The Senate’s deadlock over carbon cap-and-trade legislation has not deterred FERC Chairman Jon Wellinghoff from an agenda bent on promoting renewable energy and fighting climate change.
Last fall, even as Congress dithered, FERC launched a landmark initiative that likely will lead to sweeping new rules for expanding the nation’s electric transmission grid, grounded on Wellinghoff’s belief in wind, solar, and green power resources.
The scope is breathtaking. The effort covers not only the process of transmission planning (e.g., local, regional, and super-regional), but also the heretofore sacrosanct precinct of cost sharing for new projects. Past columns have documented how planners and system operators have set utility against utility, state against state, and region against region through the unequal parsing of grid expansion costs (see “T Party Revolt,” October 2009.) But now FERC proposes to take grid planning and cost allocation to an entirely new level, attempting for the first time to account for the overall societal benefits that many ascribe to renewable energy, such as reductions in greenhouse-gas (GHG) emissions, cuts in oil imports, and greater national security.
At this stage, the commission has conducted several preliminary technical conferences around the country (e.g., Atlanta, Phoenix and Philadelphia), and has invited the power industry to comment on a series of seemingly harmless questions, such as:
• How should merchant projects be treated for planning purposes?
• Is there adequate coordination among planning entities?
• Is the project queue process hindering the ability to plan?
• Should each transmission provider hold an open season to solicit financial interest for new projects? and
• Are dispute resolution procedures adequate to address disagreements that arise in planning?
Other questions, however, are clearly pivotal, and reveal clues about what Wellinghoff might be thinking:
• Should prospective grid developers coordinate their projects in the interest of right-sizing to make the best possible use of available corridors?
• Should stakeholders address cost allocation matters over larger geographic regions? and
• How should non-quantifiable costs or benefits be identified, factored in, or otherwise weighted? (see Notice of Request for Comments, FERC Docket AD09-8, Oct. 8, 2009.)
These ideas leave no doubt that FERC intends very soon to issue a formal rulemaking proposal to set down concrete rules governing how power producers, utilities, and ratepayers must share the cost of constructing the grid superhighway. And if FERC acts, it may well prefer the highway-byway model of cost allocation, according to the load-ratio shares of transmission owners (TOs) operating within the regional footprint, with a beneficiary-pays method applied to local, low-voltage facilities, based on actual distribution load-flow factors (DFAX), but with costs spread widely (socialized) over broad geographic areas for extra-high-voltage (EHV) highway lines, such as ITC’s massive and controversial $12-billion Green Power Express project (www.thegreenpowerexpress.com).
Seeing the handwriting on the wall, the ex-FERC chairman James Hoecker, now a private attorney representing the non-profit WIRES trade association (Working Group for Investment in Reliable and Economic Electric Systems) has filed a formal petition asking FERC to show its hand—to come clean and issue a formal rulemaking on cost allocation for grid expansion (see Petition for Rulemaking, FERC Docket RM10-4, filed Nov. 12, 2009).
Yet, FERC might be walking into a minefield. Even as it ponders new rules, it must deal with the recent remand order handed down last August by the U.S. 7th Circuit Court of Appeals in Illinois Commerce Comm’n. v. FERC. That case struck down PJM’s FERC-approved policy for socializing costs through a “postage-stamp” rate across the entire RTO footprint for building new backbone EHV transmission lines of 500 kV or larger, explaining that FERC hadn’t provided enough evidence to justify its ruling. Now, in answering the court on remand, FERC will be called on prematurely to articulate policy on questions that will overlap or pre-empt its planned rulemaking case.
And DOE also muddied the water last June when it issued its funding opportunity announcement FOA0000068, providing some $80 million in stimulus bill grant money under the American Reinvestment and Recovery Act of 2009 (ARRA), for the study of experimental models and best practices for super-regional transmission planning processes at ERCOT and the Eastern and Western Interconnections. The Western Electricity Coordinating Council has applied for a grant, as has the Eastern Interconnection Planning Collaborative, a group of 23 NERC-certified planning entities representing about 95 percent of load in the Eastern Interconnection.
The DOE hadn’t yet announced the grant winners as this issue went to press, but Edison Electric Institute wrote in late November that DOE selections “should be made very soon.” FERC might end up setting its final rule on interconnection-wide, super-regional planning before DOE’s ARRA grant projects are completed and evaluated, thereby putting the cart before the horse.
