San Francisco to Fund Nation's Largest Municipal Solar Program

The City and County of San Francisco Board of Supervisors on June 10, 2008, approved a program that will create a fund to provide rebates for residents and businesses that install solar power systems. Under the Solar Energy Incentive Program, the nation's largest municipal solar program, residents could receive between $3,000 and $6,000 for photovoltaic systems. Businesses could receive $1,500 per kilowatt installed, with a cap of $10,000 per building. The 10-year program will use up to $50 million from the city's energy-conservation account. The Board of Supervisors also voted to approve a complimentary one-year pilot program that would budget $1.5 million to buildings owned and operated by low-income residents and non-profit organizations.

The Solar Energy Incentive Program would supplement incentives from the federal investment tax credit and the California Solar Initiative. Creation of the program is propitious since the federal investment tax credit is set to expire at the end of this year.

Supervisor Dufty, a co-sponsor of the measure, believes that the program will provide an important opportunity to encourage the development of the solar industry in San Francisco. The incentives provided by the program will help with installation costs, which are more expensive in San Francisco than in surrounding counties. The program also seeks to help San Francisco increase its amount of solar generation. Currently, the city ranks last in the Bay Area in terms of the solar energy installed per capita, according to data compiled by the California Energy Commission and the California Public Utilities Commission.

CAISO Says It Will Announce MRTU Start in July

It is still unclear when the California Independent System Operator's long-awaited Market Redesign and Technology Upgrade (MRTU) will take effect, but the CAISO recently suggested it will announce the startup date in July 2008. 

Ever since the California energy crisis, the CAISO has worked on designing and implementing a new wholesale power market with features such as locational marginal pricing, financial transmission rights (called congestion revenue rights), and a day-ahead market energy market.  The CAISO filed the MRTU proposal with FERC in February 2006, and proposed a market startup date of November 2007.  Due to technical issues and ongoing administrative litigation over the details of the market design, the proposed startup date has been delayed several times, first to February 2008, then April 2008, and now again to an unknown time.   The latest delay raised the prospect of MRTU not taking effect until next fall, after the high-demand summer season, which the CAISO's latest announcement appears to confirm. 

Southern California Edison Asks FERC to Step into Arizona Transmission Siting Dispute

In the first test of the "backstop" transmission siting authority given to FERC in the Energy Policy Act of 2005 (EPAct 2005), Southern California Edison (SCE) recently discussed with FERC staff the siting of a 230-mile, 500 kV transmission line from the Palo Verde nuclear plant near Phoenix, Arizona to Devers, California, near Palm Springs (known as the Palo Verde-Devers II Line).  SCE representatives met with FERC staffers to begin a "pre-filing" consultation process in advance of filing an application for FERC to approve the proposed siting of the line. 

California covets the line as a means to bring more power into the state, and the California Public Utilities Commission (CPUC) approved the line.  However, SCE's plans hit a obstacle at the Arizona Corporation Commission (ACC).  The ACC rejected SCE's application in May 2007, stating it refused to allow SCE to plug a "230-mile extension cord" into Arizona's generation supply.  The ACC found the line would cost Arizona ratepayers $242 million, could have detrimental environmental impacts, and would significantly reduce available generation in the state, which has a rapidly growing population. 

Arizona's rejection of the line will test the extent of FERC's authority under the national interest electric transmission corridors (NIETC) provisions of EPAct 2005.  Under these provisions, Congress gave FERC authority for the first time to approve, in certain circumstances, the siting of transmission lines in areas of congestion, designated as NIETCs by the US Department of Energy.  These circumstance include when a state public utility commission has "withheld approval for more than 1 year" after a siting application is filed.  In a controversial 2006 rulemaking decision, FERC interpreted the word "withheld" in the statute to mean "deny," indicating that FERC believes it has authority to approve siting of a transmission line even when a state has rejected the line.  This order has been appealed to the US Court of Appeals for the Fourth Circuit.

Following the meeting with SCE, FERC emphasized that no application has yet been filed.  FERC also contacted the CPUC and ACC to inform them of the meeting and seek their input as to whether FERC has authority in this case.  If SCE eventually files an application, FERC will review the records developed before the CPUC and ACC, coordinate actions required by federal law, including federal environmental review, and conduct an independent evaluation.  FERC must issue a decision within one year of the filing of the application.

Final Skirmishes in Enron Contract Wars Draw to Close

Resolving the last remaining claims against Enron stemming from the 2000-2001 California energy crisis, over the past week, FERC approved two settlements involving Enron:  one with the Port of Seattle, Washington (Port), and the other with Public Utility District No. 1 of Snohomish County, Washington (Snohomish).  The Port receives a $500,000 unsecured claim against Enron in its bankruptcy proceeding, while the Snohomish will pay Enron $18 million out of the $180 million that Snohomish allegedly owes Enron in termination fees arising from Snohomish's cancellation of contracts it entered into with Enron during 2001.  FERC's approval of these settlements puts an end to rancorous litigation between the parties and dismisses Enron from the various California refund proceedings.

The Enron-Port settlement continued the debate among the current Commissioners with respect to the Mobile-Sierra "public interest" standard of review for contract modifications.  Commissioners Kelly and Wellinghoff each filed separate opinions to the order approving that settlement, expressing disagreement with FERC's approval of the public interest standard.  Both Commissioners have consistently criticized FERC orders approving the inclusion of the public interest standard in settlement agreements, arguing that the Commission should not bind itself to the that standard, which allows unilateral changes to an agreement only if required by the greater "public interest" ― a singularly demanding burden of proof.  Instead, Commissioners Kelly and Wellinghoff have argued, FERC should approve modifications to settlement agreements so long as they are "just and reasonable," which is considered a less rigorous analysis and makes it easier for agreements to be modified in the future.

In two recent decisions currently before the Supreme Court (the so-called Long-Term Contracts decisions), the US Court of Appeals for the Ninth Circuit questioned whether the public interest standard applies where a buyer challenges a contract price as being too high.

No Common Denominator on Capacity Markets

While organized energy market operators generally agree on locational marginal pricing (LMP) as the basic framework for valuing energy, no similar consensus attends capacity markets.  The New York Independent System Operator (NYISO) presently is retooling its capacity market for New York City in response to a FERC order, and the California Independent System Operator (CAISO) continues to wring its hands over the issue of capacity markets. 

Even though Consolidated Edison divested most of its New York City generation when the NYISO was created in 1999, ownership of in-city generation remained concentrated, requiring rules to mitigate installed capacity (ICAP) prices.  When talks about revising the ICAP rules broke down last July, FERC announced its expectation that the NYISO, working with market participants, would develop market rules that ensured long-term reliability without overcompensating generators.  In response, the NYISO proposed to continue to use auctions and a demand curve for pricing capacity, but also to add features such as must-offer obligations for larger suppliers, as well as an offer ceiling and price floors based on a percentage of the cost of new entry, in order to mitigate seller and buyer market power.  The market's response has been mixed.  Some have urged the use of forward capacity markets in the NYISO.  PJM and ISO-NE have adopted variations of that model, which entails procurement of capacity several years in advance, rather than only several months in advance.

