Energy Legal Blog

Rule Would Encourage Transmission Investment & Membership in Transcos & Transmission Organizations

In a November 18 notice of rulemaking FERC proposes to implement the incentives mandated in the Domenici-Barton Energy Policy Act of 2005 (EPAct 2005) for investing in electric transmission infrastructure that benefit consumers by increasing grid reliability and reducing the transmission costs caused by congestion.   The rulemaking posits that Transcos — stand-alone companies that sell transmission services at wholesale or otherwise unbundled from retail electricity sales — are the preferred vehicle through which transmission investments are made and, accordingly proposes additional financial incentives for forming, participating in, and funding Transcos.  Incentives are also proposed in the rulemaking that would encourage transmission owners to participate in transmission organizations that would operate their systems.  To be considered by the agency, public comments on the rulemaking must be submitted electronically or in hard copy by January 11, 2006.

The transmission provisions of EPAct 2005 and the proposed rulemaking respond to a recent and untenable history characterized by declining investment in transmission infrastructure, on the one hand, and burgeoning demand for electricity service, on the other.  According to industry sources, in order to assure system reliability and support competitive wholesale markets, the current $4 billion level of annual transmission investment in the US must increase to $5 billion annually.  In particular, the rulemaking implements Congress’ directives in new Federal Power Act (FPA) § 219 that FERC (1) establish incentive-based (including performance-based) rate treatments to induce investment in new and upgraded transmission systems that improve reliability and reduce congestion, and (2) provide to each transmission owner incentives to surrender operational control of its system to some form of independent operator.

Central to achieving both directives are proposals to allow returns on transmission investments that are at the top end of a zone of reasonableness, recognizing that nothing in EPAct 2005 removes or diminishes the long-standing FPA requirement that all transmission rates be just and reasonable.  This could be achieved not only by authorizing high returns on invested equity but also through the flexible use of hypothetical capital structures in setting returns.  Shortening the depreciable life of transmission investments to 15 years could also be use to accelerate the recapture of investment.  In addition to creamier returns and more rapid depreciation, the rulemaking also addresses investment risks peculiar to electric transmission infrastructure and the tax consequences of spinning off transmission to a Transco.

Aspects of the proposed rulemaking would recognize that long lead times attend designing and constructing new transmission before the new facilities become operational and begin earning revenues, and that unforeseeable things can go wrong in the meantime.  To address long lead times, the rulemaking would (1) allow l00 % of funds spent on transmission construction work in progress (CWIP) into a transmission owner’s rate base, and (2) permit the investor to expedite recovery of costs incurred before commercial operations begin by expensing rather than capitalizing those costs.   FERC solicits public advice on what pre-commercial operations costs should be eligible for expensing. 

In the event that occurrences beyond an investor’s control cause a transmission investment to be abandoned, the rulemaking would allow complete recovery of those costs.  In the past, the costs of an abandoned project typically have been split between the investor and transmission customers, but under the rulemaking could be recovered 100 cents on the dollar from customers.  FERC points to the recent example in which Southern California Edison was allowed to recover all prudently incurred costs to build transmission to interconnect a proposed wind farm.  FERC reasoned in that case that the wind farm developer’s decision to cancel its project would be beyond Edison’s control and justified complete recovery of pre-termination investments in transmission.  The rulemaking also addresses the investment deterrent confronting public utilities operating under retail freezes or moratoria.  These utilities would be unable to recover current transmission investments.  To lessen this burden, FERC proposes a deferred cost recovery program under which such a utility would begin recovery of new transmission facility costs in transmission rates as soon as the freeze or moratorium expired.

On top of these inducements, the rulemaking singles out Transcos for even further favors.  The distinguishing characteristic of a Transco is that the entirety of its business is providing transmission services (not coupled or commingled with generation) for which FERC alone sets the price.   In this respect, a Transco stands to benefit from the incentives of the rulemaking more so than an integrated public utility that sells a service of bundled power and transmission that is priced, at least in part, by state regulators.  Moreover, FERC finds in Transcos the preferred vehicle for transmission investments because it would not confront the tradeoffs that a traditional integrated utility confronts when its investment in transmission may well reduce the value of its other investments in generating plant.  Higher equity returns may accordingly be justified for Transcos because they have a history of reinvesting those returns more completely in needed new transmission infrastructure.

