By Eleanor Saunders
The Federal Energy Regulatory Commission (FERC) finalized an important rule on U.S. electricity transmission planning and cost allocation in July 2011, and now is responding to questions and concerns about the regulation’s implications for states, utilities, consumers and other affected parties.
The commission asserts the order’s provisions will bring about a more open and coherent planning process, structured around clearly articulated general principles that permit the flexibility necessary for accommodating divergent regional needs and practices. But the reaction to FERC’s new rule has varied greatly among stakeholders operating in different regulatory environments. 
Order No. 1000, entitled Final Rule on Transmission Planning and Cost Allocation by Transmission Owning and Operating Public Utilities (henceforth, Final Rule), tackles three major issues: transmission planning, cost allocation for new transmission projects and the status of non-incumbent developers — that is, entities not among the current transmission developers or operators in a region that wish to enter the market.
A central provision of the Final Rule requires that transmission planning take place at the regional level, with broad stakeholder input and coordination between neighboring regions. Although regions will retain a great deal of autonomy in defining the details of their plans, all must identify which state and federal public policies have implications for their transmission needs, and must consider these policies when evaluating proposals for specific projects.
The Final Rule further stipulates that regions develop clear cost-recovery methods for any new facilities deemed to satisfy regional needs. Although it does not mandate the use of any specific approach, the order does spell out general features, such as requiring that costs only be allocated to those who directly benefit from a given project and that a region’s method of identifying beneficiaries and assigning costs be fully transparent.
The rule represents the next step in a sequence of FERC regulations, including orders number 888 from 1996 and 890 from 2007, that aim to remove discrimination in transmission planning and ensure that less costly and more efficient power supplies reach consumers, Mason Emnett, associate director of FERC’s Office of Energy Policy and Innovation, told an audience of energy professionals at a forum in Boston on September 16.
Emnett, whose office was instrumental in developing the new rule, also stressed that despite its more than 600 pages of text, the order seeks only to establish a general framework for regions to use in planning.
“The future is in your hands,” said Emnett. He noted, for example, that “you can define your own regions,” although the FERC anticipates that current regional transmission organizations (RTOs) or independent system operators (ISOs) will provide relevant templates in at least some parts of the country.
While the traditional principles of reliability and cost-effectiveness will continue to be important determinants of regional plans, relevant public policies will now have an explicit role to play in defining transmission needs. But it is up the regions to determine which policies are applicable, Emnett said. If a region decides, for example, that an increase in renewable energy resources is important, transmission may be needed to integrate new renewable supplies rather than simply to improve reliability, he said.
The rule also aims to promote competition that maximizes the cost-effectiveness of new facilities. Toward that end, regional planning authorities must remove obstacles or cease practices that would disadvantage proposals from nonincumbent developers, such as the existing right of first refusal that has been extended to incumbent players, Emnett said.
Emnett’s presentation on behalf of FERC at the September 16 forum was followed by responses from representatives of several major New England stakeholder groups –the states, utilities and environmental organizations. The speakers conveyed largely favorable reactions toward the reforms, but raised questions about various provisions.
Peter Flynn of National Grid praised the order for “being pro-customer and providing a model of federalism” in the way that it addresses transmission planning. Flynn, who is president of National Grid’s FERC-regulated businesses, also lauded FERC’s decision to develop principles on a general rather than project-oriented level.
“The rule leaves room for the states to play a leading role in determining what public policies should enter into transmission-planning discussions, though it seems clear that RPS requirements are a stand-out candidate since they often stimulate a need for additional transmission,” said Flynn.
Seth Kaplan of the Conservation Law Foundation also addressed the public-policy requirement, which he said is squarely within FERC’s jurisdiction because the mandate is not overly general, calling only for consideration of public-policy requirements in light of their specific impact on transmission planning and costs. Thus, the rule is consistent with prior case law such as Mass Electric Company v. Department of Public Utilities, where the court found that a public utility commission may direct a utility to avoid conditions that the commission “reasonably anticipates will impose costs on the utility and be detrimental to the interests of ratepayers,” said Kaplan, who is vice president for policy and climate advocacy.
If utilities or other transmission planners fail to take into account a state’s renewable portfolio standard, or other public-policy requirements, that omission could hinder the most cost-effective approach to planning and ultimately lead to higher prices for ratepayers, he said.
