News Digest

Fortnightly Magazine - January 1 2001


News Digest


State PUCs

Retail Marketing Credits. As the Federal Energy Regulatory Commission pondered remedies for volatility in California's wholesale power markets, the state PUC was considering how much the state's three major investor-owned electric distribution utilities (UDCs) must spend on power supply procurement and retail marketing for the benefit of their standard-offer default customers, and thus how much to add to the "PX Credit" that is subtracted from bundled rates to determine the wires-only charge that UDCs assess to customers that choose a competitive retailer for generation supply.

As of late November, three proposed decisions were pending before the full commission, one issued by Administrative Law Judge Robert Barnett (with lower credits more favorable to UDCs), two more issued by Commissioners Josiah Neeper and Richard A. Bilas (with credits as much as five times higher, and thus more favorable to competitive retailers). Each decision would assess credits higher than proposed by the three UDCs-Pacific Gas & Electric (PG&E), Southern California Edison (SCE), and San Diego Gas & Electric (SDG&E)-but lower than suggested by the Office of Ratepayer Advocates (ORA) or the Alliance for Retail Markets (ARM)....

The UDCs proposed low credits, claiming that their obligation to serve as supplier of last resort made it impossible for them to avoid a significant amount of marketing or power procurement costs. But Commissioner Neeper warned against that view: "It is not correct to assume that the utilities' default provider status will always be required, and thus that certain procurement costs are in the long run unavoidable." .

Distributed Generation. In updating its current rules, New York barred electric utilities from requiring any sort of insurance coverage as a condition for interconnection by electric customers of distributed generation facilities of 300 kilovolt-amperes or less.

Instead, the commission will leave it up to private markets to craft insurance arrangements for small-scale generators that install DG plants.

The commission also will allow customers to lease their on-site DG units to third parties, and will not limit the standard interconnection contract to a specific term (e.g., five years), despite hard lessons learned from cogeneration contracts that locked in rates at out-of-market levels.

"Standardized [DG] contracts do not include payments for energy," said the commission. "It is not unreasonable for us to require utilities to enter into interconnection agreements that last for the lifetime of the DG unit." .

On-Site Solar. By contrast to New York (see above), Florida will require proof of liability insurance no less than $100,000 before allowing electric customers to interconnect photovoltaic generating systems smaller than 10 kilowatts under a pilot program with Tampa Electric.

The utility will pay customers 9 cents per kilowatt-hour for their solar generation, or 1 cent less than the premium price for the solar-generated power under a "green" energy program OK'd for Tampa Electric back in September. .

Electronic Data Interchange. New York invited comments on proposals offered on Oct. 10 by the state's EDI Collaborative for using Electronic Data Interchange in business processes for enrolling and removing retail direct access customers. .

Performance-Based Rates. Rejecting arguments from power producers, industrial customers, and the state's public advocate, Maine found no need to incorporate a mechanism to share excess earnings with ratepayers in approving a seven-year, performance-based, price index formula to set rates for electric transmission and distribution for Central Maine Power.

Instead, the PUC set a high productivity figure as an offset to the inflation adjustment allowed under the formula. The offset will equal the inflation rate in 2001, and rise from 2 percent to 2.9 percent by 2007-nearly double the offsets proposed initially by CMP..

Standard Offer Entry/Exit Fees. Maine opened an investigation of entry or exit fees for standard offer power supply service, citing "gaming" threats posed by customers who switch back and forth between competitive and SO services. The PUC posed several questions for comment, such as:

  • Cause of Gaming. Should the rule address only those problems that stem from market price fluctuations, or should it consider problems that stem from ratemaking formulas used in calculating SO rates?
  • Type of Fee. Require an "opt-out" fee (payable if a customers leaves SO service too soon), or instead charge an "entrance" fee on return to SO service?
  • Revenue Allocation. How to apportion revenues from opt-out fees if the identity of the SO provider changes between the time a customer signs up and later leaves?
  • Aggregation Deals. How to handle the case when customers enroll in SO service as an aggregated group, but then leave SO service individually? .

