Energy Legal Blog

Entergy to Forego Reactive Power Earnings and Payments

In early September, Entergy asked FERC to confirm that if Entergy stops paying itself for reactive power, then the New Orleans-based utility can refuse to pay non-affiliated generators for reactive power.  A generator is obligated to maintain reactive power within a specified bandwidth as a condition of its interconnecting with the transmission provider's system, and is not owed any compensation so long as Entergy does not pay itself or its affiliates for providing the same service.  Unanswered is why Entergy until now has paid itself and its affiliates for reactive power.

Apparently expecting a favorable answer from FERC, together with its petition, Entergy filed papers to eliminate prospectively all compensation to Entergy and its affiliates for reactive power.  [FERC Docket No. EL05-149] [NEW MATTER]

FERC Asks Commenters, Congress for Help in Closing the Jurisdictional Gap over Natural Gas Gathering

FERC recently issued a notice of inquiry asking for ideas on how to close the existing regulatory loophole that allows offshore natural gas gatherers to escape regulation.  Under current law, these gatherers fall outside of FERC's jurisdiction once they are spun off from interstate pipelines, as many were during 1990s.  Nor are these spun-off gatherers subject to state regulation.  Over the past few years, FERC has invoked various legal theories and statutes, including provisions of the Natural Gas Act and the Outer Continental Shelf Lands Act, to impose regulated rates on gatherers.  But the courts uniformly have balked.  The current notice asks for industry feedback on a 1994 order, Arkla Gathering Service Co., which set forth criteria for asserting jurisdiction over pipelines' unregulated gathering affiliates, and poses 13 detailed questions relating to the assertion of jurisdiction over these facilities.  Comments on the notice of inquiry are due 60 days after publication of the notice in the Federal Register.

FERC's primary concern in issuing the notice was the monopoly rents that offshore gatherers facilities are able to charge their customers without fear of regulatory intervention.  FERC Chair Joe Kelliher observed that some shippers have been charged "multiples, multiples" more for service on unregulated gathering systems than on the regulated pipelines they feed into, and concluded, "[i]f the law permits monopoly rents, [then] its time to change the law."  FERC was also concerned that the current laissez-faire approach enables gatherers to shut in offshore gas production at critical times, such as the recent emergency following Hurricane Katrina. [Criteria for Reassertion of Jurisdiction Over the Gathering Services of Natural Gas Company Affiliates, 112 FERC ¶ 61,292 (2005)] [NEW MATTER]

Concurrently with the issuance of the notice, Chair Kelliher and Commissioner Suedeen Kelly publicly asked Congress for new legislation granting FERC's regulatory authority over natural gas gatherers.  Some speculate that Congress may be primed to take up new energy legislation later this fall to address oil and natural gas production and conservation issues, at least partly in response to the price-gouging allegations that have arisen in the wake of Hurricanes Katrina and Rita.

Attitude Shift, EPACT Mandate, Prompt FERC to Act on Transmission Policy

Last week FERC Chair Joe Kelliher announced that his agency will soon explore ways to induce transmission investment.  The Domenici-Barton Energy Policy Act of 2005 ("EPAct 2005") directs FERC to issue a rule establishing transmission incentive rates within one year of EPAct 2005's August 8 enactment.  The investment initiative will proceed "in tandem" with FERC's just-announced proposal to update its Order No. 888 open-access transmission tariff.  [See FERC to Reprise Open Access Nearly Ten Years after Its Launch].  It would be the latest iteration of an evolving approach to FERC's transmission policy that began with its incentive pricing policy first introduced in January 2003.

An earlier initiative undertaken in January 2003 would have tied increased earnings on transmission investments to the transmission owner's participation in an independent RTO, but that proposal never made it beyond an extended comment period.  Other than a narrow policy statement issued last June addressing the passive ownership of Independent Transmission Companies ("ITCs") [See FERC Takes a Second Look at the Independent Ownership and Operation of Power Transmission Systems], the issue of investment incentives has languished.   But with the EPAct 2005 directive and a change in leadership, FERC now appears poised to tackle the issue.

According to Kelliher, the 2003 transmission policy placed too much emphasis on participation in RTOs rather than on providing transmission investment incentives.  Noting that more transmission investment has occurred in areas that did not engage in regional planning, Kelliher made the surprising observation that RTOs can be "barriers" to open-access transmission.  While FERC has authorized the incentives suggested in the 2003 transmission policy in individual cases, Kelliher foresees broader use of transmission incentives under EPAct 2005.  He predicted that the agency's policies going forward would be more flexible and could confer higher earnings on the transmission investments of affiliated transcos as well as ITCs.  But he ruled out the use of performance-based rates because, in areas with disaggregated transmission ownership, it would be too difficult to ascertain which owner was responsible for improved performance.  [NEW MATTER]

FERC Rejects SPP's Imbalance Market Proposal; Start Delayed Again

In a September 19 order FERC rejected as "inadequate" Southwest Power Pool's ("SPP") proposal to implement a real-time energy imbalance market, along with its market monitoring and market power mitigation plans.  FERC was primarily concerned that the imbalance market was not designed or would not be monitored properly to ensure stable market operation and laid out guidance for SPP in several critical areas.  FERC also rejected SPP's attempts to justify various tariff revisions as the result of its stakeholder process, saying that "SPP is ultimately responsible for the stable operation of its market and must provide justification for its proposal to show that the market will operate reasonably and provide just and reasonable rates." 

