Refinements to Policies and Procedures for Market-Based Rates for Wholesale Sales of Electric Energy, Capacity and Ancillary Services by Public Utilities, 33375-33387 [2016-12427]

Download as PDF Federal Register / Vol. 81, No. 102 / Thursday, May 26, 2016 / Rules and Regulations individual is an eligible contract participant if the individual has aggregate amounts invested on a discretionary basis of more than $10 million or more than $5 million if such individual enters into the transaction to manage the risk associated with an asset owned or liability incurred, or reasonably likely to be owned or incurred by such individual.7 The Commission adopted Rule 15b12–1 (17 CFR 240.15b12–1) on a time-limited basis to permit a registered broker-dealer to engage in a retail forex business.8 The Commission is taking no further action, and pursuant to Rule 15b12–1(d), Rule 15b12–1 will expire and no longer be effective on July 31, 2016. Upon expiration of the rule on July 31, 2016, a broker-dealer registered pursuant to Section 15(b) of the Exchange Act, including an entity that is registered as both a broker-dealer and a futures commission merchant, shall be prohibited from offering or entering into a retail forex transaction pursuant to Section 2(c)(2)(E) of the CEA. By the Commission. Dated: May 20, 2016. Brent J. Fields, Secretary. 33375 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: SUMMARY: [FR Doc. 2016–12390 Filed 5–25–16; 8:45 am] BILLING CODE 8011–01–P 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 Federal Energy Regulatory Commission, DOE. ACTION: Final rule; Order on rehearing and clarification. AGENCY: Table of Contents Paragraph Nos. I. Introduction ........................................................................................................................................................................................... II. Discussion ............................................................................................................................................................................................ A. Sellers with Fully Committed Long-Term Generation Capacity ............................................................................................... B. Reporting of Long-Term Firm Purchases .................................................................................................................................... C. Clarification of the Definition or Duration of Long-Term Firm Transmission Reservations ................................................... D. Notices of Change in Status ......................................................................................................................................................... E. New Affiliation and Behind-the-Meter Generation .................................................................................................................... F. Corporate Organizational Charts .................................................................................................................................................. G. Part 101 Waivers ........................................................................................................................................................................... H. Capacity Ratings ........................................................................................................................................................................... I. Inputs to Electric Power Production ............................................................................................................................................. J. Transmission/Natural Gas Assets Sheet ....................................................................................................................................... K. Long-Term Firm Power Purchases List ....................................................................................................................................... L. Generation Assets Sheet, Rows [B] and [H] ................................................................................................................................ III. Information Collection Statement ...................................................................................................................................................... IV. Document Availability ....................................................................................................................................................................... V. Effective Date ....................................................................................................................................................................................... Order No. 816–A (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 Order on Rehearing and Clarification I. Introduction sradovich on DSK3TPTVN1PROD with RULES 1. On October 16, 2015, the Federal Energy Regulatory Commission to transactions with major swap participants, swap dealers, major security-based swap participants, security-based swap dealers, and commodity pools. See Exchange Act Release No. 66868 (Apr. 27, 2012), 77 FR 30596 (May 23, 2012). 