Studies & Reports

Transition to Deregulation. The "prolonged and muddled transition" from regulation to market control of the North American electric power industry, including recent highly publicized brownouts and volatile prices, has raised public concerns about the industry's ability to deliver reliable service at affordable costs, according to a report by Cambridge Energy Research Associates and Arthur Andersen.

The report, "Electric Power Trends 2001," says that potential consequences of the transition difficulties include the likelihood of renewed political intervention and re-regulation that could worsen transmission gridlock and increase the industry's valuation gap. Contact Lauren Laidlaw at 617-441-2604 or

Wisconsin Power Markets. Power producers may well be able to exercise market power in Wisconsin (especially in northern Wisconsin and Upper Michigan), thereby frustrating development of retail electricity competition in the state, even after new transmission capacity is added, according to a study commissioned by the Wisconsin PSC and conducted by the consulting firm of Tabors, Caramanis and Associates of Cambridge, Mass.

Yet the report adds that a workably competitive market would not produce stranded costs or adverse effects on employees at generating facilities, but would lead to "significantly lower rates."

The authors suggest two remedies: (1) Require Wisconsin Electric Power Co. to divest its generation assets among three separate independent owners, and (2) force plant owners to dedicate a significant portion of their capacity to fixed price contracts for retail customers taking standard offer service. . -L.A.B., P.C.

Gas Franchise Forfeiture. North Carolina opened an inquiry on whether Frontier Energy LLC has made enough progress to initiate gas distribution service in newly certificated and previously unserved areas to avoid forfeiture of its franchise for lack of service. .

Gas System Outages. Citing potential harm to customers, Wyoming declined to fine K N Energy for a "series of preventable human errors" that regulators said had represented "grossly negligent and unjustifiable conduct" and had led to a total failure of the utility's retail gas distribution network for some 10,000 retail customers (business and residential) in the city of Laramie, back on July 18. Instead, the commission told K N to make improvements and supply numerous followup reports, and denied rate recovery of expenses incurred by the company (about $317,000) to shut down and relight the system during the emergency. .

QF Cost Recovery. Montana denied a request by Montana Power Co. to boost the generation component of rates to recover higher purchased power prices paid to qualifying cogeneration facilities, saying the utility failed to make the requisite showing of "irreparable financial harm," as required to earn an exception from the rate moratorium imposed under the state's electric restructuring legislation that froze rates to levels in place on July 1, 1998. . —L.A.B.

Public Benefits Programs. New Hampshire issued instructions for designing, evaluating, and funding public purpose programs for electric utilities and customers:

  • Low-Income Assistance. Rejected a flat rate discount in favor of fluctuating payments designed to cut electric bills to 6 percent and 4 percent of income, respectively, for heating and non-heating customers. .
  • Energy Efficiency. OK'd a cost-benefit test with a 15 percent adder for nonquantifiable environmental benefits, and told electric utilities to develop PAYS programs ("Pay As You Save"), with program funding costs repaid out of bill savings, so as to eliminate up-front costs or split incentives. .
  • System Benefits Charge. Allocated revenues from the 2-mill system benefit charge on a 60-40 basis between two types of public benefit programs-i.e., $0.0012 per kilowatt-hour for low-income assistance, and $0.0008 per kilowatt-hour for energy/conservation programs. .

Single-Retailer Tariff. New York OK'd a single-retailer natural gas tariff for Rochester Gas & Elec. Corp., whereby RG&E will act as a wholesaler only, providing distribution service at wholesale to unregulated retail marketers, who in turn will repackage the distribution service with the gas commodity to retail gas customers, who will look to the unregulated marketer for all billing and merchant functions. .

Securitization Bonds. Regulators in Michigan and Connecticut authorized Detroit Edison, Consumers Energy, and Connecticut Light & Power to issue bonds to securitize stranded and regulatory assets.