Meanwhile, the CAISO continues its stakeholder process to develop a capacity market.  None will be in place as of the commencement of the CAISO’s LMP market in the spring of 2008.  This won’t be unique for organized market operators.  The Midwest ISO has no centralized capacity market, but instead relies on utility compliance with reliability obligations imposed by the applicable states and reliability organizations.  The Electricity Reliability Council of Texas likewise operates an energy-only market.  Concern by the CAISO and state authorities, however, have driven analysis of a potential capacity market in this energy-import dependent state.   But in November the CAISO’s market surveillance committee (MSC) recommended holding off on development of specific capacity market rules.  It pointed out that capacity market rules typically emphasized generator must-offer obligations, whereas the California’s needs tended to be more specific due to its environmental and renewable energy mandates, and reliance on imports, hydropower and intermittent resources.  Generator interests responded to the MSC’s opinion by pointing out capacity market rules were needed to help promote infrastructure development. 

Parties Submit Joint Settlement of Pacific Intertie Dispute

On November 21, PacifiCorp, Pacific Gas and Electric Company (PG&E), the California Independent System Operator (CAISO), and several others proposed to FERC an uncontested settlement that would resolve disputes over a 94-mile segment of the Pacific AC Intertie (PACI) transmission line between Oregon and northern California.  Uniquely, the 94-mile line at issue is jointly owned by two utilities, one, PG&E,  inside the CAISO, and the other, PacifiCorp, outside of it.  Under the proposed settlement, PacifiCorp and PG&E agreed to share equally the transmission capacity over the PACI between Malin, Oregon and Round Mountain, California, with PacifiCorp eventually providing service on its portion of the line under its open-access transmission tariff (OATT).

The dispute over the PACI began earlier this year.  The two 500 kV lines that comprise the PACI are co-owned by several parties.  PacifiCorp owns the northern half of the 94-mile segment on the eastern line, and PG&E owns the southern half of that segment and has turned operational control of its capacity over to the CAISO.  Since 1967, PacifiCorp had leased its share of the capacity for a low, fixed amount to several California utilities under a 40-year agreement.  Those utilities, in turn, placed PacifiCorp's portion of the line, along with PG&E's portion of the line, under the CAISO's operational control. 

With the capacity lease set to expire by its terms in July 2007, PacifiCorp filed a notice of termination in May, and informed FERC that it intended to begin to offer service over its 47-mile segment under its OATT.  This filing drew opposition from California utilities, the California Public Utilities Commission, and the CAISO.  PG&E in turn proposed revisions to the operating agreements for the line.  In July, FERC ruled that neither PacifiCorp's nor PG&E's proposals had been shown to be just and reasonable and convened a paper hearing to sort out the details. 

With the December 31 end of the suspension period fast approaching, the parties agreed that PacifiCorp and PG&E would "swap" portions of the capacity each owns under a 20-year agreement, such that each party will have rights to half of the capacity on the entire 94-mile path.  PacifiCorp also agreed to lease a portion of its capacity back to PG&E for a ten-year period, with some capacity becoming available under PacifiCorp's OATT beginning in 2012.  PacifiCorp and the CAISO also filed a joint operating agreement for PacifiCorp's share of the line, which continues to provide for CAISO operation of the capacity.  Other agreements relating to the operation of the California-Oregon Interface were also modified to reflect the settlement arrangements, and changes were made to PG&E's Transmission Owner tariff to implement cost recovery under the ten-year lease.  The settlement will thus compensate PacifiCorp for use of its portion of the line, while keeping the capacity within the CAISO's operational control.  The Commission has yet to act on the settlement agreement, and will need to do so by the end of the year in order for the new arrangements to take effect when the existing arrangements expire.

FERC Makes Good on Rate Incentive Promises to Transmission Developers

At its November 15 meeting, FERC announced three decisions awarding several incentive mechanisms to transmission developers.  The orders were issued in response to requests from Southern California Edison Company (SCE), Baltimore Gas & Electric Company (BG&E), and Pepco Holdings, Inc. (PHI), and were among the first substantive decisions since FERC's transmission incentive rulemaking order earlier this year, Order No. 679.  To transmission developers who can show their projects would ensure reliability or reduce transmission congestion that decision, Order No. 679 proposed to provide increased transmission rate incentives, such as higher Returns on Equity (ROE), adders to the rate basis, and inclusion of 100% of Construction Work in Progress (CWIP) and abandoned facilities in rate base.  The transmission developers, in order to qualify, must demonstrate a "nexus" between the incentives sought and the investment being made, i.e., the applicant must show that the incentives are rationally related to the investments being proposed.

Two of the instant orders provided incentives for companies seeking to construct new facilities in the transmission-constrained Southern California and Mid-Atlantic regions.  SCE is building several projects in Southern California:  the Devers-Palo Verde II Project, which consists of two transmission lines; the Rancho Vista Project, which includes a new 500 kV substation; and the Tehachapi Project, which consists of over 200 miles of transmission lines and three new substations and will be used to bring renewable energy (predominantly wind) onto SCE's transmission system.  In its order, FERC found that SCE had satisfied the "nexus" standard of Order No. 679.  The agency went on to allow a 125-basis point ROE incentive for the Devers-Palo Verde II and Tehachapi Projects, and a 75-basis point ROE incentive for the Rancho Vista Project.

Similarly, BG&E is constructing two baseline transmission projects in Maryland.  While FERC granted BG&E's request for a total of 150-basis point adders (for membership in the PJM Interconnection and for constructing baseline transmission), FERC denied BG&E's request to include 100 percent of its CWIP in rate base.  FERC also established a technical conference to determine whether BG&E's projects satisfied Order No. 679's "nexus" test.

In FERC's third order, it granted a request from PHI, on behalf of its transmission-owning public utility affiliates, Atlantic City Electric Company, Delmarva Power and Light, and Potomac Electric Power Company, for a 50-basis point adder to its authorized ROE for continued membership in PJM.  The adder moves PHI's overall ROE up closer to ROEs granted for PJM transmission facilities placed in service since 2006.  FERC explained that granting PHI's request furthered the Energy Policy Act of 2005 directive that FERC encourage utilities to join RTOs and ISOs.

Demand Response Developments: Promotion and Quantification

Utilities and their regulators are increasingly taking steps to foster reductions in electricity demand — whether through improved efficiency in applications or demand management — based on a combination of economic, reliability, and, increasingly, environmental reasons.