7 7 U.S.C. 1a(18)(A)(xi). 8 See Exchange Act Release No. 69964 (Jul. 11, 2013), 77 FR 42439 (Jul. 16, 2013). By its terms, Rule 15b12–1 expires on July 31, 2016. The Commission previously adopted Rule 15b12–1 as an interim final temporary rule, and extended it once on July 11, 2012. See Exchange Act Release Nos. 64874 (Jul. 13, 2011), 76 FR 41676 (Jul. 15, 2011) and 67405 (Jul. 11, 2012), 77 FR 41671 (Jul. 16, 2012). VerDate Sep<11>2014 17:45 May 25, 2016 Jkt 238001 1 12 12 18 26 29 38 45 48 52 55 58 60 62 65 68 71 Power Act (FPA). In this order, we address requests for rehearing and clarification of Order No. 816.2 2. Nine requests for rehearing and clarification were filed.3 The requests for rehearing and clarification concern 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 marketbased 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). 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). PO 00000 Frm 00017 Fmt 4700 Sfmt 4700 E:\FR\FM\26MYR1.SGM 26MYR1 sradovich on DSK3TPTVN1PROD with RULES 33376 Federal Register / Vol. 81, No. 102 / Thursday, May 26, 2016 / Rules and Regulations 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. 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 longterm 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 4 18 CFR pt. 101 (2015). 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. VerDate Sep<11>2014 17:45 May 25, 2016 Jkt 238001 included for determining the 100 MW change in status threshold. 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 LongTerm 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 marketbased 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- PO 00000 Frm 00018 Fmt 4700 Sfmt 4700 term contract, the expiration date of the contract, and a representation that the contract is for firm sales for one year or longer.6 13. In response to NextEra’s concern that at the time a seller files for marketbased rate authority, the expiration date may be unknown, the Commission stated that if a contract expiration date is unknown at the time of the marketbased 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 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 marketbased 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-thefact 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 6 Order No. 816, FERC Stats. & Regs. ¶ 31,374 at P 39. 7 Id. P 44. 8 NextEra Rehearing Request at 2. 9 Id. at 12. 10 Id. at 13. E:\FR\FM\26MYR1.SGM 26MYR1 Federal Register / Vol. 81, No. 102 / Thursday, May 26, 2016 / Rules and Regulations sradovich on DSK3TPTVN1PROD with RULES than as amendments to pending applications.11 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 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 at 14. 12 Order No. 816, FERC Stats. & Regs. ¶ 31,374 at P 38. 13 Id. P 44. 14 Id. capacity is fully committed will be treated as informational filings rather than as amendments to filings.15 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 marketbased 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 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 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 longterm 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 11 Id. VerDate Sep<11>2014 17:45 May 25, 2016 Jkt 238001 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 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 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. 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 19 SoCal Edison Rehearing Request at 2. Rehearing Request at 2. 21 Id. at 14. 22 Id. at 15. 23 Order No. 816, FERC Stats. & Regs. ¶ 31,374 at P 255. 20 NextEra 15 Id. 16 Id. P 130. P 139. 18 Id. P 145. 17 Id. PO 00000 Frm 00019 Fmt 4700 Sfmt 4700 33377 E:\FR\FM\26MYR1.SGM 26MYR1 33378 Federal Register / Vol. 81, No. 102 / Thursday, May 26, 2016 / Rules and Regulations screens. We see no reason to treat longterm 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 marketbased 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 longterm firm transmission reservations, stating that it is currently defined as 28 days or longer.24 sradovich on DSK3TPTVN1PROD with RULES 2. Requests for Rehearing 27. Southern states that Order No. 816 appears to erroneously refer to longterm 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 longterm firm reservations. 24 Id. P 197. VerDate Sep<11>2014 17:45 May 25, 2016 Jkt 238001 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. 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 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 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). 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. 28 Id. P 231. 29 Id. P 237. 30 Id. P 18. PO 00000 Frm 00020 Fmt 4700 Sfmt 4700 seller’s relevant geographic market/ study area.31 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. 