The New Mexico Public Regulation Commission (PRC or Commission) has continued to consider the establishment of an RPS in the state. After holding a hearing and a workshop to consider the issues surrounding the standard in recent months, the Commission issued a new proposal on October 1, 2002. This new proposal replaces the one issued in March 2002 (see Regulated Resources, May 2002).
The new proposed rule, applicable to public utilities in the state, would establish an initial RPS of 4%, effective January 1, 2004. This RPS would increase to 7% on January 1, 2007, and 10% on January 1, 2010. The rule would allow utilities to meet the RPS requirement through either the purchase of renewable energy, or the construction of renewable energy generating facilities. Under the proposal, no single type of renewable energy may make up more than 50% of a utility's RPS. The proposed rule states that "[o]ther factors being equal, preference shall be given to renewable energy generated in New Mexico." Additionally, the rule would require utilities, when constructing new plants or procuring new energy supplies, to "prefer renewable energy over non-renewable sources if the life cycle costs of the renewable energy are similar to non-renewable sources on a net present value cost basis." The proposed rule would also require utilities to offer a voluntary renewable energy tariff, allowing customers to purchase additional supplies of renewable power at an added cost.
Other provisions in the rule include portfolio reporting requirements for utilities, a net metering option for renewable energy sources of less than 100 kW, and exemption and variance provisions for utilities who cannot meet the RPS mandate. Comments from interested parties are due on October 23, 2002, with response comments due on November 6, 2002. A hearing on the proposal will be held on November 14, 2002, in Santa Fe.
FERC Proposes Standard Market Design for Wholesale Electricity Markets
After several months of planning and meeting with stakeholders, on July 31, 2002, the Federal Energy Regulatory Commission (FERC or Commission) released a Notice of Proposed Rulemaking (NOPR) on standard market design. The NOPR proposes several changes and modifications to the Open Access Transmission Tariffs (OATTs) maintained by public utilities that own or control interstate transmission facilities. According to the Commission, the new rule is intended to remove the remaining impediments to competitive wholesale electricity markets that have not been remedied by Orders 888, 889 and 2000.
The most controversial provision of the new rule asserts FERC jurisdiction over the transmission portion of bundled retail electricity transactions. Currently, FERC only asserts its jurisdiction over wholesale transmissions of electricity. State regulators have voiced strong opposition to this provision, arguing that it usurps too much of their authority to regulate power markets within their states.
The NOPR also makes several changes in the provision of transmission service. First, the new rule would establish a single type of transmission service, Network Access service, replacing the several types of transmission service available under the current OATTs. Additionally, the rule would require all transmission service to be provided by an independent transmission provider (ITP). After final implementation of the rule, all transmission providers must either meet the definition of an ITP, turn the operation of their transmission facilities over to a Regional Transmission Organization (RTO) that meets the definition of an ITP, or contract with an ITP to manage its transmission system. ITPs, and RTOs meeting that definition, will administer the day-ahead and spot markets, perform market monitoring and market power mitigation, and transmission planning and expansion on a regional basis.
Another significant proposal in the rule concerns resource adequacy and system reliability. The rule contains a resource adequacy requirement that mandates a minimum 12% reserve margin in each region. Under these provisions, the ITP is responsible for forecasting future demand in its region, and assigning each entity that serves load within its region the responsibility to provide a share of the needed resources based on the ratio of its own load to the overall load in the region. ITPs are also given enforcement mechanisms under these provisions.
The rule contains several measures dealing with the management of transmission congestion and the mitigation of market power. With regard to transmission congestion, often blamed for shortfalls in locations such as California, the rule proposes the use of locational-marginal pricing (which sets different prices for the transmission of energy between different points on the grid), which FERC believes will provide for "economic redispatch" to manage congestion. The rule also provides several market power mitigation measures, including soft and hard bid caps that are triggered based on certain market conditions.
A more complete summary and analysis of the rule has been prepared by Leslie Lawner, and is available on our website. Under the timeline proposed by the Commission, the rule's requirements would be phased in beginning in July 2003, with full implementation complete by September 30, 2004. Recently, however, FERC has indicated that it may delay the final rule in order to address several concerns within the industry, and has pushed back the deadline to file comments on some of the issues in the proceeding.
