80 FR 63768 - 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
DEPARTMENT OF ENERGY
Federal Energy Regulatory Commission Federal Register Volume 80, Issue 203 (October 21, 2015)
Federal Energy Regulatory Commission
Federal Register Volume 80, Issue 203 (October 21, 2015)
| Page Range | 63768-63778 | |
| FR Document | 2015-26724 |
[Federal Register Volume 80, Number 203 (Wednesday, October 21, 2015)] [Notices] [Pages 63768-63778] From the Federal Register Online [www.thefederalregister.org] [FR Doc No: 2015-26724] ----------------------------------------------------------------------- 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. --------------------------------------------------------------------------- \1\ The related acquisition of jurisdictional facilities was authorized by the Commission in Delta Person, Limited Partnership, 142 FERC ] 62,155 (2013). --------------------------------------------------------------------------- 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\ --------------------------------------------------------------------------- \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. --------------------------------------------------------------------------- 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\ --------------------------------------------------------------------------- \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. --------------------------------------------------------------------------- 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\ --------------------------------------------------------------------------- \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. --------------------------------------------------------------------------- 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\ --------------------------------------------------------------------------- \7\ Id. at 12-13. --------------------------------------------------------------------------- 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). --------------------------------------------------------------------------- \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). --------------------------------------------------------------------------- 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. --------------------------------------------------------------------------- \9\ 79 FR 50,642; 79 FR 78,081 (2014); 80 FR 10,472 (2015). --------------------------------------------------------------------------- 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. --------------------------------------------------------------------------- \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. --------------------------------------------------------------------------- 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. --------------------------------------------------------------------------- \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. --------------------------------------------------------------------------- 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\ --------------------------------------------------------------------------- \13\ Id. P 62. \14\ Id. PP 33, 62-63. --------------------------------------------------------------------------- 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. --------------------------------------------------------------------------- \15\ Id. PP 231-232. \16\ August 18, 2014 Filing, Exhibit No. JMC-3. --------------------------------------------------------------------------- 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\ --------------------------------------------------------------------------- \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. --------------------------------------------------------------------------- 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. --------------------------------------------------------------------------- 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\ --------------------------------------------------------------------------- \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. --------------------------------------------------------------------------- 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. --------------------------------------------------------------------------- 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. --------------------------------------------------------------------------- 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\ --------------------------------------------------------------------------- \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. --------------------------------------------------------------------------- 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\ --------------------------------------------------------------------------- \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\ --------------------------------------------------------------------------- \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. --------------------------------------------------------------------------- \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, http://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. --------------------------------------------------------------------------- \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 http://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). --------------------------------------------------------------------------- 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. --------------------------------------------------------------------------- \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). --------------------------------------------------------------------------- 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\ --------------------------------------------------------------------------- \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. --------------------------------------------------------------------------- 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. --------------------------------------------------------------------------- \120\ Public Service Company of New Mexico, FERC FPA Electric Tariff, PNM Open Access Transmission Tariff. --------------------------------------------------------------------------- 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\ --------------------------------------------------------------------------- \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. --------------------------------------------------------------------------- 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\ --------------------------------------------------------------------------- \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). --------------------------------------------------------------------------- 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. --------------------------------------------------------------------------- \128\ Order No. 697, FERC Stats. & Regs. ] 31,252 at PP 848-850. --------------------------------------------------------------------------- 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
![63768 Federal Register / Vol. 80, No. 203 / Wednesday, October 21, 2015 / Notices
Description: Notice of Self- Accession Number: 20151008–5001. Also in this order, we reject, without
Certification of Exempt Wholesale Comments Due: 5 p.m. ET 10/29/15. prejudice, PNM’s request for market-
Generator Status of Seville Solar Two, Docket Numbers: ER16–35–000. based rate authority in the PNM
LLC. Applicants: Brown’s Energy Services, balancing authority area and we reject,
Filed Date: 10/8/15. LLC. without prejudice, the simultaneous
Accession Number: 20151008–5087. Description: Baseline eTariff Filing: transmission import limit (SIL) values
Comments Due: 5 p.m. ET 10/29/15. Market Based Rate Tariff to be effective submitted by PNM for the PNM
Take notice that the Commission 11/5/2015. balancing authority area. We take this
received the following electric rate Filed Date: 10/8/15. opportunity to remind applicants
filings: Accession Number: 20151008–5002. seeking initial market-based rate
Docket Numbers: ER10–2331–040; Comments Due: 5 p.m. ET 10/29/15. authority or seeking to retain such
ER14–630–017; ER10–2319–032; ER10– The filings are accessible in the authority of the type of information and
2317–032; ER13–1351–014; ER10–2330– Commission’s eLibrary system by analysis that is useful and appropriate
039. for our consideration of a Delivered
clicking on the links or querying the
Applicants: J.P. Morgan Ventures Price Test (DPT) and what is not. We are
docket number.
Energy Corporation, AlphaGen Power providing this information not only to
Any person desiring to intervene or
LLC, BE Alabama LLC, BE CA LLC, PNM but to industry broadly with
protest in any of the above proceedings
Florida Power Development LLC, Utility respect to several issues that arose in
must file in accordance with Rules 211
Contract Funding, L.L.C. our review of the DPT analysis and SIL
and 214 of the Commission’s
Description: Notice of Non-Material study prepared by PNM. These issues,
Regulations (18 CFR 385.211 and
Change in Status of the J.P. Morgan as with others, are recurring across a
385.214) on or before 5:00 p.m. Eastern
Sellers. myriad of applicants. Our goal in
time on the specified comment date.
Filed Date: 10/7/15. providing this clarification is to promote
Protests may be considered, but compliance with the Commission’s
Accession Number: 20151007–5156. intervention is necessary to become a
Comments Due: 5 p.m. ET 10/28/15. regulations and policies in an effort to
party to the proceeding. more timely process requests for market-
Docket Numbers: ER11–4380–005; eFiling is encouraged. More detailed based rate authorization and reduce
ER13–1562–004; ER13–1641–002; information relating to filing delay.
ER10–2434–006; ER10–2467–006; requirements, interventions, protests,
ER10–2488–012; ER12–1931–006; service, and qualifying facilities filings I. Background
ER15–1045–001;ER10–2504–007; ER12– can be found at: http://www.ferc.gov/ 2. On August 18, 2014, as amended on
610–007; ER13–338–006;ER12–2037– docs-filing/efiling/filing-req.pdf. For December 17, 2014 and February 18,
006; ER12–2314–005; ER10–2436– other information, call (866) 208–3676 2015,2 PNM filed a notice of change in
006;ER11–4381–005. (toll free). For TTY, call (202) 502–8659. status notifying the Commission that,
Applicants: Bellevue Solar, LLC, Dated: October 8, 2015. effective July 17, 2014, PNM purchased
Catalina Solar Lessee, LLC, Chestnut the interests in Delta Person, the owner
Nathaniel J. Davis, Sr.,
Flats Lessee, LLC, Fenton Power of a 132 megawatt (MW) gas-fired
Partners I, LLC, Hoosier Wind Project, Deputy Secretary.
