81 FR 33375 - Refinements to Policies and Procedures for Market-Based Rates for Wholesale Sales of Electric Energy, Capacity and Ancillary Services by Public Utilities
DEPARTMENT OF ENERGY
Federal Energy Regulatory Commission Federal Register Volume 81, Issue 102 (May 26, 2016)
Federal Energy Regulatory Commission
Federal Register Volume 81, Issue 102 (May 26, 2016)
| Page Range | 33375-33387 | |
| FR Document | 2016-12427 |
[Federal Register Volume 81, Number 102 (Thursday, May 26, 2016)] [Rules and Regulations] [Pages 33375-33387] From the Federal Register Online [www.thefederalregister.org] [FR Doc No: 2016-12427] ======================================================================= ----------------------------------------------------------------------- DEPARTMENT OF ENERGY Federal Energy Regulatory Commission 18 CFR Part 35 [Docket No. RM14-14-001; Order No. 816-A] Refinements to Policies and Procedures for Market-Based Rates for Wholesale Sales of Electric Energy, Capacity and Ancillary Services by Public Utilities AGENCY: Federal Energy Regulatory Commission, DOE. ACTION: Final rule; Order on rehearing and clarification. ----------------------------------------------------------------------- SUMMARY: The Federal Energy Regulatory Commission is denying requests for rehearing and granting, in part, clarification of its determinations in Order No. 816, which amended its regulations that govern market-based rate authorizations for wholesale sales of electric energy, capacity, and ancillary services by public utilities pursuant to the Federal Power Act. DATES: This rule will become effective July 25, 2016. FOR FURTHER INFORMATION CONTACT: Greg Basheda (Technical Information), Office of Energy Market Regulation, Federal Energy Regulatory Commission, 888 First Street NE., Washington, DC 20426, (202) 502-6479. Carol Johnson (Legal Information), Office of the General Counsel, Federal Energy Regulatory Commission, 888 First Street NE., Washington, DC 20426, (202) 502-8521. SUPPLEMENTARY INFORMATION: Table of Contents Paragraph Nos. I. Introduction............................................. 1 II. Discussion.............................................. 12 A. Sellers with Fully Committed Long-Term Generation 12 Capacity............................................... B. Reporting of Long-Term Firm Purchases................ 18 C. Clarification of the Definition or Duration of Long- 26 Term Firm Transmission Reservations.................... D. Notices of Change in Status.......................... 29 E. New Affiliation and Behind-the-Meter Generation...... 38 F. Corporate Organizational Charts...................... 45 G. Part 101 Waivers..................................... 48 H. Capacity Ratings..................................... 52 I. Inputs to Electric Power Production.................. 55 J. Transmission/Natural Gas Assets Sheet................ 58 K. Long-Term Firm Power Purchases List.................. 60 L. Generation Assets Sheet, Rows [B] and [H]............ 62 III. Information Collection Statement....................... 65 IV. Document Availability................................... 68 V. Effective Date........................................... 71 Order No. 816-A Order on Rehearing and Clarification I. Introduction 1. On October 16, 2015, the Federal Energy Regulatory Commission (Commission) issued Order No. 816,\1\ which amended its regulations that govern market-based rate authorizations for wholesale sales of electric energy, capacity, and ancillary services by public utilities pursuant to the Federal Power Act (FPA). In this order, we address requests for rehearing and clarification of Order No. 816.\2\ --------------------------------------------------------------------------- \1\ Refinements to Policies and Procedures for Market-Based Rates for Wholesale Sales of Electric Energy, Capacity and Ancillary Services by Public Utilities, Order No. 816, FERC Stats. & Regs. ] 31,374 (2015) (Final Rule). \2\ Order No. 816 became effective on January 28, 2016. On December 23, 2015, upon consideration of requests for a stay of the corporate organizational chart requirement, the Commission issued an order granting an extension of time such that market-based rate applicants and sellers would not be required to comply with the corporate organizational chart requirement prior to the issuance of an order on the merits of the requests for rehearing. Refinements to Policies and Procedures for Market-Based Rates for Wholesale Sales of Electric Energy, Capacity and Ancillary Services by Public Utilities, 153 FERC ] 61,337 (2015). --------------------------------------------------------------------------- 2. Nine requests for rehearing and clarification were filed.\3\ The requests for rehearing and clarification concern [[Page 33376]] the following topics: Sellers with fully committed long-term generation capacity; the reporting of long-term firm purchases; the definition or duration of long-term firm transmission reservations; notices of change in status; new affiliation and behind-the-meter generation; corporate organizational charts; and waiver of Part 101 of the Commission's regulations.\4\ --------------------------------------------------------------------------- \3\ The requests for rehearing and clarification were filed by the following entities: EDF Renewable Energy, Inc. and E.ON Climate & Renewables North America LLC (IPP Developers); Edison Electric Institute (EEI); Electric Power Supply Association (EPSA); Invenergy Thermal Development LLC and Invenergy Wind Development LLC (Invenergy); National Hydropower Association (NHA); NextEra Energy, Inc. (NextEra); Southern California Edison Company (SoCal Edison); Southern Company Services, Inc. (Southern); and Transmission Access Policy Study Group (TAPS). \4\ 18 CFR pt. 101 (2015). --------------------------------------------------------------------------- 3. In this order, in most respects, we affirm the Commission's determinations made in Order No. 816. However, regarding some issues, we provide clarification. 4. Specifically, as discussed further below, we deny rehearing regarding the requirement to include the expiration date of the contract when a seller claims that its capacity is fully committed. To the extent that the expiration date is not known at the time a seller files for market-based rate authority, we confirm that a subsequent filing to report the contract expiration date will be treated as an informational filing rather than as an amendment to a pending application. 5. We grant clarification regarding the requirement for applicants within a regional transmission organization or independent system operator (RTO/ISO) market to report all long-term firm energy and capacity purchases from generation capacity located within the RTO/ISO market if the generation is designated as a resource with capacity obligations. We clarify that this requirement does not apply if the generation is from a qualifying facility exempt from section 205 of the FPA. In addition, we affirm that a market-based rate seller must list all of its long-term firm power purchases in its asset appendix, Appendix B, even if it does not have market-based rate authority in its home balancing authority area. 6. We clarify that the Commission did not intend to change the definition of long-term firm transmission reservations in Order No. 816 and clarify that long-term firm transmission reservations are longer than 28 days. 7. Regarding the Commission's 100 megawatt (MW) threshold for the requirement to report new affiliations, we affirm the determinations made in Order No. 816 but clarify which markets would be a seller's relevant geographic market for purposes of the 100 MW threshold reporting requirement. We also deny a rehearing request to find that capacity in first-tier markets \5\ be included for determining the 100 MW change in status threshold. --------------------------------------------------------------------------- \5\ We clarify that for purposes of this order, the term ``first-tier markets'' includes all first-tier areas, whether they are a balancing authority area or an RTO/ISO market. --------------------------------------------------------------------------- 8. We affirm the Commission's determination in Order No. 816 that sellers are not required to include behind-the-meter generation in the 100 MW change in status threshold, the 500 MW Category 1 seller status threshold, or to include such generation in the asset appendices and indicative screens. 9. Additionally, we clarify that a hydropower licensee that otherwise sells power only at market-based rates will not be subject to the full requirements of the Uniform System of Accounts as a consequence of filing a cost-based reactive power tariff with the Commission, and may satisfy the requirements in Part 101 of the Commission's regulations by complying with General Instruction 16 of the Uniform System of Accounts. 10. We also provide clarification regarding other aspects of the Final Rule, including revisions to regulatory text and instructions in the asset appendix to ensure consistency with the Commission's determinations in the Final Rule. 11. Further, as discussed below, we grant an additional extension of time such that market-based rate applicants and sellers will not be required to comply with the corporate organizational chart requirement until the Commission issues an order at a later date. II. Discussion A. Sellers With Fully Committed Long-Term Generation Capacity 1. Final Rule 12. In Order No. 816, the Commission clarified that sellers may explain that their generation capacity in the relevant geographic market (including first-tier markets) is fully committed, in lieu of submitting indicative screens, in order to satisfy the Commission's market-based rate requirements regarding horizontal market power in instances where all generation owned or controlled by a seller and its affiliates in the relevant balancing authority areas or markets (including first-tier markets) is fully committed. The Commission clarified that to qualify as fully committed, a seller must commit the capacity to a non-affiliated buyer so that none of it is available to the seller or its affiliates for one year or longer. The Commission also adopted the proposal that sellers claiming that all of their relevant capacity is fully committed must provide the following information: the amount of generation capacity that is fully committed, the names of the counterparties, the length of the long-term contract, the expiration date of the contract, and a representation that the contract is for firm sales for one year or longer.\6\ --------------------------------------------------------------------------- \6\ Order No. 816, FERC Stats. & Regs. ] 31,374 at P 39. --------------------------------------------------------------------------- 13. In response to NextEra's concern that at the time a seller files for market-based rate authority, the expiration date may be unknown, the Commission stated that if a contract expiration date is unknown at the time of the market-based rate filing, the seller must, within 30 days of the date becoming known, submit an informational filing, in the docket in which the seller was granted market-based rate authorization, to inform the Commission of the contract expiration date. In response to another commenter's remark that the expiration date is reported separately in electric quarterly report (EQR) filings, the Commission noted that many contracts reported in EQR filings do not include expiration dates and determined that it would require expiration date information in order to show that generation capacity is fully committed.\7\ --------------------------------------------------------------------------- \7\ Id. P 44. --------------------------------------------------------------------------- 2. Requests for Rehearing 14. NextEra requests rehearing of the Commission's determination concerning sellers with fully committed long-term generation capacity, stating that the Commission erred in requiring a market-based rate seller to report the expiration date of a long-term contract to the Commission within 30 days of the date being known, rather than simply in an EQR filing.\8\ NextEra contends that the Commission erred by failing to set forth an explanation of the specific after-the-fact need for the contract expiration date, as the seller is also required to provide the length of the long-term contract in order to demonstrate that it has no uncommitted capacity.\9\ NextEra states that if the Commission concludes that there is an actual need for this information given that after-the-fact reporting means that the expiration date can only be used in an ex post analysis, the Commission should clarify that it will permit sellers to provide the information to the Commission either through an EQR submission or on an after-the-fact basis.\10\ NextEra states that to the extent that a seller informs the Commission of the contract expiration date within 30 days of the date becoming known, the Commission should clarify that it will treat such filings as informational filings rather [[Page 33377]] than as amendments to pending applications.\11\ --------------------------------------------------------------------------- \8\ NextEra Rehearing Request at 2. \9\ Id. at 12. \10\ Id. at 13. \11\ Id. at 14. --------------------------------------------------------------------------- 3. Commission Determination 15. The Commission stated in Order No. 816 that sellers claiming that capacity is fully committed must provide, among other things, the length of the long-term contract and the expiration date of the contract. The same information must be provided for long-term firm sales of affiliated generation capacity located in the relevant balancing authority areas or markets, including first-tier markets. Including this information in the record of a seller's market-based rate filing is necessary so that a seller's claims of fully committed capacity can be verified as needed. 