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 33. IPP Developers state that if the Commission is not inclined to provide the clarifications above, then IPP Developers request rehearing.37 34. TAPS seeks rehearing of the threshold calculation, arguing that 31 Id. P 229. Developers Rehearing Request at 1–3. 32 IPP 33 Id. 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. 37 Id. at 3. E:\FR\FM\26MYR1.SGM 26MYR1 Federal Register / Vol. 81, No. 102 / Thursday, May 26, 2016 / Rules and Regulations 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 firsttier 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 firsttier 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 longterm 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 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 sradovich on DSK3TPTVN1PROD with RULES 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 38 TAPS Rehearing Request at 1. 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. 43 Id. at 6–7. 44 Id. at 7. 39 Id. VerDate Sep<11>2014 17:45 May 25, 2016 Jkt 238001 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 nonaffiliate 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 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. PO 00000 Frm 00021 Fmt 4700 Sfmt 4700 33379 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. 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 marketbased 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 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’’). 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. E:\FR\FM\26MYR1.SGM 26MYR1 33380 Federal Register / Vol. 81, No. 102 / Thursday, May 26, 2016 / Rules and Regulations sradovich on DSK3TPTVN1PROD with RULES 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 39. The Commission did not adopt the NOPR proposal to count behind-themeter 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 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 2. Requests for Rehearing 41. TAPS requests rehearing and/or clarification, arguing that behind-themeter 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 51 Id. P 251. P 252. 53 Id. P 253. 54 TAPS Rehearing Request at 11. 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-themeter 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 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 behindthe-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 3. Commission Determination 44. We deny TAPS’s request for rehearing. As the Commission stated in the Final Rule, the output of behind-themeter 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-themeter 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 52 Id. VerDate Sep<11>2014 17:45 May 25, 2016 55 Id. 56 Id. Jkt 238001 PO 00000 at 13. Frm 00022 Fmt 4700 Sfmt 4700 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. 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 57 Order No. 816, FERC Stats. & Regs. ¶ 31,374 at P 21. 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, E:\FR\FM\26MYR1.SGM 26MYR1 Federal Register / Vol. 81, No. 102 / Thursday, May 26, 2016 / Rules and Regulations G. Part 101 a market-based rate tariff have been previously granted waiver of Part 101.65 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 2. Requests for Rehearing sradovich on DSK3TPTVN1PROD with RULES 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-bycase 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 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 with the proposed rulemakings in Docket Nos. RM15–23 and RM16–3. 60 Order No. 816, FERC Stats. & Regs. ¶ 31,374 at P 22. 61 NHA Clarification Request at 3–5. 62 Id. at 5. 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]’’)). VerDate Sep<11>2014 17:45 May 25, 2016 Jkt 238001 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 H. Capacity Ratings 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 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 costbased rate reactive power tariff and a market-based rate tariff)). 66 Order No. 816, FERC Stats. & Regs. ¶ 31,374 at P 22. 67 Order No. 697, FERC Stats. & Regs. ¶ 31,252 at P 986. 68 Order No. 816, FERC Stats. & Regs. ¶ 31,374 at P 232. 69 Id. P 15. Frm 00023 Fmt 4700 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 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 PO 00000 33381 Sfmt 4700 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. 56. In the Final Rule, the Commission eliminated the requirement that marketbased 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 70 Southern Rehearing Request at 7 n.15 (citing Order No. 816, FERC Stats. & Regs. ¶ 31,374 at P 232). 71 Order No. 816, FERC Stats. & Regs. ¶ 31,374 at P 6. E:\FR\FM\26MYR1.SGM 26MYR1 33382 Federal Register / Vol. 81, No. 102 / Thursday, May 26, 2016 / Rules and Regulations 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. 