NEW MEXICO
NM PRC Issues Proposed Renewable Energy Rule
On March 12, 2002, the New Mexico Public Regulation Commission proposed a renewable portfolio standard (RPS) for state utilities. The Commission filed the proposed rule after the Utility Division Staff submitted a Petition for Rulemaking on the subject. Interested parties in the state had previously commented on the subject of renewable energy in Utility Case No. 3619, a Commission-initiated inquiry.
The RPS contained in the rule would require "each public utility or person supplying power to New Mexico Customers" to provide a minimum percentage of their service from renewable sources. Under the proposal, those subject to the rule would be required to provide 2% of their total service in renewable energy by September 1, 2003. The percentage would rise to 5% by September 1, 2005, and 10% by September 1, 2007.
The NOPR defines renewable energy as "electrical energy generated by means of a low or zero-emissions generation technology," and includes solar, wind, hydropower, geothermal and biomass generators. The definition of renewable energy also allows a source of renewable energy to be developed in combination with fossil fuel sources. The rule would allow utilities to apply for "trading credits" in order to satisfy the portfolio standard. Additionally, the NOPR would forbid public utilities from obtaining more than 50% of the energy necessary to satisfy the RPS from any single type of renewable energy.
The proposed rule includes a requirement that public utilities offer a "voluntary renewable energy tariff," through which customers could elect to purchase renewable energy at a higher rate. The NOPR also purports to require utilities and generators to reserve 10% of their transmission capacity or rights to transmission capacity for use by renewable energy sources.
Under the current procedural schedule, the rule would be effective on June 14, 2002. Interested parties will file comments in April, and a hearing will take place on May 8, 2002.
PNM, NM PRC Settle Holding Company Case
On December 18, 2001, the New Mexico Public Regulation Commission issued an order approving a settlement between the Public Service Company of New Mexico, the state Attorney General, and the Staff of the NM PRC concerning approval of PNM's new holding company (Utility Case No. 3137). The order ends a dispute over restrictions placed on PNM by the Commission in its original order approving the holding company, issued in June of 2001 (see Regulated Resources, November 2001 issue).
PNM had disputed six of the original order's conditions:
- The condition prohibiting PNM from paying dividends in excess of annual net earnings without prior commission approval.
- The condition prohibiting PNM from having subsidiaries.
- The condition requiring PNM to submit strategic and other business plans of affiliates engaged in unregulated activities to the PRC.
- The condition that PNM's merchant plant activities be subject to the class II transaction provisions of NM PRC Rule 450.
- The condition requiring PNM to waive the right to assert federal preemption as the basis for challenging NM PRC treatment of costs and expenses when determining rates.
- The condition that the NM PRC will assume all ratemaking authority of the SEC if the Public Utility Holding Company Act ("PUHCA") is repealed.
In the settlement, PNM agreed to provide notice to the NM PRC before it pays dividends to its holding company, except that the settlement still allows a notice-free initial dividend payment of $127,000,000. PNM also agreed to submit affiliate and holding company business plans in its initial filing for the next general rate proceeding but "only to the extent such information relates to the interactions of those entities with PNM." PNM also agreed to waive its right to assert federal preemption and to submit to NM PRC jurisdiction should PUHCA be repealed.
The NM PRC agreed in the settlement to relax the requirement that PNM obtain approval from the Commission before making energy purchases from non-utility subsidiaries of its holding company. Now, PNM may make emergency and economy energy purchases from non-utility subsidiaries without prior NM PRC approval. The Commission also agreed to let PNM invest in new generation via its holding company or subsidiaries without regulatory approval. Although the Commission allowed PNM to invest in new generation without prior approval, the costs of those projects will not be included in retail rates, and any PNM-affiliate purchases that the utility wants to be included in retail rates will be closely scrutinized.
As part of the settlement, PNM and the Attorney General agreed to withdraw their appeals of the original holding company order pending before the state Supreme Court.
