Transmission Planning and Cost Allocation by Transmission Owning and Operating Public Utilities, 64890-64904 [2012-26111]

Download as PDF 64890 Federal Register / Vol. 77, No. 206 / Wednesday, October 24, 2012 / Rules and Regulations Issued in Seattle, Washington, on October 9, 2012. John Warner, Manager, Operations Support Group, Western Service Center. Administration Order 7400.9W, Airspace Designations and Reporting Points, dated August 8, 2012, and effective September 15, 2012, is amended as follows: [FR Doc. 2012–25925 Filed 10–23–12; 8:45 am] Paragraph 5000 Class D airspace. * * * * AWP CA D BILLING CODE 4910–13–P * Hawthorne, CA [Amended] Jack Northrop Field/Hawthorne Municipal Airport, CA (Lat. 33°55′22″ N., long. 118°20′07″ W.) That airspace extending upward from the surface to and including 2,500 feet MSL within 2.6-mile radius of the Jack Northrop Field/Hawthorne Municipal Airport, and that airspace 1.5 miles north and 2 miles south of the 229° bearing of the airport extending from the 2.6-mile radius to 3.8 miles southwest, and that airspace 2 miles north and 1.5 miles south of the 096° bearing of the airport extending from the 2.6-mile radius to 3.9 miles east of the airport, excluding the Los Angeles Airport Class D and that portion within the Torrance CA, Class D airspace area. This Class D airspace is effective during the specific dates and times established in advance by a Notice to Airmen. The effective date and time will thereafter be continuously published in the Airport/Facility Directory. Paragraph 6004 Class E airspace areas designated as an extension to Class D or Class E surface area. * * * AWP CA E4 * * Hawthorne, CA [Amended] Jack Northrop Field/Hawthorne Municipal Airport, CA (Lat. 33°55′22″ N., long. 118°20′07″ W.) That airspace extending upward from the surface within 2 miles north and .5 miles south of the 096° bearing of Jack Northrop Field/Hawthorne Municipal Airport, beginning 3.9 miles east of the airport extending to 6.3 miles east of the airport. This Class E airspace area is effective during the specific dates and times established in advance by a Notice to Airmen. The effective date and time will thereafter be continuously published in the Airport/Facility Directory. DEPARTMENT OF ENERGY Federal Energy Regulatory Commission 18 CFR Part 35 [Docket No. RM10–23–002; Order No. 1000– B] Transmission Planning and Cost Allocation by Transmission Owning and Operating Public Utilities Federal Energy Regulatory Commission, DOE. ACTION: Order on rehearing and clarification. AGENCY: The Federal Energy Regulatory Commission affirms its basic determinations in Order Nos. 1000 and 1000–A, amending the transmission planning and cost allocation requirements established in Order No. 890 to ensure that Commissionjurisdictional services are provided at just and reasonable rates and on a basis that is just and reasonable and not unduly discriminatory or preferential. This order affirms the Order No. 1000 transmission planning reforms that: Require that each public utility transmission provider participate in a regional transmission planning process that produces a regional transmission plan; provide that local and regional transmission planning processes must provide an opportunity to identify and evaluate transmission needs driven by public policy requirements established SUMMARY: by state or federal laws or regulations; improve coordination between neighboring transmission planning regions for new interregional transmission facilities; and remove from Commission-approved tariffs and agreements a federal right of first refusal. This order also affirms the Order No. 1000 requirements that each public utility transmission provider must participate in a regional transmission planning process that has: A regional cost allocation method for the cost of new transmission facilities selected in a regional transmission plan for purposes of cost allocation and an interregional cost allocation method for the cost of new transmission facilities that are located in two neighboring transmission planning regions and are jointly evaluated by the two regions in the interregional transmission coordination process required by this Final Rule. Additionally, this order affirms the Order No. 1000 requirement that each cost allocation method must satisfy six cost allocation principles. DATES: Effective November 23, 2012. FOR FURTHER INFORMATION CONTACT: Melissa Nimit, Federal Energy Regulatory Commission, Office of the General Counsel, 888 First Street NE., Washington, DC 20426, (202) 502– 6638. Shiv Mani, Federal Energy Regulatory Commission, Office of Energy Policy and Innovation, 888 First Street NE., Washington, DC 20426, (202) 502– 8240. SUPPLEMENTARY INFORMATION: Before Commissioners: Jon Wellinghoff, Chairman; Philip D. Moeller, John R. Norris, and Cheryl A. LaFleur. Issued October 18, 2012 Table of Contents TKELLEY on DSK3SPTVN1PROD with RULES Paragraph No. I. Introduction ........................................................................................................................................................................................... II. Transmission Planning ........................................................................................................................................................................ A. Regional Transmission Planning ................................................................................................................................................. 1. Role of Section 217(b)(4) of the Federal Power Act ............................................................................................................ 2. Regional Transmission Planning Requirements ................................................................................................................... 3. Consideration of Transmission Needs Driven by Public Policy Requirements ................................................................. B. Nonincumbent Transmission Developers ................................................................................................................................... 1. Legal Authority ...................................................................................................................................................................... 2. Requirement To Remove a Federal Right of First Refusal from Commission-Jurisdictional Tariffs and Agreements, and Limits on the Applicability of That Requirement ......................................................................................................... 3. Framework To Evaluate Transmission Projects Submitted for Selection in the Regional Transmission Plan for Purposes of Cost Allocation ........................................................................................................................................................ C. Interregional Transmission Coordination .................................................................................................................................... 1. Implementation of the Interregional Transmission Coordination Requirements .............................................................. III. Cost Allocation ................................................................................................................................................................................... 1. Cost Allocation Principle 2—No Involuntary Allocation of Costs to Non-beneficiaries .......................................................... IV. Information Collection Statement ...................................................................................................................................................... V. Document Availability ........................................................................................................................................................................ VerDate Mar<15>2010 17:17 Oct 23, 2012 Jkt 229001 PO 00000 Frm 00002 Fmt 4700 Sfmt 4700 E:\FR\FM\24OCR1.SGM 24OCR1 1 5 5 6 12 28 32 33 41 56 60 61 65 67 73 74 Federal Register / Vol. 77, No. 206 / Wednesday, October 24, 2012 / Rules and Regulations 64891 Paragraph No. VI. Effective Date ...................................................................................................................................................................................... Appendix A: Abbreviated Names of Petitioners I. Introduction TKELLEY on DSK3SPTVN1PROD with RULES 1. In Order No. 1000,1 the Commission amended the transmission planning and cost allocation requirements established in Order No. 890 2 to ensure that the rates, terms and conditions of service provided by public utility providers are just and reasonable and not unduly discriminatory or preferential. Order No. 1000’s transmission planning reforms require: (1) Each public utility transmission provider to participate in a regional transmission planning process that produces a regional transmission plan; (2) that local and regional transmission planning processes must provide an opportunity to identify and evaluate transmission needs driven by public policy requirements established by state or federal laws or regulations; (3) improved coordination between neighboring transmission planning regions for new interregional transmission facilities; and (4) the removal from Commission-approved tariffs and agreements of a federal right of first refusal. 2. Order No. 1000 also requires that each public utility transmission provider must participate in a regional transmission planning process that has: (1) A regional cost allocation method for the cost of new transmission facilities selected in a regional transmission plan for purposes of cost allocation and (2) an interregional cost allocation method for the cost of new transmission facilities that are located in two neighboring transmission planning regions and are jointly evaluated by the two regions in the interregional transmission coordination process required by this Final Rule. Order No. 1000 also requires that each cost 1 Transmission Planning and Cost Allocation by Transmission Owning and Operating Public Utilities, Order No. 1000, 76 FR 49842 (Aug. 11, 2011), FERC Stats. & Regs. ¶ 31,323 (2011), order on reh’g, Order No. 1000–A, 139 FERC ¶ 61,132 (2012). 2 Preventing Undue Discrimination and Preference in Transmission Service, Order No. 890, 72 FR 12266 (Mar. 15, 2007), FERC Stats. & Regs. ¶ 31,241, order on reh’g, Order No. 890–A, 73 FR 2984 (Jan. 16, 2008), FERC Stats. & Regs. ¶ 31,261 (2007), order on reh’g and clarification, Order No. 890–B, 73 FR 39092 (July 8, 2008), 123 FERC ¶ 61,299 (2008), order on reh’g, Order No. 890–C, 74 FR 12540 (Mar. 25, 2009), 126 FERC ¶ 61,228 (2009), order on clarification, Order No. 890–D, 74 FR 61511 (Nov. 25 2009), 129 FERC ¶ 61,126 (2009). VerDate Mar<15>2010 17:17 Oct 23, 2012 Jkt 229001 allocation method must satisfy six cost allocation principles. 3. In Order No. 1000–A, the Commission largely affirmed the reforms adopted in Order No. 1000. The Commission concluded that taken together, the reforms adopted in Order No. 1000 will ensure that Commissionjurisdictional services are provided at just and reasonable rates and on a basis that is just and reasonable and not unduly discriminatory or preferential. The Commission therefore rejected requests to eliminate, or substantially modify, the various reforms adopted in Order No. 1000. The Commission did however, make a number of clarifications. 4. Several petitioners have sought further rehearing and clarification of the Commission’s determinations in Order No. 1000–A.3 The Commission largely affirms the determinations reached in Order No. 1000–A, making clarifications to address matters raised by petitioners. II. Transmission Planning A. Regional Transmission Planning 5. Order No. 1000 built on the reforms adopted in Order No. 890 to improve regional transmission planning. First, Order No. 1000 required each public utility transmission provider to participate in a regional transmission planning process that produces a regional transmission plan and complies with existing Order No. 890 transmission planning principles.4 3 A list of petitioners filing requests for rehearing and/or clarification is provided in Appendix A. Southwest Power Pool (SPP) filed a request for clarification and/or reconsideration of Order No. 1000–A. While SPP denominates its pleading as a request for clarification, it is, in fact, a late-filed request for rehearing. Pursuant to section 313(a) of the Federal Power Act (FPA), 16 U.S.C. 825l(a) (2006), an aggrieved party must file a request for rehearing within thirty days after the issuance of the Commission’s order. Because the 30-day rehearing deadline is statutory, it cannot be extended, and SPP’s request for rehearing must be rejected as untimely. Moreover, the courts have repeatedly recognized that the time period within which a party may file an application for rehearing of a Commission order is statutorily established at 30 days by section 313(a) of the FPA and that the Commission has no discretion to extend that deadline. See, e.g., City of Campbell v. FERC, 770 F.2d 1180, 1183 (D.C. Cir. 1985); Boston Gas Co. v. FERC, 575 F.2d 975, 977–79 (1st Cir. 1978). Furthermore, we note that the issues raised by SPP are similar to those raised by other petitioners, which are summarized and addressed below in section II.B.2 of this order. 4 Order No. 1000, FERC Stats. & Regs. ¶ 31,323 at P 68. PO 00000 Frm 00003 Fmt 4700 Sfmt 4700 77 Second, Order No. 1000 adopted reforms under which transmission needs driven by Public Policy Requirements are considered in local and regional transmission planning processes.5 The Commission explained that these reforms work together to ensure that public utility transmission providers in every transmission planning region, in consultation with stakeholders, evaluate proposed alternative solutions at the regional level that may resolve the region’s needs more efficiently or cost-effectively than solutions identified in the local transmission plans of individual public utility transmission providers.6 The Commission noted that, as in Order No. 890, the transmission planning requirements in Order No. 1000 do not address or dictate which transmission facilities should be either in the regional transmission plan or actually constructed, and that such decisions are left in the first instance to the judgment of public utility transmission providers, in consultation with stakeholders participating in the regional transmission planning process.7 1. Role of Section 217(b)(4) of the Federal Power Act a. Order No. 1000–A 6. In Order No. 1000–A, the Commission affirmed Order No. 1000’s conclusion that the Commission has ample legal authority under the Federal Power Act (FPA) to undertake its regional transmission planning reforms. Among other things, Order No. 1000–A rejected arguments that FPA section 217(b)(4) 8 prohibits or otherwise limits the Commission’s ability to undertake these reforms.9 Order No. 1000–A 5 Id. The Commission explained that Public Policy Requirements are those established by state or federal laws or regulations, meaning enacted statutes (i.e., passed by the legislature and signed by the executive) and regulations promulgated by a relevant jurisdiction, whether within a state or at the federal level. Id. P 2. Order No. 1000–A clarified that this included transmission needs driven by local laws or regulations. Order No. 1000–A, 139 FERC ¶ 61,132 at P 319. 6 Id. 7 Id. P 68 n.57. 8 16 U.S.C. 824s (2006). 9 Order No. 1000–A, 139 FERC ¶ 61,132 at PP 168–179. E:\FR\FM\24OCR1.SGM 24OCR1 64892 Federal Register / Vol. 77, No. 206 / Wednesday, October 24, 2012 / Rules and Regulations acknowledged claims by some petitioners that Order No. 681,10 which requires transmission organizations that are public utilities with organized electricity markets to make available long-term firm transmission rights that satisfy certain guidelines, expressly notes a preference for load-serving entities.11 Order No. 1000–A found that Order No. 681’s priority for load-serving entities in the allocation of long-term firm transmission rights supported by existing transmission capacity is not inconsistent with Order No. 1000, which addresses planning and cost allocation for new transmission.12 Order No. 1000–A also found that the transmission planning reforms will aid, and not hinder, load-serving entities in meeting their reasonable transmission needs.13 TKELLEY on DSK3SPTVN1PROD with RULES b. Request for Rehearing 7. Transmission Access Policy Study Group argues that in Order No. 1000–A, the Commission suggested for the first time that the preference for load-serving entity long-term rights established in Order No. 681 applies only to existing transmission capacity ‘‘but not in the broader context of planning new transmission capacity.’’ 14 Transmission Access Policy Study Group contends that the Commission erred in suggesting that Order No. 681 does not apply to new transmission facilities, contending that Order No. 681 extended the preference to be afforded load-serving entities to long-term rights from existing capacity to new capacity by providing that ‘‘[w]hen * * * transmission upgrades [that are rolled into transmission rates] come into service, the transmission rights that result from such investments will be made available as rights from ‘existing capacity.’ ’’ 15 Transmission Access Policy Study Group states that this provision had one limited exception—where a transmission upgrade is participantfunded.16 It contends that this exception is inapplicable to the new transmission facilities at issue in this proceeding, as Order No. 1000 specifically ruled that participant funding will not comply with the regional or interregional cost 10 Long-Term Firm Transmission Rights in Organized Electricity Markets, Order No. 681, FERC Stats. & Regs. ¶ 31,226, order on reh’g, Order No. 681–A, 117 FERC ¶ 61,201 (2006), order on reh’g, Order No. 681–B, 126 FERC ¶ 61,254 (2009). 11 Order No. 1000–A, 139 FERC ¶ 61,132 at P 171. 12 Id. P 172. 13 Id. 14 Transmission Access Policy Study Group at 12 (quoting Order No. 1000–A, 139 FERC ¶ 61,132 at P 171). 15 Id. at 13 (quoting Order No. 681, FERC Stats. & Regs. ¶ 31,226 at P 211 (emphasis added)). 16 Id. VerDate Mar<15>2010 17:17 Oct 23, 2012 Jkt 229001 allocation principles adopted by the Final Rule.17 Transmission Access Policy Study Group urges the Commission to clarify that Order Nos. 1000 and 1000–A do not alter the scope or applicability of Order No. 681.18 In the alternative, it argues that Order No. 1000 should be reversed to the extent that it modifies the load-serving entity long-term rights preference established by Order No. 681, by limiting that preference to ‘‘existing’’ transmission facilities, rather than extending it to new transmission that is not participantfunded.19 c. Commission Determination 8. In response to Transmission Access Policy Study Group, we clarify that nothing in either Order No. 1000 or Order No. 1000–A is intended in any way to undermine or alter the guidelines the Commission instituted in Order No. 681. Order No. 1000’s transmission planning reforms are distinct from the Commission’s rulemaking in Order No. 681, as we explain below. 9. Section 1233(a) of the Energy Policy Act of 2005 enacted FPA section 217(b)(4), in which the Commission is directed to exercise its authority under the FPA in a manner that facilitates the planning and expansion of transmission facilities to meet the reasonable needs of load-serving entities to satisfy the service obligations of the load-serving entities, and enables load-serving entities to secure firm transmission rights (or equivalent tradable or financial rights) on a long-term basis for long-term power supply arrangements made, or planned, to meet such needs.20 10. Section 1233(b) of the Energy Policy Act of 2005 further directed the Commission to promulgate a rule on long-term transmission rights in organized markets.21 The Commission consequently issued Order No. 681, which adopted guidelines that independent system operators (ISOs) and regional transmission organizations (RTOs) are required to follow regarding the availability of long-term firm transmission rights, including a guideline providing that load-serving entities ‘‘must have a priority over non17 Id. load serving entities in the allocation of long-term firm transmission rights that are supported by existing capacity.’’ 22 11. As Order No. 1000–A explained, we do not find any inconsistency between Order No. 1000 and section 217(b)(4).23 Nor do we find any inconsistency between Order No. 1000 and Order No. 681. The requirements adopted by the Commission in Order Nos. 1000 and 1000–A are focused on the planning and cost allocation of new transmission facilities, as defined therein. The Commission did not intend its statements in Order No. 1000–A regarding the planning and cost allocation of certain new transmission facilities to alter the requirement in Order No. 681 that ‘‘when [transmission upgrades that are rolled into transmission rates] * * * come into service, the transmission rights that result from such investments will be made available as rights from ‘existing capacity’ * * * . Prevailing cost allocation rules will apply.’’ 24 Thus, we clarify for Transmission Access Policy Study Group that nothing in Order Nos. 1000 or 1000–A changes the requirements of Order No. 681, including the Order No. 681 established preference for load-serving entities in the allocation of long-term firm transmission rights, and that the Commission did not alter the application of Order No. 681 to new transmission facilities that are subject to the requirements of Order No. 1000. 2. Regional Transmission Planning Requirements a. Order No. 1000–A 12. Order No. 1000–A affirmed Order No. 1000’s conclusion that public utility transmission providers must revise their OATTs to provide for a regional transmission planning process that produces a regional transmission plan and satisfies Order No. 890’s transmission planning principles.25 The Commission explained that Order No. 1000 requires neither the filing of the regional transmission plan resulting from the regional transmission planning process nor the filing of specific applications of cost allocation determinations.26 With respect to this latter point, Order No. 1000–A stated 18 Id. 19 Id. 20 16 U.S.C. 824q(b)(4) (2006). 21 EPAct 2005, Public Law 109–58, section 1233, 119 Stat. 594, 960 (2005); 16 U.S.C. 824q (2006)). Section 1233 provides that within 1 year after the date of enactment of that section and after notice and an opportunity for comment, the Commission shall by rule or order, implement section 217(b)(4) of the Federal Power Act in Transmission Organizations, as defined by that Act with organized electricity markets. PO 00000 Frm 00004 Fmt 4700 Sfmt 4700 22 Order No. 681, FERC Stats. & Regs. ¶ 31,226 at P 325. 23 See Order No. 1000–A, 139 FERC ¶ 61,132 at PP 168–179 (addressing requests for rehearing and clarification of Order No. 1000 with respect to the role of section 217(b)(4)). 24 See Order No. 681, FERC Stats. & Regs. ¶ 31,226 at P 211. 25 Order No. 1000–A, 139 FERC ¶ 61,132 at PP 263–301. 26 Id. PP 285–286. E:\FR\FM\24OCR1.SGM 24OCR1 Federal Register / Vol. 77, No. 206 / Wednesday, October 24, 2012 / Rules and Regulations that such a requirement would be unnecessary to comply with Order No. 1000, noting that Order No. 1000 requires that public utility transmission providers have an ex ante cost allocation method on file with and approved by the Commission. Order No. 1000–A also noted that this cost allocation method must explain how the costs of new transmission facilities selected in a regional transmission plan for purposes of cost allocation are to be allocated, consistent with the cost allocation principles set forth in Order No. 1000.27 Consequently, customers, stakeholders, and others will have ‘‘notice’’ at the time the compliance filings are made, when the Commission acts on those filings, and as the regional transmission planning process results in the selection of a transmission facility in the regional transmission plan for purposes of cost allocation.28 However, consistent with the regional flexibility provided in Order No. 1000, Order No. 1000–A also concluded that public utility transmission providers, in consultation with stakeholders, may propose OATT revisions requiring the submission of cost allocations in their Order No. 1000 compliance filings.29 13. The Commission further stated in Order No. 1000–A that it will evaluate compliance filings to ensure that they comply with Order No. 1000 and that both stakeholders and the Commission have the right to initiate actions under section 206 of the FPA if they believe that, for example, a Commissionapproved regional transmission planning process was not followed or if a cost allocation method was not followed or produced unjust and unreasonable results for a particular new transmission facility or class of new transmission facilities.30 TKELLEY on DSK3SPTVN1PROD with RULES b. Request for Rehearing 14. Transmission Access Policy Study Group argues that the Commission should not establish a generic rule that, if transmission providers elect not to propose a section 205 filing of specific applications of their regional cost allocation, the only means to challenge such applications is under section 206.31 It states that although Order No. 1000–A nowhere uses the term ‘‘formula rate’’ to describe the rule’s treatment of regional cost allocation methodologies, it is creating a filing regimen where the 27 Id. P 286. 28 Id. 29 Id. 30 Id. P 287. 31 Transmission Access Policy Study Group at 3. VerDate Mar<15>2010 17:17 Oct 23, 2012 Jkt 229001 cost allocation methodologies will function as just that.32 15. Therefore, Transmission Access Policy Study Group contends that the Commission should require the section 205 filing of project-specific applications of the regional cost allocation methodology, or leave it to the compliance filing process to determine whether such a filing is required.33 If cost allocation methods are treated as formula rates, Transmission Access Policy Study Group maintains that the Commission can have no reasonable assurance that cost allocation methodologies will be sufficiently specific, grounded in objective criteria, and otherwise adequately constrain utility discretion.34 It further asserts that regional cost allocation methodologies, in combination with the process for selecting projects for regional cost allocation, will likely rely on assumptions and other judgments that undermine predictability.35 16. Transmission Access Policy Study Group argues that sole reliance on section 206 to challenge specific implementation of a Commissionaccepted Order No. 1000 methodology when the transmission provider has not made a section 205 filing is unjustified.36 It contends that in the non-RTO context, application of the cost allocation methodology leaves ample room for transmission providers to engage in undue discrimination, and the Commission cannot reasonably assume that the cost allocation methodology, by itself, will in all cases provide customers with ‘‘notice’’ as to how regional facilities will be selected, and their costs allocated, in the future.37 It also contends that transmission providers have the enhanced ability to discriminate, particularly where a cost allocation methodology is unlikely to have the specificity and objectivity to cabin the transmission provider’s discretion, and where stakeholders only may have the opportunity to provide input that the transmission providers are free to ignore.38 It argues that, in these cases in particular, treating the cost allocation methodology as a formula rate improperly shifts the burdens imposed by section 205.39 17. Transmission Access Policy Study Group argues that, at minimum, the 32 Id. at 4. at 5. 34 Id. at 6. 35 Id. at 7. 36 Id. 37 Id. at 7–8. 