FERC's recent creation of an Energy Innovations Sector (EIS) within the newly renamed Office of Energy Market Regulation (OMER) (formerly the Office of Energy Markets and Reliability) is intended to highlight and respond to the growing complexity and potential of demand response in U.S. electric power markets.   The EIS will focus on five areas—demand response, renewables, distributed generation, global warming and advanced technologies—and will be tasked with performing independent assessments of developments in each of these areas as well as serving as an in-house technical advisor on issues regarding the integration of these resources into FERC's traditional concerns of wholesale markets, reliability, transmission planning and resource adequacy. 

Regional collaborative efforts to encourage demand response are also gaining traction in the form of the Pacific Northwest Demand Response Project and the Midwest Demand Response Initiative in the last year.  In addition, the California Independent System Operator (CAISO) plans to open a demand response laboratory this month in an effort to educate consumers on the potential for and importance of demand response.  The lab will feature exhibits and information on the latest demand response technologies, ranging from thermostats that respond to FM radio signals to adjust air conditioning and other residential applications to an automated direct response programs for commercial and industrial clients.  The latter allows utilities and other demand response aggregators to bid in MW blocks of demand reduction at certain prices and allocate the revenue as they wish.  Increasing numbers of utilities are using programs such as these to meet supply.  Finally, the addition of third-party demand response providers to the mix further expands the range of demand response options. 

FERC's Assessments of Demand Response and Advance Metering, issued in August 2006 and again in September 2007, demonstrate, according to FERC Commissioner Wellinghoff, that implementation of demand response programs has shifted from a question of "whether" to a question of "how."  FERC plans to issue another report in 2008 and follow up every two years thereafter, with information updates in the intervening years. 

Other nationwide efforts are also underway to quantify and verify demand response resources.  Quantification can prove difficult since reliability-based demand response resources, such as direct curtailments or interruptible services, are easier to track than are economically induced resources that depend on variable levels of customer participation.  Both NERC and NAESB have undertaken efforts to calculate demand response potential in the U.S.  Also, the US Demand Response Coordinating Committee (DRCC), a group composed of utilities and other energy companies, is working to develop methods for verifying the contribution of demand response resources.

Initiatives Provide Transmission for Renewable Power

The California Energy Commission has initiated a Renewable Energy Transmission Initiative (RETI) to identify transmission projects needed to help the state meet its renewable energy development goals.  In a process similar to that already adopted in Texas, the RETI process entails identifying Competitive Renewable Energy Zones (CREZs) from which renewable energy could be brought to California consumers.  Not surprisingly for the power-importing state, CREZs could be outside as well as inside California, although designation of external CREZs to serve California may not be well received in neighboring states.

The RETI process should complement the California Independent System Operator’s (CAISO) development of transmission financing rules.  The CAISO’s FERC-approved trunkline proposal provides for sharing of costs between interconnecting renewable generators, together with subsidies from other transmission customers.  The CAISO is now working on a tariff proposal for the inelegantly named “Location Constrained Resource Interconnection” rules, and is expected to submit the proposal to FERC by the end of October. 

On the national stage, Senator Harry Reid, the Majority Leader from Nevada, has introduced a bill to promote renewable energy development.  The bill, S.2076, would require establishment of renewable energy zones and direct federal power administrations to identify the transmission needed to access renewable energy in the zones.  The prospects of the bill becoming law are uncertain.  At minimum, however, the bill signals increased awareness by senior policymakers of the need to foster transmission development to connect the nation’s vast renewable energy potential with the load centers in need of energy. 

Supreme Court to Hear Long-Term Power Contract Cases

The U.S. Supreme Court granted certiorari to review two Ninth Circuit decisions involving long-term contracts that were entered into during the 2000-2001 California energy crisis.  In a pair of decisions issued last December, Public Utility District No. 1 of Snohomish County, WA v. FERC and California Public Utilities Commission v. FERC, the Ninth Circuit held that the long-standing Mobile-Sierra doctrine and its "public interest" standard did not protect contracts from unilateral modification when they were entered in a dysfunctional market that caused prices to exceed a "zone of reasonableness."  The Ninth Circuit held that FERC should have reviewed the circumstances under which the contracts were entered, and possibly set those contracts aside if it found the prices to be unreasonable. 

Several groups of sellers sought Supreme Court review of the Snohomish and CPUC decisions to determine whether the Ninth Circuit's formulation of the Mobile-Sierra doctrine was appropriate.  Many argued the Ninth Circuit's view would upend contract certainty in electric markets, thereby inhibiting investment, if contracts could later be revised because of changes in the market, buyer's remorse, or other circumstances outside of a seller's immediate control.  Interestingly, FERC itself had asked the Supreme Court not to hear the cases, arguing that because these cases arose out of the "highly unusual context" of the 2000-2001 energy crisis they provided a "poor vehicle" for the Court to evaluate the proper application of the Mobile-Sierra doctrine to a complaint that rates were too high.

A seven-justice panel of the Supreme Court disagreed and granted certiorari in response to petitions filed by Morgan Stanley Capital Group and Calpine Corp. of the Snohomish decision.  (Chief Justice Roberts and Justice Breyer have recused themselves from the case, without explanation.)  The Court has not yet indicated whether it will grant certiorari petitions for the CPUC decision as well or will simply apply its decision in the Morgan Stanley and Calpine petitions to the CPUC case.  Briefs are due in November and December, and oral argument will likely be scheduled for sometime in the first quarter of 2008.

CPUC to Consider Innovative Energy Efficiency Incentives for State's IOUs

The California Public Utilities Commission (CPUC) will soon consider an innovative incentive program to encourage the state's investor-owned utilities (IOU) to meet energy savings goals.  Based on an August 9 proposed decision by CPUC Commissioner Dian Gruenich and Administrative Law Judge Meg Gottstein, the proposal would pay the IOUs -- include Pacific Gas & Electric Co., San Diego Gas & Electric Co., Southern California Edison Co., and Southern California Gas Co. -- up to $323 million over three years if they exceed the base targets.  If utilities satisfy these goals, the plan would purportedly save California ratepayers $2.4 billion and cut about 3.4 million tons of carbon dioxide emissions in 2008.  Conversely, if the utilities fail to meet the base targets, the plan would impose monetary penalties on them.  The proposal caps both potential earnings and losses for shareholders at $500 million.

Commissioner Gruenich, the plan's chief proponent, argued that the proposal would provide "both a meaningful level of shareholder earnings and an estimated return of over 100 percent on ratepayers' investments in energy efficiency as the utilities reach toward and exceed our 2006-2008 energy savings goals."  The proposed decision is on the CPUC's agenda for its September 20 meeting.

Western Climate Initiative Seeks 15 Percent Reduction in Greenhouse Gas Emissions

Achieving one of the goals set for itself at its inception, the Western Climate Initiative (WCI) has pledged to reduce aggregate regional greenhouse gas emissions to 15 percent below 2005 levels by 2020.   

