Analysis of FERC Order No. 1000

August 3, 2011

In its Order No. 1000 (“Order”), the Federal Energy Regulatory Commission (“FERC”) has put into place important changes to the processes that will be used to plan electric transmission facilities in the United States and the way in which the costs of those facilities will be assigned to customers.  Steptoe & Johnson’s Electric Practice Group has analyzed the Order and offers the following perspectives on its likely impact and on some of the critical issues that may arise on appeal and in the compliance process. 

Overview of Order’s Potential Impact

The Order requires that all public utility transmission owners create regional transmission planning processes that produce a list of projects approved for mandatory regional cost allocation.  It directs these transmission owners to consider transmission needs for the integration of renewable resources and other public policy requirements in the regional planning process, and it opens up the transmission business to new entrants by eliminating provisions that give a preference to incumbent utilities in constructing new regional projects.  The Order also changes the rules for transmission cost recovery by requiring all public utility transmission owners to file regional cost allocation methodologies that assign cost responsibility for regional transmission projects in a manner that is “roughly commensurate” with the benefits of the projects.

The Order sets in motion a two-stage compliance process (with filings due in 12 and 18 months) that will require a range of stakeholders with competing interests to try to reach agreement on a complex set of issues that will affect investment in and cost recovery for billions of dollars of new transmission investment.  The Order is noteworthy for the number of compliance issues that FERC has left to the industry to decide in the compliance process, including (outside of Regional Transmission Organizations (“RTOs”)) the very process that will be used to decide them.  The compliance process is therefore likely to be resource-intensive and contentious.  Although the compliance burden will probably be greater in areas that do not have RTOs, significant changes will be required even in regions with RTOs or other formal regional planning processes. 

Non-incumbent transmission developers are likely to play a significant role in the compliance process because they have the most to gain from regional planning that is effective and non-discriminatory.  The Order creates a dynamic not unlike the early stages of independent power development, where FERC sought to create a level playing field between utility and non-utility investment in new generation.  Accordingly, implementation of this Order is likely to be the beginning of a long process that will have many twists and turns as policy issues emerge and get resolved.

FERC’s Authority to Issue the Order

The Federal Power Act (“FPA”) does not give FERC express authority to regulate public utility transmission planning.  FERC defends its authority to issue the Order by contending that regional transmission planning constitutes a “practice” affecting FERC-jurisdictional rates under FPA Section 206, which FERC has the obligation to change if the practice is found to be unjust, unreasonable or unduly discriminatory.  In California ISO v. FERC, 372 F.3d 395, 403 (D.C. Cir. 2004), the Court of Appeals held “that Section 206’s empowering of the Commission to assess the justness and reasonableness of practices affecting rates of electric utilities is limited to those methods or ways of doing things…that directly affect the rate or are closely related to the rate, not all those remote things beyond the rate structure that might in some sense indirectly or ultimately do so.”  So, the core issue is whether regional planning as FERC defines it in Order No. 1000 falls on one or the other side of this somewhat subjective line.   

FERC states throughout the Order that the purpose of the regional planning process that it is ordering is to identify projects that are eligible for cost recovery under the required regional cost allocation mechanism.  Accordingly, FERC’s argument on appeal is likely to be that it is putting in place a process to determine which costs can be included in FERC-jurisdictional transmission rates that are just and reasonable, and therefore the “practices” involved are directly related to the setting of rates and close to the heart of FERC’s regulatory responsibilities.  Opponents will argue that the Order directs public utilities to engage in local and regional planning in order to identify a list of acceptable transmission projects, which has only an indirect impact on rates and constitutes a practice (resource planning) that is traditionally performed at the state level.

FERC contends in the Order that it is not interfering with any planning or approval authority that may be exercised by the states under their laws.  It claims it is not dictating which projects should be approved pursuant to state siting or other laws, and that it is not interfering with state integrated resource planning processes that are designed to determine which costs may be included in retail rates that are subject to state jurisdiction.  FERC claims to maintain a strict separation of federal and state responsibilities that is consistent with the law and current practice.

