First NERC Penalty Notices Suggest Focus on Enforcement

FERC Blesses Midwest ISO Plan for Resource Adequacy

The Federal Energy Regulatory Commission has conditionally accepted a Midwest Independent Transmission System Operator (Midwest ISO) plan for ensuring long-term resource adequacy in the RTO’s 15-state territory.  Most other RTOs and ISOs have spent years grappling with how to ensure sufficient capacity is available to meet peak demand, and contentious FERC proceedings have led to different market models in NYISO, PJM, and ISO-NE.  FERC directed MISO to develop its own resource adequacy plan after having operated for years without one.   The first planning year under the resource adequac plan will start June 2009.

MISO’s responsibilities under the new plan will include determining capacity obligations, monitoring compliance, and assessing penalties to deficient load servers.  Unlike the PJM, ISO-NE, and NYISO models, the MISO plan does not entail a centralized capacity market, but does require any load server in the Midwest ISO region to maintain access to sufficient planning resources, whether generation or demand response.  

New Reliability Standards for Cyber Security and Facilities Design Adopted for North American Grid

FERC in a January 17 order approved eight new Reliability Standards developed by the North American Electric Reliability Corporation (NERC) regarding Cyber Security (CIP).  These approvals come on the heels of FERC's approval last month of three new standards relating to Facilities Design, Connections and Maintenance (FAC).  These authorizations mark two more bundles in a long series of standards developed by NERC as the FERC-designated Electric Reliability Organization. 

The January 17 FERC-approved Cyber Security standards include CIP-002-1 – Critical Cyber Asset Identification, CIP-003-1 – Security Management Controls, CIP-004-1 – Personnel and Training, CIP-005-1 – Electronic Security Perimeter(s), CIP-006-1 – Physical Security of Critical Cyber Assets, CIP-007-1 – Systems Security Management, CIP-008-1 – Incident Reporting and Response Planning and CIP-009-1 – Recovery Plans for Critical Cyber Assets.  The standards require "owners and operators of the bulk power system to establish policies, plans and procedures to safeguard physical and electronic access to control systems, to train personnel on security matters, to report security incidents, and to be prepared to recover from a cyber incident."  

FERC Chairman Joseph Kelliher indicated that while approving these standards, FERC was also directing NERC to make modifications relating to "reasonable business judgment and acceptance of risk" that "will strengthen the reliability standards . . . and improve [the Nation's] defenses against cyber threats."  In addition, FERC directed NERC to examine "a new framework of accountability surrounding exceptions based on technical feasibility" and to monitor the development and implementation of cyber security standards by the National Institute of Standards and Technology.  

Last month's approval of three new mandatory standards for Facilities Design, Connections and Maintenance (FAC) require planning authorities and reliability coordinators to establish methodologies to determine system operating limits for the bulk-power system in the planning and operation arenas.  

FAC-010-1 requires the planning authority to develop methodology that is "applicable to the planning time horizon, does not exceed facility ratings, and includes a description of how to identify the subset of [System Operating Limits] that qualify as [interconnection reliability operating limits]."  FAC-011-1 imposes the same general directives on the reliability coordinator.  FAC-014-1 requires reliability coordinators, planning authorities, transmission planners, and transmission operators to "develop and communicate System Operating Limits in accordance with FAC-010-1 and FAC-011-1."  In addition, FAC-014-1 requires that System Operating Limits are provided to entities with a reliability-related need. 

No Common Denominator on Capacity Markets

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

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

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

FERC, NERC Flesh Out ERO Operations, Penalties, Disclosures & Budgets

Five months after FERC authorized mandatory Reliability Standards to go into effect last June, it  is now sorting out to whom the Standards apply.  It is also slogging through issues of organization and management of NERC as the Electric Reliability Organization (ERO).   

Application of Reliability Standards 

Among the issues being debated are when a participant on the electric power grid sufficiently impacts grid operations to require registration with a Regional Entity and to what extent pure power marketers should be subject to Reliability Standards.

On October 18, 2007, FERC remanded to NERC its determinations that the Florida Reliability Coordinating Council properly included Mosaic Fertilizer, LLC and City of Tampa, Florida on its compliance registry.  Mosaic and Tampa appealed their registration to NERC and then to FERC.  FERC determined that NERC did not adequately show that the either was properly registered and, in any event, failed to respond adequately to arguments against registration. 

Penalties, Budget & Business Plan

The back-and-forth between FERC and NERC to define the ERO continues.  FERC issued an order October 18 directing NERC to clarify that the maximum penalty that it or a Regional Entity could impose for violation of a Reliability Standard is $1 million per violation, per day, consistent with the Federal Power Act, and to clarify how it would address specific situations that do not fit the one-violation, one-day fact pattern.  FERC generally accepted NERC's compliance filing on these issues, and directed small follow-up clarifications to the proposed sanctions language.  Alternative situations will be handled as follows:  repeated violations during a single day may result in a $1 million penalty  for each violation; NERC will amend Reliability Standards requirements measured as an average over time to specify the minimum period in which a violation could occur and how to determine when a violation arises; and for requirements of Reliability Standards that involve discrete events that are measured only periodically or are reported by exception, a violation arises when that event occurs and continues until it is cured.