In particular, FERC found SPP's proposal lacking because it proposed a voluntary sellers' market and a mandatory buyers' market, "but no way to bridge the gap if the offers are insufficient, short of implementing emergency procedures."  SPP's proposal was also lacking because it failed to detail its market monitoring plan, market mitigation measures, and sanctions for violating market rules.  SPP also failed to clarify the different responsibilities of SPP's market monitoring unit and its independent market monitor ("IMM").  FERC directed SPP to specify in its market monitoring plan what corrective steps the IMM would take if it were to determine that the SPP markets are not producing just and reasonable prices or are failing to induce sufficient investment in infrastructure.  FERC also instructed SPP to amend its tariff language to clarify that FERC, and not the market monitor, has enforcement power.

Authorized as a regional transmission organization ("RTO") since October 1, 2004, SPP filed tariff amendments to implement the imbalance market and market monitoring and mitigation plans in response to FERC's order addressing its RTO application.  SPP had hoped to begin trials of the imbalance market in June 2005, with the market going live by October 2005.  Reliability concerns caused SPP to postpone implementation until March 2006.  In light of the current order, the imbalance market has no start date.  [Southwest Power Pool, Inc. 112 FERC ¶ 61,303 (2005)]  [NEW MATTER]

California PUC ALJ Orders Utilities to Supplement RPS Plans

A California Public Utilities Commission judge issued a draft decision conditionally approving the respective plans of the state’s three investor-owned utilities to implement the California Renewable Portfolio Standard (RPS) program, but required them to supplement their plans with further information on issues such as transmission planning and contingency planning. 

California has the nation’s most ambitious RPS program.  It requires the utilities to achieve a 20% RPS goal by 2010.  Moreover, the judge cited the PUC’s plan of working toward Governor Schwarzenegger’s declared goal of procuring 33% of the state’s electricity from renewable resources by 2020.  This focus on renewable energy presents a stiff test for Pacific Gas and Electric Company (PG&E), Southern California Edison Company (SCE), and San Diego Gas & Electric (SDG&E), and their long-term procurement plans were found lacking in many respects by the judge.   

Connecting areas where resources such as wind can be harnessed with load centers into which power must be delivered is often costly and a major challenge for renewable energy development.  Not surprisingly, because of that challenge each of the California utilities discussed the need for transmission in their plans, but the judge found their plans for new transmission insufficient and ordered that they be supplemented.   The utilities are required to supplement their long-term plans by early October. 

Books, Records and Prices: Implementing the New Holding Company Act

The Domenici-Barton Energy Policy Act of 2005 repeals the venerable Public Utility Holding Company Act of 1935 (’35 Act) and, effective February 8, 2006, replaces it with a 2005 Act bearing the same name (PUHCA 2005).  The earlier act’s structural limitations that confined holding companies to "a single integrated public-utility system, and to such other businesses as are reasonably incidental, or economically necessary or appropriate to the operations of such integrated public-utility system" are supplanted in PUHCA 2005 with what FERC in a recent rulemaking proposal calls “primarily a books and records access” statute.  Not surprisingly, in its notice of proposed rulemaking (NOPR) on how it should implement PUHCA 2005, FERC sets out how it proposes to exercise its new authority to ensure public — and particularly state regulatory — access to the books and records of future public utility holding companies.  To be considered, comments on the NOPR must be received by FERC 21 days after the NOPR is noticed in the Federal Register, which will likely occur in late October. 

While much of the NOPR addresses itself to record keeping obligations and exemptions from those obligations, it also raises more economically significant issues dealing with FERC’s new authority under PUHCA 2005 to review and authorize the pricing of and allocation of costs and revenues from non-power goods and administrative or management services that an associate company within a holding company provides to regulated public utilities within the same holding company.  In many respects, FERC proposes simply to adopt and continue the accounting rules and practices that the Securities and Exchange Commission (SEC) had developed under the ’35 Act for these intra-holding company transactions.  But in one critically important respect, FERC’s and the SEC’s approaches conflict and are not resolved in the NOPR.  That respect turns on how non-power goods and administrative or management services are priced and reflected in the public utility purchaser’s regulated rates.  The SEC’s historical practice was to set the price at cost — that is, equal to the cost that the associate company incurred in providing the non-power good or service.  But FERC, for its part, has applied a more consumer-oriented rule that sets price equal to the lower of cost or market.  For many players in the power and related services industries, perhaps the most important issue on which FERC invites public comment in the NOPR is “whether the Commission should apply [its own] lower of cost or market standard for the allocation of costs for non-power goods and services, or if [it] should instead adopt the SEC ‘at cost’ standard.”  [Repeal of the Public Utility Holding Company at of 1935 and Enactment of the Public Utility Holding Company Act of 2005, 113 FERC ¶ 61,248 (2005) NEW MATTER]

