.e., the PNM balancing authority 
area). However, based on the power flow models submitted by PNM in the 
original SIL study, it is evident that PNM scaled down these jointly-
owned generation units, including portions belonging to other 
owners.\105\ In addition, PNM provided Submittal 1 and Submittal 2 
tables which reported the results of two sensitivities that PNM 
conducted in response to the scaling guidance in the Data Request.
---------------------------------------------------------------------------

    \105\ August 18, 2014 Filing, Stahlhut Aff. Exhibit JWS-3.
---------------------------------------------------------------------------

    72. PNM's first sensitivity study ``does not scale resources with 
potential commitments outside of the PNM [balancing authority area].'' 
\106\ The second sensitivity ``scales half of the resources with 
potential commitments outside of the PNM [balancing authority area].'' 
\107\ However, for both sensitivities, PNM stated that ``the associated 
export reservations are recognized as long-term firm commitments to be 
consistent and reflect the equal but opposite effect to import 
reservations and compensate for prematurely limiting the imports below 
the physical limit of the transmission system or load within the study 
area. The export reservations are reflected in the SIL sensitivity 
analyses by inclusion in Table 2 [of Submittal 2].'' \108\
---------------------------------------------------------------------------

    \106\ Response to the Data Request at 3. We interpret PNM's 
language ``resources with potential commitments'' to mean the long-
term firm transmission reservations capacity or export reservations 
of the units within the PNM balancing authority area that have long-
term firm transmission reservations to serve load in the first tier.
    \107\ Id. at 4.
    \108\ Id. at 3-4.
---------------------------------------------------------------------------

    73. The practice of capturing long-term firm export reservations in 
Submittal 2 is inconsistent with the instructions and purpose of 
Submittal 2, which is to identify and sum the long-term firm 
transmission reservations from affiliated remote generating resources 
in the first-tier to serve native load in the study area.\109\ Export 
reservations are long-term firm transmission reservations from the 
study area to the first-tier to serve first-tier load; because the 
exports are commitments from capacity that belongs to the first-tier, 
these export reservations should not be captured in Submittal 2. As 
such, the Commission cannot utilize these sensitivities as support for 
PNM's SIL study. Furthermore, while the scaling method used in the 
first sensitivity is consistent with guidance given in the Data 
Request, the ownership and commitments of the generation units was not 
apparent in the original August 18, 2014 Filing or the December 17, 
2014 Filing. Thus, we believe that further clarification is warranted 
on the modeling and treatment of jointly-owned units in SIL studies.
---------------------------------------------------------------------------

    \109\ Puget, 135 FERC ] 61,254, at Appendix B, Sec.  II.B.
---------------------------------------------------------------------------

    74. In Puget, the Commission stated that ``[i]n the case of 
jointly-owned power plants, the plant's capacity should be allocated 
among the generator owners' balancing authority areas according to its 
ownership percentages.'' \110\ Additionally, the Commission has stated 
that a seasonal benchmark case model should simulate historical 
seasonal conditions that were present during the modeled season. The 
Commission has stated that ``[a]ny generating units owned by the study 
area utility that are located in the first-tier area, including the 
study area utility's portion of jointly-owned units[,] should be 
modeled . . . in the first-tier area.'' \111\ In addition, ``any long-
term reservations from these facilities used to serve study area native 
load shall be included in the study area net area interchange.'' \112\ 
While this statement references jointly-owned generating units located 
in the first-tier area, we believe that it is reasonable to treat 
jointly-owned generating units located within the study area committed 
to serving first-tier load similarly. As portions of these units belong 
to unaffiliated entities located in the first-tier area, they should 
not be scaled down; doing so would misrepresent the incremental 
transfer capability of the study area by reducing generation that 
actually has commitments to first-tier load.\113\ This has the effect 
of allowing more first-tier generation into the study area than is 
actually available to be displaced in the study area.
---------------------------------------------------------------------------

    \110\ Id. P 18.
    \111\ Id., Appendix B, II.D at 4.3.7.
    \112\ Id.
    \113\ See id., Appendix B, Sec.  II.D (Submittal 4: Seasonal 
Benchmark Case) (4.3.7 and 4.3.8 discuss how jointly-owned units 
should be modeled according to historical dispatch).
---------------------------------------------------------------------------