16. In Order No. 816, the Commission addressed comments submitted by NextEra regarding contract expiration dates. In consideration of NextEra's contention that the expiration date may be unknown at the time a seller files for market-based rate authority,\12\ the Commission determined that, in such instances, the seller must follow up with an informational filing to inform the Commission of the contract expiration date, within 30 days of the date becoming known.\13\ --------------------------------------------------------------------------- \12\ Order No. 816, FERC Stats. & Regs. ] 31,374 at P 38. \13\ Id. P 44. --------------------------------------------------------------------------- 17. In its request for rehearing, NextEra questions the necessity of requiring the expiration date given that sellers are required to provide the length of the contract. We continue to believe that the expiration date is an important piece of information for sellers to provide. The expiration date provides the Commission with a specific date as to when the affected generation capacity may become uncommitted and the expiration date allows the Commission to verify the information previously provided by the seller for purposes of the Commission's ex ante analysis of the seller's potential market power. With regard to NextEra's argument that the Commission erred in requiring the market- based rate seller to report the expiration date of a contract to the Commission within 30 days of the date being known, rather than in an EQR filing, we note that, as the Commission stated in Order No. 816, many contracts reported in EQR filings do not include expiration dates.\14\ Finally, consistent with Order No. 816, we grant NextEra's request that the Commission clarify that filings reporting contract expiration dates in support of a seller's claim that capacity is fully committed will be treated as informational filings rather than as amendments to filings.\15\ --------------------------------------------------------------------------- \14\ Id. \15\ Id. --------------------------------------------------------------------------- B. Reporting of Long-Term Firm Purchases 1. Final Rule 18. The Commission adopted the proposal to report in the indicative screens long-term firm purchases of capacity and/or energy that have an associated long-term firm transmission reservation. The Commission stated that requiring applicants under the market-based rate program to report all of their long-term firm purchases of energy and/or capacity, regardless of whether the applicant has operational control of the generation capacity supplying the purchased power, will improve the accuracy of the indicative screens.\16\ The Commission stated that long-term firm power purchase agreements that are reported in the indicative screens also should be reported in the asset appendix, Appendix B, and created a separate sheet in Appendix B specifically for applicants to report all such long-term firm purchases.\17\ --------------------------------------------------------------------------- \16\ Id. P 130. \17\ Id. P 139. --------------------------------------------------------------------------- 19. The Commission stated that the requirement that applicants only include long-term firm power purchase agreements in their indicative screens if they have an associated long-term transmission reservation will not apply within RTO/ISO markets if that RTO/ISO does not have long-term firm transmission reservations or their equivalent. Instead, applicants in such RTO/ISO markets will be required to report all long- term firm energy and/or capacity purchases from generation capacity located within the RTO/ISO market if the generation is designated as a network resource or as a resource with capacity obligations.\18\ --------------------------------------------------------------------------- \18\ Id. P 145. --------------------------------------------------------------------------- 2. Requests for Rehearing 20. SoCal Edison and NextEra seek clarification with regard to the reporting of long-term firm purchases. 21. SoCal Edison seeks clarification that the requirement to report all long-term firm energy and/or capacity purchases from generation capacity located within the RTO/ISO market if the generation is designated as a resource with capacity obligations does not apply if the generation is a qualifying facility exempt from section 205 of the FPA. SoCal Edison asserts that there is no reason why an applicant that holds a long-term contract with a qualifying facility exempt from FPA section 205 should have to report that in the appendix and screens, even if the facility has capacity obligations, when affiliate-owned exempt qualifying facilities would be excluded from the reporting requirement.\19\ --------------------------------------------------------------------------- \19\ SoCal Edison Rehearing Request at 2. --------------------------------------------------------------------------- 22. NextEra seeks clarification related to the necessity of reporting long-term power purchases in the asset appendix, Appendix B, by entities that do not have market-based rate authorization in their balancing authority area and as a result are not required to submit indicative screens.\20\ NextEra states that in Order No. 816, the Commission stated that long-term firm power purchase agreements that are reported in the indicative screens also should be reported in the asset appendix. NextEra states that based on this statement, NextEra understands that the Commission will not require the inclusion of long- term power purchase agreements if a seller does not have market-based rate authority in its balancing authority area, but instead makes only cost-based sales.\21\ NextEra asks the Commission to confirm that the inclusion of such information is only required for companies that have market-based authority in the relevant geographic market.\22\ --------------------------------------------------------------------------- \20\ NextEra Rehearing Request at 2. \21\ Id. at 14. \22\ Id. at 15. --------------------------------------------------------------------------- 3. Commission Determination 23. We grant SoCal Edison's requested clarification. Applicants purchasing energy and/or capacity from a qualifying facility that is exempt from section 205 of the FPA under a long-term firm power purchase agreement do not need to include such purchases in their indicative screens or in their asset appendix. In Order No. 816, the Commission determined that qualifying facilities that are exempt from section 205 of the FPA do not need to be reported in the asset appendix or indicative screens.\23\ Therefore, to ensure consistency in horizontal market power analyses filed by sellers we clarify that this exemption applies equally to long-term firm power purchases agreements backed by such resources. --------------------------------------------------------------------------- \23\ Order No. 816, FERC Stats. & Regs. ] 31,374 at P 255. --------------------------------------------------------------------------- 24. We reject NextEra's requested clarification. A market-based rate seller must list all of its generation assets in its asset appendix even if it does not have market-based rate authority in its balancing authority area or, indeed, even if its generation is fully committed and it is not submitting any indicative [[Page 33378]] screens. We see no reason to treat long-term firm power purchase agreements differently than other generation capacity. In Order No. 816, the Commission determined that long-term firm power purchase agreements with an associated long-term firm transmission reservation (or that are capacity resources in RTO/ISO markets) must be reported in a seller's indicative screens and asset appendix. Excluding long-term firm power purchase agreements as requested by NextEra would be inconsistent with that policy. In addition, sellers without market- based rate authority in their own balancing authority area typically seek market-based rate authority elsewhere and do so by submitting indicative screens for their first-tier markets. A seller's long-term firm power purchase agreements are a resource that would need to be reflected in the screens for the seller's first-tier markets. Since these agreements are reflected in the screens to the extent that they provide potential exports from a seller's balancing authority area to first-tier markets, they should be included in the seller's asset appendix. 25. We also clarify that the generation capacity associated with a unit-specific long-term contract should be reported in the ``Notes'' portion of the asset appendix. An example of this will be posted on the Commission's Web site. C. Clarification of the Definition or Duration of Long-Term Firm Transmission Reservations 1. Final Rule 26. In the Final Rule, the Commission provided clarification on the preparation of simultaneous transmission import limit (SIL) studies. In discussing SIL studies, the Commission declined a request to redefine the applicable duration of long-term firm transmission reservations, stating that it is currently defined as 28 days or longer.\24\ --------------------------------------------------------------------------- \24\ Id. P 197. --------------------------------------------------------------------------- 2. Requests for Rehearing 27. Southern states that Order No. 816 appears to erroneously refer to long-term firm transmission reservations as comprising reservations that are 28 days or longer. Southern maintains that this is contrary to precedent indicating that the expectation for entities performing SIL studies was that only transmission reservations with a duration longer than 28 days (i.e., a duration of 29 days and greater) should be considered to be long-term firm reservations. 3. Commission Determination 28. We clarify that the Commission did not intend to change the definition of long-term firm transmission reservations in Order No. 816. We reaffirm prior Commission guidance that short-term reservations are up to one month and long-term reservations are greater than one month.\25\ February is the shortest month, which means that long-term firm transmission reservations must be longer than 28 days. Thus, we clarify that long-term firm transmission reservations are longer than 28 days. --------------------------------------------------------------------------- \25\ Market-Based Rates for Wholesale Sales of Electric Energy Capacity and Ancillary Services by Public Utilities, Order No. 697- B, FERC Stats. & Regs. ] 31,285 at P 25 (2008). --------------------------------------------------------------------------- D. Notices of Change in Status 1. Final Rule 29. In the Notice of Proposed Rulemaking (NOPR), the Commission proposed to revise the change in status regulations at 18 CFR 35.42 to include a 100 MW threshold for reporting new affiliations. The Commission stated that a market-based rate seller that has a new affiliation would not be required to file a change in status for an affiliation with an entity with generation assets until its new affiliations result in a cumulative net increase of 100 MW or more of nameplate capacity in any relevant geographic market.\26\ In the Final Rule, the Commission adopted the proposed changes to the change in status requirements of section 35.42 of the Commission's regulations.\27\ --------------------------------------------------------------------------- \26\ Refinements to Policies and Procedures for Market-Based Rates for Wholesale Sales of Electric Energy, Capacity and Ancillary Services by Public Utilities, FERC Stats. & Regs. ] 32,702, at P 96 (2014) (NOPR). \27\ Order No. 816, FERC Stats. & Regs. ] 31,374 at P 251. --------------------------------------------------------------------------- 30. In the Final Rule, the Commission stated that the 100 MW threshold applies to each new relevant market (not previously studied) in which a seller and/or its affiliates acquire a cumulative net increase of 100 MW.\28\ The Commission clarified that the phrase ``any relevant market'' refers to a market in which a seller already has generation located and acquires an additional 100 MW or accumulates 100 MW or more in a new market that the seller had not studied previously.\29\ The Commission also clarified that the 100 MW threshold does not include generation capacity that can be imported from first- tier markets.\30\ The Commission agreed with commenters that generation capacity in first-tier markets should not be treated the same as capacity located in the seller's relevant geographic market/study area.\31\ --------------------------------------------------------------------------- \28\ Id. P 231. \29\ Id. P 237. \30\ Id. P 18. \31\ Id. P 229. --------------------------------------------------------------------------- 2. Requests for Rehearing 31. IPP Developers request that the Commission make the following three clarifications: (1) If an affiliate of a seller acquires or controls 100 MW of generating capacity (including long-term firm purchases), the seller must submit a notice of change in status report if that 100 MW is located in the same relevant market that was studied as the basis for the seller's grant of market-based rate authority; (2) if an affiliate of the seller acquires or controls 100 MW or more of generating capacity (including long-term firm purchases) in a market that is two tiers away or more, the seller is not required to submit a notice of change in status report; and (3) if an affiliate of the seller acquires or controls 100 MW or more of generating capacity (including long-term firm purchases) in a market that is in the first- tier, the seller is not required to submit a notice of change in status report.