Distributed Generation. In December and January the Illinois commission took comments from utilities, marketers, manufacturers, and trade and advocacy groups on how to develop policy on distributed generation.
* Rulemaking Strategy. Enron has urged the state to proceed in a fashion similar to the California PUC's
two-track investigation. It asked for two separate rulemakings on (1) interconnection standards for DG installations of 50 megawatts or less, and (2) rate design and operational issues.
* Unit Size Limits. The commission staff opposed setting any size limit on DG units. It noted that the California PUC set a 20-MW ceiling in its definition of DG to discourage DG owners from wholesale activities, preserving cost savings for consumers:
"The CPUC position was that cost savings from providing less wire and fewer connections (transformers, relays) between the power supply and the end-user, and the savings from reducing line loss and congestion on the transmission and distribution grids, would go directly to the retail customers instead of a third-party marketer or middleman.
"While this approach might be what California was looking for ¼ [we favor] a more even-handed policy that would allow generation or storage of any size to locate on the distribution system."
* Metering and Interconnection. Enron favored net metering for small DG installations, whereas the Edison Electric Institute opposes that. According to EEI, net metering creates subsidies for DG customers: "Net metering does not keep the incumbent whole for transmission and distribution costs or for the on-peak value of power. ¼ [I]t skews the price signals."
EEI added that the Institute of Electrical and Electronics Engineers "may take two years to finish its work on interconnection standards."
* Rate Structure. Commissioner Terry Harvil had asked for comments on whether unbundled electricity delivery rates should be differentiated geographically to encourage DG in areas needing grid upgrades. The staff believed that costs of managing such rates might outweigh the benefits. Enron felt that it was too early to consider the question.
David Moskowitz of The Regulatory Assistance Project (www.rapmaine.org) acknowledged rate de-averaging for transmission through nodal and zonal congestion pricing, but said distribution networks are different, usually having only single paths from substation to load, making de-averaging impractical.
* Disincentives. Moskowitz warned that utilities around the country were starting to propose higher fixed monthly customer charges and much lower usage charges for distribution service, specifically to make DG "far less attractive" to customers. He cited a case where a Nevada utility suggested raising its residential customer charge to $21 a month.
For all comments, see http://icc.state.il.us/el/docs.asp.
Wires-Only Rates. In a case setting rates for Central Maine Power Co. in its role as a "wires company," the Maine PUC said it would consider alternative approaches to a "top-down methodology" for setting transmission and distribution rate design, where generation costs are removed from current rates using standard offer prices. Docket No. 97-580, Jan. 19, 2000 (Me.P.U.C.).
Earlier, the PUC had OK'd a top-down method for designing core class rates for Maine Public Service Co. (See "News Digest," Feb. 1, 2000, p. 12.)
Gross Receipts Taxes. New York PSC chair Maureen O. Helmer praised Gov. George Pataki's proposed elimination of the "onerous" gross receipts tax on electric and natural gas utilities, which he championed in his Jan. 4 "state of the state" address.
Helmer said the action would have "an immediate and meaningful impact on everyone's energy bills, and it will provide an economic shot-in-the-arm to the energy-intensive manufacturing businesses that are critical to the continued revitalization of upstate New York."
Gas Transportation. The North Carolina commission opened a docket requesting comments on all aspects of rates, terms and conditions of transportation-only service by natural gas distribution utilities. Docket No. G-100, Sub 80, Jan. 4, 2000 (N.C.U.C.).
Gas Unbundling. Massachusetts regulators opened a docket to set rules for unbundling natural gas services, so that a utility would provide distribution-only service within its existing service territory and offer a default service option to retail customers not served by a competing supplier. D.T.E. 98-32-E, Dec. 17, 1999 (Mass.D.T.E.).
Third-Party Billers. The Pennsylvania PUC ruled that third-party billing companies must pay power suppliers and electric distribution companies for undisputed basic charges, even if the customer doesn't pay.
It rejected arguments - including those by dissenting Commissioner Nora Mead Brownell - that the ruling would place an unreasonable burden on third-party billing companies. The majority pointed out that billers will tend to be large, well-established credit card companies. Docket No. M-00991230, F.0002, Nov. 19, 1999 (Pa.P.U.C.).