38 Id. at 8. 39 Id. 33 Id. PO 00000 Frm 00005 Commission should defer making a generic finding now that section 206 is the only available recourse to challenge specific applications of regional cost allocation methodologies absent transmission providers electing to propose section 205 filings of those specific applications.40 Instead, it suggests that the Commission should leave for determination on a case-bycase basis the process of evaluating Order No. 1000 compliance filings, in response to requests by transmission providers or other stakeholders or on its own motion, whether in a particular region the filing of specific applications of the regional cost allocations is necessary.41 It maintains that deferral will enable the Commission to consider the specifics of the proposed regional cost allocation methodology in conjunction with the proposed project selection process and associated governance and other safeguards (if any), as well as the views of public utility transmission providers in that region and other stakeholders.42 c. Commission Determination 18. We deny rehearing. Transmission Access Policy Study Group has not persuaded us that the determination not to require the filing of specific applications of the cost allocation method was in error. Order No. 1000’s reforms are intended, in part, to establish an open and transparent transmission planning process and require transmission planning regions to adopt a cost allocation method or methods that provide ex ante certainty. Both the Order No. 1000 compliance process and the resulting Commissionapproved regional transmission planning process and associated cost allocation method(s) are required to have built-in mechanisms to help ensure that the processes and cost allocation methods are in fact transparent and provide the certainty that Transmission Access Policy Study Group seeks. 19. First, stakeholders have had the opportunity to participate fully in regional stakeholder meetings to advocate for a cost allocation method that provides the ex ante certainty that Order No. 1000 seeks, as well as to advocate that public utility transmission providers include a provision requiring the filing of specific applications of the cost allocation method. We believe that this approach accords with the regional flexibility we provided in Order No. 1000 for public utility transmission 40 Id. at 9. 41 Id. 42 Id. Fmt 4700 Sfmt 4700 64893 E:\FR\FM\24OCR1.SGM at 10. 24OCR1 64894 Federal Register / Vol. 77, No. 206 / Wednesday, October 24, 2012 / Rules and Regulations TKELLEY on DSK3SPTVN1PROD with RULES providers and stakeholders in a transmission planning region to develop rules that meet the transmission needs of that region, consistent with the requirements and principles set forth in Order Nos. 1000 and 1000–A. 20. Second, the Commission will carefully consider the Order No. 1000 compliance filings once they are submitted, as well as any protests filed by stakeholders, to ensure that proposals satisfy the requirements that regional transmission planning processes be open and transparent and that the cost allocation method or methods satisfy the Order No. 1000 cost allocation principles. If a filing is deficient, the Commission will require public utility transmission providers to file revisions to address those deficiencies. 21. Third, once the regional transmission planning process is approved by the Commission and becomes effective, the Order No. 890 transmission planning principles, as incorporated into a regional transmission planning process in compliance with Order No. 1000, will help mitigate concerns about the transparency of the process and the application of the cost allocation method. These principles address, among other things, stakeholder participation, information exchange, and dispute resolution.43 By incorporating these principles into the regional transmission planning process, the Commission’s expectation is that there will be increased openness and certainty concerning how beneficiaries of transmission facilities selected in the regional transmission plan for purposes of cost allocation will be determined, as well as internal processes to resolve any questions that might arise as part of this process. And as noted in Order No. 1000–A, in identifying the benefits and beneficiaries for a new transmission facility, the regional transmission planning process must provide entities who will receive regional or interregional cost allocation an understanding of the identified benefits on which the cost allocation is based, all of which would occur prior to the 43 Order No. 890 requires transmission providers to disclose to all customers and other stakeholders the basic criteria, assumptions, and data that underlie their transmission system plans. In addition, transmission providers will be required to reduce to writing and make available the basic methodology, criteria, and processes they use to develop their transmission plans, including how they treat retail native loads, in order to ensure that standards are consistently applied. Preventing Under Discrimination and Preference in Transmission Service, Order No. 890, FERC Stats. & Regs. ¶ 31,241 at P 471 (2007). VerDate Mar<15>2010 17:17 Oct 23, 2012 Jkt 229001 recovery of such costs through a formula rate.44 22. Moreover, as we explained in Order No. 1000–A, stakeholders always have the option of filing a section 206 complaint if they believe that, notwithstanding these protections, there was an incorrect application of the cost allocation method in a particular instance.45 Finally, if stakeholders believe that the previously approved cost allocation method itself is no longer just and reasonable, they also have the option of filing a section 206 complaint with respect to the cost allocation method. 23. Transmission Access Policy Study Group suggests that application of the ex ante cost allocation to, or in, particular instance(s) should require a section 205 filing with the Commission. Order No. 1000 establishes no new requirement with respect to this issue. As we note above, Order No. 1000–A stated that we would consider proposals that would require public utility transmission providers to file specific applications of the cost allocation method. Therefore, Order No. 1000 provides flexibility in this regard and the Commission stated that it will not prejudge any method before the compliance filings are filed, so long as they satisfied the cost allocation principles articulated in Order No. 1000 (with the exception that participant funding may not be the regional or interregional cost allocation method). We will carefully evaluate compliance filings to ensure that they satisfy these principles. 24. Transmission Access Policy Study Group asserts that if the cost allocation method is thought of as a formula rate, it would improperly shift the burdens under section 205 of the FPA, especially where a cost allocation method is unlikely to have specificity or objectivity to cabin transmission providers’ discretion and where they can ignore stakeholder input. We disagree with this argument. As we discuss above, Order No. 1000 provides for ex ante certainty. In Order No. 1000, the Commission stated that it required the development of regional and interregional cost allocation methods to provide greater certainty as to the cost allocation implications of a potential transmission project.46 The Commission also stated that under the regional transmission planning and interregional transmission coordination requirements, public utility transmission providers 44 Order No. 1000–A, 139 FERC ¶ 61,132 at P 746. P 231. 46 Order No. 1000, FERC Stats. & Regs. ¶ 31,323 at PP 559, 579. 45 Id. PO 00000 Frm 00006 Fmt 4700 Sfmt 4700 with stakeholders will identify, evaluate, and determine which transmission facilities meet the region’s needs, and apply the cost allocation method or methods associated with those transmission facilities.47 In Order No. 1000–A, the Commission clarified that public utility transmission providers must consult with stakeholders in developing both regional and interregional cost allocation methods.48 Therefore, the Commission specifically requires public utility transmission providers to provide the opportunity for stakeholder input in the development of the regional and interregional cost allocation methods. If a stakeholder believes that its input is being ignored, it has the right to raise its issues with the cost allocation method or methods when the relevant Order No. 1000 compliance filing is made, or in a separate section 206 filing. 25. We also disagree with Transmission Access Policy Study Group’s argument that the use of a cost allocation method could result in burden shifting under section 205. Order No. 1000–A acknowledged that stakeholder participation is an important aspect of the development of compliance filings to meet the requirements of Order No. 1000, and should ensure that the cost allocation method or methods ultimately agreed upon is balanced and does not favor any particular entity.49 Additionally, the Commission clarified that the Commission’s cost allocation requirements do not interfere with section 205 rights or otherwise impose an undue burden on parties to participate in a new and costly process, but rather build on the reforms to the transmission planning process required by Order No. 890, in which all interested parties should already be participating.50 As noted above, the regional transmission planning process must provide entities who will receive regional or interregional cost allocation an understanding of the identified benefits on which the cost allocation will be based.51 Compliance proposals submitted by transmission providers will be reviewed by the Commission to ensure they provide the upfront certainty required by Order No. 1000.52 To the extent that Transmission 47 Id. P 499. PP 559, 579. 49 Order No. 1000–A, 139 FERC ¶ 61,132 at P 637. 50 Id. P 649. 51 Id. P 746. 52 As Transmission Access Policy Study Group also recognizes, not all RTOs make section 205 filings for the application of an existing filed cost allocation methodology. See Transmission Access Policy Study Group at n.14. Transmission Access 48 Id. E:\FR\FM\24OCR1.SGM 24OCR1 Federal Register / Vol. 77, No. 206 / Wednesday, October 24, 2012 / Rules and Regulations TKELLEY on DSK3SPTVN1PROD with RULES Access Policy Study Group is concerned about cost recovery issues rather than cost allocation, Order No. 1000 explained that such questions are beyond the scope of the generic rulemaking proceeding, and Order No. 1000–A affirmed this, but clarified that public utility transmission providers, in consultation with stakeholders, may choose to address this cost recovery matter in their compliance filings.53 26. We do not believe that Transmission Access Policy Study Group has justified at this time its position that public utility transmission providers in non-RTO regions, at least, should be required to file specific applications of the cost allocation method. Again, as discussed above, our expectation is that the open and transparent transmission planning process and principle-based cost allocation method will provide stakeholders with clarity as to why and how costs are being allocated for any specific transmission facility selected in the regional transmission plan for purposes of cost allocation. This is true regardless of whether or not the transmission planning region is an ISO/ RTO. As we also discuss above, the Commission will carefully evaluate compliance proposals and any resulting protests to ensure that the proposals meet the requirements of Order No. 1000. 27. Finally, with respect to Transmission Access Policy Study Group’s request that we defer a determination on using section 206 as the default mechanism to challenge a cost allocation proposal, references to section 206 in Order No. 1000–A were to remind stakeholders of their right under that provision to file complaints. In any event, as we have previously explained, Order No. 1000–A provides that public utility transmission providers in a transmission planning region, in consultation with stakeholders, could agree to require the filing of specific applications of the cost allocation method. The Commission will review any such requirement during the Order No. 1000 compliance filings process and make a decision based on the record before us. Policy Study Group has not justified its position that this will be an issue in non-ISO/RTO regions at this time. Again, the Commission will carefully evaluate compliance filings, as well as protests thereto, to ensure that they satisfy Order No. 1000’s requirements, and the Commission will require changes if they fail to do so. 53 Order No. 1000–A, 139 FERC ¶ 61,132 at P 616. VerDate Mar<15>2010 17:17 Oct 23, 2012 Jkt 229001 3. Consideration of Transmission Needs Driven by Public Policy Requirements a. Order No. 1000–A 28. Order No. 1000–A affirmed Order No. 1000’s requirement that public utility transmission providers amend their OATTs to provide for the consideration of transmission needs driven by Public Policy Requirements.54 In affirming this requirement, Order No. 1000–A provided clarifications regarding the definition of the term ‘‘Public Policy Requirements’’ 55 and what it means to ‘‘consider’’ transmission needs driven by such requirements.56 Order No. 1000–A explained that the Commission intends that public utility transmission providers consider transmission needs driven by Public Policy Requirements just as they consider transmission needs driven by reliability or economic concerns.57 Further, the Commission stated that it does not intend public utility transmission providers to substitute their policy judgments for those of legislatures and regulators.58 Order No. 1000–A also explained that the Commission does not require that regional transmission plans support multiple likely power supply scenarios, although such a requirement could be proposed in Order No. 1000 compliance filings and the Commission would consider such a proposal.59 b. Request for Clarification 29. AEP requests clarification that an appropriate method for a region to consider transmission needs driven by Public Policy Requirements is to expressly include consideration of changes in resources and load driven by public policies as part of its baseline projection of changes in resources and load expected over the planning horizon, and then conduct reliability and congestion analyses to determine what transmission investments are optimal given those expected changes in resources and load.60 AEP argues that 54 Order No. 1000–A, 139 FERC ¶ 61,132 at PP 317–339. See also id. PP 203–216 (affirming legal basis of requirement to consider transmission needs driven by Public Policy Requirements). 55 Order No. 1000 defined ‘‘Public Policy Requirements’’ as public policy requirements established by state or federal laws and regulations. Order No. 1000, FERC Stats. & Regs. ¶ 31,323 at P 2. Order No. 1000–A clarified that this term included duly enacted laws or regulations passed by a local governmental entity, such as a municipal or county government. Order No. 1000–A, 139 FERC ¶ 61,132 at P 319. 56 Order No. 1000–A, 139 FERC ¶ 61,132 at PP 320–325. 57 Id. P 205. 58 Id. PP 326–29. 59 Id. P 331. 60 AEP at 5. PO 00000 Frm 00007 Fmt 4700 Sfmt 4700 64895 Public Policy Requirements should not be considered solely on a stand-alone basis in the planning process.61 It contends that generation or load changes driven by public policies should be factored into the scenarios, along with other anticipated resource and load changes, for which reliability and economic benefits analyses are performed.62 30. AEP states that it is concerned that some transmission providers may seek to satisfy the Commission’s public policy requirement by employing only a stand-alone process or procedures that are specifically designed to evaluate transmission needs driven by Public Policy Requirements.63 It argues that regional planning processes should consider reliability, economic, and policy-driven transmission needs together.64 In particular, AEP asserts that a region should consider what changes in generation resources and load it expects over the planning horizon, including consideration of changes driven by public policies (such as renewable portfolio standards, new environmental regulations, and demand side management programs), and then conduct reliability and congestion analyses to determine what transmission investments are optimal given these anticipated changes.65 It contends that this approach enables transmission providers to build upon existing planning processes for the reliability and economic analyses used to identify baseline reliability and economic projects.66 AEP argues that integrated consideration of public policy-driven requirements can factor into efficient decisions to accelerate a needed baseline reliability upgrade or increase the capacity of a baseline reliability upgrade or baseline economic upgrade.67 c. Commission Determination 31. We grant AEP’s request for clarification to the extent discussed below. Order No. 1000 requires public utility transmission providers to revise their OATTs to provide for the consideration of transmission needs driven by Public Policy Requirements.68 In Order No. 1000, the Commission 61 Id. at 2. 62 Id. 63 Id. at 4. 64 Id. 65 Id. 66 Id. 67 Id. 68 The requirement to consider transmission needs driven by Public Policy Requirements is described in more detail in Order No. 1000, FERC Stats. & Regs. ¶ 31,323 at PP 203–222 and Order No. 1000–A, 139 FERC ¶ 61,132 at PP 317–339. E:\FR\FM\24OCR1.SGM 24OCR1 64896 Federal Register / Vol. 77, No. 206 / Wednesday, October 24, 2012 / Rules and Regulations provides for regional flexibility so that public utility transmission providers, in consultation with stakeholders, can design proposals addressing this requirement that they believe best meet the needs of their respective transmission planning regions, so long as those proposals satisfy the essential requirement that public utility transmission providers, in consultation with stakeholders, consider transmission needs driven by Public Policy Requirements as set forth in Order No. 1000 and clarified in Order No. 1000–A.69 The Commission anticipates that a variety of approaches could satisfy the Commission’s requirements and we expect that stakeholders supporting such proposals would have the opportunity to advocate for them in the stakeholder processes leading to the Order No. 1000 compliance filings. The Commission will consider any such approaches in the compliance filings when they are submitted for review.70 B. Nonincumbent Transmission Developers 32. In Order No. 1000, the Commission addressed the removal from Commission-jurisdictional tariffs and agreements of provisions that contain a federal right of first refusal to construct transmission facilities selected in a regional transmission plan for purposes of cost allocation. The Commission also adopted a framework that requires the development of qualification criteria and protocols to govern the submission and evaluation of proposals for transmission facilities by public utility transmission providers in the regional transmission planning process. The Commission further required that a nonincumbent transmission developer of a transmission facility selected in the regional transmission plan for purposes of cost allocation have an opportunity comparable to that of an incumbent transmission developer to allocate the cost of such transmission facility through a regional cost allocation method or methods.71 TKELLEY on DSK3SPTVN1PROD with RULES 69 See, e.g., Order No. 1000–A, 139 FERC ¶ 61,132 at P 331 (‘‘It may well be the case that evaluating different power supply scenarios will be an effective way to identify more efficient or costeffective transmission solutions; however, we will not prescribe any such requirements here, consistent with our preference for regional flexibility in designing regional transmission planning processes.’’). 70 See id. 71 Order No. 1000, FERC Stats. & Regs. ¶ 31,323 at P 225. VerDate Mar<15>2010 17:17 Oct 23, 2012 Jkt 229001 1. Legal Authority a. Order No. 1000–A 33. In Order No. 1000–A, the Commission affirmed its conclusion in Order No. 1000 that it has the legal authority under section 206 of the FPA to require the elimination of federal rights of first refusal as practices that have the potential to lead to Commission-jurisdictional rates that are unjust and unreasonable or unduly discriminatory or preferential.72 The Commission stated that, consistent with its authority under section 206, the Commission acted to remedy an unjust and unreasonable or unduly discriminatory or preferential practice by requiring public utility transmission providers to eliminate a federal right of first refusal from Commissionjurisdictional tariffs and agreements and adopt the nonincumbent reforms. The Commission explained that in Order No. 1000, it had found that a federal right of first refusal applicable to transmission facilities selected in a regional transmission plan for purposes of cost allocation can lead to rates for Commission-jurisdictional services that are unjust and unreasonable or otherwise result in undue discrimination by public utility transmission providers.73 34. Finally, the Commission affirmed its decision in Order No. 1000 to address arguments that an individual contract contains a federal right of first refusal that is protected by a MobileSierra provision when it reviews the compliance filings made by public utility transmission providers.74 Consistent with Order No. 1000, the Commission explained that a public utility transmission provider that considers its contract to be protected by a Mobile-Sierra provision may present its arguments as part of its compliance filing. However, the Commission also clarified that any such compliance filing must include the revisions to any Commission-jurisdictional tariffs and agreements necessary to comply with Order No. 1000 as well as the MobileSierra provision arguments.75 The Commission concluded that this approach ensures that public utility transmission providers would not be required to eliminate a federal right of first refusal before the Commission makes a determination regarding whether an agreement is protected by a Mobile-Sierra provision and whether the Commission has met the applicable 72 Order No. 1000–A, 139 FERC ¶ 61,132 at P 357. P 360. 74 Id. P 388. 75 Id. P 389. 73 Id. PO 00000 Frm 00008 Fmt 4700 Sfmt 4700 standard of review, while at the same time ensuring that the Order No. 1000 compliance process proceeds expeditiously and efficiently. b. Requests for Rehearing and Clarification 35. Oklahoma Gas and Electric Company argues that the Commission failed to support its assertion that provisions that designate incumbent utilities to construct new transmission facilities are unduly discriminatory or preferential, or cause rates to be unreasonably high.76 Oklahoma Gas and Electric Company further argues that the Commission cannot support a finding that the current transmission rules in the Southwest Power Pool result in rates that are unjust or unreasonable.77 36. Oklahoma Gas and Electric Company also argues that the Commission ignores that the MobileSierra standard is a threshold question and that the Commission cannot shift the burden of proof to the contracting parties to propose an alternative until the Commission has answered.78 Oklahoma Gas and Electric Company asserts that, under section 206 of the Federal Power Act, the Commission must first prove that the existing rates or practices are unjust, unreasonable, unduly discriminatory or preferential, and that courts have repeatedly held that the Commission has no power to force public utilities to file particular rates unless it first finds the existing filed rates unlawful.79 Oklahoma Gas and Electric Company asserts that this two-step process is even more vital in the context of applying the MobileSierra doctrine because the Commission must presume that the rate set out in a freely negotiated wholesale-energy contract meets the just and reasonable requirement imposed by law.80 Accordingly, Oklahoma Gas and Electric Company argues that the Commission has no power to require parties to renegotiate and revise existing agreements unless it finds harm to the public interest.81 c. Commission Determination 37. We disagree with Oklahoma Gas and Electric Company that the 76 Oklahoma Gas and Electric Company at 4. 77 Id. 78 Id. at 8. at 8–9 (citing Atlantic City Elec. Co. v. FERC, 295 F.3d 1, 10 (D.C. Cir. 2002); Complex Consol. Edison Co. of New York, Inc. v. FERC, 165 F.3d 992, 1001 (D.C. Cir. 1999); Transmission Access Policy Study Group v. FERC, 225 F.3d 667, 688 (D.C. Cir. 2005)). 80 Id. at 9 (citing NRG Power Marketing, LLC v. Maine Public Utilities Commission, 130 S. Ct. 693, 700 (2010)). 81 Id. at 9–10. 79 Id. E:\FR\FM\24OCR1.SGM 24OCR1 Federal Register / Vol. 77, No. 206 / Wednesday, October 24, 2012 / Rules and Regulations Commission failed to support its determination that a federal right of first refusal for transmission facilities selected in a regional transmission plan for purposes of cost allocation may lead to Commission-jurisdictional rates that are unjust and unreasonable or unduly discriminatory or preferential. Specifically, the Commission found that a federal right of first refusal has ‘‘the potential to undermine the identification and evaluation of more efficient or cost-effective solutions to regional transmission needs, which in turn can result in rates for Commissionjurisdictional services that are unjust and unreasonable or otherwise result in undue discrimination by public utility transmission providers.’’ 82 The Commission further explained the direct effect that a federal right of first refusal can have on Commission-jurisdictional rates in Order No. 1000–A, stating that: the selection of transmission facilities in a regional transmission plan for purposes of cost allocation is directly related to costs that will be allocated to jurisdictional ratepayers. The ability of an incumbent transmission provider to discourage or preclude participation of new transmission developers through discriminatory rules in a regional transmission planning process, and in particular, the inclusion of a federal right of first refusal, can have the effect of limiting the identification and evaluation of potential solutions to regional transmission needs. This in turn can directly increase the cost of new transmission development that is recovered from jurisdictional customers through rates.83 TKELLEY on DSK3SPTVN1PROD with RULES 38. The Commission put forth several rationales to support its determination.84 In particular, the Commission noted that the Federal Trade Commission supported the Commission’s conclusion that a federal right of first refusal can create a barrier to entry that discourages nonincumbent transmission developers from proposing alternative solutions for consideration at the regional level.85 In addition, the Commission stated that it is not in the economic self-interest of incumbent transmission providers to permit new entrants to develop transmission facilities, even if proposals submitted by new entrants would result in a more efficient or cost-effective solution to the region’s needs.86 Thus, the Commission concluded that it has a reasonable 82 Order No. 1000, FERC Stats. & Regs. ¶ 31,323 at P 253. 83 Order No. 1000–A, 139 FERC ¶ 61,132 at P 358 (citations omitted). 84 Id. P 76. 85 Order No. 1000, FERC Stats. & Regs. ¶ 31,323 at P 257; see Order No. 1000–A, 139 FERC ¶ 61,132 at P 76. 