PNM Wins Right to Continue Receiving Transmission Service from APS
On May 15, 2002, FERC ordered Arizona Public Service Company (APS) to continue to provide transmission service to Public Service Company of New Mexico (PNM) under an agreement between the two companies executed in late 2000. The dispute in the case centered around APS's denial of PNM's request to continue to take transmission service under the right of first refusal contained in APS's Open Access Transmission Tariff (OATT).
At issue in the case were two transmission service agreements entered into by the parties. Under the first agreement, APS provided PNM 10 MW of long-term firm point-to-point transmission service between Palo Verde and the Mead Switchyard in the Las Vegas, Nevada area for one year (January 1, 2001 to December 31, 2001). Pursuant to the second agreement, APS provided PNM with 50 MW of long-term firm point-to-point transmission service between Palo Verde and the Westwing Switchyard, in the Phoenix, Arizona area for one year (January 1, 2001 to December 31, 2001).
In October of 2001, PNM notified APS that it intended to exercise the right of first refusal provided by § 2.2 of the APS OATT to extend the agreements for an additional year. APS stated that the right of first refusal could not be accommodated on the Palo Verde to Westwing corridor because that capacity would be recalled for use by the utility's native load.
PNM contended in its complaint that APS could not recall the capacity at issue for use by native load because neither of the service agreements contained an explicit reservation of rights by APS to recall the transmission capacity for native load growth. In support of this proposition, PNM cited Order No. 888's admonition that a transmission service agreement should specify "in the contract that the right of first refusal does not apply." PNM also noted in the complaint that § 2.2 of the APS OATT is unchanged from the pro forma tariff issued in Order No. 888, and explicitly provides for a right of first refusal for existing firm service customers.
In answering the Complaint, APS argued that PNM was "continuously aware that a right of first refusal was unavailable for the capacity" originally provided in the Agreement. APS stated that it had posted on its open access same time information system that anticipated native load growth across the transmission lines in question would reach the maximum allowable level sometime in 2002, but due to a clerical error, the system indicated that APS had sufficient available transmission capacity to accommodate PNM's right of first refusal. APS also argued in the answer that Order No. 888 does not require a transmission provider to specify in a contract that a right of first refusal will not be available because it uses the word "should" instead of "shall." Therefore, APS argued that Order No. 888 only suggests that the contract should specifically provide that a right of first refusal will not be available.
The FERC order granting PNM's complaint stated that prior Commission precedent and Order 888 definitively concludes that any restrictions on the right of first refusal provided in a transmission provider's tariff must be explicitly included in the transmission service agreement. The order also noted that the use of the word "should" in Order 888 "does not mean that this is an option for the service provider." As a result of this finding, the Commission ordered APS to allow PNM to exercise its right of first refusal for an additional year of transmission service.
Administration Proposes New Source Review (NSR) Overhaul and "Clear Skies" Legislation.
The Bush administration recently proposed an overhaul of the application of NSR to power plants when they are expanded or refurbished. The administration proposal would allow utilities to choose the 24 consecutive month period used to establish a baseline to determine if NSR requirements must be met by a plant modification, and also clarifies and expands the definition of "routine" repairs that are exempted from NSR requirements. The administration argued that the changes were being proposed because the old rules were hindering investment in new generation needed to meet demand, while opponents blasted the proposal as a significant weakening of environmental protections.
In addition to the proposed retooling of the NSR process, the administration also proposed legislation allowing energy generators to buy and sell pollution credits. The "Clear Skies" proposal would set caps on nitrogen oxide and sulfur dioxide emissions from power plants, and then allow generators who exceed the caps to purchase credits from other utilities whose emissions fall under the caps.
September 11 Security Concerns Spur FERC Actions
Security concerns prompted by the September 11 terrorist attacks, especially at nuclear power plants, have prompted FERC to consider energy information and energy facility security. After issuing a policy statement on October 11, 2001, announcing that previously public documents that contained specifications of energy facilities would no longer be made available to the general public, and could only be obtained via Freedom of Information Act request, the Commission initiated a rulemaking intended to develop regulations that will limit the public availability of "critical energy infrastructure information." (FERC Docket No. RM02-4). The rulemaking is aimed at developing a process for handling requests for such information (including assessing need for the information, determining the identity of the requester, etc.), and is also intended to clarify the definition of "critical energy infrastructure information."