generating facility located in the PNM
LLC, Oasis Power Partners, LLC, Pacific [FR Doc. 2015–26701 Filed 10–20–15; 8:45 am]
balancing authority area. PNM states
Wind Lessee, LLC, Pilot Hill Wind, LLC, BILLING CODE 6717–01–P
that the acquisition does not affect
Shiloh Wind Project 2, LLC, Shiloh III PNM’s horizontal market power
Lessee, LLC, Shiloh IV Lessee, LLC, because, prior to the acquisition, PNM
Spearville 3, LLC, Spinning Spur Wind DEPARTMENT OF ENERGY
purchased the full output of the facility
LLC, Wapsipinicon Wind Project, LLC, Federal Energy Regulatory under a long-term contract with Delta
Yamhill Solar, LLC. Commission Person and, as such, was already
Description: Notice of Change in deemed to control the output of that
Status of the EDF–RE MBR Companies. [Docket No. ER10–2302–005] facility.3
Filed Date: 10/7/15. 3. Additionally, PNM requests
Accession Number: 20151007–5249. Before Commissioners: Norman C. market-based rate authorization in the
Comments Due: 5 p.m. ET 10/28/15. Bay, Chairman; Philip D. Moeller, PNM balancing authority area.4 PNM
Docket Numbers: ER15–2426–000. Cheryl A. LaFleur, Tony Clark, and states that the market characteristics in
Applicants: Northern Indiana Public Colette D. Honorable; Public Service the PNM balancing authority area have
Service Company. Company of New Mexico, Order changed since PNM relinquished its
Description: Amendment to August Accepting Notice of Change in Status, market-based rate authority in 2010 and
12, 2015 Proposed Reactive Power Rejecting, Without Prejudice, Request PNM is therefore seeking to reestablish
Revenue Requirements of Northern for Market-Based Rate Authorization
Indiana Public Service Company for and Providing Clarification on Delta Person, Limited Partnership, 142 FERC ¶
twelve generating facilities located in Submitting Delivered Price Test 62,155 (2013).
the MISO pricing zone under ER15– Analyses and Simultaneous 2 For purposes of this order, the February 18,
Transmission Import Limit Studies 2015 amendment will be referred to as ‘‘Response
2426. to the Data Request.’’
Filed Date: 10/7/15. 1. In this order, we accept the notice 3 August 18, 2014 Filing at 1.
Accession Number: 20151007–5243. of change in status filed by Public
4 PNM states that its tariff reflects that it
tkelley on DSK3SPTVN1PROD with NOTICES
Comments Due: 5 p.m. ET 10/13/15. relinquished its market-based rate authority in the
Service Company of New Mexico (PNM) PNM and El Paso Electric Company (El Paso
Docket Numbers: ER16–34–000. to report a transaction in which it Electric) balancing authority areas. Id. at 3 (citing
Applicants: Harborside Energy, LLC. purchased the interests in Delta Person, Public Service Company of New Mexico, Docket No.
Description: Baseline eTariff Filing: ER96–1551–022 (Oct. 26, 2010) (delegated letter
Limited Partnership (Delta Person).1 order)). PNM states that it only seeks to reestablish
Market Based Rate Tariff to be effective its market-based rate authority in the PNM
11/5/2015. 1 The related acquisition of jurisdictional balancing authority area and not in the El Paso
Filed Date: 10/8/15. facilities was authorized by the Commission in Electric balancing authority area. Id. at 2 n.4.
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evaluates the physical capability of a 24. The second step is to add to the the definition of economic capacity less
supplier to reach a market.’’31 estimate of the unit’s variable generation the amount of generating capacity
22. The first part of the product cost any and all applicable transmission needed to serve the potential supplier’s
market analysis, that is, the calculation costs that a supplier would incur to native load commitments, where native
of all potential suppliers given the deliver the energy into the study area. load commitments are ‘‘commitments to
prevailing market price. The EC of a Commission regulations state that these serve wholesale and retail power
supplier is the amount of generating costs include the maximum customers on whose behalf the potential
capacity owned or controlled by a transmission rate in a transmission supplier, by statute, franchise,
potential supplier with variable costs provider’s tariff as well as the estimated regulatory requirement, or contract, has
low enough that energy from such cost of supplying energy losses.38 The undertaken an obligation to construct
capacity could be economically costs of ancillary services incurred to and operate its system to meet their
delivered to the destination market. The deliver the competing energy into the reliable electricity needs.’’ 43 Units that
EC calculation can be described as study area should also be included.39 are contractually committed or needed
follows.32 These costs should be accumulated to serve native load or meet reliable
23. The first step in calculating a beginning at the source of the generation electricity needs are not available to
potential supplier’s EC is to calculate and ending where the generation sinks compete in a DPT analysis.
the variable cost of each unit.33 in the study area.40 27. Furthermore, as stated in the
Commission regulations state that, at a 25. The final step in calculating Merger Policy Statement, the
minimum, these costs include variable economically competitive capacity is to presumption underlying the AEC
operation and maintenance, including determine whether the computed measure is that the lowest running cost
both fuel and non-fuel operation and generation cost of a unit is price units are used to serve native load and
maintenance, and environmental competitive in the study area. The other firm contractual obligations and
compliance. To the extent these costs supplier should compare the computed would not be available for other sales.44
are allocated among units at the same cost of a generating unit (including all Such units are not available to compete
plant, allocation methods should be aforementioned generation, in the DPT analysis.
fully described.34 Any generation transmission, and other costs), to the 28. The second part of the analysis,
capacity acquired under long-term firm computed market price plus five (5) evaluating whether generation with AEC
purchase contracts (i.e., contracts with a percent in the study area.41 Generation can reach the study area, and the use of
remaining commitment of more than with a delivered cost that meets all of this information to compute market
one year) should be added to the the above conditions is referred to as the shares and concentration statistics, is
potential supplier’s generation EC of that unit. discussed below.
capacity.35 In addition, the regulations 26. The AEC of the units and all 29. Turning to PNM’s calculation, we
provide that ‘‘other generating capacity suppliers must also be calculated. AEC find that the analysis as presented is
may also be attributed to another includes ‘‘capacity from generating flawed and from it we are unable to
supplier based on operational control units that are not used to serve native conclude that PNM rebutted the
criteria as deemed necessary, but the load (or are contractually presumption of PNM’s horizontal
applicant must explain the reasons for committed).’’ 42 Accordingly, AEC is the market power in the PNM balancing
doing so.’’ 36 The variable cost for amount of generating capacity meeting authority area. The deficiencies pertain
contractual capacity acquired, or to the following: (i) Data integrity; (ii)
attributed to another supplier, should be Quantity and price of capacity and/or energy identification of potential supply; (iii)
calculated in the same way as purchased or sold under the contract; and (ix) calculation of variable costs; (iv)
Information on provisions of contracts which confer accounting for power purchase
generation owned or under the direct operational control over generation resources to the
control of the supplier. Commission purchaser.’’).
agreements; (v) calculation of
regulations also require that specific 38 18 CFR 33.3(d)(5)(i) and 33.3(d)(5)(iii)(H) transmission rates; (vi) calculation of
information on long-term purchase and (2015). AEC; (vii) use of historical transaction
sale data be submitted.37 39 18 CFR 33.3(c)(4) (2015) (‘‘Perform delivered data to corroborate results; and (viii)
price test. For each destination market, the preparation of the SIL study. Each of
applicant must calculate the amount of relevant
31 Id. at 31,130. product a potential supplier could deliver to the
these items is discussed further below.