86 Order No. 1000, FERC Stats. & Regs. ¶ 31,323 at P 256. VerDate Mar<15>2010 17:17 Oct 23, 2012 Jkt 229001 expectation that expanding the universe of transmission developers offering potential solutions to regional needs can lead to the identification and evaluation of potential solutions that are more efficient or cost-effective.87 39. Furthermore, as the Commission explained in the Need for Reform section of Order No. 1000–A, the Commission is not required to make individual findings concerning the rates of individual public utility transmission providers when proceeding under FPA section 206 by means of a generic rule.88 Rather, the Commission can proceed by identifying a ‘‘theoretical threat’’ that would materialize and cause rates to be unjust and unreasonable, or unduly discriminatory or preferential.89 As discussed in the preceding paragraph, the Commission found that a federal right of first refusal has the potential to lead to rates for Commissionjurisdictional services that are unjust and unreasonable or otherwise unduly discriminatory. 40. In response to Oklahoma Gas and Electric Company’s arguments regarding the Mobile-Sierra doctrine, we reiterate that the Commission is not requiring public utility transmission providers to eliminate a federal right of first refusal before the Commission makes a determination regarding whether an agreement is protected by the MobileSierra doctrine and whether the Commission has met the applicable standard of review. As the Commission clarified in Order No. 1000–A, the Commission will first decide, based on a more complete record, including viewpoints of other interested parties, whether an agreement is protected by the Mobile-Sierra doctrine, and if so, whether the Commission has met the applicable standard of review such that it can require the modification of the particular agreement.90 If the Commission determines based on the record submitted in the compliance filing that an agreement is protected by the Mobile-Sierra doctrine and that it cannot meet the applicable standard of review, then the Commission will not consider whether the revisions to the Commission-jurisdictional tariffs and agreements submitted by a public utility transmission provider that considers its agreement to be protected by the MobileSierra doctrine comply with Order No. 1000.91 87 Order No. 1000–A, 139 FERC ¶ 61,132 at PP 77, 83. 88 Id. P 56. 89 Id. P 57. 90 Id. P 389. 91 Id. PO 00000 Frm 00009 Fmt 4700 Sfmt 4700 64897 2. Requirement To Remove a Federal Right of First Refusal From Commission-Jurisdictional Tariffs and Agreements, and Limits on the Applicability of That Requirement a. Order No. 1000–A 41. In Order No. 1000–A, the Commission affirmed its decision in Order No. 1000 to require the elimination of a federal right of first refusal from Commission-jurisdictional tariffs and agreements for transmission facilities selected in a regional transmission plan for purposes of cost allocation.92 The Commission also clarified certain terms used in Order No. 1000. For instance, the Commission clarified that the term ‘‘selected in a regional transmission plan for purposes of cost allocation’’ excludes a new transmission facility if the costs of that facility are borne entirely by the public utility transmission provider in whose retail distribution service territory or footprint that new transmission facility is to be located.93 42. The Commission stated that in general, any regional cost allocation of the cost of a new transmission facility outside a single transmission provider’s retail distribution service territory or footprint, including an allocation to a ‘‘zone’’ consisting of more than one transmission provider, is an application of the regional cost allocation method and that new transmission facility is not a local transmission facility.94 As an example, the Commission stated that transmission owning members of an RTO may not retain a federal right of first refusal by dividing the RTO into East and West multi-utility zones and allocating costs just within one zone consisting of more than one transmission provider.95 The Commission also stated that it will address whether a cost allocation to a multi-transmission provider zone is regional on a case-by-case basis based on the specific facts presented. The Commission explained that there may be a continuum of examples that range from (i) one small municipality with a single small transmission facility located within a transmission provider’s footprint, to (ii) a ‘‘zone’’ consisting of many public utility and nonpublic utility transmission providers. Accordingly, the Commission stated that public utility transmission providers may include specific situations in their compliance filings along with the filed regional cost 92 Id. P 415. P 423. 94 Id. P 424. 95 Id. 93 Id. E:\FR\FM\24OCR1.SGM 24OCR1 64898 Federal Register / Vol. 77, No. 206 / Wednesday, October 24, 2012 / Rules and Regulations allocation method or methods.96 The Commission clarified that if any costs of a new transmission facility are allocated regionally or outside of a public utility transmission provider’s retail distribution service territory or footprint, there can be no federal right of first refusal associated with such transmission facility, except as provided in Order Nos. 1000 and 1000–A.97 b. Requests for Rehearing and Clarification 43. Petitioners seek rehearing of the Commission’s determination in Order No. 1000–A that a transmission facility is considered selected in a regional transmission plan for purposes of cost allocation if any of the costs of that facility are allocated outside of the public utility transmission provider’s retail distribution service territory or footprint.98 MISO Transmission Owners Group 2 argues that under a reasonable interpretation of Order No. 1000, a transmission provider may retain its right of first refusal if a transmission facility is not selected in a regional transmission plan for purposes of cost allocation as a more efficient or costeffective solution to regional needs but instead was selected to primarily address local needs.99 MISO Transmission Owners Group 2 states that not all projects included in the regional transmission plan for which some costs are allocated outside of an individual utility’s footprint are ‘‘a more efficient or cost-effective solution to regional transmission needs,’’ such as projects constructed to meet compliance with state service obligations or where the most efficient or cost-effective solution may not be in-service in time to satisfy reliability criteria and the decision to include the project in the plan is made primarily on the basis of reliability.100 44. MISO Transmission Owners Group 2 argues, however, that statements in Order No. 1000–A suggest that the decision regarding whether a facility is more efficient or cost-effective is irrelevant to determining whether the requirement to remove federal rights of first refusal would apply.101 MISO TKELLEY on DSK3SPTVN1PROD with RULES 96 Id. 97 Id. P 430. For example, the Commission does not require an incumbent transmission provider to eliminate a federal right of first refusal for upgrades to its own transmission facilities. Order No. 1000, FERC Stats. & Regs. ¶ 31,323 at P 319. 98 See, e.g. MISO Transmission Owners Group 2 and Oklahoma Gas and Electric Company. 99 MISO Transmission Owners Group 2 at 12–13. 100 Id. at 14–15 (citing Order No. 1000–A, 139 FERC ¶ 61,132 at P 430). 101 Id. at 13–14 (citing Order No. 1000–A, 139 FERC ¶ 61,132 at P 430 (‘‘if any costs of a new transmission facility are allocated regionally or VerDate Mar<15>2010 17:17 Oct 23, 2012 Jkt 229001 Transmission Owners Group 2 argues that the Commission cites no record evidence or argument in favor of broadening the definition of transmission facilities selected in a regional transmission plan for purposes of cost allocation.102 Accordingly, MISO Transmission Owners Group 2 asks for the Commission to clarify that, in order for the requirement to eliminate the federal right of first refusal to apply, the costs of a transmission facility must not only be allocated outside of a transmission owner’s retail distribution service territory or footprint and the transmission facility must have been selected in the regional transmission plan, but it also must be selected as a more efficient or cost-effective solution to regional transmission needs. The MISO Transmission Owners Group requests that the Commission clarify that utilities may retain a right of first refusal for projects that are selected which may not be the ‘‘more efficient or cost-effective solution to regional transmission needs.’’ 103 45. MISO Transmission Owners Group 2 also argues that eliminating the ability of a transmission-owning member of an RTO to construct and allocate the costs of a local transmission facility encourages free ridership by providing an incentive for transmission providers to keep cost allocation within their retail distribution service territory to retain a right of first refusal for local transmission facilities, even when entities outside of the retail distribution service territory or footprint may receive some benefit from such facilities despite their primarily local nature.104 46. Oklahoma Gas and Electric Company argues that a broader definition of what constitutes regional cost allocation prohibits transmission planning regions from adopting approaches they believe would effectively allocate costs and fairly balance stakeholder interests.105 For instance, Oklahoma Gas and Electric Company states that the Southwest Power Pool allocates costs using a Highway/Byway Plan.106 Oklahoma Gas outside of a public utility transmission provider’s retail distribution service territory or footprint, then there can be no federal right of first refusal associated with such transmission facility.’’)). 102 Id. at 18. 103 Id. at 15–19. 104 Id. at 19. 105 Oklahoma Gas and Electric Company at 6. 106 Id. (citing Southwest Power Pool, Inc., 131 FERC ¶ 61,252 (2010), reh’g denied, 137 FERC ¶ 61,075 (2011)). Oklahoma Gas and Electric Company states that the Southwest Power Pool allocates: (1) 100% of the cost of a facility operating at 300 kV or above across the region on a postage stamp basis; (2) one-third of the cost of a facility operating above 100 kV and below 300 kV on a PO 00000 Frm 00010 Fmt 4700 Sfmt 4700 and Electric Company asserts that the Commission should ensure that the Southwest Power Pool can retain its Highway/Byway Plan for cost allocation by designating lower voltage facilities as local facilities for purposes of Order No. 1000.107 47. Some petitioners request that the Commission clarify that projects with costs allocated to a single zone should be considered local, even if the zone consists of more than one public utility transmission provider, so that the public utility transmission provider may retain a federal right of first refusal.108 AEP contends that the Commission’s proposal to defer evaluation of multiutility zones until the compliance filing stage does little to inform ongoing RTO stakeholder processes tasked with developing compliance filings.109 MISO Transmission Owners Group 2 asserts that the Commission failed to identify any record evidence or argument for its conclusion that transmission providers located in multi-transmission provider zones automatically lose their federal rights of first refusal for all transmission facilities.110 48. MISO Transmission Owners Group 2 also argues that the Commission’s stated concern that such zones might be established to circumvent Order No. 1000 is misplaced.111 In support, MISO Transmission Owners Group 2 asserts that such zones were established prior to the issuance of Order No. 1000 and based on decades of cooperation and collaboration among transmission owners.112 In addition, MISO Transmission Owners Group 2 argues that the Commission’s distinction between multi-transmission provider zones and zones containing only one transmission provider results in undue discrimination against transmission providers that happen to be located in a multi-transmission provider zone.113 regional postage stamp basis and the remaining two-thirds of the costs to the zone in which the facility is located; and, (3) all the costs of a facility operating at or under 100 kV to the zone in which the facility is located. Id. 107 Id. 108 See, e.g., AEP and MISO Transmission Owners Group 2. 109 AEP at 10–11. AEP cites as an example SPP’s stakeholder process which at the time of AEP’s request for clarification, was debating the interpretation of the Commission’s intended treatment of zones that have long included a single large, traditional load-serving public utility, as well as several small municipal or cooperative utilities that are dependent on the transmission system of the traditional public utility to serve their respective loads. 110 MISO Transmission Owners Group 2 at 24. 111 Id. at 22. 112 Id. 113 Id. at 26. E:\FR\FM\24OCR1.SGM 24OCR1 Federal Register / Vol. 77, No. 206 / Wednesday, October 24, 2012 / Rules and Regulations TKELLEY on DSK3SPTVN1PROD with RULES 49. Oklahoma Gas and Electric Company contends that the Commission incorrectly claimed in Order No. 1000– A that the scope of Order No. 1000 will be limited. It asserts that, in response to arguments that the requirement to eliminate the right of first refusal is beyond the Commission’s authority and will materially alter the business of public utilities, the Commission in Order No. 1000–A emphasized that the requirement did not extend to local transmission facilities.114 Oklahoma Gas and Electric Company asserts that based on the discussion of zones in Order No. 1000–A, it may not be possible to build a local facility under the Southwest Power Pool tariff, making all new construction subject to Order No. 1000.115 Similarly, MISO Transmission Owners Group 2 contends that RTO transmission-owning members lack individual mechanisms for cost allocation and recovery, and therefore would have no ability to build and recover the costs of local transmission facilities as they are defined in Order No. 1000.116 50. Oklahoma Gas and Electric Company argues that because the requirement to eliminate provisions that designate incumbent utilities to construct new transmission facilities is not limited in scope, and does materially alter the businesses of transmission owning companies, the Commission should find that there is no sound basis to require that public utility transmission providers remove such provisions.117 In the alternative, Oklahoma Gas and Electric Company asserts that the Commission should allow each region to define the scope of local transmission projects that will not be subject to the new rule.118 c. Commission Determination 51. On rehearing of Order No. 1000– A, petitioners have raised two issues related to Order No. 1000’s requirement that public utility transmission providers remove federal rights of first refusal from Commission-jurisdictional tariffs and agreements. First, some petitioners seek rehearing of Order No. 1000–A’s determination that if any of the costs of a new transmission facility are allocated regionally or outside of a public utility transmission provider’s retail distribution service territory or footprint, then there can be no federal right of first refusal associated with such transmission facility. Second, on 114 Oklahoma Gas and Electric Company at 3–5. at 5–6. 116 MISO Transmission Owners Group 2 at 23. 117 Oklahoma Gas and Electric Company at 7. 118 Id. 115 Id. VerDate Mar<15>2010 17:17 Oct 23, 2012 Jkt 229001 rehearing some petitioners argue that projects with costs allocated to a single zone should be considered local, even if there is more than one public utility transmission provider located in that zone, so that the public utility transmission provider may retain a federal right of first refusal under those circumstances. We deny rehearing and will discuss each of these issues in turn. 52. As noted above, the first issue we address concerns requests for rehearing of Order No. 1000–A’s determination that if any costs of a new transmission facility are allocated regionally or outside of a public utility transmission provider’s retail distribution service territory or footprint, then there can be no federal right of first refusal associated with such transmission facility, except as provided in Order Nos. 1000 and 1000–A.119 Order No. 1000 requires that a federal right of first refusal be removed for new transmission facilities selected in a regional transmission plan for purposes of cost allocation. As noted above, the Commission stated in Order No. 1000 that in general, if any costs of a new transmission facility are allocated regionally or outside a single transmission provider’s retail distribution service territory or footprint, that is an application of the regional cost allocation method and that new transmission facility is not a local transmission facility.120 Therefore, once a new transmission facility is selected in the regional transmission plan for purposes of cost allocation, it is no longer a local transmission facility exempt from the requirements of Order Nos. 1000 and 1000–A regarding the removal of federal rights of first refusal. For this reason, we deny rehearing on this issue. 53. We note that neither Order No. 1000 nor Order No. 1000–A requires elimination of a federal right of first refusal in all circumstances.121 We also note that the Commission recognized that issuance of Order No. 1000 may have occurred in the middle of a transmission planning cycle for a particular region and, therefore, directed public utility transmission providers to explain in their respective compliance filings how they intend to implement the requirements of the Final Rule.122 119 Order No. 1000–A, 139 FERC ¶ 61,132 at P 430. 120 Id. P 424 (emphasis added). No. 1000, FERC Stats. & Regs. ¶ 31,323 at PP 318–319. 122 Id. P 162. See also id. P 65 (‘‘Our intent here is that this Final Rule not delay current studies being undertaken pursuant to existing regional transmission planning processes or impede progress on implementing existing transmission plans. We 121 Order PO 00000 Frm 00011 Fmt 4700 Sfmt 4700 64899 Moreover, public utility transmission providers are required to describe the circumstances and procedures under which public utility transmission providers will reevaluate the regional transmission plan to determine if delays in the development of a transmission facility selected in a regional transmission plan for purposes of cost allocation require evaluation of alternative solutions, including those proposed by the incumbent transmission provider, to ensure the incumbent transmission provider can meet its reliability needs or service obligations.123 We will evaluate proposals related to these requirements on review of compliance filings. 54. With respect to the second issue raised by petitioners—whether a project whose costs are allocated to a single zone with multiple transmission owners should be considered local and thus permit a public utility transmission provider to retain a federal right of first refusal under these circumstances—the Commission recognized in Order No. 1000–A that special consideration is needed when a small transmission provider is located within the footprint of another transmission provider.124 The Commission acknowledged that there is a continuum of situations of multitransmission provider zones, but opted to address such situations on compliance. This acknowledgement provides public utility transmission providers who may have zonal configurations, such as a zone with a small municipality and one transmission provider, or one with many public utility and non-public utility transmission providers, an opportunity to address whether a cost allocation to a multi-transmission provider zone is regional on a case-bycase basis based on the specific facts presented. We consider many of the arguments related to multi-transmission provider zones premature because the Commission did not adopt a generic rule as to whether a cost allocation solely to a multi-transmission provider zone is an application of the regional cost allocation method for which a direct public utility transmission providers to explain in their compliance filings how they will determine which facilities evaluated in their local and regional planning processes will be subject to the requirements of this Final Rule.’’). 123 Order No. 1000–A, FERC Stats. & Regs. ¶ 31,132 at P 477. See also Order No. 1000, FERC Stats. & Regs. ¶ 31,323 at P 329 (‘‘[A]n incumbent transmission provider must have the ability to propose solutions that it would implement within its retail distribution service territory or footprint that will enable it to meet its reliability needs or service obligations.’’). 124 Order No. 1000–A, FERC Stats. & Regs. ¶ 31,132 at P 424. E:\FR\FM\24OCR1.SGM 24OCR1 64900 Federal Register / Vol. 77, No. 206 / Wednesday, October 24, 2012 / Rules and Regulations federal right of first refusal must be eliminated. Petitioners have not presented evidence that would support the Commission making a generic finding or providing additional guidance for all multi-transmission provider zones in this rulemaking proceeding. Therefore, on this second issue, we find that the Commission’s determination is a reasonable balance of competing considerations that enables the Commission to implement the requirements of Order No. 1000 in a manner that will achieve the goal of improved transmission planning. 55. We therefore agree with petitioners that the Commission’s requirements have not entirely eliminated opportunities for free ridership. As evidenced by the multiple comments and petitions the Commission received in the Order No. 1000 proceedings, the Commission balanced many competing interests in determining how to best implement the requirements of Order No. 1000. Some presented their views of the advantages of retaining a federal right of first refusal for all new transmission facilities while others presented their views of the advantages of eliminating a federal right of first refusal for all new transmission facilities. The Commission has considered the arguments raised by petitioners on rehearing with respect to both of the above-mentioned issues and rejects petitioners’ requests for rehearing as we find that the approach taken in Order Nos. 1000 and 1000–A provides the best balance of competing considerations. 3. Framework To Evaluate Transmission Projects Submitted for Selection in the Regional Transmission Plan for Purposes of Cost Allocation TKELLEY on DSK3SPTVN1PROD with RULES a. Evaluation of Proposals for Selection in the Regional Transmission Plan for Purposes of Cost Allocation i. Order No. 1000–A 56. In Order No. 1000–A, the Commission affirmed its decision in Order No. 1000 to require each public utility transmission provider to amend its OATT to describe a transparent and not unduly discriminatory process for evaluating whether to select a proposed transmission facility in a regional transmission plan for purposes of cost allocation.125 The Commission also reiterated that there are many different approaches to transmission planning and that Order No. 1000 requires only that the transmission planning process adopted by a transmission planning 125 Order No. 1000–A, 139 FERC ¶ 61,132 at P 452. VerDate Mar<15>2010 17:17 Oct 23, 2012 Jkt 229001 region satisfy the transmission planning principles discussed in Order Nos. 1000 and 1000–A. Accordingly, the Commission declined to rule in the abstract in advance of the compliance filings whether any particular transmission planning process is the only appropriate process for all regions. 57. The Commission also continued to emphasize that any qualification criteria or process for selecting transmission facilities in a regional transmission plan for purposes of cost allocation must be transparent and not unduly discriminatory.126 Finally, the Commission affirmed its decision that, if a proposed transmission facility is selected in a regional transmission plan for purposes of cost allocation, then Order No. 1000 requires that the transmission developer of that transmission facility (whether incumbent or nonincumbent) must be able to rely on the relevant cost allocation method or methods within the region should it move forward with its transmission project.127 The Commission also reiterated that it would not require public utility transmission providers in a region to adopt a provision for ongoing sponsorship rights, and pointed out that in Order No. 1000, the Commission concluded that granting transmission developers an ongoing right to build sponsored transmission projects could adversely impact the regional transmission planning process.128 Accordingly, the Commission in Order No. 1000–A declined to reverse this decision on the selection of transmission developers.129 ii. Requests for Rehearing and Clarification 58. AEP maintains that some regions are considering a process in which third parties (e.g., one or more states) select the developer for a transmission project after the regional planning entity has identified needed transmission projects in its regional transmission plan.130 AEP asserts that leaving the selection of a project developer to an entity other than the regional planning body threatens to lead to suboptimal results.131 It argues that the decision as to which entity is best suited to build a given transmission 126 Id. PP 439, 452. P 456; Order No. 1000, FERC Stats. & Regs. ¶ 31,323 at P 339. 128 Order No. 1000–A, 139 FERC ¶ 61,132 at P 456; Order No. 1000, FERC Stats. & Regs. ¶ 31,323 at P 339. 129 Order No. 1000–A, 139 FERC ¶ 61,132 at P 456; Order No. 1000, FERC Stats. & Regs. ¶ 31,323 at P 339. 130 AEP at 6. 131 Id. at 2. 127 Id. PO 00000 Frm 00012 Fmt 4700 Sfmt 4700 project necessarily relies on developer qualifications as assessed by the transmission provider, and on projected benefits, which will vary among developers.132 It contends that the selection of the best transmission solution for the region cannot be done effectively without information about the qualifications and the benefits offered by the developer for the project.133 Accordingly, AEP requests that the Commission provide clarification to discourage bifurcation of the planning process.134 iii. Commission Determination 59. We decline to clarify in advance of the compliance filings whether any particular approach to the selection of a transmission developer is a just and reasonable and not unduly discriminatory or preferential selection process. Order No. 1000 requires public utility transmission providers in a region to adopt transparent and not unduly discriminatory criteria for selecting a new transmission project in a regional transmission plan for purposes of cost allocation.135 It also requires that if a transmission project is selected in a regional transmission plan for purposes of cost allocation, the transmission developer of that transmission facility must be able to rely on the relevant cost allocation method or methods within the region should it move forward with the transmission project.136 However, the Commission declined to otherwise address the selection of a transmission developer on a generic basis.137 We continue to believe that it is not appropriate to address in advance of the compliance filings the process for selecting transmission developers in greater detail. Instead, we reaffirm the flexibility that the Commission provided to the public utility transmission providers in each transmission planning region to propose a process for selecting transmission developers in accordance with each transmission planning region’s needs.138 C. Interregional Transmission Coordination 60. In Order No. 1000, the Commission required each public utility 132 Id. at 6. at 6–7. 134 Id. at 6. 135 E.g., Order No. 1000–A, 139 FERC ¶ 31,132 at P 455. 136 Order No. 1000, FERC Stats. & Regs. ¶ 31,323 at PP 332, 339; see also Order No. 1000–A, 139 FERC ¶ 61,132 at P 456. 137 E.g., Order No. 1000–A, 139 FERC ¶ 61,132 at P 455. 