Alliant Becomes First to Try for EPAct Waiver QF Purchase Requirement

In mid-August Alliant Energy asked FERC to exempt two of Alliant's utilities, Interstate Power and Light Co. (IPL) and Wisconsin Power and Light Co. (WPL) from the QF purchase requirements contained in the Public Utility Regulatory Policy Act (PURPA).  The filing came just days after the passage of the Energy Policy Act of 2005 (EPAct 2005), and took advantage of a provision in the EPAct 2005 amending PURPA and providing for waiver of QF purchase requirements if FERC finds the service territory of the utility seeking exemption to be competitive.  The waiver is based on the reasoning that when QFs have access to other potential buyers, local utilities need not be forced to purchase the QFs' output.   

Alliant contends that the operations of the Midwest Independent Transmission Operator (MISO) allow QFs in IPL and WPL's service territories to access alternative buyers.  On the other side of the debate, protestors, including the American Wind Energy Association (AWEA) and the Electricity Consumers Resource Council (ELCON), counter that the mere operation of an RTO such as MISO is insufficient proof of a competitive market for purposes of EPAct 2005.  In particular, protestors claim that Alliant failed to demonstrate that the QFs have access to long-term energy and capacity markets and pointed to MISO's still-developing resource adequacy program and formal capacity market.   

More generally, Alliant's opponents ask that FERC clarify that the determination of whether to exempt utilities from QF purchase requirements is a service territory-specific inquiry, some going so far as to ask FERC to issue a notice of inquiry into how to implement the new PURPA language.  How FERC rules on the requested exemption and interprets the new exemption provision of EPAct 2005 will be watched closely by industry participants on both sides. [FERC Docket No. EL05-143] [NEW MATTER]

FERC Approval of Sea Breeze Merchant Cable Project May Open Door to More Transmission

In a move intended to induce development of new or upgraded transmission, FERC has approved the proposal of Sea Breeze Pacific Juan de Fuca Cable LP to run a merchant transmission line between Washington State and Vancouver, British Columbia.  As the first merchant line approved that will not be part of an existing RTO or ISO, the approval signals that FERC has become more receptive to such projects.

Sea Breeze is comprised of two phases.   The first, set for completion in winter 2007, connects a British Columbia Transmission Corp. substation in Victoria, B.C. with a Bonneville Power Authority substation in Port Angeles, WA.  A second and longer line, planned to go online in 2008, would connect Vancouver and Fairmount, WA.  Both lines will have the capacity to transmit 540 MW.

In addition to allowing the project to go forward outside of an organized market (even if one eventually forms in the region), FERC also showed flexibility with regard to the ten criteria it uses to evaluate merchant proposals.  FERC will not require the project to employ a market monitor, having determined both that requiring a monitor for a single project would not "advance the public interest" and that the need for a monitor was negated by "the fact that [the project's] single goal would be to leverage the assets in the most efficient way" possible. 

While FERC authorization for Sea Breeze to operate as a merchant clears a major milestone for the Sea Breeze sponsors ― Sea Breeze Power Corp. and Boundless Energy LLC― FERC approval is not the end of the road.  The results of a currently-underway open season that will auction capacity on the proposed lines, a step that has defeated other merchant projects, will determine whether the project will turn a profit.  But the Sea Breeze project sponsors have momentum working for them.  Sea Breeze Power has a wind project in the works for British Columbia that will need new transmission capacity to get its wind generation to market, and has received financing from a group that was involved in the successful financing of the Path 15 upgrade in California.  In addition, sponsor Boundless Energy proved successful in securing a purchaser for the capacity on its Neptune merchant line between New Jersey and Long Island.  The next few months will tell if the combination of this management team, together with a more-receptive FERC, will bring Sea Breeze to fruition as the first merchant transmission project outside of an RTO or ISO.  [Sea Breeze Pacific Juan de Fuca Cable, LP, 112 FERC ¶ 61,295 (2005)]  [NEW MATTER]

FERC to Reprise Open Access Nearly Ten Years after Its Launch

Finding that today’s electric industry has changed considerably since it “functionally unbundled” transmission services nearly a decade ago in Order No. 888, FERC questions in a recent Notice of Inquiry (NOI) whether that bold step has sufficiently overcome the “economic self-interest of transmission monopolists, particularly those with high-cost generation assets, to deny transmission or offer transmission on a basis that is inferior to that which they provide to themselves.”   By opening this inquiry, FERC acknowledges that the efficacy of “functional unbundling” (as opposed to structural reforms such as divestiture or the surrendering of operational transmission control to an independent transmission operator) is a contentious topic.  To minimize the potential for acrimony, the agency asks those who participate in the NOI to avoid the “more polarizing elements of this debate” and instead focus on reforms targeted to specific problems that persist under Order No. 888.  Comments will be due 60 days after publication of the notice in the federal register, likely sometime in late November 2005.