In response to FERC's request that NERC describe how it will process requests for information, NERC clarified that the requestor must explain the need for the information and how it will be used.  NERC clarified that requests would be met so long as they were not frivolous, too-broad or unreasonable, and that the requestor's description of the anticipated use of the information would not limit the use of the information once disclosed.  FERC accepted these clarifications.  NERC also proposed to include a new section 1600 in its rules of procedure, to establish a process for NERC or Regional Entities to issue requests for data or information needed to fulfill their obligations.  

Also on October 18, 2007, FERC accepted NERC's proposed budget and business plan for 2008, including the budgets and business plans for each of the eight regional entities and the Western Interconnection Regional Advisory Body.  FERC noted that it plans to compare proposed budgets to actual expenditures, and will require NERC to provide a true-up for itself and each Regional Entity by April 1 of each year.  FERC also directed several compliance filings with regard to the Regional Entities' proposed budgets and business plans, focusing especially on inconsistencies between the Regional Entities' income statements and their business plans, and on its concern about the adequacy of separation and independence of the SPP Regional Entity from the SPP RTO.

Demand Response Developments: Promotion and Quantification

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

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

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

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

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

Duquesne Complaint Dismissed in Time for October 1 PJM Capacity Auction

The Federal Energy Regulatory Commission (FERC) dismissed Duquesne Light Company's (Duquesne) complaint seeking to avoid participating in  the PJM Interconnection's (PJM)  scheduled October 1 Reliability Pricing Model (RPM) auction in which load servers are obligated to secure capacity reserves, and ultimately to withdraw from the regional transmission organization.

Among many deficiencies in Duquesne's complaint, FERC found that Duquesne failed to address "'the practical, operational, or other nonfinancial impacts . . . including, where applicable, the environmental, safety or reliability impacts of' PJM's exclusion of the Duquesne Zone load from the October 1 auction," as well as how reliability will be maintained if the load in its Zone is removed from the October 1 auction.

Importantly, FERC relied on both the PJM Transmission Owners' Agreement and the Reliability Assurance Agreement provisions that require that a load-serving entity seeking to withdraw from PJM must make a filing with the Commission under section 205 before that withdrawal becomes effective.  FERC ultimately found that it was the "necessary section 205 filing, rather than this complaint requesting relief on an emergency basis, [that] is the appropriate vehicle for resolving all of the issues related to Duquesne's withdrawal from PJM."  It remains to be seen whether Duquesne will make the withdrawal filing since avoiding participation in the October 1 RPM auction is no longer a motivating consideration.

Rising Capacity Costs Prompt Duquesne Light to Divorce PJM

Duqesne Light Company wants to sever ties with the PJM Interconnection regional transmission organization (RTO).  Duquesne cites the increased capacity costs resulting from PJM’s implementation of the new reliability pricing model (RPM) for capacity sales, and is asking FERC to allow it to withdraw before PJM’s next capacity auction that will cover 2009 deliveries.  PJM responded that it is too late to exclude Duquesne from that auction, and that numerous questions must be resolved, including how Duquesne would resolve it reliability requirements.  A number of others have likewise objected to Duquesne’s precipitous withdrawal. 

Duquesne has stated it intends to join the Midwest ISO, which it already borders from its location in Western Pennsylvania.  Of course, PJM is not the only organized market where member dissatisfaction has led to withdrawal.  Stating that a cost-benefit analysis compelled the conclusion, Louisville Gas & Electric and Kentucky Utilities left the Midwest ISO in 2006.  And due to unhappiness with capacity markets that mirror Duquesne’s complaint against PJM, the State of Maine has threatened to withdraw from NEPOOL and thereby ISO-New England. 

While utility membership in organized markets is voluntary, it is clear that withdrawals raise vexing issues of allocating costs to a shrunken customer base as well as long-term planning.  With the complex RPM market finally in operation, market participants are already being forced to examine a new twist, the impact of a utility’s withdrawal on capacity procurement and reliability.

House Weighs Federal "Smart Grid" and Other Efficiency Enhancements

Among energy initiatives that Congress is considering this summer, one would highlight smart grid technology on the national stage.  In hopes of not only making the U.S. grid more reliable and efficient, but also more secure and independent—often-used phrases in Congressional energy circles—the Energy and Commerce Committee approved one measure that would establish a federal Grid Modernization Commission to implement smart grid technologies. 

