Joint Subcommittee Studying Electric Utility Industry RestructuringJune 3, 1998, Richmond
The joint subcommittee met to review nationwide restructuring developments and to learn about incumbent utility market power related to transmission constraints. Restructuring stakeholders and other interested parties--including the Division of Consumer Counsel within the Attorney General's office, the SCC, and representatives of municipal power supply systems, electric cooperatives, and investor-owned utilities--gave their views on the potential for post-restructuring market power linked to transmission constraints. The three hour meeting also featured a detailed briefing from a utilities analyst and publisher on current restructuring developments in all 50 states and at the federal level.
Deregulating electric utilities' generation activities is no guaranty of competitive generation. According to the SCC Energy Division director, the potential for incumbent utility market power within their transmission systems following generation deregulation warrants close scrutiny. Market power, in this context, means the power of an incumbent utility to thwart meaningful competition for retail generation sales in the utility's former service territory.
Market power can arise from two sources (separately or in combination): (i) a transmission system running through a service territory has little or no excess capacity (producing "import constraints") or (ii) incumbent-owned generation units within the service territory must be operated virtually at all times to ensure a stable and reliable flow of power (called "must run" units). The SCC director also said that while independent system operators, or ISOs, can use dispatch authority to avert transmission system failure, they are inherently incapable of mitigating or eliminating the market power described above.
Division of Consumer Counsel
A senior assistant attorney general from the Division of Consumer Counsel noted that the presence of import constraints in an electric utility service territory reflects historic monopoly regulation of electric utilities providing bundled electric service. However, import constraints could produce market price distortions in a restructured electricity market if incumbents took advantage of them to control or deny competitor access to electric customers in the incumbents' former exclusive-service territories.
Noting that the Federal Energy Regulatory Commission (FERC) Order #888 stopped transmission tariff constraints but not physical constraints, the assistant attorney general said that absent the addition of new transmission import capability in systems such as Virginia Power's, "it may not be feasible for more than a small percentage of total peak requirements to be imported into Virginia on a firm basis." The result: no extensive competition within Virginia Power's service area from other regional suppliers. He also believes that the SCC needs to study this issue closely in the months ahead.
Virginia Power's transmission import constraints, resulting in an available transfer capability (ATC) figure of approximately 2,800-3,100 MW, were the focus of several speakers' comments, including those offered by the Municipal Electric Power Association of Virginia (MEPAV). MEPAV's members are municipal power supply systems that, generating virtually no power of their own, depend on firm power deliveries through regulated incumbents' transmission systems.
The general manager of the Blue Ridge Power Agency (a MEPAV member) told the joint subcommittee that MEPAV members in Virginia Power's service territory have wholesale peak capacity requirements of about 200 MW--all currently purchased from Virginia Power. Nevertheless, if these MEPAV members decide to purchase power from other suppliers, Virginia Power's limited transmission import capacity may inhibit access to alternative generation supply--effectively giving Virginia Power market power in that instance.
MEPAV members obtaining generation supply through AEP Virginia's transmission system also face current transmission import constraints. The representative said that AEP's transmission system is so constrained that MEPAV members participate in an AEP load-shedding plan. Under peak loading conditions, MEPAV members and other AEP wholesale customers would be required to participate in rolling blackouts to prevent transmission system failure.
Thus, AEP could exercise market power, depending on how it operates its transmission system, dispatches generation, or dispatches generation purchased from other utilities. MEPAV supports AEP Virginia's application for a new 765 Kv transmission line in AEP's service area running from the westerly portion of West Virginia into Southwest Virginia. That application is currently pending before the SCC.
AEP Virginia's president emphasized his company's concerns about constrained transmission in the AEP corridor spanning the Virginia and West Virginia border. While expressing certainty about the 765 Kv line's necessity, he was less certain about its eventual approval--much of it tied to federal environmental approvals necessitated by line routing through national forest. In any event, the earliest date now projected for the line's completion--if approvals go smoothly--is December 2002. In the meantime and absent new transmission capacity provided through this proposed line, the transmission system serving this corridor will operate outside safe limits approximately 100 days of the year.