FERC’s reasoning has embedded within it two fairly far-reaching implications.  First, it appears that FERC, without saying so, is for the first time asserting jurisdiction over the rates for bundled retail transmission service.  In those states that have not unbundled at the retail level, states have retained jurisdiction to set and review the rates, terms, and conditions of retail transmission service.  By claiming that it has the jurisdiction to establish which costs will be assigned to different parties in the FERC-regulated regional transmission planning process, and that this process constitutes a “practice affecting rates” under FPA Section 206, the Commission’s Order implicitly holds that bundled retail transmission rates are subject to its jurisdiction because Section 206 gives FERC authority to regulate practices that affect FERC-jurisdictional rates and not those that affect state-regulated rates.

This implicit jurisdictional ruling, in turn, raises questions about the meaning of the Supreme Court’s decision in New York v. FERC, 535 U.S. 1 (2002), concerning jurisdiction over the transmission component of bundled retail service.  In that decision, the Supreme Court held that FERC has exclusive jurisdiction over all interstate transmission services, but also upheld FERC’s decision not to assert jurisdiction over bundled retail transmission in connection with its Order No. 888 open access rules.  The Court’s decision suggested that FERC would have had jurisdiction to regulate bundled retail transmission services in Order No. 888, but only if it had found that discrimination was occurring in that market.  The dissent argued that, because FERC has jurisdiction, it was required to exercise it.  The majority did not order FERC to assert its jurisdiction in this area, and for this reason the states have continued to exercise jurisdiction over bundled retail transmission service rates since that time.  This Order appears to reopen this unresolved jurisdictional question.   

Second, in the Order, FERC claims authority to direct a “beneficiary” to pay for a service that it did not agree to buy pursuant to a filed agreement.  Under this Order, entities that have not chosen voluntarily to participate in an RTO will be allocated the costs of transmission facilities automatically if projects are included in a regional plan and the approved allocation mechanism requires them to pay for a share of the project, regardless of whether the entity has contracted to buy transmission service using those facilities.  This ruling seems to run up against longstanding Mobile-Sierra principles in which the Supreme Court stated that the FPA contemplates FERC regulation only of voluntary transactions.  Here, not only is FERC making transmission “purchases” mandatory, it is ordering buyers to pay for service where there are no explicit transactions taking place at all.  FERC is likely to argue that its allocation rules require that costs be allocated only to “beneficiaries” of new lines and therefore it is preventing “free-riding” on the regional transmission network by requiring the allocation of cost responsibility to entities that are effectively taking service, whether or not they formally contracted for such service. 

Finally, language used in Order No. 1000 suggests that FERC may contend that its jurisdiction to direct public utilities to engage in transmission planning was decided in Order Nos. 888 and 890, and therefore appeals on this issue should be barred based on collateral estoppel principles.  A potential response to this argument is that the planning required by Order No. 1000 has direct consequences on cost recovery for transmission investments under FERC rates.  Planning under Order Nos. 888 and 890 did not give rise to any mandatory cost allocations and therefore did not have any direct impact on rates, except in RTOs where the planning activity was the result of voluntary decisions by utilities to participate in the RTOs.

The above issues are novel ones, and the outcome of an appeal of the Order on jurisdictional grounds is difficult to predict.  In any event, it will probably be several years before an appeal is heard, and therefore public utilities will not get relief from the compliance process in the absence of a court-ordered stay, which seems unlikely in the circumstances.

Antitrust Considerations

The requirement that utilities and other stakeholders engage in joint planning to determine which transmission facilities are to be approved in the regional plan, and by whom, creates potential, new, antitrust risks, particularly for those located outside of RTOs.  As explained above, under the Order, each region will develop a framework for planning and cost allocation within the region, and will thereafter develop periodic transmission plans in accordance with the framework.  It is in the periodic plans that the determination will be made as to which projects will be eligible for regional cost allocation.  The framework will be filed with, and approved by, FERC, but the Order does not provide for the filing of the plans themselves (although a regional plan presumably will be subject to FERC review should anyone file a complaint directed at that plan).