The proposed nine-member Commission would monitor smart grid developments, develop common standards and protocols for smart grid technologies, identify barriers to implementation and propose solutions, coordinate federal and state agencies to implement smart grid efforts, and report to Congress biennially on the progress made in modernizing the electric grid system. 

The measure would also create a federal matching grant program, funded with $250 million for 2008 and $500 million for each of the years 2009-2012, to reimburse one quarter of the costs of certain smart grid investments.  The measure would amend section 111(d) of the Public Utility Regulatory Policies Act of 1978 to require states to consider regulatory standards that would allow utilities to include smart grid investments in rates, "decouple" utility profits from the volume of electricity sold, and require utilities to make time-sensitive supply, cost, price, and other information available to consumers to inform their use of smart grid technologies and demand response. 

Finally, the measure also would amend the National Energy Conservation Policy Act to require federal agencies to reduce their peak electricity consumption by 2 percent each year for 10 years, or make that percentage available as demand response, and report to Congress on the results.  The Grid Modernization Commission would also be tasked with developing a national action plan to achieve demand response potential in the U.S.

Qualifying Facilities Seek Rehearing of Reliability Standards Applicability

The Cogeneration Association of California and the Energy Producers and Users Coalition and the Midland Cogeneration Venture Limited Partnership have sought rehearing of FERC's Order No. 696, which overhauled regulations governing small power production and cogeneration by eliminating previous exemptions of qualifying facilities (QFs) from compliance with the mandatory reliability standards of new section 215 of the Federal Power Act.

The rehearing requests contend that Order No. 696 discriminates against QFs by neglecting to assure QFs that they will be able to recover their costs of complying with the new standards.  In contrast, FERC did provide that assurance to traditional public utilities that own generation.  "[B]y saddling [QFs] with significant new reliability compliance costs without also providing a cost recovery mechanism," argue the challengers, the Commission is actually discouraging energy efficient cogeneration and renewable small power production technologies that FERC otherwise has a duty to promote under the Public Utility Regulatory Policies Act of 1978, section 210 of the Federal Power Act, and the Energy Policy Act of 2005.

The parties to the rehearing requests represent the interests of approximately 20 individual companies, including the likes of the El Paso Corporation,  BP West Coast Products, Inc., Chevron U.S.A. Inc., ConocoPhillips Company, ExxonMobil Power and Gas Services Inc., Shell Oil Products US, Kern River Cogeneration Company, Salinas River Cogeneration Company, and other additional small QFs in California.

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 Approves Violation Risk Factors for NERC Reliability Standards

With only days to spare before Reliability Standards go into effect on June 1, FERC has approved Violation Risk Factors associated with those standards.  The Violation Risk Factors rank violations by the relative risk each poses to the high-voltage transmission grid.  These rankings will factor into setting penalties for violations of the Reliability Standards.  The accepted Violation Risk Factors will, like the Reliability Standards they enforce, go into effect June 1. 

FERC approved over 700 Violation Risk Factors that the North American Electric Reliability Council (NERC) had proposed.   Each relates to the 83 Reliability Standards that FERC approved in its Order No. 693 earlier this year.  Violation Risk Factors associated with proposed but not yet approved Reliability Standards will be addressed when FERC acts on those Reliability Standards themselves.  NERC categorizes Violation Risk Factors as high, medium, and low.  High risk violations could cause or contribute to bulk-power system instability, separation, or cascading failures.  Medium risk violations can affect the electrical state or the capability of the bulk-power system, or the ability to monitor and control bulk-power flows.  Low risk violations are more administrative in nature.

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. 

FERC Approves Controversial Settlement on PJM Capacity Rules

Praising the settlement process as much as the results, the Federal Energy Regulatory Commission approved, subject to certain changes, the settlement that the PJM Interconnection reached with market participants for a redesign of PJM's capacity market.

PJM's August 2005 proposal to FERC led to an order in which FERC concluded the existing capacity rules were unjust and unreasonable.  This led to settlement negotiations, encouraged by FERC, and the submission of a settlement agreement supported by a majority of market participants.  The settlement was based on the proposal PJM submitted to FERC in August 2005, but included expanded provisions deemed suitable for vertically integrated utilities.  Among the key provisions of the agreement are a sloping demand curve (which combined with generator bids determines capacity prices), forward (rather than same-year) procurement of capacity, and ultimate use of 23 locational deliverability areas (LDAs) reflecting transmission constraints, to be phased-in over several years – which some generators contended was discriminatory because of the use in the interim of an aggregated Rest-of-Market LDA that contains significant internal constraints. 

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. 

FERC Conditionally Approves PJM RTEP Process Modifications

Despite concerns about the paucity of detail in PJM's modified Regional Transmission Expansion Plan (RTEP), FERC has conditionally approved it effective retroactively to September 9 of this year. 