The rulemaking proposes also to remove a barrier to Transco formation.  As much of the nation’s existing transmission infrastructure that could be spun off to form a Transco has been depreciated to a book value far below its market value, the seller would incur accumulated deferred income taxes (ADIT) on its sizable capital gain.  Under this scenario, the seller can be expected to adjust upward the price it charges for its transmission system to cover these taxes.  FERC proposes in the rulemaking to continue its recent practice of allowing a Transco to recover in its transmission rates the increased purchase price that it pays to cover ADIT.

While clearly less enthusiastic about transmission organizations — ones with transmission systems still owned and controlled in part by traditional integrated utilities — than it is about a Transco, the rulemaking proposes to ensure that utilities that join such organizations fully recover the cost of their participation.  The rulemaking also implies and one Commissioner flatly suggested that the returns that transmission organizations earn on transmission investment should be directly proportional to how independent they are from the owners of the transmission systems that they operate.

Lastly, the rulemaking turns itself to the often controversial topic of performance-based pricing of transmission service.  FERC asks for public advice on how performance should be measured and rewarded.  Two noteworthy topics are raised.  FERC first asks whether the participation of public power entities in transmission-investment consortia should be rewarded for the low-cost debt financing they can provide through interest-free bond issues.  Second, FERC asks whether it should ask applicants for performance-enhanced rates for a statement of the innovative transmission technologies that they propose to implement.   [Promoting Transmission Investment Through Pricing Reform, 113 FERC ¶ 61,182 (2005)]

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 Seeks Comment on Whether to Revise, Repeal Market Behavior Rules

FERC asked on November 21 whether it should repeal its Market Behavior Rules in light of its new authority under the Energy Policy Act of 2005 (EPAct 2005) to prevent market manipulation.  FERC adopted the Market Behavior Rules approximately two years ago, and required them to be a part of all electric and gas market-based rate tariffs, in an effort to curb market manipulation.  The cornerstone is Market Behavior Rule 2, which prohibits "actions or transactions that are without a legitimate business purpose and that are intended to or foreseeably could manipulate market prices, market conditions, or market rules."  Public comments on whether repeal is in order are due 30 days after publication of FERC's proposal in the Federal Register, probably sometime in late December.

EPAct 2005 amended the Federal Power and Natural Gas Acts to grant FERC broader authority to prohibit any entity from using or employing "any manipulative or deceptive device or contrivance" in connection with the purchase or sale of wholesale electricity or natural gas and jurisdictional transmission or transportation services.  Pursuant to that authority, FERC initiated procedures last month to implement this new authority in rulemakings aimed at preventing market manipulation [see FERC Seeks Comments for Competition Task Force] and establishing new audit procedures [see Rulemaking to Establish Procedures for Challenging FERC Operational Audits], and a policy statement interpreting FERC's enforcement authority [see FERC Explains Its Policy on New Penalty Authority].  In these rulemakings, FERC has proposed to adopt a more specific intent or "scienter" standard of proof, which is modeled on the SEC's enforcement of Rule 10b-5 under the Securities Exchange Act of 1934, and has been interpreted by courts as requiring a showing of knowing, intentional or reckless conduct with intent to manipulate, deceive, or defraud.