Gas Retail Pilots. Out of concerns for reliability, the Virginia commission rejected a request by Washington Gas Light Co. to modify its pilot program for retail gas choice to allow it to withhold upstream pipeline capacity from suppliers at its discretion and adjust the amount of gas delivered by suppliers on exceptionally warm days if usage is low and extra storage is unavailable.
The commission said that taken together, the modifications would relieve WGL from its responsibility to acquire capacity and storage to serve customers who elect to participate in the pilot, allowing WGL to "effectively abdicat[e] its role as the supplier of last resort to these customers." Case No. PUE980895, Nov. 8, 1999 (Va.S.C.C.).
Regulatory Assets. The Connecticut Supreme Court upheld a decision by state regulators to apply $110 million of an electric utility's $141 million projected surplus to allow the utility to accelerate amortization of certain regulatory assets, rather than make refunds. The court called the accelerated amortization "directly beneficial to ratepayers." Office of Consumer Counsel v. DPUC, No. 16106, 2000 WL 29564, Jan. 25, 2000 (Conn.).
Rolled-in Pricing. A U.S. appeals court upheld orders by the Federal Energy Regulatory Commission that allowed Southern Natural Gas Co. to employ "rolled-in" rates to recover costs to build a new pipeline to bypass the existing pipeline of a smaller competitor, despite claims that the FERC's 5 percent test for qualifying for rolled-in rates worked as a subsidy for larger pipelines.
Midcoast Interstate Transmission Inc., the smaller competitor, had argued that larger systems such as Southern's could readily absorb the cost of new projects without a noticeable rise in systemwide rates. Midcoast Interstate Trans. Inc. v. FERC, No. 98-1603, Jan. 18, 2000 (D.C.Cir.).
Federal Electric Restructuring. On Jan.5 Rep. Edward Markey (D-Mass.) released a letter from FERC Chairman James Hoecker that described the proposed federal electric restructuring bill H.R. 2944 as "an unfortunate retreat from the goal of a competitive, efficient and transparent wholesale power market."
Hoecker said he preferred H.R. 2050 (Largent-Markey bill) or H.R. 1828 (Clinton administration bill).
MERGERS & ACQUISITIONS
KKR + DP&L. Dayton Power & Light Co. announced an agreement on Feb. 2 for certain affiliates of Kohlberg Kravis Roberts & Co. to invest $550 million in the utility and receive voting-preferred and trust-preferred securities and warrants with an exercise price of $21, representing 19.9 percent of DP&L shares outstanding and 4.9 percent of DP&L's total voting rights.
Earlier, DP&L had asked to recover about $686 million in stranded costs, including $441 million in after-tax transition costs, in a 3,000-page plan for consumer choice plan filed at the Ohio PUC.
ONEOK + Southwest Gas. Southwest Gas Corp. responded to ONEOK Inc.'s termination of the merger between the two companies by filing a lawsuit against ONEOK in U.S. District Court of Arizona in Phoenix, seeking damages for breach of contract.
In terminating the merger, ONEOK cited concerns over the lawsuit filed against Southwest Gas by spurned merger suitor Southern Union, which had alleged that Southwest and ONEOK conspired with an Arizona Corporation commissioner to scuttle the bid by Southern Union.
Pipeline Divestitures. El Paso Energy Corp. announced the divestiture of three major natural gas pipeline systems (East Tennessee, Sea Robin and Destin) to comply with Federal Trade Commission orders for approval of El Paso Energy's merger with Sonat Inc. All three sales were expected to close in the first quarter of 2000.
* Duke Energy Gas Transmission would buy East Tennessee Natural Gas Co. for $386.3 million.
* CMS Trunkline Gas Co. would purchase Sea Robin Pipeline for $72 million.
* An unnamed buyer was to purchase El Paso's one-third interest in the Destin Pipeline Co. LLC for $160 million, subject to a right of first refusal by El Paso Energy's partners in the venture.