NM PRC Adopts Final Electric Energy Policy
Concluding an inquiry that began in September, 2001 (see Regulated Resources, November 2001), the New Mexico Public Regulation Commission issued final Electric Energy Policy Principles at its January 8, 2002 open meeting (NM PRC Utility Case No. 3668). The Commissioners noted during the meeting that the policy is a "work in progress" and is intended to be dynamic enough to meet changing circumstances within the state and the industry. The final policy remains largely unchanged from the initial proposal, and maintains its focus on averting a supply crisis by encouraging diverse and increased supply portfolios and enhanced reliability.
The final policy deleted three of the proposed policy principles and added a new recommendation. First, the final policy drops a recommendation that the state consider requiring its native generators who operate wholesale merchant power facilities to provide power on a least-cost basis during emergency conditions. Several parties had expressed doubt about the legality of such a requirement. The adopted policy also eliminated a proposal to inquire into requiring New Mexico to utilities support state university engineering studies of technical problems in the electric industry and of methods to reduce electricity generation environmental impacts including emissions. The Commission also dropped a statement of support for the state's rural electric cooperatives. A new recommendation was added to the policy in the final order, suggesting an investigation into "areas and services in the electric industry" that could be opened to competition. As proposed, the policy only addressed examining the benefits of competitive metering service.
575 Area Code Not Needed for Years
On January 8, 2002 just seven months after it upheld its decision to require Albuquerque and Santa Fe to adopt a new area code, the New Mexico Public Regulation Commission decided to postpone the change until June of 2003. (NMPRC Docket No. 3330). The NM PRC based its decision to postpone adding the 575 area code on new information that indicates that it may not be needed for nearly a decade. According to the Federal Communications Commission, a new process for issuing telephone numbers could allow New Mexico to remain under one area until 2014.
Under the old system, new telephone numbers were issued in batches of ten thousand and many were wasted. Phone numbers go to waste because some telephone companies such as rural cooperatives and wireless companies do not need ten thousand numbers at a time. In March, 2002, New Mexico's new numbers will be issued in batches of one thousand. The reduced waste along with returned numbers will postpone the need for a new area code.
The NM PRC's decision to adopt a new area code had been based on official projections that the state would run out of new 505 phone numbers sometime in 2003. In May, 2001, the NMPRC had voted 3-2 to require Albuquerque and Santa Fe to use the new area code and upheld that decision in another 3-2 vote in June. Both votes were split among the Commissioners who are elected by district along rural/urban lines and bucked the nationwide trend of allowing larger metropolitan areas to keep the original area code.
The plan to change Albuquerque and Santa Fe area codes was expected to cost these areas close to a hundred million dollars and a group of Albuquerque businessmen, the 505 coalition, had appealed the NM PRC's decision to the New Mexico Supreme Court. At the request of the NM PRC and the 505 coalition, the state Supreme Court remanded the case to the agency.
PNM Abandons Merger, Files Suit Against Western Resources
The board of Public Service Company of New Mexico recently voted to officially terminate its $4.4 billion merger agreement with Western Resources, Inc., a Kansas utility. PNM entered into the merger agreement in November of 2000 and signs of trouble started soon thereafter.
In July, 2001 the Kansas Corporation Commission (KCC or Commission) ordered Western Resources to cut its rates by $15.6 million instead of granting Western's request for a $151 million rate increase. The Commission also ordered Western to abandon plans to separate its electric utilities from its debt-ridden unregulated businesses. The rate increase and the restructuring plans were pivotal to the PNM merger.
Talks between the two companies broke off in August, and PNM filed suit against Western in October in New York state court, asking the court to declare that it has cause to terminate the agreement with Western and for an unspecified amount of damages. In November, Western filed suit against PNM claiming it lost $650 million as a result of the failed merger.
According to PNM, the lawsuits will not affect New Mexico ratepayers because the legal costs and any damages will be charged to shareholders.