Kaplan went on to highlight the challenges inherent in the two-step process that the Final Rule sets up to first, identify relevant public policies and then, integrate those policies into transmission planning and project selection. The flexibility permitted in relation to the second step creates the risk that public-policy requirements could be treated with a wink-and-nod kind of paper compliance, said Kaplan. He compared their potential fate to that of the mechanism for grid upgrades intended to provide ‘economic benefits’ for New England electricity customers. “While the provision sits on the books, it is never used — in sharp contrast to the mechanism for planning and funding ‘reliability upgrades’, which has been used to move forward billions of dollars of projects,” he said.
Heather Hunt, executive director of the New England States Committee on Electricity (NESCOE), noted that the New England states have already been engaged in the type of coordinated planning that the order requires, so that the region’s compliance with the Final Rule may be smoother than in other parts of the country. As evidence, she cited the 2009 New England Governors’ Renewable Energy Blueprint, which explores the potential for regionally coordinated procurement of renewable energy and transmission siting.
But she also pointed to complications associated with ambiguity in the rule’s requirements, including the difficulty of specifying the impact of state laws and regulations on transmission when, for example, renewable portfolio standards can be satisfied by alternative payments as well as new generation or the amount of energy efficiency made use of in a given state can be affected by policies and decisions about loading order.
NESCOE plans to seek out stakeholder input on the question of relevant public policies for the region as a whole, and to examine how non-transmission alternatives like energy efficiency and demand response measures, only minimally addressed by the Final Rule, may play out in regional transmission planning and developer cost recovery, Hunt said.
For example, in a request for rehearing filed with FERC, the Coalition for Fair Transmission Policy, an association of seven investor-owned utilities serving over 28 percent of U.S. electric customers, said that “the Final Rule could result in higher costs to many consumers, [pre-empt] public utility and state prerogatives to determine and decide what generation resources best meet the reliability and economic needs of consumers …, and [cause] inefficiencies in competitive electric markets.”
Commenting on the public-policy requirement specifically, the group worries that regional planning might operate in a top-down way, assigning benefits that are “speculative” and “beyond the typical planning horizon,” and allocating costs on that basis rather than addressing planning decisions through a bottom-up process led by utilities, who are most familiar with resource needs.
The varying reactions to the Final Rule may reflect at least in part the very different market structures within which stakeholders operate. Northeastern, mid-Atlantic and midwestern states along with California are already organized under independent third-party RTOs or ISOs, which oversee regional transmission planning and wholesale electricity markets. In contrast, southeastern, southwestern, inter-mountain and northwestern states have retained traditional vertically-integrated utilities that control both transmission lines and dispatch of power to the grid. Besides developing and operating transmission, these utilities own generating plants that supply electricity to the grid, all under the jurisdiction of state regulatory commissions.
For companies and states where the traditional structure holds sway, FERC’s requirements for regional planning and full transparency necessitate a huge reorientation. They directly challenge a model where state utility commissions decide on the appropriateness of transmission proposals and cost allocation, planning to a substantial degree takes place within utilities and integrated resource plans are confidential corporate documents.
But Emnett noted that these changes do not come out of the blue. FERC has been invested in moving toward greater transparency and consistency in U.S. transmission planning since publishing Orders No. 888 and 890. The new Final Rule simply makes the principles clearer and provides a more detailed framework for doing so, while still allowing regions a fair amount of latitude, he said.
According to FERC Commissioner Marc Kaplan, who addressed objections raised by Coalition in an interview for E&E TV’s OnPoint on September 27, the Final Rule is a document that has “brought order out of chaos.” Spitzer focused specifically on the question of cost allocation, and described the cacophony of positions that might have determined policy before the new order was finalized – ranging from a U.S. Senate bill that “would have provided for interconnection-wide cost allocation” to a proposal to “limit how regions could impose cost allocation on their own ratepayers.”
The chaos and uncertainty have had a negative impact on the development of both transmission and generation, to the ratepayer’s detriment, he said. With the Final Rule, FERC’s bipartisan group of commissioners gave unanimous support to a path midway between the extremes, Spitzer said.
As the debate goes on and commissioners consider filings for a rehearing of rule provisions, FERC will offer three fall webinars to help regions in developing their compliance plans. Regional plans must be filed within one year of the effective date of the Final Rule, and interregional plans for common cost allocation methods for any transmission projects that may be selected by neighboring regions must be filed within eighteen months.
How the commission ultimately clarifies or reworks details of the Final Rule will be of great importance for the states and the shape of the country’s transmission backbone in the coming decades.
 See the Electricity Primer 101 for an overview of electricity markets.
 I would like to thank Seth Kaplan of the Conservation Law Foundation (personal communication, 10/4/2011) for clarifying how the context within many utilities and states operate may generate opposition to Order No. 1000.