\32\ IPP Developers state that these three clarification requests appear to be a proper application of the Commission's statements in Order No. 816. IPP Developers conclude that a seller does not have a change in status reporting obligation in regard to an affiliate's generation in first-tier and beyond areas.\33\ --------------------------------------------------------------------------- \32\ IPP Developers Rehearing Request at 1-3. \33\ Id. --------------------------------------------------------------------------- 32. However, IPP Developers state that the following statement in paragraph 238 of Order No. 816 makes this reporting obligation unclear: ``if a seller's affiliate is granted market based rate authority, and that results in 100 MW or more of new generation in a market, then the seller will have to file a corresponding change in status.'' \34\ IPP Developers state that ``a market'' could be any market other than the seller's studied relevant market, i.e., affiliate generation in first- tier or beyond markets.\35\ IPP Developers state that this statement appears to say that a seller must file a notice of change in status report regardless of the market in which an affiliate of the seller acquires or controls 100 MW or more of generating capacity.\36\ --------------------------------------------------------------------------- \34\ Id. at 3-4 (citing Order No. 816, FERC Stats. & Regs. ] 31,374 at P 238 (emphasis added)). \35\ Id. at 4. \36\ Id. --------------------------------------------------------------------------- 33. IPP Developers state that if the Commission is not inclined to provide the clarifications above, then IPP Developers request rehearing.\37\ --------------------------------------------------------------------------- \37\ Id. at 3. --------------------------------------------------------------------------- 34. TAPS seeks rehearing of the threshold calculation, arguing that [[Page 33379]] capacity in first-tier markets should be included for determining changes in the 100 MW change in status threshold.\38\ TAPS states that in the NOPR, the Commission proposed to clarify that the ``relevant geographic market'' for purposes of that 100 MW trigger included generation capacity that could be imported from first-tier markets.\39\ TAPS states that the Commission then reversed the NOPR proposal, stating that it would ``exclude markets and balancing authority areas that are first-tier to the seller's study area.'' \40\ TAPS states that the Commission erred and should grant rehearing to revise Order No. 816 to include generation in first-tier markets for purposes of change in status reporting, whether or not it is supported by a long-term firm transmission reservation.\41\ Specifically, TAPS states that the Commission should require sellers to: (1) Include first-tier capacity when there is a long-term transmission reservation associated with the capacity; and (2) include all other first-tier capacity either in its entirety or, in the alternative, on a pro rata basis consistent with the inclusion of such generation in market power screens.\42\ --------------------------------------------------------------------------- \38\ TAPS Rehearing Request at 1. \39\ Id. at 4 (citing NOPR, FERC Stats. & Regs. ] 32,702 at P 96). \40\ Id. at 5 (citing Order No. 816, FERC Stats. & Regs. ] 31,374 at P 230). \41\ Id. at 6. \42\ Id. at 5. --------------------------------------------------------------------------- 35. TAPS states that the NOPR's proposal to include first-tier generation capacity is both simple and adequate.\43\ TAPS states that the Commission could allow sellers, with appropriate support, to prorate generation in markets first-tier to the study area in the same way capacity is assigned pro rata for indicative screen analyses (assuming there are no firm transmission reservations associated with the first-tier capacity, in which case it should be accorded its full megawatt value). TAPS states that this approach would be consistent with the methodology used in the indicative screens, but would require more analysis than reporting of all first-tier capacity for purposes of change in status reports.\44\ --------------------------------------------------------------------------- \43\ Id. at 6-7. \44\ Id. at 7. --------------------------------------------------------------------------- 3. Commission Determination 36. We grant clarification regarding IPP Developers' three examples of the application of Order No. 816. The scenarios presented by IPP Developers are a proper application of the Final Rule, assuming that the seller is not a power marketer (i.e., the seller owns generation). We also grant clarification regarding the Commission's statement in paragraph 238 of Order No. 816. In paragraph 238 of Order No. 816, the Commission stated that ``if a seller's affiliate is granted market- based rate authority, and that results in 100 MW or more of new generation in a market, then the seller will have to file a corresponding change in status.'' \45\ We clarify that the phrase ``in a market'' means any relevant geographic market for the seller at the time of the change in status filing. Further, we note that the relevant geographic market for a particular seller depends on whether the seller is a power producer or a power marketer, whether the seller owns transmission or is interconnected to an affiliated transmission system, and whether the seller's generation is in an RTO/ISO. The relevant markets for a power marketer include any market where the power marketer's affiliates own generation. Thus, a power marketer that does not own any generation itself would need to report a change in status for a 100 MW net increase in any market where an affiliate owns generation and has been granted market-based rate authority.\46\ However, for a power producer, the relevant geographic market is where the seller's generation is physically located. Thus, a power producer would not need to report a 100 MW affiliate net increase in a market where the power producer itself does not own any generation. Similarly, in traditional (non-RTO/ISO) markets, the default relevant geographic market is ``first, the balancing authority area where the seller is physically located, and second, the markets directly interconnected to the seller's balancing authority area.'' \47\ However, ``[w]here a generator is interconnecting to a non-affiliate owned or controlled transmission system, there is one relevant geographic market (i.e., the balancing authority area in which the generator is located).'' \48\ For a seller located in an RTO/ISO market, the seller may consider the RTO/ ISO as the default relevant geographic market.\49\ In each circumstance, the market-based rate seller will have to determine whether any 100 MW increase is in a market that would be a relevant geographic market for that seller. --------------------------------------------------------------------------- \45\ Order No. 816, FERC Stats. & Regs. ] 31,374 at P 238 (emphasis added). \46\ A power marketer with no affiliated generation is a Category 1 seller (exempt from filing triennial updated market power analysis) in all regions and has no relevant geographic market. A power marketer that acquires generation via a long-term power purchase agreement has a relevant geographic market where the power associated with this agreement is delivered (sinks), not where it originates (unless source and sink are in the same market, which is often the case). In this scenario, the power marketer is a Category 1 or 2 seller in the relevant geographic market depending on the MWs associated with the contract(s). Category 2 sellers must submit triennial update market power analyses. \47\ 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 P 232 (2007). \48\ Id. P 232 n.217. \49\ Id. P 235 (noting that a seller may consider the RTO/ISO as the default relevant geographic market ``unless the Commission has already found the existence of a submarket''). --------------------------------------------------------------------------- 37. We deny TAPS's request that capacity in first-tier markets be included for determining the 100 MW change in status threshold. As the Commission stated in Order No. 816, when a seller has a change in status in a particular market, it does not need to include any changes in adjoining first-tier markets in calculating the 100 MW threshold, even when a purchaser has long-term firm transmission rights to import affiliated capacity located in a first-tier market. We reiterate that, with respect to the calculation of the 100 MW threshold, 100 MW located outside of the study area is not equivalent to 100 MW inside the study area. In addition, requiring sellers to consider generation capacity in first-tier markets, and prorate generation from the first-tier markets into the study area, creates uncertainty as to when a seller would trip the 100 MW threshold and effectively would force a seller to prepare import analyses to determine how much of their additional first-tier capacity could be imported into the study area. We believe that the increased burden of preparing such studies would outweigh the potential benefit gained from receiving additional information about a seller's affiliated generation. E. New Affiliation and Behind-the-Meter Generation 1. Final Rule 38. As stated above, the Commission adopted the NOPR proposal to establish a 100 MW threshold for reporting new affiliations in change of status filings. The Commission stated that a market-based rate seller that has a new affiliation will not be required to file a change in status for an affiliation with an entity with generation assets until its new affiliations result in a cumulative net increase of 100 MW of capacity in a relevant geographic market.\50\ The [[Page 33380]] Commission stated that the 100 MW threshold will be determined for each relevant geographic market but will not consider generation capacity additions in first-tier markets.\51\ --------------------------------------------------------------------------- \50\ Order No. 816, FERC Stats. & Regs. ] 31,374 at P 251. The Commission noted that if a seller files a notice of change in status for another reason, e.g., to report the entrance into a power purchase agreement of more than 100 MW, the seller should note that it has a new affiliate with market-based rate authority and include that new affiliate and any related assets in the seller's asset appendix. Id. P 251 n.334. \51\ Id. P 251. --------------------------------------------------------------------------- 39. The Commission did not adopt the NOPR proposal to count behind- the-meter generation in the 100 MW change in status threshold and 500 MW Category 1 seller threshold or to include such generation in the asset appendix and indicative screens.\52\ --------------------------------------------------------------------------- \52\ Id. P 252. --------------------------------------------------------------------------- 40. The Commission stated that the output of behind-the-meter generation should be reflected in the load data reported in the FERC Form No. 714, which reflects the fact that the load is lower than it otherwise would be if a portion of the load were not served by behind- the-meter generation. The Commission also stated that, since behind- the-meter generation is netted out of the load data, requiring sellers to count behind-the-meter generation as installed capacity could result in double-counting a portion of the seller's generation capacity. The Commission clarified that behind-the-meter generation that is consumed on-site by the host load and not sold into the wholesale market, or is not synchronized to the transmission grid, is not relevant to the Commission's horizontal market power analysis.\53\ --------------------------------------------------------------------------- \53\ Id. P 253. --------------------------------------------------------------------------- 2. Requests for Rehearing 41. TAPS requests rehearing and/or clarification, arguing that behind-the-meter generation that is available to make wholesale sales and that is not reflected as a reduction in load reported in Form No. 714 should be included in seller reporting obligations, including the 100 MW change in status threshold, the indicative screens, the asset appendix, and the 500 MW Category 1 seller status threshold. 42. Specifically, TAPS states that the Commission should make clear that behind-the-meter generation that is not consumed on-site by the host load and reflected in Form No. 714 load data must, consistent with the Commission's duty to assess market power, be included in seller reporting obligations and indicative screens and category seller status determinations. TAPS contends that generation that participates in the wholesale markets influences a seller's market power regardless of whether it may be termed behind-the-meter.\54\ TAPS argues that even if it were otherwise permissible, the exclusion for behind-the-meter generation would be arbitrary and capricious. TAPS states that because Order No. 816 fails to limit the scope of the behind-the-meter exclusion to that included in load reported in Form No. 714 or not synchronized to the grid and provides no definition of behind-the-meter generation, sellers are left to their own devices to determine what is meant by behind-the-meter generation and then to exclude those resources for purposes of reporting under Order No. 816.