On July 21, the day after after this column went to press, the Federal Energy Regulatory Commission (FERC) was set to release its most important ruling in years—the widely anticipated yet much-delayed final rule on electric transmission planning and cost allocation.
And if it looks anything like what was initially proposed, the final rule should prove worth the wait.
Edward Krapels, founder of the independent transmission company known as Anbaric Holding LLC, and prime mover behind such historic grid projects as Neptune, Hudson, and Green Line, predicted as much when he commented on FERC’s proposal last September.As Krapels put it, “We believe the commission’s final rule that this NOPR foreshadows is likely to join the other seminal acts of Congress and of the commission that have compelled the American power markets to modernize and become more innovative.”
The rule comes more than 13 months after FERC issued the NOPR (notice of proposed rulemaking), in June 2010, and nearly two years after the commission staff first convened regional meetings in Philadelphia, Atlanta and Phoenix in September 2009 to gather ideas and advice. FERC’s apparent foot-dragging marks a sure sign of feathers being ruffled—not only across much of the power industry, but also in the halls of Congress.
Earlier this year, in February, Senators Bob Corker (R-Tenn.), Ron Wyden (D-Ore.), and Richard Burr (R-N.C.) together had fired a warning shot off FERC’s port bow:
Corker and his colleagues questioned many of the NOPR’s ideas, including the proposal that transmission planners should take account of public policy mandates, such as state renewable portfolio standards (RPS), or that planners might choose to socialize (spread) the costs of new grid projects across wide swaths of utility service territories and their ratepayers, under the supposed radical theory that “beneficiaries pay.”
Even before that, after the Wall Street Journal had run an adverse editorial in December 2010, the FERC chairman was forced to mend fences. He assured Journal readers that the commission wouldn’t discard the long-held “cost causation” principle affirmed in the landmark 2009 case of Illinois Commerce Commission v. FERC, in which the U.S. Court of Appeals for the Seventh Circuit had had asked FERC for a better explanation of why PJM could allocate costs to ratepayers across its entire grid footprint, from the Atlantic to Chicago, to pay for high-voltage transmission lines designed primarily to serve needs in Pennsylvania, New Jersey, Virginia, and Maryland. (That explanation, by the way, is still forthcoming.)
Nevertheless, Wellinghoff stuck to his guns, assuring the senators in March that reforms were still needed:
“I believe,” he wrote, “it is necessary to consider the significant changes that have occurred in the electric industry over the past decade … [such as] significantly increased regional and interregional trade in wholesale power.”
“This expansion in trading activity,” Wellinghoff added, “has altered the way the transmission system is used, with an increasing number of transactions occurring across longer distances.”
As proposed in last year, the NOPR had promised a number of new requirements for regional grid planning:
• Mandatory participation in regional transmission planning processes, governed by principles laid down in 2007 for grid planning by individual utilities.
• Consideration in regional grid planning of federal, state or other public policy mandates, as to be determined by the planners themselves,
• Reforms to encourage greater participation in regional planning processes by private, independent “merchant” and “non-incumbent” transmission developers—other than load-serving utilities or other jurisdictional “incumbent” transmission owners or service providers subject to an obligation to serve.
• Elimination of any federally granted right of first refusal (ROFR) that might give preference to incumbents in deciding who is to build new transmission projects. FERC would replace ROFRs with a “sponsorship” model that instead would guarantee the right to build to those developers who propose projects.
• Greater coordination between neighboring regional grid planning groups, through the signing of coordination agreements.
• Incorporation of cost allocation rules within regional planning processes. These rules would govern intraregional cost allocations for region-specific grid projects.
• Incorporation of cost allocation rules within bilateral and multilateral coordination agreements to be signed between and among regional planning groups. Such inter-regional cost allocations apply to extensive new grid projects spanning more than one region. (See, Trans. Planning & Cost Allocation for Trans. Owning & Operating Pub. Utils., Notice of Proposed Rulemaking, FERC Dkt. RM10-23, June 17, 2010.)
Given that readers will have seen FERC’s final rule long before discovering this column, let’s take a stab at what FERC was thinking, and where it might want to take the industry.
For example, some may see FERC’s NOPR as evidence of a green agenda, or another move in a series of moves designed to strengthen RTOs at the expense of state regulators. Yet there is much more at work.
Above all, the ground has shifted. Transmission service, the bread and butter of FERC’s traditional authority, is no longer where the money is. The action (and the money) is now in the business of building transmission lines, as shown by reports from the Edison Electric Institute (EEI) that shareholder-owned utilities invested more than $37 billion (real 2009 dollars) in transmission from 2004 through 2008, and were projected thereafter to invest another $54 billion in transmission over the next five years, from 2009 through 2013. Yet a well-known study from 2009 had suggested it could take $80 billion and 15,000 miles of new lines in the Eastern Interconnection simply to support 20 percent wind integration by 2024—and even a 5-percent wind penetration would require10,000 miles ($50 billion) of added EHV lines (extra high-voltage).