138 E.g., id. 133 Id. E:\FR\FM\24OCR1.SGM 24OCR1 Federal Register / Vol. 77, No. 206 / Wednesday, October 24, 2012 / Rules and Regulations transmission provider, through its regional transmission planning process, to establish further procedures with each of its neighboring transmission planning regions for the purpose of: (1) Coordinating and sharing the results of respective regional transmission plans to identify possible interregional transmission facilities that could address transmission needs more efficiently or cost-effectively than separate regional transmission facilities; and (2) jointly evaluating such facilities, as well as jointly evaluating those transmission facilities that are proposed to be located in more than one transmission planning region.139 The Commission also required each public utility transmission provider, through its regional transmission planning process, to describe the methods by which it will identify and evaluate interregional transmission facilities and to include a description of the type of transmission studies that will be conducted to evaluate conditions on neighboring systems for the purpose of determining whether interregional transmission facilities are more efficient or cost-effective than regional facilities.140 1. Implementation of the Interregional Transmission Coordination Requirements a. Procedure for Joint Evaluation TKELLEY on DSK3SPTVN1PROD with RULES i. Order No. 1000–A 61. In Order No. 1000–A, the Commission reaffirmed Order No. 1000’s requirement that an interregional transmission facility must be selected in each relevant regional transmission plan for purposes of cost allocation to be eligible for cost allocation under the interregional cost allocation method or methods.141 The Commission explained that Order No. 1000 establishes a closer link between transmission planning and cost allocation. Additionally, the Commission stated that Order No. 1000 provides for stakeholder involvement in the consideration of an interregional transmission facility primarily through the regional transmission planning processes.142 The Commission concluded that this requirement is necessary to ensure that stakeholders have an opportunity to provide meaningful input with respect to proposed interregional transmission 139 Order No. 1000, FERC Stats. & Regs. ¶ 31,323 at P 493. 140 Id. 141 Order No. 1000–A, 139 FERC ¶ 61,132 at P 509 (citing Order No. 1000, FERC Stats. & Regs. ¶ 31,323 at P 436). 142 Order No. 1000, FERC Stats. & Regs. ¶ 31,323 at P 465; see also id. P 443. VerDate Mar<15>2010 17:17 Oct 23, 2012 Jkt 229001 facilities before such facilities are selected in each relevant regional transmission plan for purposes of cost allocation.143 62. Additionally, the Commission acknowledged that, under the interregional transmission coordination procedures of Order No. 1000, an interregional transmission facility is unlikely to be selected for interregional cost allocation unless each transmission planning region benefits or the transmission planning region that benefits compensates the region that does not through a separate agreement. The Commission expressed its continued belief that, under the regional transmission planning approach adopted in Order No. 1000, it is appropriate for each transmission planning region to determine for itself whether to select in its regional transmission plan for purposes of cost allocation an interregional transmission facility that extends partly within its regional footprint based on the information gained during the joint evaluation of an interregional transmission project.144 ii. Requests for Rehearing and Clarification 63. AEP requests clarification that the inclusion of an interregional project in a regional plan need not be subject to the same benefits tests that would be applied to a single-region project, and that a region may include an interregional project in its plan if the benefits to the region compare favorably to the share of the costs that would be borne by that region (as distinct from the total project costs).145 Specifically, it states that in determining the costs and benefits of a proposed interregional transmission project for the purposes of the selection process, a regional transmission planning entity should be permitted to evaluate the benefits provided to an affected region and assume that a portion of the costs of the project will be allocated to the affected region.146 For example, if a $100 million interregional project would have $180 million in benefits split evenly between two adjacent regions, both regions would find the project beneficial and would include it in the regional plan, if they assumed that one-half of the cost would be borne by each region.147 143 Order No. 1000–A, 139 FERC ¶ 61,132 at P 509. 144 Id. P 512. at 2, 7. 146 Id. at 8. 147 Id. 145 AEP PO 00000 Frm 00013 Fmt 4700 Sfmt 4700 64901 iii. Commission Determination 64. Order No. 1000 did not specify whether or how a regional or interregional benefit-cost threshold should be applied when selecting a project in the regional transmission plan for purposes of cost allocation, or which costs should be included when calculating a benefit-cost threshold to use in this selection process. This was to provide the opportunity for each region to develop an appropriate calculation, if it chose to use a threshold at all. Therefore, we decline to clarify in advance of the compliance filings how a benefit-cost threshold should be applied. III. Cost Allocation 65. In Order No. 1000, the Commission required that each public utility transmission provider have in its OATT a method, or set of methods, for allocating the costs of new regional transmission facilities selected in the regional transmission plan for purposes of cost allocation (‘‘regional cost allocation’’); and that each public utility transmission provider within two (or more) neighboring transmission planning regions develop a method, or set of methods, for allocating the costs of new interregional transmission facilities that each of the two (or more) neighboring transmission planning regions selected for purposes of cost allocation because such facilities would resolve the individual needs of each region more efficiently or costeffectively (‘‘interregional cost allocation’’).148 The Commission required that the OATTs of all public utility transmission providers in a region include the same cost allocation method or methods adopted by the region.149 66. The Commission also required that regional and interregional cost allocation methods each adhere to six regional and interregional cost allocation principles: (1) Costs must be allocated in a way that is roughly commensurate with benefits; (2) there must be no involuntary allocation of costs to non-beneficiaries; (3) a benefit to cost threshold ratio cannot exceed 1.25; (4) costs must be allocated solely within the transmission planning region 148 Order No. 1000, FERC Stats. & Regs. ¶ 31,323 at P 482. For purposes of Order No. 1000, a regional transmission facility is a transmission facility located entirely in one region. An interregional transmission facility is one that is located in two or more transmission planning regions. A transmission facility that is located solely in one transmission planning region is not an interregional transmission facility. Id. P 482 n.374. 149 Order No. 1000–A, 139 FERC ¶ 61,132 at P 523. E:\FR\FM\24OCR1.SGM 24OCR1 64902 Federal Register / Vol. 77, No. 206 / Wednesday, October 24, 2012 / Rules and Regulations or pair of regions unless those outside the region or pair of regions voluntarily assume costs; (5) there must be a transparent method for determining benefits and identifying beneficiaries; and (6) there may be different methods for different types of transmission facilities.150 The Commission directed that, subject to these general cost allocation principles, public utility transmission providers in consultation with stakeholders would have the opportunity to agree on the appropriate cost allocation methods for their new regional and interregional transmission facilities, subject to Commission approval.151 The Commission also found that if public utility transmission providers in a region or pair of regions could not agree, the Commission would use the record in the relevant compliance filing proceeding(s) as a basis to develop a cost allocation method or methods that meets the Commission’s requirements.152 Finally, the Commission emphasized that its cost allocation requirements are designed to work in tandem with its transmission planning requirements to identify more appropriately the benefits and the beneficiaries of new transmission facilities so that transmission developers, planners and stakeholders can take into account in the transmission planning process who would bear the costs of transmission facilities, if constructed.153 1. Cost Allocation Principle 2—No Involuntary Allocation of Costs to NonBeneficiaries a. Order Nos. 1000 and 1000–A 67. In Order No. 1000, the Commission adopted the following Cost Allocation Principle 2 for both regional and interregional cost allocation: Regional Cost Allocation Principle 2: Those that receive no benefit from transmission facilities, either at present or in a likely future scenario, must not be involuntarily allocated any of the costs of those transmission facilities. and TKELLEY on DSK3SPTVN1PROD with RULES Interregional Cost Allocation Principle 2: A transmission planning region that receives no benefit from an interregional transmission facility that is located in that region, either at present or in a likely future scenario, must not be involuntarily allocated any of the costs of that transmission facility.154 68. The Commission also required that every cost allocation method or 150 Order 17:17 Oct 23, 2012 Jkt 229001 b. Requests for Rehearing or Clarification 71. Organization of MISO States argues that the Commission erred in paragraph 690 of Order No. 1000–A when it concluded that if a project or group of projects is shown to have benefits in any one of the transmission planning scenarios studied by a public utility transmission provider in its planning process, then the conditions for satisfaction of Cost Allocation Principle 2 will be determined to have been met. It contends that, in response to ITC Companies’ request for clarification, the Commission stated that a ‘‘likely future scenario’’ that would justify an allocation of costs for new transmission facilities includes the transmission planning scenarios being used by a transmission provider to prepare a regional transmission plan.157 155 Id. No. 1000, FERC Stats. & Regs. ¶ 31,323 at PP 622–693. 151 Id. P 588. 152 Id. P 482. 153 Id. P 483. 154 Id. P 637. VerDate Mar<15>2010 methods provide for allocation of the entire prudently incurred cost of a transmission project to prevent stranded costs.155 69. On rehearing, the Commission affirmed Order No. 1000’s adoption of Regional and Interregional Cost Allocation Principle 2. The Commission explained that scenario analysis is a common feature of electric power system planning, and that it believed that public utility transmission providers are in the best position to apply it in a way that achieves appropriate results in their respective transmission planning regions.156 The Commission also found that the use of ‘‘likely future scenarios’’ would not expand the class of customers who would be identified as beneficiaries because it is limited to scenarios in which a beneficiary is identified as such on the basis of the cost causation principle. 70. The Commission clarified that public utility transmission providers may rely on scenario analyses in the preparation of a regional transmission plan and the selection of new transmission facilities for cost allocation purposes. If a project or group of projects is shown to have benefits in one or more of the transmission planning scenarios identified by public utility transmission providers in their Commission-approved Order No. 1000compliant cost allocation methods, Principle 2 would be satisfied. P 640. 156 Id. 157 Organization of MISO States at 2 (quoting Order No. 1000–A, 139 FERC ¶ 61,132 at P 690 (‘‘If a project or group of projects is shown to have benefits in one or more of the transmission planning scenarios identified by public utility transmission providers in their Commission- PO 00000 Frm 00014 Fmt 4700 Sfmt 4700 Organization of MISO States is concerned that the Commission’s clarification reads out of Principle 2 the concept of the likelihood of a future scenario by suggesting that Principle 2 would be satisfied if benefits are shown under any scenario studied by the transmission provider in its planning process.158 Accordingly, Organization of MISO States requests that the Commission clarify that its discussion in paragraph 690 of Order No. 1000–A only applies to likely future scenarios as required by Principle 2. c. Commission Determination 72. We clarify that in finding that Cost Allocation Principle 2 would be satisfied if a project or group of projects is shown to have benefits in one or more of the transmission planning scenarios identified by public utility transmission providers in their Commissionapproved Order No. 1000-compliant cost allocation methods, we did not intend to remove the ‘‘likely future scenarios’’ concept from transmission planning. We believe the evaluation of likely future scenarios can be an important factor in public utility transmission providers’ consideration of transmission projects and in the identification of beneficiaries consistent with the cost causation principle. IV. Information Collection Statement 73. The Office of Management and Budget (OMB) regulations require that OMB approve certain information collection requirements imposed by an agency.159 The revisions in Order Nos. 1000 and 1000–A to the information collection requirements were approved under OMB Control No. 1902–0233. While this order provides clarification, it does not modify any information collection requirements. Accordingly, a copy of this order will be sent to OMB for informational purposes only. V. Document Availability 74. 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 the Commission’s Home Page (http:// www.ferc.gov) and in the Commission’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. 75. From the Commission’s Home Page on the Internet, this information is approved Order No. 1000-compliant cost allocation methods, Principle 2 would be satisfied.’’)). 158 Id. 159 5 CFR 1320.11. E:\FR\FM\24OCR1.SGM 24OCR1 Federal Register / Vol. 77, No. 206 / Wednesday, October 24, 2012 / Rules and Regulations 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. 76. User assistance is available for eLibrary and the Commission’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. VI. Effective Date 77. Changes to Order Nos. 1000 and 1000–A made in this order on rehearing and clarification will be effective on November 23, 2012. 64903 By the Commission. Commissioner LaFleur is dissenting in part with a separate statement. Commissioner Clark is not participating. Nathaniel J. Davis, Sr., Deputy Secretary. Note: The following appendices will not be published in the Code of Federal Regulations. APPENDIX A: ABBREVIATED NAMES OF PETITIONERS Abbreviation Petitioner names AEP ............................................. MISO Transmission Owners Group 2. American Electric Power Service Corporation. The Midwest ISO Transmission Owners for this filing consist of: Ameren Services Company, as agent for Union Electric Company d/b/a Ameren Missouri, Ameren Illinois Company d/b/a Ameren Illinois and Ameren Transmission Company of Illinois; City Water, Light & Power (Springfield, IL); Dairyland Power Cooperative; Great River Energy; Hoosier Energy Rural Electric Cooperative, Inc.; Indianapolis Power & Light Company; MidAmerican Energy Company; Minnesota Power (and its subsidiary Superior Water, L&P); Montana-Dakota Utilities Co.; Northern Indiana Public Service Company; Northern States Power Company, a Minnesota corporation, and Northern States Power Company, a Wisconsin corporation, subsidiaries of Xcel Energy Inc.; Northwestern Wisconsin Electric Company; Otter Tail Power Company; Southern Illinois Power Cooperative; Southern Indiana Gas & Electric Company (d/b/a Vectren Energy Delivery of Indiana); Southern Minnesota Municipal Power Agency; and Wolverine Power Supply Cooperative, Inc. Oklahoma Gas and Electric Company. Oklahoma Gas and Electric Company. Organization of MISO States ...... Transmission Access Study Group. Policy Illinois Commerce Commission; Indiana Utility Regulatory Commission; Iowa Utilities Board; Kentucky Public Service Commission; Michigan Public Service Commission; Minnesota Public Utilities Commission; Missouri Public Service Commission; Wisconsin Public Service Commission; and Montana Public Service Commission. Transmission Access Policy Study Group. TKELLEY on DSK3SPTVN1PROD with RULES LaFLEUR, Commissioner, dissenting in part: As part of today’s order, the Commission affirms its holding in Order No. 1000–A that an incumbent transmission provider may not retain a federal right of first refusal (ROFR) for a new transmission project—even a local reliability project—if that project receives any amount of regional funding.1 After further consideration, I believe this decision is premature and denies transmissionplanning regions the flexibility to define local projects. I am now persuaded that the Commission should have deferred judgment on this issue until compliance, where it could have evaluated—on a case-by casebasis—proposals to define local projects in light of the principles underlying elimination of the ROFR and the requirement that costs must be allocated in a manner that is at least roughly commensurate with benefits. Because I would grant rehearing on this point, and defer the issue to compliance, I respectfully dissent in part from today’s order. In Order No. 1000, the Commission eliminated the ROFR for projects ‘‘selected in a regional transmission plan for purposes of cost allocation’’ but allowed it to continue for 1 Transmission Planning and Cost Allocation by Transmission Owning and Operating Public Utilities, Order No. 1000, 76 FR 49842 (Aug. 11, 2011), FERC Stats. & Regs. ¶ 31,323 (2011), order on reh’g, Order No. 1000–A, 77 FR 32184 (May 31, 2012), 139 FERC ¶ 61,132 at P 430 (2012). VerDate Mar<15>2010 17:17 Oct 23, 2012 Jkt 229001 local projects.2 In response, certain petitioners requested guidance as to whether the requirement to remove the ROFR for projects ‘‘selected in a regional transmission plan for purposes of cost allocation’’ required eliminating it in two specific situations: First, when costs are allocated only to multiple transmission providers within a single, local zone; and second, when local reliability projects receive some amount of regional funding as part of a cost allocation methodology.3 In essence, petitioners requested clarification as to whether these specific cost allocation mechanisms converted otherwise local reliability projects to regional projects for purposes of eliminating the ROFR. With respect to the question about zones, in Order No. 1000–A the Commission acknowledged that ‘‘there may be a continuum of examples’’ that require fact specific determinations.4 Rather than lay down a categorical rule, the Commission opted for flexibility and invited parties to raise their specific situations on compliance.5 Today’s order affirms this approach. 2 Order No. 1000, FERC Stats. & Regs. ¶ 31,323 at PP 313, 318; see also P 63 (defining local projects). 3 Order No. 1000–A, 139 FERC ¶ 61,132 at PP 409–410; see also n. 495 (examples of cost allocation methodologies reflecting distinctions between regional and local projects that were previously approved by the Commission.). 4 Id. P 424. 5 Id. PO 00000 Frm 00015 Fmt 4700 Sfmt 4700 In contrast, in Order 1000–A the Commission did reach a definitive conclusion with respect to whether any amount of regional funding converts an otherwise local reliability project in to a regional project for purposes of the ROFR. The Commission clarified, without explanation,6 that the ROFR must be eliminated if a project receives any amount of regional funding.7 As a result, a local reliability project that receives any amount of regional funding, no matter how small, is no longer local for purposes of the ROFR. Today’s order summarily affirms this decision. After further consideration, I believe the Commission acted prematurely in concluding that any amount of regional funding converts an otherwise local reliability project to a regional project for purposes of the ROFR. By reaching this conclusion in the abstract, without the benefit of considering stakeholder-vetted proposals to define local projects in light of the principles underlying elimination of the ROFR and the requirement that costs must be allocated in a manner that is at least roughly commensurate with 6 For example, the Commission did not explain, in light of its distinction in Order No, 1000 between projects in a regional plan and projects ‘‘selected in a regional transmission plan for purposes of cost allocation,’’ why eliminating the ROFR for projects ‘‘selected in a regional transmission plan for purposes of cost allocation’’ requires eliminating it for local projects that are primarily locally funded. 7 Id. P 430. E:\FR\FM\24OCR1.SGM 24OCR1 64904 Federal Register / Vol. 77, No. 206 / Wednesday, October 24, 2012 / Rules and Regulations benefits, the Commission has denied transmission planning regions the flexibility it wisely acknowledged to be necessary with respect to the zone issue. I agree with SPP and OGE that we should provide that flexibility.8 In Order No. 1000, the Commission balanced many competing policy considerations in an effort to adopt the reforms necessary to assure just and reasonable rates.9 This balance may be most pronounced in the Commission’s efforts to ensure that the regional planning process is broad, inclusive, and fair, while at the same time, mindful of the obligations and attributes of incumbent transmission providers. The Commission also went to great lengths to provide transmissionplanning regions with the flexibility to negotiate cost allocation methodologies that allocate costs in a manner that they believe is at least roughly commensurate with benefits. Where the mutual achievement of these objectives raises complex questions, as it does with respect to whether any amount of regional funding converts an otherwise local reliability project in to a regional project for purposes of the ROFR, the Commission should decide the issue on compliance, with a record, rather than by establishing categorical rules that may undermine the planning and cost allocation goals Order No. 1000 was intended to achieve.10 Accordingly, I respectfully dissent in part. lllllllllllllllllllll Cheryl A. LaFleur, Commissioner. [FR Doc. 2012–26111 Filed 10–23–12; 8:45 am] TKELLEY on DSK3SPTVN1PROD with RULES BILLING CODE 6717–01–P 8 In its request for clarification of Order 1000–A, SPP seeks guidance on how to reconcile the definitions and principles underlying Order No. 1000 with the Commission’s summary determination in Order No. 1000–A that any amount of regional funding for local reliability projects requires elimination of the ROFR. See SPP Request for Clarification at 7–16. Unlike my colleagues, I believe that SPP’s filing may properly be characterized as a request for clarification, and therefore, should be addressed in this order. However, I would not reach the merits of SPP’s arguments. Instead, I would grant rehearing on the grounds that the Commission should have deferred deciding the issue until compliance and invite SPP to make its arguments on compliance. 9 Order 1000–B at P 55. 10 See e.g. OGE Request for Rehearing at 6 (‘‘[T]he broad definition of what constitutes regional cost allocation would prohibit regional entities such as SPP from adopting approaches they believe would effectively allocate costs and fairly balance stakeholder interests.’’). VerDate Mar<15>2010 17:17 Oct 23, 2012 Jkt 229001 DEPARTMENT OF HOMELAND SECURITY Coast Guard 33 CFR Part 165 [Docket Number USCG–2012–0741] A. Regulatory History and Information On August 21, 2012, the Coast Guard published a Notice of Proposed Rulemaking (NPRM) (33 FR 50444). We received no comments on the proposed rule. No public meeting was requested, and none was held. B. Basis and Purpose RIN 1625–AA00 Safety Zone, Atlantic Intracoastal Waterway; Carolina Beach, NC Coast Guard, DHS. Temporary final rule. AGENCY: ACTION: The Coast Guard is establishing a temporary safety zone on the waters of the Atlantic Intracoastal Waterway at Carolina Beach, North Carolina. The safety zone is necessary to provide for the safety of mariners on navigable waters during maintenance on the U.S. 421 Fixed Bridge crossing the Atlantic Intracoastal Waterway, mile 295.6, at Carolina Beach, North Carolina. The safety zone will temporarily restrict vessel movement within the designated area starting on December 20, 2012, through October 31, 2013. DATES: This rule is effective from December 20, 2012, until October 31, 2013. SUMMARY: Documents mentioned in this preamble are part of docket [USCG– 2012–0741]. To view documents mentioned in this preamble as being available in the docket, go to http:// www.regulations.gov, type the docket number in the ‘‘SEARCH’’ box and click ‘‘SEARCH.’’ Click on Open Docket Folder on the line associated with this rulemaking. You may also visit the Docket Management Facility in Room W12–140 on the ground floor of the Department of Transportation West Building, 1200 New Jersey Avenue SE., Washington, DC 20590, between 9 a.m. and 5 p.m., Monday through Friday, except Federal holidays. FOR FURTHER INFORMATION CONTACT: If you have questions on this rule, call or email CWO4 Joseph M. Edge, U.S. Coast Guard Sector North Carolina; telephone 252–247–4525, email Joseph.M.Edge@uscg.mil. If you have questions on viewing or submitting material to the docket, call Renee V. Wright, Program Manager, Docket Operations, telephone (202) 366–9826. SUPPLEMENTARY INFORMATION: ADDRESSES: Table of Acronyms DHS Department of Homeland Security FR Federal Register NPRM Notice of Proposed Rulemaking PO 00000 Frm 00016 Fmt 4700 Sfmt 4700 North Carolina Department of Transportation has awarded a contract to American Bridge Company of Virginia Beach, Virginia to perform bridge maintenance on the U.S. 421 Fixed Bridge crossing the Atlantic Intracoastal Waterway, mile 295.6, at Carolina Beach, North Carolina. The contract provides for cleaning, painting, and steel repair to commence on December 20, 2012 with a completion date of October 31, 2013. The contractor will utilize a 40 foot by 60 foot sectional barge as a work platform and for equipment staging. This safety zone will provide a safety buffer to transiting vessels as bridge repairs present potential hazards to mariners and property due to reduction horizontal clearance. During this period the Coast Guard will require a one hour notification to the work supervisor for passage through the U.S. 421 Fixed Bridge along the Atlantic Intracoastal Waterway, mile 295.6, Carolina Beach, North Carolina. The bridge notification requirement will apply during the maintenance period for vessels requiring a horizontal clearance of greater than 60 feet. C. Discussion of Comments, Changes and the Final Rule We received no comments on the proposed rule. No public meeting was requested, and none was held. The temporary safety zone will encompass the waters directly under the U.S. 421 Fixed Bridge crossing the Atlantic Intracoastal Waterway, mile 295.6, at Carolina Beach, North Carolina (34°03′21″ N, 077°53′58″ W). All vessels transiting this section of the waterway requiring a horizontal clearance of greater than 60 feet will be required to make a one hour advanced notification to the work supervisor while the safety zone is in effect. This zone will be in effect from 8 a.m. December 20, 2012 through 8 p.m. October 31, 2013. D. Regulatory Analyses We developed this rule after considering numerous statutes and executive orders related to rulemaking. Below we summarize our analyses based on these statutes and executive orders. E:\FR\FM\24OCR1.SGM 24OCR1