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).’’)). sradovich on DSK3TPTVN1PROD with RULES 73 Order VerDate Sep<11>2014 17:45 May 25, 2016 Jkt 238001 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. Long-Term Firm PPAs Sheet have been modified to reflect these changes and to make certain other clean up edits. K. Long-Term Firm Power Purchases List 2. Commission Determination 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. 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.’’ 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 75 Id. PO 00000 P 270. Frm 00024 Fmt 4700 Sfmt 4700 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. 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. 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 76 44 U.S.C. 3507(d) (2012). CFR 1320.11. 78 OMB approved the information collection in Order No. 816 on December 22, 2015. 77 5 E:\FR\FM\26MYR1.SGM 26MYR1 sradovich on DSK3TPTVN1PROD with RULES Federal Register / Vol. 81, No. 102 / Thursday, May 26, 2016 / Rules and Regulations changes to the information collection include: • 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 VerDate Sep<11>2014 17:45 May 25, 2016 Jkt 238001 submitted to OMB should refer to FERC–919 and OMB Control Number 1902–0234. IV. Document Availability 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 1. The authority citation for part 35 continues to read as follows: PO 00000 Frm 00025 Fmt 4700 Sfmt 4700 Authority: 16 U.S.C. 791a–825r, 2601– 2645; 31 U.S.C. 9701; 42 U.S.C. 7101–7352. § 35.36 [Amended] 2. Amend § 35.36 as follows: a. In paragraph (a)(4), remove the comma and add in its place a semicolon. ■ b. In paragraph (a)(4), remove the phrase ‘‘sites for generation capacity development;’’. ■ 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. ■ 33383 ■ 3. Amend § 35.42 by revising paragraphs (a)(1) and (a)(2)(i) to read as follows: ■ § 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; * * * * * 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 E:\FR\FM\26MYR1.SGM 26MYR1 33384 Federal Register / Vol. 81, No. 102 / Thursday, May 26, 2016 / Rules and Regulations Format [C] Generation Name (Plant or Unit Name) Unit Name or if all units in a plant are reasonably similar, a plant name. Use EIA-860 or industry standard names to the extent Free Form Text possible. Name of the Entity owning the generation unit or plant. Please use [D] Owned By Free Form Text [E] Controlled By Free Form Text [F] Date Control Transferred MM/YYYY or DD/MM/YY the same name as in the Company Registration database if possible. Name of the Entity that controls the output of the generation unit or plant. Please use the same name as in the Company Registration database if possible. The date the unit came under the control of the Entity listed in "[E] Controlled By." Often it is the date the generation was acquired or built. Free Form Text. For Markets or Location: heir designated submarkets (PJM-East, 5004/5005, AP South, onnecticut, Southwest Connecticut, New York City, Long Island) or a ERC-defined Balancing Authority Area name. One of the six MBR regions: Northeast, Southeast, Central, SPP, Specific Text MM/YYYY or MM/DD/YY [J] Numeric. Either an integer or fixed width The nameplate capacity rating of the unit, usually provided by the numeric with one decimal Capacity Rating: Nameplate (MW) Northwest, Southwest. The date the unit first came into service. manufacturer, in MWs. Numeric. Either an integer or fixed width numeric with one decimal I I Capacity Rating: Used in Filing (MW) [L] Capacity Rating: Methodology Used in [K]: (N)ameplate, (S)easonal, 5-yr single capital letter (either "N", "S", "U", "E", or "A") to designate the ating methodology of the unit's capacity used in this filing. Describe 'Alternative" Capacity Rating Method in End Notes Sheet. (U)nit, 5-yr (E) lA, (A)Iternative End Note Number (Enter text in End sradovich on DSK3TPTVN1PROD with RULES Notes Sheet) VerDate Sep<11>2014 17:45 May 25, 2016 he capacity rating of the unit(s), in MWs, used in this filing. he number of the explanatory note in End Notes Sheet that refers to is entry. The numbers should be ascending integers throughout the ppendix. If there are three notes in the Generation Assets Sheet, Integer en the first end note in the next asset sheet should be four (please not start over with a new numbering sequence). Jkt 238001 PO 00000 Frm 00026 Fmt 4700 Sfmt 4725 E:\FR\FM\26MYR1.SGM 26MYR1 ER26MY16.039</GPH> [G] ne of the six RTO/ISOs (ISO-NE, NYISO, PJM, MISO, SPP, CAISO) or submarkets please use one of the abbreviations or names in the next column. For balancing authority areas Location: Market/Balancing Authority Area Federal Register / Vol. 81, No. 102 / Thursday, May 26, 2016 / Rules and Regulations 33385 Instructions for completing the Asset Appendix Sheet: Long-Term Firm Power Purchase Agreements {PPA) Title Format Description [ I Filing Entity and its Energy Affiliates [ I Seller Name Name of the Filing Entity or affiliate of the Filing Entity that is purchasing the energy or capacity. Free Form Text Free Form Text Name of the Filing Entity that is selling the capacity and/or energy. Please use the exact name as in the Company Registration database if