PJM filed the plan in early September, asking FERC to approve a new forward-looking planning process that is driven by economics as well as reliability considerations.  Several interests protested that the plan lacked adequate detail.  For example, it did not disclose when a proposed market solution to congestion could displace a project already incorporated into the RTEP.  Nor did it reveal how PJM proposed to measure market efficiency.  

While acknowledging that the RTEP revisions need fleshing out, FERC enumerated benefits offered by the new process that were absent under PJM's previous approach.  The benefits include its forward-looking planning and "more expansive view" of the planning process.  In particular, the revised RTEP process allows PJM to consider both market-based and rate-based solutions with equal weight when addressing congestion.  It also requires PJM to consider future market conditions when making such decisions.   

FERC directed PJM to clarify various ambiguities in its proposal.  How, for instance, did  PJM propose to evaluate long-term price forecasts and the efficacy of proposals to decongest the grid?  FERC declined to demand that PJM establish a deadline beyond which market solutions can no longer bump projects from the RTEP, and FERC agreed that PJM may continue to allocate the costs of economic upgrades to those who specifically benefit from the upgrades.   

FERC staff will convene a technical conference in the near future to examine the possibility of using demand-response/conservation resources as alternatives or complements to transmission expansion projects and how providers of demand response should be compensated.

Federal-State Cooperation Will Promote Demand Response in Power Markets

FERC has embarked on dialogue with state regulators about demand response — the designation assigned a variety of potentially promising measures consumers (as opposed to the suppliers) can take in power markets to reduce demand and prices.  The federal-state dialogue on demand response policies is auspicious because development of effective demand response that is capable of materially reducing prices will require coordination of federal regulation of wholes and state regulation of retail power markets. 

In response to directives in the Energy Policy Act of 2005, FERC prepared a report assessing demand response and advanced metering.  FERC’s August 2006 report concluded that demand response was promising and the subject of widespread interest, but yet illusory due to disconnects between wholesale and retail pricing (which fails to pass through wholesale price signals to retail consumers), economic disincentives for utilities to offer retail demand response, and other regulatory and industry barriers.  FERC also found that the use of advanced metering — meters that show consumers the present cost to generate and deliver power — varies greatly between regions and averages only 6% of electric meters nationwide. 

Discussion about demand response often lack focus.  In one sense it is any type of energy conservation, for instance turning off the lights in an empty room.  More complex versions of demand response include the incentive programs run by several regional transmission organizations and independent system operators.  These provide payments to users who reduce their power consumption under certain circumstances, in particular when demand is at its peak.  As a result, the RTO/ISO may be able to avoid dispatch of high-cost (inefficient) generators, which leads to a lower clearing price for the market and savings for other consumers.  This form of demand response does not necessarily conserve energy, as the participants in the demand response program may simply shift their energy consumption to other (non-peak) hours.  FERC’s report relies on a definition that encompasses both time-based use of electricity and incentive payments for reducing demand at times of high wholesale market prices or when demand is threatening system reliability. 

More ambitious discussions about demand response tout it as a potential substitution for power, capacity, transmission, and even ancillary services such as operating reserve.  In these contexts, demand response is seen not just as a means for customers to save money, but to allow new industries to earn money through demand response programs and measures.  The extent to which demand response can play this larger role remains to be seen and will turn in large measure on how effectively FERC and state regulators coordinate to induce suppliers to forego sales and, more importantly, to induce consumers to forego consumption in order to promote the common goods of lower prices and/or system reliability.

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.

Divided FERC Approves Incentive for New England Transmission

FERC voted by a 3-2 margin to raise by 100 basis points (1%) returns on equity invested in New England electric transmission that ISO New England identifies as necessary.  The Republican majority, including FERC Chair Joseph Kelliher, concluded that incentive rates were needed to encourage transmission expansion and reduce regional congestion; the Democratic dissenters contended that, even if targeted investment incentives may be warranted, across-the-board increases in transmission investment returns had not been justified.

The order reverses a FERC judge’s May 2005 decision that such transmission incentives should only be awarded to projects that would not be built “but for” the incentives.  In the Energy Policy Act of 2005 Congress directed FERC to develop transmission rates sufficient to induce investment.  In July 2006 FERC finalized a transmission pricing rule intended to induce investment in transmission without requiring the “but for” predicate that the judge endorsed.  By rejecting the “but for” requirement, the FERC majority appears to have been persuaded that ISO New England’s 2004 regional transmission planning ensures that the benefits of new transmission and congestion relief justify the added expense.
The dissenters were unwilling to buy so completely into the ISO New England planning process.  Commissioner Suedeen Kelly found the majority’s decision troubling because transmission owners would be able to get the 100-basis point adder regardless of whether it was in fact necessary for a given project to be constructed or the specific benefits from the project.  Commissioner Jon Wellinghoff expressed similar concerns, adding that such transmission incentives should be limited to those projects that provided incremental benefits such as energy efficiency. 