Agencies

[Federal Register Volume 77, Number 206 (Wednesday, October 24, 2012)]
[Rules and Regulations]
[Pages 64890-64904]
From the Federal Register Online via the Government Printing Office [www.gpo.gov]
[FR Doc No: 2012-26111]


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DEPARTMENT OF ENERGY

Federal Energy Regulatory Commission

18 CFR Part 35

[Docket No. RM10-23-002; Order No. 1000-B]


Transmission Planning and Cost Allocation by Transmission Owning 
and Operating Public Utilities

AGENCY: Federal Energy Regulatory Commission, DOE.

ACTION: Order on rehearing and clarification.

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SUMMARY: The Federal Energy Regulatory Commission affirms its basic 
determinations in Order Nos. 1000 and 1000-A, amending the transmission 
planning and cost allocation requirements established in Order No. 890 
to ensure that Commission-jurisdictional services are provided at just 
and reasonable rates and on a basis that is just and reasonable and not 
unduly discriminatory or preferential. This order affirms the Order No. 
1000 transmission planning reforms that: Require that each public 
utility transmission provider participate in a regional transmission 
planning process that produces a regional transmission plan; provide 
that local and regional transmission planning processes must provide an 
opportunity to identify and evaluate transmission needs driven by 
public policy requirements established by state or federal laws or 
regulations; improve coordination between neighboring transmission 
planning regions for new interregional transmission facilities; and 
remove from Commission-approved tariffs and agreements a federal right 
of first refusal. This order also affirms the Order No. 1000 
requirements that each public utility transmission provider must 
participate in a regional transmission planning process that has: A 
regional cost allocation method for the cost of new transmission 
facilities selected in a regional transmission plan for purposes of 
cost allocation and an interregional cost allocation method for the 
cost of new transmission facilities that are located in two neighboring 
transmission planning regions and are jointly evaluated by the two 
regions in the interregional transmission coordination process required 
by this Final Rule. Additionally, this order affirms the Order No. 1000 
requirement that each cost allocation method must satisfy six cost 
allocation principles.

DATES: Effective November 23, 2012.

FOR FURTHER INFORMATION CONTACT: 

Melissa Nimit, Federal Energy Regulatory Commission, Office of the 
General Counsel, 888 First Street NE., Washington, DC 20426, (202) 502-
6638.
Shiv Mani, Federal Energy Regulatory Commission, Office of Energy 
Policy and Innovation, 888 First Street NE., Washington, DC 20426, 
(202) 502-8240.

SUPPLEMENTARY INFORMATION: 

Before Commissioners: Jon Wellinghoff, Chairman; Philip D. Moeller, 
John R. Norris, and Cheryl A. LaFleur.
Issued October 18, 2012

Table of Contents

 
                                                               Paragraph
                                                                  No.
 
I. Introduction.............................................           1
II. Transmission Planning...................................           5
    A. Regional Transmission Planning.......................           5
        1. Role of Section 217(b)(4) of the Federal Power              6
         Act................................................
        2. Regional Transmission Planning Requirements......          12
        3. Consideration of Transmission Needs Driven by              28
         Public Policy Requirements.........................
    B. Nonincumbent Transmission Developers.................          32
        1. Legal Authority..................................          33
        2. Requirement To Remove a Federal Right of First             41
         Refusal from Commission-Jurisdictional Tariffs and
         Agreements, and Limits on the Applicability of That
         Requirement........................................
        3. Framework To Evaluate Transmission Projects                56
         Submitted for Selection in the Regional
         Transmission Plan for Purposes of Cost Allocation..
    C. Interregional Transmission Coordination..............          60
        1. Implementation of the Interregional Transmission           61
         Coordination Requirements..........................
III. Cost Allocation........................................          65
    1. Cost Allocation Principle 2--No Involuntary                    67
     Allocation of Costs to Non-beneficiaries...............
IV. Information Collection Statement........................          73
V. Document Availability....................................          74

[[Page 64891]]

 
VI. Effective Date..........................................          77
Appendix A: Abbreviated Names of Petitioners                  ..........
 

I. Introduction

    1. In Order No. 1000,\1\ the Commission amended the transmission 
planning and cost allocation requirements established in Order No. 890 
\2\ to ensure that the rates, terms and conditions of service provided 
by public utility providers are just and reasonable and not unduly 
discriminatory or preferential. Order No. 1000's transmission planning 
reforms require: (1) Each public utility transmission provider to 
participate in a regional transmission planning process that produces a 
regional transmission plan; (2) that local and regional transmission 
planning processes must provide an opportunity to identify and evaluate 
transmission needs driven by public policy requirements established by 
state or federal laws or regulations; (3) improved coordination between 
neighboring transmission planning regions for new interregional 
transmission facilities; and (4) the removal from Commission-approved 
tariffs and agreements of a federal right of first refusal.
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    \1\ Transmission Planning and Cost Allocation by Transmission 
Owning and Operating Public Utilities, Order No. 1000, 76 FR 49842 
(Aug. 11, 2011), FERC Stats. & Regs. ] 31,323 (2011), order on 
reh'g, Order No. 1000-A, 139 FERC ] 61,132 (2012).
    \2\ Preventing Undue Discrimination and Preference in 
Transmission Service, Order No. 890, 72 FR 12266 (Mar. 15, 2007), 
FERC Stats. & Regs. ] 31,241, order on reh'g, Order No. 890-A, 73 FR 
2984 (Jan. 16, 2008), FERC Stats. & Regs. ] 31,261 (2007), order on 
reh'g and clarification, Order No. 890-B, 73 FR 39092 (July 8, 
2008), 123 FERC ] 61,299 (2008), order on reh'g, Order No. 890-C, 74 
FR 12540 (Mar. 25, 2009), 126 FERC ] 61,228 (2009), order on 
clarification, Order No. 890-D, 74 FR 61511 (Nov. 25 2009), 129 FERC 
] 61,126 (2009).
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    2. Order No. 1000 also requires that each public utility 
transmission provider must participate in a regional transmission 
planning process that has: (1) A regional cost allocation method for 
the cost of new transmission facilities selected in a regional 
transmission plan for purposes of cost allocation and (2) an 
interregional cost allocation method for the cost of new transmission 
facilities that are located in two neighboring transmission planning 
regions and are jointly evaluated by the two regions in the 
interregional transmission coordination process required by this Final 
Rule. Order No. 1000 also requires that each cost allocation method 
must satisfy six cost allocation principles.
    3. In Order No. 1000-A, the Commission largely affirmed the reforms 
adopted in Order No. 1000. The Commission concluded that taken 
together, the reforms adopted in Order No. 1000 will ensure that 
Commission-jurisdictional services are provided at just and reasonable 
rates and on a basis that is just and reasonable and not unduly 
discriminatory or preferential. The Commission therefore rejected 
requests to eliminate, or substantially modify, the various reforms 
adopted in Order No. 1000. The Commission did however, make a number of 
clarifications.
    4. Several petitioners have sought further rehearing and 
clarification of the Commission's determinations in Order No. 1000-
A.\3\ The Commission largely affirms the determinations reached in 
Order No. 1000-A, making clarifications to address matters raised by 
petitioners.
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    \3\ A list of petitioners filing requests for rehearing and/or 
clarification is provided in Appendix A. Southwest Power Pool (SPP) 
filed a request for clarification and/or reconsideration of Order 
No. 1000-A. While SPP denominates its pleading as a request for 
clarification, it is, in fact, a late-filed request for rehearing. 
Pursuant to section 313(a) of the Federal Power Act (FPA), 16 U.S.C. 
825l(a) (2006), an aggrieved party must file a request for rehearing 
within thirty days after the issuance of the Commission's order. 
Because the 30-day rehearing deadline is statutory, it cannot be 
extended, and SPP's request for rehearing must be rejected as 
untimely. Moreover, the courts have repeatedly recognized that the 
time period within which a party may file an application for 
rehearing of a Commission order is statutorily established at 30 
days by section 313(a) of the FPA and that the Commission has no 
discretion to extend that deadline. See, e.g., City of Campbell v. 
FERC, 770 F.2d 1180, 1183 (D.C. Cir. 1985); Boston Gas Co. v. FERC, 
575 F.2d 975, 977-79 (1st Cir. 1978). Furthermore, we note that the 
issues raised by SPP are similar to those raised by other 
petitioners, which are summarized and addressed below in section 
II.B.2 of this order.
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II. Transmission Planning

A. Regional Transmission Planning

    5. Order No. 1000 built on the reforms adopted in Order No. 890 to 
improve regional transmission planning. First, Order No. 1000 required 
each public utility transmission provider to participate in a regional 
transmission planning process that produces a regional transmission 
plan and complies with existing Order No. 890 transmission planning 
principles.\4\ Second, Order No. 1000 adopted reforms under which 
transmission needs driven by Public Policy Requirements are considered 
in local and regional transmission planning processes.\5\ The 
Commission explained that these reforms work together to ensure that 
public utility transmission providers in every transmission planning 
region, in consultation with stakeholders, evaluate proposed 
alternative solutions at the regional level that may resolve the 
region's needs more efficiently or cost-effectively than solutions 
identified in the local transmission plans of individual public utility 
transmission providers.\6\ The Commission noted that, as in Order No. 
890, the transmission planning requirements in Order No. 1000 do not 
address or dictate which transmission facilities should be either in 
the regional transmission plan or actually constructed, and that such 
decisions are left in the first instance to the judgment of public 
utility transmission providers, in consultation with stakeholders 
participating in the regional transmission planning process.\7\
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    \4\ Order No. 1000, FERC Stats. & Regs. ] 31,323 at P 68.
    \5\ Id. The Commission explained that Public Policy Requirements 
are those established by state or federal laws or regulations, 
meaning enacted statutes (i.e., passed by the legislature and signed 
by the executive) and regulations promulgated by a relevant 
jurisdiction, whether within a state or at the federal level. Id. P 
2. Order No. 1000-A clarified that this included transmission needs 
driven by local laws or regulations. Order No. 1000-A, 139 FERC ] 
61,132 at P 319.
    \6\ Id.
    \7\ Id. P 68 n.57.
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1. Role of Section 217(b)(4) of the Federal Power Act
a. Order No. 1000-A
    6. In Order No. 1000-A, the Commission affirmed Order No. 1000's 
conclusion that the Commission has ample legal authority under the 
Federal Power Act (FPA) to undertake its regional transmission planning 
reforms. Among other things, Order No. 1000-A rejected arguments that 
FPA section 217(b)(4) \8\ prohibits or otherwise limits the 
Commission's ability to undertake these reforms.\9\ Order No. 1000-A
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    \8\ 16 U.S.C. 824s (2006).
    \9\ Order No. 1000-A, 139 FERC ] 61,132 at PP 168-179.

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[[Page 64892]]

acknowledged claims by some petitioners that Order No. 681,\10\ which 
requires transmission organizations that are public utilities with 
organized electricity markets to make available long-term firm 
transmission rights that satisfy certain guidelines, expressly notes a 
preference for load-serving entities.\11\ Order No. 1000-A found that 
Order No. 681's priority for load-serving entities in the allocation of 
long-term firm transmission rights supported by existing transmission 
capacity is not inconsistent with Order No. 1000, which addresses 
planning and cost allocation for new transmission.\12\ Order No. 1000-A 
also found that the transmission planning reforms will aid, and not 
hinder, load-serving entities in meeting their reasonable transmission 
needs.\13\
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    \10\ Long-Term Firm Transmission Rights in Organized Electricity 
Markets, Order No. 681, FERC Stats. & Regs. ] 31,226, order on 
reh'g, Order No. 681-A, 117 FERC ] 61,201 (2006), order on reh'g, 
Order No. 681-B, 126 FERC ] 61,254 (2009).
    \11\ Order No. 1000-A, 139 FERC ] 61,132 at P 171.
    \12\ Id. P 172.
    \13\ Id.
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b. Request for Rehearing
    7. Transmission Access Policy Study Group argues that in Order No. 
1000-A, the Commission suggested for the first time that the preference 
for load-serving entity long-term rights established in Order No. 681 
applies only to existing transmission capacity ``but not in the broader 
context of planning new transmission capacity.'' \14\ Transmission 
Access Policy Study Group contends that the Commission erred in 
suggesting that Order No. 681 does not apply to new transmission 
facilities, contending that Order No. 681 extended the preference to be 
afforded load-serving entities to long-term rights from existing 
capacity to new capacity by providing that ``[w]hen * * * transmission 
upgrades [that are rolled into transmission rates] come into service, 
the transmission rights that result from such investments will be made 
available as rights from `existing capacity.' '' \15\ Transmission 
Access Policy Study Group states that this provision had one limited 
exception--where a transmission upgrade is participant-funded.\16\ It 
contends that this exception is inapplicable to the new transmission 
facilities at issue in this proceeding, as Order No. 1000 specifically 
ruled that participant funding will not comply with the regional or 
interregional cost allocation principles adopted by the Final Rule.\17\ 
Transmission Access Policy Study Group urges the Commission to clarify 
that Order Nos. 1000 and 1000-A do not alter the scope or applicability 
of Order No. 681.\18\ In the alternative, it argues that Order No. 1000 
should be reversed to the extent that it modifies the load-serving 
entity long-term rights preference established by Order No. 681, by 
limiting that preference to ``existing'' transmission facilities, 
rather than extending it to new transmission that is not participant-
funded.\19\
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    \14\ Transmission Access Policy Study Group at 12 (quoting Order 
No. 1000-A, 139 FERC ] 61,132 at P 171).
    \15\ Id. at 13 (quoting Order No. 681, FERC Stats. & Regs. ] 
31,226 at P 211 (emphasis added)).
    \16\ Id.
    \17\ Id.
    \18\ Id.
    \19\ Id.
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c. Commission Determination
    8. In response to Transmission Access Policy Study Group, we 
clarify that nothing in either Order No. 1000 or Order No. 1000-A is 
intended in any way to undermine or alter the guidelines the Commission 
instituted in Order No. 681. Order No. 1000's transmission planning 
reforms are distinct from the Commission's rulemaking in Order No. 681, 
as we explain below.
    9. Section 1233(a) of the Energy Policy Act of 2005 enacted FPA 
section 217(b)(4), in which the Commission is directed to exercise its 
authority under the FPA in a manner that facilitates the planning and 
expansion of transmission facilities to meet the reasonable needs of 
load-serving entities to satisfy the service obligations of the load-
serving entities, and enables load-serving entities to secure firm 
transmission rights (or equivalent tradable or financial rights) on a 
long-term basis for long-term power supply arrangements made, or 
planned, to meet such needs.\20\
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    \20\ 16 U.S.C. 824q(b)(4) (2006).
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    10. Section 1233(b) of the Energy Policy Act of 2005 further 
directed the Commission to promulgate a rule on long-term transmission 
rights in organized markets.\21\ The Commission consequently issued 
Order No. 681, which adopted guidelines that independent system 
operators (ISOs) and regional transmission organizations (RTOs) are 
required to follow regarding the availability of long-term firm 
transmission rights, including a guideline providing that load-serving 
entities ``must have a priority over non-load serving entities in the 
allocation of long-term firm transmission rights that are supported by 
existing capacity.'' \22\
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    \21\ EPAct 2005, Public Law 109-58, section 1233, 119 Stat. 594, 
960 (2005); 16 U.S.C. 824q (2006)). Section 1233 provides that 
within 1 year after the date of enactment of that section and after 
notice and an opportunity for comment, the Commission shall by rule 
or order, implement section 217(b)(4) of the Federal Power Act in 
Transmission Organizations, as defined by that Act with organized 
electricity markets.
    \22\ Order No. 681, FERC Stats. & Regs. ] 31,226 at P 325.
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    11. As Order No. 1000-A explained, we do not find any inconsistency 
between Order No. 1000 and section 217(b)(4).\23\ Nor do we find any 
inconsistency between Order No. 1000 and Order No. 681. The 
requirements adopted by the Commission in Order Nos. 1000 and 1000-A 
are focused on the planning and cost allocation of new transmission 
facilities, as defined therein. The Commission did not intend its 
statements in Order No. 1000-A regarding the planning and cost 
allocation of certain new transmission facilities to alter the 
requirement in Order No. 681 that ``when [transmission upgrades that 
are rolled into transmission rates] * * * come into service, the 
transmission rights that result from such investments will be made 
available as rights from `existing capacity' * * * . Prevailing cost 
allocation rules will apply.'' \24\ Thus, we clarify for Transmission 
Access Policy Study Group that nothing in Order Nos. 1000 or 1000-A 
changes the requirements of Order No. 681, including the Order No. 681 
established preference for load-serving entities in the allocation of 
long-term firm transmission rights, and that the Commission did not 
alter the application of Order No. 681 to new transmission facilities 
that are subject to the requirements of Order No. 1000.
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    \23\ See Order No. 1000-A, 139 FERC ] 61,132 at PP 168-179 
(addressing requests for rehearing and clarification of Order No. 
1000 with respect to the role of section 217(b)(4)).
    \24\ See Order No. 681, FERC Stats. & Regs. ] 31,226 at P 211.
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2. Regional Transmission Planning Requirements
a. Order No. 1000-A
    12. Order No. 1000-A affirmed Order No. 1000's conclusion that 
public utility transmission providers must revise their OATTs to 
provide for a regional transmission planning process that produces a 
regional transmission plan and satisfies Order No. 890's transmission 
planning principles.\25\ The Commission explained that Order No. 1000 
requires neither the filing of the regional transmission plan resulting 
from the regional transmission planning process nor the filing of 
specific applications of cost allocation determinations.\26\ With 
respect to this latter point, Order No. 1000-A stated

[[Page 64893]]

that such a requirement would be unnecessary to comply with Order No. 
1000, noting that Order No. 1000 requires that public utility 
transmission providers have an ex ante cost allocation method on file 
with and approved by the Commission. Order No. 1000-A also noted that 
this cost allocation method must explain how the costs of new 
transmission facilities selected in a regional transmission plan for 
purposes of cost allocation are to be allocated, consistent with the 
cost allocation principles set forth in Order No. 1000.\27\ 
Consequently, customers, stakeholders, and others will have ``notice'' 
at the time the compliance filings are made, when the Commission acts 
on those filings, and as the regional transmission planning process 
results in the selection of a transmission facility in the regional 
transmission plan for purposes of cost allocation.\28\ However, 
consistent with the regional flexibility provided in Order No. 1000, 
Order No. 1000-A also concluded that public utility transmission 
providers, in consultation with stakeholders, may propose OATT 
revisions requiring the submission of cost allocations in their Order 
No. 1000 compliance filings.\29\
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    \25\ Order No. 1000-A, 139 FERC ] 61,132 at PP 263-301.
    \26\ Id. PP 285-286.
    \27\ Id. P 286.
    \28\ Id.
    \29\ Id.
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    13. The Commission further stated in Order No. 1000-A that it will 
evaluate compliance filings to ensure that they comply with Order No. 
1000 and that both stakeholders and the Commission have the right to 
initiate actions under section 206 of the FPA if they believe that, for 
example, a Commission-approved regional transmission planning process 
was not followed or if a cost allocation method was not followed or 
produced unjust and unreasonable results for a particular new 
transmission facility or class of new transmission facilities.\30\
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    \30\ Id. P 287.
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b. Request for Rehearing
    14. Transmission Access Policy Study Group argues that the 
Commission should not establish a generic rule that, if transmission 
providers elect not to propose a section 205 filing of specific 
applications of their regional cost allocation, the only means to 
challenge such applications is under section 206.\31\ It states that 
although Order No. 1000-A nowhere uses the term ``formula rate'' to 
describe the rule's treatment of regional cost allocation 
methodologies, it is creating a filing regimen where the cost 
allocation methodologies will function as just that.\32\
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    \31\ Transmission Access Policy Study Group at 3.
    \32\ Id. at 4.
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    15. Therefore, Transmission Access Policy Study Group contends that 
the Commission should require the section 205 filing of project-
specific applications of the regional cost allocation methodology, or 
leave it to the compliance filing process to determine whether such a 
filing is required.\33\ If cost allocation methods are treated as 
formula rates, Transmission Access Policy Study Group maintains that 
the Commission can have no reasonable assurance that cost allocation 
methodologies will be sufficiently specific, grounded in objective 
criteria, and otherwise adequately constrain utility discretion.\34\ It 
further asserts that regional cost allocation methodologies, in 
combination with the process for selecting projects for regional cost 
allocation, will likely rely on assumptions and other judgments that 
undermine predictability.\35\
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    \33\ Id. at 5.
    \34\ Id. at 6.
    \35\ Id. at 7.
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    16. Transmission Access Policy Study Group argues that sole 
reliance on section 206 to challenge specific implementation of a 
Commission-accepted Order No. 1000 methodology when the transmission 
provider has not made a section 205 filing is unjustified.\36\ It 
contends that in the non-RTO context, application of the cost 
allocation methodology leaves ample room for transmission providers to 
engage in undue discrimination, and the Commission cannot reasonably 
assume that the cost allocation methodology, by itself, will in all 
cases provide customers with ``notice'' as to how regional facilities 
will be selected, and their costs allocated, in the future.\37\ It also 
contends that transmission providers have the enhanced ability to 
discriminate, particularly where a cost allocation methodology is 
unlikely to have the specificity and objectivity to cabin the 
transmission provider's discretion, and where stakeholders only may 
have the opportunity to provide input that the transmission providers 
are free to ignore.\38\ It argues that, in these cases in particular, 
treating the cost allocation methodology as a formula rate improperly 
shifts the burdens imposed by section 205.\39\
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    \36\ Id.
    \37\ Id. at 7-8.
    \38\ Id. at 8.
    \39\ Id.
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    17. Transmission Access Policy Study Group argues that, at minimum, 
the Commission should defer making a generic finding now that section 
206 is the only available recourse to challenge specific applications 
of regional cost allocation methodologies absent transmission providers 
electing to propose section 205 filings of those specific 
applications.\40\ Instead, it suggests that the Commission should leave 
for determination on a case-by-case basis the process of evaluating 
Order No. 1000 compliance filings, in response to requests by 
transmission providers or other stakeholders or on its own motion, 
whether in a particular region the filing of specific applications of 
the regional cost allocations is necessary.\41\ It maintains that 
deferral will enable the Commission to consider the specifics of the 
proposed regional cost allocation methodology in conjunction with the 
proposed project selection process and associated governance and other 
safeguards (if any), as well as the views of public utility 
transmission providers in that region and other stakeholders.\42\
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    \40\ Id. at 9.
    \41\ Id.
    \42\ Id. at 10.
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c. Commission Determination
    18. We deny rehearing. Transmission Access Policy Study Group has 
not persuaded us that the determination not to require the filing of 
specific applications of the cost allocation method was in error. Order 
No. 1000's reforms are intended, in part, to establish an open and 
transparent transmission planning process and require transmission 
planning regions to adopt a cost allocation method or methods that 
provide ex ante certainty. Both the Order No. 1000 compliance process 
and the resulting Commission-approved regional transmission planning 
process and associated cost allocation method(s) are required to have 
built-in mechanisms to help ensure that the processes and cost 
allocation methods are in fact transparent and provide the certainty 
that Transmission Access Policy Study Group seeks.
    19. First, stakeholders have had the opportunity to participate 
fully in regional stakeholder meetings to advocate for a cost 
allocation method that provides the ex ante certainty that Order No. 
1000 seeks, as well as to advocate that public utility transmission 
providers include a provision requiring the filing of specific 
applications of the cost allocation method. We believe that this 
approach accords with the regional flexibility we provided in Order No. 
1000 for public utility transmission