Initially composed of Washington, Oregon, Arizona, New Mexico and California, the WCI was established in February 2007 with the goal of collaborating on climate action initiatives across the Western U.S., Canada and Mexico.  Since that time, Utah and the Canadian provinces of British Columbia and Manitoba have joined.  Several other states and provinces have signed on as "observers" to the WCI, including Sonora, Mexico; Wyoming; Colorado; Kansas; Nevada; and Ontario and Quebec, Canada. 

According to the Statement of Regional Goal that WCI issued last week, the regional 15 percent goal reflects the cumulative emission reduction goals of the "partner" states and provinces, and does not replace those partners' existing reduction goals, some of which — such as California's — are more aggressive than the WCI goal.   

Arizona Regulators Reject Cross-Border Transmission Line

The Arizona Corporation Commission (ACC) recently rejected an application by Southern California Edison Company (SCE) to construct a new transmission line from Devers, California to Palo Verde, Arizona.  The proposed Devers-Palo Verde No. 2 line ― a 230-mile, 1200 MW line estimated to cost approximately $600 million ― had already won approval of the California Public Utilities Commission (CPUC).  According to the CPUC, the line would serve as an important means of reducing the substantial congestion in southern California by expanding the transmission capacity into the area and allowing California utilities to import significant amounts of power from Arizona.  The ACC, on the other hand, dismissed the project as essentially allowing California to plug a "230-mile extension cord" into its generation supply, something the ACC found untenable at a time when Arizona's own population is growing rapidly. 

With both SCE and the CPUC considering appeals, the ACC's decision potentially sets up a fight under provisions of the Energy Policy Act of 2005 that allow FERC to site transmission facilities in certain Department of Energy (DOE)-designated National Interest Electric Transmission (NIET) Corridors for which state regulators have "withheld" approval for more than a year.  In a rulemaking issued late last year, FERC interpreted the word "withheld" in the statute to also mean "denied," thus potentially allowing transmission developers to bypass recalcitrant state regulators in favor of federal regulators.  In May, DOE proposed to designate an area encompassing the Devers-Palo Verde No. 2 line as a NIET corridor.

FERC Tailors Transmission to Connect Renewables

In response to a carefully crafted petition from the California Independent System Operator, the Federal Energy Regulatory Commission took a large step toward facilitating development of the transmission needed to harness wind and other renewable energy sources that are remote from load centers.  With its order granting the CAISO’s petition for declaratory order, FERC approved a financing mechanism that is intended to solve the "chicken or egg" sequencing problem of development of transmission lines and renewable energy generators in areas such as the Tehachapi region of California.

The problem vexing renewable energy advocates is that wind, geothermal and other renewable generators must be built where natural conditions allow.  But wind and geothermal hot spots are often far from the energy-thirsty urban centers, and little transmission is available at these remote locations.  Since most renewable energy projects are much smaller than large hydro or fossil-fuel plants, individual generators can’t afford to develop major new transmission projects.  Nor have transmission owners been keen on building lines to locations where the development of generation is either marginal or uncertain. 

To break this transmission logjam, some states have created transmission development agencies.  But California entities have focused more on creating cost recovery mechanisms that would allow the state's transmission-owning utilities to develop the transmission themselves.  In 2005, Southern California Edison initally proposed a "trunk line" model, but FERC objected  because ratepayers would pay for the entire facility, and because the utility would retain control of it.  FERC solicited an alternative, and the CAISO responded with a program having the following key terms:

• The project must provide access to an area with significant potential for development of remote energy resources.
• Initial costs of qualifying interconnection facilities would be rolled into the transmission revenue requirement of the transmission owner that constructs the facility, subject to a cost cap to protect ratepayers. 
• Later costs would be paid pro rata by generators who interconnect with the line.
• The project would have to be approved through the CAISO transmission planning process.
• A minimum level of generators must commit to the line before it can proceed, and another batch must have shown interest in joining. 

FERC earlier had resisted advantaging renewable energy through favorable transmission rules.  But with its approval of the CAISO program, FERC acknowledges that location-constrained resources are unique and warrant different access rules. 

FERC Dismisses CARE Complaints, Defends Market-Based Rate Program

In an order issued at its April 19 meeting, FERC dismissed two of several pending complaints by the CAlifornians for Renewable Energy (CARE) that urged FERC to abrogate two contracts:  one between Southern California Edison (SCE) and Long Beach Generation, and the other between Pacific Gas & Electric (PG&E), Metcalf Energy Center, and Los Medanos Energy Center.  The California Public Utilities Commission (CPUC) approved both of the contracts as part of its resource adequacy program.  CARE argued that, based on the Ninth Circuit's 2004 decision in State of California ex rel. Lockyer v. FERC and its recent "Long-Term Contracts" decisions (Snohomish PUD v. FERC and CPUC v. FERC), the PG&E and SCE contracts at issue were not just and reasonable and had not been pre-filed with FERC for approval, and thus were not entitled to protections of the long-standing Mobile-Sierra doctrine.  While FERC could have dismissed CARE's complains based on their lack of real factual support or development, the Commission took the opportunity to address the merits of CARE's assertions regarding the meaning of the Ninth Circuit decisions.

FERC defended its market-based rate program on several grounds:  First, FERC emphasized that the court in Lockyer had actually upheld FERC's market-based rate regime.  According to FERC, Lockyer's holding was that the Commission had failed to properly oversee the dysfunctional California energy markets during the 2000-2001 crisis by ensuring adequate compliance with its reporting requirements, meaning that sellers could be subject to retroactive refunds for those sales.  Addressing the Long-Term Contract cases, it appears that FERC's view is a narrow one, i.e., that the court held that the Mobile-Sierra protection will apply when certain factors have been met, including whether FERC provided adequate oversight of the markets in which contracts were negotiated and whether it considered changed market circumstances in deciding whether contracts negotiated in those markets remained just and reasonable. 

FERC also defended its efforts to improve the markets, emphasizing its approval of a significant overhaul of the California market (the MRTU market design);  FERC's enhanced reporting requirements, market oversight, and increased enforcement authority to address manipulation; FERC's guidance regarding reporting to the various price indices; and the Commission's ongoing effort to strengthen its market-based rate program.  FERC made clear that it considered the California crisis to be a "perfect storm" of events that are unlikely to reoccur in the future.  FERC thus determined that the contracts here did not need to be submitted for prior review, testing whether the Ninth Circuit meant what it said when it held that the market-based rate program is still valid as long as certain protections are in place.  Of course, the court has yet to bless many of these reforms, so it remains to be seen whether FERC's efforts will be sufficient.

California ISO Proposes Transmission Tailored to Renewable Energy

Picking up where one the state’s biggest utilities left off, the California Independent System Operator (CAISO) has proposed to FERC a new category of transmission that would facilitate development of renewable energy  ― particularly wind ― in regions short of adequate transmission capability.  If approved by FERC, the new type of transmission could bring on line further development of the productive Tehachapi region and help the state achieve its ambitious renewable portfolio standards. 