CMP Group + Energy East. The Maine PUC OK'd the merger of CMP Group, parent company of Central Maine Power Co., with Energy East, the holding company for New York State Electric & Gas. Energy East would acquire CMP as a subsidiary. The PUC was to retain jurisdiction over EE affiliates to ensure that CMP will be able to recover any merger costs that exceed merger savings. Docket No. 99-411, Jan. 4, 2000 (Me.P.U.C.).
Nuke Plant Sales. The watchdog group, Nuclear Information and Resource Service, filed a petition at the Nuclear Regulatory Commission on Jan. 5 that challenges the proposed transfer of the Oyster Creek nuclear plant license from GPU Nuclear to AmerGen Energy Co.
NIRS alleges that AmerGen is financially unqualified to operate Oyster Creek because it has few assets and is a limited liability corporation. (The assets of its parent companies, PECO Energy and British Energy, cannot be seized in the event major repairs are needed or financial problems occur.)
NIRS also claimed that British Energy has engaged in massive cost-cutting efforts resulting in compromises to health and safety. The petition seeks a hearing before the three-judge Atomic Safety and Licensing Board.
Hydro Relicensing. Having chosen the FERC's alternative relicensing process for its Bagnell Dam in Missouri, AmerenUE has scheduled a series of public hearings and about 120 individuals or groups have expressed an interest in testifying about management of the Ozark Lake, Missouri's largest lake, which the dam created.
Ameren's 30-year license expires Feb. 28, 2006, so it must apply to the FERC by Feb. 28, 2004 for a new license for the Osage Hydroelectric Project.
Renewable Energy. The Texas PUC has created a renewable energy credits trading program and adopted other rules to help implement a provision in the Texas electric restructuring law (Senate Bill 7) that requires installation of 2,000 additional megawatts of renewable generating capacity in Texas by 2009.
The mandate calls for the state to increase its renewable resources from the current level of about 880 MW to 1,280 MW by 2003, 1,730 MW by 2005, 2,280 MW by 2007 and 2,880 MW by 2009. The rules require that companies that sell electricity in the competitive retail market will have to buy a "fair share" of energy supplies from renewable resources to sell to end-users.
TRANSMISSION & ISOS
Mountain West Funding. The FERC authorized the Mountain West Independent System Administrator and approved a two-part tariff plan consisting of (1) transmission owner tariffs for the provision of transmission services, and (2) an ISA tariff for administering ancillary services and managing congestion using physical transmission rights (firm, recallable and nonfirm) sold at auction. In the same case, the FERC granted authority to Sierra Pacific Power and Nevada Power to transfer control of transmission facilities to the ISA.
Earlier, on Dec. 21, MW ISA chair Rosalie Day had threatened to suspend all activities until a source of funding could be found. On Jan. 20, the Nevada PUC had decided that it could not guarantee cost recovery for the ISA, and had asked the FERC to expedite review to ensure that startup funds might be made available to Mountain West as soon as possible after authorization. Docket Nos. ER99-3719-000 (authorization), EC99-100-000 (transfer), Jan. 27, 2000, 90 FERC 61,067.
Congestion Management. The FERC accepted a new method proposed by the California Independent System Operator to manage intrazonal congestion that is designed to compensate power producers more effectively for fuel-related startup costs so as to encourage them to bid more often to supply power for congestion relief.
Otherwise, the FERC ruled that the ISO lacks authority to force the redispatch of generating units to manage intrazonal congestion when the ISO believes that such congestion, coupled with a lack of bids for congestion relief, will threaten the integrity of a competitive power market. That might occur if there is only one generator located on the export side of a constraint. (Though the FERC acknowledged ISO authority to force redispatch only where intrazonal congestion threatens reliability.)
Power producers had argued that a lack of competing suppliers was no cause to abandon market approaches to congestion management, and that producers who demand high prices during a constrained period should not be viewed as wielding market power.
The FERC agreed that "there is nothing wrong with prices increasing during times of real scarcity," but it said the ISO's original congestion management scheme needed fixing so that generators would not profit by offering distorted bids creating artificial congestion. Docket No. ER00-555, Jan. 7, 2000, 90 FERC ¶61,006.
