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

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ACTION:

Order on rehearing and clarification.

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. Introduction1
II. Transmission Planning5
A. Regional Transmission Planning5
1. Role of Section 217(b)(4) of the Federal Power Act6
2. Regional Transmission Planning Requirements12
3. Consideration of Transmission Needs Driven by Public Policy Requirements28
B. Nonincumbent Transmission Developers32
1. Legal Authority33
2. Requirement To Remove a Federal Right of First Refusal from Commission-Jurisdictional Tariffs and Agreements, and Limits on the Applicability of That Requirement41
3. Framework To Evaluate Transmission Projects Submitted for Selection in the Regional Transmission Plan for Purposes of Cost Allocation56
C. Interregional Transmission Coordination60
1. Implementation of the Interregional Transmission Coordination Requirements61
III. Cost Allocation65
1. Cost Allocation Principle 2—No Involuntary Allocation of Costs to Non-beneficiaries67
IV. Information Collection Statement73
V. Document Availability74
VI. Effective Date77
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.

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.

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]

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

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]

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]

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 non-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 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 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]

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]

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 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]

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]

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 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]

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 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 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.

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 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 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]

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]

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.

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 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]

c. Commission Determination

37. We disagree with Oklahoma Gas and Electric Company that the 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:

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]

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]

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.

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]

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 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 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]

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]

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 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 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]

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]

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 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] 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 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 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

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.

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 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 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

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]

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]

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]

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 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 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]

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]

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. 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.

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.

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 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

AbbreviationPetitioner names
AEPAmerican Electric Power Service Corporation.
MISO Transmission Owners Group 2The 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 CompanyOklahoma Gas and Electric Company.
Organization of MISO StatesIllinois 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 GroupTransmission 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.

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.

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.

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 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 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]

Accordingly, I respectfully dissent in part.

Cheryl A. LaFleur,

Commissioner.

Footnotes

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).

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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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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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4.  Order No. 1000, FERC Stats. & Regs. ¶ 31,323 at P 68.

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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.

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7.  Id. P 68 n.57.

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9.  Order No. 1000-A, 139 FERC ¶ 61,132 at PP 168-179.

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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).

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11.  Order No. 1000-A, 139 FERC ¶ 61,132 at P 171.

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12.  Id. P 172.

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14.  Transmission Access Policy Study Group at 12 (quoting Order No. 1000-A, 139 FERC ¶ 61,132 at P 171).

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15.  Id. at 13 (quoting Order No. 681, FERC Stats. & Regs. ¶ 31,226 at P 211 (emphasis added)).

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20.  16 U.S.C. 824q(b)(4) (2006).

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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.

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22.  Order No. 681, FERC Stats. & Regs. ¶ 31,226 at P 325.

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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)).

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24.  See Order No. 681, FERC Stats. & Regs. ¶ 31,226 at P 211.

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25.  Order No. 1000-A, 139 FERC ¶ 61,132 at PP 263-301.

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26.  Id. PP 285-286.

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27.  Id. P 286.

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30.  Id. P 287.

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31.  Transmission Access Policy Study Group at 3.

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32.  Id. at 4.

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33.  Id. at 5.

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34.  Id. at 6.

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35.  Id. at 7.

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37.  Id. at 7-8.

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38.  Id. at 8.

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40.  Id. at 9.

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42.  Id. at 10.

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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).

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44.  Order No. 1000-A, 139 FERC ¶ 61,132 at P 746.

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45.  Id. P 231.

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46.  Order No. 1000, FERC Stats. & Regs. ¶ 31,323 at PP 559, 579.

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47.  Id. P 499.

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48.  Id. PP 559, 579.

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49.  Order No. 1000-A, 139 FERC ¶ 61,132 at P 637.

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50.  Id. P 649.

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51.  Id. P 746.

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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.

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53.  Order No. 1000-A, 139 FERC ¶ 61,132 at P 616.

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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).

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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.

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56.  Order No. 1000-A, 139 FERC ¶ 61,132 at PP 320-325.

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57.  Id. P 205.

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58.  Id. PP 326-29.

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59.  Id. P 331.

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60.  AEP at 5.

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61.  Id. at 2.

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63.  Id. at 4.

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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.

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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.”).

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70.  See id.

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71.  Order No. 1000, FERC Stats. & Regs. ¶ 31,323 at P 225.

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72.  Order No. 1000-A, 139 FERC ¶ 61,132 at P 357.

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73.  Id. P 360.

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74.  Id. P 388.

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75.  Id. P 389.

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76.  Oklahoma Gas and Electric Company at 4.