    75. Thus, we clarify that, for purposes of generation scaling for 
the SIL, the appropriate method of modeling a generation unit in the 
study area that is jointly-owned between the seller and one or more 
unaffiliated sellers in the first-tier area is to represent the unit as 
multiple units in the model based on ownership percentage such that the 
multiple units fully represent the generation commitments and impacts 
on the transmission system. One unit will represent the seller's 
generation capacity in the study area, and one or more additional units 
will represent the capacity owned by unaffiliated entities within the 
first-tier area.\114\ The seller's unit will remain modeled within the 
study area balancing authority area while the portion of the unit(s) 
belonging to unaffiliated first-tier sellers will be given the 
appropriate first-tier balancing authority area number in the model. 
Importantly, we note that this method retains the same physical 
location of the unit within the transmission network as modeled; 
however, the portion of the unit(s) belonging to the unaffiliated 
first-tier sellers would not be considered a study area generator for 
purposes of calculating net area interchange. We also note that with 
this method, the seller's generation capacity can appropriately be 
scaled down, and the portion of the unit(s) belonging to the 
unaffiliated first-tier sellers now modeled in the first-tier area can 
appropriately be scaled up to serve study area load if it is not 
committed under long-term firm transmission reservations. Additionally, 
any generating resources in the first-tier with long-term firm 
transmission reservations to serve study area load should be reported 
as a long-term firm transmission reservation in Submittal 2.\115\ 
Furthermore, entities are required to ``[p]rovide a listing of first-
tier area generating units and portions of jointly-owned first-tier 
area generating units to be scaled-up in the first-tier area, including 
any first-tier area generation or portions of jointly-owned first-tier 
area generating units physically located within the study area, 
according to the same methods used historically in assessing available 
transmission for non-affiliate resources.'' \116\ Entities should 
identify their jointly-owned units, report the ownership breakdown, and 
indicate what scaling, if any, was utilized for each portion of the 
generator.
---------------------------------------------------------------------------

    \114\ In Puget, the Commission approved NorthWestern's use of 
this general method to represent the jointly-owned Colstrip plant. 
The model represented separate generators for each owner, each with 
one owner's portion of Colstrip's total capacity. Id. P 18.
    \115\ Id., Appendix B, II.B, Instruction 3.
    \116\ Id., Appendix B, II.G (Submittal 7: The Sub-System File) 
(7.2.1).
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    76. Finally, we clarify that entities should complete the 
``Description of Remote Resources'' column as necessary

[[Page 63778]]

in each row of Submittal 2.\117\ We expect that, at a minimum, entities 
will indicate the balancing authority area from which these remote 
resources are sourced.
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    \117\ Id., Appendix B, II.B (Submittal 2: Identification of 
Long-Term Firm Transmission Reservations used to Import Power for 
Generating Resources in the First-Tier Area to Serve Native Load in 
the Study Area) (Instruction 2).
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Conclusion
    77. As described above, we are unable to validate the results of 
PNM's SIL model, its calculations of EC and AEC, and its DPT analysis. 
Thus, we find that PNM has not adequately rebutted the presumption of 
horizontal market power caused by its failure of the indicative screens 
in the PNM balancing authority area. Therefore, we reject, without 
prejudice, PNM's request for market-based rate authorization in the PNM 
balancing authority area. We encourage other market-based rate 
applicants to make use of the guidance and clarification offered 
herein.

D. Notice of Change in Status

    78. PNM states that its purchase of Delta Person does not affect 
PNM's horizontal market power because PNM was already deemed to control 
the output of the Delta Person facility under a long-term contract with 
Delta Person.\118\ In its most recent updated market power analysis for 
the Southwest region, PNM studied Delta Person's generation in the 
first-tier balancing authority areas in which PNM has market-based rate 
authority.\119\
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    \118\ August 18, 2014 Filing at 1.
    \119\ Public Service Company of New Mexico, Docket No. ER10-
2302-004 (Aug. 22, 2014) (delegated letter order). PNM has market-
based rate authority in seven first-tier balancing authority areas 
to the PNM balancing authority area. These balancing authority areas 
are Southwestern Public Service Company, Western Area Power 
Administration-Colorado Missouri, Western Area Power 
Administration--Lower Colorado, Public Service Company of Colorado, 
Arizona Public Service Company, Salt River Project, and Tucson 
Electric Power Company.
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    79. Based on PNM's representations, we find that PNM satisfies the 
Commission's requirements for market-based rates regarding horizontal 
market power in all balancing authority areas in which PNM currently 
has market-based rate authority, i.e., outside of the PNM and El Paso 
Electric balancing authority areas.
    80. PNM represents that of it and its affiliates, only PNM owns or 
controls transmission facilities subject to Commission jurisdiction. 
PNM states that open access to these transmission facilities is 
provided pursuant to the terms of PNM's Open Access Transmission Tariff 
on file with the Commission.\120\ Further, PNM represents that neither 
it nor any affiliate owns or controls intrastate natural gas 
transportation, storage, or distribution facilities. PNM represents 
that it owns several sites that may be used for generation capacity 
development including sites in which PNM has existing facilities. PNM 
states that it currently has plans to develop new generation at or near 
the San Juan Generating Station in the PNM balancing authority area. 
Additionally, PNM states that it holds one undeveloped site near 
Albuquerque, New Mexico.
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    \120\ Public Service Company of New Mexico, FERC FPA Electric 
Tariff, PNM Open Access Transmission Tariff.
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    81. PNM states that it purchases coal under various long-term 
agreements but does not currently own any coal mines or mineral rights. 
PNM represents that these coal purchase contracts are used exclusively 
to supply coal to power plants owned and operated by PNM.
    82. Finally, PNM states that it has not erected barriers to entry 
into the relevant market, the PNM balancing authority area, and will 
not erect barriers to entry into the relevant market.
    83. Based on PNM's representations, we find that PNM satisfies the 
Commission's requirements for market-based rates regarding vertical 
market power.
    84. Based on PNM's satisfaction of the Commission's requirements 
for market-based authorization regarding horizontal and vertical market 
power in the markets where it has market-based rate authority, we 
accept PNM's notice of change in status.