Grid Infrastructure. An interim report by the U.S. Department of Energy on power outages that occurred during summer 1999 warned that operating practices, regulatory policies and technological tools needed for fundamental changes in the electric industry were not yet in place to assure an acceptable level of reliability.
The report, "Findings From the Summer of 1999" by the department's power outage study team, also says that the operation of the electric system is much more difficult to coordinate in a competitive environment.
The report lays some blame on utilities for cutting costs in anticipation of competition and thus spending less on reliability, and also finds that because responsibility for reliability has been spread among utilities, independent system operators, power producers and customers, the overall infrastructure for reliability assurance "has been considerably eroded." See http://tis.eh.doe.gov.
Redispatch Pilot Program. The FERC granted a request by the North American Electric Reliability Council to extend its market redispatch pilot program for congestion management in the Eastern Interconnection until April 1. Docket No. ER99-2012-002, Jan. 27, 2000, 90 FERC ¶61,058.
Power Outages. The Michigan PSC on Jan. 3 opened an investigation into methods for improving service reliability, directing staff to consult with utilities and others to formulate recommendations in a status report by March 31, and a final report by May 1. Case Nos. U- 12269 and U-12270.
Purchased Power Contracts. The Los Angeles Department of Water and Power and Montana Power Co. have completed a transaction to terminate the remaining 11 years of an existing power sales contract, and assign the purchase obligation under the new agreement (114 MW from Montana Power's leased share of Colstrip Unit 4) to an undisclosed third party.
Purchase Power Contracts - Refunds. New York State Electric & Gas Corp. has asked two non-utility generators to provide assurances that they will have the ability to refund an estimated $2.7 billion in overpayments when their power purchase agreements with NYSEG end.
In a letter to the owner of Allegheny Hydro Nos. 8 and 9, NYSEG threatened to terminate the contracts if it did not receive the assurances within 30 days. NYSEG and Allegheny Hydro had entered into the power contracts in 1988 under New York PSC mandate. The contracts included advance payment accounts reflecting the difference between the price NYSEG pays for power under the contracts and the company's actual avoided costs.
At the end of 1999, the combined balance in Allegheny Hydro's payment accounts was thought to exceed $111 million. Assuming electric prices and NYSEG's avoided costs escalate at the projected rate of inflation, the balance will grow to nearly $2.7 billion by 2030, the end of the contract term.
The Chicago Mercantile Exchange is adding six additional cities and Cooling Degree Day indexes to its weather futures contract listings. The CME will list both Heating Degree Day and Cooling Degree Day indexes for 10 cities, adding Dallas, Des Moines, Iowa, Las Vegas, Philadelphia, Portland, Ore., and Tucson, Ariz., to the previous HDD listings of Atlanta, Chicago, Cincinnati and New York. In addition, 12 monthly contract expirations will be offered, covering the period February 2000 through January 2001.
Austin Energy has selected Convergent Group Corp. to implement business process improvements designed to maximize the efficiency of the utility's energy delivery operations and the effectiveness of its customer service. Convergent Group's solution will detail steps the utility should take to maximize the efficiency of its energy delivery operations. The working solution, enabled by Convergent Group's Solutions Workbench, is an integrated suite of technologies designed to deliver the functionality required to support Austin Energy's management business objectives.
Unitil Corp. has signed an agreement with BusinessEdge Solutions Inc. to further automate the Usource product line for the mid-market segment of small to medium industrial and commercial customers. Under the technology agreement, BusinessEdge will design and implement an e-business strategy using flow-through processing of transactions in a deregulated energy environment. BusinessEdge, based in Edison, N.J., delivers e-business enablement and strategic information technology services, while Usource is Unitil's Internet energy auction system serving large commercial and industrial customers.
MDU Resources Group Inc. has signed an agreement to acquire Great Plains Natural Gas Co., a natural gas distribution company serving 19 communities in western Minnesota and southeastern North Dakota, in a stock-for-stock exchange. The acquisition is subject to the approval of the Minnesota Public Utilities Commission and the North Dakota Public Service Commission. Following the acquisition, Great Plains will be operated as a division of MDU.
