Transmission & ISOs
RTO West. Six Western utilitiesAvista Corp., Montana Power Co., Portland General Electric, Puget Sound Energy, Nevada Power Co., and Sierra Pacific Power Co. joined to file a plan with the Federal Energy Regulatory Commission to form an independent for-profit transmission company, known as TransConnect, that would lease transmission lines from the six companies and in turn belong to a planned new regional transmission organization, known as RTO West, which would operate in an eight-state region. .
GridSouth RTO. CP&L Energy, Duke Energy, and SCANA Corp. proposed jointly to form GridSouth Transco LLC, a for-profit investor-owned transmission company independent from the three founding companies that would also purport to qualify as a regional transmission organization, or RTO, in the Southeast United States.
The companies had announced their intent to form GridSouth in July, and had held a series of public meetings in August and September to develop input from stakeholders. But state regulators in the region have not yet implemented retail supply choice for electric customerswhich may affect RTO plans.
As GridSouth explained in its proposal, "in light of the status of industry restructuring in the Carolinas, the applicants are not in a position to divest their transmission assets to GridSouth at this time. ... In these circumstances, the realistic option ... is to transfer functional control ... to an RTO." See www.gridsouth.com.
Recalled Capacity. Admitting that the required software modifications are "not technically feasible at this time," the New York ISO has put off filing a permanent set of tariffs governing recalls of installed capacity (ICAP) from out of state, and instead had informed the FERC that it will continue its transitional ICAP market design beyond the original Oct. 31 sunset date, until the end of the ISO's "capability year," on April 30, 2001.
As the ISO explained, "NY ISO's software is comprised of many different computer programs that work together in an integrated fashion. A modification in one program inevitably requires adjustments to other programs. Proposed modifications ... require intensive testing and modeling."
Under the transitional ICAP design, the ISO may recall electric capacity that suppliers have committed out of state paying the higher of the recall price set by bid at the supplier's discretion, or the real-time locational marginal price. In the ideal case, the ISO recalls increments of such external capacity on a least-cost basis.
However, as the ISO has explained, "despite [our] best efforts, NY ISO does not have the software capability to evaluate automatically all the recall bids submitted by ICAP suppliers who enter into external transactions."
The net effect of continuing the transitional ICAP market through the winter is that the ISO will continue to follow its stop-gap language in tariff section 5.12.7, which states the NY ISO will recall energy on a least-cost-bid basis only "when automated evaluation of recall bids is available." .
Scheduling Imbalances. Led by the city of Anaheim, and supported by other public power interests, five municipal electric utilities in southern California asked the FERC to strike down the practice followed by the California ISO of billing all scheduling coordinators (SCs) equally through its neutrality adjustment clause (NAC) to reimburse the ISO for costs it incurs for conducting "out-of-market" (OOM) redispatch to correct system imbalances that occur when SCs "game" the market by underestimating the load they likely will need to serve.
The cities say the ISO charges discriminate against innocent parties. "It forces SCs that have taken responsibility for submitting schedules adequate to serve their loads to subsidize other SCs."
Meanwhile, the ISO defended its rate making practice as consistent with FERC rulings allowing systemwide charges for services that benefit the entire grid. It added that it was working to fix the problem. In fact, at its Oct. 4 meeting, the ISO Board of Governors had told ISO management to allow costs to SCs in proportion to deviations from schedules, but at that time the Board had actually raised the NAC price cap from 9.5 cents per megawatt-hour to 35 cents per megawatt-hour.
The ISO incurs costs when it cannot call up enough real-time supplemental energy from bids committed to supply ancillary services and thus must buy energy through OOM dispatch calls (sometimes at very high prices) to ensure gridwide reliability. The cities alleged that underscheduling and OOM redispatch calls have only increased since the price caps imposed by the ISO real-time energy markets have discouraged bids for replacement reserve capacity.
By contrast, Southern California Edison calls the Anaheim complaint "mistaken," and believes the problem stems more from generating plants holding their output off the market in an attempt to collect higher, uncapped OOM prices. As Edison explained, "suppliers are holding supplies back from the day-ahead market and the OOM payment mechanism provides them with an incentive to do so." It asked the FERC to consolidate the Anaheim complaint and look for a comprehensive solution within its broader investigation of wholesale power market. .
