Many forces-competitive, regulatory, legal and technical-are today putting the squeeze on the U.S. transmission grid. A system that once offered convenient movement of electrons and thrived in an air of cooperation among users is now often at the center of contested cases before regulatory agencies and courts. As the new order of generation, transmission and distribution (T&D) shakes out, the grid will be frayed and its interconnectivity realigned.
Originally, power dispatch followed a fairly straightforward, connect-the-dots pattern. The dots represented utility-owned generating plants, feeding power at prescribed points with interconnectivity designed as a way to back up neighboring utilities during emergencies. Moving power over long distances was not the intent.
Now, however, the more than 4.5 million miles of T&D lines are being reassigned to new functions as economics and dispatch patterns change. Segments of the existing bulk power transmission network will be used in ways different from those originally planned or historically used. Consequently, new bottlenecks will be created, and some existing transmission constraints will be exacerbated. Traditional transmission planning will not be adequate in a deregulated, market-driven environment.
Making the connection
One notable change is the escalating number of new generation sources requiring connection. In a paper prepared for the 1999 Institute of Electrical and Electronic Engineers (IEEE) T&D conference and exposition held in New Orleans in April, ABB ETI`s Willie Wong, et al., addressed the future challenge of the competition of generation and transmission projects. In a competitive market, generation companies build new plants and close old plants at their discretion. There is uncertainty about the amount of transmission capacity required since there is no longer coordinated planning of generation and transmission. They pointed out that while uncertainty is not new, under open market conditions the same uncertainty is increased dramatically because the size, location and existence of generating units are subject to change, often with short notice.
They presented as another challenge the construction time of transmission projects vs. generation projects. The lead time for new line construction of transmission projects is typically in the range of five to 10 years, while that for a gas turbine or combined-cycle power plant is two years or less. Therefore, a generation project might be initiated after the transmission project has commenced and significantly alter the financial assumptions of the original decision used to justify the transmission project.
Merchant power plant developers are among those feeling the pinch from the investments needed to tie in to existing lines. Calpine Corp., for example, is developing a 700 MW gas-fired combined-cycle facility for the Magic Valley Co-op in Texas. Other potential customers include Central Power & Light (CP&L), Public Utility Board of Brownsville, and others in northern Texas and Mexico. In response to capacity shortage on CP&L`s transmission system that threatened Calpine`s project viability, CP&L and Magic Valley agreed to pay for a new $125 million transmission line, and Calpine agreed to limit its claim for access priority to its 250 MW commitment to Magic Valley. Other planned merchant tie-ins and expansions are listed in the accompanying table.
Shrinking violets need not apply
Wong, et al., discussed how plans for projects such as these must include analysis under a strong beam of market feasibility criteria. Market-based planning integrates economics and the traditional laws of generation, load and transmission. It should include consideration of the following:
– project identification and screening,
– the value of the transmission project,
– who will benefit and by how much,
– optimal project rating/capacity,
– utilization factor,
– uncertainty and risk assessment,
– financial model, and
Taking a closer look at the utilization factor highlights how expectations in today`s marketplace have changed. Uncertainty in power flow due to physical power trading shortens the return on investment period acceptable-or profitable-to the transmission owner and investor. The effects of future load growth and power trading on transmission utilization determine a project`s revenue potential. A higher utilization rate means a higher rate of return on a new transmission project, resulting in a shorter return period on investment. This is especially important since reliance on investment hedges made possible in the past by utilities` ability to recover costs from their ratepayers is now tenuous-in fact, illusory.
Tony Schuster, Northern States Power Co.`s transmission systems vice president, also emphasized this sharp focus on cost recovery in a recent interview. He said, “The whole issue is if there will be flow across the line to justify cost.” Decisions often pivot on whether the line will reduce cost or increase reliability. Considering the challenges facing new projects, Schuster said, “Shrinking violets aren`t going to get transmission built.”
Demonstrating they are not among the shrinking violets are Wisconsin Public Service Corp. (WPS), Minnesota Power Inc., and Texas Utilities Electric Co. (TU Electric) with their recently announced transmission expansion projects.