[[Page 64894]]

providers and stakeholders in a transmission planning region to develop 
rules that meet the transmission needs of that region, consistent with 
the requirements and principles set forth in Order Nos. 1000 and 1000-
A.
    20. Second, the Commission will carefully consider the Order No. 
1000 compliance filings once they are submitted, as well as any 
protests filed by stakeholders, to ensure that proposals satisfy the 
requirements that regional transmission planning processes be open and 
transparent and that the cost allocation method or methods satisfy the 
Order No. 1000 cost allocation principles. If a filing is deficient, 
the Commission will require public utility transmission providers to 
file revisions to address those deficiencies.
    21. Third, once the regional transmission planning process is 
approved by the Commission and becomes effective, the Order No. 890 
transmission planning principles, as incorporated into a regional 
transmission planning process in compliance with Order No. 1000, will 
help mitigate concerns about the transparency of the process and the 
application of the cost allocation method. These principles address, 
among other things, stakeholder participation, information exchange, 
and dispute resolution.\43\ By incorporating these principles into the 
regional transmission planning process, the Commission's expectation is 
that there will be increased openness and certainty concerning how 
beneficiaries of transmission facilities selected in the regional 
transmission plan for purposes of cost allocation will be determined, 
as well as internal processes to resolve any questions that might arise 
as part of this process. And as noted in Order No. 1000-A, in 
identifying the benefits and beneficiaries for a new transmission 
facility, the regional transmission planning process must provide 
entities who will receive regional or interregional cost allocation an 
understanding of the identified benefits on which the cost allocation 
is based, all of which would occur prior to the recovery of such costs 
through a formula rate.\44\
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    \43\ Order No. 890 requires transmission providers to disclose 
to all customers and other stakeholders the basic criteria, 
assumptions, and data that underlie their transmission system plans. 
In addition, transmission providers will be required to reduce to 
writing and make available the basic methodology, criteria, and 
processes they use to develop their transmission plans, including 
how they treat retail native loads, in order to ensure that 
standards are consistently applied. Preventing Under Discrimination 
and Preference in Transmission Service, Order No. 890, FERC Stats. & 
Regs. ] 31,241 at P 471 (2007).
    \44\ Order No. 1000-A, 139 FERC ] 61,132 at P 746.
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    22. Moreover, as we explained in Order No. 1000-A, stakeholders 
always have the option of filing a section 206 complaint if they 
believe that, notwithstanding these protections, there was an incorrect 
application of the cost allocation method in a particular instance.\45\ 
Finally, if stakeholders believe that the previously approved cost 
allocation method itself is no longer just and reasonable, they also 
have the option of filing a section 206 complaint with respect to the 
cost allocation method.
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    \45\ Id. P 231.
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    23. Transmission Access Policy Study Group suggests that 
application of the ex ante cost allocation to, or in, particular 
instance(s) should require a section 205 filing with the Commission. 
Order No. 1000 establishes no new requirement with respect to this 
issue. As we note above, Order No. 1000-A stated that we would consider 
proposals that would require public utility transmission providers to 
file specific applications of the cost allocation method. Therefore, 
Order No. 1000 provides flexibility in this regard and the Commission 
stated that it will not prejudge any method before the compliance 
filings are filed, so long as they satisfied the cost allocation 
principles articulated in Order No. 1000 (with the exception that 
participant funding may not be the regional or interregional cost 
allocation method). We will carefully evaluate compliance filings to 
ensure that they satisfy these principles.
    24. Transmission Access Policy Study Group asserts that if the cost 
allocation method is thought of as a formula rate, it would improperly 
shift the burdens under section 205 of the FPA, especially where a cost 
allocation method is unlikely to have specificity or objectivity to 
cabin transmission providers' discretion and where they can ignore 
stakeholder input. We disagree with this argument. As we discuss above, 
Order No. 1000 provides for ex ante certainty. In Order No. 1000, the 
Commission stated that it required the development of regional and 
interregional cost allocation methods to provide greater certainty as 
to the cost allocation implications of a potential transmission 
project.\46\ The Commission also stated that under the regional 
transmission planning and interregional transmission coordination 
requirements, public utility transmission providers with stakeholders 
will identify, evaluate, and determine which transmission facilities 
meet the region's needs, and apply the cost allocation method or 
methods associated with those transmission facilities.\47\ In Order No. 
1000-A, the Commission clarified that public utility transmission 
providers must consult with stakeholders in developing both regional 
and interregional cost allocation methods.\48\ Therefore, the 
Commission specifically requires public utility transmission providers 
to provide the opportunity for stakeholder input in the development of 
the regional and interregional cost allocation methods. If a 
stakeholder believes that its input is being ignored, it has the right 
to raise its issues with the cost allocation method or methods when the 
relevant Order No. 1000 compliance filing is made, or in a separate 
section 206 filing.
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    \46\ Order No. 1000, FERC Stats. & Regs. ] 31,323 at PP 559, 
579.
    \47\ Id. P 499.
    \48\ Id. PP 559, 579.
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    25. We also disagree with Transmission Access Policy Study Group's 
argument that the use of a cost allocation method could result in 
burden shifting under section 205. Order No. 1000-A acknowledged that 
stakeholder participation is an important aspect of the development of 
compliance filings to meet the requirements of Order No. 1000, and 
should ensure that the cost allocation method or methods ultimately 
agreed upon is balanced and does not favor any particular entity.\49\ 
Additionally, the Commission clarified that the Commission's cost 
allocation requirements do not interfere with section 205 rights or 
otherwise impose an undue burden on parties to participate in a new and 
costly process, but rather build on the reforms to the transmission 
planning process required by Order No. 890, in which all interested 
parties should already be participating.\50\ As noted above, the 
regional transmission planning process must provide entities who will 
receive regional or interregional cost allocation an understanding of 
the identified benefits on which the cost allocation will be based.\51\ 
Compliance proposals submitted by transmission providers will be 
reviewed by the Commission to ensure they provide the upfront certainty 
required by Order No. 1000.\52\

[[Page 64895]]

To the extent that Transmission Access Policy Study Group is concerned 
about cost recovery issues rather than cost allocation, Order No. 1000 
explained that such questions are beyond the scope of the generic 
rulemaking proceeding, and Order No. 1000-A affirmed this, but 
clarified that public utility transmission providers, in consultation 
with stakeholders, may choose to address this cost recovery matter in 
their compliance filings.\53\
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    \49\ Order No. 1000-A, 139 FERC ] 61,132 at P 637.
    \50\ Id. P 649.
    \51\ Id. P 746.
    \52\ As Transmission Access Policy Study Group also recognizes, 
not all RTOs make section 205 filings for the application of an 
existing filed cost allocation methodology. See Transmission Access 
Policy Study Group at n.14. Transmission Access Policy Study Group 
has not justified its position that this will be an issue in non-
ISO/RTO regions at this time. Again, the Commission will carefully 
evaluate compliance filings, as well as protests thereto, to ensure 
that they satisfy Order No. 1000's requirements, and the Commission 
will require changes if they fail to do so.
    \53\ Order No. 1000-A, 139 FERC ] 61,132 at P 616.
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    26. We do not believe that Transmission Access Policy Study Group 
has justified at this time its position that public utility 
transmission providers in non-RTO regions, at least, should be required 
to file specific applications of the cost allocation method. Again, as 
discussed above, our expectation is that the open and transparent 
transmission planning process and principle-based cost allocation 
method will provide stakeholders with clarity as to why and how costs 
are being allocated for any specific transmission facility selected in 
the regional transmission plan for purposes of cost allocation. This is 
true regardless of whether or not the transmission planning region is 
an ISO/RTO. As we also discuss above, the Commission will carefully 
evaluate compliance proposals and any resulting protests to ensure that 
the proposals meet the requirements of Order No. 1000.
    27. Finally, with respect to Transmission Access Policy Study 
Group's request that we defer a determination on using section 206 as 
the default mechanism to challenge a cost allocation proposal, 
references to section 206 in Order No. 1000-A were to remind 
stakeholders of their right under that provision to file complaints. In 
any event, as we have previously explained, Order No. 1000-A provides 
that public utility transmission providers in a transmission planning 
region, in consultation with stakeholders, could agree to require the 
filing of specific applications of the cost allocation method. The 
Commission will review any such requirement during the Order No. 1000 
compliance filings process and make a decision based on the record 
before us.
3. Consideration of Transmission Needs Driven by Public Policy 
Requirements
a. Order No. 1000-A
    28. Order No. 1000-A affirmed Order No. 1000's requirement that 
public utility transmission providers amend their OATTs to provide for 
the consideration of transmission needs driven by Public Policy 
Requirements.\54\ In affirming this requirement, Order No. 1000-A 
provided clarifications regarding the definition of the term ``Public 
Policy Requirements'' \55\ and what it means to ``consider'' 
transmission needs driven by such requirements.\56\ Order No. 1000-A 
explained that the Commission intends that public utility transmission 
providers consider transmission needs driven by Public Policy 
Requirements just as they consider transmission needs driven by 
reliability or economic concerns.\57\ Further, the Commission stated 
that it does not intend public utility transmission providers to 
substitute their policy judgments for those of legislatures and 
regulators.\58\ Order No. 1000-A also explained that the Commission 
does not require that regional transmission plans support multiple 
likely power supply scenarios, although such a requirement could be 
proposed in Order No. 1000 compliance filings and the Commission would 
consider such a proposal.\59\
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    \54\ Order No. 1000-A, 139 FERC ] 61,132 at PP 317-339. See also 
id. PP 203-216 (affirming legal basis of requirement to consider 
transmission needs driven by Public Policy Requirements).
    \55\ Order No. 1000 defined ``Public Policy Requirements'' as 
public policy requirements established by state or federal laws and 
regulations. Order No. 1000, FERC Stats. & Regs. ] 31,323 at P 2. 
Order No. 1000-A clarified that this term included duly enacted laws 
or regulations passed by a local governmental entity, such as a 
municipal or county government. Order No. 1000-A, 139 FERC ] 61,132 
at P 319.
    \56\ Order No. 1000-A, 139 FERC ] 61,132 at PP 320-325.
    \57\ Id. P 205.
    \58\ Id. PP 326-29.
    \59\ Id. P 331.
---------------------------------------------------------------------------

b. Request for Clarification
    29. AEP requests clarification that an appropriate method for a 
region to consider transmission needs driven by Public Policy 
Requirements is to expressly include consideration of changes in 
resources and load driven by public policies as part of its baseline 
projection of changes in resources and load expected over the planning 
horizon, and then conduct reliability and congestion analyses to 
determine what transmission investments are optimal given those 
expected changes in resources and load.\60\ AEP argues that Public 
Policy Requirements should not be considered solely on a stand-alone 
basis in the planning process.\61\ It contends that generation or load 
changes driven by public policies should be factored into the 
scenarios, along with other anticipated resource and load changes, for 
which reliability and economic benefits analyses are performed.\62\
---------------------------------------------------------------------------

    \60\ AEP at 5.
    \61\ Id. at 2.
    \62\ Id.
---------------------------------------------------------------------------

    30. AEP states that it is concerned that some transmission 
providers may seek to satisfy the Commission's public policy 
requirement by employing only a stand-alone process or procedures that 
are specifically designed to evaluate transmission needs driven by 
Public Policy Requirements.\63\ It argues that regional planning 
processes should consider reliability, economic, and policy-driven 
transmission needs together.\64\ In particular, AEP asserts that a 
region should consider what changes in generation resources and load it 
expects over the planning horizon, including consideration of changes 
driven by public policies (such as renewable portfolio standards, new 
environmental regulations, and demand side management programs), and 
then conduct reliability and congestion analyses to determine what 
transmission investments are optimal given these anticipated 
changes.\65\ It contends that this approach enables transmission 
providers to build upon existing planning processes for the reliability 
and economic analyses used to identify baseline reliability and 
economic projects.\66\ AEP argues that integrated consideration of 
public policy-driven requirements can factor into efficient decisions 
to accelerate a needed baseline reliability upgrade or increase the 
capacity of a baseline reliability upgrade or baseline economic 
upgrade.\67\
---------------------------------------------------------------------------

    \63\ Id. at 4.
    \64\ Id.
    \65\ Id.
    \66\ Id.
    \67\ Id.
---------------------------------------------------------------------------

c. Commission Determination
    31. We grant AEP's request for clarification to the extent 
discussed below. Order No. 1000 requires public utility transmission 
providers to revise their OATTs to provide for the consideration of 
transmission needs driven by Public Policy Requirements.\68\ In Order 
No. 1000, the Commission

[[Page 64896]]

provides for regional flexibility so that public utility transmission 
providers, in consultation with stakeholders, can design proposals 
addressing this requirement that they believe best meet the needs of 
their respective transmission planning regions, so long as those 
proposals satisfy the essential requirement that public utility 
transmission providers, in consultation with stakeholders, consider 
transmission needs driven by Public Policy Requirements as set forth in 
Order No. 1000 and clarified in Order No. 1000-A.\69\ The Commission 
anticipates that a variety of approaches could satisfy the Commission's 
requirements and we expect that stakeholders supporting such proposals 
would have the opportunity to advocate for them in the stakeholder 
processes leading to the Order No. 1000 compliance filings. The 
Commission will consider any such approaches in the compliance filings 
when they are submitted for review.\70\
---------------------------------------------------------------------------

    \68\ The requirement to consider transmission needs driven by 
Public Policy Requirements is described in more detail in Order No. 
1000, FERC Stats. & Regs. ] 31,323 at PP 203-222 and Order No. 1000-
A, 139 FERC ] 61,132 at PP 317-339.
    \69\ See, e.g., Order No. 1000-A, 139 FERC ] 61,132 at P 331 
(``It may well be the case that evaluating different power supply 
scenarios will be an effective way to identify more efficient or 
cost-effective transmission solutions; however, we will not 
prescribe any such requirements here, consistent with our preference 
for regional flexibility in designing regional transmission planning 
processes.'').
    \70\ See id.
---------------------------------------------------------------------------

B. Nonincumbent Transmission Developers

    32. In Order No. 1000, the Commission addressed the removal from 
Commission-jurisdictional tariffs and agreements of provisions that 
contain a federal right of first refusal to construct transmission 
facilities selected in a regional transmission plan for purposes of 
cost allocation. The Commission also adopted a framework that requires 
the development of qualification criteria and protocols to govern the 
submission and evaluation of proposals for transmission facilities by 
public utility transmission providers in the regional transmission 
planning process. The Commission further required that a nonincumbent 
transmission developer of a transmission facility selected in the 
regional transmission plan for purposes of cost allocation have an 
opportunity comparable to that of an incumbent transmission developer 
to allocate the cost of such transmission facility through a regional 
cost allocation method or methods.\71\
---------------------------------------------------------------------------

    \71\ Order No. 1000, FERC Stats. & Regs. ] 31,323 at P 225.
---------------------------------------------------------------------------

1. Legal Authority
a. Order No. 1000-A
    33. In Order No. 1000-A, the Commission affirmed its conclusion in 
Order No. 1000 that it has the legal authority under section 206 of the 
FPA to require the elimination of federal rights of first refusal as 
practices that have the potential to lead to Commission-jurisdictional 
rates that are unjust and unreasonable or unduly discriminatory or 
preferential.\72\ The Commission stated that, consistent with its 
authority under section 206, the Commission acted to remedy an unjust 
and unreasonable or unduly discriminatory or preferential practice by 
requiring public utility transmission providers to eliminate a federal 
right of first refusal from Commission-jurisdictional tariffs and 
agreements and adopt the nonincumbent reforms. The Commission explained 
that in Order No. 1000, it had found that a federal right of first 
refusal applicable to transmission facilities selected in a regional 
transmission plan for purposes of cost allocation can lead to rates for 
Commission-jurisdictional services that are unjust and unreasonable or 
otherwise result in undue discrimination by public utility transmission 
providers.\73\
---------------------------------------------------------------------------

    \72\ Order No. 1000-A, 139 FERC ] 61,132 at P 357.
    \73\ Id. P 360.
---------------------------------------------------------------------------

    34. Finally, the Commission affirmed its decision in Order No. 1000 
to address arguments that an individual contract contains a federal 
right of first refusal that is protected by a Mobile-Sierra provision 
when it reviews the compliance filings made by public utility 
transmission providers.\74\ Consistent with Order No. 1000, the 
Commission explained that a public utility transmission provider that 
considers its contract to be protected by a Mobile-Sierra provision may 
present its arguments as part of its compliance filing. However, the 
Commission also clarified that any such compliance filing must include 
the revisions to any Commission-jurisdictional tariffs and agreements 
necessary to comply with Order No. 1000 as well as the Mobile-Sierra 
provision arguments.\75\ The Commission concluded that this approach 
ensures that public utility transmission providers would not be 
required to eliminate a federal right of first refusal before the 
Commission makes a determination regarding whether an agreement is 
protected by a Mobile-Sierra provision and whether the Commission has 
met the applicable standard of review, while at the same time ensuring 
that the Order No. 1000 compliance process proceeds expeditiously and 
efficiently.
---------------------------------------------------------------------------

    \74\ Id. P 388.
    \75\ Id. P 389.
---------------------------------------------------------------------------

b. Requests for Rehearing and Clarification
    35. Oklahoma Gas and Electric Company argues that the Commission 
failed to support its assertion that provisions that designate 
incumbent utilities to construct new transmission facilities are unduly 
discriminatory or preferential, or cause rates to be unreasonably 
high.\76\ Oklahoma Gas and Electric Company further argues that the 
Commission cannot support a finding that the current transmission rules 
in the Southwest Power Pool result in rates that are unjust or 
unreasonable.\77\
---------------------------------------------------------------------------

    \76\ Oklahoma Gas and Electric Company at 4.
    \77\ Id.
---------------------------------------------------------------------------

    36. Oklahoma Gas and Electric Company also argues that the 
Commission ignores that the Mobile-Sierra standard is a threshold 
question and that the Commission cannot shift the burden of proof to 
the contracting parties to propose an alternative until the Commission 
has answered.\78\ Oklahoma Gas and Electric Company asserts that, under 
section 206 of the Federal Power Act, the Commission must first prove 
that the existing rates or practices are unjust, unreasonable, unduly 
discriminatory or preferential, and that courts have repeatedly held 
that the Commission has no power to force public utilities to file 
particular rates unless it first finds the existing filed rates 
unlawful.\79\ Oklahoma Gas and Electric Company asserts that this two-
step process is even more vital in the context of applying the Mobile-
Sierra doctrine because the Commission must presume that the rate set 
out in a freely negotiated wholesale-energy contract meets the just and 
reasonable requirement imposed by law.\80\ Accordingly, Oklahoma Gas 
and Electric Company argues that the Commission has no power to require 
parties to renegotiate and revise existing agreements unless it finds 
harm to the public interest.\81\
---------------------------------------------------------------------------

    \78\ Id. at 8.
    \79\ Id. at 8-9 (citing Atlantic City Elec. Co. v. FERC, 295 
F.3d 1, 10 (D.C. Cir. 2002); Complex Consol. Edison Co. of New York, 
Inc. v. FERC, 165 F.3d 992, 1001 (D.C. Cir. 1999); Transmission 
Access Policy Study Group v. FERC, 225 F.3d 667, 688 (D.C. Cir. 
2005)).
    \80\ Id. at 9 (citing NRG Power Marketing, LLC v. Maine Public 
Utilities Commission, 130 S. Ct. 693, 700 (2010)).
    \81\ Id. at 9-10.
---------------------------------------------------------------------------

c. Commission Determination
    37. We disagree with Oklahoma Gas and Electric Company that the

[[Page 64897]]

Commission failed to support its determination that a federal right of 
first refusal for transmission facilities selected in a regional 
transmission plan for purposes of cost allocation may lead to 
Commission-jurisdictional rates that are unjust and unreasonable or 
unduly discriminatory or preferential. Specifically, the Commission 
found that a federal right of first refusal has ``the potential to 
undermine the identification and evaluation of more efficient or cost-
effective solutions to regional transmission needs, which in turn can 
result in rates for Commission-jurisdictional services that are unjust 
and unreasonable or otherwise result in undue discrimination by public 
utility transmission providers.'' \82\ The Commission further explained 
the direct effect that a federal right of first refusal can have on 
Commission-jurisdictional rates in Order No. 1000-A, stating that:
---------------------------------------------------------------------------

    \82\ Order No. 1000, FERC Stats. & Regs. ] 31,323 at P 253.

the selection of transmission facilities in a regional transmission 
plan for purposes of cost allocation is directly related to costs 
that will be allocated to jurisdictional ratepayers. The ability of 
an incumbent transmission provider to discourage or preclude 
participation of new transmission developers through discriminatory 
rules in a regional transmission planning process, and in 
particular, the inclusion of a federal right of first refusal, can 
have the effect of limiting the identification and evaluation of 
potential solutions to regional transmission needs. This in turn can 
directly increase the cost of new transmission development that is 
---------------------------------------------------------------------------
recovered from jurisdictional customers through rates.\83\

    \83\ Order No. 1000-A, 139 FERC ] 61,132 at P 358 (citations 
omitted).