Virginia Power's vice president and general counsel told the joint subcommittee that Virginia's western transmission interface has transfer capability comparable to that existing in many U.S. regions. Additionally, anticipated construction of merchant plants in Virginia Power's service territory by new market entrants should contribute to a vibrant generation market after restructuring.
The Virginia Power representative asked the joint subcommittee to consider the role of ISOs when examining the market power issue. Import constraints and "must run" units do not automatically equate with market power inconsistent with competitive opportunity in a restructured market. Regional ISOs--a key ingredient in California's restructured market and an important component in Virginia's 1998 legislation--can mitigate market power through generation dispatch coordination among generators, eliminating the risk that a utility could keep competitors out of its former, regulated service territory.
He also reminded the joint subcommittee that the Federal Energy Regulatory Commission (FERC) has already approved the PJM and New England ISOs to the north as well as the California ISO-approvals, he said, that only would have been granted if rules designed to prevent market power had already been put in place. Moreover, pricing remedies have been built into these ISOs in the rare case that transmission constraints interfere with the ability of generators to bid power into a regional power exchange (RPX) and with the market's ability to set prices.
Market power issues in a multi-state ISO must be evaluated in a market broader than Virginia. Consequently, FERC--and not the General Assembly--may be the ultimate authority in establishing rules to mitigate potential market power resulting from the physical characteristics of any incumbent utility's generation and transmission systems. Nevertheless, since HB 1172 of 1998 (Virginia's restructuring law) conditions deregulation's commencement on the operation of an ISO and an RPX for at least one year, sufficient protection through this delay, in combination with FERC's rules concerning market power for that ISO, should provide appropriate protection against undue market dominance.
CNG, parent company to Virginia Natural Gas and CNG transmission, billed itself as a new entrant in the electricity market. Its subsidiary, CNG Retail, was described to the joint subcommittee as an integrated energy company furnishing natural gas, electricity and other energy-related products with about 250,000 residential customers, making it one of the country's largest residential energy marketers. CNG suggested that market power in some service territories may be partially mitigated by new market entrants constructing small generation facilities. Describing one strategy as "distributed generation," such generation includes micro turbines and fuel cells.
A CNG vice president emphasized that new market entrants are essential to competition's success in a restructured electricity market, noting that the level of stranded cost recovery by incumbent utilities may be the single largest barrier to new market entrants. With that in mind, CNG suggested that utilities should be required to submit their generation assets to an auction process; utility owners or their affiliates would be permitted to participate like any other bidder. CNG views this as the best available tool for determining the future value of utility assets. The company also stressed the need for truly independent ISOs--indifferent to whose electricity they carry and concerned only with safety and reliability.
The Virginia, Delaware and Maryland Association of Electric Cooperatives' vice president appeared briefly before the joint subcommittee to emphasize the current transmission import constraints in Virginia Power's service territory. He cited current information on the Open Access Same-time Information System (OASIS) showing Virginia Power reporting about 288 MW of additional, firm capacity in the month of June. In his view, price caps on generation in service territories with transmission constraints is an insufficient response to the market power problem. Divestiture, in his estimation, may not resolve the problem, either.
MEPAV, the Office of Consumer Counsel, and the electric cooperatives told the joint subcommittee that, in their view, an SCC examination of the market power issue should occur as part of Virginia's preparatory steps for retail competition in the electricity market.
National Trends and Developments
A former Ohio consumer counsel, who now publishes The Leap Letter (a bimonthly newsletter devoted to state-based restructuring developments) presented a detailed briefing on nationwide restructuring activities. He concentrated on recent nationwide restructuring developments and on recent trends in state and federal restructuring policy.
