FERC Augments, Revamps Enforcement Guidance and Procedures

FERC has taken several steps to clarify its policies for conducting enforcement investigations, carrying out its authority to impose penalties on violators, and broadening the scope of issues to be covered by its ex parte rules and no-action letter procedures.  The additional guidance is welcome in light of the seemingly haphazard approach to enforcement that FERC has taken over the last couple of years. 

FERC’s new Revised Policy Statement on Enforcement supersedes its 2005 Policy Statement on Enforcement.  The Revised Policy Statement affirms FERC's existing enforcement policies and explains the usual steps involved in FERC's conduct of audits and enforcement investigations.  It describes the types of matters that FERC has recently determined do not merit investigation or that have not resulted in findings of a violation or sanction.  It lists several actions that entities can take to develop strong compliance programs, and offers suggestions for making effective self-reports.  Finally, it augments the current list of factors that FERC will consider when determining the seriousness of an offense:

• What, if any, harm was there to the efficient and transparent functioning of the market?
• What are the earnings, revenues and market share of the part of the company that is under investigation?
• What penalty amount best deters improper conduct, while not excessively discouraging beneficial market participation?
• What was the motivation of those accused of the improper conduct?
• Was the integrity of the regulatory process impaired:
• Was there a risk of serious harm, even if the actual harm was slight of non-existent? 

FERC also issued a Notice of Proposed Rulemaking (NOPR) to clarify its regulations governing ex parte contacts (Rule 2201) and separation of functions (Rule 2202) in the context of non-public investigations.  Rule 2202 prohibits FERC staff that act as litigators in an adjudicated proceeding from advising as to the outcome or decision in that proceeding.  The NOPR proposes that this separation begin at the point when FERC issues a show-cause order in a proceeding or initiates a civil action under Part 1b of FERC's regulations.  The NOPR also proposes to apply FERC's ex parte rules during investigations conducted under Part 1b, where they do not currently apply.   

FERC Mostly Affirms Market-Based Rate Program

On April 21, FERC issued an order generally affirming its market-based rate program, promulgated last June in Order No. 697.  FERC left many of its prior determinations in place, including much of the analysis sellers must provide in order to receive or maintain authority to sell electric energy, capacity, and/or ancillary services at market-based rates. 

In particular, FERC affirmed its decision to combine its prior four-pronged analysis into an evaluation of horizontal and vertical market power.  FERC will continue its approach of using "indicative" screens to determine both a seller's wholesale market share and whether the seller is a "pivotal" supplier within the relevant geographic market.  If a seller fails to pass either of these screens, FERC will presume the seller has market power within that market and require the seller to either (a) refute that it has market power or (b) adopt mitigated (i.e., cost-based) rates for that market.  FERC also affirmed its decision to remove questions about the relationship between market-based rate sellers and their affiliated franchised public utilities from the market-based rate review program, and instead to codify those requirements in FERC's regulations as ongoing obligations that sellers must continue to meet.

FERC did offer certain clarifications or revise certain of its prior determinations on rehearing.  One of FERC's major changes was to allow a seller that has been presumed to have market power in the short-term to continue to show that it does not have market power, and thus may continue to charge market-based rates, with respect to its long-term contracts.  To do so, a seller is required to show that the buyer has other viable alternatives to purchasing power under the contract.  Additionally, with respect to FERC's affiliate restrictions, FERC granted rehearing on its adoption of a prohibition on two-way information sharing between market-based rate sellers and affiliated franchised public utilities with captive customers, determining instead that to adopt a one-way prohibition, i.e., the utility may not provide information to the market-based rate seller.  A few FERC's other notable clarifications included:

• FERC clarified that sellers may make use of ISO/RTO mitigation and/or market monitoring in order to show they do not possess market power and that such mitigation and monitoring will be presumed to be sufficient to address market power concerns, although other parties may present evidence otherwise. 

• FERC made certain clarifying changes with respect to the horizontal market power analysis, which examines whether a seller has generation market power in generation.  In particular, FERC clarified the data that it will rely upon in this analysis.  FERC generally affirmed its decision to rely solely on historical data to determine whether a seller has market power.  However, FERC conceded that it will consider, on a case-by-case basis, "clear and compelling evidence" that certain changes in relevant geographic markets should be taken into account.  Additionally, FERC also provided several clarifications to the transmission import studies that sellers must provide to account for uncommitted generation capacity in their relevant markets.

• FERC clarified that sellers are not required to report on firm transmission rights or congestion contracts (collectively, FTRs) as part of their analyses of their vertical market power, which examines whether a seller has market power with respect to transmission or can erect other barriers to entry.

• FERC codified definitions of "affiliate" and "captive customers" in its regulations, and clarified that the affiliate restrictions in its regulations generally supersede prior "codes of conduct."

Standards of Conduct Proposal Retreats from Structural to Functional Separation

A recent FERC Standard of Conduct rulemaking proposal retreats from its Order 2004 expansion of the standards of conduct, expressly finding that expansion too complex and unworkable.  FERC proposes a return to its 1990s vintage functional separation model of Order 497 (natural gas) and Order 889 (electric power), eliminating both Order 2004's concept of "Energy Affiliates" and its emphasis on corporate separation.  FERC concludes that returning to mere functional separation will encourage compliance by making the rules clearer, which the agency indicates is necessary in light of the new penalty regime of the Energy Policy Act of 2005 (EPAct 2005).  Comments on the proposed rule must be filed with FERC by May 12. 