The antitrust risk is most likely to arise in a situation in which a transmission project developer does not succeed in having its project included in the regional plan (and is, therefore, ineligible for regional cost allocation), and alleges that the incumbent transmission owners either conspired to exclude its project or are seeking, individually or collectively, to monopolize transmission.  Although the presence and extent of FERC regulation would be relevant to the court or enforcement agency in assessing the antitrust issues, it may not be dispositive.  The complaining party would likely allege that although FERC compelled potential transmission developers to engage in a collaborative planning process, it left to the parties’ discretion how the process should be carried out, and therefore the antitrust laws apply and condemn anticompetitive agreements or actions arising in the course of developing a plan.   

In RTOs, it is the RTO itself that has final approval authority for the regional transmission plan.  The status of the RTO as an independent entity that does not own transmission and has been determined by FERC to be outside the control of the transmission owners, would, in general, make it very difficult for a project developer to maintain an antitrust suit for exclusion of its project in an RTO market.  Outside of an RTO market, the greater the level of control over the decision-making process that is maintained by the transmission owners, the greater the level of potential antitrust risk.  Some thoughts as to how transmission owners might minimize antitrust risk outside of RTO markets include the following:

  • Filing the annual transmission plan with FERC for approval under FPA Section 205.  Although the Rule does not require such filings, FERC asserted jurisdiction over the plans and did not preclude their filing.   Such a FERC filing would enhance the transmission owners’ defense that the plan is subject to FERC’s exclusive jurisdiction (e.g., is subject to the filed rate doctrine) and a favorable FERC decision would also strengthen the arguments that the planning decisions contained in the plan are pro-competitive and reasonable.
  • Including in the regional framework that an independent monitor will ensure that all potential projects are judged fairly and with no undue preferences.  The framework could identify the independent monitor and seek FERC approval of the monitor as being independent from the transmission owners.
  • Developing and having approved by FERC a decision-making or dispute resolution structure in the regional framework that ensures that, as in RTOs, the transmission owners will not be able to control the decision-making process.
  • Designing a planning framework that integrates necessary state approval processes into the process of selecting which facilities to include in the annual plans.  Issues of state-action immunity are complex, but if the states within the region require state certifications or other approvals to build a transmission project, then it may be possible to integrate the state approval process into the overall planning framework in a way that provides state-action immunity to the transmission owners. Greater state involvement in the annual plans would also strengthen the arguments that the planning decisions contained in the plans are reasonable.

Incumbent Rights to Build New Facilities

As noted above, FERC holds, with limited exceptions, that any regional planning arrangement that affords a preference (“right of first refusal” or “ROFR”) in favor of existing transmission owners to build new regional transmission projects is unduly discriminatory and must be eliminated.  In the Order, FERC decided against requiring a formal competitive bidding process for such new transmission facilities in favor of one in which project sponsors can propose their own projects for inclusion in the regional plan, subject to processes and eligibility requirements to be established in the compliance process.

Some form of competition between competing sponsors of the same or similar projects seems unavoidable under the Order, and the new rules raise the prospect of sponsors presenting artificially low project cost estimates in order to be chosen in the planning process.  This, in turn, will require the creation of mechanisms to prevent or penalize parties that submit artificially low cost estimates and to ensure a fair assessment of competing projects.  In any event, project cost estimates presented in the regional planning process are likely to have more significance than they do now and may affect the level of allowed cost recovery.

During the compliance process, disagreements are likely to arise over the eligibility requirements for third parties to develop transmission projects.  The Order suggests that these eligibility requirements may address a developer’s financial and technical capability to design, construct, and operate the facilities.  To the extent that utilities propose more rigorous eligibility requirements, new entrants are likely to argue that the utilities are attempting to limit competition for investment in new facilities in contravention of the rule.  Ultimately, FERC will have to determine what constitutes undue discrimination in this area.   