 Many of the reforms contemplated in the questions of the NOI were proposed earlier as part of the transmission component of FERC’s comprehensive, yet controversial and now abandoned, standard market design or SMD.  Noteworthy areas of inquiry in the NOI are:

·        A transmission provider operating under the Order No. 888 open-access tariff is not required to offer transmission at the same price and on the same terms and conditions that it provides transmission to itself, but it is allowed to “bundle” transmission with its retail delivery service to native load customers, making the transmission component of that service wholly opaque.  In the NOI FERC does not propose to change this treatment, but notes that in section 1233 of the new Domenici-Barton Energy Policy Act of 2005 (EPA 2005) Congress defined native load service obligation and directed that providers of this service are entitled to transmission sufficient to fulfill their obligation.  FERC asks whether this entitlement is consistent with the existing practice of bundled transmission.  Arguably, in order to ensure that it properly implements the new entitlement, FERC may feel compelled to unbundled transmission service from retail delivery service so that it can oversee the right of first refusal implicitly called for in section 1233. 

·        Also with reference to EPA 2005, FERC notes that section 1231 of the new law authorizes it to require non-public (governmental or cooperatively owned) utilities to provide open-access transmission whereas, under Order No. 888, such utilities were required only to provide open access on a reciprocal basis to public utilities that provided open access transmission to them.  In the NOI FERC asks whether it should exercise this new authority and, if so, whether on a case-by-case basis or across-the-board in a rulemaking.

·        With regard to the types of transmission service offerings, FERC in the NOI asks (as it proposed in SMD) whether the current offerings of network service and point-to-point should be conflated into a single transmission offering that (unlike network) can readily trade in secondary (reassignment) markets.  Should transmission providers be required to offer firm service for periods as short as one hour; if so, should customers be allowed to batch hourly rights into longer-term firm service?

·        FERC also asks whether transmission pricing should be reconsidered.  Are there more efficient alternative to locational marginal pricing?  Should the price cap on transmission reassigned in secondary markets be lifted?

·        And perhaps of most immediate consequence for transmission sellers and customers, FERC asks what use it should make of the authority that EPA 2005 grants it to impose new and more-severe civil penalties for violations of the Federal Power Act.  Should the agency adopt uniform sanctions applicable to specific violations of open-access transmission tariffs by either transmission providers or transmission customers?  FERC also asks whether certain infractions, such as “setting aside more transmission capacity than is needed to serve native load and using the capacity for third-party sales,” should be considered the type of market manipulation that new section 1283 of EPA 2005 prohibits and subjects to the new civil penalties.

Consistent with the agency’s policy priority of encouraging utilities to join in and surrender operational control of their transmission to independent regional operators, FERC pointedly asks whether some of the reforms discussed in the NOI need only be applied to transmission systems that are independently operated.  [Preventing Undue Discrimination and Preference in Transmission Services, 112 FERC ¶ 61,299 (2005)]  [NEW MATTER]

Constellation, Progress Energy Join Growing Number of Utilities Considering New Nuclear Projects

In the wake of the Energy Policy Act of 2005, a growing number of new nuclear projects are in the works, as both Constellation Energy and Progress Energy recently announced plans to join the ranks of those utilities already considering expansion of their nuclear generation capabilities. 

On September 15, 2005, Constellation and French-based AREVA, Inc. announced the creation of UniStar Nuclear, a joint enterprise that will provide the business framework to oversee the development, construction, and operation of a "standardized fleet" of new nuclear power plants.  Bechtel Power Corporation will also provide architectural, engineering, and contracting support for the undertaking.  UniStar plans to market an advanced power reactor, called the U.S. Evolutionary Power Reactor ("EPR"), which is a 1600 MW evolutionary power reactor designed by AREVA specifically for the U.S.  The U.S. version of EPR is based on AREVA's advanced nuclear power plant, which is already being used across Europe.  AREVA is currently completing EPR's design certification in the U.S., and the new technology should be licensed and ready to deploy by 2015.  Constellation hopes to use UniStar to cultivate joint ventures to develop the new nuclear generators.  Constellation's president, Michael Wallace, referred to the unique business framework as "a one-stop shop approach to design, build, license, and operate a fleet of nuclear power plants."

Progress Energy has also recently announced that it is studying the possibility of increasing its stable of nuclear generating plants by adding a sixth nuclear power plant in the near future.  The North Carolina-based utility notified the Nuclear Regulatory Commission ("NRC") that it expects to select a potential site and vendor by the end of 2005.  While Progress has not made the final decision to go ahead with a new nuclear project, if the process goes as planned, it could apply to the NRC for a construction and operating license by 2008, begin construction as soon as 2010, and start commercial operations by approximately 2015.  Progress currently operates five nuclear plants in the Carolinas and Florida. 