The electric industry today stands where the natural gas industry stood in the early and middle part of the 20th century: characterized by huge energy resources located in remote and unpopulated producing regions, with a need to transport that energy to heavily populated consuming regions.
For the natural gas industry, Congress passed the Natural Gas Act, which gave authority to the Federal Power Commission to certify and regulate natural gas pipeline construction. That put the feds in charge of where the money was.
Not so for electricity. The Federal Power Act contains no significant grant of regulatory authority over siting and construction of transmission lines. That creates a vacuum that FERC aims to fill.
Yet, as it turns out, even FERC’s surrogates, the RTOs, don’t quite have all the necessary tools to plan and site transmission projects. Engineers can’t plan the grid without knowing the extent and location of desired resources—something that RTOs can’t guarantee, because RTOs don’t enact RPS laws; states do. RTOs don’t issue siting permits; states do.
Thus, FERC’s proposal to require regional transmission planners to consider public policy as a governing criterion, in addition to reliability and economic congestion, aims to recapture the half of the process that went missing when transmission planning migrated from utilities and state commissions to federally regulated RTOs, but generation resource planning was left behind, still governed by state law.
And so FERC’s NOPR can be seen not only as a bid to carve out a federal role in the regulation of the transmission construction sector, but to do so in the most efficient way possible, by reuniting grid planning and generation resource planning under one roof—but at the regional level.
Transmission planning typically takes account of a universe of factors, such as future load, growth, changes in generation dispatch, locational marginal prices, loop flows, the location of new generating units, the possible retirement of existing units, other transmission expansions, and existing and new interconnections with neighboring grid systems.
But consider this question: Should transmission planning allow for selection of a non-transmission solution, such as energy storage or demand response?
Some would say yes—certainly FERC would—but many of the vertically integrated, load-serving utilities of the Southeast would likely say no.
One such possible example would be the Southern Company, with its operating utility subsidiaries Georgia Power, Alabama Power, Mississippi Power, and Gulf Power.
As Southern explained in comments filed at FERC in response to the initial NOPR, a transmission plan is exactly that and no more. By contrast, resource options, such as fossil generation, nuclear, wind or solar, pumped storage, and even demand response, are committed through RFP solicitations conducted under state-mandated resource planning processes. Specific resources win inclusion in the resource plan by gaining a long-term purchased power contract or similar agreement that fixes an obligation to serve load. Once certified as part of this state-governed plan, the resource then becomes known fact and a verified data input to serve as a starting point for the transmission plan.
In fact, as Southern noted, a non-transmission solution can be considered in its transmission plan only to the extent that it addresses problems linked directly to transmission line power flows, loading, and congestion. For example, a transmission plan could consider need for a local must-run generation plant to relieve congestion or perhaps supply reactive power, but not in the sense that the plant was needed to support a public policy requirement. That, Southern explained, would bypass the state-mandated RFP process, which itself is structured to honor any applicable public policy directives imposed by state or local laws and regulations:
Thus, Southern Company in its comments professes not even to know how it would actually comply with a FERC rule requiring it to participate in a regional grid planning exercise that would consider public policy as a mandate. In the Southeast, “policy” is something dealt with before you get to transmission planning. Otherwise, if you don’t know what resources are to be procured, and where, how would you plan the grid?
The NOPR, said Southern, “would jettison the current paradigm in the Southeast … in favor of some sort of speculative process.”
Curiously enough, the vertically integrated utilities of the Southeast find a certain sort of ally in New England—an RTO area with centralized energy markets—and where utilities and regulators generally tend to favor FERC’s ideas, but worry that unbridled consideration of public policy in transmission planning could lead to approval of high-cost, long-haul grid lines to import distant renewables, while ignoring the less transmission-intensive alternative of delivering closer wind energy from just offshore.
This concern leads New England interests to an opposite conclusion, however: that a key reason for integrating policy criteria and generation resource planning with grid planning must be to that transmission planning remains a “least-cost” process.
Thus, the Massachusetts DPU (the state utility commission) had filed comments with FERC embracing the policy criterion, but warning that states must be afforded “substantial deference” in the identification and consideration of their own policy goals in the planning process.
And the Ohio PUC took a similar tack, insisting that each state involved in a transmission planning region must have its own voice and veto:
“If FERC is to base transmission cost recovery on state energy public policy mandates, each individual state must be vested with authority to review and approve as accurate [any] assumptions made regarding that state’s energy policies.”