In retreating to functional (from structural) separation, the proposal rulemaking appears to validate vertically integrated utilities by conceding that Order 2004 was hindering the advantages that accrue from vertical integration.  Nevertheless, the agency seems to be adrift between acknowledgment of the planning and integration advantages of the historical utility model and distrust of the  non-competitive characteristics of that model.  

Specifically, the proposed Standard of Conduct reform would implement:  

(1)  An “independent functioning rule” that defines the two groups of employees — “transmission function" and "marketing function" — who must function independently.  This division is based on what the employees do, not where they are employed.  Employees not directly engaged in transmission or marketing -- for example attorneys, accountants, and certain supervisors -- will not have their functions constrained by the proposed rule.   

(2)  A “no-conduit rule” to ensure independent functioning by prohibiting transmission function employees from communicating non-public transmission-related information with marketing function employees.  The no-conduit rule bars both communicating and receiving non-public transmission information, and everyone, regardless of function, is prohibited from being a conduit.   

(3)  A “transparency rule” to help detect, correct, and sanction violations of the independent functioning and no-conduit rules.  Whenever information is communicated in violation of the independent functioning or no-conduit rules, then, as provided in the current rules, the transmission function employee must immediately post that information on OASIS.  In addition, any interaction of transmission and marketing function employees would have to be contemporaneously recorded (handwritten notes may suffice) and made available to FERC on request, so the agency can monitor compliance with the rules.     

Unclear from the transparency rule is whether the damage of an improper disclosure of non-public transmission information can be undone.  Penalties for violations would remain unchanged from those enacted under EPAct 2005.

FERC Proposes Sundry Changes to Organized Power Market Rules

In a new rulemaking, the Federal Energy Regulatory Commission (FERC) has resisted pressure from various groups to examine the foundations of organized wholesale power markets administered by RTOs and ISOs, and instead proposes various tweaks to the rules in these markets. 

FERC rejected the calls by the American Public Power Association and others who have argued that organized power markets are failing to produce just and reasonable rates and that FERC should engage in fundamental reform of RTOs and ISO.  Instead, FERC focused its proposals on areas where it stated that improvements were supported by the law, facts and economic theory, but which have also been high-profile of late, whether due to advocacy by individual Commissioners (such as demand response) or because of bitter disputes within or about RTOs (such as market monitoring).  The specific proposals fall into four categories.

          Demand Response

o        Require RTOs and ISOs to accept bids from demand response resources in their markets for certain ancillary services comparable to other resources.

o        During a system emergency, require RTOs and ISOs to eliminate a charge to a buyer for taking less energy in the real-time market than it purchased in the day-ahead market.

o        Require RTOs and ISOs to permit an aggregator of retail customers to bid demand response on behalf of retail customers.

o        Modify market rules to allow market-clearing prices, during a period of operating reserve shortage, to reach a level that rebalances supply and demand so as to maintain reliability while providing sufficient provisions for mitigating market power.

Long-term Power Contracting

o        Require RTOs and ISOs to dedicate a portion of their websites for market participants to post offers to buy or sell power on a long-term basis.

Improved Market Monitoring

o        Require each RTO and ISO to provide its Market Monitoring Unit (MMU) with access to market data, resources and personnel necessary to carry out its duties.

o        Require the MMU to report directly to the RTO or ISO board.

o        Expand the list of recipients who would receive MMU recommendations regarding rule and tariff changes, and broaden the scope of behavior reported to FERC.

o        Remove the MMU from tariff administration, including mitigation, and require each RTO and ISO to include in its tariff ethics standards for MMU employees.

o        Expand dissemination of MMU market information to a broader constituency, with more frequent reports.

Responsiveness to Customers and Stakeholders

o        Adopt principles for RTOs and ISOs to ensure inclusiveness, fairness in balancing diverse interests, representation of minority positions, and ongoing responsiveness.

Comments on the proposed rules are due April 21.  In addition to the proposed reforms, FERC also ordered a technical conference to be held to consider proposals for modifying the design of organized markets, as well as a separate technical conference to discuss barriers to demand response in organized markets.

FERC Takes Action to Prevent Cross-Subsidization between Affiliates

FERC continues to tweak its rules regarding mergers and acquisitions under section 203 of the Federal Power Act (FPA), issuing new regulations that impose restrictions on affiliate transactions between certain public utilities and their unregulated affiliates.  FERC explained that it intends to fill a perceived regulatory gap in its current affiliate sales rules, and stated that this final rule, combined with an order issued the same day allowing for grants of blanket authorization for a public utility to dispose of voting securities, marks the completion of the "initial implementation" of the rules governing transactions conducted under section 203. 