FERC
FERC Focuses on Wholesale Market Power
The Federal Energy Regulatory Commission has focused attention on generation market power in wholesale electricity markets. On November 20, 2001, the Commission issued two significant orders addressing its market-based rate methodology and market power screening functions. FERC also announced plans to create a new office within the agency to oversee wholesale energy markets.
In the November 20 order concerning market-based rate methodology, the Commission proposed to place conditions on all existing and new market-based rate tariffs. The conditions are intended to curb anticompetitive behaviors or the exercise of market power by generators. (FERC Docket No. EL01-118). The order proposes a blanket provision that would subject the seller's market-based rate authority to "refunds or other remedies" if the seller is found to have engaged in anticompetitive practices or to have exercised market power. The order describes "anticompetitive behavior or exercises of market power" as behavior that raises market prices through "physical or economic withholding of supplies," and it gives examples of some behaviors the Commission believes will trigger the proposed conditions.
The second November 20 order, issued as part of its consideration of the triennial market-based rate authority updates submitted by three companies, establishes a new generation market power screen (FERC Docket No. ER96-2495 et al.). Since the 1980's, the Commission has allowed sales of electricity in wholesale markets at "market-based rates" when it found that the seller did not currently have, and could not exercise, generation market power. In these previous decisions, the Commission used a "hub and spoke analysis" to determine the applicant's market share of uncommitted generation in a particular market. While there was no specific standard, FERC normally found that market power existed when the seller had over 20% market share in the given market.
The market power screen newly announced in this order, called the Supply Market Assessment (SMA), differs from the previous market power screen in two respects. First, the SMA screen considers transmission constraints when determining the relevant geographic market. The Commission believes that this change allows the market power screen to "more accurately determine what supply can reach buyers to compete with the applicant." Second, the new screen establishes a specific threshold for determining whether an applicant has market power in a given geographic area. The new test determines whether the applicant is "pivotal" in the relevant market by considering whether the applicant's capacity exceeds the market's surplus of capacity above peak demand, known as the market's "supply margin." An applicant is "pivotal" in the market, and fails the SMA screen when its capacity exceeds the market's supply margin. The Commission noted that this new calculation will "identify whether the applicant is a must-run supplier needed to meet peak load in the control area," making the screen more "sensitive to the potential for the applicant to successfully withhold supplies in the market in order to raise prices."
Finally, FERC announced that as of January 2002, it is creating a new Office of Market Oversight and Investigations (OMOI). The OMOI will be responsible for monitoring wholesale energy markets and identifying potential problems and flaws in those markets. It will also suggest possible enforcement actions for market violations. The Commission hopes the OMOI will provide FERC with an "early warning system" capable of identifying potential market problems before they reach crisis levels. William F. Hederman, Jr. was recently appointed director of the new office.
Combined Electric and Natural Gas Standards of Conduct Considered
The Federal Energy Regulatory Commission is currently considering revised standards of conduct for energy affiliates of electric and natural gas transmission providers (FERC Docket No. RM01-10). The revised standards of conduct proposal, which was issued on September 27, 2001, would combine and expand the current standards for the electric and natural gas industries.
The current standards of conduct for natural gas industry affiliates are contained in FERC Order No. 497, issued in 1988, while the standards for electricity industry affiliates are set forth in FERC Order No. 889, issued in 1996. Both sets of standards were intended to prevent the exercise of market power over transmission of natural gas or electricity by separating transmission function employees from energy marketing employees and by ensuring that transmission services are provided to affiliates and non-affiliates in a non-discriminatory fashion. The Commission proposes to combine and revise Order No. 497's and Order No. 889's standards because of the increasing convergence of the two industries. This convergence sparked fears that entities that own both natural gas transmission and electric generation could exercise undue market power over the provision of natural gas for gas-fired electricity generation.