In fact, the industry’s reaction to FERC’s initial NOPR tends to suggest that the greater the reliance on public policy as a criterion for transmission planning, the closer the industry will move toward regional regulation.
For example, ISO New England in its comments suggested solving the problem by turning to a regional state committee, both to define what public policy is, and specify resource needs in great detail for the engineers and stakeholders who actually craft the transmission plan:
“The regional state committee would make this identification in writing and provide an appropriate degree of specificity … for example, by identification of the location of the existing or proposed generating resources desired to be integrated into the regional bulk power system, or by identifying a sufficiently formulated conceptual transmission project.”
Interestingly enough, this New England vision produces a sort of state-directed resource planning process—just as Southern Company touted in its comments—but in a federally regulated setting. That is, the resource planning adheres to state aims, but it gets done within the confines of a federally regulated and regional planning process.
And PJM in fact argued that without integrating state policies into the federally regulated regional process, grid planning becomes speculative and loses its bearings.
“To be actionable,” PJM argued, federal or state policymakers must articulate an identifiable public policy in the form of “assumptions, criteria and metrics” that a transmission planner can implement.
For example, as PJM asks, if the transmission cost of developing wind energy exceeds a state’s penalty for failing to satisfy its renewable portfolio standard, “should the transmission planner continue to plan the identified transmission facilities?”
And, in a similar vein, argues PJM, a planner would want to know whether a particular state would intend to develop renewable resources from within its own borders, even if the costs are significantly higher than out-of-state wind resources.
“In the end,” writes PJM, under a ‘build it and they will come’ approach, the transmission planner is trying to predict how the market will respond.
“This is a very different paradigm [from] the one used today.”
In fact, PJM argues that public policy mandates will prove actionable in regional transmission planning only if all parties are synchronized:
“The regional nature of planning and the interstate nature of the grid seem to point to the need for regional compacts among states to couple shared policy objectives with … siting and permitting authorities.”
Of all the NOPR’s reforms, the proposed elimination of ROFRs drew by far the most outcry. On one hand, the commission sought to calm the waters to assuring the industry that in killing off any federally granted ROFRs, it supposedly wouldn’t pre-empt any state-imposed right or obligation to build. Yet this balancing act on first glance would appear difficult to maintain.
For example, many states will grant a certificate of public convenience to authorize transmission line construction only to regulated load-serving retail utilities. So FERC might strike an express ROFR from an RTO tariff, only to find that incumbent transmission owners retain a de facto ROFR under state statutes. To do anything more, FERC would require some sort of grant from Congress to exercise jurisdiction over transmission line siting and construction.
Yet FERC already exercises some small measure of authority over transmission siting and construction, in the form of its generation interconnection rules adopted some eight years ago in Order 2003. Moreover, that authority was upheld in 2007 as a “practice affecting rates,” as the court decided that FERC rules setting terms, conditions, and procedures for generator interconnections bore a close enough relationship to the commission’s recognized statutory authority over interstate transmission service. (See, NARUC v. FERC, D.C. Cir., 475 F.3d 1277.)
Should that reasoning apply once again to justify the commission’s claimed authority to ban ROFRs and level the playing field in the transmission construction sector?
Many seem to think not, based upon a different ruling from the same court, issued in 2004, that struck down FERC authority relating to RTO boards of directors as not sufficiently connected to a “practice affecting rates.” (See, CAISO v. FERC, D.C. Cir., 372 F.3d 395.)
In fact, some have pointed to FERC’s Order 2003 interconnection policy as a continuing sore spot that could undermine attempts to introduce real competition to grid siting and construction.
For example, while FERC OK’d a revised transmission planning process (RTPP) last December for the California ISO—a regime designed expressly to replace ad hoc, project-based planning with an open and bottom-up needs-based process—concerns remain that FERC Order 2003 still provides a way for incumbent utility transmission owners to bypass the RTPP and claim rights to build the lines sought by power plant developers to connect their new generating units to the grid.
Thus, on April 29, California Public Utilities Commission president Michael Peevey took time to write to California ISO President and CEO Yakout Mansour, complaining that “numerous projects submitted for consideration by independent transmission developers have all been rejected as unnecessary,” even as utilities were using the generator interconnection process to capture grid construction deals from plant developers.
“The net result,” Peevey wrote, “appears to be a total reliance on IOU transmission development and a significant step back from the use of competitive solicitations for transmission projects, despite the … revised transmission planning process that was laboriously crafted in consultation with stakeholders.”
“This,” Peevey added, “is disappointing.”
Meanwhile, the NOPR would leave FERC’s generator interconnection rules exactly as they are.