FERC Rules to Promote Transparency in Natural Gas Markets

On December 21 the FERC adopted a Final Rule that establishes an annual reporting requirement designed, as Chairman Kelliher said, "to boost our efforts to carry out Congress’ mandate [in the Energy Policy Act of 2005] to protect consumers by protecting the integrity of the markets for physical [natural] gas."

The final rule directs buyers and sellers of more than 2.2 million MMBtus of physical natural gas annually to file information pertaining to the size of physical natural gas markets, the relative importance of indexed and fixed price transactions, and the identity of major traders.   Specifically, Form No. 552 filings will report on the total volume of sales and purchases, the volumes of transactions that were priced at fixed prices, and the volumes of transactions that were reportable to price index publishers.  In addition, affected buyers and sellers must indicate whether sales of natural gas are transacted under a blanket sales certificate.  Form No. 552 must be filed by May 1 of each year, starting in 2009 for transactions delivered in the previous year.

Simultaneously, FERC issued a Notice of Proposed Rulemaking (NOPR) in which it proposes "to require both interstate and certain major non-interstate natural gas pipelines to post capacity, daily scheduled flow information and daily actual flow information" in order to achieve price transparency in natural gas sale and transportation markets.  Chairman Kelliher stated, however, that "the new proposed rule has a narrower application on major non-interstate pipelines [because it would] limit the reporting requirement to major non-interstate pipelines with significant gas flows that do not fall entirely upstream of a processing plant or deliver gas almost exclusively to retail consumers."  Commissioner Spitzer invited comments as to "whether the posting requirements for both interstate and non-major interstate pipelines should be similar" and "how the posting requirements should apply to storage facilities."   Comments on the NOPR are due in mid March.

Competing FERC and CFTC Jurisdictional Claims Are Court Bound

FERC in a November 30 order refused to reconsider its July 26 decision to impose $291 million in civil penalties against Amaranth Advisors (Amaranth) for gaming the natural gas futures market and manipulating the price of natural gas.  FERC upheld its own jurisdiction to impose penalties on Amaranth, rejecting the Commodities Futures Trading Commission's (CFTC) insistence that it alone has jurisdiction over manipulation of gas futures contracts.  FERC found instead that "the language and statutory purpose of Section 315 of the Energy Policy Act of 2005" (EPAct 2005) gave FERC "broad authority to sanction manipulative conduct by any entity 'in connection with' the purchase, sale or transport of natural gas within its jurisdiction." 

In the earlier July order, FERC had directed Amaranth to show cause why it had not violated the Natural Gas Act and FERC's anti-market manipulation rules, and proposed a $291 million civil penalty for allegedly manipulating the gas futures market by selling New York Mercantile Exchange (NYMEX) futures contracts just before they expired.  In an August request for rehearing, Amaranth argued that FERC did not have jurisdiction to impose the proposed civil penalties, and that the CFTC had exclusive enforcement authority for manipulation of gas futures markets.  The case has set up a turf war between FERC's expanded enforcement authority under EPAct 2005 and the CFTC's traditional regulation of commodities markets, and led the CFTC to argue that it has exclusive jurisdiction over this case.  Amaranth may now appeal FERC's orders to a US Court of Appeals, which may ultimately delineate the boundaries of FERC's expanded enforcement authority in relation to the CFTC's authority over commodity futures markets. 

Also in the November 30 order, FERC gave Amaranth 14 days to responds to the original show-cause order.

Connecticut Blocks Pipeline Across Long Island Sound

A US District Court vindicated Connecticut´s opposition to construction of a pipeline across Long Island Sound, ruling that the US Secretary of Commerce's decision to overrule the state's opposition to the pipeline was arbitrary and capricious.  Barring a reversal at some future stage of the case, Connecticut thus prevailed in the latest of its numerous high-profile energy disputes, which in recent years have included opposition to a direct-current transmission cable across Long Island Sound and disputes over electric power prices and market rules.  The case is of further interest because it involves litigation under the Coastal Zone Management Act (CZMA), a statute intended to balance decisional authority between state and federal agencies.

The Islander East Pipeline, which is jointly owned by Spectra Energy and Keyspan Energy, proposes to lay a 45-mile pipeline from Long Island to Connecticut.  To proceed, the project requires the go-ahead from the Federal Energy Regulatory Commission under the Natural Gas Act, but is also subject to the CZMA.  Under the CZMA, a state may develop a coastal management plan to help manage infrastructure and activities along its coast.  Connecticut determined that the Islander East Pipeline project was not consistent with is coastal management plan.  The Secretary of Commerce overruled the State, finding no alternatives to a project that met the CZMA requirement of advancing a national interest that outweighed local harms. 

Following an appeal by the State, the Court found shortcomings in the Secretary's analysis regarding the harm from the project and the potential for alternatives.  In particular, the Court found that the Secretary had failed to consider adequately the environmental impact of constructing the pipeline, including on shellfish habitat.  The Court further concluded that the Secretary had not considered adequately alternatives such as expansion of the Iroquois Gas Transmission System pipeline, which already crosses the sound, or placement of Islander East along that corridor. Following the Court's remand, the Department of Commerce will now reconsider its decision.

High Cash Distributions of Master Limited Partnerships May Set Regulated Equity Return to Natural Gas Pipelines

In a July 19 proposed Policy Statement, the Federal Energy Regulatory Commission (FERC) floats the idea of substituting cash distributions that natural gas pipelines, organized as master limited partnerships (MLP), make to their partners for the corporate dividends that the agency uses in discounted cash flow (DCF) analyses to set regulated equity returns for natural gas pipeline companies.  The industry has long requested and anticipated this policy development since, increasingly, natural gas pipelines (like their oil pipeline cousins) have switched from traditional C-corporations to lower-taxed MLPs — from twice-taxed corporate dividends to once-taxed MLP cash distributions that tend to be higher.  If the Policy Statement is adopted, it may also affect equity returns of electric transmission systems, a number of which are considering switching from C-corporations to (MLP-comparable) real estate investment trusts (REIT).  To be considered, public comments on the proposed Policy Statement must be submitted within 30 days of publication in the Federal Register — sometime in late August.  A final Policy Statement is expected before year’s end.

Since corporate dividends distribute a portion of earnings, dividends have traditionally been a dependable indicator of where regulated returns on equity should be set, namely at a level that permits utility investors to earn a reasonable return on investment while also providing adequate funds for future growth.  Use of MLP cash distributions instead of corporate dividends is controversial in that those distributions can, and not infrequently do, exceed earnings and provide not only a return on investment but also a return of investment, which, if used in a DCF analysis, would award higher equity returns to natural gas pipelines, and possibly double recovery of some investments in the form of both equity return and depreciation.    (Presumably the same would be true if the cash distributions of an electric transmission REIT were used in a DCF analysis to set a transmission utility’s equity return.)