Order No. 707 extends the affiliate transaction restrictions already in place for entities with market-based rates and utilities requesting merger approval to franchised public utilities that have captive customers or that own or provide transmission service over jurisdictional transmission facilities.  Under the new rules, wholesale sales of power between such public utilities and power sales affiliates with market-based rate authority will require FERC approval.  In addition, such a public utility that sells non-power goods and services to an affiliate with market-based rate authority or an unregulated affiliate will be required to do so at a price that is the higher of either cost or market price.  Lastly, a public utility subject to the rules will not be permitted to purchase non-power goods or services from an affiliate at a price above market price, except that the public utility cannot receive non-power goods and services from a centralized service company above cost. 

Revised Contents of Sellers' Market-Based Rate Tariffs Clarified

FERC Tweaks Open-Access Reforms in Order No. 890-A

In late December FERC issued Order No. 890-A, clarifying and modifying the reforms it made in Order No. 890 to open-access transmission requirements originally established by Order Nos. 888 and 889 and revising the associated pro forma open access transmission tariff. 

In the primary clarifications and modifications, FERC:

• affirmed a tiered approach to calculating energy and generator imbalance charges, while revising the calculation itself:  imbalance charges should be based on the last 10 MW dispatched by the transmission provider for any purpose, rather than the last 10 MW dispatched to serve native load;
• affirmed lifting the price cap on reassignments of transmission capacity for all transmission customers through October 2010 (though the price cap lift may be extended based on a required FERC staff report due in May 2010);
• clarified that the control area of an off-system resource must be identified before it can qualify as a "network" resource, but deferred revising the minimum lead time for undesigating network resources; and
• clarified posting requirements related to processing of service requests and the time frame for implementation of transmission rollover rights reforms. 

As with Order No. 890, transmission providers must submit compliance filings to incorporate the modifications contained in Order No. 890-A—within 60 days of the order's publication in the Federal Register for non-RTO/ISO transmission providers whose facilities are not within an RTO/ISO footprint, and within 90 days for RTO/ISO transmission providers.

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.

FERC Makes Good on Rate Incentive Promises to Transmission Developers

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

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

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

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

FERC Finds PJM Not in Violation of Tariff in Months-Long Dispute with Customers over Independence of Market Monitor

In response to PJM Interconnection, Inc.'s (PJM) Offer of Settlement to resolve its much-publicized  dispute regarding the independence of PJM's Market Monitoring Unit (MMU) and allegations of tariff violations, interested parties on August 22 gave the Federal Energy Regulatory Commission (FERC)  a wide range of options to pursue in response to the Offer of Settlement, including: (1) setting the dispute for evidentiary hearing; (2) invoking settlement judge procedures; or (3) postponing action on the matter pending the agency’s action on the Advanced Notice of Proposed Rulemaking's goal to develop industry standards for the MMU structure. 

On September 20 FERC concluded that there was no evidence that PJM violated its tariff; thus no hearing was necessary.  Nevertheless, FERC ruled that the evidence was more than sufficient to demonstrate that the PJM MMU reporting requirements are unjust and unreasonable.  While the MMU before was under an "unusual degree of supervision" by PJM management, FERC directed in its order that, whatever other conclusion the parties may reach during settlement proceedings, the resolution must include provisions that the MMU report solely to the PJM Board or an independent committee of the Board.   Commissioner Suedeen Kelly noted in her statements that more specific tariff provisions are needed to promote a stronger working relationship between the MMU and its overseer and to engender confidence in market operations.

In its September 20 Order and Commission open meeting, FERC acknowledged and commended the complainants and Dr. Joseph Bowring for bringing this important matter to the Commission's attention, commended PJM Board's prompt and positive actions in promoting settlement discussions with its Offer of Settlement, and expressed its opinion that "a consensual resolution is most likely to restore confidence in the efficient, impartial and competitive operation of PJM's markets and in the monitoring of those markets."  Commissioner Jon Wellinghoff added that the pending rulemaking will help define the role of an MMU, but cautioned that it is PJM itself, in the settlement procedures with customers, that can best restore confidence in the markets PJM administers.  If not, then the agency made clear it is ready to step in and resolve structural and functional issues surrounding the PJM MMU.

Southeastern Group Undertakes Regional Transmission Planning

A group of utilities in the southeast ― where utilities have to date resisted forming regional transmission organizations ― have announced a proposal to develop an interregional transmission planning process.  Under the plan to be released September 14, the utilities will work jointly to collect data, coordinate planning assumptions, and address stakeholder study requests.  The coordinated efforts will provide a centralized information source for transmission users, who will no longer have to consult each transmission owner separately.  The effort answers FERC's Order No. 890, which mandated broader regional coordination of transmission planning. 

Involved in the efforts are several major utilities, including Duke Energy Carolinas, Entergy, Progress Energy Carolinas, South Carolina Electric & Gas, Southern Company, and the Tennessee Valley Authority, as well as a number of municipal transmission providers and electric coops.  The effort will build upon a few small regional planning groups that already exist in areas of the southeast, such as the North Carolina Transmission Planning Cooperative, but will allow broader information sharing and cooperation across the entire region.

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 Tweaks, Codifies Market-Based Rate Program

After prolonged deliberations on its wholesale market-based rate program, FERC issued its Final Rule on the matter June 21, 2007.  The 670-page rule will become effective sometime in late August or early September ― 60 days after its publication in the Federal Register. 