California Cash Crisis. Citing rising power costs and cash flow shortfalls of "astounding" dimensions, Southern California Edison joined with Pacific Gas & Electric to ask the FERC as an emergency measure to force power generators to disclose costs and impose price caps of $100 per megawatt-hour in markets for energy, ancillary services, and out-of-market (OOM) dispatch calls in day-ahead, hour-ahead, day-of, and real-time markets operated by both the California Independent System Operator (ISO) and Power Exchange (PX).
PG&E said it paid 16.3 cents, 11 cents, and 18.7 cents per kilowatt-hour, respectively, to buy power in wholesale markets in June, July, and August 2000 (vs. 3, 3.9 and 4.1 cents per kilowatt-hour in 1999), while the state-mandated freeze on retail electric rates only allocated approximately 5.4 cents per kilowatt-hour for purchased power, leaving no mechanism to recover the higher costs.
"The level of these price increases cannot be explained by increases in the price of natural gas," said Edison and PG&E. "Moreover, natural gas prices have increased everywhere, but electricity prices in California and the Western region are far higher than in other markets."
They warned that continued high prices could jeopardize financial integrity: "PG&E and Edison ... are each, in effect, loaning money to their customers to pay their energy bills. In turn, PG&E and Edison have had to borrow money to make the payments." .
California Market Surveillance. At its meeting on Oct. 4 the California ISO's Board of Governors rejected a motion to implement load-differentiated price caps based on natural gas prices weighted by heat content, but did not otherwise appear to issue any formal response to reports issued in September by the ISO's market surveillance committee.
On Sept. 6, the MSC issued a report finding that June 2000 price spikes in the ISO's markets for energy and ancillary services were nearly triple the level that should have been expected under competition.
Later on Sept. 21, the MSC had urged that price caps still were needed in ISO markets, given various structural market flaws, including lack of price-responsive demand:
"We regretfully conclude that the ISO's price cap authority must be extended, even though price caps are flawed as a long-run solution."
New York Price Distortions. Describing markets as "still adversely affected by flaws," the New York Independent System Operator asked the FERC to extend its "temporary extraordinary procedures" until April 30 for correcting price distortions.
And it warned that some software fixes actually could make things worse, as traders become "more imaginative in adapting their bidding strategies to the changing market environment."
Nevertheless, the ISO did report some progress in making prices more logical. For example, the ISO said as last summer turned to fall, it was forced to "correct" real-time prices after the fact less frequently than before. For September, such price corrections occurred for only 0.42 percent of discrete pricing intervals. By comparison, it had to correct real-time prices more frequently in August (0.53 percent of the time), July (1.87 percent), and June (3.92 percent). .
New England Capacity Prices. Supported by state PUCs, but opposed by other power marketers like itself, Alternate Power Source Inc. asked the FERC to force ISO New England to recalculate April clearing prices in the ISO's auction for installed capacity (ICAP market) to correct allegedly distorted prices.
APS attacked an ISO ICAP price of $3,240 per megawatt-month, saying that the capacity should have had a "zero marginal cost," since the April ICAP market showed an excess supply of 2,522 MW. It argues that even if the FERC cannot order retroactive refunds to traders, the ISO has a legal duty under the filed rate doctrine to recalculate prices in prior periods that are not consistent with tariffs that govern price determination.
In fact, the ISO already had recalculated ICAP prices for January, February, and March, on finding "anomalous conduct" by market participants, and the FERC itself in June had told the ISO to kill the ICAP auction, since it wasn't functioning properly. But the ISO has declined since to mitigate ICAP prices for April, May or June. It argued that under its Market Rule 17 it can only examine bidding behavior-not the prices proper-and so cannot act without evidence of specific conduct by bidders.
Meanwhile, the Maine PUC joined the New England Conference of Public Utilities Commissioners in endorsing the APS complaint, and said it would file its own complaint attacking ICAP prices.
But other power marketers see APS as attempting to escape its bad bargains. According to Select Energy, "APS took a risk by relying on the residual market." And Sithe New England Holdings put it more bluntly: "APS requests this relief solely because it went short into the ICAP market, hoping in vain to satisfy its capability responsibility free of charge. Granting the complaint would rescue APS from its own failed business decision not to hedge." .