The revised standards, if adopted, would include expanded definitions of "transmission provider" and "affiliate," and would apply to all energy affiliates of transmission owning entities, and not just to their marketing and sales affiliates. This means, for example, that the standards of conduct would apply to purchases of electricity intended to serve the transmission provider's native retail load. These transactions are exempt from the current standards of conduct. Transmission providers that are themselves a FERC approved Regional Transmission Organization would be automatically exempt from the new standards, while transmission providers who have granted managerial and operational control over their transmission facilities to an RTO could request an exemption under the proposed rules.
FERC Continues Interconnection Rulemaking Process
Following up on its October 12, 2001 announcement (see Regulated Resources, November 2001), the Federal Energy Regulatory Commission issued an Advanced Notice of Proposed Rulemaking (ANOPR) addressing the standardization of generator interconnection agreements and procedures (FERC Docket No. RM02-1). The October 25, 2001 ANOPR set an aggressive timeline for filing comments and sought to have interested parties file a single "consensus document" outlining points of agreement and pros and cons on issues where agreement was not reached.
The ANOPR announces the Commission's intent to adopt a set of standard generator interconnection procedures as well as a standard generator interconnection agreement that would apply to all utilities subject to the Federal Power Act. FERC is considering basing its standards on those adopted by the Electric Reliability Council of Texas (ERCOT) with an additional set of "best practices." The ERCOT standards and the Commission's "best practices" were attached to the ANOPR for comment.
The best practices document, which was developed by the Commission based on its decisions in previous cases, includes several noteworthy items. The practices require comparable treatment between transmission providers that serve both retail loads and merchant generators. This requirement would change the current rules which permit transmission owners who serve retail load to reserve capacity on their system for future load growth, by allowing "other suppliers such as merchant plants" to be competing resources for meeting load and load growth. The practices would also require transmission providers to initiate streamlined procedures for generation projects under 20 megawatts and exempts these smaller projects from the requirement to pay for transmission studies or network upgrades. The best practices document also addresses generator siting and would require transmission providers to post optimal and non-optimal generation sites on their web site. The Commission's best practices document also discusses the interconnection products transmission providers must offer, the queuing of interconnection requests, and deposits and time lines for interconnection projects.
The ANOPR included FERC's current pricing policy without modification. The Commission noted that it will address cost responsibility and pricing in the next generator interconnection standards rulemaking, and that its inclusion of the current pricing policy should not be considered an indication of its long-term preference.
The consensus document requested by the Commission was filed on January 11, 2002. After considering comments, FERC is expected to issue a second, more specific NOPR, which is likely to include provisions regarding pricing and cost responsibility.
FERC Green Lights Midwest RTO that includes Alliance
The Federal Energy Regulatory Commission granted Regional Transmission Organization status to the Midwest Independent System Operator (MISO) by acting on five interrelated orders at its December 19, 2001 meeting. (FERC Docket Nos. RTO1-87-000, et al; RT01-88-000, et al; EL-01-80-001, et al; ER01-3000-000, et al; EC01-137-000). It also denied the Alliance Companies' proposal for a separate stand-alone RTO and ordered Alliance to explore joining the not-for-profit MISO organization. FERC stressed that its approval of another not-for-profit RTO does not preclude other RTOs in other parts of the country from adopting a different, for-profit, organizational form such as a transco.
The decisions placed a clear emphasis on the importance of the scope and configuration characteristics of proposed RTOs. For example, the Commission cited MISO's announced merger with the Southwest Power Pool (SPP), which vastly increases the scope of the RTO. In fact, the merged MISO-SPP RTO will operate in twenty states and in the Canadian province of Manitoba. Furthermore, FERC indicated that Alliance's RTO proposal lacked sufficient scope and that the public interest in a large, seamless and robust market would be best served if Alliance joined the MISO.
Although the FERC denied Alliance's proposal for a stand-alone for-profit RTO, the Commission said it was confident that the companies could form a successful Transco under the MISO's Appendix I. This appendix provides a framework for the membership in and operation of independent transmission companies within the Midwest ISO. In another order, the FERC addressed a National Grid proposal to manage the Alliance transmission system. It directed Alliance to explore how its business plan, including National Grid's proposal, could be accommodated within the MISO RTO.