Constellation and Progress are not alone among utilities eyeing an expanded nuclear fleet.  Duke Power, Southern Nuclear Operating (a subsidiary of Southern Company), South Carolina Electric & Gas, and Santee Cooper have all also recently announced plans to consider developing new nuclear generation. 

Market Pricing: When and Where to Allow It?

Connecticut's Attorney General has filed a complaint asking FERC to amend the market rules in ISO-New England to replace generators' reliability-must-run ("RMR") agreements and market-based rate authority with cost-based rates, a move the complaint claims will save ratepayers in the state $1 billion over the next year.  The complaint attacks what it alleges to be a "benefit-of-the-bargain" arrangement that allows generators to reap excess profits either through RMR arrangements or market-rates.  Competitive conditions do not exist in the state, according to the Connecticut AG, and will not develop until additional transmission is constructed.  This contention is rich in irony since it was the Connecticut AG and other Connecticut pols who recently prevailed in forcing FERC to delay adoption of a new arrangement for pricing capacity that the ISO-NE argued would relieve power shortages in New England by stimulating development of generation. 

Another dispute over the competitiveness of power markets has broken out in Illinois, where Commonwealth Edison and Ameren sought to buy power supplies through a reverse auction process.  The Illinois Attorney General objected and is seeking to prevent the Illinois Commerce Commission ("ICC") from allowing this power procurement method.  The AG argues that the ICC does not have authority to allow use of a reverse auction, because it would amount to passing through to ratepayers market prices, which may not be done until the market is deemed "competitive."

The appropriateness of market-pricing is playing out from another angle elsewhere.  FERC's current test for market-pricing authority has indicated that several vertically integrated utilities have market power in their control areas, which, if not mitigated, should cause them to forfeit market-pricing authority.  A number of these utilities have responded by relinquishing their market-pricing authority and reverting to cost-based regulated rates.  But that too has prompted protests.  In response to Duke Power's plan to return to cost-based rates for sales in its control area, one power marketer complained that the cost-of-service pricing that Duke proposed in fact gave Duke Power considerable discretion in what rate to charge and failed to mitigate Duke's dominant position in the market.  In addition, several muni customers of Duke are contending that they stand to be harmed if Duke decides to sell more of its power elsewhere since it is confined to cost-based rates only in its own control area.

FERC Initiates Process for Formation of Overdue Mandatory Reliability Standards

The Energy Policy Act of 2005 directs FERC to finalize by February 5, 2006, a design for a new electricity reliability organization ("ERO") over which it will have jurisdiction, and develop mandatory reliability standards and a process for enforcement of these standards.  On September 1 FERC proposed criteria in a rulemaking for establishing the ERO.  Public comments on the criteria are due Friday, October 7. 

Currently, the North American Electric Reliability Council ("NERC") administers voluntary operational standards for the bulk-power system in North America.   It is widely expected that FERC will choose NERC to become the ERO.

In its rulemaking, FERC proposes a process through which the ERO can develop and propose reliability standards, subject to FERC's review and approval.  FERC also proposes funding the ERO through "end-users" fees, and procedures for ERO's and FERC' joint enforcement of the new mandatory reliability rules.  As proposed in the rulemaking, all owners, operators and users of the bulk power system ― including public and governmental entities ordinarily exempt from FERC regulation ― will be obligated to comply with the approved reliability standards, regardless of whether the entity is a member of the ERO.  As proposed, penalties could include not only monetary forfeitures, but also limitations on activities, functions, or operations.  FERC asks for comment on the appeals process, as well as how the collected monetary penalties should be applied.

The rulemaking also proposes a process enabling the ERO to delegate enforcement authority to a regional subordinate and procedures for the establishment of independent Regional Advisory Bodies that can provide advice to FERC on regional reliability matters.    [Rules Concerning Certification of the Electric Reliability Organization; and Procedures for the Establishment, Approval, and enforcement of electric Reliability Standards, 112 FERC ¶ 61,239, (2005)] [NEW MATTER]

CPUC and CEC Wrangle over Electricity Transmission Corridors

A recent meeting between the California Public Utility Commission (CPUC) and the California Energy Commission (CEC) exposed mounting tension over which should have the authority to site new transmission facilities.  This is the most recent flare up in the turf battles that have undermined the Golden State's efforts to craft a plan for adding badly needed transmission facilities. 

The disagreement stemmed from the CEC's draft Integrated Energy Policy Report (IEPR), part of a proceeding initiated pursuant to the California legislature's 2004 request that CEC develop a strategic transmission investment plan.  In addition to asking the state legislature to grant it the authority to designate electricity transmission corridors, the CEC's draft plan also suggested that it be granted transmission permitting authority.  As the CEC and CPUC met Monday to update California's Energy Action Plan (EAP), the CEC suggested including in the updated EPA its recommendation to shift transmission siting authority to itself, a change also advocated by Governor Schwarzenegger in his effort to create a state Department of Energy.  Rebuffing this encroachment onto its authority (California's public utilities code currently places the siting authority sought by the CEC with the CPUC), the CPUC countered that other means are available to improve the state's transmission siting and planning approval process, and that it has opened a proceeding to study the matter. 