It’s no surprise, then, why many question FERC’s audacity in jumping the gun before Congress decides on a national renewable portfolio standard, or passes a cap-and-trade or carbon tax bill granting authority to FERC to consider climate-change factors in regulating the transmission grid. Ohio stands as a prime example, where state utility regulators responded to FERC’s October inquiry with questions of their own:
“The Ohio commission is confused as to whether it is FERC’s goal to create a robust low-cost high-voltage grid to serve the country’s expanding needs, or whether FERC has separate societal goals such as the reduction of carbon emissions.” (Comments, FERC Docket AD09-8, filed Nov. 20, 2009.)
“This lack of clarity,” the Ohio commission added, “makes it problematic to arrive at specific responses to FERC’s inquiries … FERC should issue a policy statement clearly delineating its objectives … Such Policy Statement should also cite FERC’s statutory authority.”
The PSEG companies, headquartered in New Jersey, and which have benefited from PJM’s socialized cost-sharing for high-voltage (500 kV or higher) transmission lines located along the Mid-Atlantic Seaboard (see Figure 1), agree that FERC shouldn’t upstage Congress:
“Transmission planning,” writes Vilna Waldron Gaston, associate general regulatory counsel for PSEG Services, “cannot substitute for a national energy policy.” (Comments, filed Nov. 23, 2009.)
ELCON, representing the industrial consumer sector, suggests that any attempt to award points for the imagined but inchoate benefits of renewable energy without a green light from Congress represents no less than a perversion of rate-making principles and a violation of FERC’s statutory charge:
“FERC must resist the temptation to socialize the costs of new transmission.
“Political pressure for interregional transmission projects such as may be considered in conjunction with the development of renewable projects is not a reason to depart from the long-standing doctrine of just and reasonable rates.” (Comments, filed Nov. 23, 2009.)
But others, such as ITC Holdings, the nation’s largest independent transmission company, see this initiative as a natural extension of FERC’s present jurisdiction over interstate transmission rates and services, and lawful even without any formal guidance from Congress, as ITC noted in comments filed November 13:
“Regional planning,” writes ITC, “has too often been nothing more than the assembly of local projects proposed by individual transmission owners.
“ITC understands that FERC cannot enact climate legislation or a national renewable portfolio standard, but the commission can and should require transmission planning processes to achieve objectives beyond reliability and to look forward, rather than merely reacting.”
In testimony on the Kerry-Boxer climate legislation (S. 1733) presented October 27 before the Senate Committee on Environment and Public Works, Wellinghoff stated that Congress could “help clarify” FERC authority to allocate green-grid construction costs among project beneficiaries, but warned against any “unduly restrictive language” that would require FERC to calculate “the precise monetary benefits” of any new project.
Hoecker and his WIRES coalition concur on the point, and cite as an example a clause found in section 121 of the draft Bingaman bill (S. 1462, American Clean Energy Leadership Act), which would mandate cost sharing proportionate to the “measurable benefits” of any grid project. “This restriction,” writes WIRES President Paul McCoy (also Trans-Elect’s president), “is impractical and a detriment to investment.”
This notion of benefits is key for those in the power industry who want FERC to mandate a comprehensive, top-down, and wide-area grid-planning protocol that looks at the big picture, instead of just stapling together a roll-up collection of local proposals under a bottom-up analysis and calling it a regional or super-regional plan.
“Regional planning has too often been nothing more than the assembly of local projects proposed by individual transmission owners,” writes ITC.
Thus, as Mid-American Energy explains, multi-state EHV projects suffer under ISO and RTO planning regimes, which it calls “footprint-specific,” and too driven by reliability concerns and “near-term economic planning horizons.” (Comments, filed Nov. 23, 2009.)
Old Dominion Electric Co-op., a full-fledged PJM member, says what’s missing is a “feedback loop,” where the smaller, local planning agencies submit plans to a super-regional authority, and then have them returned with input and recommendations on how they can upgrade their project plans to better mesh with macro-scale projects.
But more important, green-grid proponents want FERC to consider factors such as those listed by the DOE’s Electricity Advisory Committee in its January 2009 white paper, Keeping the Lights on in a New World, such as greater fuel diversity, improved resource adequacy, lower and more stable rates, and access to new generation technologies.