  • OK's bonds to finance $1.8 billion of regulatory assets, with a surcharge of $0.004239 per kilowatt-hour to recover the assets. .
  • OK's bonds to finance $468.5 million in regulatory assets, with finance surcharge of $0.0025 per kilowatt-hour to recover the assets. .
  • OK's rate reduction bonds to securitize some $1.5 billion in regulatory and stranded assets. . —L.A.B.

Stranded Costs. In an open meeting held Nov. 1, the Texas PUC suggested that electric utility ratepayers should be allowed to benefit in some way if electric utilities in the state might end up with "negative" stranded costs (assets worth more than book value), even though state law does not allow for calculation of such negative balances, and asked its staff to produce a final order to deal with the possibility.

With recent price runups in natural gas and wholesale power markets, the PUC predicted a higher-than-expected value for nuclear generation owned by utilities. It questioned whether it would have to "undo" various mitigation measures it had adopted earlier (e.g., allowing accelerated depreciation on power plants liable to stranding). —P.C.

Electric Reliability

Mandatory Federal Standards. Acknowledging failure in trying to get Congress to pass federal legislation, the Department of Energy asked for comments on whether it should open its own rulemaking case to compel the Federal Energy Regulatory Commission to impose mandatory standards for electric reliability. The DOE asked for comments on several questions, including:

  • Current Rules. What's wrong with the current system, and have violations of standards jeopardized reliability?
  • FERC Authority. What can the FERC do under current authority? Can it impose standards or delegate that task to a separate, self-regulating, reliability organization (SRRO)?
  • RTO Issues. How would regional transmission organizations interact with an SRRO? .

NERC 10-Year Assessment. The North American Electric Reliability Council (NERC) released its reliability assessment for the years 2000-2009, predicting a sharp turnaround in availability of generation supply, with higher summer reserve margins by 2004 in most of the country-in the Eastern and Western Interconnections, but not in ERCOT, where NERC projects that margins will rise slightly through 2002, but then begin to fall. Consistent with that prediction, NERC projects greater growth in demand and load in the ERCOT than in the West or East. The study also reveals a sharply higher incidence nationwide of requests for transmission line loading relief (TLR), beginning in April 2000, and continuing through the remainder of the year at a much higher plateau than in prior years.

  • Study projects 1.9 percent annual growth nationwide in both electric demand and load, but stronger rates in the West (2.1 percent increase) and ERCOT (2.7 percent) than in the East (1.7 percent).
  • Increasing through 2004, especially in the Northeast (NPCC) and the Mid-Atlantic (MAAC), and to a lesser degree in Florida (FRCC) and the West (WSCC), but flat or falling slightly during the same time frame in the Midwest (ECAR and MAPP), and the South- east (SERC). Margins are projected at dangerously low levels in Texas (ERCOT) by 2009, based on announced construction plans for new merchant generation.
  • TLR logs show a steady growth in requests for line relief since 1997, plus an approximate tripling of TLR events from 1999 to 2000 during almost all months.
  • NERC projects that production of natural gas in the Western Canadian Sedimentary Basin (and Canadian exports to the United States) will remain roughly constant through about 2012, when each will begin to fall, with WCSB production unable to fill export pipeline capacity by 2018. See

Michigan Grid Constraints. The Michigan PSC directed the state's three largest electric utilities (Consumers Energy, Detroit Edison, and Indiana Michigan Power) to assess and report on near-term generation and transmission capacities, plus any planned upgrades or additions, and how such capacity may affect service reliability and retail open access programs this coming summer.

The PSC expressed concern that long-term contracts may have tied up grid capacity and imposed "artificial" shortages. . —L.A.B.

Transmission & ISOs

Non-Spinning Reserves. Finding fault with a fix-it plan proposed in September, and seeing no resolution of market flaws, the FERC told the New York ISO to maintain its existing price cap of $2.52 (plus opportunity costs) in the non-spinning reserve market, and ordered a technical conference to explore possible solutions.