possible. Contracted amount of the PPA in MW. If the contract is for the entire output of a specific generation unit, you may de-rate the unit using Numeric. Either an integer or fixed width [C] Amount of PPA (MW) numeric with one decimal the same de-rating methodology that is used for generators of the same technology elsewhere in the appendix. If this amount is derated please explain in the End Notes Sheet. Energy-only contracts must be converted from MWh to MW. Only report contracts one year or longer. Free Form Text. For Markets or submarkets please use one of the Location: [D] [E] Market/Balancing Authority Area (Source) abbreviations or names in the next column. For balancing authority areas please use the NERC-defined name One of the six RTO/ISOs (ISO-NE, NYISO, PJM, MISO, SPP, CAISO) or their designated submarkets (PJM-East, 5004/5005, AP South, Connecticut, Southwest Connecticut, New York City, Long Island) or a NERC-defined Balancing Authority Area name. For "System" PPAs, identify all markets and balancing authority areas from which the PPA is sourced to the extent the source location(s) is specified in the PPA. Free Form Text. For Markets or submarkets please use one of the Location: Market/Balancing Authority Area (Sink) One of the six RTO/ISOs (ISO-NE, NYISO, PJM, MISO, SPP, CAISO) or their designated submarkets (PJM-East, 5004/5005, AP South, abbreviations or names in the next Connecticut, Southwest Connecticut, New York City, Long Island) or a NERC-defined Balancing Authority Area name. For all PPAs, identify where the capacity and/or ener is delivered. column. For balancing authority areas please use the NERC-defined name Specific Text MM/DD/YY MM/DD/YY [I] [J] Enter the text "Unit" if the PPA is from a specific unit such as a wind generator selling its output to a utility, or from multiple units at a single plant. Please provide the name of the unit or facility supplying "Unit" or "System" Type of PPA (Unit or System) End Note Number (Enter text in End the PPA in the End Notes Sheet. Enter "System" if the PPA is sourced from a utility's or IPP's fleet with different units providing power at different times. Same instruction as the Generation Assets Sheet. Integer Notes Sheet) Instructions for completing the Asset Appendix Sheet: Transmission/Natural Gas Assets Title Format Description Same instruction as the Generation Assets Sheet. Filing Entity and its Energy Affiliates Cite to order accepting OATI or the Commission cite to the order accepting the Filing Entity's or its Energy Affiliate's current OATI, or the order transferring control of the order approving the transfer of :::trc:a:c:n:::sm=is=sc:io:cn~f=a=c:c:ilc:it:c:ie:::sc:t=oc:a:cnc:R~Tc:O~o~r:::ISc::0""-1----------------~ transmission facilities to an RTO/ISO.;;;;p;t;;;~;t\h;tyjp;~t;jiityj Free Form Text Controlled By Name of the Entity that controls the transmission/natural gas assets. Date Control Transferred uthority Area Market/Balancin Same instruction as the Generation Assets Sheet. Same instruction as the Generation Assets Sheet. Size (e.g., length and kV for electric, Description of the size of the facility in the measures relevant to the specific type of facility. For example, for electric "Size" refers to the t. length and diameter for pipelines, and Free Form Text length and kV rating of the transmission line; for gas pipeline "Size" capacity for gas storage) sradovich on DSK3TPTVN1PROD with RULES [J] VerDate Sep<11>2014 refers to the length and diameter of the pipeline; for gas storage "Size" refers to the capacity of the facility. End Note Number (Enter text in End Notes Sheet) 17:45 May 25, 2016 Jkt 238001 Same instruction as the Generation Assets Sheet. PO 00000 Frm 00027 Fmt 4700 Sfmt 4725 E:\FR\FM\26MYR1.SGM 26MYR1 ER26MY16.040</GPH> [I] 33386 Federal Register / Vol. 81, No. 102 / Thursday, May 26, 2016 / Rules and Regulations Fc:J Title Format End Note Number [A] Description Should match an End Note number in the Generation Assets, Long- Integer Term Firm PPAs or Transmission/Natural Gas Assets Sheets. Sheet (Generation Assets, Long-Term [B] The words 11 Generation 11 1 11 PPA 11 1 or .. Transmission/Natural Gas .. Firm PPAs or Transmission/Natural Gas Assets) Indicates in which asset sheet the End Note is located. Free Form Text [B] [C] [D] [E] [F] [G] [H] [I] [I] [K] ln-SeNice Date Capacity Rating: Nameplate (MW) Capacity Rating: Used Location Filing Entity and Generation Market/ Docket# Date where MBR Name Owned Controlled Balancing Control its Energy authority was (Plant or By By Authority Transferred granted Unit Name) Affiliates Area Geographic Region in Filing (MW) Asset Appendix: Long-Term Firm Power Purchase Agreements (PPA) ~ [B] [A] [D] [C] [E] [H] [I] [J] Type of l"l 1~1 End Note Number (Enter Location Filing Entity and its Energy Affiliates Seller Name Market/ Amount Balancing ofPPA Authority Area (MW) !Source! Market/ Balancing Authority Area !Sinkl Geographic Region (Sink) Start Date (mo/da/yr) PPA (Unit or Svsteml End Date (mo/da/yr) text in End Notes Sheetl Asset Appendix: Transmission/Natural Gas isets I I Intrastate Pipelines and/or Gas Storage Facilities [D] [C] [E] [F] [G] I [H] Location Cite to order accepting OATT or order Filing Entity and approving the its Energy transfer of Affiliates transmission sradovich on DSK3TPTVN1PROD with RULES 17:45 May 25, 2016 rn length and kV Asset Name and Use Owned By Controlled By Market/ Date Control Balancing Geographic Region Transferred Authority Area facilities to an RTOoriSO VerDate Sep<11>2014 [I] Size Size (e.g., Jkt 238001 PO 00000 Frm 00028 Fmt 4700 Sfmt 4725 for electric, End Note Number length and (Enter text in End diameter for Notes Sheet) pipelines, and capacity for gas stora2el E:\FR\FM\26MYR1.SGM 26MYR1 ER26MY16.041</GPH> [A] FOR FURTHER INFORMATION CONTACT: [FR Doc. 2016–12427 Filed 5–25–16; 8:45 a.m.] Andrew R. Davis, Chief of the Division of Interpretations and Standards, Office of Labor-Management Standards, U.S. Department of Labor, 200 Constitution Avenue NW., Room N–5609, Washington, DC 20210, olms-public@ dol.gov, (202) 693–0123 (this is not a toll-free number), (800) 877–8339 (TTY/ TDD). SUPPLEMENTARY INFORMATION: BILLING CODE 6717–01–C DEPARTMENT OF LABOR Office of Labor-Management Standards 29 CFR Parts 403 and 458 The Reorganization and Delegation of Authority for the Procedures Involving the Election of Officers in Federal Sector Labor Organizations; Filing Threshold for Simplified Annual Reports; and Instructions Regarding the Reports for Labor Organization Officer and Employee, Labor Organization Annual Report, Trusteeship, and Terminal Trusteeship Office of Labor-Management Standards, DOL. ACTION: Final rule; technical corrections. AGENCY: The Office of LaborManagement Standards (OLMS) is making a number of technical corrections to its regulations and LM form instructions. OLMS is revising the instructions for the Form LM–30, Labor Organization Officer and Employee Report. OLMS is also amending a 2003 final rule on labor organization annual reports in order to incorporate the previously updated filing threshold for smaller labor organizations with gross annual receipts totaling less than $250,000, make a technical correction to the instructions for the Form LM–2 Labor Organization Annual Report, Item 36 (Dues and Agency Fees), as well as to update the instructions for the Form LM–15, Trusteeship Report, and Form LM–16, Terminal Trusteeship Report. In addition, OLMS is amending a 2013 technical amendment implementing Secretary’s Order No. 02–2012, which delegated appellate authority over certain federal sector labor organization officer election matters to the Administrative Review Board. DATES: Effective May 26, 2016. sradovich on DSK3TPTVN1PROD with RULES SUMMARY: VerDate Sep<11>2014 17:45 May 25, 2016 Jkt 238001 Background The Form LM–30 final rule that is the subject of these corrections appeared in the Federal Register on October 26, 2011 (76 FR 66441); the final rule revised the Form LM–30, Labor Organization Officer and Employee Report, its instructions, and related provisions in the Department’s regulations. The rule implemented section 202 of the Labor-Management Reporting and Disclosure Act of 1959 (LMRDA), 29 U.S.C. 432, whose purpose is to require officers and employees of labor organizations to report specified financial transactions, arrangements, and holdings to effect public disclosure of any possible conflicts of interest with their duty to the labor organization and its members. The Form LM–30 and instructions are referenced in 29 CFR part 404. See 29 CFR 404.3 (Form of Annual Report). These corrections also amend a final rule published in the Federal Register on October 10, 2003 (68 FR 58374), concerning labor organization annual reports. In that rule, the Department increased the filing threshold for Form LM–2 filers from $200,000 to $250,000 in gross annual receipts. See 68 FR 58383. However, the rule did not make a corresponding amendment to the text of 29 CFR 403.4(a)(1) (Simplified annual reports for smaller labor organizations), which permits smaller labor organizations to file the simplified Form LM–3 if they do not have gross annual receipts that meet the filing threshold for the Form LM–2. Furthermore, the 2003 rule mandated electronic filing of the Form LM–2 for PO 00000 Frm 00029 Fmt 4700 Sfmt 4700 33387 labor organizations with $250,000 or more in gross receipts. See 68 FR 58407. The instructions for the Form LM–2 were properly revised to reflect this requirement, but the rule did not update the instructions for the Form LM–15, Trusteeship Report, or the instructions for the Form LM–16, Terminal Trusteeship Report, both of which still contain references to the old paper format of the Form LM–2. Pursuant to Title III of the LMRDA and the Department’s regulations at 29 CFR part 408, the instructions for the Forms LM– 15 and LM–16 detail a parent organization’s obligation to complete the Form LM–2 on behalf of a subordinate organization that it has placed in trusteeship. Moreover, today’s corrections fix an omission in Section III of the instructions