ITC offers its own top-10 list of so-called unquantifiable benefits:
• Lower line losses;
• GHG emission reductions;
• Fewer out-of-market TLRs (transmission loading relief);
• Deferred need for new generation;
• Smaller requirements for planning reserves;
• Improved reliability and enhanced grid security;
• More competition and less market power;
• Higher capacity factors in wind-rich areas;
• Insurance against extreme contingencies; and
• Reduced need for foreign oil.
Such lists would overthrow the so-called beneficiary pays cost-allocation method, which is founded on traditional rate-making principles. But the Ohio PUC protests:
“There should be no non-quantified costs or benefits. Everyone should be charged in relation to the amount [of energy] they inject or withdraw.
“Failing this, any attempt to quantify is purely speculation.”
Industry consensus has emerged for at least a trio of special concerns raised by FERC, including viability of merchant grid projects, the value of open season solicitations, and whether to maintain the right-of-first refusal (ROFR) enjoyed by utility transmission owners (TOs).
Merchant Transmission: Most industry comments state no extraordinary problems for merchant transmission projects, except perhaps in the West, where many utility TOs remain vertically integrated, so that merchant projects must compete against utility-sponsored rate-based projects that enjoy guaranteed cost recovery. The two TransCanada merchant projects, Chinook and Zephyr Transmission, say they have been participating—without being legally required to do so—in regional grid-planning processes, led by WECC and other groups, but suggest that “the full panoply of regional planning need not and should not be imposed on the merchant transmission provider.”
Open Seasons: ITC advises FERC that an up-front open-season solicitation process to gauge financial interest from potential investors can work for certain projects, “particularly for DC projects where capacity is known [measurable] … contractual commitments for shares of that capacity can be made, similar to the natural gas pipeline model in which this concept arose.”
As Xcel Energy noted in its comments, open-season solicitations have helped identify ahead of time which projects are viable, and send a signal to the developer about how much capacity really is needed. But Xcel echoes ITC’s point regarding DC lines: “None of these situations to date have involved networked transmission facilities [AC lines] … embedded in an existing regional network.”
ROFR: Perhaps surprisingly, most commentators take no offense from the right-of-first refusal that FERC guarantees to utility TOs to accept responsibility within their own service areas to build a project approved by planners, though FERC has inquired whether such rights could preclude third parties from constructing lower-cost or superior facilities.
The California ISO (CAISO) points out, for example, that the Southwest Power Pool tariff employs a narrowly tailored ROFR that allows it to avoid the problem by forcing the incumbent utility TO to upgrade its project to match a third-party proposal.
CAISO adds, however, that not all grid developer cost projections can be accepted on faith. “Project sponsors,” the ISO writes, “could simply submit lowball cost estimates.
“A right of first refusal avoids placing the ISO in the position of having to evaluate competing projects based on potentially spurious cost estimates.”
Sunflower Electric Power, a Kansas G&T co-op and a staunch supporter of the green-grid superhighway, defends the ROFR concept as a catalyst for sparking collaborations between merchant developers and utilities. Sunflower adds that like other incumbent utility TOs, it owns existing rights of way and can fall back on relationships already established with landowners who might be affected:
“We have the boots on the ground.”
Consider the major 500-kV high-voltage transmission projects set for eastern PJM that figured in the August ruling by Judge Posner and the 7th U.S. Circuit Court of Appeals (ICC v. FERC) that struck down FERC Opinion 494. FERC had OK’d PJM’s proposal to spread the costs of the lines (see Figure 1) across the entire RTO footprint, thus imposing costs on Ohio’s Dayton Power & Light and Illinois’s Commonwealth Edison.
The court’s ruling sent the case back to FERC, with instructions to the commission to return with more convincing evidence to justify the so-called “postage-stamp” cost allocation. The remand proceedings now are underway, and illustrate how difficult it might prove for FERC to pursue its envisioned rulemaking, given the complications already brewing over this single dispute.
And time is of the essence.
On November 6, for example, a group of municipal townships in Northern New Jersey, joined by the Eastern Environmental Law Center and the ad hoc coalition known as “Stop the Lines!” (www.stopthelines.com) asked the New Jersey Board of Public Utilities to dismiss the pending application of Public Service Electric & Gas for a certificate of need for its proposed Susquehanna-Roseland 500-kV transmission lines (see right-hand upper corner of Figure 1), arguing that the line was no longer financially viable, given the 7th Circuit’s ruling that struck down PJM’s cost-sharing model—and PSE&G’s expected funding mechanism. (See Motion to Dismiss, N.J. BPU Docket No. EM09010035, filed Nov. 6, 2009.)
