Energy Industry Updates for September 2010

30 September 2010 Publication

Legal News: Energy Industry

California Regulators Rev Up Renewable Portfolio Standard to 33 percent; Voters Might Apply Brakes

California regulators recently passed an aggressive renewable portfolio standard (RPS) that will require 33 percent of electricity sold in the state to come from renewable sources, but a November ballot initiative could change things.

On September 23, 2010, the California Air Resources Board (CARB) approved a rule, as directed by an earlier executive order by Gov. Arnold Schwarzenegger, to increase the RPS from the current 20-percent requirement that sunsets at the end of 2010. The regulation is the product of coordination and cooperation by CARB, the California Public Utilities Commission, the California Energy Commission, and the California Independent System Operator. This action comes on the heels of the California Legislature’s recent failure to pass a bill that would have made the 33-percent target a state law.

The rule’s phased-in approach provides interim targets for renewable energy: 20 percent in 2012 – 2014, 24 percent in 2015 – 2017, 28 percent in 2018 – 2019, and 33 percent for 2020 and beyond. While the prior RPS covered investor-owned utilities and publicly owned utilities, this regulation extends to all entities that deliver electricity, including municipal utilities. Thus, public power entities like the Los Angeles Department of Water and Power, the largest public utility in the United States, will be required to meet the new RPS.

California has been a leader in aggressive RPS policies, which were first outlined in 2006 by A.B. 32, the state’s landmark global warming law. Yet CARB’s new rule could be short-lived. An initiative on California’s November ballot, Proposition 23, would freeze the provisions of A.B. 32 until the state’s unemployment rate drops to 5.5 percent or lower for four consecutive quarters. A suspension of A.B. 32 would likely lead to a corresponding freeze on renewable energy expansion.


Illinois Electric Power Procurement Issues for 2011

The Illinois Power Agency’s (IPA) plan for purchasing power for Illinois’ two largest electric utilities, ComEd and Ameren, in 2011 is set to be filed for confirmation or modification in the Illinois Commerce Commission (ICC). Created in 2007, the IPA is charged with purchasing electric power for the utilities in a way that ensures “adequate, reliable, affordable, efficient, and environmentally sustainable electric service at the lowest total cost over time.” The IPA procures power to meet the estimated needs of the utilities’ customers pursuant to a procurement plan in which power producers bid against each other to meet portions of the required power load at the lowest possible price. Further, the IPA is directed by statute to ensure that a minimum portion of the electric supplied is “generated from cost-effective renewable energy resources” (at least six percent by June 1, 2011, with 75 percent of that amount coming from wind generation, to the extent available, and a required percentage from solar generation starting in 2012). The IPA’s draft 2011 procurement plan garnered many comments from the utilities, government agencies, industry members and associations, and public interest groups, which highlight important issues that the ICC may have to address:

  • Financial swaps versus contracts for physical delivery of electricity. Some parties raised concerns that the new Dodd-Frank Wall Street Reform and Consumer Protection Act and regulations to be adopted by the CFTC regarding swap contracts may have consequences for the IPA’s planned reliance on swaps rather than contracts for physical delivery of energy. They desire that language be put into the plan acknowledging that the IPA may need to shift its portfolio away from swaps and more towards contracts for actual delivery of electricity depending upon how the CFTC regulations develop.
  • Renewable energy credits (RECs) versus power purchase agreements. The IPA’s plan would meet the renewable energy portfolio requirements through the purchase of one-year RECs rather than by entering into power purchase agreements for actual delivery of electricity generated from wind or other renewable resources. While many stakeholders approve of this approach, members of the renewable energy industry would prefer to see contracts for actual purchases of renewable energy in order to help foster the development of such resources.
  • Short-term versus longer-term RECs. Renewable energy industry groups seek to have the IPA adopt the use of five-year RECs rather than solely using one-year RECs to meet the renewable portfolio requirements. They point to the overall growing demand for renewable resource capacity throughout the Midwest ISO and PJM states due to similar renewable energy portfolio mandates and other factors. It is predicted that this growing demand may outpace the available supply of renewable energy resources. They argue that use of five-year RECs will provide more stable cash flow to renewable resource owners, thereby encouraging more development of wind and solar generation, while maintaining more flexibility for the IPA than products with a longer delivery period.
  • Purchase of energy efficiency measures as an alternative resource. The IPA draft plan included a proposal that it be allowed to use the purchase of energy efficiency measures as an alternative resource for utility portfolios. ICC Staff and the utilities raise concerns about whether this option is permissible under the IPA Act and/or the Public Utilities Act (PUA). ComEd raises the concern that energy efficiency measures are not “standard wholesale products,” which is how the IPA is directed to meet its portfolio requirements by statute. There also is the question as to how the purchase of such alternatives would interface with the utilities’ energy efficiency programs and targets required by the PUA, and whether there could be double counting, as the utilities’ need estimates submitted to the IPA already factored in reduced energy demand as a result of their energy efficiency plans. Other stakeholders, however, submitted comments in favor of energy efficiency measures being purchased in lieu of supply, and look for the IPA to include energy efficiency measures beyond those included in the utilities’ statutorily required plans.