In light of FERC's new EPAct 2005 authority, some commentators have suggested that the Market Behavior Rules are redundant, if not superfluous.  In particular, these critics point to the fact that the new anti-fraud rules of EPAct 2005 may be enforced against "any entity," including entities not usually subject to FERC's jurisdiction, while the Market Behavior Rules are applicable only to public utilities possessing market-pricing authority.  But notwithstanding this broader coverage, the Market Behavior Rules and specifically Market Behavior Rule 2 impose a stricter standard than the more-punitive new rules under EPAct 2005:   They proscribe actions or transactions that "foreseeably" could manipulate market prices, conditions, or rules, while the EPAct 2005 rules will require proof of intent.  [Investigation of Terms and Conditions of Public Utility Market-Based Rate Authoriziations, 113 FERC ¶ 61,190 (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)]

FERC Approves Enron-California Settlement

FERC approved a $1.5 billion settlement between Enron and the plaintiff group known as the California parties, as well as the attorneys general of Oregon and Washington, and FERC staff.  The settlement resolves claims and matters arising from transactions in the western energy markets from January 16, 1997, through June 25, 2003.   

The settlement includes an $875 million unsecured claim against Enron in the bankruptcy proceeding, a $600 million civil penalty in favor of the California, Oregon and Washington attorneys general, and cash or cash equivalence of $47.4 million.  Ominously for others who did business with the disgraced energy giant, the settlement also requires Enron to cooperate with the settling parties in their claims against other entities related to events in the Western energy market.  

The settlement has also been approved by the California Public Utilities Commission and the United States Bankruptcy Court for the Southern District of New York, which is adjudicating Enron's bankruptcy.  FERC's order noted that the value and timing of the settlement's $875 million unsecured claim in the bankruptcy proceeding is uncertain due to the ongoing bankruptcy litigation.  

FERC Chairman Joseph Kelliher called the Enron settlement a turning point in the agency's efforts to bring closure to the 2000-2001 Western energy crisis.  He also attributed the settlement to FERC's "strong enforcement posture."  Combined with the Chairman's recent statements in support of FERC's Office of Market Oversight and Investigations, its seems clear that the agency intends to emphasize its market oversight and enforcement roles.

Bankruptcy Court Cedes to FERC Resolution of Terminated Enron Contract

A New York bankruptcy judge has become the first to implement a provision of the Energy Policy Act of 2005 (EPAct 2005) that prohibits bankruptcy judges from deciding disputes over the fees associated with termination of pre-June 20, 2001, power supply contracts where the seller has been found to have manipulated the market and had its FERC market-pricing authority revoked.  In EPAct 2005 Congress granted to FERC exclusive jurisdiction to decide whether such sellers should be permitted to collect termination fees from their former buyers.  Although this provision of the statute does not mention Enron by name, it nevertheless squarely targets the disgraced energy trading giant.  Enron declared bankruptcy on December 2, 2001, inducing many of its buyers to terminate.  In order to benefit from this provision of the statute, a buyer's objection to payment of a termination fee must be pending and not subject to the final order of any court.

The specific dispute before the bankruptcy judge stemmed from a contract entered into in August 2000, which called for Enron to supply power to Luzenac America Inc.'s talc processing facilities in Montana.  After Enron filed for bankruptcy, its trustee sued Luzenac in the U.S. bankruptcy court for the southern district of New York for contract termination fees.  That suit is still pending.  Based on the EPAct provision, Luzenac petitioned FERC in October to review Enron's claim for termination fees.  In response, Enron asked the bankruptcy court to prevent Luzenac from pursuing its FERC petition.  Judge Arthur Gonzalez, however, denied Enron's motion, and agreed that, as a consequence of EPAct 2005, FERC has exclusive jurisdiction to resolve the dispute.  The judge's ruling will pave the way for other former Enron buyers to petition FERC to relieve them of Enron termination charges, which FERC is expected to do.

Pacific Northwest Grid Restructuring Proposal Fails, Utilities Vow to Continue On Without Bonneville

Following persistent delays and bickering, the nine utilities that originally proposed the formation of Grid West voted unanimously at a meeting on November 1 to reject a compromise proposal put forth by the Bonneville Power Administration ("BPA"), with six of those utilities promising to forge ahead with plans for a new regional entity without BPA.  While Puget Sound Energy and Avista Corp. have announced they no longer plan to participate in a regional organization, PacifiCorp, Idaho Power, NorthWestern, Sierra Pacific Resources, Portland General Electric, and the British Columbia Transmission Corp. insist they intend to regroup and continue their plans to develop an independent entity in the Pacific Northwest. 