    38. The Commission put forth several rationales to support its 
determination.\84\ In particular, the Commission noted that the Federal 
Trade Commission supported the Commission's conclusion that a federal 
right of first refusal can create a barrier to entry that discourages 
nonincumbent transmission developers from proposing alternative 
solutions for consideration at the regional level.\85\ In addition, the 
Commission stated that it is not in the economic self-interest of 
incumbent transmission providers to permit new entrants to develop 
transmission facilities, even if proposals submitted by new entrants 
would result in a more efficient or cost-effective solution to the 
region's needs.\86\ Thus, the Commission concluded that it has a 
reasonable expectation that expanding the universe of transmission 
developers offering potential solutions to regional needs can lead to 
the identification and evaluation of potential solutions that are more 
efficient or cost-effective.\87\
---------------------------------------------------------------------------

    \84\ Id. P 76.
    \85\ Order No. 1000, FERC Stats. & Regs. ] 31,323 at P 257; see 
Order No. 1000-A, 139 FERC ] 61,132 at P 76.
    \86\ Order No. 1000, FERC Stats. & Regs. ] 31,323 at P 256.
    \87\ Order No. 1000-A, 139 FERC ] 61,132 at PP 77, 83.
---------------------------------------------------------------------------

    39. Furthermore, as the Commission explained in the Need for Reform 
section of Order No. 1000-A, the Commission is not required to make 
individual findings concerning the rates of individual public utility 
transmission providers when proceeding under FPA section 206 by means 
of a generic rule.\88\ Rather, the Commission can proceed by 
identifying a ``theoretical threat'' that would materialize and cause 
rates to be unjust and unreasonable, or unduly discriminatory or 
preferential.\89\ As discussed in the preceding paragraph, the 
Commission found that a federal right of first refusal has the 
potential to lead to rates for Commission-jurisdictional services that 
are unjust and unreasonable or otherwise unduly discriminatory.
---------------------------------------------------------------------------

    \88\ Id. P 56.
    \89\ Id. P 57.
---------------------------------------------------------------------------

    40. In response to Oklahoma Gas and Electric Company's arguments 
regarding the Mobile-Sierra doctrine, we reiterate that the Commission 
is not requiring public utility transmission providers to eliminate a 
federal right of first refusal before the Commission makes a 
determination regarding whether an agreement is protected by the 
Mobile-Sierra doctrine and whether the Commission has met the 
applicable standard of review. As the Commission clarified in Order No. 
1000-A, the Commission will first decide, based on a more complete 
record, including viewpoints of other interested parties, whether an 
agreement is protected by the Mobile-Sierra doctrine, and if so, 
whether the Commission has met the applicable standard of review such 
that it can require the modification of the particular agreement.\90\ 
If the Commission determines based on the record submitted in the 
compliance filing that an agreement is protected by the Mobile-Sierra 
doctrine and that it cannot meet the applicable standard of review, 
then the Commission will not consider whether the revisions to the 
Commission-jurisdictional tariffs and agreements submitted by a public 
utility transmission provider that considers its agreement to be 
protected by the Mobile-Sierra doctrine comply with Order No. 1000.\91\
---------------------------------------------------------------------------

    \90\ Id. P 389.
    \91\ Id.
---------------------------------------------------------------------------

2. Requirement To Remove a Federal Right of First Refusal From 
Commission-Jurisdictional Tariffs and Agreements, and Limits on the 
Applicability of That Requirement
a. Order No. 1000-A
    41. In Order No. 1000-A, the Commission affirmed its decision in 
Order No. 1000 to require the elimination of a federal right of first 
refusal from Commission-jurisdictional tariffs and agreements for 
transmission facilities selected in a regional transmission plan for 
purposes of cost allocation.\92\ The Commission also clarified certain 
terms used in Order No. 1000. For instance, the Commission clarified 
that the term ``selected in a regional transmission plan for purposes 
of cost allocation'' excludes a new transmission facility if the costs 
of that facility are borne entirely by the public utility transmission 
provider in whose retail distribution service territory or footprint 
that new transmission facility is to be located.\93\
---------------------------------------------------------------------------

    \92\ Id. P 415.
    \93\ Id. P 423.
---------------------------------------------------------------------------

    42. The Commission stated that in general, any regional cost 
allocation of the cost of a new transmission facility outside a single 
transmission provider's retail distribution service territory or 
footprint, including an allocation to a ``zone'' consisting of more 
than one transmission provider, is an application of the regional cost 
allocation method and that new transmission facility is not a local 
transmission facility.\94\ As an example, the Commission stated that 
transmission owning members of an RTO may not retain a federal right of 
first refusal by dividing the RTO into East and West multi-utility 
zones and allocating costs just within one zone consisting of more than 
one transmission provider.\95\ The Commission also stated that it will 
address whether a cost allocation to a multi-transmission provider zone 
is regional on a case-by-case basis based on the specific facts 
presented. The Commission explained that there may be a continuum of 
examples that range from (i) one small municipality with a single small 
transmission facility located within a transmission provider's 
footprint, to (ii) a ``zone'' consisting of many public utility and 
nonpublic utility transmission providers. Accordingly, the Commission 
stated that public utility transmission providers may include specific 
situations in their compliance filings along with the filed regional 
cost

[[Page 64898]]

allocation method or methods.\96\ The Commission clarified that if any 
costs of a new transmission facility are allocated regionally or 
outside of a public utility transmission provider's retail distribution 
service territory or footprint, there can be no federal right of first 
refusal associated with such transmission facility, except as provided 
in Order Nos. 1000 and 1000-A.\97\
---------------------------------------------------------------------------

    \94\ Id. P 424.
    \95\ Id.
    \96\ Id.
    \97\ Id. P 430. For example, the Commission does not require an 
incumbent transmission provider to eliminate a federal right of 
first refusal for upgrades to its own transmission facilities. Order 
No. 1000, FERC Stats. & Regs. ] 31,323 at P 319.
---------------------------------------------------------------------------

b. Requests for Rehearing and Clarification
    43. Petitioners seek rehearing of the Commission's determination in 
Order No. 1000-A that a transmission facility is considered selected in 
a regional transmission plan for purposes of cost allocation if any of 
the costs of that facility are allocated outside of the public utility 
transmission provider's retail distribution service territory or 
footprint.\98\ MISO Transmission Owners Group 2 argues that under a 
reasonable interpretation of Order No. 1000, a transmission provider 
may retain its right of first refusal if a transmission facility is not 
selected in a regional transmission plan for purposes of cost 
allocation as a more efficient or cost-effective solution to regional 
needs but instead was selected to primarily address local needs.\99\ 
MISO Transmission Owners Group 2 states that not all projects included 
in the regional transmission plan for which some costs are allocated 
outside of an individual utility's footprint are ``a more efficient or 
cost-effective solution to regional transmission needs,'' such as 
projects constructed to meet compliance with state service obligations 
or where the most efficient or cost-effective solution may not be in-
service in time to satisfy reliability criteria and the decision to 
include the project in the plan is made primarily on the basis of 
reliability.\100\
---------------------------------------------------------------------------

    \98\ See, e.g. MISO Transmission Owners Group 2 and Oklahoma Gas 
and Electric Company.
    \99\ MISO Transmission Owners Group 2 at 12-13.
    \100\ Id. at 14-15 (citing Order No. 1000-A, 139 FERC ] 61,132 
at P 430).
---------------------------------------------------------------------------

    44. MISO Transmission Owners Group 2 argues, however, that 
statements in Order No. 1000-A suggest that the decision regarding 
whether a facility is more efficient or cost-effective is irrelevant to 
determining whether the requirement to remove federal rights of first 
refusal would apply.\101\ MISO Transmission Owners Group 2 argues that 
the Commission cites no record evidence or argument in favor of 
broadening the definition of transmission facilities selected in a 
regional transmission plan for purposes of cost allocation.\102\ 
Accordingly, MISO Transmission Owners Group 2 asks for the Commission 
to clarify that, in order for the requirement to eliminate the federal 
right of first refusal to apply, the costs of a transmission facility 
must not only be allocated outside of a transmission owner's retail 
distribution service territory or footprint and the transmission 
facility must have been selected in the regional transmission plan, but 
it also must be selected as a more efficient or cost-effective solution 
to regional transmission needs. The MISO Transmission Owners Group 
requests that the Commission clarify that utilities may retain a right 
of first refusal for projects that are selected which may not be the 
``more efficient or cost-effective solution to regional transmission 
needs.'' \103\
---------------------------------------------------------------------------

    \101\ Id. at 13-14 (citing Order No. 1000-A, 139 FERC ] 61,132 
at P 430 (``if any costs of a new transmission facility are 
allocated regionally or outside of a public utility transmission 
provider's retail distribution service territory or footprint, then 
there can be no federal right of first refusal associated with such 
transmission facility.'')).
    \102\ Id. at 18.
    \103\ Id. at 15-19.
---------------------------------------------------------------------------

    45. MISO Transmission Owners Group 2 also argues that eliminating 
the ability of a transmission-owning member of an RTO to construct and 
allocate the costs of a local transmission facility encourages free 
ridership by providing an incentive for transmission providers to keep 
cost allocation within their retail distribution service territory to 
retain a right of first refusal for local transmission facilities, even 
when entities outside of the retail distribution service territory or 
footprint may receive some benefit from such facilities despite their 
primarily local nature.\104\
---------------------------------------------------------------------------

    \104\ Id. at 19.
---------------------------------------------------------------------------

    46. Oklahoma Gas and Electric Company argues that a broader 
definition of what constitutes regional cost allocation prohibits 
transmission planning regions from adopting approaches they believe 
would effectively allocate costs and fairly balance stakeholder 
interests.\105\ For instance, Oklahoma Gas and Electric Company states 
that the Southwest Power Pool allocates costs using a Highway/Byway 
Plan.\106\ Oklahoma Gas and Electric Company asserts that the 
Commission should ensure that the Southwest Power Pool can retain its 
Highway/Byway Plan for cost allocation by designating lower voltage 
facilities as local facilities for purposes of Order No. 1000.\107\
---------------------------------------------------------------------------

    \105\ Oklahoma Gas and Electric Company at 6.
    \106\ Id. (citing Southwest Power Pool, Inc., 131 FERC ] 61,252 
(2010), reh'g denied, 137 FERC ] 61,075 (2011)). Oklahoma Gas and 
Electric Company states that the Southwest Power Pool allocates: (1) 
100% of the cost of a facility operating at 300 kV or above across 
the region on a postage stamp basis; (2) one-third of the cost of a 
facility operating above 100 kV and below 300 kV on a regional 
postage stamp basis and the remaining two-thirds of the costs to the 
zone in which the facility is located; and, (3) all the costs of a 
facility operating at or under 100 kV to the zone in which the 
facility is located. Id.
    \107\ Id.
---------------------------------------------------------------------------

    47. Some petitioners request that the Commission clarify that 
projects with costs allocated to a single zone should be considered 
local, even if the zone consists of more than one public utility 
transmission provider, so that the public utility transmission provider 
may retain a federal right of first refusal.\108\ AEP contends that the 
Commission's proposal to defer evaluation of multi-utility zones until 
the compliance filing stage does little to inform ongoing RTO 
stakeholder processes tasked with developing compliance filings.\109\ 
MISO Transmission Owners Group 2 asserts that the Commission failed to 
identify any record evidence or argument for its conclusion that 
transmission providers located in multi-transmission provider zones 
automatically lose their federal rights of first refusal for all 
transmission facilities.\110\
---------------------------------------------------------------------------

    \108\ See, e.g., AEP and MISO Transmission Owners Group 2.
    \109\ AEP at 10-11. AEP cites as an example SPP's stakeholder 
process which at the time of AEP's request for clarification, was 
debating the interpretation of the Commission's intended treatment 
of zones that have long included a single large, traditional load-
serving public utility, as well as several small municipal or 
cooperative utilities that are dependent on the transmission system 
of the traditional public utility to serve their respective loads.
    \110\ MISO Transmission Owners Group 2 at 24.
---------------------------------------------------------------------------

    48. MISO Transmission Owners Group 2 also argues that the 
Commission's stated concern that such zones might be established to 
circumvent Order No. 1000 is misplaced.\111\ In support, MISO 
Transmission Owners Group 2 asserts that such zones were established 
prior to the issuance of Order No. 1000 and based on decades of 
cooperation and collaboration among transmission owners.\112\ In 
addition, MISO Transmission Owners Group 2 argues that the Commission's 
distinction between multi-transmission provider zones and zones 
containing only one transmission provider results in undue 
discrimination against transmission providers that happen to be located 
in a multi-transmission provider zone.\113\
---------------------------------------------------------------------------

    \111\ Id. at 22.
    \112\ Id.
    \113\ Id. at 26.

---------------------------------------------------------------------------

[[Page 64899]]

    49. Oklahoma Gas and Electric Company contends that the Commission 
incorrectly claimed in Order No. 1000-A that the scope of Order No. 
1000 will be limited. It asserts that, in response to arguments that 
the requirement to eliminate the right of first refusal is beyond the 
Commission's authority and will materially alter the business of public 
utilities, the Commission in Order No. 1000-A emphasized that the 
requirement did not extend to local transmission facilities.\114\ 
Oklahoma Gas and Electric Company asserts that based on the discussion 
of zones in Order No. 1000-A, it may not be possible to build a local 
facility under the Southwest Power Pool tariff, making all new 
construction subject to Order No. 1000.\115\ Similarly, MISO 
Transmission Owners Group 2 contends that RTO transmission-owning 
members lack individual mechanisms for cost allocation and recovery, 
and therefore would have no ability to build and recover the costs of 
local transmission facilities as they are defined in Order No. 
1000.\116\
---------------------------------------------------------------------------

    \114\ Oklahoma Gas and Electric Company at 3-5.
    \115\ Id. at 5-6.
    \116\ MISO Transmission Owners Group 2 at 23.
---------------------------------------------------------------------------

    50. Oklahoma Gas and Electric Company argues that because the 
requirement to eliminate provisions that designate incumbent utilities 
to construct new transmission facilities is not limited in scope, and 
does materially alter the businesses of transmission owning companies, 
the Commission should find that there is no sound basis to require that 
public utility transmission providers remove such provisions.\117\ In 
the alternative, Oklahoma Gas and Electric Company asserts that the 
Commission should allow each region to define the scope of local 
transmission projects that will not be subject to the new rule.\118\
---------------------------------------------------------------------------

    \117\ Oklahoma Gas and Electric Company at 7.
    \118\ Id.
---------------------------------------------------------------------------

c. Commission Determination
    51. On rehearing of Order No. 1000-A, petitioners have raised two 
issues related to Order No. 1000's requirement that public utility 
transmission providers remove federal rights of first refusal from 
Commission-jurisdictional tariffs and agreements. First, some 
petitioners seek rehearing of Order No. 1000-A's determination that if 
any of the costs of a new transmission facility are allocated 
regionally or outside of a public utility transmission provider's 
retail distribution service territory or footprint, then there can be 
no federal right of first refusal associated with such transmission 
facility. Second, on rehearing some petitioners argue that projects 
with costs allocated to a single zone should be considered local, even 
if there is more than one public utility transmission provider located 
in that zone, so that the public utility transmission provider may 
retain a federal right of first refusal under those circumstances. We 
deny rehearing and will discuss each of these issues in turn.
    52. As noted above, the first issue we address concerns requests 
for rehearing of Order No. 1000-A's determination that if any costs of 
a new transmission facility are allocated regionally or outside of a 
public utility transmission provider's retail distribution service 
territory or footprint, then there can be no federal right of first 
refusal associated with such transmission facility, except as provided 
in Order Nos. 1000 and 1000-A.\119\ Order No. 1000 requires that a 
federal right of first refusal be removed for new transmission 
facilities selected in a regional transmission plan for purposes of 
cost allocation. As noted above, the Commission stated in Order No. 
1000 that in general, if any costs of a new transmission facility are 
allocated regionally or outside a single transmission provider's retail 
distribution service territory or footprint, that is an application of 
the regional cost allocation method and that new transmission facility 
is not a local transmission facility.\120\ Therefore, once a new 
transmission facility is selected in the regional transmission plan for 
purposes of cost allocation, it is no longer a local transmission 
facility exempt from the requirements of Order Nos. 1000 and 1000-A 
regarding the removal of federal rights of first refusal. For this 
reason, we deny rehearing on this issue.
---------------------------------------------------------------------------

    \119\ Order No. 1000-A, 139 FERC ] 61,132 at P 430.
    \120\ Id. P 424 (emphasis added).
---------------------------------------------------------------------------

    53. We note that neither Order No. 1000 nor Order No. 1000-A 
requires elimination of a federal right of first refusal in all 
circumstances.\121\ We also note that the Commission recognized that 
issuance of Order No. 1000 may have occurred in the middle of a 
transmission planning cycle for a particular region and, therefore, 
directed public utility transmission providers to explain in their 
respective compliance filings how they intend to implement the 
requirements of the Final Rule.\122\ Moreover, public utility 
transmission providers are required to describe the circumstances and 
procedures under which public utility transmission providers will 
reevaluate the regional transmission plan to determine if delays in the 
development of a transmission facility selected in a regional 
transmission plan for purposes of cost allocation require evaluation of 
alternative solutions, including those proposed by the incumbent 
transmission provider, to ensure the incumbent transmission provider 
can meet its reliability needs or service obligations.\123\ We will 
evaluate proposals related to these requirements on review of 
compliance filings.
---------------------------------------------------------------------------

    \121\ Order No. 1000, FERC Stats. & Regs. ] 31,323 at PP 318-
319.
    \122\ Id. P 162. See also id. P 65 (``Our intent here is that 
this Final Rule not delay current studies being undertaken pursuant 
to existing regional transmission planning processes or impede 
progress on implementing existing transmission plans. We direct 
public utility transmission providers to explain in their compliance 
filings how they will determine which facilities evaluated in their 
local and regional planning processes will be subject to the 
requirements of this Final Rule.'').
    \123\ Order No. 1000-A, FERC Stats. & Regs. ] 31,132 at P 477. 
See also Order No. 1000, FERC Stats. & Regs. ] 31,323 at P 329 
(``[A]n incumbent transmission provider must have the ability to 
propose solutions that it would implement within its retail 
distribution service territory or footprint that will enable it to 
meet its reliability needs or service obligations.'').
---------------------------------------------------------------------------

    54. With respect to the second issue raised by petitioners--whether 
a project whose costs are allocated to a single zone with multiple 
transmission owners should be considered local and thus permit a public 
utility transmission provider to retain a federal right of first 
refusal under these circumstances--the Commission recognized in Order 
No. 1000-A that special consideration is needed when a small 
transmission provider is located within the footprint of another 
transmission provider.\124\ The Commission acknowledged that there is a 
continuum of situations of multi-transmission provider zones, but opted 
to address such situations on compliance. This acknowledgement provides 
public utility transmission providers who may have zonal 
configurations, such as a zone with a small municipality and one 
transmission provider, or one with many public utility and non-public 
utility transmission providers, an opportunity to address whether a 
cost allocation to a multi-transmission provider zone is regional on a 
case-by-case basis based on the specific facts presented. We consider 
many of the arguments related to multi-transmission provider zones 
premature because the Commission did not adopt a generic rule as to 
whether a cost allocation solely to a multi-transmission provider zone 
is an application of the regional cost allocation method for which a

[[Page 64900]]

federal right of first refusal must be eliminated. Petitioners have not 
presented evidence that would support the Commission making a generic 
finding or providing additional guidance for all multi-transmission 
provider zones in this rulemaking proceeding. Therefore, on this second 
issue, we find that the Commission's determination is a reasonable 
balance of competing considerations that enables the Commission to 
implement the requirements of Order No. 1000 in a manner that will 
achieve the goal of improved transmission planning.
---------------------------------------------------------------------------

    \124\ Order No. 1000-A, FERC Stats. & Regs. ] 31,132 at P 424.
---------------------------------------------------------------------------

    55. We therefore agree with petitioners that the Commission's 
requirements have not entirely eliminated opportunities for free 
ridership. As evidenced by the multiple comments and petitions the 
Commission received in the Order No. 1000 proceedings, the Commission 
balanced many competing interests in determining how to best implement 
the requirements of Order No. 1000. Some presented their views of the 
advantages of retaining a federal right of first refusal for all new 
transmission facilities while others presented their views of the 
advantages of eliminating a federal right of first refusal for all new 
transmission facilities. The Commission has considered the arguments 
raised by petitioners on rehearing with respect to both of the above-
mentioned issues and rejects petitioners' requests for rehearing as we 
find that the approach taken in Order Nos. 1000 and 1000-A provides the 
best balance of competing considerations.
3. Framework To Evaluate Transmission Projects Submitted for Selection 
in the Regional Transmission Plan for Purposes of Cost Allocation
a. Evaluation of Proposals for Selection in the Regional Transmission 
Plan for Purposes of Cost Allocation
i. Order No. 1000-A
    56. In Order No. 1000-A, the Commission affirmed its decision in 
Order No. 1000 to require each public utility transmission provider to 
amend its OATT to describe a transparent and not unduly discriminatory 
process for evaluating whether to select a proposed transmission 
facility in a regional transmission plan for purposes of cost 
allocation.\125\ The Commission also reiterated that there are many 
different approaches to transmission planning and that Order No. 1000 
requires only that the transmission planning process adopted by a 
transmission planning region satisfy the transmission planning 
principles discussed in Order Nos. 1000 and 1000-A. Accordingly, the 
Commission declined to rule in the abstract in advance of the 
compliance filings whether any particular transmission planning process 
is the only appropriate process for all regions.
---------------------------------------------------------------------------

    \125\ Order No. 1000-A, 139 FERC ] 61,132 at P 452.
---------------------------------------------------------------------------

    57. The Commission also continued to emphasize that any 
qualification criteria or process for selecting transmission facilities 
in a regional transmission plan for purposes of cost allocation must be 
transparent and not unduly discriminatory.\126\ Finally, the Commission 
affirmed its decision that, if a proposed transmission facility is 
selected in a regional transmission plan for purposes of cost 
allocation, then Order No. 1000 requires that the transmission 
developer of that transmission facility (whether incumbent or 
nonincumbent) must be able to rely on the relevant cost allocation 
method or methods within the region should it move forward with its 
transmission project.\127\ The Commission also reiterated that it would 
not require public utility transmission providers in a region to adopt 
a provision for ongoing sponsorship rights, and pointed out that in 
Order No. 1000, the Commission concluded that granting transmission 
developers an ongoing right to build sponsored transmission projects 
could adversely impact the regional transmission planning process.\128\ 
Accordingly, the Commission in Order No. 1000-A declined to reverse 
this decision on the selection of transmission developers.\129\
---------------------------------------------------------------------------

    \126\ Id. PP 439, 452.
    \127\ Id. P 456; Order No. 1000, FERC Stats. & Regs. ] 31,323 at 
P 339.
    \128\ Order No. 1000-A, 139 FERC ] 61,132 at P 456; Order No. 
1000, FERC Stats. & Regs. ] 31,323 at P 339.
    \129\ Order No. 1000-A, 139 FERC ] 61,132 at P 456; Order No. 
1000, FERC Stats. & Regs. ] 31,323 at P 339.
---------------------------------------------------------------------------

ii. Requests for Rehearing and Clarification
    58. AEP maintains that some regions are considering a process in 
which third parties (e.g., one or more states) select the developer for 
a transmission project after the regional planning entity has 
identified needed transmission projects in its regional transmission 
plan.\130\ AEP asserts that leaving the selection of a project 
developer to an entity other than the regional planning body threatens 
to lead to suboptimal results.\131\ It argues that the decision as to 
which entity is best suited to build a given transmission project 
necessarily relies on developer qualifications as assessed by the 
transmission provider, and on projected benefits, which will vary among 
developers.\132\ It contends that the selection of the best 
transmission solution for the region cannot be done effectively without 
information about the qualifications and the benefits offered by the 
developer for the project.\133\ Accordingly, AEP requests that the 
Commission provide clarification to discourage bifurcation of the 
planning process.\134\
---------------------------------------------------------------------------

    \130\ AEP at 6.
    \131\ Id. at 2.
    \132\ Id. at 6.
    \133\ Id. at 6-7.
    \134\ Id. at 6.
---------------------------------------------------------------------------

iii. Commission Determination
    59. We decline to clarify in advance of the compliance filings 
whether any particular approach to the selection of a transmission 
developer is a just and reasonable and not unduly discriminatory or 
preferential selection process. Order No. 1000 requires public utility 
transmission providers in a region to adopt transparent and not unduly 
discriminatory criteria for selecting a new transmission project in a 
regional transmission plan for purposes of cost allocation.\135\ It 
also requires that if a transmission project is selected in a regional 
transmission plan for purposes of cost allocation, the transmission 
developer of that transmission facility must be able to rely on the 
relevant cost allocation method or methods within the region should it 
move forward with the transmission project.\136\ However, the 
Commission declined to otherwise address the selection of a 
transmission developer on a generic basis.\137\ We continue to believe 
that it is not appropriate to address in advance of the compliance 
filings the process for selecting transmission developers in greater 
detail. Instead, we reaffirm the flexibility that the Commission 
provided to the public utility transmission providers in each 
transmission planning region to propose a process for selecting 
transmission developers in accordance with each transmission planning 
region's needs.\138\
---------------------------------------------------------------------------

