The Trouble With Order 1000
Originally published June 6, 2013
Since 1996, the Federal Energy Regulatory Commission has issued a succession of orders on transmission access, planning and cost allocation. And electric utilities have complied with those rules.
But with Order No. 1000—issued in 2011—many utilities think the commission has gone too far.
In a nutshell, Order No. 1000 requires that public (that is, FERC-regulated) utility transmission providers engage in regional and interregional transmission planning. It also requires them to develop a FERC-approved method of allocating costs for new regional and interregional transmission facilities. The planning process must provide an opportunity to consider what FERC calls “public policy requirements.”
Many parties petitioned in 2011 for rehearing of Order No. 1000, challenging FERC’s legal authority to issue mandates on transmission planning, priority to build and cost allocation.
The American Public Power Association, one of the petitioners, said FERC failed to carry out its statutory obligation under Section 217(b)(4) of the Federal Power Act to use its authority to ensure that transmission planning meets the reasonable needs of load-serving entities. “A policy that is developed in the first instance to meet the needs of transmission developers, which may (or may not) benefit [load-serving entities], does not comport with the statute’s directive,” APPA said.
Another petitioner, the Large Public Power Council, argued that FERC lacks the legal authority to allocate transmission development costs in the absence of contracts between the transmission developers and actual customers agreeing to take service from the new facilities. Further, LPPC argued that FERC lacked the authority to compel transmission planning and failed to facilitate planning for service to native load, as required by section 217(b)(4) of the Federal Power Act. Finally, LPPC and NRECA argued that FERC erred in expanding reciprocity to include an obligation to participate in regional planning and to pay for transmission costs allocated in those processes, even if the non-regulated utilities choose not to use the new facilities.
In May 2012, FERC issued Order No. 1000-A, denying most of the many rehearing requests of Order No. 1000. In October of the same year, it issued Order No. 1000-B, which denied a rehearing of Order No. 1000-A.
The commission rejected legal claims that Section 202(a) of the Federal Power Act, which deals with “voluntary coordination” of facilities, bars it from requiring regional and interregional transmission reforms. FERC also rejected legal claims that Section 217(b)(4) of the Federal Power Act requires it to ensure that the needs of load-serving entities are met.
Next step: court appeal. Rebuffed by FERC, a number of parties filed petitions for review of Order No. 1000, among them APPA. The petitions have been consolidated and initial briefs were filed on May 28, 2013 with the U.S. Court of Appeals for the District of Columbia Circuit.
The Large Public Power Council (LPPC), whose members comprise 25 of the larger, asset-owning members of APPA, including joint action agencies, was among the petitioners. “Our [LPPC] members are particularly concerned that the cost allocation feature of the rule will result in bills being sent our way for facilities we do not need and choose not to use." Since FERC presented the planning and cost allocation provisions of the rule as a single package, LPPC chose to challenge the whole underlying justification of the rule,” said Jonathan Schneider, a partner at Stinson Morrison Hecker, the District of Columbia law firm representing LPPC.
“We have no quarrel about participating in regional planning,” he said. “But we don’t want to participate in a process that will allocate costs to us whether we need the facilities or not.”
While the appeals cover several issues, three are key, said Cynthia Bogorad, a partner at Spiegel & McDiarmid law firm who represents the Transmission Access Policy Study Group (TAPS), an intervenor in the appeals whose members include numerous public power utilities and joint action agencies. They are public policy requirements, right of first refusal and cost allocation. “Those are the issues that people care about, whether they’re in an RTO [regional transmission organization] region or a non-RTO region.”
The court has identified eight groups of issues to be addressed in briefs: threshold issues, cost allocation, right of first refusal, transmission planning and public policy, state sovereignty, reciprocity, FERC’s refusal to act under FPA Section 211A and the scope of cost allocation.
Threshold issues. The petitioners “focus this brief on the arguments challenging the basic predicates for the rulemaking.”
Randy Elliott, a principal with Miller Balis and O’Neil law firm, offers an example of a question that the brief addresses: Is regional planning something that FERC can mandate or does Section 202(a) of the Federal Power Act make it voluntary?