E. Reporting Requirements

    85. An entity with market-based rate authorization must file an 
Electric Quarterly Report (EQR) with the Commission, consistent with 
Order Nos. 2001 \121\ and 768,\122\ to fulfill its responsibility under 
section 205(c) \123\ of the Federal Power Act to have rates on file in 
a convenient form and place.\124\ PNM must file EQRs electronically 
with the Commission consistent with the procedures set forth in Order 
No. 770.\125\ Failure to timely and accurately file an EQR is a 
violation of the Commission's regulations for which PNM may be subject 
to refund, civil penalties, and/or revocation of market-based rate 
authority.\126\
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    \121\ Revised Public Utility Filing Requirements, Order No. 
2001, FERC Stats. & Regs. ] 31,127, reh'g denied, Order No. 2001-A, 
100 FERC ] 61,074, reh'g denied, Order No. 2001-B, 100 FERC ] 
61,342, order directing filing, Order No. 2001-C, 101 FERC ] 61,314 
(2002), order directing filing, Order No. 2001-D, 102 FERC ] 61,334, 
order refining filing requirements, Order No. 2001-E, 105 FERC ] 
61,352 (2003), order on clarification, Order No. 2001-F, 106 FERC ] 
61,060 (2004), order revising filing requirements, Order No. 2001-G, 
120 FERC ] 61,270, order on reh'g and clarification, Order No. 2001-
H, 121 FERC ] 61,289 (2007), order revising filing requirements, 
Order No. 2001-I, FERC Stats. & Regs. ] 31,282 (2008).
    \122\ Electricity Mkt. Transparency Provisions of Section 220 of 
the Fed. Power Act, Order No. 768, FERC Stats. & Regs. ] 31,336 
(2012), order on reh'g, Order No. 768-A, 143 FERC ] 61,054 (2013).
    \123\ 16 U.S.C. 824d(c) (2012).
    \124\ See Revisions to Electric Quarterly Report Filing Process, 
Order No. 770, FERC Stats. & Regs. ] 31,338, at P 3 (2012) (citing 
Order No. 2001, FERC Stats. & Regs. ] 31,127 at P 31).
    \125\ Order No. 770, FERC Stats. & Regs. ] 31,338.
    \126\ The exact filing dates for these reports are prescribed in 
18 CFR 35.10b (2015). Forfeiture of market-based rate authority may 
require a new application for market-based rate authority if the 
applicant wishes to resume making sales at market-based rates.
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    86. PNM must timely report to the Commission any change in status 
that would reflect a departure from the characteristics the Commission 
relied upon in granting market-based rate authority.\127\
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    \127\ Reporting Requirement for Changes in Status for Public 
Utilities with Market-Based Rate Authority, Order No. 652, FERC 
Stats. & Regs. ] 31,175, order on reh'g, 111 FERC ] 61,413 (2005); 
18 CFR 35.42 (2015).
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    87. Additionally, PNM must file an updated market power analysis 
for all regions in which it is designated as a Category 2 seller in 
compliance with the regional reporting schedule adopted in Order No. 
697.\128\ The Commission also reserves the right to require such an 
analysis at any intervening time.
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    \128\ Order No. 697, FERC Stats. & Regs. ] 31,252 at PP 848-850.
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    The Commission orders:
    (A) PNM's notice of change in status is hereby accepted for filing, 
as discussed in the body of this order.
    (B) PNM's request for market-based authority in the PNM balancing 
authority area is hereby rejected, without prejudice, as discussed in 
the body of this order.
    (C) PNM's SIL study is hereby rejected, without prejudice, as 
discussed in the body of this order.
    (D) The Secretary is hereby directed to publish a copy of this 
order in the Federal Register.

    By the Commission.

    Issued: October 15, 2015.
Kimberly D. Bose,
Secretary.
[FR Doc. 2015-26724 Filed 10-20-15; 8:45 am]
BILLING CODE 6717-01-P

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