To address these concerns, FERC proposes two limitations on the use of MLP cash distributions in DCF analyses.  First, in order to be eligible for use in a DCF analysis, MLP cash distributions would be capped so that they could not exceed the reported earnings of an MLP natural gas pipeline — a return on, but not of, investment.  Second, a proponent of using MLP cash distributions in a DCF analysis would be required to produce and analyze multi-year data on the selected MLPs to show that cash distributions were not excessive and that earnings and growth were sustainable over time.

FERC Aggressively Responds To Natural Gas Violations

Over the past month, FERC has continued its heightened enforcement activity, approving two settlements with separate natural gas shippers who self-reported violations of the Commission's orders and regulations.  The settlements illustrate FERC's oft-stated preference for settling, rather than litigating, alleged violations.  FERC has now approved eight settlements, totaling $30 million, with natural gas and electric entities since the beginning of 2007.

On May 21, FERC approved a settlement with Columbia Gulf Transmission Company, in which the company agreed to pay $2 million to resolve an Office of Enforcement investigation into whether it violated orders allowing Tennessee Gas Pipeline Company to construct a receipt point interconnection on a Louisiana natural gas complex co-owned by Columbia Gulf and Tennessee.  In 2005, FERC issued an order approving Tennessee's proposal to construct a receipt interconnection at the complex, based on FERC's open-access policy.  The two companies subsequently disputed which one would operate the new interconnection, and in 2006, FERC attempted to settle the matter by directing Columbia Gulf to provide the taps necessary for Tennessee's interconnection.  FERC also referred the matter to the Office of Enforcement, which began an investigation into whether Columbia Gulf's actions violated FERC's orders approving the interconnection, and at the conclusion of its investigation, alleged that Columbia Gulf had substantially delayed and had created unwarranted obstacles to the project's completion.

The Columbia Gulf settlement comes on the heels of a May 9 order approving a stipulation and consent agreement with Calpine Energy Services, LP.  Calpine agreed to pay $4.5 million for entering into thousands of transactions in which it transported more than 150 billion cubic feet of natural gas on eight pipelines without holding title to the gas.  The settlement also resolved violations involving the misuse of pipeline capacity by Calpine affiliates to serve other affiliates and the improper movement of natural gas.  Calpine, which is currently in bankruptcy, received approval from the bankruptcy court for the settlement as a pre-petition unsecured claim.

Department of Energy Proposes $9 Billion in Clean Energy Loans

Nine billion dollars could flow to guarantee loans to clean energy projects under a May 10 Department of Energy (DOE) Notice of Proposed Rulemaking (NOPR) under the Energy Policy Act of 2005. Each approved project could receive guarantees covering up to 80% of total project costs.  To be considered by the agency, written comments must be submitted within 45 days from notice in the Federal Register — likely late June or early July.

DOE proposes loan guarantees for ten categories of projects and technologies, including:  renewable energy systems; advanced fossil energy technology, including qualifying coal gasification systems; residential, industrial or transportation hydrogen fuel cell applications; advanced nuclear facilities, carbon capture and sequestration practices; efficiency in electrical generation, transmission and distribution; end-use efficiency technologies; production facilities for fuel efficient vehicles; pollution control equipment; and certain crude oil refineries.

Allocation of the $9 billion in loans will not be equally distributed among the ten categories; rather, $4 billion is reserved for central power stations, $4 billion for biofuels and clean transportation fuels, and only $1 billion for projects involving new technologies for electric transmission or renewable power generation systems.  According to DOE, precise allocation of the guarantees will depend upon the merits and benefits of a particular proposal and the accompanying statutory and regulatory requirements.

While the program is a positive development for the energy industry as a whole, efficient and fair implementation by DOE is critical, and that implementation is the specific subject-matter of the May 10 NOPR.  Provisions of particular interest to potential loan applicants include payment of the Credit Subsidy Cost, assessment of fees to loan recipients, rules on financial structure and eligibility of lenders, regulatory review, and default and audit rules.

Those industries now participating in eligible technologies and those planning expansion into clean energy projects can find public comment and public meeting procedures at Section III of the NOPR.

FERC Proposes to Trim Applicability of Standards of Conduct to Both Electric Utility and Natural Gas Pipeline Energy Affiliates

In response to the court remand of FERC's Order No. 2004 standards of conduct as they apply to natural gas pipelines, a proposed rule to revise the standards of conduct has quickly followed FERC's interim rule on the subject, issued earlier this month.  The proposed rule would make permanent the interim rule.  The interim rule exempted from the standards of conduct restrictions on energy affiliates of natural gas pipelines. 

Application of the standards of conduct to energy affiliates of electric utilities was not challenged on appeal of Order No. 2004.  The proposed rule, however, suggests following the court's natural gas pipeline ruling and eliminating application to the energy affiliates of electric utilities as well as natural gas pipelines.  In the rulemaking proceeding, FERC will consider whether evidence of abuse or the potential for abuse involving electric utilities' energy affiliates justifies retaining the standards applicability to electric utility energy affiliates.  If FERC decides that this justification exists, then the standards will apply more broadly to electric utility operations than to natural gas pipelines. 

The proposed rule would make permanent provisions contained in the interim rule regarding other issues challenged on appeal but not addressed by the court.  These provisions include allowing risk management employees and lawyers to be shared between natural gas pipelines and their marketing affiliates, and requiring natural gas providers to post only those "discretionary acts" that waive adherence to tariff provisions.   

Finally, in an extension of FERC's Order 2004 policy that employees involved only in "bundled retail sales" were not considered "marketing affiliates" and thus not subject to the standards of conduct, the proposed rule would relax the standards of conduct as to public utilities' "planning" and "competitive solicitation" employees so that these employees can access non-public transmission information in connection with implementing state-mandated integrated resource planning and competitive solicitations.  The main focus of this proposal is on the electric transmission grid and issues of reliability and accurate long-term planning. 

FERC Issues Interim Rule for Standards of Conduct for Natural Gas

FERC has adopted in Order No. 690 an interim rule on the applicability of standards of conduct to interstate natural gas pipelines; the placeholder rule responds to a US Appeals Court decision in National Fuel Gas Supply Corp. v. FERC, 468 F.3d 831 (D.C. Cir. 2006) that FERC’s earlier Order No. 2004 unlawfully expanded the standards of conduct governing affiliate favoritism to apply beyond the marketing affiliates of a natural gas pipeline ─ that is, the court struck down application of the standards to non-marketing affiliates.  The placeholder defines "marketing" (including brokering) to mean a sale of natural gas to any person or entity by a seller that is not an interstate pipeline, except when (1) the seller is selling gas solely from its own production, (2) the seller is selling gas solely from its own gathering or processing facilities, or (3) the seller is an intrastate natural gas pipeline or a local distribution company making an on-system sale.  Although the case involved only the affiliate conduct standards as applied to a natural gas pipeline, the ruling cast in doubt the application of identical standards of conduct to the non-marketing affiliates of electric transmission providers.  In addition: 