New England Price Caps. The FERC clarified a prior order (issued July 26) by explaining that the temporary price caps of $1,000 per megawatt-hour that it set for ISO New England during certain system conditions of capacity deficiency must remain in effect for the entire day for which such conditions are forecasted, or for the remainder of the day on which they are declared. The cap affects markets for energy and automatic generation control whenever the ISO institutes its "Operating Procedure 4." Commissioner Curt Hébert dissented, arguing that the majority now allows the ISO to impose price caps when it expects a shortage, so that the ISO can predict an emergency and impose caps even if the emergency never occurs. .
Retroactive Price Relief. In a case similar to the complaint by APS over price spikes in ISO New England's ICAP market , many power marketers have intervened to protest three separate complaints filed by (1) Northeast Utilities and United Illuminating Co., (2) the Maine PUC, and (3) Bangor Hydro-Electric Co., all of which ask the FERC to compel ISO-NE to recalculate the unprecedented price peaks of $2,870 and $6,000 that occurred on May 8 during hours 13-17. The complaints allege that the prices violated New England rules and were based at least in part on New York prices that were later recalculated by the New York ISO.
The marketers argue that the requests for retroactive price relief violate FERC policy set earlier this year .
For example, in opposing the Bangor-Hydro complaint, FPL Energy notes, "BH completely ignores the numerous [protests] to the first two complaints, as if they never happened ... there [we] explain how the NEPOOL Market Rules and FERC's decisions and policies against retroactive rate making forbid revising energy clearing prices several months after the fact."
HQ Energy Services Inc., an affiliate of Hydro Quebec, distinguishes between fixing errors and second-guessing discretionary acts: "While the filed rate doctrine allows corrections of computational errors in calculating prices, it does not support BH's request for retroactive changes to decision making made in the course of dispatching generators."
HQ also adds, "The price change in New York is not authorized by the NY ISO's tariffs and will be the subject of proceedings at the FERC." .
Notice of Price Hikes. Massachusetts regulators OK'd final guidelines for pricing and procurement of default electric service, creating a three-step process requiring utilities to use direct mail (as opposed to bill inserts) to notify customers about any changes in pricing up to six months out.
"Direct mail signifies to the customer that the company has something important to say," the regulators said.
On another issueconcerning revenue shortfalls for default standard offer service caused by last summer's high power pricesthe regulators said that utilities could recover costs from all distribution customers, and not just default customers. The regulators explained that default service acts "as insurance for all customers who enter the competitive market." .
Standard Offer Shortfalls. The Maine PUC, citing rising wholesale power prices, boosted standard offer rates for Bangor Hydro-Electric Co. by 32.5 percent, the exact amount requested by the utility in mid-September, after it estimated that without adjustment, standard offer revenues would fall $7.9 million short of costs. The adjustment comes on top of an earlier increase approved in July. .
Standard Offer Service. The Ohio PUC OK'd significantly different plans for standard offer service in two recent electric restructuring orders, for Dayton Power & Light Co. and for Monongahela Power Co. Each order grants a 5 percent discount off generation costs for residential standard offer service, but each also deals differently with the problem of customers "gaming" such service by switching back and forth between supplier.
- Monongahela Power. Non-aggregated residential customers who take service from competitive suppliers would be able to return twice to default service before a minimum stay period would take effect. Case No. 00-02-EL-ETP, Oct. 5, 2000 (Ohio P.U.C.).
- Dayton P&L. To address gaming, the agreement stipulates that during a "market development period" (MDP) running through 2003, any residential customer who takes generation service from DP&L at any point between the summer peak demand period of May 16 and Sept. 15 either must remain on standard offer service through April 15 of the following year, or choose a market-price-based tariff approved by the PUC and not lower than the generation cost embedded in the standard offer. Customers pay a $5 fee to switch, but have one free switch during the MDP until a 20 percent switching level has been reached. Case No. 99-1687, et al., Sept. 21, 2000 (Ohio P.U.C.).
Environmental Disclosures. The Emissions Disclosure Working Group at the Maryland PSC has submitted a set of six different labels to be used by electric utilities and suppliers offering standard offer and competitive electric supply services in the state's deregulated electricity market.
The labels would disclose the fuel mix of supplied energy, listing percentages for coal, natural gas, nuclear, fuel oil, other unspecified fossil fuels, and renewable energy (including geothermal, hydroelectric power, solar energy, wind, solid waste, wood, and biomass). The labels also would disclose emissions of sulfur dioxide, nitrogen oxides, and carbon dioxide, in pounds per megawatt-hour. .