Notably, in the Final Rule:

• As proposed in last year's Notice of Proposed Rulemaking (NOPR), FERC transformed its four-prong market power analysis into a more traditional horizontal and vertical market power analysis.  The "horizontal" analysis asks whether sellers have market power in generation, while the "vertical" analysis asks whether sellers have market power in transmission or can erect other entry barriers.  FERC codified restrictions on affiliate transactions ― the former fourth prong ― and will require tariff provisions that require market-based rate sellers to abide by these regulations.
• FERC divided sellers into two categories—Category 1 sellers, who are power marketers or power producers that own or control less than 500 MW of generation in a region and are not affiliated with franchised public utilities, and Category 2 sellers, who are all other sellers.  Category 1 sellers are no longer required to file triennial market power analyses, but instead FERC will monitor their market positions through change-in-status filings and electronic quarterly reports (both of which continue to be required of all sellers).
• FERC will now review sellers' triennial market power analyses on a rotating regional basis.  To facilitate its review, FERC divided the country into six regions, and will review two regions per year according to a schedule provided in Appendix D to the Final Rule.
• FERC retained its existing indicative screens for generation market power.  The "wholesale market share screen" measures a seller's share of the relevant geographic market; the "pivotal supplier screen" determines whether a seller is pivotal in the market and unilaterally can raise prices.  If a seller fails either screen, FERC presumes market power, which the seller can either attempt to refute or acquiesce in mitigation.
• FERC rescinded the exemption for generation facilities constructed after July 9, 1996.  Generators had argued the exemption was needed to encourage construction of new generation, but FERC disagreed, finding that as time goes on, more and more generating units would be subject to the exemption, making detection of market power more difficult.
• FERC provided guidance on identifying who "controls" generation for purposes of the both generation market power analysis and the change-in-status reporting obligation.  FERC declined to adopt generic presumptions of control, but instead will stick with a fact-specific analysis.  FERC's guiding principle is that if an entity can prevent generation from reaching a market, it "controls" that generation. 
• Transmission owners (and sellers affiliated with transmission owners) can continue to show they have mitigated transmission market power by operating under an open-access transmission tariff (OATT).  Although not automatic, FERC will now consider OATT violations as grounds for revocation of the seller's market-based rate authority so long as there is a "nexus" between the tariff violation and the market-based rate authority.  FERC generally will not revoke a seller's market-based rate authority for its transmission affiliate's tariff violation. 
• The newly codified affiliate restrictions continue to prohibit power sales between a franchised public utility with captive customers and affiliated power marketers with market-based rate authority (now known as "market-regulated power sales affiliates") without prior FERC approval.  
• The Final Rule modifies and codifies the existing "code of conduct" from market-based rate tariffs.  The regulations now specifically bar utilities from using third parties to circumvent the affiliate restrictions.  In addition, FERC created a specific exception to allow utilities to share with affiliates senior officers and directors, certain legal and administrative personnel, and field and technical personnel so long as these employees do not act as "conduits" for impermissible communications. 
• A seller found to have market power in one market, requiring mitigation in that market, will be allowed to sell at market-based rates into neighboring markets so long as it commits not to sell to an affiliate and have that affiliate sell it back into the mitigated area (so-called "ricochet" transactions). 
• FERC declined suggestions that it use the cost-based rates of the WSPP Agreement to mitigate market power.  Instead FERC determined that those rates may no longer be just and reasonable and convened an investigation into the WSPP Agreement in a separate docket. 
• FERC removed restrictions and posting requirements currently imposed on third-party sales of ancillary services, in the hopes of encouraging competitive ancillary services markets.
  

FERC Scrutinizes Organized Power Markets, but Proposes No Reforms for Now

Following a series of industry conferences on wholesale electricity markets, FERC issued an advanced notice of proposed rulemaking (ANOPR) aimed at exploring means of strengthening competition in organized power markets ― markets with spot energy sales and administered by regional transmission organizations (RTOs) or independent system operators (ISOs).  Public comments on the ANOPR will be due in mid- to late-August ― 45 days following publication in the Federal Register.

FERC is not aiming for a major redesign of RTO or ISO markets, but rather is focusing on four discrete issues on which the agency seeks advice:

• the role of demand response in organized markets, including possible rule changes to increase its use in times of emergency as well as through aggregation and for (or in lieu of ) ancillary services;  
• opportunities for long-term power contracting, including having the organized market operator serve as a clearing house for information on bilateral prospective bilateral deals;
• attributes of market monitors, including independence, enforcement authority, and reporting responsibility; and
• the responsiveness of RTOs and ISOs, in particular at the board level, to customers and other stakeholders.

Each of these issues relates to recent hot topics at the agency.  Commissioner Wellinghoff has become a vocal proponent of demand response.  An increasingly acrimonious dispute between PJM management and its market monitor has drawn attention to the role of market monitors, and in particular their independence.  The perceived remoteness of ISO and RTO boards has brought some calls for allowing market participants greater access to the boards.  And both energy users and project developers at times call for greater use of long-term contracts to stabilize prices.

After reviewing public comments on these topics, FERC will decide whether to issue a notice of proposed rulemaking to propose specific changes to its regulations governing power markets.