WPS and Minnesota Power plan to construct a 250-mile, 345 kV line from Wausau, Wis., to Duluth, Minn. Depending on siting and regulatory review and approval, the line could be in service during 2002 at an estimated cost of $125 million to $175 million.
TU Electric announced the filing of its Application for a Certificate of Convenience and Necessity at the Public Utility Commission of Texas (PUCT) requesting certification for a proposed 345 kV double circuit transmission line linking north and south central Texas (Limestone-Watermill line).
The Independent System Operator (ISO) of the Electric Reliability Council of Texas (ERCOT) designated the Limestone-Watermill project as critical to the reliability of the ERCOT system, thus qualifying the project for expedited consideration by PUCT.
Two existing 345 kV double circuit lines connect south Texas to north Texas. One line runs from the Houston area north to the southeastern side of Dallas. The other is from the San Antonio-Austin area through Waco to the southwestern side of Dallas. The new line (175 miles of circuit) will provide a third line running from Limestone County in south central Texas to southern Dallas County at an estimated cost of $67 million.
TU Electric reported studies indicate the present north-south transfer capacity is about 1,800 to 2,000 MW. Addition of the Limestone-Watermill line will increase transfer capacity to about 4,000 MW.
Unlike the voluntary interconnections discussed above, others are mandatory. For example, FERC ordered Illinois Power Co. (IP) to establish a physical interconnection of its grid with a 138 kV line that the Illinois Municipal Electric Agency (IMEA) is constructing. This dispute revolved around the allocation of costs associated with reconductoring one IP line and upgrading of another. IP initially refused to establish the interconnection unless IMEA agreed to pay 100 percent of the costs of the upgrades. IMEA argued that the costs associated with the upgrades represented system costs that were not directly assignable to IMEA.
In addition to their traditional intermediary functions, regulatory agencies are seeing new roles evolve with the new market. FERC voted in April to accept and enforce the Western Systems Coordinating Council`s (WSCC) reliability standards. This marked the first time FERC specifically approved such transmission standards and agreed to resolve related disputes about compliance by utilities-no longer relying on voluntary compliance of the 107 utility members. Utilities could face fines of up to $10,000 or 10 mills/kWh, whichever is greater, for violating WSCC standards.
The notion of fair play-and its definition-has the ability to incite spirited volleys of opinion among market participants as the following example demonstrates.
NERC announced Market Redispatch (MRD) as an alternative to its Transmission Loading Relief (TLR) procedures to relieve transmission constraints in the Eastern Interconnection this summer. MRD allows for bilateral redispatch transactions, creating counterflows to ease constraints on congested flowgates. Transmission customers must prearrange the transactions with the individual generation owners. Slated at press time to have started on June 1 and ending Sept. 30, 1999, the MRD option will be available for 13 (perhaps up to 25) common transmission constraints and will apply to all transmission reservation priorities (non-firm through firm) in lieu of TLR curtailment.
In late March, the National Energy Marketers Association (NEMA) responded to NERC`s proposal by filing a protest with FERC. NEMA`s position stated NERC`s proposal to require certain customers to enter into counterflow transactions in lieu of being curtailed substitutes one form of penalty for another, again with unfair and disproportionate impacts falling upon customers using point-to-point service. NEMA noted that utilities, by virtue of their stake in native load transactions, very likely have an inherent conflict of interest in deciding which transactions are to be forced to enter into counterflow transactions.
Also taking a swing at MRD was the Electric Power Supply Association (EPSA). Its executive director, Lynne H. Church, said, “NERC has appropriately recognized the difficulties associated with mandatory transmission curtailments and wants to employ TLRs only after more market-based responses have been implemented, but a number of changes are needed before the proposed pilot program is put in place.”
EPSA called upon FERC for implementation of mandatory participation by transmission providers in the program, pilot procedures that are not unduly complex, no obligation that transmission customers pay twice for the same transaction, TLR and MRD alternatives that are properly scaled to address actual transmission constraints, and fair compensation for the parties whose transactions are curtailed.