\55\ --------------------------------------------------------------------------- \54\ TAPS Rehearing Request at 11. \55\ Id. --------------------------------------------------------------------------- 43. TAPS states that the Commission should clarify that its exclusion of behind-the-meter generation was intended to be restricted by its clarification at paragraph 253 of the Final Rule--that only generation that is reflected in Form No. 714 or not synchronized would be excludable from generation from market-based rate reporting and market power screens. Alternatively, TAPS states that the Commission should grant rehearing and: (1) Adopt its NOPR proposal to include behind-the-meter generation, with El Paso's clarification--i.e., that behind-the-meter generation that is not reflected as a decrease in load on Form No. 714 should be included in seller reporting obligations and all market power screens; or (2) otherwise avoid creating a behind-the- meter generation blind spot of undefined proportions in its market power monitoring and assessment regimen.\56\ --------------------------------------------------------------------------- \56\ Id. at 13. --------------------------------------------------------------------------- 3. Commission Determination 44. We deny TAPS's request for rehearing. As the Commission stated in the Final Rule, the output of behind-the-meter generation largely should be reflected in the load data reported in the FERC Form No. 714, which reflects the fact that the load is lower than it otherwise would be if a portion of the load were not served by behind-the-meter generation. Accordingly, since behind-the-meter generation is netted out of the load data, requiring sellers to count behind-the-meter generation as installed capacity could result in double-counting a portion of some sellers' generation capacity. Further, the Commission stated in the Final Rule that behind-the-meter generation not sold into the wholesale market is not relevant to the Commission's horizontal market power analysis. Regarding TAPS's concern about behind-the-meter generation that is available to make wholesale sales and is not reflected in load reported in Form No. 714, we believe, at this time, that this category of generation is relatively limited and that the burden of sellers reporting this behind-the-meter generation would outweigh the benefits of such reporting. Therefore, at this time, we will not require sellers to report this type of generation. F. Corporate Organizational Charts 1. Final Rule 45. In the Final Rule, the Commission adopted the proposal to require a seller to include a corporate organizational chart when filing an initial application for market-based rate authority, an updated market power analysis, or, in some circumstances, a notice of change in status reporting new affiliations.\57\ The Commission revised the regulatory text in section 35.37(a)(2) and in section 35.42(c) in this regard. --------------------------------------------------------------------------- \57\ Order No. 816, FERC Stats. & Regs. ] 31,374 at P 21. --------------------------------------------------------------------------- 2. Requests for Rehearing 46. Invenergy, SoCal Edison, NextEra, EEI, and EPSA request rehearing and/or clarification with respect to the requirement to submit corporate organizational charts. Parties argue, among other things, that the requirement imposes a substantial administrative burden on filers and is at odds with the objective of streamlining the market-based rate filing process. 3. Commission Determination 47. As noted above, upon consideration of requests for a stay of the corporate organizational chart requirement, the Commission issued an order granting an extension of time such that market-based rate applicants and sellers would not be required to comply with the corporate organizational chart requirement prior to the issuance of an order on the merits of the requests for rehearing.\58\ Upon consideration of the concerns raised by the parties on rehearing regarding this requirement, we grant an additional extension of time such that market-based rate applicants and sellers will not be required to comply with the corporate organizational chart requirement until the Commission issues an order at a later date addressing this requirement. The extension will allow the Commission more time to fully consider the benefits and burdens associated with the corporate organizational chart requirement.\59\ --------------------------------------------------------------------------- \58\ Refinements to Policies and Procedures for Market-Based Rates for Wholesale Sales of Electric Energy, Capacity and Ancillary Services by Public Utilities, 153 FERC ] 61,337 (2015). \59\ The Commission continues to consider appropriate mechanisms for consolidating the Commission's data collection requirements, including this organizational chart requirement, with the proposed rulemakings in Docket Nos. RM15-23 and RM16-3. --------------------------------------------------------------------------- [[Page 33381]] G. Part 101 Waivers 1. Final Rule 48. The Commission clarified that granting waiver of 18 CFR part 101 under market-based rate authority does not waive the requirements under Part I of the FPA for hydropower licensees. In addition, the Commission clarified that hydropower licensees that only make sales at market-based rates may satisfy the requirements in Part 101 of the Commission's regulations (Uniform System of Accounts) by complying with General Instruction 16 of the Uniform System of Accounts, and confirmed that hydropower licensees that have Commission-approved cost-based rates are required to comply with the full requirements of the Uniform System of Accounts.\60\ --------------------------------------------------------------------------- \60\ Order No. 816, FERC Stats. & Regs. ] 31,374 at P 22. --------------------------------------------------------------------------- 2. Requests for Rehearing 49. NHA requests clarification that a hydropower licensee that otherwise sells power only at market-based rates will not be subject to the full requirements of the Uniform System of Accounts as a consequence of filing a cost-based reactive power tariff with the Commission.\61\ Alternatively, NHA requests that the Commission clarify that it will allow licensees that otherwise sell only at market-based rates to request authorization, on a case-by-case basis, to continue to rely on General Instruction 16 of the Uniform System of Accounts at the time a reactive power tariff is filed with the Commission.\62\ --------------------------------------------------------------------------- \61\ NHA Clarification Request at 3-5. \62\ Id. at 5. --------------------------------------------------------------------------- 50. NHA argues that the Commission determined in Order No. 697 that ``little purpose would be served to require compliance with accounting regulations for entities that do not sell at cost-based rates and do not have captive customers.'' \63\ NHA represents that the Commission has previously found that reactive power tariffs do not have captive customers and do not raise the same concerns as other cost-based rate tariffs.\64\ Additionally NHA notes that entities with a reactive power tariff and a market-based rate tariff have been previously granted waiver of Part 101.\65\ --------------------------------------------------------------------------- \63\ Id. at 3 (citing Order No. 697, FERC Stats. & Regs. ] 31,252 at P 984). \64\ Id. at 3-4 (citing Order No. 697, FERC Stats. & Regs. ] 31,252 at P 483 (``concerns underlying the affiliate restrictions do not apply to sales of reactive power because those sales are typically either made to transmission providers so that the transmission provider can satisfy its obligation to provide reactive power or made by the transmission provider under its applicable [open access transmission tariff]'')). \65\ Id. (citing Sunbury Generation, LLC, 108 FERC ] 61,160 (2004) (Sunbury); Illinois Power Generating Co., 148 FERC ] 61,238 (2014) (granting waivers of Parts 41, 101, and 141 of the Commission's regulations to entities with a cost-based rate reactive power tariff and a market-based rate tariff)). --------------------------------------------------------------------------- 3. Commission Determination 51. We clarify that a hydropower licensee that otherwise sells power only at market-based rates will not be subject to the full requirements of the Uniform System of Accounts as a consequence of filing a cost-based reactive power tariff with the Commission. Such a seller may satisfy the requirements in Part 101 of the Commission's regulations by complying with General Instruction 16 of the Uniform System of Accounts. We find that this clarification is consistent with previous Commission findings in Order No. 697 and Sunbury, as noted by NHA. We continue to find, however, that hydropower licensees that have Commission-approved cost-based rates are required to comply with the full requirements of the Uniform System of Accounts.\66\ Additionally, we remind sellers that ``previously granted waivers of the accounting requirements will continue to be rescinded where a seller is found to have market power (or where the sellers accepts a presumption of market power) and the seller proposes cost-based rate mitigation or the Commission imposes cost-based rate mitigation.'' \67\ --------------------------------------------------------------------------- \66\ Order No. 816, FERC Stats. & Regs. ] 31,374 at P 22. \67\ Order No. 697, FERC Stats. & Regs. ] 31,252 at P 986. --------------------------------------------------------------------------- H. Capacity Ratings 1. Final Rule 52. In the Final Rule, the Commission revised the regulations at 18 CFR 35.42 relating to the change in status reporting requirements to permit sellers to use nameplate or seasonal capacity ratings for the 100 MW threshold for most generation and allow energy-limited generation to use either nameplate or a five-year average capacity factor.\68\ The Commission found that solar photovoltaic and solar thermal facilities are energy limited and determined that, due to their unique characteristics, solar photovoltaic facilities, unlike other energy-limited facilities, must use nameplate capacity and may not use five-year average capacity factors.\69\ --------------------------------------------------------------------------- \68\ Order No. 816, FERC Stats. & Regs. ] 31,374 at P 232. \69\ Id. P 15. --------------------------------------------------------------------------- 2. Request for Rehearing 53. Southern notes the Commission's determination in the Final Rule permitted sellers to use nameplate or seasonal capacity ratings for the 100 MW threshold for most generation. Southern states that the regulatory text accompanying the Final Rule includes the phrase ``or seasonal'' in 18 CFR 35.42(a)(2)(i) but not in 18 CFR 35.42(a)(1). Southern requests that the Commission add the phrase ``or seasonal'' to 18 CFR 35.42(a)(1) to align with the discussion in the Final Rule.\70\ --------------------------------------------------------------------------- \70\ Southern Rehearing Request at 7 n.15 (citing Order No. 816, FERC Stats. & Regs. ] 31,374 at P 232). --------------------------------------------------------------------------- 3. Commission Determination 54. We find that it is appropriate to revise 18 CFR 35.42(a)(1) to add the phrase ``or seasonal.'' Additionally, we are revising both 18 CFR 35.42(a)(1) and (a)(2)(i) to further align the regulations with the discussion in the Final Rule. Specifically, the revised regulations will indicate that the 100 MW or more of capacity should be based on nameplate or seasonal capacity ratings and, for energy-limited resources, with the exception of solar photovoltaic facilities, the capacity ratings should be based on nameplate or five-year average capacity factors. These revised regulations will indicate that for solar photovoltaic facilities, the capacity ratings should be based on nameplate capacity. I. Inputs to Electric Power Production 1. Final Rule 55. The Commission considers a seller's ability to erect other barriers to entry as part of the vertical market power analysis and, as such, the Commission requires a seller to provide a description of its inputs to electric power production.\71\ Section 35.36(a)(4) of the Commission's regulations define inputs to electric power production to mean intrastate natural gas transportation, intrastate natural gas storage or distribution facilities, sites for generation capacity development, physical coal supply sources and ownership of or control over who may access transportation of coal supplies. --------------------------------------------------------------------------- \71\ Order No. 816, FERC Stats. & Regs. ] 31,374 at P 6. --------------------------------------------------------------------------- 56. In the Final Rule, the Commission eliminated the requirement that market-based rate sellers file quarterly land acquisition reports and provide information on sites for generation capacity development in market-based rate applications and triennial updated market power analyses. Specifically, the Commission adopted the proposal to [[Page 33382]] revise the regulations at 18 CFR 35.42 relating to the change in status reporting requirements regarding sites for new generation capacity development and also adopted the proposal to revise the regulations at 18 CFR 35.37 to remove the requirement that sellers provide information regarding sites for generation capacity development to demonstrate a lack of vertical market power. However, no changes to the definition of inputs to electric power production were made in the Final Rule. 2. Commission Determination 57. In light the determinations made in the Final Rule, we revise our regulations at 18 CFR 35.36(a)(4) to remove sites for generation capacity development from the definition of inputs to electric power production. However, we clarify that the affirmative statement regarding barriers to entry required in 18 CFR 35.37(e)(3) continues to cover sites for generation capacity development. J. Transmission/Natural Gas Assets Sheet 1. Final Rule 58. In the NOPR, the Commission proposed to require any seller that has been granted waiver of the requirement to file an open access transmission tariff (OATT) for its transmission facilities to report in its Transmission/Natural Gas Assets Sheet the citation to the Commission order granting the OATT waiver for those transmission facilities.