As these two branches of state government jockey for jurisdictions, another transmission plan hovers in the background:  the CAISO's transmission planning process announced earlier this year.  With so many leaders pushing in different directions, the California grid risks taking on the look of a Rube Goldberg design.

Court Limits FERC's Jurisdiction as Bonneville, Munis Escape Refund Liability in California Energy Crisis Case

On September 6, 2005, the U.S. Court of Appeals for the Ninth Circuit issued an order excusing the Bonneville Power Administration ("Bonneville") and other governmental entities and "non-public utilities" from any potential refund liability in the California refund proceedings.  The court found that FERC did not have authority under the Federal Power Act ("FPA") to order these entities to pay refunds.  The main question for the court was whether FERC's refund authority is based upon the identities of the sellers (i.e., public versus non-public utilities) or the nature of the transactions (i.e., FERC's broad regulatory authority over the sale of electric energy for resale in interstate commerce).  The court decided that the sellers' identities was the paramount consideration, and since these sellers were not "public utilities" as defined by the FPA, FERC's refund authority did not extend to their wholesale electric energy sales.  Dismissed from the proceeding, and thus escaping any future refund liability, were Bonneville, along with various California cities, counties, irrigation districts, and state entities. 

The case involved the petition for review by several governmental entities and other sellers that did not fit into the FPA's definition of "public utility" (i.e., the "non-public utilities") of various FERC orders that purported to impose refund liability on all entities selling power into California markets during the 2000-2001 energy crisis.  In these orders, FERC reasoned that its broad authority over the wholesale sales of electricity in interstate commerce gave it the authority to require all sellers to pay refunds, while at the same time admitting that it did not have direct authority over governmental entities and non-public utilities.  The Ninth Circuit disagreed and found that since governmental and municipal utilities are not "public utilities" under the FPA, FERC's refund authority did not reach them.  The court cited the FPA's express exemption for U.S. federal, state, and municipal governmental entities and the statute's general definition of public utilities.  If FERC had jurisdiction over governmental entities merely by reason of its authority over wholesale energy sales, the court reasoned, these provisions would have been superfluous.  The court refused to read these provisions out of the statute and held that FERC had acted improperly in ordering these entities to pay refunds.  The court also cited previous FERC precedent, which held that Congress had explicitly exempted governmental entities from FERC's authority to set just and reasonable rates.  Although the court noted that the energy crisis was an extraordinary circumstance, it did not permit FERC to ignore its own precedent.

While the decision's immediate impact will be to excuse Bonneville and other municipal utilities from refunds relating to California sales, the decision's overall impact will likely extend past California.  Complainants in the Pacific Northwest proceedings (Port of Seattle v. FERC, Docket No. 03-74193) have argued that FERC's authority to order refunds does extend to governmental entities like Bonneville.  The Ninth Circuit's decision here, however, appears to have settled the question that FERC does not have jurisdiction over these entities, apparently precluding any arguments to the contrary in the Pacific Northwest appeal.  [Bonnevill Power Administration v. Federal Energy Regulatory Commission, Ninth Cir. 02-70262 (September 6, 2005) FERC Docket No. EL00-95, et al.] [UPDATE]

ENERGY POLICY ACT OF of 2005: INVESTMENT OPPORTUNITIES & COMPLIANCE CHALLENGES

The attorneys and consultants of Bracewell & Giuliani’s Energy and Government Relations practices were involved in the drafting and passage of important provisions of the Domenici-Barton Energy Policy Act of 2005.  These include new laws that will open new investment opportunities in natural gas and power resource development and transportation/transmission.  They also impose new performance and regulatory compliance obligations and possible penalties, both civil and criminal, on those who participate as sellers or buyers in natural gas, power and transportation/transmission markets, at wholesale and retail.  The B&G attorneys and consultants intimately familiar with these provisions of the new law have prepared analyses of the investment opportunities and compliance challenges presented by the 2005 Act.  For further information on these opportunities and challenges, contact Gene Godley or Chuck Shoneman in the Washington, DC office, (202) 828-5800, Timothy Toy in the New York City office, (212) 508-6100, and Phil Ricketts or Paul Fox in the Austin, Texas office, (512) 472-7800.

PJM Ventures Thoughtfully into Vexatious World of Capacity Markets

The role of an electricity capacity market has been described as inducing the right amount of investment of the right type in the right locations.  (Cramton/Stoft 2005).  Following the contentious introduction (or proposed introduction) of capacity markets in New York and New England, the PJM Interconnection unveiled in a September 1 submission to FERC its reliability pricing model (RPM) for getting a capacity market “just right” in the Mid-Atlantic.  PJM’s filing with FERC came not quite a month after Congress instructed FERC to proceed cautiously with ISO New England’s comparable proposal for a locational installed capacity (LICAP) market.  For its part, PJM asked FERC to approve RPM no later than January 31 so that the Interconnection will be able to prepare for the first of what will become annual capacity auctions on June 1, 2006.  FERC is expected to convene soon a series of technical conferences on the RPM proposal.