32 We note that these steps are not an exhaustive destination market from owned or controlled PNM’s Calculation of Economic
list to perform a DPT analysis; however, these steps capacity at a price, including applicable
are provided as an illustration to discuss PNM’s transmission prices, loss factors and ancillary
Capacity
DPT analysis. services costs, that is no more than five (5) percent
33 Revised Filing Requirements Under Part 33 of
i. Data Integrity
above the pre-transaction market clearing price in
the Commission’s Regulations, Order No. 642, FERC the destination market.’’ (emphasis added)). 30. PNM submitted compact discs
Stats. & Regs. ¶ 31,111, at 31,886 n.39 (2000), order 40 Merger Policy Statement, FERC Stats. & Regs. (CDs) that included its DPT model and
on reh’g, Order No. 642–A, 94 FERC ¶ 61,289 ¶ 31,044 at 31,132 (‘‘In contrast, a supplier that is
(2001).
underlying work papers with links to
three or four ‘wheels’ away from the same buyer
34 18 CFR 33.3(d)(2)(i) (2015).
may be an economic supplier if the sum of the
other data sources that are not available
35 18 CFR 33.3(c)(4)(i)(A) (2015) (specifying that wheeling charges and the effect of losses is less than on its CDs. For instance, when opening
the potential supplier’s capacity is adjusted by the difference between the decremental cost of the some of the files on the CDs submitted
subtracting capacity committed under long-term buyer and the price at which the supplier is willing on August 18, 2014 and on February 18,
firm sales contracts and adding capacity acquired to sell.’’ (emphasis added)).
under long-term firm purchase contracts). 41 April 14 Order, 107 FERC ¶ 61,018 at
2015, there is an error message that
36 Id. Appendix F (‘‘[D]etermine the suppliers that could states ‘‘There are links to data sources
37 18 CFR 33.3(d)(3) (2015) (‘‘Long-term purchase sell into the destination market at a price less than that cannot be updated.’’
tkelley on DSK3SPTVN1PROD with NOTICES
and sales data. For each sale and purchase of or equal to 5% over the market price. That is, 31. We remind applicants that
capacity, the applicant must provide the following determine which generators have costs less than or including workable links to data sources
information: (i) Purchasing entity name; (ii) Selling equal to 1.05 times the market price.’’); id.,
entity name; (iii) Duration of the contract; (iv) Appendix F n.216 (‘‘The costs include running in the spreadsheets enables the
Remaining contract term and any evergreen costs, transmission charges, [operation and
provisions; (v) Provisions regarding renewal of the maintenance] and environmental adders.’’). 43 18CFR 33.3(d)(4)(i) (2015).
contract; (vi) Priority or degree of interruptibility; 42 Merger Policy Statement, FERC Stats. & Regs. 44 Merger Policy Statement, FERC Stats. & Regs.
(vii) FERC rate schedule number, if applicable; (viii) ¶ 31,044 at 31,132. ¶ 31,044 at 31,132.
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![63772 Federal Register / Vol. 80, No. 203 / Wednesday, October 21, 2015 / Notices
Commission to verify the accuracy of 34. Commission regulations require PNM further clarifies that ‘‘[t]he
the data sources and to ensure the that a potential supplier’s EC be characteristics for all of the units
accuracy of the submitted DPT. adjusted by long-term firm contracts.48 included in the analysis, including their
Units that are committed to unaffiliated estimated incremental costs, are
ii. Identification of Potential Supply
entities under long-term firm contracts included in work papers.’’ 51 PNM states
32. PNM appears to have included should be attributed to the purchasing that incremental costs were derived by
generating units that are no longer entities rather than the owners of those multiplying unit specific heat rates
operational when it calculated EC. EC is facilities, and should potentially be (generally from the Energy Information
the amount of generating capacity included in EC only if the purchasing Administration (EIA) Form 860 or
owned or controlled by a potential entity has EC. Thus, the inclusion of Ventyx) by fuel prices (from FERC Form
supplier with variable costs low enough nonoperational units in the DPT 423 for the Study Period, as reported by
that energy from such capacity could be analysis is inappropriate and the output Ventyx) and then adding VOM and any
economically delivered to the of facilities that are committed under applicable environmental adders.
destination market. Including, for long-term firm contracts should be 37. Fuel is a significant component of
example, the San Onofre Nuclear attributed to the purchasing entities and variable cost, and natural gas- and coal-
Generating Station (San Onofre) as included as EC only if the purchasing fired generation is a significant portion
operational and reporting units 2 and 3 entity has EC. The inclusion of of the generation analyzed by PNM.52
of this plant as having EC in all seasons generation from such units distorts the PNM takes a number of steps to
of the DPT analysis is inconsistent with amount of EC in the DPT analysis. This compute a fuel price for generators to
the definition of EC.45 Thus, the output raises additional concerns that the DPT determine whether they are economic in
of generating facilities, such as San results may be inaccurate and each of the 10 season/load levels. PNM
Onofre, that are not in operation during unreliable. appears to use natural gas price data
the seasons studied in a DPT analysis from the ‘‘ICE10x Day Ahead Gas
iii. Calculating Variable Costs
cannot feasibly be delivered to the Prices’’ for the El Paso Gas (Permian
destination market and should not be 35. As mentioned above, Commission Basin) and El Paso—South Mainline
included in EC. regulations state that for each generating locations.53 Further, PNM appears to
plant or unit owned or controlled by use EIA and Velocity Suite data to
33. Similarly, PNM identifies many
each potential supplier in a DPT compute coal prices across the Western
units as having their output committed
analysis, the applicant must also Electricity Coordinating Council
under long-term power purchase
provide variable cost components, (WECC) region.
contracts, but still considers the units to
which must include at a minimum: (A) 38. For natural gas, PNM computes
have EC in the model. For example,
variable operation and maintenance, seasonal prices at the two locations
PNM identifies Whitewater Hill Wind
including both fuel and non-fuel mentioned above by averaging all of the
Partners as having EC when Whitewater
operation and maintenance; and (B) hourly prices for each location in each
Hill Wind Partners has affirmed to the
environmental compliance.49 season/load level. These two locations
Commission that the output of its
facility is fully committed to an seem to be the hubs that are closest to
Variable Cost: Fuel
unaffiliated third party.46 An entity that the PNM balancing authority area.
36. In its August 18, 2014 Filing, PNM However, PNM also includes in its
does not own any uncommitted capacity states that it constructed a supply curve
or hold a long-term purchase contract spreadsheets hourly gas prices for 22
‘‘in the model for each entity by locations in the WECC region.54 The
should not be considered as a potential estimating its unit-specific incremental
supplier of EC in a DPT analysis.47 In summer average prices for the 22
dispatch costs. The incremental cost is locations range from $1.88 at ‘‘Questar
addition, PNM did not provide the calculated by multiplying the fuel cost
information for these contracts as North Pool’’ to $3.27 at ‘‘PG&E-
for the unit by the unit’s efficiency (heat Citygate,’’ a variation of almost 74
required in 18 CFR 33.3(d)(3)(i). rate) and adding any additional variable percent. Although PNM submitted data
costs that may apply, i.e., costs for for 22 locations, it only used prices from
45 We note that the Velocity Suite database
variable operations and maintenance the two hubs identified above to
indicates that the San Onofre plant units 2 and 3
last generated electricity in January 2012, while the and costs for environmental offsets.’’ 50 calculate input costs for all gas-fired
study period for the DPT analysis was December generators in the WECC region.