\72\ The Commission did not adopt the NOPR proposal in the Final Rule, agreeing with SoCal Edison that this requirement would not provide useful information in light of Order No. 807.\73\ The Commission further stated that, ``even if a seller has been granted waiver of the requirement to file an OATT, those transmission facilities should be reported in its asset appendix.'' \74\ --------------------------------------------------------------------------- \72\ NOPR, FERC Stats. & Regs. ] 32,702 at P 120. \73\ Order No. 816, FERC Stats. & Regs. ] 31,374 at P 300 (citing Open Access and Priority Rights on Interconnection Customer's Interconnection Facilities, Order No. 807, FERC Stats. & Regs. ] 31,367 (2015) (amending Commission regulations to waive the OATT requirements of section 35.28, the OASIS requirements of Part 37, and the Standards of Conduct requirements of Part 358, under certain conditions, for entities that own interconnection facilities)). \74\ Id. P 295 (citing Order No. 697-A, FERC Stats. & Regs. ] 31,268 at P 378 (``We clarify that the transmission facilities that we require to be included in that asset appendix are limited to those the ownership or control of which would require an entity to have an OATT on file with the Commission (even if the Commission has waived the OATT requirement for a particular seller).'')). --------------------------------------------------------------------------- 2. Commission Determination 59. Upon further consideration, we modify the requirement to report in the asset appendix transmission facilities that have been granted an individual OATT waiver or that qualify for a blanket waiver under Order No. 807 and find that sellers are no longer required to include such facilities in their Transmission/Natural Gas Assets Sheet. We find that the burden of providing information on such facilities outweighs any benefit to reporting it. For this reason, we eliminate the requirement to report in the Transmission/Natural Gas Assets Sheet facilities that qualify for blanket waiver of the OATT requirement under Order No. 807 and those that have been granted an individual OATT waiver. K. Long-Term Firm Power Purchases List 1. Final Rule 60. In the Final Rule, the Commission established a new, separate list in the asset appendix in which market-based rate sellers are to report their Long-Term Firm Power Purchase Agreements (PPAs).\75\ The Commission agreed with commenters that the format of the Generation Assets Sheet was not well suited for reporting long-term firm purchases. --------------------------------------------------------------------------- \75\ Id. P 270. --------------------------------------------------------------------------- 2. Commission Determination 61. Subsequent to the issuance of Order No. 816, Commission Staff received numerous calls from sellers requesting guidance with respect to completing the Long-Term Firm PPAs Sheet. Upon further consideration, we recognize that certain modifications to this sheet and its instructions are warranted to improve its clarity. To that end, we are making the following changes. First, we are eliminating the existing column B, ``Docket # where MBR authority was granted'' as this is duplicative of information required elsewhere in the asset appendix. In response to questions as to whether the ``Market/Balancing Authority Area'' column was referring to the source or sink of the transaction, we are adding a column and specifically requesting sellers to identify both the source and sink of the transaction in separate designated columns. Finally, in response to other questions raised by market-based rate filers, we are adding a column requiring sellers to indicate whether a particular long-term firm purchase agreement is backed by a specific identified generation unit or by the supplier's generation fleet (i.e., a ``system'' contract). Instructions for the Long-Term Firm PPAs Sheet have been modified to reflect these changes and to make certain other clean up edits. L. Generation Assets Sheet, Rows [B] and [H] 1. Final Rule 62. The Final Rule contained instructions for completing the asset appendix. The description of Row [B] indicated that, if applicable, sellers should include the docket number where market-based rate or qualifying facility status was originally granted, and that it can be an EL or QF docket number. The description of Row [H] listed the six market-based rate regions but mistakenly listed the Southeast region twice and failed to mention the Northwest region. 2. Commission Determination 63. We revise the instructions for Row [B] of the asset appendix to remove references to EL and QF dockets. This revision does not change the Commission's determinations in Order No. 816. Rather, this revision aligns the description and format information regarding Row [B] with the Commission's intent that Row [B] contain the docket number where market-based rate authority was granted. 64. We revise the instructions to Row [H] of the Generation Assets Sheet to delete the second reference to ``Southeast'' and replace it with ``Northwest.'' III. Information Collection Statement 65. The Office of Management and Budget (OMB) regulations implementing the Paperwork Reduction Act of 1995 \76\ require that OMB approve certain information collection requirements imposed by an agency.\77\ Upon approval of a collection(s) of information, OMB will assign an OMB control number and an expiration date. Respondents subject to the filing requirements of a rule will not be penalized for failing to respond to these collections of information unless the collections of information display a valid OMB control number. --------------------------------------------------------------------------- \76\ 44 U.S.C. 3507(d) (2012). \77\ 5 CFR 1320.11. --------------------------------------------------------------------------- 66. The revisions made in Order No. 816 to the information collection requirements for market-based rate sellers were approved under FERC-919 (OMB Control No. 1902-0234).\78\ This order clarifies and makes minor revisions to some aspects of the existing information collection requirements for the market-based rate program. The [[Page 33383]] changes to the information collection include: --------------------------------------------------------------------------- \78\ OMB approved the information collection in Order No. 816 on December 22, 2015. ---------------------------------------------------------------------------Removing the need to list transmission facilities in the Transmission/Natural Gas Assets Sheet that have an OATT waiver or that qualify for the blanket OATT waiver (a slight burden decrease) adding a source/sink column and a column for generation unit/system contract type to the Long-Term Firm PPAs Sheet (slight burden increases) removing column B, ``Docket # where MBR authority was granted'' from the Long-Term Firm PPAs Sheet and removing references to ``EL'' and ``QF'' in the instructions for Row [B] of the Generation Assets Sheet (de minimis decreases) removing sites for generation capacity development from the definition of inputs to electric power production at 18 CFR 35.36(a)(4) (no change to burden). The Commission estimates that there will be no net change to burden. This Final Rule will be submitted to OMB for review and approval of a ``No Material/Nonsubstantive Change.'' Title: Market Based Rates for Wholesale Sales of Electric Energy, Capacity and Ancillary Services by Public Utilities (FERC-919). Action: Clarification and Revision of Currently Approved Collection of Information. OMB Control No.: 1902-0234. Respondents for This Rulemaking: Public utilities, wholesale electricity sellers, businesses, or other for profit and/or not for profit institutions. 67. Interested persons may obtain information on the reporting requirements by contacting: Federal Energy Regulatory Commission, 888 First Street NE., Washington, DC 20426 [Attention: Ellen Brown, Office of the Executive Director, email: DataClearance@ferc.gov, phone: (202) 502-8663, fax: (202) 273-0873]. Comments concerning the requirements of this rule may also be sent to the Office of Information and Regulatory Affairs, Office of Management and Budget, Washington, DC 20503 [Attention: Desk Officer for the Federal Energy Regulatory Commission]. For security reasons, comments should be sent by email to OMB at oira_submission@omb.eop.gov. Comments submitted to OMB should refer to FERC-919 and OMB Control Number 1902-0234. IV. Document Availability 68. In addition to publishing the full text of this document in the Federal Register, the Commission provides all interested persons an opportunity to view and/or print the contents of this document via the Internet through FERC's Home Page (http://www.ferc.gov) and in FERC's Public Reference Room during normal business hours (8:30 a.m. to 5:00 p.m. Eastern time) at 888 First Street NE., Room 2A, Washington, DC 20426. 69. From FERC's Home Page on the Internet, this information is available on eLibrary. The full text of this document is available on eLibrary in PDF and Microsoft Word format for viewing, printing, and/or downloading. To access this document in eLibrary, type the docket number excluding the last three digits of this document in the docket number field. 70. User assistance is available for eLibrary and the FERC's Web site during normal business hours from FERC Online Support at 202-502- 6652 (toll free at 1-866-208-3676) or email at ferconlinesupport@ferc.gov, or the Public Reference Room at (202) 502- 8371, TTY (202) 502-8659. Email the Public Reference Room at public.referenceroom@ferc.gov. V. Effective Date 71. These regulations are effective July 25, 2016. List of Subjects in 18 CFR Part 35 Electric power rates, Electric utilities, Reporting and recordkeeping requirements. By the Commission. Issued: May 19, 2016. Nathaniel J. Davis, Sr., Deputy Secretary. In consideration of the foregoing, the Commission amends Part 35, Chapter I, Title 18, Code of Federal Regulations, as follows: PART 35--FILING OF RATE SCHEDULES AND TARIFFS 0 1. The authority citation for part 35 continues to read as follows: Authority: 16 U.S.C. 791a-825r, 2601-2645; 31 U.S.C. 9701; 42 U.S.C. 7101-7352. Sec. 35.36 [Amended] 0 2. Amend Sec. 35.36 as follows: 0 a. In paragraph (a)(4), remove the comma and add in its place a semicolon. 0 b. In paragraph (a)(4), remove the phrase ``sites for generation capacity development;''. 0 3. Amend Sec. 35.42 by revising paragraphs (a)(1) and (a)(2)(i) to read as follows: Sec. 35.42 Change in status reporting requirement. (a) * * * (1) Ownership or control of generation capacity or long-term firm purchases of capacity and/or energy that results in cumulative net increases (i.e., the difference between increases and decreases in affiliated generation capacity) of 100 MW or more of capacity based on nameplate or seasonal capacity ratings, or, for solar photovoltaic facilities, nameplate capacity, or, for other energy-limited resources, nameplate or five-year average capacity factors, in any individual relevant geographic market, or of inputs to electric power production, or ownership, operation or control of transmission facilities; or (2) * * * (i) Owns or controls generation facilities or has long-term firm purchases of capacity and/or energy that results in cumulative net increases (i.e., the difference between increases and decreases in affiliated generation capacity) of 100 MW or more of capacity based on nameplate or seasonal capacity ratings, or, for solar photovoltaic facilities, nameplate capacity, or, for other energy-limited resources, nameplate or five-year average capacity factors, in any individual relevant geographic market; * * * * * 0 4. Revise appendix B to subpart H to read as follows: Appendix B to Subpart H of Part 35--Corporate Entities and Assets Sample Appendix BILLING CODE 6717-0-P [[Page 33384]] [GRAPHIC] [TIFF OMITTED] TR26MY16.039 [[Page 33385]] [GRAPHIC] [TIFF OMITTED] TR26MY16.040 [[Page 33386]] [GRAPHIC] [TIFF OMITTED] TR26MY16.041 [[Page 33387]] [GRAPHIC] [TIFF OMITTED] TR26MY16.042 [FR Doc. 2016-12427 Filed 5-25-16; 8:45 a.m.] BILLING CODE 6717-01-C
![Federal Register / Vol. 81, No. 102 / Thursday, May 26, 2016 / Rules and Regulations 33375
individual is an eligible contract By the Commission. SUMMARY: The Federal Energy
participant if the individual has Dated: May 20, 2016. Regulatory Commission is denying
aggregate amounts invested on a Brent J. Fields, requests for rehearing and granting, in
discretionary basis of more than $10 Secretary. part, clarification of its determinations
million or more than $5 million if such [FR Doc. 2016–12390 Filed 5–25–16; 8:45 am] in Order No. 816, which amended its
individual enters into the transaction to BILLING CODE 8011–01–P
regulations that govern market-based
manage the risk associated with an asset rate authorizations for wholesale sales
owned or liability incurred, or of electric energy, capacity, and
reasonably likely to be owned or ancillary services by public utilities
DEPARTMENT OF ENERGY
incurred by such individual.7 pursuant to the Federal Power Act.