"We find that the present state of the ... market is largely the same as that which precipitated mitigation in the first place," said the FERC, noting that several market flaws continued to persist: (1) a highly concentrated market, (2) no viable plan for allowing some participants to "self-supply" their own operating reserves, and (3) no solution to the problem of moving power reserves across transmission constraints from western New York to the eastern sector.

Dissenting commissioner Curt Hébert questioned the idea of a conference: "The exchange ... may make for an interesting salon, but will lead nowhere." . -L.A.B.

Michigan Transco Plan. Facing widespread opposition, the FERC agreed to rehear its order that allowed International Transmission Co. (to be created by Detroit Edison) to charge transmission rates pegged and frozen at the level of the transmission component of Detroit Edison's retail bundled electric rates, as set by the Michigan PSC. .

Must-Run Protocols. The California PUC, ISO, and Electricity Oversight Board each filed protests opposing a new formula rate tariff proposed by Southern Energy Delta and Southern Energy Protrero, which is designed to allow Southern Energy to recover any potential revenues that it might otherwise lose on reliability must-run (RMR) plants because of new ISO Tariff Amendment 26. That amendment, known as the "pre-dispatch protocol," now forces RMR plant owners to choose between two alternative forms of payment: (1) the standard RMR contract payment, which includes variable costs plus a fixed-option payment for capacity value; or (2) the market-clearing price in the day-ahead energy market, but forces RMR owners to make that choice blindly, before the day-ahead market clears and the price becomes known.

Southern Energy claims that the RMR contract allows plant owners to file rate changes to recover unforeseen costs imposed by future ISO tariff changes, but the PUC, ISO, and EOB claim that Southern's proposed formula rate is open-ended, putting no cap on potential recoveries, which would depend on differentials between RMR contract rates and hourly markets.

In particular, the ISO points out that the availability of the RMR contract rate actually makes RMR owners better off than other generators, since RMR plants with high startup costs or long ramp-up times can keep running and avoid off-peak losses during periods when day-ahead market rates might otherwise fall below variable running costs. The ISO opposes recovery of opportunity costs, insisting instead that RMR dispatch should allow plant owners only to recover any net incremental costs (netted against incremental revenues) incurred by making their plants available for must-run dispatch. .

Midwest ISO Defections. State utility commissions in Illinois and Michigan urged the FERC to delay its review of the request by Illinois Power (through its parent company Dynegy) to withdraw from the Midwest ISO in favor of the proposed Alliance Regional Transmission Organization, alleging that Illinois Power has not shown its request to be in the public interest.

Moreover, the Illinois and Michigan regulators say it would be wrong for the FERC to decide the matter before it issues final decisions on the MISO and Alliance RTO proposals (yet to be filed under FERC Order 2000).

The two commissions urge the FERC to allow only one RTO for the Midwest region. They say FERC inaction "has led directly to the RTO disarray" plaguing the Midwest, creating "uncertainty and speculation" in the region. .

Public Power Participation. Three separate cases before the FERC raise questions concerning the rights of municipal electric utilities to join the California ISO and file tariffs for transmission service provided over their own facilities, reflecting their own transmission revenue requirements (TRR).

  • In one case, the city of Vernon has asked the FERC to give "fast-track" status to its application to join the ISO-the first-ever such application by a municipal utility-to overcome alleged foot-dragging by the ISO and its participating transmission owners (PTOs). The city said it was "concerned that the ISO may be giving existing PTOs a veto right" over its application, and suggested that the PTOs were "attempting to coerce concessions ... by way of refusing to execute a [revised] transmission control agreement." .
  • In the second case, also involving the city of Vernon, the FERC said that with minor modifications it would accept Vernon's proposed TRR and 11.6 percent return on equity, as submitted by the Vernon city council (the governmental body that sets Vernon's rates), but only because the council's TRR and ROE used rate-setting methods for transmission service comparable to methods already OK'd for Southern California Edison. Thus, the FERC explained that it was not deferring to the Vernon city council, but would reserve the right to review nonjurisdictional municipal activities whenever they affect jurisdictional ISO activities. .
  • ISO Determinations. In the third case, the FERC OK'd a California ISO tariff that would require municipal utilities either to file their own TRR with the FERC for review, or to allow the ISO's own revenue review panel, after approving the municipal TRR, to submit it to the FERC for further review and acceptance, despite the FERC's lack of jurisdiction over municipal utilities. .