FERC also issued a landmark decision allowing San Diego Gas & Electric (SDG&E) to increase its rates in order to recover the extra grid security costs it has incurred since September 11. (FERC Docket No. ER02-1687). The order allowed the utility to increase its transmission rates by $ 0.00004/Kwh in order to raise nearly $700,000 each year to pay for extra grid security measures. SDG&E noted in its application that it served several military installations, and that the extra security was intended to prevent unauthorized access to substations and control areas. Shortly after the September 11 attacks, the Commission had told utilities that it would approve such increases if the extra security costs were prudently incurred.
Finally, FERC has proposed security standards for all participants in electric markets. According to the Commission, the purpose of the standards is to "ensure that electric market participants have a basic Security Program protecting the electric grid and market from the impacts of acts, either accidental or malicious, that . . . could cause wide ranging, harmful impacts on grid operations and market resources." The proposed standards, posted on FERC's website (www.ferc.gov), cover such items as access control, personnel, electronic systems management, planning and incident response. FERC proposes that the standards become effective on January 1, 2004, and would require that each participant file a self-certification each year thereafter certifying that they are in compliance with the standards.
Update on California – FERC Alters Price Caps, Considers Altering Power Contracts
In mid-July, FERC voted to raise the price cap on wholesale electricity sold in the California and Western markets to $250 per megawatt hour, which began on October 1. The new price cap replaces a previous cap of $91.87. The Commission stated that the higher bid cap was necessary to attract supplies and protect against another power shortage in the West. The Commission's order also instituted certain reforms in the mitigation process for the California market, and retained the "must-offer" requirement currently imposed on power generators in certain circumstances.
The Commission has also been considering the requests of California to renegotiate and alter the terms of several long-term power contracts it signed during the energy crisis. The state claims that it was overcharged, and that the rates in the contracts are unjust and unreasonable. The parties were directed to Commission-facilitated mediation in July, and were granted more time to reach agreement by a FERC administrative law judge in August.
Most recently, FERC has filed suit in United States District Court for the District of Columbia to enforce a July order it issued requiring a reorganization of the California ISO. In that order, the Commission ruled that the ISO board was not truly independent, as required by Order 888's ISO principles. The order required the ISO to organize into two tiers, with an independent non-stakeholder board responsible for making decisions, and a stakeholder board in an advisory role. California Governor Gray Davis called the order "nothing less than a hostile takeover of California's electricity grid by the federal government," and the ISO voted not to follow the dictates of the order.
FERC Issues Order on El Paso Pipeline Capacity Allocations
On May 31, 2002, the FERC issued an order directing El Paso Natural Gas to change the capacity allocation procedures in its gas transportation tariff. El Paso has two types of firm transportation contracts -- contract demand (CD) and full requirements (FR) contracts. CD contracts give the shipper specific delivery rights up to an agreed-to quantity at certain designated delivery points. FR contracts enable the customer to take its full natural gas requirement every day with no specified volume limitation. FR contracts serve primarily the East-of-California customers while customers receiving gas at the California border do so under CD contracts. Both contracts give shippers the right to system-wide primary receipt points, allowing them to nominate gas from any basin or pool. If nominations at a point exceed capacity, the nominations are prorated based on capacity availability.
At the time the FR contracts were authorized in a 1996 rate settlement, El Paso had excess, unsold capacity on its system. Currently, there is no longer excess capacity on the system. The San Juan Basin is one of several basins that deliver gas into El Paso, and prices there are generally lower than in other producing areas. As a result, shippers nominate more supplies from the San Juan Basin than El Paso can receive. This requires pro-rationing at receipt points in the San Juan Basin and has led to FR customers receiving service in excess of their 1996 billing determinants and CD shippers receiving service below their contracted levels.
El Paso made a compliance filing under the Commission's Order No. 637 to allocate capacity to FR and CD shippers and three complaints were filed against El Paso's existing capacity allocation procedures. In response, the Commission found that El Paso's existing capacity allocation methodology has ceased to be just and reasonable as it results in regular reductions in firm service and causes CD customers to make demand payments for capacity they cannot use. FERC also found that unrestricted growth under the FR contracts degrades firm service, that the rates paid by the FR shippers do not effectively ration capacity, and that the FR contracts can also provide unfair competitive advantages to new power plants served under those contracts. Finally, FERC concluded that the FR contracts discourage pipeline-to-pipeline competition since they prevent the shippers from taking service from another pipeline.