Retail competition legislation is still a relatively recent phenomenon. States began adopting restructuring legislation in 1996 when four states (including California and New Hampshire) enacted retail competition laws. In 1997, six states followed suit; and in 1998, three states (including Virginia and Connecticut) passed restructuring bills. New Hampshire's retail competition plan is currently embroiled in litigation over provisions limiting stranded cost recovery to 60 percent of such costs. California's retail competition plan went "live" on April 1, but has attracted low levels of interest in the residential sector, as dramatically evident in Enron's recent suspension of further residential marketing activity there. It was suggested that the statutory rate cut given Californians in the restructuring legislation provided little incentive for them to seek alternative generation providers.
Initiatives to repeal all or part of some states' restructuring legislation is a recent phenomenon. A proposed Massachusetts initiative, for example, would repeal that state's restructuring bill, while similar sentiment is surfacing in Montana, where much of that state's generation is up for sale following restructuring. So far, however, a much-anticipated special session of the Montana legislature to address this development has failed to materialize. Finally, California voters may soon have restructuring repeal before them; ballot petitions to repeal portions of California's restructuring laws were recently approved by that state's attorney general and are circulating throughout the state.
The analyst also discussed a number of significant trends in restructuring legislation, including (i) utility mergers in anticipation of or in conjunction with restructuring, including a proposed merger between AEP and a major Texas-based utility; (ii) statutory rate cuts in recent restructuring bills; (iii) utility generation divestiture increasingly viewed as a viable option for market power mitigation; and (iv) the trend toward recoverability of stranded costs, subject to mitigation.
Pennsylvania, which enacted its restructuring legislation in 1997, is a key state to watch. Currently, over 200,000 electricity customers are participating in pilot programs, and the Pennsylvania Public Utilities Commission (PUC) is actively engaged in determining stranded costs for its regulated utilities. Recently, Pennsylvania's PUC reached an important stranded costs settlement with PECO, allowing about $5 billion in stranded costs between 1999 and 2010, using a 10.75 percent return. A total of $1.1 billion may be securitized, a settlement provision upheld in a May Pennsylvania court order.
The PECO stranded costs recovery will be "trued up" yearly to reflect actual electricity sales. Other significant provisions require PECO to (i) transfer its generation asset and liabilities and wholesale power contracts to a separate corporate affiliate, (ii) unbundle and permit competition in providing metering, billing and collection services for customers with retail access, and (iii) expand PECO's current universal service program and its low-income weatherization program. Another key settlement provision addresses PECO as a "default provider." If, by January 1, 2001, fewer than 35 percent of PECO's customers have chosen an electric supplier, customers will be assigned suppliers to bring the number up to 35 percent. In 2003, the targeted percentage will be 50 percent. Additionally, on January 1, 2001, competitive bidding will take place for 20 percent of residential service.
Currently pending before the Pennsylvania PUC is the issue of stranded cost recovery related to non-utility generation (NUG) contracts to which the Pennsylvania Electric Company (Penelec) and other Pennsylvania utilities are parties. Penelec is claiming approximately $1.2 billion in stranded costs, of which NUG contracts constitute approximately $1 billion. Pennsylvania's restructuring act includes recovery for "prudently incurred costs to cancel, buy out, buy down or renegotiate contract obligations to NUGs." According to the analyst, a recent decision by a PUC administrative law judge recommended against the utilities' exceeding the PUC's rate cap to pay for buying out NUG contracts. That recommendation--and the broader issue of stranded NUG costs--awaits final PUC action.
Future Subcommittee Activities
The chairman announced that the joint subcommittee will convene its next meeting in Richmond on July 9. The meeting's tentative agenda includes a close look at ISO/RPX formation, with discussion of the proposed Alliance and Midwest ISOs. An additional meeting has been scheduled on August 18. The chairman also announced tentative plans to hold a November meeting in Reston in conjunction with a conference to be convened by the Center for Innovative Technology.
Further information concerning the SJR 91 joint subcommittee is available on-line at http://dls.state.va.us/sjr91.htm.
The Honorable Jackson E. Reasor, Jr., Chairman
Legislative Services contact: Arlen K. Bolstad