Regional Versus Local Planning

The ROFR limitations adopted in the Order apply only in the “regional” planning process.  Each public utility must still retain a “local” transmission planning process that applies to transmission facilities constructed within its service territory and for which costs can only be assigned to that utility’s customers.  In other words, the Order does not prohibit public utilities from planning and building transmission on a single-system basis and recovering the costs only from their own customers, under traditional, single-utility cost recovery rules.  It merely requires a concurrent regional process in which it may be found that the construction of regional facilities is preferable from an efficiency standpoint.  Public utilities are permitted to retain ROFR provisions in their local planning. 

FERC’s application of its anti-ROFR decision solely to the regional planning process may be problematic for FERC on appeal.  If challenged, FERC will have to justify its decision to apply the Section 206 non-discrimination requirement only in the context of regional planning, leaving incumbent utilities with a preference under the local planning processes that are also included in each utility’s Order No. 890 OATT. The Order rejects ROFRs because FERC found that they prevent the most effective projects from being presented and considered, and it is not obvious why this reasoning does not apply to local planning.  The distinction may also result in disputes with non-incumbent developers over whether projects should have been included in the regional plan rather than the local plan.

The local/regional planning distinction is also likely to engage the interest of state regulators and transmission customers that may prefer, or not prefer, that the costs of transmission facilities be allocated more broadly under regional cost allocation methods.  This in turn could lead to disputes over whether specific transmission projects should be considered local or regional projects for planning and cost allocation purposes, with states and customers competing against each other to limit their own cost exposure. 

Cost Allocation/Measurement of Benefits

FERC requires public utility transmission owners in each region to establish generic cost allocation methodologies applicable to all transmission projects included in their regional transmission plans; costs cannot be allocated on a case-by-case basis.  Participant funding is rejected as an optional regional cost allocation method.  Different methodologies may (but don’t have to) be adopted for different categories of transmission projects (reliability, economic, public policy).  FERC establishes six criteria that must be satisfied, but the overriding one is that a methodology must assign costs on a basis that is “roughly commensurate” with the benefits of the project.  This standard was adopted by the Seventh Circuit in its decision in Illinois Commerce Commission v. FERC, 576 F.3d 470 (7th Cir. 2009), involving PJM’s regional cost allocation.  Negotiation of acceptable cost allocation methodologies will likely be very difficult, as this has proven to be a very contentious issue in the RTOs as the Illinois Commerce Commission case attests.  After almost two years, FERC has not yet issued an order on remand in that case, which indicates the inherent difficulty in resolving these issues.

For those regions (primarily in RTOs) that have already adopted regional cost allocation methodologies, it is unclear from the Order whether existing methodologies, especially those that socialize the costs of new transmission, will have to be replaced.  FERC suggests that existing approved methods may be retained, but most of the existing approved methods were opposed when filed, and the Commission presumably will have to find that they satisfy the six criteria set forth in the Order to be retained, which provides an opening for opponents to force a reconsideration of existing mechanisms, particularly those that socialize cost responsibility. 

Where no existing cost allocation methodology exists, or where the existing allocation method is contrary to the Order, it remains to be seen whether it will be possible for the regions to achieve consensus around one or more generic methodologies that satisfy the “benefits” test adopted in the Order.  FERC provides very little guidance on how it expects benefits to be defined and calculated and the methods that would satisfy the six standards.  It is likely that consensus will not be reached in many cases and competing proposals will be filed at the end of the compliance period, which will force resolution of the issue back onto FERC.     