Market Monitor Continues Lobbing Shells at Defensive PJM Management

The recriminations between PJM management and its market monitor have reached a crescendo.  In a June 12 multi-volume response to FERC's investigation regarding PJM Interconnection's (PJM) alleged interference of its market monitoring unit (MMU), Dr. Joseph Bowring, PJM Market Monitor, supplemented allegations made in an April 5 statement that PJM management violated the MMU’s independence and compromised other objectives of the PJM tariff.  Among the specific allegations, Dr. Bowring charges that PJM management: (1) refused to prosecute a unit's exercise of market power that resulted in costs to market participants to the tune of $20 million; (2) pressured the MMU to modify its position on mitigating market power in the new RPM capacity market; (3) authorized confidential procedures that gave PJM management preferential review authority over MMU reports effectively modifying Attachment M to PJM's tariff, which contains PJM's Market Monitoring Plan; (4) ordered the Market Monitor to remove a central conclusion from its 2005 State of the Market Report; (5) sought to change or delay the release of four MMU reports from 2004 to the present. (6) ordered the MMU in 2005 not to post minutes of a recent Market Monitoring Advisory Committee (MMAC) meeting and in 2006 ordered the MMU to remove the discussion of a recent FERC Order regarding market monitoring form the MMAC meeting agenda; (7) prevented the MMU from analyzing the BGS auction for the New Jersey Public Utilities Commission in December 2006; and (8) replaced the Market Monitor with the VP of Markets at PJM as the Chairperson of the Cost Development Task Force, a group responsible for developing, reviewing, and recommending standard procedures for calculating costs of products or services for cost-based rates analysis .

Concurrently PJM submitted its own two-volume response to the FERC, dismissing Bowring’s criticisms.  Contrary to Dr. Bowring, PJM contends that “there is no factual basis for any claim that PJM has violated its tariff."  According to PJM, no one has alleged "that the MMU was ever prevented from performing any of its tariff-defined functions or reporting to the Commission any instances of market manipulation or other inappropriate conduct in the PJM markets."  Furthermore, PJM concluded that no evidence has been presented to demonstrate "that the market monitor was prevented from bringing to the Commission's attention matters of concern regarding the markets."  

Dr. Bowring also disclosed information he claimed points to PJM management's interference with MMU staffing, including targeting specific MMU employees for PJM Markets Division openings and threatening to eliminate MMU control over its data and data management.  According to PJM, however, it has provided the MMU with all appropriate staff to "carry out its tariff-defined functions," including maintaining its reliance on contract labor and adopting an especially aggressive and enhanced retention plan to encourage current MMU employees to remain with the MMU during the review period associated with the Complaint and this investigation.  

Regulators and market participants, particularly consumer groups, remain anxious about the MMU’s independence and effectiveness pending resolution of the charges and counter charges.

Arizona Regulators Reject Cross-Border Transmission Line

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

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

FERC to Investigate Claims of PJM Management Interference in Market Monitoring

Qualifying Facilities No Longer Generically Exempt from Reliability Standards

On May 18, FERC made good on its promise to extend reliability standards to Qualifying Facilities (QF).  Order No. 696 overhauls regulations governing small power production and cogeneration facilities by eliminating previous exemptions of QFs from compliance with section 215 of the Federal Power Act.  According to the final rule, FERC believes "there is not a meaningful distinction between QF and non-QF generators that warrants a generic exemption of QFs from reliability standards."  QF generators, FERC explained, affect the bulk-power systems as much as non-QF generators and should therefore be similarly subject to new mandatory reliability standards that become effective on June 4, 2007.  

Commenters during the Notice of Proposed Rulemaking process for Order No. 696 urged FERC to consider a number of factors in its evaluation.  FERC was not persuaded and denied generic exemptions, including exemptions for QFs below a certain size or ones serving only behind the meter load.  FERC instead directed that North American Electric Reliability Corporation (NERC) or Regional Entities could consider factors warranting specific exemptions when an individual QF is evaluated for registration (the general procedures for registration are outlined at Section 500 of NERC's Rules of Procedure).   FERC explained that, in this regard, Order No. 696 puts QFs and non-QFs on equal footing "to not be subject to reliability standards" since the registration process is designed to determine applicability of the standards on a case-by-case basis.  FERC also pointed out that QF's still have the opportunity to appeal to the agency if the QF believes its registration was in error.

FERC Signs Off on 83 Mandatory Reliability Rules

Putting into place for the first time mandatory standards to ensure reliability in the nation's electric transmission system, on March 16, FERC issued an order adopting 83 out of 107 reliability standards that were proposed by the North American Electric Reliability Corporation (NERC) last year.  Certified as the Electric Reliability Organization (ERO) contemplated in the Energy Policy Act of 2005, NERC will play a primary role in developing, monitoring, and enforcing the reliability standards.  Most of the standards take effect this summer; FERC rejected calls by some industry participants for a phase-in or transition period

FERC directed substantial changes to many of the standards, but approved them as mandatory and enforceable nonetheless.  NERC can iron out details through its stakeholder process, FERC advised.  Those standards that were not adopted were remanded back to NERC for further development or for NERC to provide additional information.  FERC declined to adopt a blanket waiver from the standards for small entities; rather, FERC approved the continued use of the existing NERC compliance registration process and Functional Model to register entities who must comply with the standards.  Under this process, NERC will register:  distribution providers or load-serving entities with a peak load of 25 MW or greater and are directly connected to the bulk electric system or that are responsible entities as part of a required demand management (load-shedding) program; individual generating units that are 20 megavolt-amperes (MVA) or greater; generating plants with an aggregate MVA above 75; and transmission owners and operators with 100 kV or higher facilities.