A newly formed subsidiary of EPRI (Electric Power Research Institute) will offer customized technical support services to both members and non-members of its research program. Called EPRIsolutions Inc., the for-profit subsidiary will hasten the application of EPRI technologies already developed through decades of collaborative research. "Technology holds the key to success in a more competitive electric industry," said Kurt Yeager, EPRI president and chief executive officer. "Applying advanced technologies, however, is more difficult in an era of severe cost cutting. EPRIsolutions will work directly with our customers to select, install and support those EPRI technologies most suitable for their particular needs."
Transmission Management- Doing the RTO Polka
By Bruce W. Radford. editor-in-chief of Public Utilities Fortnightly.
The Midwest ISO tried changing its tune to court Alliance, but ended up with ComEd. Now who's belle of the ball?
It seemed like a good idea. The consensus was that without the transmission facilities of American Electric Power Co., the Midwest Independent System Operator (MISO) would be too small for workable dispatch and congestion management in its area, and perhaps even too feeble to qualify as a regional transmission organization (RTO) under the guidelines proposed by the Federal Energy Regulatory Commission.
So in November, MISO proposed to add a new appendix to its agreement to allow an independent transmission company (ITC) to coexist as a second-tier entity within the ISO structure. It bent over backwards to invite a new ITC. It opened the door for the member companies of the proposed independent Alliance transmission company to join the MISO and retain its separate identity.
Then something went wrong on the way to the dance. It turned out that the Alliance companies weren't interested. But somebody else was. That somebody was Commonwealth Edison, which joined with IES Utilities, Interstate Power and MidAmerican Energy in mid-December to petition the FERC to form an ITC to operate within MISO.
AND COMMONWEALTH EDISON WOULD NOT PLAY SECOND FIDDLE. It would operate its own control area, manage grid congestion and arrange for supply of ancillary services. It would design an extensive system of incentives to attract more suitors and more investment. It would eliminate the long-held primacy of native load rights. Aren't those the things that the RTO should do? Pretty soon, industry wags started touting the ComEd transco as the new belle of the ball.
Enron fell in love: "[We] strongly endorse the petitioners' commitment to eliminate the native-load exemption."
Alliance was bemused: "[T]he Midwest ISO speculates that the Alliance Companies may wish to participate in the Midwest ISO. The Alliance Companies wish to comment on that speculation."
Dynegy preferred to wait till spring, for the RTO workshops: "[T]he timing of [the] proposal is such that if acted upon by the FERC now, it would be taken off the table in terms of the open and collaborative process."
But it came down to the American Public Power Association to explain what had happened, in its comments filed on Jan. 14:
"APPA believes that if approved, the ComEd et al. ITC proposal will ultimately result in the dissolution of the Midwest ISO as proposed and approved by the commission. Should MISO survive, it will become the mere titular king of its region, with symbolic, not real authority over various ITC fiefdoms."
MEANWHILE, MISO WAS STILL AWAITING APPROVAL of its Appendix I proposal to amend its ISO agreement and structure, filed Nov. 1 in FERC Docket ER00-448-000. When MISO announced its idea, many in the industry had called it "conceptual."
Representing a coalition of transmission customers, attorney Sam Randazzo urged the FERC to go slow: "In the absence of critical facts, the commission should refrain from any action in this proceeding that would prevent it from exercising the full scope of its powers in the future."
However, when ComEd filed its ITC proposal on Dec. 30 in Docket No. EL00-25-000, some apparently thought it too specific. Listen to Wabash Valley Power Association, in its comment filed Jan. 12:
"[T]he ITC proposal ¼ goes too far, too soon. ¼ The incentives proposed ¼ are excessive. ¼ Petitioners propose a 200-basis-point enhancement on return on equity for divestiture ¼ There has been no demonstration that such incentives are necessary."
ATTORNEY SARA SCHOTLAND SAW NOTHING BUT TROUBLE FOR THE FERC. In her comments representing the Electricity Consumers Resource Council, she noted:
"FERC should not authorize reallocation of RTO functions from MISO to ITCs such that neither meet the minimum [test], or ¼ Order 2000 will become a dead letter.
"The ComEd ITC proposal should be rejected because it will emasculate MISO of key RTO functions, including ¼ congestion management.
