Last year, when a federal court rebuffed the Federal Energy Regulatory Commission (FERC) on its efforts to reward electric utilities with a higher return on equity (ROE) as a bonus for joining a regional transmission organization (RTO), the judge ruminated on the difficulty of designing incentives for transmission owners: “Calculating this rate [ROE] would be relatively easy,” the judge declared, “if a utility’s interest in its grid—its business as a transmission owner (TO)—were publicly traded.”
However, as the judge then noted, “There are no publicly traded independent pure electric transmission companies.” (See, Kentucky PSC v. FERC, D.C. Cir., Feb. 18, 2005, 397 F.3d 1004.)
But what a difference a year can make. Just last summer, on July 26, 2005, according to reports, the standalone transco known as International Transmission Co. (a spin-off from Detroit Edison) launched an initial public offering (IPO) of a minority stake in the company. That IPO, which reportedly garnered $287.5 million on 12.5 million shares (a minority stake of approximately one-third—the balance of 33.22 million shares remaining in private hands), had exceeded the then current value of all of ITC’s shareholder equity as of the end of the prior quarter, according to the IPO prospectus. Given this success, the idea of a publicly traded, for-profit company devoted entirely to the electric transmission business might soon become commonplace. And to help the grid business get on its feet, Congress declared last fall in section 1241 of its landmark Energy Policy Act legislation (EPACT) that FERC must soon establish “incentive-based rate treatments for the transmission of electric energy in interstate commerce.” The concept of transmission as a business was now ensconced in the federal statute books.
Within weeks, FERC itself had proposed a new set of regulations, under the new section 219 of the Federal Power Act, explaining in broad outline how it might approve generous financial incentives for new investments in transmission—incentives once dubbed as “candy.” Citing widely available data, the commission reiterated how transmission investment had declined in real dollar terms throughout most of the 1970s, ’80s, and ’90s (despite huge increases in load), and how the Edison Electric Institute (EEI) had estimated that capital spending on the grid “must increase by 25 percent, from $4 billion annually to $5 billion annually,” to ensure system reliability and to accommodate wholesale electric markets.
“The 2.5 percent growth rate in transmission mileage since 1999,” the commission added, “is insufficient to meet the expected 50 percent growth in consumer demand for electricity over the next two decades.”
Armed with such numbers (and impelled by Congress), FERC said it would consider awarding incentives through a number of well-known rate-making techniques:
• accelerated depreciation;
• hypothetical capital structures;
• single-issue rate cases;
• cost recovery for projects abandoned or canceled for reasons outside the utility’s control;
• deferral of cost recovery to a future date for utilities under a rate freeze (or if forced to wait an inordinate time between rate cases);
• current expensing (instead of capitalization) of pre-commercial costs for permitting or site certification; and
• rate base recovery of 100 percent of prudent construction work in progress (CWIP), rather than accrual of an allowance for funds used during construction (AFUDC).
Most importantly, however, the list of rewards in the notice of proposed rulemaking (NOPR) also included an ROE “sufficient to attract new investment” and, as had failed to pass muster with the appellate court judge, a higher ROE allowance for utilities joining an RTO. (See, NOPR, FERC Docket No. RM06-4, issued Nov. 17, 2005.)
As of mid-January, the new NOPR had spawned more industry comment than just about any other FERC proposal in recent memory. Much of the response appeared extremely favorable, but therein was the problem. As the Pennsylvania PUC had noted, “it is difficult to argue against the abstract notion [of] new transmission investment.” Yet, as the PUC also noted, “transmission congestion is not always best relieved by construction of new or additional transmission facilities.”
Many questioned the lack of any objective standards, benchmarks, or cost-benefit analysis defining what utilities or developers would need to achieve or prove to qualify for incentives. FERC’s “asymmetric” plan, they complained, was lacking penalties for all sorts of possible ways in which utilities might fail to follow through on commitments for investment or development. It appeared to many that FERC intended to reward utilities simply for carrying out “good utility practice”—for doing no more than satisfying a pre-existing legal obligation to construct and maintain transmission networks as a monopoly asset, capable of meeting all reliability standards and ensuring adequate service to consumers at least cost.
Representing NASUCA, the National Association of State Utility Consumer Advocates, Ohio Consumer Counsel Janine L. Migden-Ostrander argued that FERC had “ignored” parts of the EEI survey that showed a reversal of the trend since 1999, with annual expenditures on grid expansions now said to hit about $6 billion in calendar 2006—higher than FERC’s figure of $5 billion required, and high enough, perhaps, to dispense with any need for “candy.” She warned that incentives easily could outweigh benefits, and as an example offered an analysis that NASUCA witness Matthew I. Kahal had performed on a policy statement on grid expansion proposed by FERC only a few years earlier (FERC Docket No. PL03-1), showing that similar incentives could cost consumers nationwide as much as $711 million a year, or $13 billion over a nearly 20-year time frame. (See NOPR, Comments of NASUCA, p. 3, filed Jan. 11, 1005.)