To remedy these concerns, FERC found in its order that the FR contracts must be converted to CD contracts. In doing so, FR shippers will have to bid and pay for additional capacity when needed, giving El Paso economic incentive to build capacity necessary to meet growing demand. Once the FR contracts are converted, the FR customers will be free to find alternative capacity arrangements on other pipelines, thus enhancing competition.
El Paso must make additional capacity available to FR shippers through capacity turnbacks, adjustments for seasonal usage, and a priority in the Line 2000 Power Up project. This is to ensure FR shippers have capacity rights at existing levels.
El Paso was also directed to meet with its customers as soon as possible and as often as needed to establish CD entitlements for each FR shipper. El Paso is to initiate a capacity rationalization process in which shippers may turn back capacity and converting FR shippers can acquire that capacity to augment what they acquire during the conversion process. (FR service will remain an option for FR shippers taking service under a ceiling of 10,000 Dth/d.) The FR conversions are to be effective Nov. 1, 2002. Then El Paso must allocate primary receipt point rights among all CD and converting FR shippers, using an iterative process. If, after Nov. 1, 2002, El Paso is not able to provide firm service, for reasons other than force majeure, it will be obligated to give demand charge credit to its firm CD customers.
El Paso will also increase the number of pools in the San Juan Basin from 2 to 4 in order to eliminate the need to allocate capacity pro rata on a daily basis. El Paso will now operate 8 pools: Bondad Station, Bondad Mainline, Blanco, Rio Vista, Anadarko, Plains, Keystone and Waha.
In a follow up order issued on September 20, 2002, the Commission deferred the effectiveness of the FR to CD conversion to May 1, 2003. The Commission reasoned that this deferral would simplify the conversion and allocation process because it will now occur close to the date when new capacity from the Power Up Project would be available. Thus, according to the order, El Paso will be able "to allocate the full 5,400,000 Mcf/d of capacity in the initial conversation." The order also made several clarifications to the initial order.
Commission Investigates Trading Practices FERC or Commission spent much of the spring and summer in both formal and informal investigations of the trading practices of several energy providers. FERC staff has been conducting the investigation, and based on the findings of that informal investigation, the Commission initiated a formal investigation into the trading practices of several utilities during the 2000-2001 energy crisis. The Commission is expected to issue a report to Congress in the coming months.
Rulemaking on Generator Interconnection Moves Forward. On April 24, 2002, FERC issued a Notice of Proposed Rulemaking (NOPR) on standardization of generator interconnection agreements and procedures (FERC Docket No. RM02-4). The proposed rule is intended to establish a single set of interconnection rules for use nationally, so that power plant developers will be familiar with the requirements for interconnection no matter where they build a plant. The NOPR builds on a collaborative "advanced" rulemaking process which the Commission initiated in 2001 (see Regulated Resources, November 2001 and May 2002).
Noting that many interconnection disputes concern the distinction between interconnection facilities and network facilities, the NOPR clarifies that "interconnection facilities" are those facilities located between the generator and the connection to the grid. The NOPR also clarifies that a generator is not required to sign a transmission service agreement to gain interconnection, although establishing an interconnection does not alone grant the generator any rights to transmission capacity. The NOPR additionally provides that transmission providers and any affected third party transmission owners, instead of generators, should coordinate and perform the studies and network upgrades necessary to accommodate the interconnection. The standard generator interconnection procedures in the rule are applied only when a generator interconnects to the transmission system or makes wholesale sales in interstate commerce at the transmission or distribution voltage level. The proposed rule requires small generators of less than 20 MW to pay for all studies and upgrades necessary to accommodate their interconnection, although those smaller generators are provided with accelerated study procedures.
The most significant point of disagreement likely to dominate future debate over the NOPR regards pricing. In the NOPR, the Commission adopted its current pricing policy, which requires generators to pay the full cost of direct assignment facilities, and to pay the costs of necessary network upgrades up front, and then recover those costs through credits on transmission service bills. The current pricing policy was maintained even though the Commission (with the exception of Commissioner Massey) had indicated some willingness to allow parties to argue the circumstances surrounding particular interconnections when deciding upon cost allocations.