Negotiations to form an independent entity in the region have been going on for several months.  The Grid West proposal was put forth several months ago by a number of investor-owned utilities and BPA.  The parties drafted bylaws for Grid West, but were careful to make clear that the organization would not be a Regional Transmission Organization ("RTO"), a concept that would have faced strong opposition from state officials.  The Grid West parties even sought a declaratory order from FERC that the proposed entity would satisfy FERC's requirements but would not necessarily have to qualify as an RTO.  Following FERC's conceptual approval of Grid West in July, a number of public power agencies and municipal utilities, among BPA's primary customers, formed a group called the Transmission Improvements Group ("TIG") and put forth their own counter-proposal to Grid West.  TIG's proposal flirted with limited improvements to the transmission grid, but stopped far short of placing grid operations in the hands of an independent board.  [See Negotiations Continue on BPA's Role.]  The Grid West parties and TIG appeared to be at an impasse, when in late October, Deputy Secretary of Energy Clay Sell wrote a letter to BPA encouraging cooperation in the region.  BPA, in turn, released a compromise, or so-called "convergence," plan that sought to marry the two fundamentally antithetical proposals.  BPA convened a meeting of interested parties on November 1 to gauge support for the convergence plan; however, during this meeting, BPA failed to garner any support for its proposal. 

Following the rejection of its compromise plan, BPA has pledged to continue talking with interested parties, and TIG has stated that it has further ideas about how to proceed.  The six remaining Grid West utilities plan to rewrite the Grid West bylaws, removing the provisions that concern BPA, and plan to contact other entities that may want to join a future initiative, inducting the Alberta independent system operator and Public Service of Colorado.  However, even if these Grid West faithfuls cohere, it remains to be seen how effective their organization could be without BPA's involvement, given its large share (by most counts, approximately 75 percent) of the transmission facilities in the Pacific Northwest.

California Voters Reject Return to “Good Ol’ Days”

California voters affirmed they support competition in the state's energy markets.  In the latest election, approximately 65% of voters opposed a ballot initiative that would have banned retail choice, increased state oversight of utilities, and eliminated direct access for those customers not already in the state's program.  The Utility Reform Network sponsored Proposition 80, arguing that it was needed to replace failed deregulation policies and to prevent market manipulation, price spikes, and rolling blackouts in the future.  Had it been accepted, the initiative would have allowed for private energy companies, such as non-utility generators and marketers, to be placed under the jurisdiction of the California Public Utility Commission ("CPUC"), and utilities would have been prohibited from charging prices responsive to demand.

Interestingly, in September, the CPUC unanimously voted to oppose Proposition 80, determining that the initiative duplicated work already in progress at the Commission, and would prevent the Commission from fulfilling the goals it set in its Energy Action Plan II, including supporting the existing competitive retail market and re-opening the direct access program, which allows large commercial energy users to buy power directly from private energy companies.  According to its opponents, the rejection of Proposition 80 will ensure customer choice and encourage development of much-needed generation capacity.

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]

Mirant Plant Showdown Prompts Efforts to Expand Transmission in D.C.

In the latest version of its Regional Transmission Expansion Plan, the PJM Interconnection announced support for an additional $297 million in transmission upgrades, including $70 million for new transmission lines needed for the nation's capital.  Adequacy of available power supply became an issue in the greater District of Columbia (DC) metro area late last summer when Mirant announced it was shutting down its 482-MW, coal-fired power plant in Alexandria, Virginia because of air emissions.  The DC Public Service Commission (PSC) petitioned FERC and the Department of Energy (DOE) to prevent the shutdown.  See Reliability v. Health: Neighboring States Battle over Dirty but Needed Generator.

Following a brief shutdown, the Mirant plant resumed limited operations.  The shutdown, however, focused attention on the need to increase power supply to the DC area.  In October, Potomac Electric Power Company (PEPCO)  ― the utility serving DC ― filed an emergency petition for authorization from the DC PSC to construct two 230 kV underground and two 69 kV overhead transmission lines.  PEPCO cited as an emergency the uncertainty about the future of the Mirant plant, and asked the DC PSC to waive certain procedural requirements so that the transmission lines could be constructed on an expedited basis.  PEPCO earlier had supported the DC PSC's petition to FERC and DOE. 