Nevertheless, there remain larger concerns. The problem lies in EPACT’s call for incentives not only to ensure reliability, but also to benefit consumers by “reducing the cost of delivered power by reducing transmission congestion.” This requirement appears to sanction incentives for grid expansions that are commonly viewed as optional or “economic.” In RTO parlance, an “economic” grid expansion is treated as a merchant endeavor—a private asset dedicated to profit with no public interest characteristic that might require certification from regulators.
In essence, EPACT’s reference to congestion relief compels regulators to take a broad regional or even national view of the value of a given grid investment. It forces regulators and utilities to think more in terms of moving lignite-fired power from, say, North Dakota to New Jersey, and what that would save in fuel, than in terms of how reducing the chance of an outage in, say, Princeton, would improve quality of life. This broad regional view implies an entirely different set of winners and losers. And it clashes in particular with the needs of state regulators, who modify retail rates only rarely (and then based on zonal averages rather than nodal differentials), and who see the prevention of local outages as the prime directive.
At LG&E Energy, now known as E.On AG, which recently acquired Powergen plc, the parent company of utilities subsidiaries Kentucky Utilities and Louisville Gas & Electric, Vice President Michael Beer commented that the NOPR could clash with state statutes forcing utilities to serve retail native load at least cost, and to invest in transmission not to accommodate wholesale markets or long-distance regional exports and imports, but rather, only if it will serve local needs .
Also, the incentive scheme that EPACT imposes on FERC may well spell the end for the rate design known as license-plate pricing. This pricing design allocates grid expansion costs only to those consumers native to the smaller utility-specific service territory where the investment is located. In that manner, Ohio ratepayers would pay the entire cost of a new 760-kV line designed to help import North Dakota power to New Jersey to help East Coast consumers save money. License-plate pricing famously ignores the benefits that grid expansion can foster between widely dispersed geographic market areas. It spells trouble for any federal policy that awards incentives for investment designed to maximize such efficiencies, but then allocates their costs entirely within narrow boundaries. By contrast, it likely would encourage greater use of postage-stamp pricing, which spreads grid expansion costs across a larger footprint, or some other form of rate design that includes at least some sort of allocation factor that treats the grid as a sort of superhighway, designed for long-haul power movements.
Evidence of this conflict already can be seen building in cases recently pending at FERC that involve allocations of grid upgrade costs within several RTOs.
Putting aside for the moment the question of cost allocation and pricing for upgrades, the grid-incentive NOPR has revealed a strong industry preference for revamping the discounted cash-flow (DCF) method that FERC now uses to set ROE for transmission owners.
Ameren, Trans-Elect, Progress Energy, Southern California Edison, and others have called on the commission in no uncertain terms either to scrap the DCF method, or at least consider alternatives.
Writing for Southern Company Services, counsel Andrew Tunnell notes a strong disconnect between models such as DCF, founded on identification and calculation of specific variables to explain stock price growth, and what is actually observed in stock markets. He notes also that while FERC’s DCF model often has produced returns under 10 percent (akin to the interest rate stated in the commission’s regulations on rate refunds), the S&P 500 Electric Utility Stock Index in 2004 earned an overall 13.9 percent. He adds that FERC at least should adjust its ROE model—applied currently to book value—to reflect an industry average market-to-book ratio of 2.47 to 1, according to the S&P 500 Utility Index as of year-end 2005.
At Progress Energy, Deputy General Counsel Len Anthony suggests that FERC ought to consider restating the incentive adder in terms of dollars per kilowatt-month of new added grid capacity, rather than as a bonus to ROE allowance (though the effect would be the same).
By contrast, FERC’s idea of using hypothetical capital structures in rate making, with higher equity ratios, has not fared so well.
Representing the Transmission Access Policy Study Group, attorneys Robert McDiarmid and Cynthia Bogorad (Spiegel & McDiarmid, in Washington, D.C.) suggest that skewing capital structure to fashion a financial incentive represents a distortion of reality, since markets treat the transmission business as lower-risk than generation, so that a stand-alone transco, in the real world, actually would be highly leveraged, and would sport a thinner equity ratio than a traditional utility.
For example, McDiarmid and Bogorad note that the capital structure for ITC’s parent company contains less than 29 percent equity, and more than 71 percent debt. (They add that as of Jan. 3, 2006, ITC’s price earnings ratio was 29.21, and its market-to-book ratio was 3.46, according to data taken from the Yahoo Finance Internet site.)
If FERC’s plan suffers an Achilles’ heel, it’s that utilities cannot pocket any federal bonus for grid investment or RTO participation until state regulators OK that extra cost in retail rates. True, the filed-rate doctrine ordinarily requires state PUCs to passthrough any charge approved via FERC tariff, but you never know—as shown by a case now pending in the upper Midwest, within the RTP footprint of the Midwest Independent System Operator (MISO).
On Dec. 21, the Minnesota PUC agreed to allow Minnesota Power (Allete) and Northern States Power (Xcel) to use the state’s fuel clause adjustment (FCA) law to recover certain net costs that MISO had billed the two utilities under its “day 2” market regime, but not other costs that appeared to fall outside the scope of the FCA. (See Minn. PUC Docket Nos. E-002/M-04/1970, Dec. 21, 2005.)