Slamming and Cramming. Michigan regulators invited all "interested persons" to submit proposals to protect electric customers from slamming (switching them to another supplier without consent) and cramming (billing them for unwanted services). .
Renewable Energy Portfolios. New Mexico regulators relaxed rules for its 5 percent minimum standard for renewable energy portfolios for standard offer service, waiving compliance if it would cause rates for standard offer service to rise more than 0.001 cents per kilowatt-hour, because of the relatively higher cost of renewable energy resources.
At the same time, however, the regulators required utilities to offer an optional "green power" tariff for standard offer customers willing to pay more for larger amounts of renewable power.
Assuming a price of $.08 per kilowatt-hour for standard service without a renewable energy requirement, the new rule would allow a maximum allowable percentage rate increase of 1.25 percent for compliance with the renewable standard, or about $0.50 per month for a customer using 500 kWh per month. .
Industrial Incentives. With one commissioner dissenting, the New Hampshire PUC expanded a special rate discount contract for Pubic Service Co. of New Hampshire (PSNH) to cover additional factories operated by an industrial electric customer as an incentive to promote economic development in the state and add new jobs in manufacturing.
Dissenting commissioner Nancy Brockway objected, saying that applicants for special rate discounts should be held to a high standard, with claims of new jobs held "to rigorous scrutiny before being accepted as the basis for a major rate subsidy."
Brockway added, "Unlike the situation facing the customer in 1995, today there is a high likelihood of a general rate decrease for all customers, making the additional discount from a special contract less [relevant] in location and expansion decisions."
Brockway also expressed concern that incentive discounts could add to demand peaks with ISO New England, which has struggled of late with price spike problems during peak periods. .
Stranded Costs. The New Hampshire PUC also reversed an April order that had reduced allowable stranded costs for PSNH by some $78 million, now deciding that the order might cause the utility to lose eligibility to claim income tax deductions for accelerated depreciation, and noting also that the state's new electric restructuring law (SB 472, enacted June 12), requires a certain minimum level of customer savings from the PSNH restructuring plan. .
In a companion order, the PUC allowed PSNH to securitize stranded costs up to the limit allowed in the new law ($670 million), less $6 million for each month that elapses between Oct. 1, 2000 and the eventual startup date for electric competition in the state. The amount includes above-market costs ($558 million) for interests in the Seabrook and Millstone 3 nuclear plants, $97 million related to acquisition premiums and Financial Accounting Standard 107, and $15 million for premiums for financing and debt retirement. .
Gas Billing Practices. The Georgia PSC, aiming to quell an "utter state of confusion," proposed rules to force natural gas marketers to send bills to customers within 90 days after receiving a meter reading from the local distribution company, or pay penalties of up to $15,000 per violation, plus an added $10,000 per day for failure to comply. .
Firm Gas Capacity Rights. The Ohio PUC OK'd a tariff clause for retail gas supply choice by East Ohio Gas Co. to require competitive marketers to hold primary, firm capacity sufficient to meet 100 percent of peak day demands of retail customers, but asked its staff to study objections by marketers Enron and New Power Co., which argued that the rule was too restrictive, and urged the PUC to allow marketers to buy less firm capacity rights from secondary markets.
In a separate opinion, Commissioner Craig Glazer said that East Ohio should have done more to prove the need for marketers to buy firm capacity.
"Legally, the PUC may find it extremely difficult to undo this requirement once approved, without the agreement of East Ohio," said Glazer. "[I]t is noteworthy that this Commission has not required a similar 'comparable capacity' requirement in any other gas choice program nor on electric marketers." .
American Electric Power has selected LineSoft Corp.'s line design software, LD-Pro, to automate transmission and distribution line design for service regions formed as a result of AEP's recent merger with Central and South West Corp. Prior to the merger, CSW worked with LineSoft in a successful LD-Pro pilot. AEP, already an LD-Pro user, will deploy 200 LD-Pro design seats for work in Texas, Oklahoma, Arkansas, and Louisiana, bringing to 600 the number of LD-Pro seats AEP is using.