The Commission adopted Rule Federal Energy Regulatory DATES: This rule will become effective
15b12–1 (17 CFR 240.15b12–1) on a Commission July 25, 2016.
time-limited basis to permit a registered FOR FURTHER INFORMATION CONTACT:
broker-dealer to engage in a retail forex 18 CFR Part 35 Greg Basheda (Technical Information),
business.8 The Commission is taking no [Docket No. RM14–14–001; Order No. 816– Office of Energy Market Regulation,
further action, and pursuant to Rule A] Federal Energy Regulatory
15b12–1(d), Rule 15b12–1 will expire Commission, 888 First Street NE.,
and no longer be effective on July 31, Refinements to Policies and Washington, DC 20426, (202) 502–
2016. Upon expiration of the rule on Procedures for Market-Based Rates for 6479.
July 31, 2016, a broker-dealer registered Wholesale Sales of Electric Energy, Carol Johnson (Legal Information),
pursuant to Section 15(b) of the Capacity and Ancillary Services by Office of the General Counsel, Federal
Exchange Act, including an entity that Public Utilities Energy Regulatory Commission, 888
is registered as both a broker-dealer and AGENCY: Federal Energy Regulatory First Street NE., Washington, DC
a futures commission merchant, shall be Commission, DOE. 20426, (202) 502–8521.
prohibited from offering or entering into
ACTION: Final rule; Order on rehearing SUPPLEMENTARY INFORMATION:
a retail forex transaction pursuant to
and clarification.
Section 2(c)(2)(E) of the CEA. Table of Contents
Paragraph
Nos.
I. Introduction ........................................................................................................................................................................................... 1
II. Discussion ............................................................................................................................................................................................ 12
A. Sellers with Fully Committed Long-Term Generation Capacity ............................................................................................... 12
B. Reporting of Long-Term Firm Purchases .................................................................................................................................... 18
C. Clarification of the Definition or Duration of Long-Term Firm Transmission Reservations ................................................... 26
D. Notices of Change in Status ......................................................................................................................................................... 29
E. New Affiliation and Behind-the-Meter Generation .................................................................................................................... 38
F. Corporate Organizational Charts .................................................................................................................................................. 45
G. Part 101 Waivers ........................................................................................................................................................................... 48
H. Capacity Ratings ........................................................................................................................................................................... 52
I. Inputs to Electric Power Production ............................................................................................................................................. 55
J. Transmission/Natural Gas Assets Sheet ....................................................................................................................................... 58
K. Long-Term Firm Power Purchases List ....................................................................................................................................... 60
L. Generation Assets Sheet, Rows [B] and [H] ................................................................................................................................ 62
III. Information Collection Statement ...................................................................................................................................................... 65
IV. Document Availability ....................................................................................................................................................................... 68
V. Effective Date ....................................................................................................................................................................................... 71
Order No. 816–A (Commission) issued Order No. 816,1 Power Act (FPA). In this order, we
which amended its regulations that address requests for rehearing and
Order on Rehearing and Clarification
govern market-based rate authorizations clarification of Order No. 816.2
I. Introduction for wholesale sales of electric energy, 2. Nine requests for rehearing and
1. On October 16, 2015, the Federal capacity, and ancillary services by clarification were filed.3 The requests
Energy Regulatory Commission public utilities pursuant to the Federal for rehearing and clarification concern
to transactions with major swap participants, swap 1 Refinements to Policies and Procedures for Sales of Electric Energy, Capacity and Ancillary
dealers, major security-based swap participants, Market-Based Rates for Wholesale Sales of Electric Services by Public Utilities, 153 FERC ¶ 61,337
security-based swap dealers, and commodity pools. Energy, Capacity and Ancillary Services by Public (2015).
See Exchange Act Release No. 66868 (Apr. 27, Utilities, Order No. 816, FERC Stats. & Regs. ¶ 3 The requests for rehearing and clarification were
2012), 77 FR 30596 (May 23, 2012). 31,374 (2015) (Final Rule). filed by the following entities: EDF Renewable
2 Order No. 816 became effective on January 28,
7 7 U.S.C. 1a(18)(A)(xi).
Energy, Inc. and E.ON Climate & Renewables North
2016. On December 23, 2015, upon consideration of
8 See Exchange Act Release No. 69964 (Jul. 11, America LLC (IPP Developers); Edison Electric
sradovich on DSK3TPTVN1PROD with RULES
requests for a stay of the corporate organizational
2013), 77 FR 42439 (Jul. 16, 2013). By its terms, Institute (EEI); Electric Power Supply Association
chart requirement, the Commission issued an order
Rule 15b12–1 expires on July 31, 2016. The granting an extension of time such that market- (EPSA); Invenergy Thermal Development LLC and
Commission previously adopted Rule 15b12–1 as based rate applicants and sellers would not be Invenergy Wind Development LLC (Invenergy);
an interim final temporary rule, and extended it required to comply with the corporate National Hydropower Association (NHA); NextEra
once on July 11, 2012. See Exchange Act Release organizational chart requirement prior to the Energy, Inc. (NextEra); Southern California Edison
Nos. 64874 (Jul. 13, 2011), 76 FR 41676 (Jul. 15, issuance of an order on the merits of the requests Company (SoCal Edison); Southern Company
2011) and 67405 (Jul. 11, 2012), 77 FR 41671 (Jul. for rehearing. Refinements to Policies and Services, Inc. (Southern); and Transmission Access
16, 2012). Procedures for Market-Based Rates for Wholesale Policy Study Group (TAPS).
VerDate Sep<11>2014 17:45 May 25, 2016 Jkt 238001 PO 00000 Frm 00017 Fmt 4700 Sfmt 4700 E:\FR\FM\26MYR1.SGM 26MYR1](https://thefederalregister.org/doc/81_FR_33477/page/1.svg)
![Federal Register / Vol. 81, No. 102 / Thursday, May 26, 2016 / Rules and Regulations 33379
capacity in first-tier markets should be regarding the Commission’s statement located in an RTO/ISO market, the seller
included for determining changes in the in paragraph 238 of Order No. 816. In may consider the RTO/ISO as the
100 MW change in status threshold.38 paragraph 238 of Order No. 816, the default relevant geographic market.49 In
TAPS states that in the NOPR, the Commission stated that ‘‘if a seller’s each circumstance, the market-based
Commission proposed to clarify that the affiliate is granted market-based rate rate seller will have to determine
‘‘relevant geographic market’’ for authority, and that results in 100 MW or whether any 100 MW increase is in a
purposes of that 100 MW trigger more of new generation in a market, market that would be a relevant
included generation capacity that could then the seller will have to file a geographic market for that seller.
be imported from first-tier markets.39 corresponding change in status.’’ 45 We 37. We deny TAPS’s request that
TAPS states that the Commission then clarify that the phrase ‘‘in a market’’ capacity in first-tier markets be included
reversed the NOPR proposal, stating that means any relevant geographic market for determining the 100 MW change in
it would ‘‘exclude markets and for the seller at the time of the change status threshold. As the Commission
balancing authority areas that are first- in status filing. Further, we note that the stated in Order No. 816, when a seller
tier to the seller’s study area.’’ 40 TAPS relevant geographic market for a has a change in status in a particular
states that the Commission erred and particular seller depends on whether the market, it does not need to include any
should grant rehearing to revise Order seller is a power producer or a power changes in adjoining first-tier markets in
No. 816 to include generation in first- marketer, whether the seller owns calculating the 100 MW threshold, even
tier markets for purposes of change in transmission or is interconnected to an when a purchaser has long-term firm
status reporting, whether or not it is affiliated transmission system, and transmission rights to import affiliated
supported by a long-term firm whether the seller’s generation is in an capacity located in a first-tier market.
transmission reservation.41 Specifically, RTO/ISO. The relevant markets for a We reiterate that, with respect to the
TAPS states that the Commission power marketer include any market calculation of the 100 MW threshold,
should require sellers to: (1) Include where the power marketer’s affiliates 100 MW located outside of the study
first-tier capacity when there is a long- own generation. Thus, a power marketer area is not equivalent to 100 MW inside
term transmission reservation associated that does not own any generation itself the study area. In addition, requiring
with the capacity; and (2) include all would need to report a change in status sellers to consider generation capacity
other first-tier capacity either in its for a 100 MW net increase in any market in first-tier markets, and prorate
entirety or, in the alternative, on a pro where an affiliate owns generation and generation from the first-tier markets
rata basis consistent with the inclusion has been granted market-based rate into the study area, creates uncertainty
of such generation in market power authority.46 However, for a power as to when a seller would trip the 100
screens.42 producer, the relevant geographic MW threshold and effectively would
35. TAPS states that the NOPR’s market is where the seller’s generation force a seller to prepare import analyses
proposal to include first-tier generation is physically located. Thus, a power to determine how much of their
capacity is both simple and adequate.43 producer would not need to report a 100 additional first-tier capacity could be
TAPS states that the Commission could MW affiliate net increase in a market imported into the study area. We believe
allow sellers, with appropriate support, where the power producer itself does that the increased burden of preparing
to prorate generation in markets first-tier not own any generation. Similarly, in such studies would outweigh the
to the study area in the same way traditional (non-RTO/ISO) markets, the potential benefit gained from receiving
capacity is assigned pro rata for default relevant geographic market is additional information about a seller’s
indicative screen analyses (assuming ‘‘first, the balancing authority area affiliated generation.
there are no firm transmission where the seller is physically located,
reservations associated with the first-tier and second, the markets directly E. New Affiliation and Behind-the-Meter
capacity, in which case it should be interconnected to the seller’s balancing Generation
accorded its full megawatt value). TAPS authority area.’’ 47 However, ‘‘[w]here a 1. Final Rule
states that this approach would be generator is interconnecting to a non-
consistent with the methodology used affiliate owned or controlled 38. As stated above, the Commission
in the indicative screens, but would transmission system, there is one adopted the NOPR proposal to establish
require more analysis than reporting of relevant geographic market (i.e., the a 100 MW threshold for reporting new
all first-tier capacity for purposes of balancing authority area in which the affiliations in change of status filings.