After a short comment period, the ICC must confirm or modify the plan no later than December 28, 2010.


FERC Separately Praises and Scolds NERC as Nation’s Electric Reliability Organization

Two recent orders show that the North American Electric Reliability Corporation (NERC) can be caught between the sometimes conflicting demands of its stakeholder-driven reliability standard development process and FERC directives. NERC plays a role as the nation’s developer and chief enforcer of Reliability Standards.

In the first order, FERC accepted NERC’s three-year performance assessment finding that NERC continues to fulfill its statutory and regulatory responsibilities as the nation’s electric reliability organization (ERO) to develop and enforce Reliability Standards. NERC was certified as the ERO in 2006 and the three-year performance assessment was filed on July 20, 2009. NERC has developed — and FERC thereafter approved — at least 95 mandatory Reliability Standards. Additionally, NERC, and the regional reliability organizations, have registered more than 1,800 entities, including entities in Canada, responsible for compliance with Reliability Standards.

While FERC accepted NERC’s performance assessment, it ordered NERC to make an informational filing within six months to address concerns regarding the Reliability Rtandards development process and activities of the regional entities. In the informational filing, NERC must update FERC on the status of the 120 action items NERC identified in the performance assessment. FERC directed NERC to comment on implementing certain practices in the Reliability Standards development process, including:

  • Posting proposed regional Reliability Standards for comment from the continent-wide pool of interested stakeholders for consideration, while allowing the regional open processes to make final determinations to be submitted to NERC
  • Providing for comments from NERC technical staff on proposed regional Reliability Standards
  • Including regional Reliability Standards in other NERC review processes that it uses for continent-wide Reliability Standards

Additionally, NERC must continue to submit quarterly updates to FERC on Reliability Standards development. FERC instructed NERC to develop criteria for evaluating events that have the highest impact on reliability and procedures to ensure timely communication between FERC Staff, NERC, and the regional entities. NERC also must develop a plan to address capacity and energy in its reliability assessment methodology and a timeline for executing the plan.

In the second order, FERC rejected NERC’s request for rehearing and/or clarification of a March 18, 2010 order that required NERC to propose revisions to its procedural rules. FERC ordered revisions to NERC’s procedural rules to address a conflict between its standards development process and its obligation as the ERO to submit to FERC new or modified Reliability Standards under the Federal Power Act. Additionally, FERC ordered NERC to develop modifications to Reliability Standards that govern Bulk-Power System facility ratings (FAC-008-1). FERC issued the order because the procedural rules had prevented NERC from fully complying with FERC’s order to modify FAC-008-1.

FERC stated that its order was intended to prevent standards development procedures being used to block FERC directives. In the case of FAC-008-1, the procedural rules resulted in FERC-ordered changes not passing the NERC balloting process. FERC emphasized that it was not attempting to “dictate” the content of Reliability Standards; however, NERC was not allowed to ignore a FERC directive.

The ERO is not required to develop a modification or new Reliability Standard that rigidly adheres to the technical approach specified in a final FERC directive, but it must develop and submit to FERC some proposal that affirmatively responds to the concern or goal underlying the directive and an adequate technical analysis if it decides to take a different approach. The ERO has a statutory obligation to comply with FERC directives under section 215(d)(5); it is not absolved of that obligation by merely considering a FERC directive in the standards development process. NERC must propose revisions to its Reliability Standards development procedures by December 13, 2010.

FERC will hold a commissioner-led technical conference to discuss reliability monitoring, enforcement, and compliance issues in November 2010 as well as a commissioner-led conference in either January or February 2011. The final agenda for these conferences will be determined based on discussions between NERC, FERC Staff, and Canadian regulators.


FERC Lifts Price Cap on Reassigned Transmission Capacity

After a 30-month study of the competitive effects of removing the price cap on reassigned transmission capacity, FERC voted to permanently lift the cap for all such reassignments. The removal of the price cap will become effective on October 1, 2010 and is implemented to help facilitate the development of a market for electric transmission capacity reassignment as a competitive alternative to primary transmission capacity.