Spurred by a dispute before the Commission over an unexecuted interconnection agreement filed by a large base load coal-fired power plant, FERC Chairman Pat Wood III recently stated that the standardized interconnection agreements currently being considered must accommodate the needs of all fossil fuel sources, not just natural gas. Chairman Wood acknowledged that up to this point in the rulemaking process FERC has been primarily concerned with the needs of natural gas fired generation facilities.
The Commission intends to issue a final rule by the end of 2002.
Commission Issues Proposed Policy Statement on Changes to Market-Based Rate Contracts. On August 1, 2002, the FERC issued a proposed policy statement on the standard of review that must be met by parties seeking to justify a change to a market-based rate contract for wholesale electricity sales. The policy statement was prompted by recent uncertainties in wholesale electricity markets, and by the recent complaints filed with the Commission seeking to modify the rates charged in long-term agreements entered into at the height of the 2001 California energy crisis. One issue in those complaints was whether the complainant would be held to a "public interest" standard of review or a "just and reasonable" standard.
Specifically, the proposed policy requires the parties to a contract to include specific language (proposed by the Commission in the policy statement) in the agreement if they intend for the contract to be held to a "public interest" standard of review, also known as the Mobile-Sierra doctrine. If the exact language proposed by the Commission is not included in the agreement, the "just and reasonable" standard would be presumed to apply. The Commission believes this new policy, if adopted, would limit disputes over the proper standard of review and promote certainty in contracting.
FERC Approves Western Pipeline Expansion. On July 17, 2002, FERC issued an order approving an expansion of the Kern River pipeline. The expansion will extend the pipe 716 miles through California, Nevada and Wyoming, and is expected to eventually provide natural gas fuel to approximately 30 percent of the new electric generation scheduled to come inline in southwestern California.
According to the Commission, the approval is the first issued under FERC's National Environmental Policy Act pre-filing process. That process involves an initial collaboration between the applicant, stakeholders and the Commission staff to identify and resolve as many issues as possible early in the application process. FERC attributes the fact that approval of the Kern River expansion was completed in 12 months to this new process.
New Mexico in Brief . . .
Las Cruces Rates May Rise - City officials in Las Cruces, New Mexico are considering a 3.8 percent increase in monthly utility rates. The across-the-board increase for water and gas service, as well as waste collection, is necessary, according to city officials, to ensure that revenues will adequately cover costs in the current fiscal year. City officials also reportedly proposed the increases to cover water rights acquisition and water rights adjudication. Under the plan, gas rates will increase by four percent, while water service rates will go up two percent.
New Power Plant Begins Commercial Operation - The generating affiliate of Public Service Company of New Mexico began commercial operation of a new power plant in Lordsburg, New Mexico. The plant is the first built by PNM to sell power exclusively in the wholesale market, and will be used primarily to serve Texas-New Mexico Power Company under the terms of a five-year all-requirements contract between the companies. PNM expects to begin operation at another new plant, the Afton Generating Station near Las Cruces, in September.
Arizona in Brief . . .
Divestiture of Generation Delayed by Corporation Commission – The Arizona Corporation Commission (ACC) voted in late August to eliminate the requirement that utilities divest their generating assets under the state's deregulation plan. In its decision, the ACC stated that Arizona Public Service Company (APS) and Tucson Electric Power (TEP) both have market power, and that full divestiture would have limited the Commission's ability to protect consumers in those areas where the companies can exercise market power. The decision also required APS to file a separate application to transfer recently built generating assets from its Pinnacle West Energy Corporation to itself.
The vote followed an order by an ACC administrative law judge order recommending a further delay of the divestiture requirement. Judge Lyn Farmer recommended the delay because "the wholesale market in Arizona is poorly structured and susceptible to possible malfunction and manipulation." Judge Farmer's recommended order also included a requirement that state utilities Tucson Electric Power and Arizona Public Service purchase only 50 percent of their power in the open wholesale market, unless their own generating capacity falls short of demand.