In other orders, the Commission said that International Transmission Company could join the new RTO as an independent transmission company with the ability to pursue innovative business strategies. Under ITC's proposal, it will be responsible for maintaining and developing transmission while the RTO will be responsible for congestion management and curtailments, tariff administration, and security coordination.
Although the FERC generally approved of the MISO's structural characteristics, it did require some changes. The Commission found that while MISO generally met the independence requirements of Order 2000, it was unacceptable to allow transmission owners to have veto privileges on filings that affect pricing. It also conditioned the MISO's RTO status on modifying its agreement to give it the authority to propose rates, terms, and conditions of transmission service. FERC also indicated that MISO needed to make some changes to comply with Order 2000's scope and regional configuration requirements. To that end, FERC ordered MISO to present recommendations for its eastern seam within 60 days of the order so that integration with Alliance goes more smoothly. The Commission also ordered MISO to participate in FERC Docket No. RM01-12, the rulemaking aimed at standardizing market design rules. FERC also told MISO that it should develop congestion management solutions while the final rule is pending.
The Commission required MISO to make additional filings to ensure that its independent market monitor (IMM) is truly independent of the RTO. It also directed MISO to re-file its market-monitoring plan as an attachment to its tariff. It directed MISO to modify its planning framework to make it possible for third parties to participate in constructing and owning new transmission facilities and to fully consider all market perspectives and identify expansions needed to support competition and reliability.
Alliance, MISO at Impasse
In early March, the Alliance Companies filed a petition asking FERC for an order finding its proposed policy resolutions provide an appropriate basis for Alliance GridCo to participate in the Midwestern RTO. The parties (MISO and Alliance) had recently informed FERC that their Commission-ordered negotiations were stalled. The goal of the talks had been to explore ways for Alliance to operate an independent transmission company under MISO's umbrella.
The two could not agree on how operational functions should be split between the Alliance GridCo and the MISO. Other areas of disagreement include the level of services the GridCo should have to purchase from the MISO, formulas for calculating service charges, rate design methodology, and revenue distribution for transmission service within the MISO RTO. Furthermore, Alliance claims MISO bears the responsibility for the failed negotiations and is treating Alliance differently from other independent transmission companies interested in operating under the MISO's umbrella.
FERC Orders for the WSCC and California Markets
The Federal Energy Regulatory Commission issued a broad rehearing order concerning a number of issues related to the California and western energy markets (FERC Docket Nos. EL00-95-001, et al). This order addressed rehearing and clarification requests for FERC's August 23, November 1, December 8 and December 15, 2000 orders as well as its March 9, June 19, and July 25, 2001 refund and price mitigation orders.
FERC issued a wide range of changes and clarifications that affect sellers, buyers (including the California ISO), pricing, and refunds. The order clearly excluded governmental sellers (such as federal and municipal utilities) and Rural Utilities Service-financed cooperatives from price mitigation in bilateral transactions outside the ISO spot markets and from the must-offer requirement outside California. FERC also eliminated the December 15, 2000 under-scheduling penalty. This order allows marketers, load-serving entities, and hydroelectric units selling in the California ISO and PX markets to submit evidence (during the refund period after the conclusion of the refund hearing) that the refund method results in a total revenue shortfall for their transactions.
The order also contained other cost-related clarifications. For example, it directed the California ISO to pay the cost that generators incur to comply with the must-offer requirement, the cost of keeping units at minimum load status, even if the ISO does not purchase the power. (See also FERC Docket Nos. ER01-3013-000, ER01-889-000 where the Commission ordered the ISO to enforce the creditworthiness provisions of its tariffs and waived the must-offer requirement for generators in transactions not backed by a creditworthy party.) FERC also made it clear that units operating outside California may set the mitigated market-clearing price. According to the December 19, 2001 order the mitigated market-clearing price is set by the proxy price of the last unit dispatched and not by the lower of the proxy price or the actual bid of the marginal unit.