In a separate notice of proposed rulemaking issued the same day, FERC proposed to extend the reliability standards to Qualifying Facilities (QF) above 20 MW, despite the fact that QFs are exempt from most FERC regulation.  Comments in this proceeding are due April 17, 2007. 

Making Waves ― FERC Turns Attention to Ocean Power

The Federal Energy Regulatory Commission has put the spotlight on a lesser known but potentially valuable source of renewable energy by announcing an interim policy and inviting public comment on how to process preliminary permit applications for ocean energy: wave, current, and instream hydropower technologies.  The Commissioners expressed interest in promoting these technologies, but also concern about their reliability, environmental and safety implications, and commercial viability. 

While various other countries, including the United Kingdom, are more advanced in developing ocean energy, interest is growing in the U.S. and FERC has already issued several preliminary permits for ocean energy projects.  FERC’s jurisdiction extends from the same section of the Federal Power Act that controls licenses for hydroelectric dams.  A preliminary permit under the FPA gives the permit holder first priority in applying for a license for a project, but does not authorize construction. 

With more parties seeking preliminary permits and licenses, FERC chose to announce an interim policy to give applications strict scrutiny while seeking comment on alternative approaches, including moderate scrutiny or declining altogether to issue permits.  The stricter approach entails more scrutiny of permit applications and narrowing the scope of any permits that are granted, and is intended to promote competition and prevent applicants from site-banking, that is, reserving sites without an intent of developing them.  FERC has also asked for public comment on how it should enforce permits once they are issued. 

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.

FERC Tinkers on Transmission Investment Incentives

Responding to concerns raised by state regulators, FERC closed out 2006 by amending its rules intended to induce investment in new transmission infrastructure.  FERC issued the original rule last July pursuant to EPAct 2005 (and the new FPA § 219), which decried a shortage of transmission investments and directed FERC to develop transmission incentives.  The original rule identified rate perquisites available to applicants that meet certain criteria.  While the incentives remain available to a broad range of investors, demonstrating eligibility has become more demanding. 

First, FERC clarified that its "nexus" requirement ─ that incentives must be tailored to meet the particular risks faced by the applicant ─ will be applied strictly, and will not be satisfied in every case.  Routine investments in the ordinary course of expanding an applicant's transmission system, for example, would be less likely to meet the nexus test than new projects presenting special challenges and encountering uncertain risks.  As opposed to the original approach, where the nexus test was applied to each incentive requested, now an applicant must demonstrate that the total package of incentives being applied for is tailored to address the demonstrable risks or challenges it faces.  In beefing up its nexus requirement, however, FERC declined to adopt a "but for" test ─ but for the incentives, the project would not be built ─ due to the difficulty of satisfying such a test.   

FERC also emphasized that it will not routinely grant an incentive ROE, and that any ROE it does grant will not always fall at the "top" of the zone of reasonableness.  In addition to justifying a higher ROE under the nexus test, an applicant must also justify where within the zone of reasonableness the return should lie.  FERC will continue to allow petitions for declaratory order seeking a specific ROE.  Finally, the new rule reaffirms the availability of an ROE incentive to transcos and to utilities that join or remain in ISOs and RTOs.   

Finally, the new rule seeks to alleviate state concerns that rebuttable presumptions, contained in the original rule, that would consider certain projects eligible for incentives, would not adequately measure whether the project would improve reliability or decrease congestion, as required by the FPA.  While FERC maintained a rebuttable presumption that a project is eligible for incentives if it results from a fair and open regional-planning process, or received state construction approval, if those processes do not consider whether the project ensures reliability or reduces congestion, then the applicant must independently validate that the project meets those criteria. 

Guidance on FERC Assessment of Civil Penalties

In an attempt to show it means business regarding its enhanced authority to assess civil penalties under the Energy Policy Act of 2005 (EPAct 2005), on December 21, FERC issued a statement of administrative policy detailing the procedures it will use in assessing civil penalties, but emphasized the continuing importance of negotiated settlements, which are not subject to the procedures.  In EPAct 2005, Congress authorized FERC to impose penalties of up to $1 million per day per violation, for violations of the statutes that FERC administers —  Parts I and II of the Federal Power Act (FPA), the Natural Gas Act (NGA), and the Natural Gas Policy Act (NGPA) —  and the rules, regulations, and orders issued pursuant to those statutes.  The December 21 policy statement complements a prior Policy Statement on Enforcement, issued in October 2005, which discussed the factors FERC would take into account in responding to violations and determining appropriate remedies, and emphasized the need for companies to create an internal "culture of compliance" and self-report violations.  [See FERC Explains Its Policy on New Penalty Enforcement.] 