• The interim rule allows sharing risk management employees between natural gas pipelines and their energy and marketing affiliates when the employees are engaged in transmission functions or sales or commodity functions.   
• The interim rule requires a natural gas pipeline to maintain a log of the tariff provisions that it waives, but only with respect to tariff provisions that provide for such discretionary waivers, and to provide the log to any person requesting it within 24 hours of the request. 
• Order No. 690 clarifies that FERC will treat natural gas pipeline lawyers as permissibly shared employees.  FERC's orders on Order No. 2004 had provided that while lawyers could provide legal or regulatory advice in their traditional roles without becoming transmission function employees ─ subject to the standards of conduct ─ to the extent that a lawyer engaged in transmission functions or in planning, directing, or organizing transmission functions, the lawyer was not exempt from also being a transmission function employee (and thus not permissibly shared between a natural gas transmission provider and its affiliates).   
• Order No. 690 clarifies that FERC will not require newly certificated natural gas pipelines to observe the standards of conduct until they commence transmission transactions with their marketing affiliates.  FERC's orders on Order No. 2004 had provided that newly formed transmission providers would become subject to the standards of conduct as soon as they began soliciting business or negotiating contracts. 

The interim rule retains provisions of Order No. 2004 not challenged on appeal.  Those provisions will continue to apply to natural gas transmission providers and their marketing affiliates.

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.

Judge Grants Florida Gas Initial Approval of LNG Standards

A FERC judge has approved the gas quality and interchangeability standards that Florida Gas Transmission (FGT) proposed for the liquefied natural gas (LNG) introduced into its pipeline system.  The judge's decision could usher in standards for not only FGT but all pipeline systems throughout the U.S.   

The case began with a proposed interconnection agreement between AES Ocean Express LLC (AES) and FGT, under which AES – through its proposed Ocean Express LNG terminal in the Bahamas – would deliver re-gasified LNG into FGT's interstate pipeline system.  AES complained to FERC that FGT's proposed gas quality and interchangeability standards for these deliveries were too restrictive.   

The FGT standards fell between the lenient standards that LNG suppliers favor and strict standards advocated by Florida's gas-fired power generators.  The judge ruled that FGT had struck the appropriate balance between encouraging increased imports of LNG and protecting domestic pipeline systems from damage.  He deferred the issue of cost allocation for testing regasified LNG, however, claiming that a separate hearing should be established to address that issue.  Also raised but not addressed was whether the standards for imported LNG should also apply to domestic gas supplies. 

Although AES has yet to obtain approval from Bahamas regulators to construct the terminal, a FERC approval of the ALJ's decision could still have far reaching implications, as the standards proposed by FGT would apply to all LNG terminals planning to inject re-gasified natural gas into FGT's system.  Such approval may also set a baseline for future FERC proceedings to establish gas quality standards applicable to re-gasified LNG nationwide.

Legislator Questions Value of Post-PUHCA Consolidations to Ratepayers

National Grid USA (National Grid) announced its proposed acquisition of Keyspan, the largest distributor of natural gas in the Northeast and New York state's largest electricity generator.  At the completion of the merger, National Grid will have a combined 3.4 million natural gas customers and 8 million electric consumers in the New York and New England area.  Keyspan will continue to operate in its own name, although it will be a wholly owned subsidiary of National Grid.  The companies have targeted to close the transaction by early 2007.

This announcement comes on the heels of Exelon's purchase of PSEG, Mid-American's purchase of PacifiCorp, Duke Energy's planned acquisition of Cinergy, and the merger of  Florida-based FPL Group with Constellation Energy ― all made feasible by last year's repeal of  the Public Utility Holding Company Act of 1935 (PUHCA).  (See Energy Policy Act of 2005 Hands FERC a Long To-Do List, FERC Pares Back Accounting & Record Keeping, but Retains Strict Transfer Pricing for Public Utility Holding Companies under PUHCA 2005 and Congress Enacts Energy Bill)  Some legislators, such as Rep. Edward Markey, have begun to question whether these consolidations will benefit utility ratepayers, and have expressed concern that FERC may not properly scrutinize utility mergers and acquisitions, even though FERC was given authority to do so in connection with PUHCA's repeal.  Rep. Markey has called on the states to strengthen state laws concerning such mergers because due to the repeal of PUHCA, the Securities and Exchange Commission no longer has the authority to review debt financing associated with such transactions.

NAESB Recommends Natural Gas-Electric Power Coordination

The Gas-Electric Interdependency Committee (GEIC) of the North American Energy Standards Board (NAESB) has submitted to FERC a final status report on its strategies for fostering increased cooperation between the natural gas and electric industries.  The New England cold snap of January 2004 spurred this effort by straining the area's gas infrastructure and highlighting the different operating practices in the natural gas and electric power industries.  In response, the GEIC began its investigation into both industries and in June 2005 submitted to FERC a preliminary report that identified issues related to coordination between the industries and highlighted potential actions to address those issues. 

The final status report identifies six activities that would benefit from better coordination:  (1) the development of standards for capacity release pricing for pipelines with negotiated rate authority from FERC; (2) adding another nomination cycle to allow shippers and power generators with firm transportation rights the flexibility to nominate gas in coordination with their market clearing times; (3) giving pipelines the ability to shift gas for primary firm transportation within a pipeline path to another market without having to re-offer that gas as secondary firm transportation; (4) clearing RTOs/ISO markets sufficiently far in advance to facilitate timely gas flow nominations ; (5) requiring generators offering power into day-ahead market to have appropriate commercial arrangements in place to fulfill needed obligations; and (6) defining certain terms, including alternative fuel capability, firm transportation service, and must-run generator. 

Energy Advisor to Coordinate State Energy Policy in Rhode Island

Rhode Island Governor Donald L. Carcieri (R) issued an executive order in mid-January creating the Office of Chief Energy Advisor to the Governor, and named Andrew Dzykewicz, Senior Project Manger at the Rhode Island Economic Development Corporation (RIEDC), to fill this new role.  Mr. Dzykewicz will be responsible for coordinating tiny Rhode Island's energy policy, and one of the first tasks assigned to the new Advisor is to oversee the enactment of a five-point energy agenda intended to assist in accessing affordable energy supplies and increasing energy conservation.

The Governor's five-point plan includes: 1) increasing natural gas supplies by offering support for regional siting of liquefied natural gas (LNG) terminals under construction in Eastern Canada, which, once up and running will increase the state's supplies and could allow Rhode Island to avoid the need for placement of LNG terminals along Narragansett Bay; 2) assisting FERC in reforming wholesale electricity pricing; 3) assisting low-income state residents to pay energy bills through a state assistance program that would supplement federal assistance; 4) completing a joint State Energy Office-RIEDC project intended to facilitate wind power development; and 5) performing a statewide audit of energy use to identify inefficiencies and to devise strategies to reduce energy consumption.