2012 through November 2013. This information is 48 18 CFR 33.3(c)(4)(i)(A) (2015) (‘‘Economic
39. Additionally, PNM uses only three
sourced from the Ventyx, Velocity Suite database in capacity means the amount of generating capacity
September 2015. We note that the San Onofre plant owned or controlled by a potential supplier with natural gas prices in its model, one for
is currently in the process of decommissioning. See variable costs low enough that energy from such each of the summer, winter and
Decommissioning of San Onofre, http:// capacity could be economically delivered to the shoulder seasons. To do this, for the
www.songscommunity.com. destination market. Prior to applying the delivered one-hour Summer Super Peak 1 (S_SP1)
46 Response to the Data Request, Workpaper price test, the generating capacity meeting this
‘‘Wkp—Suppliers Details.xlsx’’ (Tab ‘‘AEC By definition must be adjusted by subtracting capacity
Suppliers—Base Prices’’). See also Whitewater Hill committed under long-term firm sales contracts and description of variable costs is generally interpreted
Wind Partners, LLC, Docket No. ER02–2309–000 at adding capacity acquired under long-term firm to mean ‘‘Variable Operations and Maintenance’’
1 (filed July 11, 2002); Whitewater Hill Wind purchase contracts (i.e., contracts with a remaining costs.
51 August 18, 2014 Filing, Carey Aff. ¶ 34 n.36.
Partners, LLC, Docket No. ER02–2309–000 (Aug. 29, commitment of more than one year.’’).
52 For instance, natural gas-fired generation
2002) (delegated letter order accepting filing). Note 49 18 CFR 33.3(d)(2)(i) (2015). Additionally, ‘‘[t]o
also that the comments in the spreadsheet the extent costs described in paragraph (d)(2)(i) of accounts for 28 percent of the nameplate generation
submitted by PNM identify Whitewater Hill Wind this section are allocated among units at the same capacity in the underlying PNM dataset. See id.,
Partners as being under a long-term contract. There plant, allocation methods must be fully described.’’ Workpaper ‘‘Gas Prices Final.xlsx.’’
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are additional cells in PNM’s spreadsheets that 18 CFR 33.3(d)(2)(ii) (2015). 53 See id., Workpaper ‘‘Gas Prices Final.xlsx’’
identify certain generating facilities as having EC or 50 August 18, 2014 Filing, Carey Aff. ¶ 34. We (Tab ‘‘Wkp—Gas Prices’’); December 17, 2014
AEC even though the spreadsheets also show those note that ‘‘Ventyx’’ is the same database as Filing, Workpaper ‘‘Wkp PNM DPT Public
facilities as being under long-term contracts. ‘‘Velocity Suite’’ also referred to as ‘‘Velocity.’’ In Inputs.xlsx’’ (Tab ‘‘Wkp—Gas Prices,’’ Tab ‘‘Wkp—
47 We note that here we describe Whitewater Hill this order we use the term ‘‘Velocity Suite’’, except Coal Spot Prices,’’ Tab ‘‘Wkp—Detailed Coal
Wind Partners for illustrative purposes only, and for where the term ‘‘Ventyx’’ or ‘‘Velocity’’ is used Transactions’’).
not because it is the only entity listed in PNM’s in direct quotes from PNM’s filings. We note that 54 August 18, 2014 Filing, Workpaper ‘‘Gas Prices
DPT analysis that lacks EC or AEC. the acronym ‘‘VOM’’ used above in PNM’s Final.xlsx’’ (Tab ‘‘Wkp—Gas Prices’’).
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necessary, but the applicant must to formulate its questions and the data transmission provider’s tariff as well as
explain the reasons for doing so.’’ 63 source(s) PNM used in its calculation of the estimated cost of supplying energy
48. As noted above, Commission competitive supply. PNM further added losses.68
regulations require information on all that TriState ‘‘has substantial purchase 54. PNM did not include all
long-term firm purchases and sales ‘‘for agreements, including ownership in applicable transmission costs in its EC
each sale and purchase of capacity’’ as [WECC] output facilities that would not calculation. In the December 17, 2014
part of the DPT analysis.64 A seller be tracked by Velocity.’’ 67 PNM did not Filing, PNM’s DPT analysis used a
performing a DPT analysis should mention any other sellers who might be universal $2.00 transmission rate for all
account for the purchase contracts of in this similar situation. peak periods and a $1.00 transmission
potential suppliers because the 51. We appreciate PNM’s Response to rate for all off-peak periods for all
contracts may affect the competitive the Data Request but find that more generators, regardless of location.69
situation of a supplier in a DPT analysis. information is necessary. While PNM 55. In the Data Request, PNM was
A supplier with a contractual obligation provided information on TriState’s requested to provide the transmission
to sell energy or capacity may not have purchasing, it did not disclose the rate schedule for the PNM balancing
any AEC to be considered as competing amount of power purchased under these authority area and all of the balancing
in the DPT analysis. Conversely, a contracts that would enable TriState to authority areas where competing
supplier with the contractual obligation meet its native load requirements and suppliers are located, and to provide
to purchase supply may have excess have sufficient generation to be a cites to the relevant open access
energy and become a potential supplier competitive supplier in the DPT transmission tariff(s).70 The Data
in the DPT analysis. The determination analysis. PNM also did not meet the Request asked PNM to explain if the
of whether a supplier with purchase reporting requirements for long-term transmission rates used in its DPT
contracts has EC or AEC depends on a contracts of sales and purchases in 18 analysis are the maximum rates for the
number of factors specific to that CFR 33.3(d)(3) for TriState or for any PNM balancing authority area and the
supplier such as the supplier’s native other suppliers, such as Whitewater Hill balancing authority areas where the DPT
load (if any), the amount of generation Wind Partners, whose output is fully analysis indicates there is competitively
the supplier has to meet that load, committed under long-term contract to priced generation.71 Finally, the Data
including any contracts the supplier has another entity. Additionally, in its Request directed that, if those are not
to buy or sell energy or capacity, and the Response to the Data Request, PNM did the maximum rates, PNM should re-run
prevailing market price. These specific not indicate whether there are other the AEC calculations to include the cost
factors should be accounted for in a DPT potential suppliers with long-term to traverse each balancing authority area
analysis to determine whether a contracts or adjust its model to reflect using the maximum ‘up to’ transmission
potential supplier with purchase any other potential suppliers with rate when PNM re-runs the DPT
contracts is a potential competitor. native load obligations greater than their model.72
49. The Data Request sought respective generation capacity. 56. In Response to the Data Request,
information from PNM concerning how 52. Generation units in a supplier’s PNM stated that it assumed
certain sellers could be considered portfolio whose output is committed transmission rates for purposes of the
competitive suppliers for purposes of under long-term firm contracts should model because it lacks details on
the DPT analysis when each of those not be considered available to compete specific transmission rates for some of
seller’s native load appeared to exceed in the study area as AEC. Including such the WECC transmission providers. PNM
its generation capacity. Specifically, capacity may overstate the amount of stated that this assumption has a de
PNM was asked to explain whether one AEC that a potential supplier can minimis impact on the results of the
particular supplier, Tri State Generation contribute or inaccurately attribute that analyses. PNM also provided a
& Transmission Association Inc. capacity to the wrong potential supplier spreadsheet that identifies the 24
(TriState), could have any uncommitted in a DPT analysis. Additionally, individual balancing authority areas in
capacity to compete with PNM given incorrectly attributing capacity to sellers WECC, their minimum and maximum
that TriState’s peak load is reported to that have sold the output of their transmission rates, information on the
be greater than its generation capacity. facilities to unaffiliated entities under rate schedules for these balancing
The Data Request did not specifically purchase power agreements impacts the authority areas and screen snapshots of
identify any other sellers in a similar market concentration results of the DPT the appropriate Open Access Same
situation to TriState. However, the Data analysis. Lastly, PNM did not adjust its Time Information System (OASIS) Web
Request directed PNM to identify every model as requested in the Data Request sites where PNM retrieved the
potential supplier for whom its study or otherwise explain that such maximum and minimum rates.73
deducted native load obligations, the adjustment was not required. For these 57. We note that these maximum rates
amount of those obligations and the reasons, we are unable to rely on PNM’s for the peak periods ranged from $1.26
source of their native load values.65 DPT analysis. to $10.02 and averaged $4.96. Likewise,
Finally, the Data Request directed PNM the maximum rates for the off-peak
v. Transmission Rates periods ranged from $0.72 to $9.00 and
to adjust its model as needed to reflect
TriState and other sellers that have load 53. As mentioned above, Commission averaged $3.59. In Response to the Data
greater than their respective regulations require a DPT analysis to Request, PNM provided a sensitivity
uncommitted capacity.66 account for any and all applicable analysis that used the average of these
50. In its Response to the Data transmission costs that a supplier would
Request, PNM stated that there are incur to deliver the energy into the 68 18 CFR 33.3(d)(5) (2015).