FERC Chair Joseph Kelliher emphasized that FERC generally prefers settlement to litigation, and predicted that the majority of penalty decisions will likely be made through negotiated settlements.  Consequently, it is not entirely clear how often the civil penalty procedures will be put to use.  To the extent they are put to use, FERC explained that it will first provide notice describing a violation and the proposed penalty.  The targeted person or company will have a chance to respond and explain why the penalty should not be assessed.  Following the target's response or explanation:

• For violations of Part I of the FPA, if a final compliance order has been violated, then FERC will conduct an administrative hearing before an administrative law judge (ALJ); if no final compliance order has been violated, then an entity may choose between the ALJ hearing and an immediate assessment of the proposed penalty.
• For violations of Part II of the FPA, the entity may choose between a hearing before an ALJ or an immediate penalty assessment. 
• For violations of the NGA, FERC will require either a paper hearing or a hearing before an ALJ, depending on the circumstances involved, and will issue an order after considering an entity's response.  
• Finally, for violations of the NGPA, FERC explained that the NGPA does not provide for an on-the-record administrative hearing; rather, FERC will assess the penalties after considering the facts.

Once FERC issues a final order assessing the appeal, if the entity does not voluntarily pay the penalty within 60 days, FERC can institute a collection action in the appropriate United States district court.  At this point, proposed penalties are subject to de novo review by the district courts.  Entities assessed penalties may appeal final Commission decisions by following the usual appeal procedures, i.e., by filing a petition for review within the appropriate time to a U.S. Court of Appeal.

Court Decision Likely to Roll Back Applicability of Standards of Conduct for Both Pipeline and Utility Affiliates

A three-judge panel of the U.S. Court of Appeals for the District of Columbia Circuit in a November 17 ruling struck down a divided (2-1) FERC expansion of the applicability of Standards of Conduct that prohibit interstate natural gas pipelines and electric transmission grid owners/operators from sharing non-public pipeline or transmission- grid information with affiliates.  Before the November 2003 expansion, the Standards applied only to the marketing affiliates of the pipes and transmission systems; after, it applied to all “energy affiliates.”   Responding to natural gas pipelines’ complaints that the expanded applicability would cost the industry an estimated $240 million annually and was based on no evidence of preferential treatment of “energy affiliates,” the panel held that FERC’s “vast expan[sion] of the reach of the Standards,” based only on a theoretical possibility of affiliate favoritism, violated the Administrative Procedures Act requirement of reasoned decisionmaking.  FERC has 45 days to petition for rehearing, barring which the case will be remanded to the agency.  On remand, according to panel, FERC may (1) confine the Standards to market affiliates — those who actually buy and sell the transmission capacity of the pipes and wires, (2)  develop a factual record of abuse that would justify the expanded applicability, or (3) try to develop support for the expansion based on a “theoretical threat of abuse.”  The panel cautioned that the theoretical approach would likely fail.

As precedent, the panel decision reigns in the Standards as applied only to “energy affiliates” of natural gas pipelines, such as producers, gatherers, processors and risk managers, and not to the comparable affiliates of electric transmission system operators.  But this distinction is likely to vanish on remand since the agency prefers uniform rules for accessing natural gas pipelines and electric transmission systems to the extent possible.  Moreover, since one of the most vocal opponents of the expansion from early in its genesis, then-Commissioner Joe Kelliher, is now the FERC Chair, odds are that the agency won’t seek rehearing and, instead will retreat on remand to its original application of the Standards only to marketing affiliates of the pipes and grid operators.

Federal-State Tension Accompanies FERC's Final Rule on Backstop Transmission Siting

FERC has issued a Final Rule establishing procedures that it will use for permitting construction of transmission lines in National Interest Electric Transmission Corridors (NIET) corridors.  In EPAct 2005, Congress authorized the Department of Energy to designate NIET corridors in congested areas of the high-voltage power grid.  Congress, in turn, granted FERC new authority to permit construction of transmission lines within designated NIET corridors in instances when a state permitting authority either has not acted or is unable to act on an application for siting authority.  The federal permit is controversial because it confers on the permit recipient a new federal right of eminent domain to condemn private property for rights of way ― a right previously available only from state and local authorities.   

Most elements of the Final Rule track an earlier proposed rule.  FERC must find that the proposed facilities would meet five basic criteria, including reducing congestion and enhancing energy independence.  Applicants for permits must file Participation Plans to maximize stakeholder contributions, and engage in a prefiling process at FERC.  The Final Rule does change this prefiling process.  Under the proposed rule, while an applicant was required to wait one year after applying to state or local authorities before filing its permit application at FERC, it could nevertheless begin the prefiling activities at FERC earlier, concurrent with ongoing state siting proceedings.  In response to loud outcry from state regulatory agencies concerned that FERC would effectively commandeer ongoing state review of transmission projects in NIET corridors, the Final Rule now prohibits both filing an application and initiating prefiling activities at FERC before one year following the beginning of state proceedings.   

Another controversial provision related to the states was resolved in favor of a stronger FERC authority.  EPAct allows FERC to grant a permit where a state has "withheld approval" of transmission facilities.  FERC determined that "withheld approval" applies both to where states deny permits and where states fail to act on permits.  While FERC Chair Kelliher supported this decision, calling it a reasonable interpretation, Commissioner Kelly disagreed, arguing that the interpretation leaves states with little choice: either permit the facilities or FERC will do it for you.  Kelliher pointed out that FERC could have legally implemented a process that ran simultaneously with state processes, but did not do so.  The practical result of this middle ground, however, is a lengthier permitting process – Kelliher admitted that projects that fail to win state siting approval face another 20 months of regulatory review at FERC. 