Business Wire

Avista Corp. subsidiary Avista Advantage has reached an agreement with EnerTech Capital Partners for a strategic business investment that includes capital, access to a wide network of resources, hands-on support, and counsel. The investment will be used to help refine, expand, and market Avista Advantage's growing suite of facility cost management service offerings and includes the first round of private equity financing. Terms of the agreement were not released.

Boston-based consulting firm EFI Inc. has teamed with Savoy WebEngines Inc. and been awarded $524,952 from the U.S. Department of Energy to bring to market the Internet-based energy management system, the Savoy WebEngine. The grant was one of 18 research and development projects selected by DOE to receive funding. The projects are designed to improve energy efficiency of commercial and multi-family residential buildings across the country by using less electricity and reducing pollution from heating and cooling systems.

Sermatech International has acquired Turbine Technology Services Corp., a high-technology engineered products and services provider for gas turbine and combined cycle power plants. Terms of the deal were not disclosed. "As the installed base of gas turbines has grown rapidly, power generation plant owners have been looking for ways to effectively reduce costs and to manage the complex outages required to keep their machines running efficiently," said James McCabe, president of Sermatech. The capabilities of Turbine Technology Services complement our growing core of gas turbine products and services enabling us to meet our customers' need for comprehensive maintenance packages."

In preparation for customer choice and retail competition beginning in Alberta on Jan. 1, 2001, EPCOR, an Alberta-based utility services provider, has implemented an advanced billing system from Itron Inc. to meet the billing needs of its commercial and industrial energy customers. Itron's MV-PBS is a client/server-based billing and market settlement solution that produces customized bills and invoices to meet the needs of commercial, industrial, and wholesale energy customers that purchase energy under a variety of complex rates, supply contracts, and schedules.

Convergent Group Corp. has signed a definitive agreement with a wholly-owned subsidiary of Schlumberger Ltd., whereby the Schlumberger subsidiary will acquire 71.7 percent of the outstanding Convergent Group common shares for $8.00 per share in cash. Convergent Group management and employees will own approximately 26 percent of the remaining shares, and Cinergy Ventures LLC, a unit of Cinergy Corp., the firm's largest client, will retain equity in the firm, holding the remaining ownership interest. -C.J.L.


Power Markets
California Prices: Real or Rigged?

FERC review only opens up an endless debate.

By Thanksgiving, after the Nov. 22 deadline had passed at the Federal Energy Regulatory Commission for submitting comments on the remedies the agency had proposed to tame runaway power prices in California and the West, the whole question had split into three separate and distinct debates:

  • Why should the "filed rate doctrine" bar retroactive refunds when prices are set by markets, not by tariffs?
  • Do California's high prices stem from anticompetitive behavior, market design, or simple scarcity of supply?
  • If a price cap is warranted, then what is the just and reasonable price?

On Nov. 22, San Diego Gas & Electric and Southern California Edison both asked the FERC to change its tune and order retroactive refunds of excess power costs. Edison saw the key problem as one of market power and abuse. By contrast, SDG&E did not insist that market manipulation was to blame, but instead urged the FERC to cap wholesale prices based on costs incurred by generators.

Meanwhile, PG&E asked the California Public Utilities Commission to stabilize rates and proposed a five-year stabilization plan that would lock the cap on wholesale power costs at 6.5 cents per kilowatt-hour ($65/MWh) for residential and small business customers, under a recently enacted state law that otherwise would give discretion to the PUC to adjust the 6.5-cent ceiling. But even that modest proposal could lead to trouble. In mid-November, California PUC commissioner Carl Wood suggested in a draft decision that the statutory 6.5-cent plan could make San Diego Gas & Electric Co. even worse off, if significant numbers of large-volume industrial, commercial, and agricultural customers take advantage of the 6.5-cent plan, and if purchased power costs continue to rise. The PUC was expected to review Wood's proposed decision on Dec. 7. .