FERC to Consider Settlement in PJM Capacity Market Redesign

Thirteen months after the PJM Interconnection proposed to FERC the Reliability Pricing Model (RPM), a redesign of its capacity market, the nation’s largest RTO and many of its members submitted to FERC a proposed settlement agreement to create a new capacity market.  The submitting parties asked FERC to approve the settlement by December 22, 2005, so that it can take effect by June 1, 2007.

The settlement agreement uses many of the concepts included in the proposal PJM had submitted to FERC, but applies them differently, often in a way less favorable to generators.  A sloping demand curve – which combined with generator bids determines capacity prices – continues to be part of the market design, but the pricing points are suppressed.  Instead of procuring capacity four years in advance, as originally proposed, the settlement would require only three-year forward procurement.  The proposed settlement would ultimately create 23 locational deliverability areas (LDAs) reflecting transmission constraints.  Recognition of LDAs then allows capacity prices to vary between regions to reflect constraints on deliverability.  However, all of the LDAs would not take effect until the 2010-2011 delivery year, leaving in place until then awkwardly shaped LDAs with internal constraints, such as the Rest-of-Market LDA that groups together Dominion-Virginia Power and other areas that are separated by significant transmission constraints.  Other modifications include addition of the Fixed Resource Requirement, which allows utilities to opt out of the RPM and instead self-supply capacity, whether from their own resources or through bilateral arrangements. 

The proposed settlement is the result of four months of settlement talks that began a few weeks after FERC’s April 20, 2006 order finding the existing capacity rules to be unjust and unreasonable. 

New PJM Market Efficiency Analysis Synthesizes Economic and Reliability Planning

Expanding on changes made to its regional transmission expansion plan (RTEP) process last June, the PJM interconnection has asked FERC to approve further RTEP adjustments intended to coordinate economic planning with reliability planning in a "forward-looking market efficiency analysis."  

The June changes projected RTEP's planning horizon fifteen years into the future, and developed more fully the shorter-term outlooks.  With the current redo, PJM will apply a revamped market efficiency analysis to the fifteen-year horizon.  The intended  result is a forward-looking assessment in lieu of PJM's current economic planning, which focuses only on mitigating historical congestion.   

The new efficiency analysis considers the economic benefits associated with three types of reliability upgrades.  The first type provides economic benefits simply by accelerating the in-service date.  The second type relieves economic constraints.  The third type achieves cost savings even when no reliability violations are at issue.  These evaluations will consider a wide array of economic metrics, from fuel costs to generation retirement scenarios.  Based on this evaluation process, PJM planning officials will recommend needed upgrades to PJM's board.  The recommendation will designate who would construct, own or finance the upgrade; the estimated cost; and the market participants who should bear the cost.  Once included in RTEP an upgrade would continue to be evaluated and compared to alternatives, such as demand response or new generation.  PJM cautioned that it would consider removing an upgrade from RTEP only when other market solutions are implemented that obviate the reliability or economic need for the upgrade. 

In another change, PJM has eliminated the one-year window for economic upgrades, under which PJM – once it identified an area of historically unhedgeable congestion – waited one year during which a market participant could propose a solution before PJM itself initiated upgrades as part of the RTEP process.  The one-year lagtime is no longer needed, PJM reasoned, due to the increased depth of economic as well as reliability information that the revised RTEP will provide concerning areas where the system will experience future needs.   

“Let It Be Me,” NERC Tells FERC

Within days of FERC clarifying final elements of its Electric Reliability Organization (ERO) rule, the North American Electric Reliability Organization (NERC) filed with the agency its long-awaited ERO application.  On February 3, FERC issued its final rule establishing the criteria it will use to select an ERO, as mandated in the Energy Policy Act of 2005.  FERC Rule Allows Regional Entities to Propose and Enforce Reliability Standards]  But the rule didn’t go into effect pending a FERC decision on how to handle conflicts between the ERO's reliability standards and FERC-approved tariffs.  The revised rule provides that if FERC finds a conflict to exist, it may offer an RTO or affected utility an opportunity to submit a revised tariff, or FERC itself may modify the tariff itself under its Federal Power Act authority. 

On April 4, NERC submitted to FERC its application for recognition as the US ERO, along with over 100 proposed reliability standards that it would enforce under its new designation.  [NERC ERO Application]  Simultaneously, NERC submitted applications to Canada's National Energy Board and various Canadian provinces to be recognized as the reliability coordinator in Canada.  Little doubt exists that NERC will be certified as the US ERO since it has served in essentially that capacity since the 1960s.  But robust debate is expected as to whom the ERO’s reliability standards will apply, as some EPAct provisions exempt entities that engage solely in power distribution.  In addition, the extent of the ERO’s authority, if any, to delegate to regional councils standard-setting powers is likely to be contentious, with regional entities vying for region-specific standards and FERC wanting to maintain uniform national standards.   