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differences between the reporting in the study area and add these costs to the 69 December 17, 2014 Filing, Workpaper ‘‘Wkp
estimate of the available unit’s variable PNM DPT Public Inputs.xlsx’’ (Tab ‘‘Wkp—TTC
data sources that the Commission used and Tx Rates’’).
generation cost. Commission regulations 70 Data Request, Question No. 14a, at 6.
63 Id. state that these costs must include the 71 Id., Question No. 14b, at 6–7.
64 See 18 CFR 33.3(d)(3). See also n.37 above. maximum transmission rate in a 72 Id., Question No. 14c, at 7.
65 See Data Request, Question No. 5, at 4. 73 See Response to the Data Request, ‘‘WECC
66 See Data Request, Question No. 6, at 4. 67 Response to the Data Request at 8. OATT Rates.xlsx.’’
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maximum transmission rates to update in Order No. 697, the Commission implicitly allocate an entity’s lowest
its DPT model.74 PNM complied with stated that ‘‘in markets where utilities running cost units to serve its native
the first part of Question 14 by retain significant native load load. Based on this response, we
identifying that the $2.00 and $1.00 obligations, an analysis of available conclude that PNM did not allocate the
transmission rates are not the maximum economic capacity may more accurately lowest cost units of itself and its
rates for the peak and off-peak periods, assess an individual seller’s competitors to serve their respective
respectively. PNM also identified the 24 competitiveness, as well as the overall native load. Therefore, we are unable to
source balancing authority areas and competitiveness of a market, because rely on the reported results of potential
provided a link and screen snapshots of available economic capacity recognizes competitive AEC suppliers and whether
the OASIS Web sites for these balancing the native load obligations of the they accurately reflect the costs of the
authority areas that display their sellers.’’ 81 competitive generation in the market.
maximum and minimum rates. 61. The Data Request directed PNM to
58. However, we find the remaining vii. Historical Transaction Data to
explain whether its DPT model first
portion of PNM’s Response to the Data Corroborate Results
allocated the lowest running cost units
Request to be unresponsive to the to a supplier’s native load and cited to 63. Commission regulations state that
question asked and not in compliance the Merger Policy Statement.82 In ‘‘[t]he applicant must provide historical
with Commission regulations. PNM did Response to the Data Request, PNM trade data and historical transmission
not re-run the DPT analysis with the stated, in part, that ‘‘[t]he model data to corroborate the results of the
maximum rate for each balancing implicitly allocates PNM’s lowest horizontal Competitive Analysis
authority area as requested in the Data running cost units to serve native load Screen.’’ 86 Commission regulations also
Request 75 and required by Commission for PNM and non-PNM suppliers to state that the applicant must provide
regulations.76 Furthermore, PNM did their native load (non-PNM load) by the data and information used in calculating
not calculate any additional costs for derivation of the [AEC]. The DPT model the EC and AEC that a potential supplier
transmission losses or ancillary services does not rank order each supplier’s could deliver to a destination market,
necessary to deliver energy into the generating units from lowest to highest including transmission capability,
study area, as required by Commission running cost but rather aggregates all transmission constraints and firm
regulations.77 For capacity outside of [EC] for each supplier within the transmission rights.87 Further,
the study area, PNM did not consider seasonal/load periods analyzed.’’ 83 Commission direction has been to
additional transmission charges that a 62. In the Merger Policy Statement, provide a ‘‘trade data check’’ to support
competing generator would likely incur the Commission stated that the AEC the results of the DPT analysis.88
to deliver power to the destination measure ‘‘includes capacity from 64. The Data Request directed PNM to
market. Therefore, we find that PNM’s generating units that are not used to identify suppliers with AEC and
calculations underestimate the serve native load (or are contractually document their contribution to
transmission cost component for most committed).’’ 84 However, PNM stated competing supply entering the PNM
observations in its dataset and further that ‘‘[t]he DPT model does not rank study area.89 In its Response to the Data
compromise the results of the DPT order each supplier’s generating units Request, PNM provided a spreadsheet
analysis. from lowest to highest running cost but that complied with the request by
vi. Calculation of AEC rather aggregates all economic capacity identifying all generation units, their
for each supplier within the seasonal/ location, and the identity of the
59. As mentioned above, alternative suppliers with non-zero contribution to
suppliers should be able to reach the load periods analyzed.’’ 85 Further, it is
unclear how PNM’s model might the AEC calculation.90
market both economically and 65. Although the Data Request did not
physically.78 First, we discuss how to specifically ask PNM to provide
61,177 (2008); Nat’l Grid, plc, 117 FERC ¶ 61,080,
determine the AEC of a supplier. at PP 27–28 (2006), reh’g denied, 122 FERC ¶ historical transaction data to corroborate
60. After computing the EC of 61,096 (2008); Westar Energy, Inc., 115 FERC ¶ the results of its DPT analysis, we take
potential competing suppliers, an 61,228, at P 72, reh’g denied, 117 FERC ¶ 61,011,
this opportunity to provide clarification
applicant should compute the AEC of at P 39 (2006); Nev. Power Co., 113 FERC ¶ 61,265,
at P 15 (2005). for PNM and others who may file a DPT
those suppliers. AEC is ‘‘the amount of 81 Order No. 697, FERC Stats. & Regs. ¶ 31,252 at
generating capacity meeting the P 112. 86 18 CFR 33.3(c)(6) (2015).
definition of EC less the amount of 82 Data Request, Question No. 4, at 3 (‘‘In the 87 See 18 CFR 33.3(d)(7)–(9) (2015).
generating capacity needed to serve the [AEC] calculation, please explain whether the 88 See Merger Policy Statement, FERC Stats. &
potential supplier’s native load model first allocates PNM’s lowest running cost Regs. ¶ 31,044 at 30,133 (‘‘It would be expected that
units to serve native load for PNM. Please explain there be some correlation between the suppliers
commitments.’’ 79 We note that the whether the model allocates the lowest running cost included in the market by the delivered price test
Commission has relied more heavily on units of non-PNM suppliers to their native load and those actually trading in the market. As a
AEC in the DPT analysis when utilities (non-PNM load).’’). The Data Request noted that check, actual trade data should be used to compare
have significant native load.80 Further, ‘‘AEC includes ‘capacity from generating units that actual trade patterns with the results of the
are not used to serve native load (or are delivered price test. For example, it may be
74 See
contractually committed) and whose variable costs appropriate to include current trading partners in
id. are such that they could deliver energy to a market
75 Data
the relevant market even if the above analysis
Request, Question No. 14c, at 7 (‘‘If the at a price close to the competitive price in the indicates otherwise.’’).