Retroactive Refunds? At a public hearing before Chairman James J. Hoecker and Commissioner William Massey of the FERC, held in San Diego Nov. 14, California Gov. Gray Davis had again called on the FERC to require retroactive rate refunds for San Diego consumers.

"Your plan will make things worse next summer," Davis said, referring to the proposed order.

The governor's words echoed the comments of California state Sen. Steve Peace, who had testified a week earlier at the FERC in Washington, D.C. on Nov. 9, calling for retroactive refunds. Peace had questioned why the FERC should apply the filed rate doctrine (barring retroactive refunds) when rates are based not on cost of service, but on competitive forces.

"There's no filed rate," argued Peace, "because there is no cost of service."

In fact, just a few days earlier, Congressman Bob Filner (D-Calif.) had introduced new federal legislation (H.R. 5626) to amend the Federal Power Act to allow the FERC to order refunds of rates to the extent they exceed the just and reasonable level, with interest accrued "from the date on which the rate or charge was paid," in the special case where the FERC has prescribed market-based rates for the transmission or sale of electricity.

Refunds could prove problematic, however. Chairman Hoecker pointed out the problem in a statement he released on Nov. 17, asking for guidance.

"If the commission were to order refund of excessive rates," asked Hoecker, "how would we determine the excess in a market-based rate environment? What would be the just and reasonable rate? Who would be responsible for refunding the overcharge?"

Market Power or Broken Markets? Testifying before the FERC on Nov. 9, Diane Jacob, chairwoman of the San Diego County Board of Supervisors, had laid it all on the table.

"I liken what is happening in San Diego to white collar crime and no less," she said.

Others blame the market structure. In comments filed Nov. 21 on behalf of ELCON, the Electricity Consumers Resource Council, and various industrial customer groups, attorney Sara Schotland reminded the FERC that her clients had been warning of structural flaws in the California market for years, especially the idea of dividing the power exchange from the independent system operator, and thus forcing the ISO to work through third-party scheduling coordinators to balance the grid in real time.

"As far back as July 25, 1994," said Schotland, "we warned that the U.K. model is better left in the U.K., and identified fundamental problems with the power exchange concept that unfortunately have been realized."

In their paper attached to comments filed by Southern California Edison, consultant Scott Harvey and professor William Hogan offered new explanations of structural market flaws in California.

"Prices have been high in California," they wrote, "surprisingly high."

In particular, Harvey and Hogan noted that because of the sequential nature of California markets, with a day-ahead auction for energy as a consumer product, followed by real-time auctions for ancillary services and energy system balancing, they believed that even those sellers lacking market power were withholding output from one auction to get a higher price in a later auction, thus causing day-ahead energy prices to rise to the level of opportunity costs represented by higher prices in later-clearing markets.

Surprisingly, however, they advised against abandoning the single-price principle in favor of a pay-as-bid auction. According to Harvey and Hogan, "pay-as-bid pricing systems introduce inefficiencies that raise market prices in a manner that can be hard to distinguish from the exercise of market power."

Costs, Caps, and Scarcity. At the other end, many power marketers and power plant owners, such as Dynegy, Enron, and Calpine, have begun to argue that prices are not really out of line-they simply represent rising costs and scarcity of supply when compared with demand.

The marketers and power producers not only oppose the idea of price caps, but question how the FERC can hope to calculate a "just and reasonable" price for power, based on fuel prices, plant operating costs and characteristics, and the owner's profit expectations, when costs are changing so rapidly and each power plant and owner is unique.