for the Form LM–16, by making clear that the treasurer of the parent union, in addition to the president (or corresponding principal officers), is required to sign the subordinate union’s Form LM–2 report, pursuant to 29 U.S.C. 461(a). The Forms LM–16 and LM–16 and instructions are referenced in 29 CFR part 408. See 29 CFR 408.3 (Form of Initial Report) and 29 CFR 408.7 (Terminal Trusteeship Information Report). Additionally, these amendments correct a technical error in the instructions for Form LM–2 Labor Organization Annual Report, Item 36 (Dues and Agency Fees), by clarifying an example concerning the reporting by a parent body and its subordinate for dues retained by the parent body from dues checkoff as payment for supplies purchased from the parent body by its subordinate. The Form LM–2 and instructions are referenced in 29 CFR part 403. See 29 CFR 403.3 (Form of Annual Financial Report—Detailed Report). Finally, these corrections amend a final rule published in the Federal Register on February 5, 2013 (78 FR 8022), concerning technical amendments implementing Secretary’s Order No. 02–2012 (77 FR 69378), E:\FR\FM\26MYR1.SGM 26MYR1 ER26MY16.042</GPH> Federal Register / Vol. 81, No. 102 / Thursday, May 26, 2016 / Rules and Regulations

Agencies

[Federal Register Volume 81, Number 102 (Thursday, May 26, 2016)]
[Rules and Regulations]
[Pages 33375-33387]
From the Federal Register Online via the Government Publishing Office [www.gpo.gov]
[FR Doc No: 2016-12427]


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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.

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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\
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    \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).
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    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\
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    \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).
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    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.
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    \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.
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    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\
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    \6\ Order No. 816, FERC Stats. & Regs. ] 31,374 at P 39.
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    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\
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    \7\ Id. P 44.
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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\
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    \8\ NextEra Rehearing Request at 2.
    \9\ Id. at 12.
    \10\ Id. at 13.
    \11\ Id. at 14.
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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\
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    \12\ Order No. 816, FERC Stats. & Regs. ] 31,374 at P 38.
    \13\ Id. P 44.
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    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\
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    \14\ Id.
    \15\ Id.
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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\
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    \16\ Id. P 130.
    \17\ Id. P 139.
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    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\
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    \18\ Id. P 145.
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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\
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    \20\ NextEra Rehearing Request at 2.
    \21\ Id. at 14.
    \22\ Id. at 15.
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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.
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    \23\ Order No. 816, FERC Stats. & Regs. ] 31,374 at P 255.
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    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\
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    \24\ Id. P 197.
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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.
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    \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).
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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

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changes to the information collection include:
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    \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

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[FR Doc. 2016-12427 Filed 5-25-16; 8:45 a.m.]
 BILLING CODE 6717-01-C