Producers and Pipelines Team Up to Urge Changes in Natural Gas Infrastructure Development

Strange bedfellows, the Interstate Natural Gas Association of America ("INGAA") and the Natural Gas Supply Association ("NGSA"), together petitioned FERC to initiate a rulemaking to re-examine the parameters of blanket certificate authority and to make clear to the marketplace that shippers who make projects financially possible may enjoy preferential rates.  The petitioners explained that to ensure the adequacy of pipeline infrastructure in the future, FERC must act to make it easier for the industry to build capacity.

Specifically, the INGAA and NGSA suggested that FERC permit blanket authorization for mainline expansions where the expansion meets the dollar limits imposed by FERC's regulations.  The Parties stated that there should be little concern regarding the rate impact of this proposal because the dollar limits would cap the size of the projects that could be completed under the blanket authority provision.  Additionally, according to the petition, because FERC's rules require the posting of available capacity, this guarantees non-discriminatory treatment of new capacity.  Regarding the dollar limits, the Parties proposed that the limits be adjusted to reflect not only inflation, but also specific factors that can have a big impact on pipeline construction costs, such as complex permitting processes and environmental requirements.

INGAA and NGSA also urged that the blanket authorization provision be amended to allow blanket certificate eligibility for certain underground storage enhancements and takeaway facilities for LNG, and that FERC establish a policy that allows for predictable preferential treatment for shippers who underwrite the cost of a new facility through timely commitments.  According to the petitioners, this would allow sponsors and shippers the ability to negotiate without fear that their agreement containing a rate bargain for the foundation shippers will be undone, and would provide a strong incentive for shippers to become foundation shippers.

Two Paths to a Future Powered by Integrated Gasification Combined Cycle

Both California and Pennsylvania recently put forward energy plans that are likely to speed implementation of highly efficient and low-polluting technologies for generating electricity from gasified coal.  The 2005 Integrated Energy Policy that the California Energy Commission ("CEC") adopted at the end of November would indirectly have this effect by requiring the Golden State's utilities to procure power only from generating stations that meet Governor Schwarzenegger's (R) greenhouse gas ("GHG") performance standards, which integrated gasification combined cycle ("IGCC") units can but traditional coal-fired plants cannot.  Fast on the heals of the CEC Policy, Pennsylvania Governor Rendell (D) unveiled his Energy Deployment for a Growing Economy ("EDGE") initiative to provide low-interest loans for IGCC units and a moratorium on required pollution controls on existing coal-fired plants whose owners commit before 2007 to install IGCC by the beginning of 2013.  The Rendell proposal likely will require Environmental Protection Agency ("EPA") approval of the moratorium on pollution controls at existing plants as that would extend by two years the 2010 emission reduction directive of EPA's recently announced Clean Air Interstate Rule ("CAIR").

California is the 6th largest economy in the world and the 17th largest emitter of GHG.  Every two years the CEC updates California's energy plan.  The 2005 plan imposes on utility power procurements the GHG performance standards that Governor Schwarzenegger established last June.  Those standard aim to reduce GHG emissions to 2000 levels by 2010, to 1990 levels by 2020, and to 80 percent of 1990 levels by 2050.  These standards effectively rule out procurements from traditional coal-fired plants and cast into doubt the viability of several dozen non-IGCC coal-fired projects (including some under construction) that are designed to serve the enormous California market.  Another project targeted to the California electricity market, the 1,300-mile Frontier transmission line that would link Powder River Basin coal deposits in Wyoming with California, may also be jeopardized by implementation of the GHG performance standards.

Because the capital cost of an IGCC plant runs 20-plus percent higher than for a traditional coal-fired unit, some have predicted that, in order to access the abundant coal reserves in the west, California would likely need to invest in some early IGCC plants to help demonstrate and establish the technology.  But then comes along the Pennsylvania initiative.  If it garners EPA buy in, EDGE could provide precisely the stimulus that IGCC requires, not only in Pennsylvania and California, but also in other markets with abundant coal reserves.   The program will give new and retrofit IGCC projects priority access to nearly $ 1 billion in low-interest loans form the Keystone State's Economic Development Financing and Energy Development Authorities.  Two of the leading IGCC technology providers, General Electric and Shell Oil, have committed to Governor Rendell that they will guarantee the performance of their equipment in connection with the EDGE program.

Nearly 10 percent of Pennsylvania electric generation capacity is coal-fired units that will need to discontinue operations or invest in costly pollution controls beginning in 2010 under CAIR.  [See Maryland Governor Proposes Plan to Reduce Plant Emissions] Each of these will be a candidate for conversion to IGCC under Governor Rendell's initiative.  When coal is gasified pollutants can be removed more economically and efficiently than they can be removed from the pulverized coal burned in traditional plants.  IGCC plants also emit significantly less carbon dioxide, the GHG principally responsible for global warming.

With Heightened Enforcement Threatened against Objectionable Natural Gas & Power Transactions, FERC to Offer Industry Guidance in the Form of ‘No-Action Letters’

Congress in the Domenici-Barton Energy Policy Act of 2005 (EPAct 2005) and FERC in proposed implementing regulations looked to the Securities Exchange Act of 1934 and its anti-fraud provisions to put in place parallel new prohibitions against and heightened penalties for manipulation and deception in connection with the wholesale natural gas and power transactions that FERC regulates.  [See FERC Looks to Past for Future Anti-fraud Enforcement and FERC Explains Its Policy on New Penalty Authority]   Not surprisingly, in a November 18 interpretation of its rules, FERC has looked again to the practices of the Securities and Exchange Commission (SEC) and the Commodity Futures Trading Commission (CFTC) under the securities laws to adopt a process for educating and guiding the natural gas and power industry on complying with the new prohibitions.  Specifically, through its staff FERC will now issue discretionary ‘no-action letters’ similar to those that the SEC and CFTC staff issue.

Presented with a specific transaction that an applicant for a no-action letter proposes to undertake, FERC will have the division of its staff with relevant expertise examine the transaction for compliance with FERC’s Standards of Conduct, Market Behavior Rules, and (once they are finalized and implemented) new rules implementing the anti-fraud provisions of EPAct 2005.  If the contemplated transaction passes muster under these strictures, then the FERC staff can issue a no-action letter indicating that the staff will not recommend any enforcement action in connection with the transaction.  While not binding on FERC itself (just as no-action letters are not binding on the SEC or CFTC), they almost always have this effect since they represent the consensus view of those on the staff most familiar with the subject matter of and rules pertaining to the proposed transaction at issue.  Unlike FERC’s earlier procedures for obtaining the informal advice of its staff, which ordinarily commanded a fee, the new no-action letter procedures will be free of charge, at least initially.