Major New Transmission Line in the Works – Utilities in Arizona are planning a new transmission line from the hub at the Palo Verde Nuclear Generating Station, through Pinal County and to the East Valley near Phoenix. The project is intended to serve future growth in Pinal County, west of Phoenix, and the East Valley. While no exact route has been set, utility officials hope to route the line through the Casa Grande-Coolidge area in Pinal County and end it at a substation in East Mesa, where it would tie to an existing East Valley transmission grid. The utilities involved in the project, which include Arizona Public Service, the Salt River Project, Tucson Electric Power, and the Santa Cruz Water and Power Association, have already begun holding public meetings in an effort to gain input on the best route. The utilities plan to take several alternative routes to the Arizona Transmission Line and Generating Station Siting Committee, who will then make a recommendation to the Arizona Corporation Commission. The commission is expected to make a final decision by the end of 2003.
Fires Slow New Transmission Construction – The massive fire that threatened the town of Show Low in the summer and burned large swaths of forest in Eastern Arizona also forced the shutdown of key transmission lines in the area. Those shutdowns were performed as a safety precaution for crews fighting the blaze. The closure of the line, which carries power from a plant in Eastern Arizona to the Tucson area, did not affect service to customers.
Fire danger in dry forests near Tucson has all but halted the planning of a new transmission line in that area. Forest Service closures of lands in the region, as a precaution due to high fire danger and bone-dry conditions, have denied access to officials performing environmental assessments for the project. Originally scheduled to be completed in 2004, the project will now likely be delayed.
The West in Brief . . .
Western Governors Want Expanded Energy Trading Across Borders, Agree on New Transmission Protocols – The Western Governors Association (WGA) agreed in June to advocate for the expansion of cross-border energy trading between the United States, the Western Canadian provinces and Mexico. The governors agreed to develop a process to coordinate energy planning processes in the Western region with cross-border assessments, and to encourage a summit between the U.S., Canada and Mexico to facilitate the planning process. WGA leaders hope the summit can lead to an agreement on reaching the mutual energy demands and environmental goals of the three countries.
The WGA also agreed in June to a set of interstate transmission protocols for siting and permitting new transmission lines. Under the new guidelines, project teams made up of state and federal permitting and policy agencies would consolidate environmental reviews, coordinate deadlines, and share records, information and analysis.
BPA May Hike Rates – The Bonneville Power Administration (BPA), the federal entity that markets wholesale power from federal hydroelectric projects in the Northwest, has hinted that it is running out of money and may be forced to raise rates. BPA traditionally has provided low rates for wholesale service to utilities and direct service customers in the Northwest, while selling its surplus power out of the region. BPA officials say that the higher wholesale electric prices that originally allowed it to provide exceedingly low rates for utilities in its area have dropped significantly, causing its current financial situation.
Nevadans Vote on Public Power for Las Vegas Area – Las Vegas, Nevada area residents voted in support of an advisory question on the November ballot asking voters if the state legislature should "take appropriate action to enable the electricity provider for Southern Nevada to be a locally controlled, not-for-profit entity." The non-binding ballot measure was approved by 57% of the voters in Clark County, which includes Las Vegas.
Nevada Regulators Allow Casinos to Shop for Power – Also in Nevada, the Public Utilities Commission for the first time approved the requests of several casino operators and the owner of a large shopping mall to exit the regulated utility system and buy power from an outside supplier. The requests were filed pursuant to Assembly Bill 661, passed last year, which allows customers that use more than 1 million watts of power to seek permission to buy from a competitive supplier. The first application to exit the regulated system and buy power competitively was unanimously denied by the PSC in March 2002.
In the Courts . . .
D.C. Circuit Rules on FERC Authority Over ISO/RTO Members. In mid-July, the United States Court of Appeals for the District of Columbia Circuit issued a ruling that may call into question the authority of FERC over individual members of ISOs or RTOs. The Court ruled that FERC has no authority to prevent utility members of the PJM Interconnection ("PJM") from changing their rates or withdrawing from PJM without prior Commission approval.
The appeal arose out of a 1997 FERC order conditionally approving the proposal of the utility members of PJM to form an ISO under the principles of Order 888. Specifically, that order was conditioned upon the utilities eliminating a provision in the tariff allowing them to unilaterally change their rates without prior Commission approval. FERC also ordered the utilities to seek FERC permission before withdrawing from the ISO, reasoning that such a requirement was necessary to avoid effectively giving the members of the ISO "implicit" control over the ISO board. The PJM utilities appealed this order, arguing that FERC had exceeded its statutory authority in several ways.