Reliability and legislation
NERC`s most recent Year 2000 status report indicated the electric utility industry has completed more than 75 percent of the testing and remediation needed by the end of March. This number was up from 44 percent as of last November. Fewer than 3 percent of all components tested have required Y2K fixes, and the errors that appeared were mostly cosmetic or nuisance type errors, such as incorrect dates in logs.
Michehl R. Gent, NERC`s president, said, “That is not to say that all is perfect. Our report shows that some utilities will be Y2K ready later in 1999 than we had targeted.” According to the report, some organizations may not complete work on generators until a scheduled maintenance outage in the fall, and some vendor upgrades are not available until after June 30. In addition, a portion of the distribution systems intends to complete Y2K testing and remediation after the June 30 industry target date.
NERC reported that electric distribution systems may be least sensitive to Y2K anomalies because most equipment is mechanical, meaning there are relatively few digital controls and embedded chips. (See the accompanying sidebar about the trend in outsourcing of distribution functions.)
As the preceding discussion illustrated, the grid`s Y2K operational reliability seems to be on track overall. Legislative assurance of reliability, on the other hand, is not yet in place to the extent many in the industry desire. Debate continues in the wake of the Clinton administration`s recently announced federal restructuring legislation.
In recent testimony before the Energy and Power Subcommittee of the House Commerce Committee`s hearing on transmission and reliability, NERC`s vice president, David R. Nevius, said, “The existing voluntary system for setting and encouraging compliance with industry reliability standards for the transmission system is not sustainable in today`s increasingly competitive electricity industry. An independent, self-regulatory organization, under government oversight, is the best way to develop and enforce compliance with reliability rules for the interstate transmission system. The alternative to an industry organization is, by default, a government agency.”
NERC, over the last year, developed an industry consensus legislative proposal to establish such an independent organization. The consensus language is supported by a broad coalition of industry organizations and stakeholders including: American Public Power Association, Canadian Electricity Association, Edison Electric Institute, EPSA, Electricity Consumers Resource Council, Enron Corp., and the National Rural Electric Cooperative Association.
Also testifying before the Energy and Power Subcommittee, Trudy Utter, Tenaska Power Services Co.`s vice president and general manager, said, “The wholesale power market is expanding, new generation is starting to be built and the promise of technical innovation, lower prices and better services is becoming reality. Nevertheless, many issues related to competition and transmission structure and reliability cannot be dealt with piecemeal by the states, nor fully resolved within FERC`s existing legal authorities.”
Utter`s remarks also represented the consensus views of the EPSA`s members.
Although there exists consensus that reliability must be assured, just how to achieve that goal sustains lively debate. For example, one provision under the Clinton proposal was to bring all transmission-owning utilities (including public power entities such as the Tennessee Valley Authority and federal Power Marketing Administrations) under FERC`s jurisdiction.
Nashville Electric Service`s CEO, Matthew Cordaro, told the Subcommittee subjecting public power transmission systems to regulation by FERC would add a layer of regulation “where none is needed, and it fails to recognize the fundamental difference between a nonprofit government-owned entity whose rates are set by elected officials and a profit-making entity whose rates are set by private individuals.”
FERC chairman, James Hoecker, called on the panel to give FERC authority to apply Order 888 to non-jurisdictional utilities-federal power marketing administrations, public power utilities and most rural electric cooperatives. He said compliance with FERC`s access rules is workable for public power utilities.
Hoecker added that full competition remains hindered by “continuing opportunities for transmission owners to unduly discriminate in the operation of their transmission systems so as to favor their own or their affiliates` power marketing activities.” FERC receives many complaints, and in some cases has confirmed discriminatory conduct, he said.
Access to transmission is a “hot button,” which is to be expected given the territorial, financial and reliability issues riding on it. Wisconsin Public Power`s CEO, Roy Thilly, recently told reporters, “We`ve got an ISO in the Midwest with lines that look like they must have been drawn by a chimpanzee.”
As the transmission skirmishes evolve, Thilly`s transmission chimp may very well bulk up to a King Kong.
The lead time for new transmission line construction projects is typically in the range of five to ten years. Photo courtesy of ABB Power Lines.