rates used in your model are not the maximum rate, market. The presumption underlying this measure 89 Data Request, Question No. 15, at 7 (‘‘Please
please re-run your AEC calculations using the is that the lowest running cost units are used to provide the following information for each supplier
maximum ‘up to’ transmission rate to include the serve native load and other firm contractual with a non-zero contribution to the available
cost to traverse each balancing authority when you obligations and would not be available for other economic capacity in the study area of your model:
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re-run your DPT model.’’). sales.’’’ Data Request, Question No. 4 n.6, at 3
76 18 CFR 33.3(d)(5) (2015).
the full name of each supplier, the name of the
(citing Merger Policy Statement, FERC Stats. & Regs. unit(s) that supplied the energy, the amount of
77 18 CFR 33.3(d)(5) (2015). ¶ 31,044 at 30,132). energy supplied by each unit(s) in megawatts and
78 Merger Policy Statement, FERC Stats. & Regs. 83 Response to the Data Request at 7.
the balancing authority area location of the unit(s)
¶ 31,044 at 30,130. 84 Merger Policy Statement, FERC Stats. & Regs. for each of the 10 load level/study periods.’’
79 18 CFR 33.3(c)(4)(i)(B) (2015). ¶ 31,044 at 30,132. (footnote omitted)).
80 Great Plains Energy, Inc., 121 FERC ¶ 61,069, 85 Response to the Data Request at 7 (emphasis 90 Response to the Data Request at 12 &
at P 34 & n.44 (2007), reh’g denied, 122 FERC ¶ added). Workpaper ‘‘Wkp—Suppliers Details.xlsx.’’
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analysis in a section 205 proceeding in relevant market as uncommitted Therefore, the Commission previously
order to rebut the presumption of capacity limited by the simultaneous has provided guidance so that sellers
market power. PNM did not submit transmission import capability.94 In can more accurately measure the
historical transaction data or Puget Sound Energy, Inc., the amount of available transmission
transmission data to corroborate the Commission consolidated and clarified capability into the study area. One area
results of its model as required by 18 its direction regarding SIL studies given of concern has been the proper
CFR 33.3(c)(6). For example, although in previous orders and provided modeling and scaling of jointly-owned
PNM indicates in its Response to the required formats for submitting SIL generating plants in a SIL study,
Data Request that its model includes data.95 Specifically, the Commission particularly when units have long-term
significant generation capacity from the directed filers to submit their SIL data firm transmission reservations.101 The
California Independent System Operator in the format provided in Appendix B Commission has determined that these
Corporation (CAISO) market as available of Puget in order to properly summarize remote plants should be dispatched at
to compete in the PNM balancing and document their SIL study results.96 their historical output levels and should
authority area, PNM did not submit 68. The SIL study calculates the not be scaled down as doing so would
historical transaction data or aggregated simultaneous transfer be unrealistic and inconsistent with
transmission data to corroborate this. capability into the balancing authority historical practices.102
PNM could have submitted eTag data to area being studied. It is intended to 70. In Pinnacle West,103 the
demonstrate flows from CAISO were provide a reasonable simulation of Commission identified errors and
consistent with its DPT model. historical conditions and is not a provided guidance and clarification as
Moreover, the Commission’s review of theoretical maximum import capability to how the SIL study should be revised
eTag data was not able to corroborate or best import case scenario.97 A to satisfy the Commission’s
PNM’s results. Without such simplified view of the SIL study is that requirements. The PNM SIL study
information, we are concerned that the it simultaneously increases generator presents issues similar to those
amount of competing generation output in one area, the first-tier, and presented by the SIL study at issue in
capacity imported into the PNM study decreases generator output in another Pinnacle West. With regard to the PNM
area in PNM’s DPT analysis is not area, the study area. As the source of SIL study, the Data Request noted that
supported by historical trade or generation is incrementally shifted, some units within the study area have
transmission data and is overstated. We single contingency conditions are tested long-term firm commitments to serve
remind DPT filers that they should in both areas while the relevant load outside of the study area. The Data
provide historical trade and transmission elements are monitored for Request noted that the Commission
transmission data and explain overloads.98 A ‘‘single contingency expects that any such unit’s generation
significant discrepancies between condition’’ is the unexpected failure of that has been committed with long-term
modeling results and such data. a single system component, such as a firm transmission reservations would be
generator, transmission line, circuit considered unavailable for scaling;
viii. SIL Study
breaker, switch or other electrical however, it appears that some such
66. As mentioned above, alternative equipment.99 The Commission direction units were scaled down during the SIL
suppliers must be able to reach the has been to increase or ‘‘scale up study. Therefore, the Data Request
market both economically and available generation in the exporting required PNM to identify all generation
physically. We provide clarification (aggregated first tier areas) and scale units within the PNM balancing
regarding determining the physical down the study area resources authority area that have long-term firm
capability of a supplier with EC and according to the same methods used transmission reservations (to serve
AEC to reach the study area.91 historically in assessing available study area load or to export power to the
67. The physical ability of a supplier transmission for non-affiliate first-tier), describe whether the unit’s
to reach the market or study area resources.’’ 100 output level was either maintained or
requires the use of a SIL study as a basis 69. The Commission recognizes that it scaled in the SIL study, and adjust the
for transmission access for both the is a complex process for a seller to SIL study as necessary.104
indicative screens and the DPT estimate transmission capability using 71. In its Response to the Data
analysis.92 In Order No. 697, the the model of its transmission system in Request, PNM filed revised work papers
Commission clarified that the SIL study a simplified manner so that elements are and SIL information. PNM also
as shown in Appendix E of the April 14 accurately accounted for in SIL studies. submitted a table listing the long-term
Order is the only study that meets the firm transmission reservations for
Commission’s requirements for the DPT 94 April 14 Order, 107 FERC ¶ 61,018 at exports out of the PNM balancing
analysis and the indicative screens.93 In Appendix E.
the April 14 Order, the Commission set 95 Puget Sound Energy, Inc., 135 FERC ¶ 61,254 101 A long-term firm transmission reservation is a
the amount of supply that can reach the (2011) (Puget). reservation that is 28 days or longer. See Order No.
96 Submittal 1 of Appendix B of Puget contains
697, FERC Stats. & Regs. ¶ 31,252 at P 368 (‘‘While
91 In this order, we do not discuss the ultimate a summary table of components used to calculate we find that firm transmission reservations less
DPT calculations, combining the economic and SIL values and provides a spreadsheet format with than or equal to 28 days in duration are usually
physical analyses to create market share and numerical examples. Submittal 2 provides a unpredictable, we believe that firm transmission
concentration indices because we do not believe spreadsheet for identification of long-term firm reservations of a longer duration are not related to
that the first two steps of the PNM DPT analysis transmission reservations used to import power the unpredictable nature of real time events and are
provide a reasonable foundation to examine this from seller and affiliate generating resources in a based upon planned and predictable events.
final step. first-tier area to serve native load in the study area. Therefore, the Commission will require sellers to
97 Puget, 135 FERC ¶ 61,254 at Appendix B account for firm and network transmission
92 Order No. 697, FERC Stats. & Regs. ¶ 31,252 at
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P 19. (citing Order No. 697, FERC Stats. & Regs. ¶ 31,252 reservations having a duration of longer than 28
93 Id. (‘‘With regard to [SILs], the Commission at P 354). days.’’).
98 See, e.g., Puget, 135 FERC ¶ 61,254, Appendix 102 See Pinnacle West Capital Corp., 117 FERC ¶
adopts the requirement that the SIL study be used
as a basis for transmission access for both the B, § I.D (Prior Commission Direction on Scaling). 61,316, at P 6 (2006) (Pinnacle West).