The appellate court found for the PJM member utilities on both issues. With regard to the ability of the utilities to unilaterally file rate changes without prior FERC approval, the Court found that Section 205 of the Federal Power Act (FPA) specifically grants the utilities this right, and FERC is only empowered to reject rate changes after the fact if they are found to be not "just and reasonable" under Section 206 of the FPA. In reaching this holding, the Court rejected FERC's argument that its own Order 888 (with its requirement that ISO's be independent) grants the agency the power to require utilities to forfeit their rights to file new rates under section 205 of the FPA.
With regard to FERC's attempt to assert jurisdiction over utility members who wish to exit PJM, the Court found that FERC had no authority in this regard because Section 202 of the FPA only requires FERC approval for the selling, leasing or other disposition of "jurisdictional facilities" worth more than $50,000. The Court did not accept FERC's argument that joining an ISO is a "disposition" of facilities. Specifically, the Court noted that the terms "sell" and "lease" in the FPA "clearly contemplate a transfer of ownership or proprietary interest". Since the utility members of PJM only granted operational control to the ISO, and did not actually transfer ownership of their transmission facilities, there was no transfer of ownership that could trigger FERC's Section 203 authority.
Second Circuit Strikes Down New York State Legislation Aimed at Con Ed Charges. The United States Court of Appeals for the Second Circuit recently issued a ruling invalidating a law passed by the New York State Legislature that would have barred utility company Consolidated Edison (Con Ed) from seeking to raise its rates in order to recover $200 million in expenses related to a shut down of its Indian Point Nuclear Power Plant. The court's decision was extremely unique because it utilized the bill of attainder clause of the United States Constitution to strike down the state law. That provision, which prevents legislative actions that determine guilt, has never been used by a federal court to protect a corporation.
The state legislation at issue specifically prohibited the New York State Public Service Commission (PSC) from allowing Con Ed to recover its losses from an 11-month shutdown of the Indian Point facility in 2000. The incident leading to the shutdown of the facility raised a stir in the state because Con Ed had reportedly known for nearly two decades that the facility's piping was faulty. The faulty material was not replaced because it would have forced a shut down of the plant. The Legislation at issue not only barred the PSC from allowing Con Ed to recover its costs stemming from the shutdown but also specifically stated in its findings that Con Ed "failed to exercise reasonable care on behalf of the health, safety and economic interest of its customers."
The appeals court held that the New York state law was an unconstitutional "bill of attainder," or non-judicial determination of guilt. The court first held that the bill of attainder clause in the U.S. Constitution could be applied to corporations, noting the rarity of its holding when it stated "we have been unable to unearth any case in which a corporation has ultimately prevailed in challenging legislation as a bill of attainder." The court then went on to find that the New York State Legislature's actions met two other requirements necessary to find a bill of attainder; first, it "define[d] past conduct as wrongdoing," and second, it imposed a punishment for that wrongdoing.
New York has filed a writ of certiorari seeking an appeal of the decision at the United States Supreme Court.
FERC Upheld on Sea Robin Determination. The United State Court of Appeals for the District of Columbia Circuit recently upheld a FERC order reclassifying a portion of the Sea Robin Pipeline from a transportation facility to a gathering facility. The reclassification removed that portion of the pipeline from FERC jurisdiction, since the agency is granted no authority over the rates and charges of gathering facilities. The decision of the court could have ripple effects for other similar offshore pipelines.
The pipeline at issue in the case gathers gas from 67 offshore drilling rigs and transfers it to a compressor station. The gas then travels 66 miles to a processing facility where it is prepared for shipment to customers. In its decision, the appellate court upheld FERC's determination that the 66-mile stretch of the pipeline, beginning at the compressor station, is a transportation facility, subject to federal jurisdiction, while the remainder of the pipeline is a gathering facility. Gas shippers had argued that leaving such large portions of the pipeline unregulated would expose them to price gouging. The court rejected the shipper's arguments, stating that "although we might draw a different line, we cannot say that the commission acted unreasonably in concluding that the . . . compressor station is the place where non-jurisdictional gathering ends and jurisdictional transportation begins."