    \135\ E.g., Order No. 1000-A, 139 FERC ] 31,132 at P 455.
    \136\ Order No. 1000, FERC Stats. & Regs. ] 31,323 at PP 332, 
339; see also Order No. 1000-A, 139 FERC ] 61,132 at P 456.
    \137\ E.g., Order No. 1000-A, 139 FERC ] 61,132 at P 455.
    \138\ E.g., id.
---------------------------------------------------------------------------

C. Interregional Transmission Coordination
    60. In Order No. 1000, the Commission required each public utility

[[Page 64901]]

transmission provider, through its regional transmission planning 
process, to establish further procedures with each of its neighboring 
transmission planning regions for the purpose of: (1) Coordinating and 
sharing the results of respective regional transmission plans to 
identify possible interregional transmission facilities that could 
address transmission needs more efficiently or cost-effectively than 
separate regional transmission facilities; and (2) jointly evaluating 
such facilities, as well as jointly evaluating those transmission 
facilities that are proposed to be located in more than one 
transmission planning region.\139\ The Commission also required each 
public utility transmission provider, through its regional transmission 
planning process, to describe the methods by which it will identify and 
evaluate interregional transmission facilities and to include a 
description of the type of transmission studies that will be conducted 
to evaluate conditions on neighboring systems for the purpose of 
determining whether interregional transmission facilities are more 
efficient or cost-effective than regional facilities.\140\
---------------------------------------------------------------------------

    \139\ Order No. 1000, FERC Stats. & Regs. ] 31,323 at P 493.
    \140\ Id.
---------------------------------------------------------------------------

1. Implementation of the Interregional Transmission Coordination 
Requirements
a. Procedure for Joint Evaluation
i. Order No. 1000-A
    61. In Order No. 1000-A, the Commission reaffirmed Order No. 1000's 
requirement that an interregional transmission facility must be 
selected in each relevant regional transmission plan for purposes of 
cost allocation to be eligible for cost allocation under the 
interregional cost allocation method or methods.\141\ The Commission 
explained that Order No. 1000 establishes a closer link between 
transmission planning and cost allocation. Additionally, the Commission 
stated that Order No. 1000 provides for stakeholder involvement in the 
consideration of an interregional transmission facility primarily 
through the regional transmission planning processes.\142\ The 
Commission concluded that this requirement is necessary to ensure that 
stakeholders have an opportunity to provide meaningful input with 
respect to proposed interregional transmission facilities before such 
facilities are selected in each relevant regional transmission plan for 
purposes of cost allocation.\143\
---------------------------------------------------------------------------

    \141\ Order No. 1000-A, 139 FERC ] 61,132 at P 509 (citing Order 
No. 1000, FERC Stats. & Regs. ] 31,323 at P 436).
    \142\ Order No. 1000, FERC Stats. & Regs. ] 31,323 at P 465; see 
also id. P 443.
    \143\ Order No. 1000-A, 139 FERC ] 61,132 at P 509.
---------------------------------------------------------------------------

    62. Additionally, the Commission acknowledged that, under the 
interregional transmission coordination procedures of Order No. 1000, 
an interregional transmission facility is unlikely to be selected for 
interregional cost allocation unless each transmission planning region 
benefits or the transmission planning region that benefits compensates 
the region that does not through a separate agreement. The Commission 
expressed its continued belief that, under the regional transmission 
planning approach adopted in Order No. 1000, it is appropriate for each 
transmission planning region to determine for itself whether to select 
in its regional transmission plan for purposes of cost allocation an 
interregional transmission facility that extends partly within its 
regional footprint based on the information gained during the joint 
evaluation of an interregional transmission project.\144\
---------------------------------------------------------------------------

    \144\ Id. P 512.
---------------------------------------------------------------------------

ii. Requests for Rehearing and Clarification
    63. AEP requests clarification that the inclusion of an 
interregional project in a regional plan need not be subject to the 
same benefits tests that would be applied to a single-region project, 
and that a region may include an interregional project in its plan if 
the benefits to the region compare favorably to the share of the costs 
that would be borne by that region (as distinct from the total project 
costs).\145\ Specifically, it states that in determining the costs and 
benefits of a proposed interregional transmission project for the 
purposes of the selection process, a regional transmission planning 
entity should be permitted to evaluate the benefits provided to an 
affected region and assume that a portion of the costs of the project 
will be allocated to the affected region.\146\ For example, if a $100 
million interregional project would have $180 million in benefits split 
evenly between two adjacent regions, both regions would find the 
project beneficial and would include it in the regional plan, if they 
assumed that one-half of the cost would be borne by each region.\147\
---------------------------------------------------------------------------

    \145\ AEP at 2, 7.
    \146\ Id. at 8.
    \147\ Id.
---------------------------------------------------------------------------

iii. Commission Determination
    64. Order No. 1000 did not specify whether or how a regional or 
interregional benefit-cost threshold should be applied when selecting a 
project in the regional transmission plan for purposes of cost 
allocation, or which costs should be included when calculating a 
benefit-cost threshold to use in this selection process. This was to 
provide the opportunity for each region to develop an appropriate 
calculation, if it chose to use a threshold at all. Therefore, we 
decline to clarify in advance of the compliance filings how a benefit-
cost threshold should be applied.

III. Cost Allocation

    65. In Order No. 1000, the Commission required that each public 
utility transmission provider have in its OATT a method, or set of 
methods, for allocating the costs of new regional transmission 
facilities selected in the regional transmission plan for purposes of 
cost allocation (``regional cost allocation''); and that each public 
utility transmission provider within two (or more) neighboring 
transmission planning regions develop a method, or set of methods, for 
allocating the costs of new interregional transmission facilities that 
each of the two (or more) neighboring transmission planning regions 
selected for purposes of cost allocation because such facilities would 
resolve the individual needs of each region more efficiently or cost-
effectively (``interregional cost allocation'').\148\ The Commission 
required that the OATTs of all public utility transmission providers in 
a region include the same cost allocation method or methods adopted by 
the region.\149\
---------------------------------------------------------------------------

    \148\ Order No. 1000, FERC Stats. & Regs. ] 31,323 at P 482. For 
purposes of Order No. 1000, a regional transmission facility is a 
transmission facility located entirely in one region. An 
interregional transmission facility is one that is located in two or 
more transmission planning regions. A transmission facility that is 
located solely in one transmission planning region is not an 
interregional transmission facility. Id. P 482 n.374.
    \149\ Order No. 1000-A, 139 FERC ] 61,132 at P 523.
---------------------------------------------------------------------------

    66. The Commission also required that regional and interregional 
cost allocation methods each adhere to six regional and interregional 
cost allocation principles: (1) Costs must be allocated in a way that 
is roughly commensurate with benefits; (2) there must be no involuntary 
allocation of costs to non-beneficiaries; (3) a benefit to cost 
threshold ratio cannot exceed 1.25; (4) costs must be allocated solely 
within the transmission planning region

[[Page 64902]]

or pair of regions unless those outside the region or pair of regions 
voluntarily assume costs; (5) there must be a transparent method for 
determining benefits and identifying beneficiaries; and (6) there may 
be different methods for different types of transmission 
facilities.\150\ The Commission directed that, subject to these general 
cost allocation principles, public utility transmission providers in 
consultation with stakeholders would have the opportunity to agree on 
the appropriate cost allocation methods for their new regional and 
interregional transmission facilities, subject to Commission 
approval.\151\ The Commission also found that if public utility 
transmission providers in a region or pair of regions could not agree, 
the Commission would use the record in the relevant compliance filing 
proceeding(s) as a basis to develop a cost allocation method or methods 
that meets the Commission's requirements.\152\ Finally, the Commission 
emphasized that its cost allocation requirements are designed to work 
in tandem with its transmission planning requirements to identify more 
appropriately the benefits and the beneficiaries of new transmission 
facilities so that transmission developers, planners and stakeholders 
can take into account in the transmission planning process who would 
bear the costs of transmission facilities, if constructed.\153\
---------------------------------------------------------------------------

    \150\ Order No. 1000, FERC Stats. & Regs. ] 31,323 at PP 622-
693.
    \151\ Id. P 588.
    \152\ Id. P 482.
    \153\ Id. P 483.
---------------------------------------------------------------------------

1. Cost Allocation Principle 2--No Involuntary Allocation of Costs to 
Non-Beneficiaries
a. Order Nos. 1000 and 1000-A
    67. In Order No. 1000, the Commission adopted the following Cost 
Allocation Principle 2 for both regional and interregional cost 
allocation:

    Regional Cost Allocation Principle 2: Those that receive no 
benefit from transmission facilities, either at present or in a 
likely future scenario, must not be involuntarily allocated any of 
the costs of those transmission facilities.

and

    Interregional Cost Allocation Principle 2: A transmission 
planning region that receives no benefit from an interregional 
transmission facility that is located in that region, either at 
present or in a likely future scenario, must not be involuntarily 
allocated any of the costs of that transmission facility.\154\
---------------------------------------------------------------------------

    \154\ Id. P 637.

    68. The Commission also required that every cost allocation method 
or methods provide for allocation of the entire prudently incurred cost 
of a transmission project to prevent stranded costs.\155\
---------------------------------------------------------------------------

    \155\ Id. P 640.
---------------------------------------------------------------------------

    69. On rehearing, the Commission affirmed Order No. 1000's adoption 
of Regional and Interregional Cost Allocation Principle 2. The 
Commission explained that scenario analysis is a common feature of 
electric power system planning, and that it believed that public 
utility transmission providers are in the best position to apply it in 
a way that achieves appropriate results in their respective 
transmission planning regions.\156\ The Commission also found that the 
use of ``likely future scenarios'' would not expand the class of 
customers who would be identified as beneficiaries because it is 
limited to scenarios in which a beneficiary is identified as such on 
the basis of the cost causation principle.
---------------------------------------------------------------------------

    \156\ Id.
---------------------------------------------------------------------------

    70. The Commission clarified that public utility transmission 
providers may rely on scenario analyses in the preparation of a 
regional transmission plan and the selection of new transmission 
facilities for cost allocation purposes. If a project or group of 
projects is shown to have benefits in one or more of the transmission 
planning scenarios identified by public utility transmission providers 
in their Commission-approved Order No. 1000-compliant cost allocation 
methods, Principle 2 would be satisfied.
b. Requests for Rehearing or Clarification
    71. Organization of MISO States argues that the Commission erred in 
paragraph 690 of Order No. 1000-A when it concluded that if a project 
or group of projects is shown to have benefits in any one of the 
transmission planning scenarios studied by a public utility 
transmission provider in its planning process, then the conditions for 
satisfaction of Cost Allocation Principle 2 will be determined to have 
been met. It contends that, in response to ITC Companies' request for 
clarification, the Commission stated that a ``likely future scenario'' 
that would justify an allocation of costs for new transmission 
facilities includes the transmission planning scenarios being used by a 
transmission provider to prepare a regional transmission plan.\157\ 
Organization of MISO States is concerned that the Commission's 
clarification reads out of Principle 2 the concept of the likelihood of 
a future scenario by suggesting that Principle 2 would be satisfied if 
benefits are shown under any scenario studied by the transmission 
provider in its planning process.\158\ Accordingly, Organization of 
MISO States requests that the Commission clarify that its discussion in 
paragraph 690 of Order No. 1000-A only applies to likely future 
scenarios as required by Principle 2.
---------------------------------------------------------------------------

    \157\ Organization of MISO States at 2 (quoting Order No. 1000-
A, 139 FERC ] 61,132 at P 690 (``If a project or group of projects 
is shown to have benefits in one or more of the transmission 
planning scenarios identified by public utility transmission 
providers in their Commission-approved Order No. 1000-compliant cost 
allocation methods, Principle 2 would be satisfied.'')).
    \158\ Id.
---------------------------------------------------------------------------

c. Commission Determination
    72. We clarify that in finding that Cost Allocation Principle 2 
would be satisfied if a project or group of projects is shown to have 
benefits in one or more of the transmission planning scenarios 
identified by public utility transmission providers in their 
Commission-approved Order No. 1000-compliant cost allocation methods, 
we did not intend to remove the ``likely future scenarios'' concept 
from transmission planning. We believe the evaluation of likely future 
scenarios can be an important factor in public utility transmission 
providers' consideration of transmission projects and in the 
identification of beneficiaries consistent with the cost causation 
principle.

IV. Information Collection Statement

    73. The Office of Management and Budget (OMB) regulations require 
that OMB approve certain information collection requirements imposed by 
an agency.\159\ The revisions in Order Nos. 1000 and 1000-A to the 
information collection requirements were approved under OMB Control No. 
1902-0233. While this order provides clarification, it does not modify 
any information collection requirements. Accordingly, a copy of this 
order will be sent to OMB for informational purposes only.
---------------------------------------------------------------------------

    \159\ 5 CFR 1320.11.
---------------------------------------------------------------------------

V. Document Availability

    74. 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 the Commission's Home Page (http://www.ferc.gov) and 
in the Commission'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.
    75. From the Commission's Home Page on the Internet, this 
information is

[[Page 64903]]

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.
    76. User assistance is available for eLibrary and the Commission'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.

VI. Effective Date

    77. Changes to Order Nos. 1000 and 1000-A made in this order on 
rehearing and clarification will be effective on November 23, 2012.
    By the Commission. Commissioner LaFleur is dissenting in part with 
a separate statement. Commissioner Clark is not participating.

Nathaniel J. Davis, Sr.,
Deputy Secretary.

    Note:  The following appendices will not be published in the 
Code of Federal Regulations.


              Appendix A: Abbreviated Names of Petitioners
------------------------------------------------------------------------
                 Abbreviation                       Petitioner names
------------------------------------------------------------------------
AEP..........................................  American Electric Power
                                                Service Corporation.
MISO Transmission Owners Group 2.............  The Midwest ISO
                                                Transmission Owners for
                                                this filing consist of:
                                                Ameren Services Company,
                                                as agent for Union
                                                Electric Company d/b/a
                                                Ameren Missouri, Ameren
                                                Illinois Company d/b/a
                                                Ameren Illinois and
                                                Ameren Transmission
                                                Company of Illinois;
                                                City Water, Light &
                                                Power (Springfield, IL);
                                                Dairyland Power
                                                Cooperative; Great River
                                                Energy; Hoosier Energy
                                                Rural Electric
                                                Cooperative, Inc.;
                                                Indianapolis Power &
                                                Light Company;
                                                MidAmerican Energy
                                                Company; Minnesota Power
                                                (and its subsidiary
                                                Superior Water, L&P);
                                                Montana-Dakota Utilities
                                                Co.; Northern Indiana
                                                Public Service Company;
                                                Northern States Power
                                                Company, a Minnesota
                                                corporation, and
                                                Northern States Power
                                                Company, a Wisconsin
                                                corporation,
                                                subsidiaries of Xcel
                                                Energy Inc.;
                                                Northwestern Wisconsin
                                                Electric Company; Otter
                                                Tail Power Company;
                                                Southern Illinois Power
                                                Cooperative; Southern
                                                Indiana Gas & Electric
                                                Company (d/b/a Vectren
                                                Energy Delivery of
                                                Indiana); Southern
                                                Minnesota Municipal
                                                Power Agency; and
                                                Wolverine Power Supply
                                                Cooperative, Inc.
Oklahoma Gas and Electric Company............  Oklahoma Gas and Electric
                                                Company.
Organization of MISO States..................  Illinois Commerce
                                                Commission; Indiana
                                                Utility Regulatory
                                                Commission; Iowa
                                                Utilities Board;
                                                Kentucky Public Service
                                                Commission; Michigan
                                                Public Service
                                                Commission; Minnesota
                                                Public Utilities
                                                Commission; Missouri
                                                Public Service
                                                Commission; Wisconsin
                                                Public Service
                                                Commission; and Montana
                                                Public Service
                                                Commission.
Transmission Access Policy Study Group.......  Transmission Access
                                                Policy Study Group.
------------------------------------------------------------------------

    LaFLEUR, Commissioner, dissenting in part:

    As part of today's order, the Commission affirms its holding in 
Order No. 1000-A that an incumbent transmission provider may not 
retain a federal right of first refusal (ROFR) for a new 
transmission project--even a local reliability project--if that 
project receives any amount of regional funding.\1\ After further 
consideration, I believe this decision is premature and denies 
transmission-planning regions the flexibility to define local 
projects. I am now persuaded that the Commission should have 
deferred judgment on this issue until compliance, where it could 
have evaluated--on a case-by case-basis--proposals to define local 
projects in light of the principles underlying elimination of the 
ROFR and the requirement that costs must be allocated in a manner 
that is at least roughly commensurate with benefits. Because I would 
grant rehearing on this point, and defer the issue to compliance, I 
respectfully dissent in part from today's order.
---------------------------------------------------------------------------

    \1\ Transmission Planning and Cost Allocation by Transmission 
Owning and Operating Public Utilities, Order No. 1000, 76 FR 49842 
(Aug. 11, 2011), FERC Stats. & Regs. ] 31,323 (2011), order on 
reh'g, Order No. 1000-A, 77 FR 32184 (May 31, 2012), 139 FERC ] 
61,132 at P 430 (2012).
---------------------------------------------------------------------------

    In Order No. 1000, the Commission eliminated the ROFR for 
projects ``selected in a regional transmission plan for purposes of 
cost allocation'' but allowed it to continue for local projects.\2\ 
In response, certain petitioners requested guidance as to whether 
the requirement to remove the ROFR for projects ``selected in a 
regional transmission plan for purposes of cost allocation'' 
required eliminating it in two specific situations: First, when 
costs are allocated only to multiple transmission providers within a 
single, local zone; and second, when local reliability projects 
receive some amount of regional funding as part of a cost allocation 
methodology.\3\ In essence, petitioners requested clarification as 
to whether these specific cost allocation mechanisms converted 
otherwise local reliability projects to regional projects for 
purposes of eliminating the ROFR.
---------------------------------------------------------------------------

    \2\ Order No. 1000, FERC Stats. & Regs. ] 31,323 at PP 313, 318; 
see also P 63 (defining local projects).
    \3\ Order No. 1000-A, 139 FERC ] 61,132 at PP 409-410; see also 
n. 495 (examples of cost allocation methodologies reflecting 
distinctions between regional and local projects that were 
previously approved by the Commission.).
---------------------------------------------------------------------------

    With respect to the question about zones, in Order No. 1000-A 
the Commission acknowledged that ``there may be a continuum of 
examples'' that require fact specific determinations.\4\ Rather than 
lay down a categorical rule, the Commission opted for flexibility 
and invited parties to raise their specific situations on 
compliance.\5\ Today's order affirms this approach.
---------------------------------------------------------------------------

    \4\ Id. P 424.
    \5\ Id.
---------------------------------------------------------------------------

    In contrast, in Order 1000-A the Commission did reach a 
definitive conclusion with respect to whether any amount of regional 
funding converts an otherwise local reliability project in to a 
regional project for purposes of the ROFR. The Commission clarified, 
without explanation,\6\ that the ROFR must be eliminated if a 
project receives any amount of regional funding.\7\ As a result, a 
local reliability project that receives any amount of regional 
funding, no matter how small, is no longer local for purposes of the 
ROFR. Today's order summarily affirms this decision.
---------------------------------------------------------------------------

    \6\ For example, the Commission did not explain, in light of its 
distinction in Order No, 1000 between projects in a regional plan 
and projects ``selected in a regional transmission plan for purposes 
of cost allocation,'' why eliminating the ROFR for projects 
``selected in a regional transmission plan for purposes of cost 
allocation'' requires eliminating it for local projects that are 
primarily locally funded.
    \7\ Id. P 430.
---------------------------------------------------------------------------

    After further consideration, I believe the Commission acted 
prematurely in concluding that any amount of regional funding 
converts an otherwise local reliability project to a regional 
project for purposes of the ROFR. By reaching this conclusion in the 
abstract, without the benefit of considering stakeholder-vetted 
proposals to define local projects in light of the principles 
underlying elimination of the ROFR and the requirement that costs 
must be allocated in a manner that is at least roughly commensurate 
with

[[Page 64904]]

benefits, the Commission has denied transmission planning regions 
the flexibility it wisely acknowledged to be necessary with respect 
to the zone issue. I agree with SPP and OGE that we should provide 
that flexibility.\8\
---------------------------------------------------------------------------

    \8\ In its request for clarification of Order 1000-A, SPP seeks 
guidance on how to reconcile the definitions and principles 
underlying Order No. 1000 with the Commission's summary 
determination in Order No. 1000-A that any amount of regional 
funding for local reliability projects requires elimination of the 
ROFR. See SPP Request for Clarification at 7-16. Unlike my 
colleagues, I believe that SPP's filing may properly be 
characterized as a request for clarification, and therefore, should 
be addressed in this order. However, I would not reach the merits of 
SPP's arguments. Instead, I would grant rehearing on the grounds 
that the Commission should have deferred deciding the issue until 
compliance and invite SPP to make its arguments on compliance.
---------------------------------------------------------------------------

    In Order No. 1000, the Commission balanced many competing policy 
considerations in an effort to adopt the reforms necessary to assure 
just and reasonable rates.\9\ This balance may be most pronounced in 
the Commission's efforts to ensure that the regional planning 
process is broad, inclusive, and fair, while at the same time, 
mindful of the obligations and attributes of incumbent transmission 
providers. The Commission also went to great lengths to provide 
transmission-planning regions with the flexibility to negotiate cost 
allocation methodologies that allocate costs in a manner that they 
believe is at least roughly commensurate with benefits. Where the 
mutual achievement of these objectives raises complex questions, as 
it does with respect to whether any amount of regional funding 
converts an otherwise local reliability project in to a regional 
project for purposes of the ROFR, the Commission should decide the 
issue on compliance, with a record, rather than by establishing 
categorical rules that may undermine the planning and cost 
allocation goals Order No. 1000 was intended to achieve.\10\
---------------------------------------------------------------------------

    \9\ Order 1000-B at P 55.
    \10\ See e.g. OGE Request for Rehearing at 6 (``[T]he broad 
definition of what constitutes regional cost allocation would 
prohibit regional entities such as SPP from adopting approaches they 
believe would effectively allocate costs and fairly balance 
stakeholder interests.'').
---------------------------------------------------------------------------

    Accordingly, I respectfully dissent in part.

-----------------------------------------------------------------------

Cheryl A. LaFleur,

Commissioner.

[FR Doc. 2012-26111 Filed 10-23-12; 8:45 am]
BILLING CODE 6717-01-P