Driving the CAISO proposal is the fact that many of the most promising sites for wind energy development are far from existing transmission lines.  FERC’s transmission policies allocate most interconnection costs to the generator, which works against developers of remote wind farms.  The CAISO would lessen this entry barrier by allocating the initial costs of developing a multi-user interconnection line, or trunkline, to the regional transmission owner who, in turn, would recoup those costs over time through the CAISO’s transmission access charge.  Interconnecting generators would then pay their pro-rated share of the line’s costs once they start operations.  Other elements of the proposal are intended to limit cost impacts on ratepayers and ensure this type of transmission is used only for major projects.  

The proposal follows the efforts of Southern California Edison, which in 2005 sought FERC approval for rolling in the costs of a trunkline intended to allow interconnections with wind projects in the Tehachapi region.  In a split decision, FERC rejected the proposal on the grounds that the proposed roll-in did not benefit all transmission users, but there were indications that a proposal by the CAISO might be received more favorably. 

The leader in wind generation, Texas, has taken another path for developing needed transmission.  It will designate renewable energy development zones based on renewable energy potential, and then mandate transmission development from the zones to more populated areas.  Since most of Texas is not subject to FERC’s jurisdiction, however, that proposal did not require Washington's blessing.

Separately, FERC has been conducting a rulemaking to revise its Order 888 open-access tariff.  As part of the rulemaking, FERC has considered requiring transmitting utilities to offer a new category of conditional firm transmission service that would benefit wind and other intermittent sources of energy.  FERC is scheduled to discuss the rulemaking at its upcoming February ­­15 meeting and a final order will likely issue soon thereafter. 

California PUC Takes Steps Towards Reducing State's Emissions

In an effort to comply with a new state law limiting carbon dioxide and other greenhouse gas (GHG) emissions in California, on January 25 the California Public Utilities Commission (CPUC) adopted an interim Greenhouse Gas Emissions Performance Standard.  The interim standard requires the state's energy providers to source their power supply from plants that emit less than 1,100 pounds of CO2 per megawatt hour whenever they enter into any new or renewed power purchase commitments of five years or more.  That emission rate is equivalent to the CO2 emitted from a combined-cycle natural gas turbine.  Construction of new power plants and major investments by utilities in existing power plants would also be subject to the standard.  The interim standard will be in place until the CPUC can establish a permanent, enforceable load-based GHG emissions standard.

The CPUC's decision was seen as a challenge to traditional coal-fired generators whose CO2 emissions would not meet the interim standard, particularly those located outside the state that sell into California markets.  At present, California gets approximately 20% of its power from traditional coal plants that are located outside the state.  Clean coal plants with CO2 controls would be able to meet the interim standard.

CAISO Considers Delaying MRTU Again

California Energy Commission Notes Slow Progress by Utilities on State Renewable Standards

Despite all the legislative efforts to beef up California's renewable portfolio standards (RPS) in recent months, the California Energy Commission (CEC) recently disclosed that the state's investor-owned utilities (IOU) are making little progress toward meeting the state's requirements that 20% of power supply must come from renewable energy sources by 2010.  In an draft update to its Integrated Energy Policy Report, released November 17, the CEC concluded that at the current pace, the state will fail to meet the 2010 goal, unless the IOUs take action now. 

According to the CEC, the primary and most obvious reason for the slow pace thus far has been a lack of construction of new transmission capable of  linking green resources with load ― an obstacle reported in other states as well.  In September, the California IOUs indicated to California Public Utilities Commission (CPUC) that they may fail to meet the RPS goals because of the state's limited transmission facilities.  The CEC report also notes that the California IOUs' renewable efforts have been hampered by green projects that have been abandoned or otherwise never began operations.  For example, according to the CEC's report, while the IOUs have signed contracts since the initial passage of the RPS in 2002 for as much as 4,095 MW of renewable capacity, only 242 MW of that capacity are on-line today.  Other obstacles cited by the CEC include:  the complexity of the CPUC's RPS program for IOUs; financing uncertainty; and slow progress in repowering aging wind facilities.

The CEC report also made recommendations to get the IOUs back on track, such as suggesting that the CPUC clarify its IOU RPS program, enforce RPS non-compliance penalties, expedite its review of already proposed renewable projects by Southern California Edison (SCE) and San Diego Gas & Electric, and work with the California ISO to compel SCE to meet the 2010 schedule for its Tehachapi renewable project.  The CEC also recommended that IOUs be required to procure 3% above what the RPS requires in order to compensate for potential contract failure.  The CEC has scheduled a workshop to be held December 7 to receive input on the draft report.

California Enacts More Aggressive RPS Plan

There are growing concerns that due to transmission constraints and cumbersome regulatory procedures, California will struggle to meet the requirements of its renewable portfolio standard (RPS) legislation.  Nevertheless, in a sign of the state's ambition, Gov. Schwarzenegger recently signed into law an even stricter RPS standard.

Under the new law, the state's retail providers (excluding municipal utilities) must obtain 20% of their power from renewable energy by the year 2010, instead of 2017.  However, another aspect of the law may make the utilities' challenge less onerous.  Until now, California regulators have not authorized the use of renewable energy credits (RECs) to meet RPS requirements, but the new law allows the state's Public Utilities Commission and Energy Commission to develop such a system of credits.  In addition, renewable energy from outside the state may now become eligible to help meet RPS requirements.  These provisions are likely to help integrate western renewable energy markets.

FERC Conditionally Approves CAISO MRTU Filing

In a September 21 order, a full panel of five FERC commissioners unanimously accepted the California Independent System Operator's (CAISO) long awaited Market Redesign and Technology Upgrade (MRTU) tariff.  While directing the CAISO to make some changes around the edges, FERC approved the core of MRTU proposal.  It includes a day-ahead energy market, revised hour-ahead scheduling timelines, a form of locational marginal pricing (LMP), a new congestion management system with long-term firm transmission rights, redesigned market power mitigation measures, and resource adequacy backstop provisions that would allow the CAISO to procure power to meet forecasted load.  The MRTU tariff would also provide for gradual increases of the energy bid cap.  The CAISO proposes to implement MRTU in November 2007.

But several issues need more work, according to FERC.  It directed the parties to convene technical conferences on "seams" issues (how CAISO interacts with neighboring western markets), the allocation of transmission capacity available for imports, and the CAISO's Business Practices Manuals.  FERC also complained that the CAISO's proposal for offering long-term firm transmission rights ─ something that FERC mandated ─ remains mired in stakeholder negotiations.  In addition, FERC directed the CAISO to implement "convergence bidding" within 12 months and to develop measures to counteract incentives for load-serving entities to underschedule, and invited interested parties to file demand response proposals within 60 days.  Responding to commenters that expressed concerns that the necessary software would not be ready and operational by the CAISO's proposed November 2007 implementation date, FERC directed the CAISO to certify at least 60 days in advance of implementation that software and markets will work as expected.