change in status reports.44 generator is located).’’ 48 For a seller The Commission stated that a market-
based rate seller that has a new
3. Commission Determination 45 Order No. 816, FERC Stats. & Regs. ¶ 31,374 at affiliation will not be required to file a
36. We grant clarification regarding P 238 (emphasis added). change in status for an affiliation with
IPP Developers’ three examples of the 46 A power marketer with no affiliated generation
an entity with generation assets until its
is a Category 1 seller (exempt from filing triennial
application of Order No. 816. The updated market power analysis) in all regions and new affiliations result in a cumulative
scenarios presented by IPP Developers has no relevant geographic market. A power net increase of 100 MW of capacity in
are a proper application of the Final marketer that acquires generation via a long-term a relevant geographic market.50 The
Rule, assuming that the seller is not a power purchase agreement has a relevant
geographic market where the power associated with
power marketer (i.e., the seller owns this agreement is delivered (sinks), not where it 49 Id. P 235 (noting that a seller may consider the
generation). We also grant clarification originates (unless source and sink are in the same RTO/ISO as the default relevant geographic market
market, which is often the case). In this scenario, ‘‘unless the Commission has already found the
38 TAPS Rehearing Request at 1. the power marketer is a Category 1 or 2 seller in existence of a submarket’’).
the relevant geographic market depending on the
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50 Order No. 816, FERC Stats. & Regs. ¶ 31,374 at
39 Id. at 4 (citing NOPR, FERC Stats. & Regs. ¶
MWs associated with the contract(s). Category 2 P 251. The Commission noted that if a seller files
32,702 at P 96).
sellers must submit triennial update market power a notice of change in status for another reason, e.g.,
40 Id. at 5 (citing Order No. 816, FERC Stats. &
analyses. to report the entrance into a power purchase
Regs. ¶ 31,374 at P 230). 47 Market-Based Rates for Wholesale Sales of
41 Id. at 6.
agreement of more than 100 MW, the seller should
Electric Energy Capacity and Ancillary Services by note that it has a new affiliate with market-based
42 Id. at 5.
Public Utilities, Order No. 697, FERC Stats. & Regs. rate authority and include that new affiliate and any
43 Id. at 6–7. ¶ 31,252 at P 232 (2007). related assets in the seller’s asset appendix. Id. P
44 Id. at 7. 48 Id. P 232 n.217. 251 n.334.
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![Federal Register / Vol. 81, No. 102 / Thursday, May 26, 2016 / Rules and Regulations 33381
G. Part 101 Waivers a market-based rate tariff have been 2. Request for Rehearing
previously granted waiver of Part 101.65 53. Southern notes the Commission’s
1. Final Rule
3. Commission Determination determination in the Final Rule
48. The Commission clarified that permitted sellers to use nameplate or
granting waiver of 18 CFR part 101 51. We clarify that a hydropower seasonal capacity ratings for the 100
under market-based rate authority does MW threshold for most generation.
licensee that otherwise sells power only
not waive the requirements under Part Southern states that the regulatory text
at market-based rates will not be subject
I of the FPA for hydropower licensees. accompanying the Final Rule includes
to the full requirements of the Uniform
In addition, the Commission clarified the phrase ‘‘or seasonal’’ in 18 CFR
System of Accounts as a consequence of
that hydropower licensees that only 35.42(a)(2)(i) but not in 18 CFR
make sales at market-based rates may filing a cost-based reactive power tariff
with the Commission. Such a seller may 35.42(a)(1). Southern requests that the
satisfy the requirements in Part 101 of Commission add the phrase ‘‘or
the Commission’s regulations (Uniform satisfy the requirements in Part 101 of
the Commission’s regulations by seasonal’’ to 18 CFR 35.42(a)(1) to align
System of Accounts) by complying with with the discussion in the Final Rule.70
General Instruction 16 of the Uniform complying with General Instruction 16
System of Accounts, and confirmed that of the Uniform System of Accounts. We 3. Commission Determination
hydropower licensees that have find that this clarification is consistent 54. We find that it is appropriate to
Commission-approved cost-based rates with previous Commission findings in revise 18 CFR 35.42(a)(1) to add the
are required to comply with the full Order No. 697 and Sunbury, as noted by phrase ‘‘or seasonal.’’ Additionally, we
requirements of the Uniform System of NHA. We continue to find, however, are revising both 18 CFR 35.42(a)(1) and
Accounts.60 that hydropower licensees that have (a)(2)(i) to further align the regulations
Commission-approved cost-based rates with the discussion in the Final Rule.
2. Requests for Rehearing are required to comply with the full Specifically, the revised regulations will
49. NHA requests clarification that a requirements of the Uniform System of indicate that the 100 MW or more of
hydropower licensee that otherwise Accounts.66 Additionally, we remind capacity should be based on nameplate
sells power only at market-based rates sellers that ‘‘previously granted waivers or seasonal capacity ratings and, for
will not be subject to the full of the accounting requirements will energy-limited resources, with the
requirements of the Uniform System of continue to be rescinded where a seller exception of solar photovoltaic
Accounts as a consequence of filing a is found to have market power (or where facilities, the capacity ratings should be
cost-based reactive power tariff with the the sellers accepts a presumption of based on nameplate or five-year average
Commission.61 Alternatively, NHA market power) and the seller proposes capacity factors. These revised
requests that the Commission clarify cost-based rate mitigation or the regulations will indicate that for solar
that it will allow licensees that Commission imposes cost-based rate photovoltaic facilities, the capacity
otherwise sell only at market-based rates mitigation.’’ 67 ratings should be based on nameplate
to request authorization, on a case-by- capacity.
case basis, to continue to rely on H. Capacity Ratings
I. Inputs to Electric Power Production
General Instruction 16 of the Uniform
1. Final Rule
System of Accounts at the time a 1. Final Rule
reactive power tariff is filed with the 52. In the Final Rule, the Commission 55. The Commission considers a
Commission.62 revised the regulations at 18 CFR 35.42 seller’s ability to erect other barriers to
50. NHA argues that the Commission relating to the change in status reporting entry as part of the vertical market
determined in Order No. 697 that ‘‘little requirements to permit sellers to use power analysis and, as such, the
purpose would be served to require nameplate or seasonal capacity ratings Commission requires a seller to provide
compliance with accounting regulations for the 100 MW threshold for most a description of its inputs to electric
for entities that do not sell at cost-based generation and allow energy-limited power production.71 Section 35.36(a)(4)
rates and do not have captive generation to use either nameplate or a of the Commission’s regulations define
customers.’’ 63 NHA represents that the five-year average capacity factor.68 The inputs to electric power production to
Commission has previously found that Commission found that solar mean intrastate natural gas
reactive power tariffs do not have photovoltaic and solar thermal facilities transportation, intrastate natural gas
captive customers and do not raise the are energy limited and determined that, storage or distribution facilities, sites for
same concerns as other cost-based rate due to their unique characteristics, solar generation capacity development,
tariffs.64 Additionally NHA notes that photovoltaic facilities, unlike other physical coal supply sources and
entities with a reactive power tariff and ownership of or control over who may
energy-limited facilities, must use
nameplate capacity and may not use access transportation of coal supplies.
with the proposed rulemakings in Docket Nos.
five-year average capacity factors.69 56. In the Final Rule, the Commission
RM15–23 and RM16–3. eliminated the requirement that market-
60 Order No. 816, FERC Stats. & Regs. ¶ 31,374 at
P 22. 65 Id. (citing Sunbury Generation, LLC, 108 FERC
based rate sellers file quarterly land
61 NHA Clarification Request at 3–5. ¶ 61,160 (2004) (Sunbury); Illinois Power acquisition reports and provide
62 Id. at 5. Generating Co., 148 FERC ¶ 61,238 (2014) (granting information on sites for generation
63 Id. at 3 (citing Order No. 697, FERC Stats. & waivers of Parts 41, 101, and 141 of the capacity development in market-based
Commission’s regulations to entities with a cost-
Regs. ¶ 31,252 at P 984).
based rate reactive power tariff and a market-based
rate applications and triennial updated
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64 Id. at 3–4 (citing Order No. 697, FERC Stats. &
rate tariff)). market power analyses. Specifically, the
Regs. ¶ 31,252 at P 483 (‘‘concerns underlying the
affiliate restrictions do not apply to sales of reactive
66 Order No. 816, FERC Stats. & Regs. ¶ 31,374 at Commission adopted the proposal to
power because those sales are typically either made P 22.
67 Order No. 697, FERC Stats. & Regs. ¶ 31,252 at 70 Southern Rehearing Request at 7 n.15 (citing
to transmission providers so that the transmission
provider can satisfy its obligation to provide P 986. Order No. 816, FERC Stats. & Regs. ¶ 31,374 at P
68 Order No. 816, FERC Stats. & Regs. ¶ 31,374 at 232).
reactive power or made by the transmission
provider under its applicable [open access P 232. 71 Order No. 816, FERC Stats. & Regs. ¶ 31,374 at
transmission tariff]’’)). 69 Id. P 15. P 6.