The need for capacity markets for electricity are generally attributed to regulation that prevents consumers from seeing and responding to high prices during periods of scarcity — the absence of price-elastic demand — and the long-lead times typically required to increase supply either through new generating capacity or upgraded transmission.  As a result demand is not accurately or timely valued.  Like other operators of bulk power systems that must balance supply and load, PJM historically addressed this failing of existing electricity markets by hosting a capacity market as far as 12 months into the future and requiring all member load servers to maintain capacity equal to peak load plus a “reserve margin,” such as 15 percent.  Failure to maintain the reserve margin triggers a deficiency charge based on the cost of a new combustion turbine.  While this approach was copasetic in the traditional world of vertically integrated electric utilities, it deters sufficient investment in generation capacity in markets (such as much of PJM) in which generation is competitive and decoupled from transmission and load-serving distribution activities. 

This is because the fixed reserve margin and deficiency charge price capacity below the margin at zero and price capacity above the margin up to the deficiency charge — in other words, produce a demand curve that is vertical rather than the downward sloping curve that describes demand for most commodities.  The resulting prices will not recover the cost of a generator during extended periods until a shortage develops, causing prices to skyrocket, inducing over-investment in new capacity, and causing boom-bust cycles that have characterized large segments of the power industry in recent years.  While customers may like this result so long as they benefit from low prices during periods of sufficient capacity and are shielded by regulation from very high, scarcity prices, developers in competitive supply markets will not volunteer to invest in such markets. 

The reserve margin with deficiency charge approach was jettisoned first in New York, when NYISO replaced it with capacity prices set on a downward sloping demand curve that varies depending on the locational value of energy.  FERC authorized implementation of this pricing and a US appeals court upheld FERC against complaints from some consumer groups that the new pricing mechanism was a form of incentive pricing that required greater justification than FERC provided.  ISO-NE followed suit, but ran head long into withering opposition to its LICAP proposal, particularly from politicians and consumers in areas of New England that are notoriously short of capacity, such as Connecticut.  That opposition culminated with the US Congress including in the Domenici-Barton Energy Policy Act of 2005 in a “sense of Congress” admonishing FERC to evaluate carefully the objections to LICAP.  That admonition and FERC’s response derailed LICAP and capacity market reforms generally for at least one year in New England.

PJM’s contribution, RPM, is a more comprehensive and arguably more thoughtful approach to capacity market reform than that of either NYISO or ISO-NE.  Under RPM, PJM will conduct annual auctions for delivery of capacity to specified locations in each of the four seasons four years later (the Delivery Year).  The auction will not be confined to offers of generation.  Transmission owners/operators can also offer capacity, and consumers can offer capacity from reduced demand.  Each load server will be required to secure capacity sufficient for its peak load plus reserve margin in the Delivery Year through self-supplied capacity, bilaterally purchased capacity, or capacity committed in the auction for that year.  In lieu of the current deficiency charge, RPM contemplates a downward sloping demand curve called a variable resource requirement (VRR) curve.  While PJM presents several options for the VRR curve (in comparison to the implicit vertical curve of the existing deficiency charge), the slope of each curve is set in relation to the annual fixed cost of a combustion turbine.  Payments to sellers whose capacity clears in the auctions would equal the annual cost fixed cost of a combustion turbine, less revenues to such a turbine from forecasted energy and ancillary services sales.

To placate American Electric Power (a relatively new member of PJM), PJM included in  “draft business rules” accompanying its FERC filing AEP’s proposal that would allow a load-serving member to opt out of RPM under certain circumstances.  In order to do so the load server would have to demonstrate that it possessed sufficient capacity to meet it peak load plus reserve margin four years in advance.  PJM does not indicate support or opposition to this opt out, presenting it to FERC as a jump ball.

PJM makes a strong case that its RPM is an improvement over the status quo.  By looking four-years into the future, RPM stands to provide a predictable and stable cash flow to generators and investors.  Locational pricing will help ensure actual deliverability of capacity into constrained areas, which has often been lacking in the past.  At the same time, revenues from the VRR curve, together with seasonal differentiation that permits imports of capacity that could not otherwise commit on an annual or semi-annual basis, should ensure capacity adequacy at minimum long-term prices.  Notwithstanding these attributes of RPM, representatives of large industrial users and representatives of rate payers in capacity-short locations understand the price tag for adequate capacity and have vowed to fight it. 

Northeast LNG Projects Navigate between Scylla and Charybdis

Both the Weaver's Cove Fall River, Massachusetts project and the now-three LNG projects proposed for Maine's Passamaquoddy Bay continue to battle local and regional opposition.