DOE Congestion Study to Identify National Interest Electric Transmission Corridors

In response to a Energy Policy Act of 2005 (EPAct 2005) directive that the Department of Energy (DOE) report on electric transmission congestion nationwide (congestion study), DOE has issued a Notice of Inquiry (NOI) seeking advise on how to proceed.  So begins a process with the hoped-for result of catalyzing the construction of transmission facilities in areas desperately in need of enhanced transfer capability.  Public comments in response to the NOI are due March 6, 2006. 

The congestion study will inventory geographic areas where significant congestion exists.  DOE will publish the congestion study by August 8, 2006, and seek further public comment at that time.  As the follow-up report may include designations of geographic areas with transmission capacity constraints or congestion adversely affecting consumers as "national interest electric transmission corridors" (NIETCs) [See Congress Enacts Energy Bill and Energy Policy Act of 2005 Hands FERC a Long To-Do List], comments on the study may propose potential NIETCs.  DOE will then evaluate those potential NIETCs based on certain criteria, some of which DOE has identified and offered for comment, including whether there is a "clear need" to remedy reliability problems, and whether NIETC designation would enhance U.S. energy independence.   

Designation as a NIETC will open the door for FERC to issue permits for construction of electric transmission facilities in the NIETC.  Prerequisite to issuing such a permit, FERC must determine that a proposed transmission project will serve the public interest and that the state where it would be located cannot or will not issue a permit.  The next milestone in this process will be selection of the criteria used to evaluate NIETC nominations – the result of which will affect both the scope and success of the NIETC initiative.

FERC Rule Allows Regional Entities to Propose and Enforce Reliability Standards

FERC has satisfied another major mandate of the Energy Policy Act of 2005 by issuing final rules that pave the way for certification of an Electric Reliability Organization ("ERO") as well as the establishment of mandatory electric reliability standards.  Notably the rule condones more regional flexibility than FERC originally envisioned [See Rules Concerning Certification of the Electric Reliability Organization; and Procedures for the Establishment, Approval, and Enforcement of Electric Reliability Standards]; Regional Entities are allowed both to propose reliability standards and to enforce (under ERO and FERC supervision) those standards that are adopted.  The rule, styled Order No. 672, establishes: 

• Credentials required of an ERO;
• Procedures for the ERO to propose new or modified reliability standards for FERC review (FERC will evaluate the standards on whether they are just, reasonable, not unduly discriminatory or preferential, and in the public interest);
• Funding of the ERO;
• Directions for enforcing adopted reliability standards;
• ERO authority to delegate to a Regional Entity the authority to propose and enforce reliability standards;
• An ERO and Regional Entity audit programs to ensure compliance with the reliability standards;
• Periodic ERO reports assessing the reliability and adequacy of the bulk power system; and
• Procedures for establishing regional advisory bodies. 

As expected, the North American Electric Reliability Council will soon apply to FERC to be designated as the ERO.  The application must be delivered to FERC by April 3, 2006.  FERC noted in the Final Rule that it plans to provide adequate time for industry participants to transition from the current regime of voluntary reliability standards to the new ERO world of mandatory and enforceable reliability standards.  [Rules Concerning Certification of the Electric Reliability Organization; and Procedures for the Establishment, Approval, and Enforcement of Electric Reliability Standards, 114 FERC ¶ 61,104 (2006)]

FERC to Mirant: Keep Power Flowing to Nation's Capital

Finding that a power-supply emergency existed in the Washington, DC area, Secretary of Energy Bodman on December 20 issued an emergency order directing Mirant to continue to operate its Potomac River, 482-MW power plant.  The plant had stopped operations to avoid violating its air quality permit.  Secretary Bodman explained that, absent the Potomac River plant, should either of Potomac Electric Power Company's (Pepco) 230-kV lines become unavailable, power supply to the Capital would be in jeopardy.

Following the Secretary, in a January 9 order FERC ordered PJM Interconnection L.L.C. (PJM) and Pepco to devise a long-term plan to maintain adequate reliability in the Washington, D.C. region, as well as an interim plan to provide adequate reliability pending implementation of a long-term plan.   Due to the fact that PJM's and Pepco's current transmission system has been shown to have a high probability of violating the NERC and PJM reliability standards, FERC directed PJM and Pepco jointly to develop a comprehensive long-term plan to address operation, planning and construction of needed transmission facilities for the region.  PJM and Pepco must file the comprehensive plan with FERC by February 8 and must also jointly submit progress reports to FERC on a monthly basis until the plan has been fully implemented.  Immediately after the issuance of FERC's order, Pepco announced that it already has a plan in the works to build new transmission lines in the area. See Mirant Plant Showdown Prompts Efforts to Expand Transmission in D.C.