Interregional Transmission Planning

The Order appears to relax the planning requirements in the context of interregional planning.  First, the Order does not require each region to engage in formal interregional transmission planning with each of its neighboring regions; it requires only planning coordination, and this does not include a requirement to issue a formal plan that includes the identification of approved projects that will be subject to interregional cost allocation.  Second, the Order provides that no region will be required to bear the cost of a transmission project that is physically located in a neighboring region unless it agrees voluntarily to do so, and this appears to apply regardless of whether it is demonstrated that the former region benefits from a project located outside its region.

Order No. 1000 appears to create rough going for developers seeking cost recovery for transmission projects that are designed to facilitate the delivery of renewable power over long distances.  The Order does not contain any forcing mechanism for two or more regions to formally consider interregional projects.  The rule does not provide a strong mechanism for transmission developers in regions with significant quantities of wind power, for example, to obtain cost recovery from more distant regions where the power could be used to meet Renewable Portfolio Standard (“RPS”) requirements.  FERC states, for example, that it is rejecting any requirement to engage in interconnection-wide transmission planning, which will likely abort ongoing efforts in this area.  The Order is therefore likely to promote the use of more “homegrown” renewables to meet RPS requirements. 

If this issue is appealed, FERC may have to reconcile the allocation rule prohibiting the involuntary assignment of costs outside of a single region with its requirement that the costs of regional projects be allocated in a manner roughly commensurate with benefits.  FERC does not explain why the benefits standard, taken from the Seventh Circuit’s decision in Illinois Commerce Commission, should not apply to facilities located in a neighboring region under the interregional planning required by the Order.  FERC may also have to provide a policy justification for using two sets of planning requirements for regional and interregional plans when both are “practices” covered by Section 206. 

Treatment of Existing Projects

FERC states that the new regional planning rules will apply on a going-forward basis and are not intended to interfere with the processing of projects that have been identified or approved in an existing regional transmission plan, as opposed to “new” transmission facilities identified prospectively.  However, FERC defined “new” facilities as “those transmission facilities that are subject to evaluation or reevaluation as the case may be, within a public utility transmission provider’s local or regional transmission planning process after the effective date of the public utility transmission provider’s [compliance] filing.”  FERC further noted that “transmission facilities often are subject to continuing evaluation as development schedules and transmission needs change, and that the issuance of this Final Rule is likely to fall in the middle of ongoing planning cycles.”  FERC ruled that each region will have the right to determine at what point a previously-approved project is no longer subject to reevaluation, noting that “existing planning processes already include specific points at which a project will no longer be subject to reevaluation.”  FERC directed public utilities to include in their compliance filings an explanation of how they will determine which facilities evaluated in their local and regional planning processes will be subject to the requirements of Order No. 1000. 

Although FERC apparently prefers to leave prior decisions unchanged and wants existing regional planning processes to move forward during the compliance process, the Order is far from clear as to which projects it would consider to be grandfathered into existing rules, both for approval purposes and for purposes of determining whether existing or new cost allocation methods apply to such projects.  For this reason, the Order compels those developers with projects that have been included in regional plans but that have not yet entered the construction phase to participate actively in the compliance process to prevent backtracking on projects under the rubric of “reevaluation” of existing projects.  This applies both to retaining existing planning approvals and to application of existing cost allocation methodologies to those projects.

Identification of Public Policy Projects

FERC requires each region to consider transmission projects constructed for public policy purposes under federal laws or state laws applicable to that region, which is a euphemism for requiring regional plans to evaluate proposed transmission projects that are designed to integrate renewable generation in order to meet renewable portfolio standards.  However, FERC does not address how a region should define the need for public policy projects in regions where different (or no) state RPS requirements exist, or where one or more states establishes a preference for in-state projects to meet an RPS.  It directs the regions to address this issue and goes out of its way to state that it intends to afford the regions significant discretion to determine what transmission needs must be evaluated in the regional planning process.  


If you have any questions about this Order or its potential implications, please contact David Raskin ( or 202.429.6254), Rick Roberts ( or 202.429.6756) or Steve Ross ( or 202.429.6279).