Industry and Regulators Aim to Synchronize Natural Gas Supply and Power Markets

During a northeastern cold spell in January 2004, natural gas-fired electric generators had significant problems obtaining adequate fuel supplies in time to participate in the ISO New England market and provide emergency power.  This experience caused the industry and its regulators to question whether the ISO/RTO scheduling and market-clearing practices are compatible with the scheduling of natural gas purchases and transportation. 

The North American Energy Standards Board (NAESB) established a Gas-Electric Coordination Task Force to look at the problem.  The Task Force identified several features of ISO/RTO tariffs that discouraged gas-fired generators from participating in ISO/RTO markets during periods of heightened demand or supply interruptions.  At the top of the list were discrepancies between gas nomination timelines and ISO/RTO market clearing timelines.  For example, a generator may submit an offer to sell into an ISO/RTO organized market based on prevailing natural gas prices, but by the time the ISO or RTO accepts the offer and clears the market, during extreme conditions, gas prices may have increased dramatically.  ISO/RTO market rules generally do not provide the flexibility for a generator to increase its offer price in response to the increased natural gas price.  Exposure to that risk can cause a gas-fired generator to refrain form offering its output at all during periods of heightened demand when that generation is needed most.  In an attempt to avoid these disincentives, and to increase coordination between the gas and electric markets, FERC recently directed each ISO or RTO by January 16, 2007, either to propose revisions to its offering and market clearing deadlines or to explain why such revisions are not needed.

One of the NAESB Task Force's reports also included recommended standards for natural gas transmission service providers' communications with electric power generators and independent transmission system operators.  Noting that improved communication would help address, but would not completely resolve, the coordination difficulties, FERC proposed to adopt these communication standards into its regulations in a recent notice of proposed rulemaking, on which public comments are due December 18, 2006.

FERC to Electric Utilities and Qualifying Facilities: Presume This!

To address the energy shortages of the 1970s, the Public Utility Regulatory Policies Act was enacted to empower qualifying cogenerators or small power producers (from renewables) ― qualifying facilities or QFs ― to "put" their electric generation to an interconnected electric utility and charge the utility an avoided-cost rate, and also demand backup power from the utility.  Because the avoided-cost rate was often locked in at relatively high prices, utilities for years sough repeal or amendment of the "put."  In the Energy Policy Act of  2005, Congress agreed and directed FERC to end prospectively the "put" for post-October 8, 2005, power sales by QFs that are found to enjoy nondiscriminatory market access.

Responding to this directive, FERC originally proposed to end generically the "put" for all electric utilities participating in independent transmission system operations that offer auction-based day-ahead and real-time energy markets ― the so-called Day 2 markets of ISO New England, the Midwest ISO, the New York ISO and the PJM Interconnection.  But in an October 20 ruling, the agency retreated to a more nuanced approach that creates rebuttable presumptions as to when a QF enjoys nondiscriminatory market access and when it doesn't.

One presumption is that QFs of 20 megawatts or less do not have nondiscriminatory market access.  But for a QF larger than 20 megawatts the "put" presumptively ends if, on a utility purchaser's application, FERC finds the QF is connected to an open-access transmission system that can access a Day 2 market, a Day 1 (an auction-based real-time market only) RTO that also includes sufficiently competitive markets, or the functional equivalent of these.  New England, the Midwest, New York and PJM qualify as Day 2; pending implementation of scheduled new market redesigns, SPP and the California ISO will remain Day 1 (leaving to case-by-case determinations the question whether the markets are sufficiently competitive); and FERC deemed ERCOT a functional equivalent.  The larger QFs can rebut the presumption of nondiscriminatory access by showing that characteristics of how they operate ― for example erratic cogeneration available for sale or non-dispatchability, or where they operate ― for examples in proximity to a binding transmission constraint ― preclude market access.

The new rule provides not only for termination of the "put" in circumstances where a QF fails to rebut the presumption of nondiscriminatory market access, but also for its reinstatement where a QF later shows that the nondiscriminatory market access it once enjoyed is no longer accessible.   

FERC Addresses Critical Energy Infrastructure Information

Five years after introducing measures that would limit access to information about the nation's energy infrastructure, FERC is again reassessing what protections and procedures are necessary for both protecting and reasonably disseminating this information.  On September 21, FERC issued a final rule and a notice of proposed rulemaking (NOPR), addressing critical energy infrastructure information (CEII), which is protected by FERC's regulations.  The issuances highlight the balancing act FERC has had to play in protecting sensitive information and ensuring the safety of energy facilities, on the one hand, and in recognizing the due process rights of interested persons who want to participate in FERC regulatory proceedings, on the other.  To be considered, public comments on the NOPR must be received by November 2, 2006.

FERC's final rule, Order No. 683, streamlined the requirements interested parties must satisfy in order to obtain CEII, and included the requirement that requesting parties submit a signed non-disclosure agreement along with a request for CEII.  FERC also addressed the problem that companies filing information with FERC tend to "over-designate"  information as C