Additionally, Pepco recently announced that it would be repairing one of its 230-kV lines sometime this month.  The Department of Energy declined to grant a Virginia Department of Environmental Quality (VDEQ) request to order Pepco to postpone its transmission line repairs until Mirant could put the proper air pollution controls in place at the plant, stating instead through its spokesman that it will address VDEQ's request in a future order.   [District of Columbia Pub. Serv. Comm'n, 114 FERC ¶ 61,017 (2006)]

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.

No Consensus on Securing Long-term Generation Adequacy

Regional efforts to ensure long-term generation adequacy reveal a wide range of views by various interest groups who either support or to varying degrees oppose the market rules being proposed to ensure that there is sufficient generation available in all regions of the country.  A PJM effort to revise its plan is heating up, while the battle in New England continues and a new plan is approved in California.

Citing growing concerns about generation retirements and looming capacity shortages, PJM filed with FERC in late August a proposed Reliability Pricing Model (RPM).  The RTO proposes RPM as a replacement to the simpler installed capacity model it has used since starting its bid-based energy markets in 1997.  The new resource adequacy plan resembles in various ways the capacity market of the neighboring New York Independent System Operator.  The RPM includes a downward-sloping demand curve for pricing of capacity, locationally-different prices in response to shortages in constrained regions, a four-year forward capacity procurement, enhanced monitoring and mitigation for capacity markets, and various other features such as allowing demand response and new transmission to compete in capacity markets.  Numerous parties responded to the proposal with a wide range of opinions, including claims by certain utilities that RPM is not necessary because most areas within the RTO have no supply shortages, as well as general support from generator interests who claim the existing capacity rules are inadequate.  Tension between state and federal regulators was evident in the comments of the Organization of PJM States, consisting of the state utility regulators from states where PJM has a presence, which argued RPM would not accomplish its objectives and that FERC should convene a hearing on the RPM proposal.

Meanwhile, a contentious FERC proceeding to revise the resource adequacy mechanism in New England persists.  Earlier in the fall, parties in support and against ISO-New England’s locational installed capacity (LICAP) proposal presented oral arguments to the FERC Commissioners.  Previous administrative measures had included a hearing and several rounds of written arguments.  Despite this robust record, heated opposition to LICAP, primarily from Connecticut interests opposed to potential price increases caused by the locational differences in capacity pricing, has rendered FERC unwilling to approve the plan.  Instead, evoking past disasters, FERC recently warned that a California-style crisis might visit parts of New England if market rules aren’t revised to encourage more development of generation, and directed the parties to engage in settlement talks.  FERC also set a deadline of January 31, 2006 for the filing of any alternatives to the LICAP proposal.

Speaking of California, the state’s Public Utility Commission has adopted a long-anticipated resource adequacy plan for the state’s three largest investor-owned utilities, PG&E, Southern California Edison, and San Diego Gas & Electric as well as electric service providers and community choice aggregators.  As with the plans being promulgated and debated in other parts of the country, this plan is intended to encourage timely development of generation in areas where shortages might otherwise develop.  Entities covered by the plan would have to demonstrate by June 2006 that they have secured enough capacity to serve expected customer demand, plus a 15-17% reserve margin.  The contracts would have to identify the specific resources that provide capacity.  The PUC’s plan also acknowledges the need for localized electricity capacity requirements but defers implementation pending further consideration, and sets penalties that will rise to three times the monthly cost for new capacity as a sanction for a utility's failure to meet its resource adequacy obligation.  The bilateral liquidated damages contracts previously used in California to ensure resource adequacy will be gradually phased out.

Wyoming Finances Power Line Project to Improve Transmission and Reliability

Using bonds issued through the state's mineral trust fund, the Wyoming Infrastructure Authority ("WIA") recently financed its first power line project, the Basin Electric Power Cooperative's 130-mile $50 million 230-kilovolt transmission line to be located in northeastern Wyoming.  The Basin Electric project — the first step in WIA's forecasted 500 miles of needed transmission — is expected to deliver power within the state and facilitate exports to neighboring California, Colorado and Utah.  The circuit on the Basin Electric project is anticipated close by the end of 2008.

The WIA's charter tasks the authority with conceiving, funding, constructing, maintaining and operating electric transmission line projects using up to $1 billion in state-backed bonds.  It is intended that the new transmission lines will provide export market access for the substantial bituminous coal deposits in the state's Powder River Basin as well as up to 8,000 megawatts of wind generation proposed for development in the Cowboy State.

FERC Initiates Process for Formation of Overdue Mandatory Reliability Standards

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

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

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

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

Reliability v. Health: Neighboring States Battle over Dirty but Needed Generator

A cross-Potomac skirmish over the competing principles of energy reliability and public health has broken out over the fate of Mirant Potomac River's 482-MW, coal-fired power plant in Alexandria, Virginia.  The District of Columbia Public Service Commission’s ("DCPSC") petition to FERC and the Department of Energy ("DOE") to prevent Mirant from shutting down both provoked urgent protests and drew support from regional stakeholders.  