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![33382 Federal Register / Vol. 81, No. 102 / Thursday, May 26, 2016 / Rules and Regulations
revise the regulations at 18 CFR 35.42 2. Commission Determination Long-Term Firm PPAs Sheet have been
relating to the change in status reporting 59. Upon further consideration, we modified to reflect these changes and to
requirements regarding sites for new modify the requirement to report in the make certain other clean up edits.
generation capacity development and asset appendix transmission facilities L. Generation Assets Sheet, Rows [B]
also adopted the proposal to revise the that have been granted an individual and [H]
regulations at 18 CFR 35.37 to remove OATT waiver or that qualify for a
the requirement that sellers provide blanket waiver under Order No. 807 and 1. Final Rule
information regarding sites for find that sellers are no longer required 62. The Final Rule contained
generation capacity development to to include such facilities in their instructions for completing the asset
demonstrate a lack of vertical market Transmission/Natural Gas Assets Sheet. appendix. The description of Row [B]
power. However, no changes to the We find that the burden of providing indicated that, if applicable, sellers
definition of inputs to electric power information on such facilities outweighs should include the docket number
production were made in the Final Rule. any benefit to reporting it. For this where market-based rate or qualifying
reason, we eliminate the requirement to facility status was originally granted,
2. Commission Determination
report in the Transmission/Natural Gas and that it can be an EL or QF docket
57. In light the determinations made Assets Sheet facilities that qualify for number. The description of Row [H]
in the Final Rule, we revise our blanket waiver of the OATT listed the six market-based rate regions
regulations at 18 CFR 35.36(a)(4) to requirement under Order No. 807 and but mistakenly listed the Southeast
remove sites for generation capacity those that have been granted an region twice and failed to mention the
development from the definition of individual OATT waiver. Northwest region.
inputs to electric power production. K. Long-Term Firm Power Purchases List 2. Commission Determination
However, we clarify that the affirmative
statement regarding barriers to entry 1. Final Rule 63. We revise the instructions for Row
required in 18 CFR 35.37(e)(3) continues 60. In the Final Rule, the Commission [B] of the asset appendix to remove
to cover sites for generation capacity established a new, separate list in the references to EL and QF dockets. This
development. asset appendix in which market-based revision does not change the
rate sellers are to report their Long-Term Commission’s determinations in Order
J. Transmission/Natural Gas Assets Firm Power Purchase Agreements No. 816. Rather, this revision aligns the
Sheet (PPAs).75 The Commission agreed with description and format information
1. Final Rule commenters that the format of the regarding Row [B] with the
Generation Assets Sheet was not well Commission’s intent that Row [B]
58. In the NOPR, the Commission suited for reporting long-term firm contain the docket number where
proposed to require any seller that has purchases. market-based rate authority was granted.
been granted waiver of the requirement 64. We revise the instructions to Row
2. Commission Determination
to file an open access transmission tariff [H] of the Generation Assets Sheet to
(OATT) for its transmission facilities to 61. Subsequent to the issuance of delete the second reference to
report in its Transmission/Natural Gas Order No. 816, Commission Staff ‘‘Southeast’’ and replace it with
Assets Sheet the citation to the received numerous calls from sellers ‘‘Northwest.’’
Commission order granting the OATT requesting guidance with respect to
completing the Long-Term Firm PPAs III. Information Collection Statement
waiver for those transmission
facilities.72 The Commission did not Sheet. Upon further consideration, we 65. The Office of Management and
adopt the NOPR proposal in the Final recognize that certain modifications to Budget (OMB) regulations implementing
Rule, agreeing with SoCal Edison that this sheet and its instructions are the Paperwork Reduction Act of 1995 76
this requirement would not provide warranted to improve its clarity. To that require that OMB approve certain
useful information in light of Order No. end, we are making the following information collection requirements
807.73 The Commission further stated changes. First, we are eliminating the imposed by an agency.77 Upon approval
that, ‘‘even if a seller has been granted existing column B, ‘‘Docket # where of a collection(s) of information, OMB
waiver of the requirement to file an MBR authority was granted’’ as this is will assign an OMB control number and
OATT, those transmission facilities duplicative of information required an expiration date. Respondents subject
should be reported in its asset elsewhere in the asset appendix. In to the filing requirements of a rule will
appendix.’’ 74 response to questions as to whether the not be penalized for failing to respond
‘‘Market/Balancing Authority Area’’ to these collections of information
72 NOPR, FERC Stats. & Regs. ¶ 32,702 at P 120. column was referring to the source or unless the collections of information
73 Order No. 816, FERC Stats. & Regs. ¶ 31,374 at sink of the transaction, we are adding a display a valid OMB control number.
P 300 (citing Open Access and Priority Rights on column and specifically requesting 66. The revisions made in Order No.
Interconnection Customer’s Interconnection sellers to identify both the source and
Facilities, Order No. 807, FERC Stats. & Regs. ¶
816 to the information collection
31,367 (2015) (amending Commission regulations to
sink of the transaction in separate requirements for market-based rate
waive the OATT requirements of section 35.28, the designated columns. Finally, in sellers were approved under FERC–919
OASIS requirements of Part 37, and the Standards response to other questions raised by (OMB Control No. 1902–0234).78 This
of Conduct requirements of Part 358, under certain market-based rate filers, we are adding
conditions, for entities that own interconnection
order clarifies and makes minor
facilities)).
a column requiring sellers to indicate revisions to some aspects of the existing
sradovich on DSK3TPTVN1PROD with RULES
74 Id. P 295 (citing Order No. 697–A, FERC Stats. whether a particular long-term firm information collection requirements for
& Regs. ¶ 31,268 at P 378 (‘‘We clarify that the purchase agreement is backed by a the market-based rate program. The
transmission facilities that we require to be specific identified generation unit or by
included in that asset appendix are limited to those the supplier’s generation fleet (i.e., a 76 44U.S.C. 3507(d) (2012).
the ownership or control of which would require
an entity to have an OATT on file with the ‘‘system’’ contract). Instructions for the 77 5CFR 1320.11.
Commission (even if the Commission has waived 78 OMB approved the information collection in
the OATT requirement for a particular seller).’’)). 75 Id. P 270. Order No. 816 on December 22, 2015.
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![Federal Register / Vol. 81, No. 102 / Thursday, May 26, 2016 / Rules and Regulations 33383
changes to the information collection submitted to OMB should refer to Authority: 16 U.S.C. 791a–825r, 2601–
include: FERC–919 and OMB Control Number 2645; 31 U.S.C. 9701; 42 U.S.C. 7101–7352.
• Removing the need to list 1902–0234.
§ 35.36 [Amended]
transmission facilities in the
IV. Document Availability
Transmission/Natural Gas Assets Sheet ■ 2. Amend § 35.36 as follows:
that have an OATT waiver or that 68. In addition to publishing the full ■ a. In paragraph (a)(4), remove the
qualify for the blanket OATT waiver (a text of this document in the Federal comma and add in its place a
slight burden decrease) Register, the Commission provides all semicolon.
• adding a source/sink column and a interested persons an opportunity to
■ b. In paragraph (a)(4), remove the
column for generation unit/system view and/or print the contents of this
document via the Internet through phrase ‘‘sites for generation capacity
contract type to the Long-Term Firm
PPAs Sheet (slight burden increases) FERC’s Home Page (http:// development;’’.
• removing column B, ‘‘Docket # www.ferc.gov) and in FERC’s Public ■ 3. Amend § 35.42 by revising
where MBR authority was granted’’ from Reference Room during normal business paragraphs (a)(1) and (a)(2)(i) to read as
the Long-Term Firm PPAs Sheet and hours (8:30 a.m. to 5:00 p.m. Eastern follows:
removing references to ‘‘EL’’ and ‘‘QF’’ time) at 888 First Street NE., Room 2A,
in the instructions for Row [B] of the § 35.42 Change in status reporting
Washington, DC 20426.
requirement.
Generation Assets Sheet (de minimis 69. From FERC’s Home Page on the
decreases) Internet, this information is available on (a) * * *
• removing sites for generation eLibrary. The full text of this document (1) Ownership or control of generation
capacity development from the is available on eLibrary in PDF and capacity or long-term firm purchases of
definition of inputs to electric power Microsoft Word format for viewing, capacity and/or energy that results in
production at 18 CFR 35.36(a)(4) (no printing, and/or downloading. To access cumulative net increases (i.e., the
change to burden). this document in eLibrary, type the difference between increases and
The Commission estimates that there docket number excluding the last three decreases in affiliated generation
will be no net change to burden. This digits of this document in the docket capacity) of 100 MW or more of capacity
Final Rule will be submitted to OMB for number field. based on nameplate or seasonal capacity
review and approval of a ‘‘No Material/ 70. User assistance is available for ratings, or, for solar photovoltaic
Nonsubstantive Change.’’ eLibrary and the FERC’s Web site during facilities, nameplate capacity, or, for
Title: Market Based Rates for normal business hours from FERC other energy-limited resources,
Wholesale Sales of Electric Energy, Online Support at 202–502–6652 (toll nameplate or five-year average capacity
Capacity and Ancillary Services by free at 1–866–208–3676) or email at factors, in any individual relevant
Public Utilities (FERC–919). ferconlinesupport@ferc.gov, or the geographic market, or of inputs to
Action: Clarification and Revision of Public Reference Room at (202) 502– electric power production, or
Currently Approved Collection of 8371, TTY (202) 502–8659. Email the ownership, operation or control of
Information. Public Reference Room at transmission facilities; or
OMB Control No.: 1902–0234. public.referenceroom@ferc.gov. (2) * * *
Respondents for This Rulemaking:
V. Effective Date (i) Owns or controls generation
Public utilities, wholesale electricity
71. These regulations are effective facilities or has long-term firm
sellers, businesses, or other for profit
July 25, 2016. purchases of capacity and/or energy that
and/or not for profit institutions.
results in cumulative net increases (i.e.,
67. Interested persons may obtain List of Subjects in 18 CFR Part 35 the difference between increases and
information on the reporting
Electric power rates, Electric utilities, decreases in affiliated generation
requirements by contacting: Federal
Reporting and recordkeeping capacity) of 100 MW or more of capacity
Energy Regulatory Commission, 888
requirements. based on nameplate or seasonal capacity
First Street NE., Washington, DC 20426
ratings, or, for solar photovoltaic
[Attention: Ellen Brown, Office of the By the Commission.
facilities, nameplate capacity, or, for
Executive Director, email: Issued: May 19, 2016. other energy-limited resources,
DataClearance@ferc.gov, phone: (202) Nathaniel J. Davis, Sr., nameplate or five-year average capacity
502–8663, fax: (202) 273–0873]. Deputy Secretary. factors, in any individual relevant
Comments concerning the requirements
In consideration of the foregoing, the geographic market;
of this rule may also be sent to the
Commission amends Part 35, Chapter I, * * * * *
Office of Information and Regulatory
Title 18, Code of Federal Regulations, as
Affairs, Office of Management and ■ 4. Revise appendix B to subpart H to
follows:
Budget, Washington, DC 20503 read as follows:
[Attention: Desk Officer for the Federal PART 35—FILING OF RATE
Energy Regulatory Commission]. For Appendix B to Subpart H of Part 35—
SCHEDULES AND TARIFFS Corporate Entities and Assets Sample
security reasons, comments should be
sent by email to OMB at oira_ ■ 1. The authority citation for part 35 Appendix
submission@omb.eop.gov. Comments continues to read as follows: BILLING CODE 6717–0–P
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Document Created: 2016-05-26 01:14:02
Document Modified: 2016-05-26 01:14:02
| Category | Regulatory Information | |
| Collection | Federal Register | |
| sudoc Class | AE 2.7: GS 4.107: AE 2.106: | |
| Publisher | Office of the Federal Register, National Archives and Records Administration | |
| Section | Rules and Regulations | |
| Action | Final rule; Order on rehearing and clarification. | |
| Dates | This rule will become effective July 25, 2016. | |
| Contact | Greg Basheda (Technical Information), Office of Energy Market Regulation, Federal Energy Regulatory Commission, 888 First Street NE., Washington, DC 20426, (202) 502-6479. | |
| FR Citation | 81 FR 33375 | |
| CFR Associated | Electric Power Rates; Electric Utilities and Reporting and Recordkeeping Requirements |
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