Energy Legal Blog

FERC Allows Duquesne to Exit PJM, but with Conditions

FERC on January 17 conditionally approved Duquesne Light's request to withdraw from the PJM Interconnection and join the Midwest Independent System Operator.  Last November, Duquesne filed an application with FERC seeking approval to leave PJM over rising capacity costs as a result of PJM's new forward capacity market.  In comments and protests filed in December, PJM and other PJM market participants asked FERC to hold Duquesne be held to its financial commitments to the market and ensure that its withdrawal would not harm other market participants financially.

In the January 17 order, FERC agreed to hold Duquesne responsible for its commitments in the PJM forward capacity market.  FERC conditioned Duquesne's right to exit PJM upon the utility honoring commitments for all forward capacity auctions in which its load had been included.  This means that Duquesne will be liable for forward capacity costs through May 2011.  (Duquesne had asked FERC to make its withdrawal from PJM and termination of its obligations in the capacity markets effective May 31, 2008.)  FERC also directed Duquesne to submit further information on its remaining obligations, including how many and what its continuing obligations to PJM are, what its allocated share of costs for the PJM regional transmission planning process is, and how it will be integrated into the Midwest ISO.

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. 

Maryland Energy Administration Calls for Efficiency and More Local Generation

The Maryland Energy Administration (MEA) released its Strategic Electricity Plan on January 14 in an effort to help customers lower their energy bills.  The plan, focused on conservation, efficiency and local new generation, also came in response to Maryland Governor Martin O'Malley's recent warning that the state could face serious power shortages in the near future.

The plan aims to reduce both electricity consumption and peak demand by 15% by the year 2015 and require the state's utilities to implement performance-based programs to help meet these goals.  The MEA predicts that if these goals are met, electricity consumption in the state would fall by 25 billion kilowatt-hours and consumer charges fall by over $2 billion in 2015 and by over $4 billion in 2020.

The plan comprises four central elements.  First, financing would come from a Strategic Energy Investment Fund of revenues earned from the state's sale of carbon allowances as part of Maryland's participation in the Regional Greenhouse Gas Initiative (RGGI), a 10-state initiative that aims to reduce greenhouse gases.  Second, the plan would implement energy efficiency programs, including incentives and rebates for consumers to purchase efficient appliances and have home energy audits, as well as installing interruptible load (cycling) devices on their air conditioners.  Third, the plan calls for increased investment in new generation within the state, particularly investment in sources of renewable energy, including by improving grant programs for the development of solar and geothermal energy, encouraging long-term contracts for new generation, and evaluating the need to require utilities to build or purchase new generating capacity to meet peak summertime demand.  Finally, the MEA asks for additional resources to help it produce biennial state energy plans, encourage regional transmission planning, and stimulate clean energy within Maryland.

Maryland retail customers have in recent years faced significant increases in their electric bills, following the expiration of retail rate freezes on the state's utilities.  Moreover, Governor O'Malley has predicted that by 2011 the state will face electricity shortages during peak periods.

Revised Contents of Sellers' Market-Based Rate Tariffs Clarified

Federal Trade Commission Examines Green Marketing and Carbon Offset Markets

With increased concern about climate change, but limited government action, voluntary carbon markets have bloomed in recent years.  The Federal Trade Commission (FTC), which regulates advertising claims, is now taking a closer look at these new carbon offset markets to gauge how the money they attract is being invested.  The FTC held a workshop in early January and is considering revising its environmental marketing guides to address sales of carbon offsets markets as well as renewable energy credits (RECs). 

Carbon offsets are credits that correlate to quantifiable reductions in greenhouse gas credits.  Purchasers of carbon offsets can claim that their carbon-emitting activity, such as travel, is offset by unrelated beneficial measures.  Common examples include tree planting or forest preservation, as well as investment in generation of energy from low-carbon-emissions sources.  Carbon offsets are typically measured in volumes of carbon.  RECs are quantifications of energy produced with renewable means, and are measured in megawatt-hours.  Voluntary REC markets allow buyers to purchase RECs to support renewable energy development.  State renewable portfolio standards also rely on RECs to quantify utilities’ mandatory procurement of renewable energy. 

The concern related to carbon offsets and RECs is whether the funds from voluntary sales are being used in legitimate or constructive ways.  Concerns have been voiced over issues such as whether eligible projects might oversell credits, or, even if not, whether the money paid goes to existing projects or projects that would have happened anyway.  For example, if an existing, operating windfarm that was built without any sales of RECs or carbon offsets subsequently obtains additional funds from such sales, there is arguably no additional environmental benefit obtained from these REC or carbon offset sales.

The FTC is inviting comments on carbon offset guidelines until January 25 and on environmental marketing guidelines until February 11, and will subsequently decide how and if to revise the marketing guides. 

Final Skirmishes in Enron Contract Wars Draw to Close

Resolving the last remaining claims against Enron stemming from the 2000-2001 California energy crisis, over the past week, FERC approved two settlements involving Enron:  one with the Port of Seattle, Washington (Port), and the other with Public Utility District No. 1 of Snohomish County, Washington (Snohomish).  The Port receives a $500,000 unsecured claim against Enron in its bankruptcy proceeding, while the Snohomish will pay Enron $18 million out of the $180 million that Snohomish allegedly owes Enron in termination fees arising from Snohomish's cancellation of contracts it entered into with Enron during 2001.  FERC's approval of these settlements puts an end to rancorous litigation between the parties and dismisses Enron from the various California refund proceedings.

The Enron-Port settlement continued the debate among the current Commissioners with respect to the Mobile-Sierra "public interest" standard of review for contract modifications.  Commissioners Kelly and Wellinghoff each filed separate opinions to the order approving that settlement, expressing disagreement with FERC's approval of the public interest standard.  Both Commissioners have consistently criticized FERC orders approving the inclusion of the public interest standard in settlement agreements, arguing that the Commission should not bind itself to the that standard, which allows unilateral changes to an agreement only if required by the greater "public interest" ― a singularly demanding burden of proof.  Instead, Commissioners Kelly and Wellinghoff have argued, FERC should approve modifications to settlement agreements so long as they are "just and reasonable," which is considered a less rigorous analysis and makes it easier for agreements to be modified in the future.

In two recent decisions currently before the Supreme Court (the so-called Long-Term Contracts decisions), the US Court of Appeals for the Ninth Circuit questioned whether the public interest standard applies where a buyer challenges a contract price as being too high.

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 Provides Clarification to Financial Houses' Utility Security Acquisition Authority