"The suggestion that incumbent utilities in the Midwest retain this responsibility blatantly undermines FERC's RTO initiatives."
Regional Transmission Organizations -
SPP Move Seen as "Too Much Too Soon"
By Carl J. Levesque, associate editor, and Bruce W. Radford,editor-in-chief, of Public Utilities Fortnightly.
Co-ops, PUCs and power marketers fight bid by Southwest Power Pool to qualify as first RTO.
The Southwest Power Pool waited only 10 days after the Federal Energy Regulatory Commission had released its Order 2000 on regional transmission organizations before applying to the FERC to qualify as an RTO, and the rush drew protests from rural electric cooperatives, state public utility commissions (PUCs) and power
Some saw the plan as "business as usual." Others called it "too much too soon." See FERC Docket No. ER00-975, application filed Dec. 30, 1999, protests filed Jan. 18-31, 2000.
DYNEGY PROTESTED THE EXEMPTIONS GRANTED TO NATIVE LOAD. Such customers were excused from taking service under the regional tariff. Dynegy said that would allow participating utilities to continue using the grid "unconstrained by OASIS [the open-access, same-time information system] to which all other transmission users are subject." Dynegy also noted that SPP would not transfer operational control of dispatch and scheduling to SPP, as stipulated in Order No. 2000. That objection was repeated by the Golden Spread Electric Cooperative Inc. and Kansas Electric Power Cooperative Inc.
Three other cooperatives - East Texas Electric Co-op Inc., Northeast Texas Electric Co-op. Inc. and Tex-La Electric Co-op of Texas Inc. - expressed disapproval that SPP had not submitted a revised transmission tariff for RTO operations. They pointed out that when SPP earlier had filed a modified and expanded regional tariff, the commission had said that changes would be required later if the SPP were to seek approval as an RTO or ISO. (See FERC Docket No. ER99-4392-000.)
SPP's failure, the co-ops argued, "should be fatal to its application."
A KEY PROTEST WAS FILED BY THE STATE PUCS of Arkansas, Kansas and Missouri, which together complained of some areas lacking in detail and others not complying with the RTO rule:
* Independence from Owners. No clear idea in many situations on how the RTO and transmission owners (TOs) share responsibility, not only in control area operations, but particularly in new grid construction, where expansion might involve two or more transmission owners.
* Rate Pancaking. Some SPP members would remain outside the RTO.
* Congestion Management. Bilateral trades for redispatch would not disclose in public the true price for relieving
* Rate Setting. Procedures for seeking changes in revenue requirement and pricing structures would overlap. The PUCs said transmission owners should first submit rate requests to the RTO, which would then forward meritorious cases to the FERC.
* Asset Transfers. SPP proposed using an agency agreement to transfer control of transmission to the RTO (to avoid creating tax problems for municipal and public power utilities). The PUCs favored the usual transfer agreements approved by the FERC under Federal Power Act Section 203.
The PUCs added that SPP's proposals for managing short-run congestion (to avoid curtailments of firm service) resembled those approved by the FERC for the Midwest Independent System Operator. Yet in that case, as the PUCs observed, the FERC had said it was "unclear how this procedure will work in practice."
Nevertheless, the PUCs said they supported SPP's ongoing discussions of a possible merger with the Midwest ISO.
SOME PROTESTORS COMPLAINED THAT SPP'S rushed application left no chance for input from interested parties, and saw that as defeating the purpose of the regional workshops on RTOs to be held this spring by the FERC.
And, with SPP's bid marking the first request for RTO status, Dynegy felt the commission should set a high standard for adherence to Order 2000. "It is¼absolutely critical that the Commission insist that SPP's proposal meet both the letter and spirit of Order No. 2000. If [it] sets a precedent of allowing exceptions to its new regulations at this early date¼the competitive advantages it envisioned¼will never be realized."
SPP asked the FERC to act on or before March 1 to speed the process of electing three new classes of nonstakeholders to its board of directors.
-CJL and BWR
News Digest was compiled by Carl J. Levesque, associate editor, Lori Burkhart and Phillip Cross, contributing legal editors, and Bruce W. Radford, editor-in-chief. For more frequent updates, see www.pur.com.
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