Because of ambiguities in FERC’s Market Behavior Rules and the newness of the anti-fraud provisions, access to the no-action letter process should prove a welcome development.  Use of the process should be integrated into the compliance program of every prudent participant in wholesale natural gas and power markets.  Requests for issuance of no-action letters should be addressed to FERC’s general counsel and should be submitted on a non-public basis.  They will remain confidential until answered, at which time, absent extraordinary circumstances, both the request and answer will become public.  The request must particularize in detail the parties to the proposed transaction and the requester’s role.  If FERC staff finds the transaction too speculative or vague, it can either request additional information or decline to respond.  [Informal Staff Advise on Regulatory Requirements, 113 FERC ¶ 61,174 (2005)]

FERC Stands by Its Policy Permitting Natural Gas Transportation Discounts

FERC recently reaffirmed its policy permitting competitive discounting of natural gas transportation charges, upholding the practice against charges that competitive discounting shifts costs unfairly to captive customers of the discounting pipeline.  According to FERC, allowing pipelines to adjust throughput to reflect increased sales at discounts remains an important tool for maximizing system usage of interstate pipelines, benefiting all users.

FERC's current policy is to allow pipelines to discount transportation charges on a nondiscriminatory basis, to meet competition from all other forms of transportation.  Before late 2004, FERC allowed discounting only for the purpose of meeting competition from capacity release or from intrastate pipelines.  FERC opted to allow discount adjustments for any of these competitive reasons.   But following an inquiry in late 2004, the agency stated that discounting to meet competition from all alternative transportation options lowered costs to all users by spreading pipeline costs over an increasing number of units of throughput.  

The Illinois Municipal Gas Agency, together with the Northern Municipal Distributor Group and the Midwest Region Gas Agency had asked FERC to reconsider its discounting policy.  They argued that the discounting does not benefit the captive customers of the discounting pipeline, and generally they claimed that low elasticity of demand for natural gas transportation prevented discounts from materially increasing demand and throughput.  As a consequence, the complainants charged that discounting often shifts more costs to captive customers than it saves all customers generally from increased throughput.

Not so, countered FERC.  The evidence is that discounting more than offsets any shift in fixed costs on most systems.  FERC qualified, however, that if presented with circumstances on an individual pipeline that warrant additional protections for captive customers, such protections could be considered in individual rate cases.  In a noteworthy partial dissent, Commissioner Suedeen Kelly argued that pipelines should be required to post on their websites the reasons for providing a discount to a particular shipper.  [Policy for Selective Discounting by Natural Gas Pipelines, 113 FERC ¶ 61,173 (2005)]

Developers of LNG Facilities Now Must Complete Pre-Filing Process

FERC recently implemented a rule that requires potential developers of new LNG terminals to begin pre-filing procedures at least six months before filing a formal application with FERC.  The pre-filing process had previously been optional, but becomes mandatory under the recently enacted Domenici-Barton Energy Policy Act of 2005 (EPAct 2005).  While EPAct 2005 prescribes the pre-filing process only for applicants for new LNG terminals, FERC's rule is more expansive.  In accordance with the agency's National Environmental Policy Act responsibility to consider the potential environmental effects of LNG facilities, FERC has applied the pre-filing requirements to applicants seeking to construct all of the jurisdictional facilities entailed by an LNG terminal, including regasification, storage, and pipelines.  In addition, since many of the same safety concerns that arise with new LNG facilities may also arise when existing LNG terminals are modified or expanded, FERC will apply the rule to applicants seeking to make changes whenever the proposed modifications involve significant state and local safety considerations that have not been previously addressed.

Applicants subject to the new rule must now submit to FERC as much detail about their proposed facilities as possible, including the proposed project's conceptual design and engineering features, and its potential environmental, security and safety impacts.  The applicant has a window of 180 days after FERC issues notice of the prospective applicant's initiation of the pre-filing process to file the formal application for authorization of the LNG facilities. 

Congress' stated intention in requiring FERC to implement this requirement is to encourage LNG developers to coordinate with state and local authorities to address safety and security considerations.  In furtherance of this goal, the rule requires applicants to submit to FERC the names of the relevant federal and state agencies and identify the agency selected by the governor of the state where the project would be located to consult with FERC on the project's potential consequences.  Applicants must also demonstrate that this state agency has been made aware of the applicant's intention to use the pre-filing process.  [Regulations Implementing Energy Policy Act of 2005; Pre-Filing Procedures for Review of LNG Terminals and Other Natural Gas Facilities; New Matter]

Court Affirms Pro-Shipper, Competitive Rules on Use of Natural Gas Pipelines

After having sent FERC back to the drawing board to rethink its rules on a firm shipper’s right of first refusal to extend a capacity reservation on an interstate natural gas pipeline beyond its initial term and to segment a firm reservation into forward and backhauls, a U.S. Appeals court on October 28 vindicated the agency’s resolution of both issues. 

Specifically, in connection with the right of first refusal that existing firm shippers enjoy under FERC’s open-access rules, the court held that FERC was justified in eliminating its cap on the number of years that an existing firm shipper must commit to in order to match the firm service request of a competing shipper and trigger the existing shipper’s right of first refusal.  Previously, FERC had proposed to cap the term that the existing firm shipper match at 20 years and then 5 years, but the court found no reasoned basis for either cap.  Now, for a shipper to take advantage of the right of its right of first refusal to extend firm service beyond the term of its reservation, it will have to match a competing purchaser’s term, without limitation on the term, and price (as before, up to a maximum rate).  According to both FERC and the court agreeing with the agency, a term cap was not needed to prevent a pipeline from exercising market power since five other constraints on pipeline operations already cabined the potential exercise of market power against existing shippers:  (1) cost of service rates; (2) the requirement that a pipelines sell all of its capacity; (3) shipper access to FERC complaint procedures; (4) a shippers’ ability to release for third-party sales capacity that it reserved but didn’t need; and (5) the non-discriminatory access rules of the standard pipeline tariff.

On the backhaul issue, the court rejected interstate pipeline objections to FERC’s proposal to permit firm shippers to divide their capacity reservations within a transportation zone into forward hauls, backhauls, or combined forward hauls and backhauls. The pipelines contended that allowing such flexible uses of firm reservations effectively amended the contracts between the firm shippers and the pipelines; FERC and the court ruled that it did not.  Allowing backhauls within a zone of firm reservation and giving that haul a firm, yet secondary priority to firm (but superior to interruptible) was service that the firm shipper had paid for and was not a new service requiring contract amendment. 

The two shipping rules affirmed by the court laudably promote competition, without compromising consumer protections.  On the right of first refusal issue, requiring incumbent shippers to match fully the offers of competing shippers is fair and forces shippers to value competitively scarce resources.  And on the backhaul issue, allowing shipper flexible use of capacity it has already paid for, irrespective of direction of flow, simply prevents interstate pipelines from proliferating services and charges.   [American Gas Association v. FERC (DC Cir. No. 04-1094] 

DOE Increases Reporting Requirements in Effort to Increase Response to Natural Gas Supply Needs

In an effort to improve the country's ability to respond to future energy-related supply problems and to keep the general public informed on the current state of natural gas trading, the Department of Energy's Office of Fossil Energy ("OFE") has added a new monthly reporting requirement to existing and future Orders authorizing the import and export of natural gas and liquefied natural gas ("LNG").   The first monthly report, for the reporting period November 1, 2005, through November 30, 2005, must be filed no later than December 30, 2005, and can be filed electronically through OFE's website - www.fe.doe.gov.