Comments offered at the FERC's Nov. 9 hearing in Washington suggested that a reasonable power price, based on the costs of a gas-fired peaking plant, might vary anywhere between $75 and $350 per megawatt-hour, or even higher, even with the heat rate held constant, depending on such factors as the number of hours in the year during which the plant operates, and the number of years that the owners expect to wait before recovering their fixed costs.

Anyone eager to define the cost of generation should read the California PUC's motion in which it literally begs the FERC to help it force power plant owners to answer subpoenas requiring them to supply cost data. "The CPUC wants to know how much money each generating and trading entity is making."

On Nov. 14, California PX CEO George Sladoje announced the formation of a "Blue Ribbon Panel," led by Professor Alfred Kahn, to investigate criticisms of California's power markets and to determine whether the current rules for setting market-clearing prices in the PX day-ahead market produce a "fair and efficient" electricity price. The panel was to solicit comments from interested parties and meet in New York City on Nov. 28, and later in San Francisco on Dec. 12.

Mergers & Acquisitions

Sierra + PGE. Still following its old policy predating Order 642, FERC allowed Sierra Pacific Resources to acquire Portland General Electric, relying on two promises by the merged company to cap prices and to limit any firm reservations to one hour on any transmission facility that uses the constrained Alturas intertie. .

Federal Review. Two-and-one-half years after issuing its original rulemaking notice, the FERC finally approved a final rule governing approval of electric and gas utility mergers, largely ratifying its existing "Appendix A screen" already used to evaluate horizontal competition, but with some new wrinkles added, such as adding ancillary services and real-time reserve markets to the list of relevant products.

The FERC also called for a technical conference to evaluate the use of computer models to simulate markets.

Nevertheless, the FERC largely ignored concerns raised by the Federal Trade Commission and others about relying on the merging utilities to supply and evaluate their own data, without independent validation. They noted that the Hart-Scott-Rodino law allows regulators to collect evidence from third parties, and allows for confidential, off-the-record give-and-take exchanges that may serve better to uncover threats to competition.

Commissioner Curt Hébert voted for the order but suggested that the FERC lacks antitrust experience and instead should rely more on the FTC and the Department of Justice for merger review. . —L.A.B.

PUC Merger Review. North Carolina regulators issued rules forcing electric or gas utilities seeking merger approval to submit a cost-benefit study and a market power analysis, despite opposition from Duke Energy and Carolina Power & Light, which preferred to leave antitrust issues to federal agencies. .

Power Plants

Expedited Licensing. Faced with tight reserve margins and resulting political pressure, the California Energy Commission by a 4-0 vote on Nov. 15 adopted emergency regulations to implement the state's new six-month "fast-track" process for licensing thermal power plants, required by Assembly Bill 970, signed into law on Sept. 6. . -C.J.L.

AFUDC Financing. Citing figures that it found "excessive," the Florida PSC denied a request by the investor-owned Florida Public Utilities Co. (FPUC) to accrue allowance for funds used during construction (AFUDC) at a rate of 11.17 percent to finance construction of a gas pipeline gate station and lateral to serve a new 200-megawatt, gas-fired power plant to be constructed by a third party.

Nevertheless, the PSC did OK a project-specific 14.4 percent return on equity (ROE), yielding an 11.17 percent return on net project investment, even though FPUC's current overall ROE (as set by state regulators) was only 11.4 percent.

The PSC explained that the higher ROE was the product of negotiations between a "willing buyer" and a "willing seller." .

Downwind Pollution. The U.S. Justice Department, Environmental Protection Agency, and the State of New York have reached an agreement in principle with Virginia Power requiring the company to cut emissions (SO2 and NOx) from its eight coal-fired power plants, pay a $5.3 million civil fine, surrender certain SO2 emissions allowances, and contribute $13.9 million in environmental projects.

The agreement comes a year after the EPA and New York-and later New Jersey, Vermont, and Massachusetts-announced intentions to sue the owners of several Midwestern and Mid-Atlantic coal-fired power plants, two of which were owned by Virginia Power, for violating the federal Clean Air Act. -C.J.L.

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