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78.  Id. at 8.

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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)).

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80.  Id. at 9 (citing NRG Power Marketing, LLC v. Maine Public Utilities Commission, 130 S. Ct. 693, 700 (2010)).

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81.  Id. at 9-10.

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

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

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84.  Id. P 76.

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85.  Order No. 1000, FERC Stats. & Regs. ¶ 31,323 at P 257; see Order No. 1000-A, 139 FERC ¶ 61,132 at P 76.

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86.  Order No. 1000, FERC Stats. & Regs. ¶ 31,323 at P 256.

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87.  Order No. 1000-A, 139 FERC ¶ 61,132 at PP 77, 83.

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88.  Id. P 56.

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89.  Id. P 57.

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90.  Id. P 389.

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92.  Id. P 415.

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93.  Id. P 423.

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94.  Id. P 424.

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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.

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98.  See, e.g. MISO Transmission Owners Group 2 and Oklahoma Gas and Electric Company.

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99.  MISO Transmission Owners Group 2 at 12-13.

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100.  Id. at 14-15 (citing Order No. 1000-A, 139 FERC ¶ 61,132 at P 430).

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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.”)).

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102.  Id. at 18.

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103.  Id. at 15-19.

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104.  Id. at 19.

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105.  Oklahoma Gas and Electric Company at 6.

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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.

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107.  Id.

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108.  See, e.g., AEP and MISO Transmission Owners Group 2.

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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.

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110.  MISO Transmission Owners Group 2 at 24.

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111.  Id. at 22.

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112.  Id.

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113.  Id. at 26.

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114.  Oklahoma Gas and Electric Company at 3-5.

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115.  Id. at 5-6.

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116.  MISO Transmission Owners Group 2 at 23.

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117.  Oklahoma Gas and Electric Company at 7.

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118.  Id.

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119.  Order No. 1000-A, 139 FERC ¶ 61,132 at P 430.

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120.  Id. P 424 (emphasis added).

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121.  Order No. 1000, FERC Stats. & Regs. ¶ 31,323 at PP 318-319.

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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.”).

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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.”).

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

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

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126.  Id. PP 439, 452.

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127.  Id. P 456; Order No. 1000, FERC Stats. & Regs. ¶ 31,323 at P 339.

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128.  Order No. 1000-A, 139 FERC ¶ 61,132 at P 456; Order No. 1000, FERC Stats. & Regs. ¶ 31,323 at P 339.

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129.  Order No. 1000-A, 139 FERC ¶ 61,132 at P 456; Order No. 1000, FERC Stats. & Regs. ¶ 31,323 at P 339.

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130.  AEP at 6.

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131.  Id. at 2.

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132.  Id. at 6.

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133.  Id. at 6-7.

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134.  Id. at 6.

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135.  E.g., Order No. 1000-A, 139 FERC ¶ 31,132 at P 455.

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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.

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137.  E.g., Order No. 1000-A, 139 FERC ¶ 61,132 at P 455.

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138.  E.g., id.

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139.  Order No. 1000, FERC Stats. & Regs. ¶ 31,323 at P 493.

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140.  Id.

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141.  Order No. 1000-A, 139 FERC ¶ 61,132 at P 509 (citing Order No. 1000, FERC Stats. & Regs. ¶ 31,323 at P 436).

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142.  Order No. 1000, FERC Stats. & Regs. ¶ 31,323 at P 465; see also id. P 443.

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143.  Order No. 1000-A, 139 FERC ¶ 61,132 at P 509.

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144.  Id. P 512.

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145.  AEP at 2, 7.

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146.  Id. at 8.

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147.  Id.

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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.

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149.  Order No. 1000-A, 139 FERC ¶ 61,132 at P 523.

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150.  Order No. 1000, FERC Stats. & Regs. ¶ 31,323 at PP 622-693.

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151.  Id. P 588.

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152.  Id. P 482.

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153.  Id. P 483.

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154.  Id. P 637.

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155.  Id. P 640.

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156.  Id.

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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.”)).

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158.  Id.

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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, 77 FR 32184 (May 31, 2012), 139 FERC ¶ 61,132 at P 430 (2012).

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2.  Order No. 1000, FERC Stats. & Regs. ¶ 31,323 at PP 313, 318; see also P 63 (defining local projects).

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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.).

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4.  Id. P 424.

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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.

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7.  Id. P 430.

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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.

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9.  Order 1000-B at P 55.

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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.”).

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[FR Doc. 2012-26111 Filed 10-23-12; 8:45 am]

BILLING CODE 6717-01-P