OFE regulates natural gas imports and exports pursuant to section 3 of the Natural Gas Act.  Before the new rule, OFE collected information about natural gas and LNG import and export activities on a quarterly basis.  In accordance with the Department of Energy's Natural Gas Data Collection Initiative to improve the way the Department gathers and disseminates information about the use and origin of natural gas supplies in the U.S., OFE has expanded its collection activities.  The monthly reports must include information pertaining to the country of origin of an import or country of destination for an export, the points of entry and/or exit, and the total volume at each point of entry and/or exit for the month.

Pennsylvania Lacks Competition in Retail Natural Gas Supply Market

In a recent report released to the Governor and to the state General Assembly, the Pennsylvania Public Utility Commission ("PAPUC") concluded that competition in the Pennsylvania retail natural gas supply market simply does not exist.  This, of course, is not good news for ratepayers who are watching prices skyrocket due to increased demand worldwide as well as the effects of recent hurricanes on transportation and distribution lines in the South.  As a result of its findings, the PAPUC has determined that it will convene natural gas industry stakeholders to examine ways to increase competition and develop recommendations for changes to market structure and operation.

Pursuant to the 1999 Natural Gas Choice and Competition Law, the PAPUC was required to investigate the level of competition five years after the law had gone into effect.  The purpose of the law was to create opportunities for customers to purchase gas from independent suppliers. However, the PAPUC found that it is difficult for suppliers to enter the retail natural gas market in Pennsylvania because of differing security requirements and varying penalties that are not assessed in a cost-based manner by the natural gas distribution companies.  Additionally, the PAPUC found that the marketplace currently lacks accurate and timely price signals.   Although the report was supported by all five Commissioners, Commissioner Bill Shane expressed concern that a new stakeholder process would be a "futile exercise."

AES Corp.'s Proposed Boston Harbor LNG Project Meets with Tentative Approval

After rejecting two similar projects in or near their state, Rhode Island officials made clear in recent weeks that AES Corp.'s latest proposal to build a new liquefied natural gas ("LNG") facility on an island in Boston Harbor met with their approval.  Reportedly, AES Corp. is considering leasing Outer Brewster Island, a state-owned island eight miles from the Boston shoreline, in the hopes of building a new LNG facility there.

Rhode Island's support of an Outer Brewster Island facility stands in sharp contrast to its vehement opposition to two other projects in the area, the Weavers Cove project, planned for Fall River, Massachusetts, and a proposed terminal expansion by KeySpan Corp. in Providence, Rhode Island.  On September 20, 2005, Rhode Island Attorney General Patrick Lynch sent a letter to President Bush calling the proposal more sensible than Weavers Cove or the KeySpan expansion and calling on the President to urge FERC to stop considering these proposals.  Rhode Islanders feared that these two projects would pose serious security risks to the area because they were either too close to large population centers or would require LNG tankers to navigate the narrow Narraganset Bay.  AES Corp.'s proposal, on the other hand, is two miles from the nearest population center (in Hull, Massachusetts) and ten miles from downtown Boston.  Moreover, tankers could sail directly to Outer Brewster Island without having to enter narrow waterways.

Despite smooth sailing with Rhode Island, the AES project remains in its infancy and could yet be scuttled by opposition in Massachusetts.

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.

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.

Energy Policy Act of 2005 Hands FERC a Long To-Do List

The Domenici-Barton Energy Policy Act of 2005, signed into law on August 8, mandates that FERC issue several new rules and engage in other new initiatives over the next few months.  Milestones of particular significance to the power and natural gas industries are:

• Within 60 days:  Issue regulations on the National Environmental Policy Act pre-filing process for liquefied natural gas (LNG) projects. 
• Within 90 days: 
  • Consult with Departments of Interior, Commerce, and Agriculture, to establish procedures for trial-type expedited proceedings for mandatory conditions and fishways on hydropower licenses.
  • Issue a final rule exempting QFs, EWGs, and foreign utility companies from access requirements that take effect upon PUHCA repeal (PUHCA is repealed effective 6 months after enactment).
• Within 4 months: 
  • Issue rules to exempt from section 1275 any holding company whose public utility operations are confined to a single state and any other class of transactions FERC finds not relevant to jurisdictional public utility rates.
  • Issue any rules necessary to implement new PUHCA provisions.
  • Submit to Congress recommendations and conforming amendments to federal law necessary to carry out the new PUHCA subtitle.
• By Dec. 31, 2005:  Conclude California energy crisis proceedings and submit to Congress a report describing actions taken and timetables, if any, for further action.
• Within 180 days: 
  • Issue final rule implementing new reliability provisions.
  • Issue rule revising criteria for useful thermal output of QFs under PURPA.
  • Sign MOU with Commodity Futures Trading Commission on information under electric and gas market transparency provisions.
  • Report to Congress on progress in licensing and constructing Alaska natural gas pipeline.
  • With DOE, report to Congress on how to make available to all transmission owners and RTOs real-time information on the functional status of transmission lines within Eastern and Western Interconnections.
• Within 1 year:
  • By rule or order, establish how to meet the needs of load-serving entities.
  • Issue rules for incentive-based rate treatments for transmission in interstate commerce.
  • Convene regional joint boards to study security constrained dispatch, report to Congress.
  • Publish annual report assessing regional demand response resources.
  • As a member of a 5-member inter-agency task force, submit report to Congress assessing competition within wholesale and retail electricity markets.
  • Consult with DOE to conduct at least 3 LNG forums.
  • Enter MOU with other federal agencies to coordinate review and permitting of electric transmission facilities.
• Within 18 months:  Consult with DOE to submit report to President and Congress on benefits of cogeneration and small power production
• Within 2 years:  Consult with Agriculture, Commerce, Defense, Energy, Interior and states to identify corridors for pipelines and electricity transmission and distribution facilities on federal land in Western states, perform environmental reviews for those designations, and incorporate corridors into relevant agency land use plans
• Within 4 years:  Consult with Agriculture, Commerce, Defense, Energy, Interior and states to establish procedures to identify corridors for pipelines and electricity facilities for all other (i.e., non-Western) states.
• No deadline is set for these actions:
  • Issue rules governing national transmission corridor permits.
  • Adopt rules providing expedited procedures for processing FPA § 203 applications within 180 days.
  • Conclude MOU with Secretary of Defense to coordinate LNG facilities that may affect active military installations.
  • Consider New England states' objections to proposed locational installed capacity ("LICAP") requirement pending at FERC.
  • By rule or order, require non-regulated transmission entities to provide comparable open access.
  • Issue rules to permit recovery of prudently incurred costs of QF contracts.

Congress Enacts Energy Bill

One month after the Senate approved its version of a comprehensive energy bill, see Senate Votes in Favor of Energy Bill, Tumultuous Conference Awaits, Congress enacted the Energy Policy Act of 2005.  Although maligned by energy and taxpayer watchdogs as a "piñata of perks and pork" for big oil, big nuclear and other entrenched energy industries, the 2005 Act, as it affects certain aspects of the power and natural gas industries, promises to profoundly change the structure and prospects of new energy business organizations and the viability of new liquefied natural gas and power transmission projects.