FERC's approval of MRTU comes after a long summer of intensive lobbying by public power groups and public officials in the west who oppose California's market revisions.  Opponents argued that features of the market structure proposed by the CAISO, particularly LMP, were not well suited to western energy markets, and that the changes in California would drive up prices across the west.  In light of the size and importance of the California marekt in relation to the rest of the west, opponents also fear that wherever California goes the rest of the western states will have no choice but to follow.  The FERC commissioners disagreed, and several expressed their views that MRTU would not have adverse impacts on the rest of the west.

CAISO Continues Consideration of Transmission for Renewables

Still struggling with how to establish a third category of transmission, the California Independent System Operator (CAISO) staff has decided to delay for a month its pursuit of a FERC declaratory order approving the new category.  Currently, CAISO's tariff provides for two transmission categories:  network facilities and generation intertie ("gen-tie") facilities.  The third category under consideration by CAISO is intended to assist renewable generators by building the high-voltage transmission lines often needed to bring renewable power to markets from distant locations.  Similar efforts are also being undertaken by the California Public Utility Commission.   

CAISO staff proposes that project costs for this third category be initially rolled into CAISO's transmission access charge.  Once the project becomes operational, the developer would reimburse its share of the costs, thereby making generators' cost responsibilities proportional to the capacity required for each one's interconnection.  CAISO staff plans to make a declaratory order filing asking FERC for guidance on amending the CAISO tariff to incorporate the new transmission category.  This plan has slowed, however, due in part to concerns expressed by the CAISO's Market Surveillance Committee and external stakeholders over whether the new category would unfairly favor renewable projects and whether renewable project developers need assistance.  Also, FERC's rejection last year of Southern California Edison's request for rolled-in rate recovery for a new transmission category gives some CAISO officials pause. 

First in Nation, California Set to Mandate Greenhouse Gas Reductions

California is poised to become the first US jurisdiction to mandate reductions of greenhouse gas (GHG) emissions as soon as Gov. Schwarzenegger signs the California Global Warming Solutions Act of 2006, which he negotiated with the state legislature,  By 2020 the bill would require GHG emissions be reduced to 1990 levels in the state.  Whether the reductions program will include market-based emissions trading favored by industrial interests is unclear.

The bill does not specify a given percentage level reduction of GHG emissions reductions, but requires reduction to a 1990 emission baseline that the California Air Resource Board (CARB)  is to establish.  Much of the detail is left to the CARB's implementation process, which includes adoption of rules and regulations by January 1, 2008.  Regulations for achieving the GHG emissions goals are to take into account many salutary but seemingly incompatible considerations.  These include equitable distribution of emissions allowances, avoiding disproportionate impacts on low-income communities, crediting entities that have already voluntarily reduced emissions, maintaining existing air quality standards, costs and benefits, minimization of administrative burdens, minimization of leakage (a reduction of GHG emissions in-state that is offset by an increase elsewhere), and consideration of the contribution of different sources of GHG emissions. 

By June 30, 2007, the CARB is to issue a list of discrete GHC reduction measures that can be implemented before other measures; by January 1, 2010, the CARB is to adopt regulations to implement those early measures.  Emission sources would have to start GHG reporting in 2008, and the CARB would start enforcing GHG emissions reductions by January 1, 2012.

Gov. Schwarzenegger earlier signed an agreement with British Prime Minister Tony Blair committing California and the United Kingdom to cooperate in battling climate change and promoting energy diversity.  The agreement calls for cooperation on technologies, sharing data, and developing market-based incentives. 

California PUC Judge Rules that LNG Must Meet Air Quality Standards

In a state proceeding addressing the increasingly important issue of natural gas interchangeability, a California Public Utilities Commission ("CPUC") Administrative Law Judge recommended that utilities must ensure that burning of future liquefied natural gas ("LNG") imports, which may have a higher heat rate than other supplies, meets the current applicable emissions requirements.

The proceeding was prompted by concerns about the adequacy of natural gas supplies and infrastructure in California.  As in other parts of the country, imported LNG is expected to help meet growing demand.  In the context of the applicable gas quality standards, utilities San Diego Gas & Electric and its affiliate Southern California Gas Co. asked the CPUC to accept revised gas quality specifications, including a Wobbe Index value (which is related to the gas' heat rate), due to the requirements of future LNG imports, which differ from current natural gas standards.  The South Coast Air Quality Management District, which is the agency responsible for reversing the non-attainment status of the South Coast Air Basin, objected to the utilities' proposal, arguing that future LNG imports are expected to have a higher heat rate and may lead to an increase in emissions from household and industrial equipment and from vehicles that run on compressed natural gas.  The ALJ recommended minor rule changes but otherwise proposed that utilities comply with existing standards and submit an environmental assessment for any proposed deviations from those standards.  The ALJ also would require CPUC staff to conduct studies related to gas quality standards.

California Comes Closer to Renewable Energy Tracking

The California Energy Commission (CEC) has taken another step toward meeting the California Legislature's mandate to create a tracking system to monitor compliance with the state's renewable portfolio standard (RPS).  Last week, CEC approved a contract with the Western Electricity Coordinating Council (WECC) that supports the Western Renewable Energy Generation Information System (WREGIS).  WREGIS is a voluntary, independent renewable energy registry and tracking system for the Western Interconnect that will be used to verify retail sellers' compliance with the California RPS.  WREGIS should ensure that renewable generation will be counted once only for purposes of meeting the RPS and will verify retail product claims in California and other states.  WECC will serve as the institutional home for WREGIS. 

WECC and the CEC expect WREGIS to be up and running by mid-2007.  While initially funded by California ratepayers, once WREGIS is operational it will charge user fees to recover its operating costs. 

Colorado, Oregon, Nevada, New Mexico, and Arizona are also considering requiring the use of WREGIS to ensure compliance with each of their renewable energy policies.  While the contract supporting WREGIS acknowledges that the tracking system could be used in other states, California is focusing on meeting its own accelerated RPS goal of 20% renewable energy by 2010; other states may need to work with WECC individually to tailor the product to their own needs.

Solar Advocates Challenge PG&E Price Reduction

Spotlighting the challenges of balancing utility rates and renewable energy incentives, the California Solar Energy Industries Association (CALSEIA) has protested Pacific Gas & Electric Co.'s (PG&E) proposed revisions to its residential time-of-use electric rates.  According to CALSEIA, lowered summer rates will remove incentives for customers to go solar.   