In a letter of clarification sent to the BPU a week later, on November 11, attorneys for the opponents asked for a stay pending PJM’s anticipated “retooling” of cost allocation rules during the remand: “Until this occurs, this Board and the parties cannot know who will pay how much for the Project … The folly of proceeding under such circumstances is only too apparent.”
Local newspapers from Northern New Jersey since have reported that BPU hearing commissioner Joseph Fiordaliso has set aside the motion, and that a BPU ruling on a certificate of need was due to be issued around Jan. 15, 2010. But the case stands as an example of the financial turmoil FERC must accommodate.
In addition, FERC must decide not only whether to defend the PJM model against calls for a retreat to the former beneficiary-pays regime, but also whether to go in the opposite direction—to extend RTO-wide cost sharing to even smaller-voltage lines, as Exelon is prepared to propose.
For background: In late October 2009, against the wishes of many utility members in eastern PJM, Exelon asked FERC to open the record in Opinion 494 via a paper hearing to admit additional evidence on costs, benefits, and pros and cons of PJM’s bright-line 500-kV cutoff for regional cost sharing. Exelon argues that the evidence in the case, even if repackaged and explained by FERC, never will convince the appeals court to relent on its August ruling. (See Motion to Establish Procedures on Remand, FERC Docket EL05-121, filed Oct. 29, 1009.)
Exelon argues that PJM had proposed its 500-kV postage-stamp method only after the date that administrative law judge Cowan had closed the trial record with the various parties still at loggerheads, and even had issued his initial decision before PJM sent its proposal to FERC as a last-ditch effort to win some sort of consensus among stakeholders. In essence, FERC’s Opinion 494 was more like an uncontested settlement than a clearly reasoned and argued case.
In fact, that’s one of Hoecker’s key points, featured in the WIRES petition noted earlier, asking for a rulemaking:
“This may illustrate the risks of relying so heavily on stakeholder processes that do not yield an adequate record and are not otherwise bounded by specific rate requirements” (Petition for Rulemaking, p. 7).
The Ohio and Illinois commissions have since sided with Exelon and still feel aggrieved by PJM’s cost-sharing formula, as it leaves them as net losers, having to spend millions of dollars to pay for the 500-kV lines (see Figure 1), without receiving any measureable benefits—let alone any of the unquantifiable kind.
Dayton Power & Light, representing only 2.5 percent of PJM’s retail load, has weighed in as well. DP&L points out that if the Court of Appeals upholds FERC’s Opinion 494 on remand, its share of socialized PJM 500-kV grid-expansion costs will exceed $120 million, boosting its annual transmission revenue requirement by half, from $40 million to $60 million—all for facilities from which it derives virtually no benefit, in a classic rate-making sense.
Dayton adds that this higher cost must be borne by fewer ratepayers, as its zonal peak load is falling from 3,740 MW in 2007 to a forecast (by PJM) of 3,368 MW for 2010.
“A significant portion of this reduction is not going to return any time in the near future,” writes Randall V. Griffin, chief regulatory counsel for the parent company DPL (Answer of Dayton P&L, FERC Docket EL05-121, filed Dec. 10, 2009).
“Several large businesses,” adds Griffin, “including the Delphi Corporation, General Motors Corp., DHL Express, and NCR have shut down their plants or largely eliminated operations in Dayton’s zone. Thus a 50-percent transmission rate increase will be shouldered increasingly by Dayton’s residential ratepayers.”
Exelon’s answer, however, isn’t to backtrack to the old beneficiary-pays formula, based on DFAX distribution power flows. No, that would spoil the party. Rather, Exelon’s remedy calls for bringing out a second punchbowl, and sharing costs across the region for all transmission lines down to the level of 345 kV. (Motion to Respond to Indicated Transmission Owners, p. 6, FERC Docket No. EL05-121, filed Nov. 10, 2009.)
Of course, this new cutoff would see the eastern PJM utilities now having to pay millions to support grid facilities in western PJM, since, as Exelon explains, 345-kV lines dominate in Ohio, Indiana and Illinois.
“Exelon wishes to make it abundantly clear in this pleading that we believe a 500-kV cutoff for socializing costs is unjust and unreasonable … Companies in western PJM have historically used a 345-kV architecture for facilities that perform a comparable function.
“We intend to submit evidence in the remand docket that using a cutoff of 345-kV would be just and reasonable.”