99 Id. Appendix B (citing Carolina Power & Light 103 Id. P 3.
indicative screens and the DPT analysis. Further,
the Commission clarifies that the SIL study as Co., 128 FERC ¶ 61,039, at P 8 n.7 (2009)). 104 Data Request, Question No. 2, at 2 (citing
shown in Appendix E of the April 14 Order is the 100 April 14 Order, 107 FERC ¶ 61,018 at Pinnacle West, 117 FERC ¶ 61,316 at P 6; April 14
only study that meets our requirements.’’). Appendix E. Order, 107 FERC ¶ 61,018 at Appendix E).
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authority area and the corresponding As such, the Commission cannot utilize multiple units fully represent the
source generator within the study area. these sensitivities as support for PNM’s generation commitments and impacts
This table indicates that these SIL study. Furthermore, while the on the transmission system. One unit
generation units are jointly-owned by scaling method used in the first will represent the seller’s generation
PNM and other entities, and that the sensitivity is consistent with guidance capacity in the study area, and one or
non-PNM owned portions of these units given in the Data Request, the more additional units will represent the
are committed with long-term firm ownership and commitments of the capacity owned by unaffiliated entities
transmission reservations to export out generation units was not apparent in the within the first-tier area.114 The seller’s
of the study area (i.e., the PNM original August 18, 2014 Filing or the unit will remain modeled within the
balancing authority area). However, December 17, 2014 Filing. Thus, we study area balancing authority area
based on the power flow models believe that further clarification is while the portion of the unit(s)
submitted by PNM in the original SIL warranted on the modeling and belonging to unaffiliated first-tier sellers
study, it is evident that PNM scaled treatment of jointly-owned units in SIL will be given the appropriate first-tier
down these jointly-owned generation studies. balancing authority area number in the
units, including portions belonging to 74. In Puget, the Commission stated
that ‘‘[i]n the case of jointly-owned model. Importantly, we note that this
other owners.105 In addition, PNM
power plants, the plant’s capacity method retains the same physical
provided Submittal 1 and Submittal 2
should be allocated among the generator location of the unit within the
tables which reported the results of two
sensitivities that PNM conducted in owners’ balancing authority areas transmission network as modeled;
response to the scaling guidance in the according to its ownership however, the portion of the unit(s)
Data Request. percentages.’’ 110 Additionally, the belonging to the unaffiliated first-tier
72. PNM’s first sensitivity study ‘‘does Commission has stated that a seasonal sellers would not be considered a study
not scale resources with potential benchmark case model should simulate area generator for purposes of
commitments outside of the PNM historical seasonal conditions that were calculating net area interchange. We
[balancing authority area].’’ 106 The present during the modeled season. The also note that with this method, the
second sensitivity ‘‘scales half of the Commission has stated that ‘‘[a]ny seller’s generation capacity can
resources with potential commitments generating units owned by the study appropriately be scaled down, and the
outside of the PNM [balancing authority area utility that are located in the first- portion of the unit(s) belonging to the
area].’’ 107 However, for both tier area, including the study area unaffiliated first-tier sellers now
sensitivities, PNM stated that ‘‘the utility’s portion of jointly-owned units[,] modeled in the first-tier area can
associated export reservations are should be modeled . . . in the first-tier appropriately be scaled up to serve
recognized as long-term firm area.’’ 111 In addition, ‘‘any long-term study area load if it is not committed
commitments to be consistent and reservations from these facilities used to under long-term firm transmission
reflect the equal but opposite effect to serve study area native load shall be reservations. Additionally, any
import reservations and compensate for included in the study area net area generating resources in the first-tier
prematurely limiting the imports below interchange.’’ 112 While this statement with long-term firm transmission
the physical limit of the transmission references jointly-owned generating reservations to serve study area load
system or load within the study area. units located in the first-tier area, we should be reported as a long-term firm
The export reservations are reflected in believe that it is reasonable to treat transmission reservation in Submittal
the SIL sensitivity analyses by inclusion jointly-owned generating units located 2.115 Furthermore, entities are required
in Table 2 [of Submittal 2].’’ 108 within the study area committed to to ‘‘[p]rovide a listing of first-tier area
73. The practice of capturing long- serving first-tier load similarly. As generating units and portions of jointly-
term firm export reservations in portions of these units belong to owned first-tier area generating units to
Submittal 2 is inconsistent with the unaffiliated entities located in the first- be scaled-up in the first-tier area,
instructions and purpose of Submittal 2, tier area, they should not be scaled including any first-tier area generation
which is to identify and sum the long- down; doing so would misrepresent the
or portions of jointly-owned first-tier
term firm transmission reservations incremental transfer capability of the
from affiliated remote generating area generating units physically located
study area by reducing generation that
resources in the first-tier to serve native within the study area, according to the
actually has commitments to first-tier
load in the study area.109 Export load.113 This has the effect of allowing same methods used historically in
reservations are long-term firm more first-tier generation into the study assessing available transmission for
transmission reservations from the area than is actually available to be non-affiliate resources.’’ 116 Entities
study area to the first-tier to serve first- displaced in the study area. should identify their jointly-owned
tier load; because the exports are 75. Thus, we clarify that, for purposes units, report the ownership breakdown,
commitments from capacity that belongs of generation scaling for the SIL, the and indicate what scaling, if any, was
to the first-tier, these export reservations appropriate method of modeling a utilized for each portion of the
should not be captured in Submittal 2. generation unit in the study area that is generator.
jointly-owned between the seller and 76. Finally, we clarify that entities
105 August 18, 2014 Filing, Stahlhut Aff. Exhibit one or more unaffiliated sellers in the should complete the ‘‘Description of
JWS–3. first-tier area is to represent the unit as
106 Response to the Data Request at 3. We
Remote Resources’’ column as necessary
multiple units in the model based on
interpret PNM’s language ‘‘resources with potential
commitments’’ to mean the long-term firm ownership percentage such that the 114 In Puget, the Commission approved
tkelley on DSK3SPTVN1PROD with NOTICES
transmission reservations capacity or export NorthWestern’s use of this general method to
reservations of the units within the PNM balancing 110 Id. P 18. represent the jointly-owned Colstrip plant. The
authority area that have long-term firm transmission 111 Id., Appendix B, II.D at 4.3.7. model represented separate generators for each
reservations to serve load in the first tier. 112 Id. owner, each with one owner’s portion of Colstrip’s
107 Id. at 4. total capacity. Id. P 18.
113 See id., Appendix B, § II.D (Submittal 4:
108 Id. at 3–4. 115 Id., Appendix B, II.B, Instruction 3.
Seasonal Benchmark Case) (4.3.7 and 4.3.8 discuss
109 Puget, 135 FERC ¶ 61,254, at Appendix B, how jointly-owned units should be modeled 116 Id., Appendix B, II.G (Submittal 7: The Sub-
§ II.B. according to historical dispatch). System File) (7.2.1).