Lower peak summer rates will protract the time required for solar voltaic customers to recoup their investment made in voltaic technology.  Among PG&E's filed rate revisions, which became effective in May, is a residential time-of-use service tariff that lowers summer peak rates by between 10 and 25 percent, while increasing off-peak winter rates by between 14 and 35 percent.  CALSEIA argues that the lower summer peak rates increase from 10 years to 13 years the period required for solar customers to recoup their investment, extending the payback time for solar photovoltaic systems by about 25 percent.   

US Appeals Court Balloons Seller Refund Exposure on California Sales during 2000-01 Energy Crisis

Nearly one year after ruling that FERC lacks jurisdiction to order governmental utilities to refund proceeds on their sales into the California Power Exchange (PX) and ISO markets during the 2000-01 energy crisis [see Court Limits FERC's Jurisdiction as Bonneville, Munis Escape Refund Liability in California Energy Crisis Case], the same panel of the US Court of Appeals for the Ninth Circuit ruled August 2 that the potential refund liability of other sellers — primarily investor-owned public utilities, independent generators and marketers — could go far beyond the parameters that FERC initially set. 

In addition to making refunds on sales into the PX and ISO single-price auction markets, the court ruled that sellers subject to FERC jurisdiction could also be required to make refunds on (1) out-of-market or OOM sales to the ISO for load balancing, (2) sales made during non-emergency hours when power supply was sufficient to meet demand,  (3)  bilateral block-forward sales to the PX, (4) exchange sales where power would be delivered to the ISO in one time period and repaid in kind plus a premium at a later time,  and (5) sleeve sales in which the seller was actually an intermediary between the PX or ISO and another seller who couldn’t or wouldn’t transact directly with the PX or ISO due credit concerns.  In each of these rulings, the court deferred to and upheld each FERC decision requiring refunds of charges in excess of a mitigated price, irrespective of how poor FERC’s reasoning or inadequate its evidence.  Conversely, the court was at pains to overturn any limitation that FERC placed on sellers’ refund liabilities (as in the case of block forward and exchange sales).  The only exception was the court’s reluctant affirmance of FERC’s decision that long-term bilateral sales to the California Department of Water Resources were not properly at issue in this case involving only sales to the PX and ISO; but even in so ruling the court hastened to add that California buyers “argue, with considerable force” that prices in those bilateral sales were unlawful and “may be the subject of other challenges.” 

Even more stunning than the panel’s single-minded drive to expand the universe of sales subject to refund was its directive to FERC that it expand the time frame of remedies by allowing California buyers to prosecute anew allegations of tariff violations for which refunds would not be confined to a period following a refund effective date no earlier than 60 days following the filing of a complaint.  FERC had confined refunds to sales occurring after October 2, 2000 — the refund effective date set when San Diego Gas & Electric’s lodged its August 2 complaint against sellers to the PX and ISO.  That limitation was wrong, according to the court, because FERC should have allowed the California complainants to seek refunds on earlier sales most, if not all, of which FERC itself had already investigated for tariff violations (including alleged violations of the ISO’s Market Monitoring and Information Protocols) and in many instances entered into settlements requiring the sellers to disgorge revenues back to California.  Although far from a paragon of clarity, the panel’s decision seems to direct FERC to permit the California complainants to seek further refunds on top of those FERC already exacted on some of the same sales to the PX and ISO.

California to Guarantee Recovery of Transmission Investments Supporting Renewable Generation

The California PUC has approved a new mechanism to ensure that utilities recover their investments in interconnecting and transmitting power from renewable generation.  These investments will be recovered in rates to retail customers. 

The PUC action is based on a broad interpretation of California statutes that the PUC asserts allow it to develop cost recovery methods for transmission that supports renewable power.  California statutes encourage renewables by imposing a Renewable Portfolio Standards (RPS) and encouraging transmission to support renewables.  [See California PUC Proposals Aim to Put Ambitious Renewables Goals in Reach.]  Earlier PUC efforts to promote transmission from renewable generators became entangled in FERC's generator interconnection policies. 

FERC says that generators must pay the costs of generator tie lines and that generators must initially finance transmission network upgrades and then recoup their investment in the form of credits against future transmission charges.  The PUC is concerned that FERC's policy will not result in sufficient transmission for renewable generation, preventing the state from achieving its RPS goals.  This issue takes on particular urgency because of pending disputes over who pays for transmission to a potentially large wind power development in the Tehachapi region.  The wind developers say they cannot proceed under FERC's developer-upfront-payment model. 

The PUC had previously tried to resolve the issue by requiring transmission providers to advance funding for these transmission lines, a position contrary to FERC policy.  That approach was rejected by the California courts as intruding into an area of exclusive FERC jurisdiction.  Then, last year, Southern California Edison raised this issue at FERC.  In response FERC offered as a partial solution guaranteeing recovery of investments in transmission network upgrades, but not in generation tie lines.  [See FERC Denies SoCal Ed Full Approval of Utility's Plan to Add Transmission, Use Wind to Reach RPS Goals]  The California PUC found FERC's partial solution insufficient to meet California RPS goals. 

Against this background, and at the request of the California utilities, the PUC has now adopted a new approach, which seeks to avoid a conflict with FERC.  Rather than requiring the California utilities to advance funds for transmission upgrades, the PUC simply guarantees that Golden State utilities will recover retail charges investments in transmission that are deemed necessary to meet California RPS goals – regardless of whether the transmission is a generator tie line or a network upgrade.  The combination of the RPS standards and guaranteed retail recovery of upfront transmission costs is certain to encourage renewable development and enable the utilities to advance funds for transmission investments.  Since California's three investor-owned utilities and the Cal ISO support this approach, it is likely that the utilities will accept the invitation. 

California PUC Proposals Aim to Put Ambitious Renewables Goals in Reach

California has one of the nation’s most ambitious renewable portfolio standards (RPS).  It requires the state’s utilities to procure 20% of their electric power from renewable resources by 2010.  Gov. Schwarzenegger has suggested raising this level even higher.  However, administrative complexities, transmission shortages (particularly in the wind-rich Tehachapi region), and other issues have slowed utilities' progress toward these goals.  With a series of decisions in late May, the California Public Utilities Commission (CPUC) hopes to accelerate RPS compliance.

The CPUC approved 2006 renewable energy procurement plans for PG&E, San Diego Gas & Electric and Southern California Edison.  In a decision with uncertain impact on independent renewable energy developers, the CPUC also encouraged the three large utilities to build their own renewable capacity. 

The CPUC also initiated a new rulemaking to address the annual RPS procurement cycle, reporting, compliance, and enforcement, as well as standard contract terms.  This rulemaking, however, would not resolve the issue of the use of renewable energy credits (RECs).  The state does not allow RPS compliance through trading and purchases of unbundled RECs (RECs sold separately from the energy produced by a generator).  The agency did, however, approve a proposal allowing delivery of the renewable energy anywhere in the state; previously renewable energy had to be delivered to the applicable utility’s service area to be credited toward RPS compliance.  This change should help facilitate renewable energy transactions.