In a separate but related order, FERC altered the price mitigation method for west-wide winter spot market transactions (FERC Docket No. EL01-68-000). The change is triggered when the average of three gas indices increases 10 percent from the level last used to calculate the mitigated price and will remain in place through April 30, 2002.The recalculation was designed to bring continued price stability to the west where a large number of the systems in the 11-state Western Systems Coordinating Council (WSCC) are winter-peaking systems.
In its most recent order, the Commission consolidated and set for an evidentiary hearing several complaints related to long-term power contracts in the western market. Several utilities in California, Nevada and Washington State filed complaints alleging that the prices they were charged under long-term power contracts were the product of energy markets found by the FERC to be dysfunctional, making the prices unjust and unreasonable. The complaints ask that the contract prices be modified. The Commission elected to set the complaints for an evidentiary hearing to afford the plaintiffs in each case the opportunity to meet the unusually high burden required to justify contract modification. The order noted that the evidence contained in the complaints alone did not meet this burden. Before a hearing takes place, however, the order requires the parties to comply with any contractually required mediation, and urged the parties to make every effort to settle the cases during mediation.
Arizona
Arizona Transmission Project Gains Approval; Generation Project Put on Hold
In early February, the Arizona Corporation Commission (ACC or) approved a new transmission project in the Phoenix area, while a generation company announced that it has shelved plans for a new facility in the state.
On February 7, 2002, the ACC approved a new high-voltage transmission project proposed by Arizona Public Service Company (APS) and the Salt River Project (SRP). The new 500 kV line will connect the Palo Verde Nuclear Generating Station to Avondale, Arizona, a community west of Phoenix. According to APS, the project is needed to relieve transmission constraints in the fast-growing metropolitan area. After several rounds of hearings and testimony, the project was recommended for approval by the Arizona Power Plant and Transmission Line Siting Committee, the entity charged with evaluating new generation and transmission projects under Arizona law. That recommendation contained several environmental, aesthetic and engineering conditions. The ACC accepted the recommendation after adding a final condition. The project is scheduled to be complete by Summer, 2003.
Also in February, Reliant announced that it is halting plans for the Signal Peak generating facility in Arizona. The first phase of the 1,160 MW natural gas fired project was scheduled to come online in 2004. The company cited new forecasts indicating that energy supplies in the West will be adequate in the next several years as the basis of its decision.
Arizona Regulators Consider Electric Restructuring Issues
On January 22, 2002, the Hearing Division of the Arizona Corporation Commission opened a generic docket to consider issues related to electric restructuring, which has already commenced in Arizona. Interested parties have until February 25, 2002 to respond to a number of questions posed by the Commissioners on a wide range of electric restructuring issues such as corporate structure and affiliate transactions, renewable energy, pollution from electric power plants, federal and state jurisdiction, revisions to the Electric Competition Rules, and information about retail electric providers. The ACC staff has requested the Commission consolidate its consideration of generic docket issues with an inquiry on the Arizona Independent Scheduling Administrator, a request by Arizona Public Service Co. for a variance to allow it to purchase power from an affiliate, and Tucson Electric Power's request for variance and market generation credit proceeding.
Utilities, Energy and Telecommunications Law
Modrall Sperling's energy and regulatory lawyers have handled some of the most significant matters heard by New Mexico regulators, such as securing the state's first location permit issued for a nonutility electric generating station. We are well-versed in New Mexico's recent electricity deregulation legislation and in the legislation merging the Public Utilities Commission with the State Corporation Commission to form the Public Regulation Commission. We have represented clients in transactions, legislation, rulemakings, adjudications, and litigation concerning electric, gas and water utility certification, franchise agreements, rates and service, implementation of the Federal Energy Policy Act of 1992, electricity, gas and telecommunications assets siting, interconnection, transmission, financing, acquisitions and mergers, electric and gas restructuring and doing business with electric, gas, water and telecommunications utilities. Modrall Sperling also brings unique expertise to energy and regulatory issues in Indian country.
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