For several years the demand for relatively clean-burning natural gas has increasingly outstripped North American production, giving impetus to efforts to import liquefied natural gas ("LNG").  But concerns over the safety of LNG re-gasification facilities in this country, both on- and off-shore, have seen myriad LNG development proposals from coast-to-coast crash in the face of public opposition.  The 2005 Act will override that opposition in part by consolidating many of the needed approvals, including siting, in one agency – FERC.  State and local authorities are effectively stripped of authority to block the siting of LNG importing and processing facilities.

The 2005 Act also promises to effect fundamental changes in the future structure and operation of power markets.  It does so by repealing the Public Utility Holding Company Act of 1935 ("PUHCA") and amending the Public Utility Regulatory Policies Act of 1978 ("PURPA").  At the same time, it gives FERC the authority to certify a new Electric Reliability Organization ("ERO") that (under regulatory supervision from FERC and its Canadian counterpart) will set and enforce standards for the reliable operation of the Eastern and Western Interconnections and the Electric Reliability Council of Texas.  The confluence of these developments will be profound and will likely force further consolidation of the power industry. 

Since its enactment 70 years ago, PUHCA was amended twice to allow limited holding company investment in power generation — in qualifying facilities under PURPA and in exempt wholesale generators under the Energy Policy Act of 1992.  But otherwise PUHCA confined utility holding companies to a single integrated public-utility system and has policed intra-holding company transactions to prevent cross subsidization.  Repeal of the PUHCA will knock down the barriers to consolidation of geographically and operationally diffuse utility systems.  Pending consolidations, such as Duke-Cinergy and MidAmerican-PacifiCorp, which may well have been barred by PUHCA's single integrated public-utility system requirement, now appear to have been prescient in anticipating PUHCA's repeal.  They likely will prove to be harbingers of other consolidations.

The so-called PURPA put also falls victim to the 2005 Act.  The PURPA-imposed obligation of traditional public utilities to buy the output of qualifying cogenerators and small, renewable generators at an avoided-cost price ushered competition in wholesale power markets into the 1980s.  The Energy Policy Act of 1992 later swelled the ranks of competitive generators by creating an additional class of PUHCA-exempt competitive generators with exempt wholesale generators ("EWGs").  Going forward after implementation of the 2005 Act, qualifying facilities and EWGs will no longer exist.  There will simply be power generators selling at wholesale and, where permitted by local law, at retail.  FERC is empowered by the 2005 Act to review and approve utility acquisitions of existing generating facilities in order to prevent (among other things) undue concentrations of generation market power.  Unclear, however, is who will build new generation under the largely deregulated scheme of the 2005 Act.   Arguably, without the price support of the PURPA put and the investment restrictions of PUHCA, only a shrinking universe of highly capitalized investors or existing utilities will build new generation in the future.  Some of these may ally with Indian tribes and construct power plant on tribal lands since the 2005 Act has special provisions for encouraging Indian energy development.  These provisions include the creation of an Office of Indian Energy Policy and Programs within the Interior Department with authority to pre-approve tribal-energy-resource agreements.

The 2005 Act will also tend to consolidate markets through its introduction of an ERO.  While the stated purpose of the ERO is to standardize, and make enforceable for the first time, rules for reliably operating the bulk power systems of North America, the indirect effect of that standardization will be the consolidation of formerly balkanized markets and the facilitation of increased trading in bulk power.

Thumbs up for Three LNG Terminals, Down for Another

            In late June FERC approved the construction and operation of three new liquefied natural gas (“LNG”) terminals that jointly will be able to import up to four billion cubic feet per day of LNG into the United States.  Weaver's Cove Energy and Mill River Pipeline, affiliates of Hess LNG, proposed one of the projects, which will be located in Fall River, Massachusetts.  The other project, proposed by Golden Pass LNG Terminal and Golden Pass Pipeline, subsidiaries of ExxonMobil, will be constructed in Texas and Louisiana.  These projects, together with the Vista del Sol LNG Terminal LP that FERC approved earlier, are the latest in a slew of LNG proposals intended to address the countries’ growing natural gas supply deficit.  See UPDATE (06/30/04).

The Weaver's Cove project includes a new terminal and two affiliated pipelines that would connect the terminal to the Algonquin Gas Transmission system and intrastate pipelines.  The project has met with great opposition from local interests, but FERC said that with appropriate conditions the project should be authorized.  It is the first LNG terminal in the current onslaught approved for the Northeast U.S.  The Golden Pass LNG terminal will be constructed at the Port Arthur ship channel in Texas and Louisiana.  Over 120 miles of new pipeline will connect the terminal with existing interstate and intrastate pipeline systems.

On the same day that it approved the Weaver's Cove and Golden Pass projects, FERC denied an application submitted by KeySpan LNG and Algonquin Gas Transmission to convert an existing LNG facility in Providence, Rhode Island into a new LNG import terminal.  FERC cited the applicant's failure to show that the facility would meet current construction and safety standards as its basis for the denial.

The Vista del Sol LNG Terminal LP and Vista del Sol Pipeline LP are also sponsored by ExxonMobil, and would be located in San Patricio County, Texas.  The past few months have seen FERC authorize the construction and operation of numerous other new LNG terminals in the Gulf region.  More approvals are likely in the pipelines as FERC endeavors to increase U.S. capacity for importing LNG.  Initial approval is no guarantee that proposed projects will successfully navigate the difficult path to completion and operation. [Weaver's Cove Energy, LLC, 112 FERC ¶ 61,070 (2005), Golden Pass LNG Terminal LP, 112 FERC ¶ 61,041 (2005), KeySpan LNG, L.P., 112 FERC ¶ 61,028 (2005) & Cameron LNG, LLC, 111 FERC ¶ 61,490 (2005)] [UPDATE]

Senate Votes in Favor of Energy Bill, Tumultuous Conference Awaits

          In what some have described as the easy first step down what will surely be a long and difficult road, on June 28, 2005, the Senate voted 85-12 to pass its version of the energy bill (H.R. 6), which has an estimated price tag of up to $35 billion.  The Senate's version would benefit the power industry in several key ways, but it also addresses energy conservation and development of clean energy alternatives.  Despite drawing praise from President Bush for its bipartisan support, the bill still faces an iffy future in a Senate-House conference that is sure to be contentious.  There are substantial differences between the Senate version and the earlier House version, which was passed April 21, 2005.  See UPDATE (04/30/03).  The President has said he wants a bill from Congress by August 1, before Congress recesses, leaving lawmakers a short window in which to iron out differences.  Given Congress's recent record of failure on passing comprehensive energy legislation, this could prove to be a tall order.