Southern California Edison and Renewable Suppliers Agree on Fixed Prices

Southern California Edison (SCE), reputed to be the nation’s largest wholesale purchaser of renewable energy, announced it has reached an agreement with four of its largest renewable energy suppliers establishing a fixed price for the utility's renewable energy purchases.  Subject to California Public Utilities Commission approval, the agreement would amend certain existing contracts for SCE’s power purchases from Qualifying Facilities (QF).  It applies to wind, solar, biomass, geothermal, and small hydro purchases through mid-2012, and would pay participating developers 6.15 cents per kilowatt-hour, increasing by 1% per year. 

Not clear at this time is whether SCE will seek to offer these terms to future as well as existing renewable energy suppliers.  Nor did the utility elaborate on its reasons for seeking to amend the contracts.  Since the inception of QF "avoided cost" pricing in 1978, prices under QF agreements have been a point of contention between owners of QFs and utilities.  The fixed price now adopted by SCE appears to mirror the fixed-priced feed-in tariffs that have been used in countries such as Spain and Germany.  By offering all renewable energy developers the same price, and by mandating that utilities buy renewable output at that price, the feed-in tariffs have spurred a great deal wind energy development in those countries.  Until now feed-in tariffs have not been used in the United States, where renewable portfolio standards (RPS) and the federal production tax credit have been the primary stimulus for renewables development.  However, in some states, including California, the administrative process for implementing and complying with RPS has proven cumbersome and unattractive to many developers.  It remains to be seen whether standardizing prices, or other contract terms, might help promote further renewable energy development in the US as it has in Europe.

CAISO Submits Long-Awaited MRTU Tariff

After seemingly endless delays, the California Independent System Operator ("CAISO") on February 9, 2006, finally submitted to FERC its long-promised market redesign and technology upgrade ("MRTU") tariff.  Originally proposed in 2002 in response to FERC findings that the California markets were dysfunctional, the CAISO undertook to redesign its markets and software.  The CAISO itself acknowledges the MRTU tariff remains incomplete; before the MRTU system can come on-line, the CAISO will have more work to do, including developing business practices and determining the appropriate methodologies for designating resources needed to meet day-ahead procurement targets, releasing post-day ahead resource adequacy capacity, and allocating CRRs to merchant transmission projects.  Comments on the tariff are due March 27, 2006, with reply comments due April 17. 

The CAISO's new tariff includes several prominent changes to its market design and market mitigation, including the implementation of a day-ahead market, an hour-ahead scheduling process, and a real-time market that uses locational marginal pricing ("LMP") and security-constrained unit commitment to dispatch resources and manage congestion.

In its filing, the CAISO extols the virtues of LMP, claiming its version of LMP is similar to the system in place in other of the country's organized markets.  The CAISO also claims it does not expect prices to rise as a result of LMP.  For the most part, MRTU will settle charges on an aggregated basis with three load aggregation points ("LAPs"), which correspond to the territories of California's three investor-owned utilities.  However, certain transactions (such as those involving pump loads, exports, metered sub-systems, existing transmission contracts, and transmission ownership rights) will be scheduled and settled on a more "granular" level – i.e., on the basis of nodes that will often be confined to an area smaller than an LAP.  MRTU will also implement congestion revenue rights ("CRRs") to help customers hedge congestion costs.  On the contentious issue of how to allocate such rights, the CAISO proposes to allocate CRRs first to California's load-serving entities ("LSEs"), who, the CAISO reasons, helped pay for the transmission system.  Any remaining CRRs will be auctioned off to all creditworthy parties.  Entities serving load outside of California may obtain CRRs by pre-paying certain wheeling charges. 

MRTU will implement a residual unit commitment ("RUC") process that should help ensure reliability by allowing the CAISO grid operator to secure on a day-ahead basis incremental capacity it forecasts it will need in real-time.  The CAISO hopes for the RUC process to work in concert with the California Public Utilities Commission's ("CPUC's") resource adequacy program.  The CAISO will also undertake to perform local capacity studies to assess the amount of capacity needed in transmission-constrained areas.  It will procure capacity to make up for any shortfalls and allocate the costs to any LSEs that fail to maintain sufficient reserves.

In addition to redesigning its market, the MRTU proposal adds several market power mitigation provisions, based on similar measures in PJM.  The filing includes an initial $500/MWh cap for energy bids, with a plan to raise the cap to $1000/MWh over the next two years in increments of $250/MWh.  The CAISO also proposes to implement a $250/MWh cap for ancillary services and RUC availability bids.  The MRTU proposal would also revise the vexatious must-offer obligation so that only those units whose capacity is needed to meet a utility's resource adequacy requirements would be required to offer their capacity into the CAISO's markets.

The CAISO is aiming for MRTU to become effective in November 2007.  In order for its software vendors to have sufficient time to develop appropriate software, the CAISO thus asked FERC to approve the MRTU tariff by this June, without holding any hearings or requiring any changes.

What the Regulator Giveth, Only the Regulator May Taketh Away

A federal judge ruled January 27 that FERC has exclusive jurisdiction over power supply contracts between Calpine Corp. and several California utilities.  Because they are underwater, these contracts have been tied up in Calpine's bankruptcy.  Although an immediate victory for the California utilities, by reinforcing the primacy of regulatory jurisdiction properly granted by the legislature, the court’s decision should also buttress supplier contracts that California utilities and the state have sought to abrogate in recent years, including large multi-year purchases that California Department of Water Resources (CDWR) made at the end of the 2000-2001 western energy crisis.

Following an order of  a Fifth Circuit US Court  of Appeals decision (Mirant v. Potomac Electric Power Co.), FERC found on January 3 that it did not have jurisdiction under the Federal Power Act to order a party in bankruptcy to continue performing under a power supply contract.  See FERC Purports to Advise Bankruptcy Court on Debtor Contract Rejection.  But Judge Richard Casey, of the U.S. District Court for the Southern District of New York, rejected Mirant and FERC’s reliance on it.  He held that FERC cannot cede its authority to the courts.  According to Judge Casey, the bankruptcy court cannot exercise its authority to interfere with the jurisdiction of a federal agency acting within its properly delegated regulatory capacity, and nothing in the Bankruptcy Code prohibits FERC from exercising its jurisdiction over the contracts.  Thus, Calpine cannot achieve in bankruptcy court what it could not otherwise achieve without FERC approval:  "ceas[ing] performance under the rates, terms, and conditions of filed rate wholesale energy contracts in the hopes of getting a better deal."  Judge Casey added, "what FERC giveth, only FERC may taketh away."  The court also vacated a temporary restraining order that prohibited FERC from ordering Calpine to continue performance of the contracts.

The decision is a victory — at least for now — for the California utilities who sought to have the Calpine contracts affirmed and had looked to FERC to decide the issue.   But what goes ar