Prompting the DCPSC's petition was Mirant's announcement that, because of a Virginia Department of Environmental Quality ("VDEQ") directive to remedy air quality violations, it would shut down the plant on August 24.  In its petition, the DCPSC argued that the proposed shutdown, which Mirant has implemented, would have a "drastic and potentially immediate effect" on electric reliability in the greater Washington, D.C. area, possibly leading to curtailments of electric service, load shedding and blackouts.  The DCPSC asked the DOE to mandate continued operation of the plant pursuant to its authority under section 202(c) of the FPA, a statutory provision that was put in play during the 2000-2001 California crisis and the August 2003 Northeast blackout, and asked FERC to take complimentary actions under the FPA.

Supporters of the DCPSC petition include PEPCO, the Pennsylvania Public Utility Commission, and the PJM Interconnection.  In its comments, PJM contended that the shutdown was not consistent with its rules for plant deactivation and did not give PJM an opportunity to consider the effect of the shutdown on system reliability.   Not surprisingly, Mirant asked that any order in response to the DCPSC petition requiring it to resume operations should specify that such order preempts the authority of the VDEQ and any other federal and state environmental requirements. 

Anticipating Mirant's request for preemption, the City of Alexandria, which opposes as premature the emergency request made by the DCPSC, pointed out that Mirant’s action to shut down the plant was unilateral, mandated by neither Virginia nor Alexandria.  Alexandria stated that it while it welcomed Mirant’s action as appropriate in light of the environmental concerns, DOE and FERC should consider Mirant’s corporate motives and agenda, and suggested that this was "a wholly manufactured scenario by Mirant to allow it to diminish its public and contractual obligations" by operating in violation of its air permit.

The VDEQ asked that any federal order to resume plant operations should consider the impacts thereof on air quality in Virginia.  The Southern Environmental Law Center, a nonprofit group, argued for rejection of the DCPSC request on the grounds that the plant's shutdown had been expected for years and was in response to "gross violations" of federal and state clean air laws that precluded a finding this was an emergency under section 202(c).

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

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

• Within 60 days:  Issue regulations on the National Environmental Policy Act pre-filing process for liquefied natural gas (LNG) projects. 
• Within 90 days: 
  • Consult with Departments of Interior, Commerce, and Agriculture, to establish procedures for trial-type expedited proceedings for mandatory conditions and fishways on hydropower licenses.
  • Issue a final rule exempting QFs, EWGs, and foreign utility companies from access requirements that take effect upon PUHCA repeal (PUHCA is repealed effective 6 months after enactment).
• Within 4 months: 
  • Issue rules to exempt from section 1275 any holding company whose public utility operations are confined to a single state and any other class of transactions FERC finds not relevant to jurisdictional public utility rates.
  • Issue any rules necessary to implement new PUHCA provisions.
  • Submit to Congress recommendations and conforming amendments to federal law necessary to carry out the new PUHCA subtitle.
• By Dec. 31, 2005:  Conclude California energy crisis proceedings and submit to Congress a report describing actions taken and timetables, if any, for further action.
• Within 180 days: 
  • Issue final rule implementing new reliability provisions.
  • Issue rule revising criteria for useful thermal output of QFs under PURPA.
  • Sign MOU with Commodity Futures Trading Commission on information under electric and gas market transparency provisions.
  • Report to Congress on progress in licensing and constructing Alaska natural gas pipeline.
  • With DOE, report to Congress on how to make available to all transmission owners and RTOs real-time information on the functional status of transmission lines within Eastern and Western Interconnections.
• Within 1 year:
  • By rule or order, establish how to meet the needs of load-serving entities.
  • Issue rules for incentive-based rate treatments for transmission in interstate commerce.
  • Convene regional joint boards to study security constrained dispatch, report to Congress.
  • Publish annual report assessing regional demand response resources.
  • As a member of a 5-member inter-agency task force, submit report to Congress assessing competition within wholesale and retail electricity markets.
  • Consult with DOE to conduct at least 3 LNG forums.
  • Enter MOU with other federal agencies to coordinate review and permitting of electric transmission facilities.
• Within 18 months:  Consult with DOE to submit report to President and Congress on benefits of cogeneration and small power production
• Within 2 years:  Consult with Agriculture, Commerce, Defense, Energy, Interior and states to identify corridors for pipelines and electricity transmission and distribution facilities on federal land in Western states, perform environmental reviews for those designations, and incorporate corridors into relevant agency land use plans
• Within 4 years:  Consult with Agriculture, Commerce, Defense, Energy, Interior and states to establish procedures to identify corridors for pipelines and electricity facilities for all other (i.e