Recently, the Aquidneck Island Planning Commission took delivery of two commissioned reports that predicted that the Weaver's Cove LNG project would cause major traffic backups and hurt Rhode Island's marine and tourism economies.  Weaver's Cove has stated that the reports were based on flawed assumptions.  Weaver's Cove earlier this month also saw Mass. Governor Mitch Romney notify FERC of changed conditions surrounding the development of the terminal as a result of the inclusion of a provision in the recently passed federal transportation bill that mandates preservation of the Brighton Street Bridge.  It was intended that the bridge would be replaced with a drawbridge to accommodate LNG tankers that would be blocked by the existing Brighton Street Bridge.  Additionally, the U.S. Navy has asked FERC to reconsider its approval of Weaver's Cove, claiming that tankers passing through the Narragansett Bay area would interrupt testing of underwater weaponry.  Weaver's Cove immediately responded, asking FERC to deny the Navy's filing outright, because it was out of time.  The recently passed Domenici-Barton Energy Policy Act requires FERC to consult with the Pentagon on the siting of LNG facilities; whether that new law will come into play is not currently known. (Docket No. CP04-36, et al.)

In Maine, a third proposal for an LNG facility along the Maine side of the Passamaquoddy Bay has been advanced, causing several Canadian opponents to call for Ottawa's Prime Minister Martin to take action.  The opponents seek a declaration from the Prime Minister that LNG supertankers will not be allowed to cross Canadian waters to enter the Bay.  To date, none of the three proposed facilities has received the necessary regulatory approvals to proceed with the development of their respective projects.

South Carolina Regulator Considering Competitive Procurement of Power

The South Carolina Public Service Commission ("SCPSC") is considering whether utility procurement rules should be changed in the state to require a competitive RFP-based solicitation process.  This inquiry grows out of a recent SCPSC decision granting local electric and gas distributor SCE&G a rate increase. 

The SCPSC appears reluctant to embrace competitive procurement.  This is evident from the order granting SCE&G a rate increase.  Even thought the Commission undertook the RFP inquiry, it also faulted the RFP concept, affirming its earlier rejection of challenges to a utility's self-construction of generation as well as it earlier conclusion that use of an RFP would not have produced a lower cost option with the same reliability characteristics as the plant constructed by the utility.

Nevertheless, the SCPSC decided to consider an RFP process for the future, stating that such an RFP process "under appropriate circumstances, could" produce lower rates.  The SCPSC said that it is "considering" competitive bidding, that any competitive bidding process might vary between utilities, and that the price of new generation capacity need not be the sole selection criterion in the RFP process.  A hearing to consider these issues will convene on October 26, 2005, in Columbia.

The SCPSC's initiative suggests movement, however imperceptible, toward competitive procurement, or at least greater transparency in utility procurement procedures.  In the neighboring state of Georgia, the Georgia PSC last year took a step towards increased competition in generation procurement by instituting a rulemaking to require appointment of an independent evaluator to oversee utility purchases of generation in the state and ensure the proposals of independent power companies receive due consideration. 

Incentives to Sell Are Needed More than Improved Metrics, Says FTC

Reprising a message it has voiced for nearly decade, a frustrated Federal Trade Commission (FTC) lectured FERC that standardizing the measurement of available transmission capacity (ATC), as FERC proposes, is fine, but unlikely to eradicate the real problem of transmitting utilities denying available transmission capacity for use by power sellers with whom they compete.  “Behavioral rules, such as rules governing calculation of ATC,” instructed the competition watchdog FTC, will not effectively address transmission discrimination unless accompanied by solutions that deprive transmitting utilities of both the ability and incentive to keep competitors off the transmission grids that the transmitting utilities own and operate.  In other words, transmitting utilities need a greater incentive to sell than to hoard.

The FTC delivered this message in August 22 comments on FERC’s public notice of inquiry seeking advise on how to improve the calculation of the portion of total transmission capacity (TTC) that is available to serve wholesale customers after satisfying the transmitting utilities other obligations, which comprise principally service to retail customers.  A recent task force of the North American Electric Reliability Council (NERC) had found that they industry currently use 50 to 60 different and largely inaccurate measures of both TTC and ATC.  Surely, the FTC opined, greater transparency, consistency and accuracy in determining how much of the transmission grid is available to support competitive wholesale is called for.  But so long as a “transmission operator with control over the electric power grid in an area may have the incentive and the ability (through transmission discrimination) to insulate its own generation,” then it will likely do so and hold ATC, however well measured, off of the market. 

What is needed are structural solutions, according to the FTC, i.e., “establishment of Regional Transmission Organizations or independent transmission operators (Transcos) to operate the grid,” coupled with incentive for “economically appropriate transmission upgrades that expand the scope of the geographic market.”  The FTC first began advocating such structural solutions to FERC in 1996 comments on FERC’s then pending open-access transmission tariff initiatives, Orders No. 888 and No. 889.   Reform of TTC and ATC calculations is likely a best available short-term deterrent to transmission discrimination in markets without an RTO, the FTC acknowledged.  More accurate calculations will likely reduce curtailments — transmission line relief orders — and could help operators respond more precisely to security emergencies.  And to the extent that more accurate measures make it harder for transmitting utilities to discriminate without detection, then the profitability of undue discrimination may lessen and with it opposition to the structural reforms that the FTC has so long advocated.