The Senate bill is encompassing.  Democrats were especially pleased with the inclusion of a Renewable Portfolio Standard, which will require utilities to generate ten percent of their electricity from renewable sources by 2020.  The bill also repeals the Public Utility Holder Company Act ("PUHCA") of 1935.  In lieu of PUHCA’s regulatory protections against holding company abuses, the bill would expand FERC’s authority to review utility mergers.  The Senate version also grants to FERC exclusive siting authority for liquefied natural gas ("LNG") facilities, an issue that has caused serious friction between FERC and various state governments that want more control over the siting of LNG facilities.

The Senate bill's tax incentives total $18 billion over the next ten years, offset by $4 billion in revenue-generating measures.  Forty percent of these tax incentives are geared toward renewable energy, conservation, and energy-efficient buildings.  The House's tax package, in contrast, provided only $8 billion in tax incentives.  Both exceed the Administration's proposal for only $6.7 billion in tax breaks.

The Senate bill also includes a voluntary plan for reducing greenhouse gases, along with a sense-of-Senate provision putting that branch of government on lonely record in support of action on global warming.  Although non-binding and unlikely to emerge from conference, this sense-of-Senate provision represents the first time that a branch of the federal government has officially acknowledged that greenhouse gases cause global warming.

Other key provisions include: an ethanol mandate of 8 billion gallons by 2012 (as compared with the House's mandate of 5 billion gallons); an oil savings provision requiring the President to reduce demand by 1 million barrels per day by 2015; a provision granting FERC new authority to approve the location of electrical transmission lines; mandatory electric reliability standards to improve operation of the nation's high-voltage transmission system and prevent blackouts; a call for an inventory of the oil and gas resources in the outer continental shelf; and a federal loan guarantee program to commercialize new technologies for fuel cells, coal, nuclear, carbon sequestration, and other advancements, including government-backed loans for power plants that create electricity from cleaner-burning coal and facilities that turn coal into natural gas.

Supporters of the Senate version, including Senate Energy and Natural Resources Committee Chairman Pete Domenici (R-NM) and Ranking Minority Member Jeff Bingaman (D-NM), acknowledge that the bill will not have an immediate impact on high gasoline, natural gas, or electricity prices.  High power prices are a keen political issue since oil prices peaked at a record high in June of $60/barrel and gasoline averaged $2.00/gallon nationwide.  In lieu of short-term benefits, the bill's supporters instead emphasized the long-term impact of the Senate bill, which they hope will increase domestic energy production by increasing renewable energy and alternative fuels, improving electricity transmission reliability, and reducing demand and the need for more power plants by boosting energy conservation and efficiency programs.  Senator Domenici did say, however, that the bill might offer some short-term relief for U.S. manufacturers from skyrocketing natural gas costs.

The main sticking point in the upcoming conference committee will likely be the insistence by House Republicans that the energy bill include a waiver of liability for manufacturers of the gasoline additive MTBE, which has polluted water supplies in many parts of the country.  Other contentious areas are likely to be the House provision authorizing oil and gas drilling in the wilderness of the Arctic National Wildlife Refuge, which is absent from the Senate bill, the differing tax packages included in each version, and the Senate's Renewable Portfolio Standard.  (H.R. 6) [UPDATE]

FERC Provides More Guidance on Status Changes that Power Sellers with Market-Pricing Authority Must Report

FERC relented in June to market participants’ demands and provided additional examples of those types of changes in status that, if not reported to the agency, could cause a power seller to forfeit its market-pricing authority. 

 The resulting message was a classic example of a regulator seeking to point those it regulates in a salutary direction, while at the same time striving mightily not to fence itself in through overly descriptive examples of applicable conduct.  FERC provided several illustrations of the types of contracts and events that would and would not trigger the reporting requirement, but also sought to protect its flexibility to demand reporting of new contractual arrangements by reiterating that it would not further specify what constitutes “control” of generating capacity. 

FERC stated that events and contracts that would trigger the reporting requirements include the testing of new generation facilities (subject to a 100-MW cumulative threshold), acquisitions of ownership or control of natural gas storage or intrastate pipelines, and obtaining generation capacity credits that transfer control.  In contrast, events not triggering reporting include becoming affiliated with an interstate pipeline and upgrading a utility’s own transmission network to increase total transfer capability.  [Reporting Requirement for Changes in Status for Public Utilities with Market-Based Rate Authority, 111 FERC ¶ 61,413 (2005)]  [UPDATE]

FERC Revises Business Practices Standards for Pipelines and Proposes New Standards for Electric Utilities

            On May 9, 2005, FERC issued complementary orders adopting revised business practices for natural gas pipelines and proposing similar standards for electric utilities.  The orders largely adopt standards proposed by the North American Energy Standards Board (NAESB). 

The Final Rule for gas pipelines adopts several standards developed by the Whole Gas Quadrant (WGQ) of NAESB, including WGQ's recommended practices for creditworthiness and gas quality reporting.  The creditworthiness standards provide procedural rules by which pipelines should deal with their customers with respect to credit issues, and these standards received broad support from shippers and pipelines.  They would provide standardized procedures for obtaining credit information; acknowledging and responding to requests for and receipt of information; notifying shippers regarding creditworthiness issues and contract termination;  reevaluating of determinations that a service requester is not creditworthy; and monitoring releases of capacity only to shippers  found to be creditworthy.   

FERC's Final Rule also adopts WGQ's proposed standards for gas quality reporting.  These standards include requirements that a pipeline include on its Informational Posting Web Site a link or reference guide to its gas quality tariff provisions and information on its daily average gas quality for preceding days to the extent quality information is available for locations that are representative of mainline gas flow for the most recent three-month period.  The Final Rule will become effective June 16, 2005, and pipelines are required to file with FERC conforming tariff provisions by July 1, 2005, to be effective September 1, 2005.  

In an attempt to similarly streamline reporting requirements and business practices for electric utilities, FERC also issued a Notice of Proposed Rulemaking (NOPR) proposing business practices standards that seek to incorporate standards developed by NAESB's Whole Electric Quadrant (WEQ).  The NOPR proposes to adopt: (1) Open Access Same-Time Information Systems (OASIS) Business Practices Standards; (2) OASIS Communications Protocols; and (3) an OASIS Data Dictionary.  The NOPR also proposes procedures for  redirecting transmission service, queuing multiple submissions of identical transmission requests, adopting the OASIS requirements of FERC's Large Generator Interconnection Rule (Order No. 2003), and for reviewing and updating OASIS standards.  Finally, the NOPR proposes to incorporate WEQ business practices standards, which complement the Version 0 Reliability Standards developed by the North American Electric Reliability Council (NERC).  To be considered by the agency, public comments on the NOPR must be submitted by July 1, 2005.   [Standards for Business Practices of Interstate Natural Gas Pipelines, 111 FERC ¶ 61,203 (2005) and Standards for Business Practices and Communication Protocols for Public Utilities, 111 FERC ¶ 61,204 (2005)] [NEW MATTER]

U.S. District Court Finds Filed Rate Doctrine also Applies to Market-Based Rates in Natural Gas Markets

On April 8, 2005, the U.S. District Court for the District of Ne