Another threshold issue, said Elliott, is whether transmission planning is within a state’s purview, outside of FERC’s jurisdiction.
Some utilities in non-RTO regions—the Southeast and the Northwest—argue that they don’t need an order, said Elliott. “They say that creating more rules and requirements at the federal level makes it more difficult for them to comply with applicable state laws.”
Cost allocation. According to FERC, participating in a regional planning process and contributing to any cost allocation is what it takes for a municipal utility to provide reciprocal service, said Schneider. “And if a municipal utility doesn’t participate, FERC jurisdictional transmission providers are entitled to deny municipal utilities the right to use the transmission system. As a result, the municipal utility could be turned into an island, unable to use the facilities in the region.”
The question, said Schneider, is how far FERC can go in extending the reciprocity rule as it pertains to municipal utilities. “Can a municipal utility be required to contribute to this broad funding mechanism,” he asks. The commission's view that it is justified in extending the reciprocity rule effectively to require municipals to fund regional projects they may not need motivated LPPC to appeal not only the reciprocity provisions of the rule, but the broader cost allocation mechanism.
Because of the potential for the cost allocation features of the rule to apply to municipals through the reciprocity principle (see below), LPPC joined several other petitioners—among them investor-owned utilities, the New York ISO and NRECA -- in arguing that FERC does not have the authority to require anyone to fund transmission projects that they do not use. According to Schneider, “the Federal Power Act only allows FERC to set rates for transmission providers that are charged to their customers. This statute does not permit a funding mechanism assessing costs to all entities in a region, whether they use a transmission provider's facilities or not. FERC only has the authority to assess rates when a customer and a transmission provider have chosen to do business with each other.”
As Elliott noted, by allocating costs to entities that aren’t customers of, and have no relationship with, a transmission provider, FERC is acting more like a taxing authority than a rate-setting authority.
“FERC makes a big legal leap in Order 1000 with respect to its authority to order transmission cost allocation over the use of all transmission facilities that provide transmission service—regardless of the contractual relationship that the beneficiaries may have with the transmission owner or operator,” said Sue Kelly, senior vice president of policy analysis and general counsel at APPA.
The cost allocation issue is “huge,” said Bogorad. “It’s a key element and could pull the rug from under the whole order in non-RTO areas.”
Right of first refusal. One of FERC’s policy objectives is to create more competition among builders of transmission, “to get more developers in the game,” said Elliott.
He noted that the incumbent transmission owners argue in their brief that eliminating their federal right of first refusal to build new transmission is unsupported by the record and exceeds FERC’s authority. They also claim it abrogrates their private contractual rights.
Although its implications are broader, this issue is most contentious in RTOs, said Bogorad. “Right of first refusal was part of the agreement setting up RTOs. Individual transmission providers in non-RTO regions don't have explicit rights of first refusal in their FERC tariffs.”
In their tariff agreement with an RTO, many transmission owners essentially said: I have the right of first refusal to build any facilities in my footprint. If you, the RTO, need a new transmission facility, I am the one to build it, said APPA’s Kelly. “FERC decided these agreements prejudiced the ability of new third parties to enter the transmission business.”
A number of state legislatures are moving to enact laws that would restore the right of first refusal, Kelly said.
Transmission planning and public policy. Order No. 1000 requires transmission providers to develop transmission plans considering transmission needs “driven by public policy requirements” of state and federal laws and regulations.
Petitioners offer two challenges to the “public policy” mandate of Order No. 1000. The first is one raised by APPA, NRECA, TAPS, and other parties, that the order does not comply with Congress’ specific directive in Section 217(b)(4) of the Federal Power Act. The section directs FERC to exercise its authority in a manner that facilitates the planning and expansion of transmission facilities to meet the reasonable needs of load-serving entities to satisfy their service obligations. “This directive is very specific,” Elliott said. “And it’s the only provision in the Federal Power Act that mentions transmission planning. Yet Order No. 1000 makes it an optional public policy requirement.”
“Our beef is this, Congress gave FERC specific obligations, and it wasn’t to say to transmission providers: it’s up to you to decide whether new facilities are needed or not to plan for the needs of load-serving entities, which include transmission-dependent utilities,” said Bogorad.