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![63778 Federal Register / Vol. 80, No. 203 / Wednesday, October 21, 2015 / Notices
in each row of Submittal 2.117 We Commission.120 Further, PNM the Federal Power Act to have rates on
expect that, at a minimum, entities will represents that neither it nor any file in a convenient form and place.124
indicate the balancing authority area affiliate owns or controls intrastate PNM must file EQRs electronically with
from which these remote resources are natural gas transportation, storage, or the Commission consistent with the
sourced. distribution facilities. PNM represents procedures set forth in Order No.
that it owns several sites that may be 770.125 Failure to timely and accurately
Conclusion
used for generation capacity file an EQR is a violation of the
77. As described above, we are unable development including sites in which Commission’s regulations for which
to validate the results of PNM’s SIL PNM has existing facilities. PNM states PNM may be subject to refund, civil
model, its calculations of EC and AEC, that it currently has plans to develop
and its DPT analysis. Thus, we find that penalties, and/or revocation of market-
new generation at or near the San Juan
PNM has not adequately rebutted the based rate authority.126
Generating Station in the PNM
presumption of horizontal market power balancing authority area. Additionally, 86. PNM must timely report to the
caused by its failure of the indicative PNM states that it holds one Commission any change in status that
screens in the PNM balancing authority undeveloped site near Albuquerque, would reflect a departure from the
area. Therefore, we reject, without New Mexico. characteristics the Commission relied
prejudice, PNM’s request for market- 81. PNM states that it purchases coal upon in granting market-based rate
based rate authorization in the PNM under various long-term agreements but authority.127
balancing authority area. We encourage does not currently own any coal mines
87. Additionally, PNM must file an
other market-based rate applicants to or mineral rights. PNM represents that
updated market power analysis for all
make use of the guidance and these coal purchase contracts are used
regions in which it is designated as a
clarification offered herein. exclusively to supply coal to power
plants owned and operated by PNM. Category 2 seller in compliance with the
D. Notice of Change in Status 82. Finally, PNM states that it has not regional reporting schedule adopted in
78. PNM states that its purchase of erected barriers to entry into the Order No. 697.128 The Commission also
Delta Person does not affect PNM’s relevant market, the PNM balancing reserves the right to require such an
horizontal market power because PNM authority area, and will not erect analysis at any intervening time.
was already deemed to control the barriers to entry into the relevant The Commission orders:
output of the Delta Person facility under market.
a long-term contract with Delta (A) PNM’s notice of change in status
83. Based on PNM’s representations,
Person.118 In its most recent updated we find that PNM satisfies the is hereby accepted for filing, as
market power analysis for the Commission’s requirements for market- discussed in the body of this order.
Southwest region, PNM studied Delta based rates regarding vertical market (B) PNM’s request for market-based
Person’s generation in the first-tier power. authority in the PNM balancing
balancing authority areas in which PNM 84. Based on PNM’s satisfaction of the authority area is hereby rejected,
has market-based rate authority.119 Commission’s requirements for market- without prejudice, as discussed in the
79. Based on PNM’s representations, based authorization regarding horizontal body of this order.
we find that PNM satisfies the and vertical market power in the
(C) PNM’s SIL study is hereby
Commission’s requirements for market- markets where it has market-based rate
based rates regarding horizontal market rejected, without prejudice, as discussed
authority, we accept PNM’s notice of
power in all balancing authority areas in change in status. in the body of this order.
which PNM currently has market-based (D) The Secretary is hereby directed to
E. Reporting Requirements
rate authority, i.e., outside of the PNM publish a copy of this order in the
and El Paso Electric balancing authority 85. An entity with market-based rate Federal Register.
areas. authorization must file an Electric
By the Commission.
80. PNM represents that of it and its Quarterly Report (EQR) with the
affiliates, only PNM owns or controls Commission, consistent with Order Nos. Issued: October 15, 2015.
transmission facilities subject to 2001 121 and 768,122 to fulfill its Kimberly D. Bose,
Commission jurisdiction. PNM states responsibility under section 205(c) 123 of Secretary.
that open access to these transmission [FR Doc. 2015–26724 Filed 10–20–15; 8:45 am]
120 Public Service Company of New Mexico,
facilities is provided pursuant to the BILLING CODE 6717–01–P
FERC FPA Electric Tariff, PNM Open Access
terms of PNM’s Open Access Transmission Tariff.
Transmission Tariff on file with the 121 Revised Public Utility Filing Requirements, 124 See Revisions to Electric Quarterly Report
Order No. 2001, FERC Stats. & Regs. ¶ 31,127, reh’g Filing Process, Order No. 770, FERC Stats. & Regs.
117 Id., Appendix B, II.B (Submittal 2: denied, Order No. 2001–A, 100 FERC ¶ 61,074, ¶ 31,338, at P 3 (2012) (citing Order No. 2001, FERC
Identification of Long-Term Firm Transmission reh’g denied, Order No. 2001–B, 100 FERC ¶ Stats. & Regs. ¶ 31,127 at P 31).
Reservations used to Import Power for Generating 61,342, order directing filing, Order No. 2001–C, 125 Order No. 770, FERC Stats. & Regs. ¶ 31,338.
Resources in the First-Tier Area to Serve Native 101 FERC ¶ 61,314 (2002), order directing filing,
126 The exact filing dates for these reports are
Load in the Study Area) (Instruction 2). Order No. 2001–D, 102 FERC ¶ 61,334, order
118 August 18, 2014 Filing at 1. refining filing requirements, Order No. 2001–E, 105 prescribed in 18 CFR 35.10b (2015). Forfeiture of
119 Public Service Company of New Mexico, FERC ¶ 61,352 (2003), order on clarification, Order market-based rate authority may require a new
Docket No. ER10–2302–004 (Aug. 22, 2014) No. 2001–F, 106 FERC ¶ 61,060 (2004), order application for market-based rate authority if the
(delegated letter order). PNM has market-based rate revising filing requirements, Order No. 2001–G, 120 applicant wishes to resume making sales at market-
authority in seven first-tier balancing authority FERC ¶ 61,270, order on reh’g and clarification, based rates.
tkelley on DSK3SPTVN1PROD with NOTICES
areas to the PNM balancing authority area. These Order No. 2001–H, 121 FERC ¶ 61,289 (2007), order 127 Reporting Requirement for Changes in Status
balancing authority areas are Southwestern Public revising filing requirements, Order No. 2001–I,
FERC Stats. & Regs. ¶ 31,282 (2008). for Public Utilities with Market-Based Rate
Service Company, Western Area Power
122 Electricity Mkt. Transparency Provisions of Authority, Order No. 652, FERC Stats. & Regs. ¶
Administration-Colorado Missouri, Western Area
Power Administration—Lower Colorado, Public Section 220 of the Fed. Power Act, Order No. 768, 31,175, order on reh’g, 111 FERC ¶ 61,413 (2005);
Service Company of Colorado, Arizona Public FERC Stats. & Regs. ¶ 31,336 (2012), order on reh’g, 18 CFR 35.42 (2015).
Service Company, Salt River Project, and Tucson Order No. 768–A, 143 FERC ¶ 61,054 (2013). 128 Order No. 697, FERC Stats. & Regs. ¶ 31,252
Electric Power Company. 123 16 U.S.C. 824d(c) (2012). at PP 848–850.
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Document Created: 2018-02-27 08:54:11
Document Modified: 2018-02-27 08:54:11
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| Collection | Federal Register | |
| sudoc Class | AE 2.7: GS 4.107: AE 2.106: | |
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| Section | Notices | |
| FR Citation | 80 FR 63768 |
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