The DC PSC has yet to issue any substantive orders in response to PEPCO's petition, but the D.C. Office of the People's Counsel recently sounded in with its concerns, arguing that the DC PSC should move expeditiously but also adhere to its normal permitting process for the proposed transmission projects, which entails extensive intra-government consultation and community outreach.  Meanwhile, the future of the Mirant plant remains unresolved.

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] 

First Gulf of Mexico Wind Project Advances in Texas

Wind developers have long had their eyes on offshore sites for future development of wind energy, but no offshore projects to date have been completed in the U.S.  That may soon change.  A major step was taken towards establishing the first windfarm in the Gulf of Mexico when the Texas General Land Office signed an agreement with a wind developer that plans to construct a windfarm approximately seven miles off Galveston Island. 

Under the arrangement, Galveston-Offshore Wind, LLC, would initially construct two 80-meter meteorological towers to gather wind data to determine where the 150 MW windfarm would be sited within the 11,355-acre leased area.  In addition, studies will be made of migratory bird patterns to attempt to minimize injuries to birds.  This is a significant issue in light of the large number of birds that migrate across the Gulf.  Once research is completed and necessary permits secured, the developer would proceed with construction of approximately 50 wind turbines, which is estimated to take up to five years and cost approximately $300 million. 

Under the agreement, the developer would initially pay the state a 3.5 percent royalty from the windfarm's total production, to increase to 4.5 percent for years 9-16, and to 5.5 percent for years 17-30.  Another benefit associated with the deal is that the state's revenues from the agreement, estimated to surpass $26 million, will be deposited in the state's Permanent School Fund, which helps fund public education. 

Rulemaking to Establish Procedures for Challenging FERC Operational Audits

As a part of an overhaul of its enforcement procedures and authority, on October 20 FERC issued a notice of proposed rulemaking (NOPR) that would extend its financial auditing rules to operational audits.  These audits seek to gauge compliance with FERC's standards of conduct, code of conduct, market behavior rules, rules on interlocking directorates, and other standards under the Federal Power Act, as well as audits pursuant to the Natural Gas Act and Interstate Commerce Act.  Public comments on this proposed rulemaking are due November 22, 2005; reply comments are due November 29.

Just one of a slew of rulemakings FERC has recently undertaken, the NOPR would allow companies subject to operational audits to challenge the auditor's findings before FERC issues an order on the merits of any disputed findings on non-compliance.  Under the proposal, FERC would still issue an order on the merits with respect to any non-disputed compliance issues, but would issue a public notice as to any disputed audit findings.  The audited entity or person could then choose between a shortened review procedure and a trial-type hearing to challenge the disputed audit matters.  Under the shortened procedures, the audited person and other interested parties, including FERC's technical staff, would be allowed to submit memoranda of the facts and law supporting their positions to the Commission.  Any person that elects the shortened procedures will be precluded from subsequently requesting a trial-type hearing.

Until now, the shortened procedures have been available only to subjects of financial audits.  Perhaps acknowledging a potential increase in the number of operational audits it will perform, FERC Chairman Joseph Kelliher noted that out of "simple fairness," procedures for challenging the findings made in operational audits should be available to all audited entities just as they are for the targets of financial audits.  While in principle, this sounds like a positive development for companies subject to operational audits, it may prove little more than a sham.  Under the existing financial auditing rules, the shortened procedures have often been perfunctory, with the auditor serving as judge and jury over the target's appeal.  In practice, this creates an incentive to demand a trial-type hearing (whenever contested facts can arguably support such a demand)  because then FERC or an administrative judge, rather than the auditor, will hear and decide factual disputes, cross examine the audit staff, and develop a further record for appeals.  [Prodceudres for Disposition fo Contested Audit Matters, 113 FERC ¶ 61,069 (2005)]