In addition, a number of other petitioners argue that the order’s public policy mandate is amorphous, arbitrary and capricious and contrary to law. “Our view is that it’s much better for utilities to make these decisions based on their own evaluation of demand,” Schneider said.
“We have no quarrel with public policies that call for utilities to buy renewables,” he said. “But we should let the utilities decide the most economical way to meet those goals, rather than letting FERC decide through the FERC-sponsored transmission plans.
“It’s pretty clear that FERC seeks to provide a funding mechanism for longer line facilities that—in its mind—provide some broad public interest benefit, based on a field of dreams philosophy,” Schneider said. “If you build it, good things will happen.
“Many of our members are very green, with ambitious renewable goals,” said Schneider. They have invested in local renewable resources and in the transmission that will bring these resources to customers. “They don’t think FERC is justified to make decisions on what investments are good from a public policy perspective.”
State sovereignty. Three public service commissions—Alabama, Connecticut, and Florida—and the National Association of Regulatory Utility Commissioners are arguing that FERC is “trampling on state sovereignty,” Elliott said. They say they have authority over transmission siting, construction and development.
Reciprocity. Publicly owned utilities and NRECA argue that the reciprocity provisions unlawfully tie their eligibility for transmission services from jurisdictional transmission providers to their agreement to abide by the rulemaking’s transmission planning and cost allocation mandates.
“FERC doesn’t have the legal authority to extend reciprocity to require municipal utilities to pay for regional allocation funding mechanisms,” said Schneider. He noted that the reciprocity rule was challenged years ago but the issue was never fully aired. “The case was not considered ‘ripe,’ but [the court said that] if and when municipal utilities are denied service by a jurisdictional transmission provider, they should complain to the court.”
FERC’s refusal to act under FPA Section 211A. In its brief filed May 28, the Edison Electric Institute argued that FERC acted arbitrarily in declining to invoke Section 211A of the Federal Power Act to extend the rulemaking’s mandates directly to non-jurisdictional utilities. They said the result is undue discrimination and preference in favor of non-jurisdictional transmission providers.
“Section 211A, known as ‘FERC-lite,’ gives FERC limited authority to regulate the transmission service of non-jurisdictional entities,” Elliott said. “EEI is arguing that the public power and cooperative community should be treated the same as FERC-regulated utilities in Order No. 1000.”
Scope of cost allocation. Finally, the International Transmission Co. is arguing that the cost allocation rules didn’t go far enough in enabling the cost of developing high-voltage lines to be allocated regionally—and beyond, Elliott said. “Under FERC’s rule, the costs can’t be allocated to neighboring regions without the agreement of those regions to bear the costs.”
APPA has petitioned for review of the public policy requirement and FPA Section 217(b)(4) issue, Kelly said. “We haven’t taken a position on most of the other issues because our members have diverse positions. We are taking up issues we can all agree on.”
Kelly called the transmission planning requirements a “third-rail issue.” In Order No. 1000, FERC ignores Section 217(b)(4), which says that the commission shall exercise its authority to ensure that load-serving entities—such as public power utilities—receive the transmission service they need to meet their service obligations, she said. “FERC doesn’t place the needs of load-serving entities like us very high on its list.”
On the other hand, Section 217(b)(4) makes no reference to public policy requirements. “Cost allocation is a big issue in the court appeal, because FERC never defined a public policy requirement,” Kelly said. “Everybody suspected that it referred to the construction of transmission for renewables. But FERC wouldn’t say so.”
Some states have renewable portfolio standards and might need transmission that helps them meet that requirement, she said. But she pointed to the example of Michigan, which has an RPS that favors in-state resources. “So they wonder why should the state pay for transmission that carries wind energy from North Dakota to Chicago?”
The Federal Power Act is not an environmental statute, Kelly said. “But FERC is trying to meet environmental goals with the act.” So the court will decide whether FERC's public policy requirement comports with the statue.
FPA Provision 211A. EEI has said FERC should extend its rulemaking to non-jurisdictional utilities. “We will actually be supporting FERC on this issue,” Kelly said.
All briefs will be filed by the end of this year, with oral arguments expected during the first half of 2014. But Kelly said it could be a while before the court issues a decision.
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