The ruling shows clearly the potential difficulty in trying to use state PUC rate cases to reconcile and recover FERC-approved costs unique to special federal programs created through industry restructuring. The items involved in the case had included: (1) net fuel-related costs incurred in buying and selling power through the day-ahead market; (2) administrative “uplift” charges related to MISO management of uncollectible accounts of defaulting traders; and (3) net “congestion” costs related to LMP differentials in nodal energy prices, and activity relating to FTRs (financial transmission rights). Citing the limited scope of the FCA law, the PUC had denied authority to recover the congestion costs through the FCA. Yet these congestion costs had represented nothing much more than LMP differentials in nodal energy prices—a logical component of any FCA charge—as MISO had explained in a petition for rehearing filed with the PUC.
As of early February, the PUC reportedly was reconsidering the matter. Yet, shortly after the December ruling, Minnesota Power notified MISO of its intent to withdraw from RTO membership in a year’s time, and Xcel told MISO its continued participation in the RTO was “under review.” (See NOPR, Comments of TAPS, pp. 39-40, note 94, filed Jan. 11, 2006. See also, Petition of MISO for rehearing, filed Jan. 10, 2006, Minn. PUC Docket No. E-002/M-04-1970.)
Last month FERC struck down a proposal by the MISO RTO to adopt a postage-stamp method to allocate 20 percent of the cost of “reliability” grid upgrades at lines 345-kV or greater across a broad region. Moreover, it directed its staff to convene a technical conference to examine the issues raised by the MISO proposal, including questions about regional cost sharing for grid upgrades undertaken for purposes of reliability. (See Docket No. ER06-18, Feb. 3, 2006, 114 FERC ¶61,106.)
Contrast now FERC’s dissatisfaction with the MISO design versus a similar but more lenient plan in the Southwest Power Pool.
Thus, last April, FERC approved a proposal by Southwest Power Pool to adopt a region-wide, postage-stamp cost allocation to apply to a greater portion—33 percent—of the revenue requirement of any grid network upgrades worth more than $100,000. The remaining two-thirds of the cost in the power pool would be allocated locally to zones (typical license-plate pricing), based on each zone’s share of the incremental megawatt-mile benefits accruing to the zone, as determined through a formula to calculate the power flow impacts caused by the upgrade. (See FERC Docket Nos. ER05-652, et al., Apr. 22, 2005, 111 FERC 61,118.)
In a third case, FERC is considering whether to retain the current system of “modified zonal rates” for transmission access service in the PJM RTO (license-plate pricing with zones altered somewhat from strict utility service territory boundaries), or whether to adopt some sort of regional sharing of transmission plant costs to reflect the economic benefits accruing to PJM from the recent addition of American Electric Power and other Midwestern utilities to the RTO footprint.
Two groups—AEP and Allegheny Energy on one hand, and Baltimore Gas & Electric and Old Dominion Electric Co-op on the other (the so-called “Transmission Owner Proponents,” or TOPs)—have offered competing plans, with each plan described as a “highway-byway” model. That is, each would adopt some degree of regional cost sharing for the costs of highways (large-capacity transmission lines), and fold-in the cost of byways (smaller-sized lines) within a typical, license-plate zone. Each plan would divide highways from byways at a different capacity level, but under each plan, loads in all zones would pay a uniform, RTO-wide highway charge to provide RTO-wide recovery of high-voltage transmission service costs. (See AEP Transmittal Letter, filed Sept. 30, 2005, and Summary of Prepared Direct Testimony of Ralph Bourquin, Jr., on Behalf of Transmission Owner Proponents, filed Sept. 30, 2005, FERC Docket No. EL05-121.)
By contrast, take a look at the current fight within PJM over RTO-directed allocations among license-plate pricing zones to recover costs for grid upgrades mandated by the RTO through its RTEP process (Regional Transmission Expansion Plan).
In particular, in that case, consider the protest filed by Robert Patrylo, CEO of H-P Energy Resources LLC, on how PJM’s RTEP upgrades address many localized reliability problems but fail completely to deal with massive problems on three east-west 500-kV lines that form the backbone for macro-scale economic exchanges of power between the Midwest, on one hand, and Maryland, Washington, D.C., and Virginia on the other.
According to Patrylo, LMPs associated with congestion across these lines typically run about $44/MWh to the west, and about $83 to the east. “This is an enormous price differential,” he notes, “that shows no sign of abating.” (See Protest of H-P Energy Resources, LLC, filed Jan. 26, 2006, FERC Docket No. ER06-456.)
In short, Patrylo’s protest shows how RTO-mandated reliability upgrades, coupled with zonal cost allocations, can easily mask more fundamental inequities involving broad-based regional differentials in the delivered price of power.
In this case, even the Maryland Public Service Commission (PSC) has weighed in. In the PSC’s recent 10-year plan (2005-2014) for Maryland’s electric companies, the state commission observes that “the highest LMPs in all of PJM have bulls-eye centered near Frederick County, Maryland.”
Says the Maryland commission: “The PJM transmission system cannot support the energy imports that eastern PJM, and central and eastern Maryland in particular, desire to receive.”