Gas Technology Institute has acquired a majority interest in TICORA Geosciences Inc., a coalbed methane and shale resource evaluation firm based in Denver. Joining GTI's E&P Services group, TICORA will continue to provide geological-based technical support to major and independent coal and shale gas producers and the natural gas research community.
Utility.com has launched three appliance service plans to cover repair of major household appliances. The plans are available to customers who sign up online and incur a modest monthly fee on their credit or debit card. Appliances include air conditioners, water heaters, furnaces, heat pumps, refrigerators, dishwashers, and clothes washers and dryers.
Kansas City Power & Light Co.'s telecommunications subsidiary, KLT Telecom Inc., conditionally has agreed to acquire for an aggregate purchase price of approximately $110 million an additional 31 percent of the fully diluted common stock in DTI Holdings Inc., a St. Louis firm that is developing a nationwide fiber optic network for voice and data communications. The investment would increase KLT Telecom's fully diluted ownership to 78 percent of the optical networking firm.
Reliant Energy has announced a $25 million equity investment in Grande Communications, which is building a broadband network that will offer bundled services, including high-speed Internet, all-distance telephone, and advanced cable entertainment to homes and business. The investment is expected to close upon approval under the Hart Scott Rodino Act. Reliant Energy also committed to invest, under certain conditions, a similar amount in a future Grande Communications equity financing.
Williams and Invensys plc have formed a strategic alliance to link and deliver communications systems and energy management solutions for customers across commercial, industrial, and residential markets. Developing communications networks and energy management systems for schools, colleges and universities, healthcare facilities, and commercial facilities will be an initial focus of the alliance.
USEC Inc. has completed 20 percent of the historic 20-year United States-Russian Megatons to Megawatts program that converts material from Russian nuclear warheads into fuel for commercial power plants. The equivalent of 4,000 nuclear warheads, or 100 metric tons of weapons grade uranium, have been converted into fuel for power plants and delivered to USEC.
Studies & Reports
Uniform Business Standards. A task force at the Gas Industry Standards Board has proposed forming a new organization to supplant GISB that would oversee development of uniform business standards across the energy industry, in both electric and natural gas markets, with standards for such functions as electronic exchange of information, record and data formats, communications protocols, and related business practices.
A 20-plus-page "strawman" document, issued Sept. 27, outlines ideas for membership, governance, committee structure, voting, and funding. See www.gisb.org/pdf/stmn092700.pdf.
Information Technology. Citing excessive costs and mixed reviews on "usability" and flexibility, the National Energy Marketers Association has recommended that state PUCs "mitigate" their use of the electronic data interchange (EDI) protocol by adopting the XML protocol (extensible markup language), sponsored in 1998 by the Working Group of the World Wide Web Consortium, and designed specifically to send information over the Internet.
The NEMA issued its call in a white paper on uniform standards for delivery of energy products and services, including guidelines for technology and information exchange. See www.energymarketers.com/Documents/ FinalUCC.pdf.
Standby Service. The New York PSC ruled that when electric utilities sell off generating plants, the PSC retains jurisdiction over rates the utility charges to the new owners for turnkey station use and start-up services, as such rates qualify as retail rates for standby sales when delivered by the franchised utility to the generator, rather than as wholesale rates for generation and transmission services, as the new owners had argued.
"Station use and start-up services ... are delivered through meters that measure retail consumption," said the PUC, "either for service provided to the generation facility when it is not operating, or for service electrically isolated and separately metered from the output of the facility when it is operating. ... Rather than being resold by the generator receiving it, [such] service is used on-site to operate the generator's facilities."
The PSC also rejected arguments by the new owners to net the standby services against plant output: "When the generator does not operate, there is nothing to net against, because all services are supplied from an outside source," it said. .
Greenhouse Gas Mitigation. FERC Commissioner Linda Breathitt questioned environmental claims in two cases granting licenses for hydroelectric and gas pipeline construction projects, arguing that in certifying the extent to which a given project would avoid greenhouse gas emissions, the project sponsors should not be allowed to proceed from a base line that assumes the absence of any project at all-an "impossible analysis," said Breathitt.
Nevertheless, she voted to license the two projects: (1) the 326-megawatt Missouri-Madison hydroelectric project proposed by PP&L Montana, and (2) gas pipeline looping facilities proposed by Reliant Energy Gas Transmission Co. to deliver gas to cogeneration facilities. .
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