In Order No. 888, issued in 1996, FERC concluded that a transmission provider’s pro forma Open Access Transmission Tariff must explicitly allow the voluntary reassignment of all or part of a holder’s firm point-to-point capacity rights to any eligible customer. Concerning the appropriate rate for transmission capacity reassignment, FERC established that it could not permit reassignments at market-based rates because it was unable to determine whether the market for reassigned transmission capacity was competitive enough not to allow resellers to exert market power. As a result, FERC capped the rate at the highest of: (1) the original transmission rate charged to the purchaser (assignor); (2) the transmission provider’s maximum stated transmission rate in effect at the time of the reassignment; or (3) the assignor’s own opportunity costs capped at the cost of expansion.

More than a decade later, in 2007, FERC determined that to promote the development of a stronger secondary market for transmission capacity, it was appropriate to temporarily remove the price cap for all transmission customers reassigning transmission capacity. FERC directed the Staff to carefully monitor the reassignment-related data to spot any issues in the development of the secondary market, specifically, the potential exercise of market power. FERC Staff published the report of the two-year study period in April 2010, concluding that the secondary market has grown sufficiently and that resale prices reflected market fundamentals rather than exercise of market power. Based on the report and FERC’s experience in the natural gas transportation market, FERC decided to lift the price cap for all reassignments of electric transmission capacity. FERC anticipates that removal of the price cap will help foster the development of a more robust secondary market for transmission capacity because point-to-point transmission service customers will have increased incentives to resell their service whenever others place a higher value on it.


Green Technology Pilot Program: Impact of the USPTO’s Elimination of the Green Technology Classification Requirement

After 10 months, some impact can already be seen from the pilot program (Pilot Program) the United States Patent and Trademark Office (USPTO) announced last December to expedite the examination of patent applications directed to certain green technology inventions. The Pilot Program was intended to reduce the time required to patent these inventions by an average of one year, contrasting this pendency reduction to the average time of 40 months to final decision for green technology inventions.

As originally set forth, to qualify for participation in the Pilot Program, applicants had to satisfy several requirements: (1) the application must be a non-reissue, non-reexamination, and non-provisional utility application filed prior to December 8, 2009; (2) the application must be classified as one of a list of enumerated green technologies; (3) the application must meet certain formalities requirements, such as having fewer than 20 total claims and not yet having received a substantive office action from the USPTO; and (4) the application must claim an invention material to green technology.

While the Pilot Program was well received in the green technology community, many potential participants found the technology classification requirement to be confusing and unduly restrictive. The USPTO’s decision to restrict participation to only certain technologies was viewed by many as excluding several important areas of green technology. The technology restriction also was a primary reason that the USPTO was denying many of the petitions filed. Recognizing the problem, on May 21, 2010, the USPTO announced the elimination of its classification requirement for participation in the Pilot Program. According to the USPTO, the classification requirement was originally intended to assist the USPTO in balancing patent examiners’ workloads and to gauge the resources needed to run the Pilot Program. Having met these objectives by other means, the classification requirement was no longer necessary. It should be noted that, although the requirement regarding classification has been withdrawn, an application must still claim an invention material to green technology to qualify. For purposes of the Pilot Program, the USPTO has stated that material inventions include those that: (1) materially enhance the quality of the environment, (2) materially contribute to the discovery or development of renewable energy resources, (3) materially contribute to the more efficient utilization and conservation of energy resources, and (4) materially contribute to greenhouse-gas emission reduction.

Eliminating the classification requirement has increased both the number of petitions to participate in the Pilot Program and the percentage of applicants granted expedited status. A review of data on the Pilot Program indicates that while the number of petitions being filed has not increased significantly, the percentage of those petitions that are granted has, due to the removal of the technology restriction. Interestingly, the elimination did little to affect the distribution of technology broadly represented in the Pilot Program. The distribution of petitions by technology group within the USTPO classification scheme remained relatively steady. The top three broad technology areas represented by petitions were chemical and materials engineering (approximately 30 percent), semiconductors and electrical arts (approximately 25), and mechanical arts (approximately 20 percent).

In light of the expansion of the Pilot Program, it may present an attractive opportunity for patent applicants in the green technology area, particularly for those companies that previously considered it, but whose technology was not originally included. The Pilot Program was originally capped at 3,000 participants. In the nearly 10 months since the Pilot Program started, slightly more than 1,500 petitions have been filed, with more than 700 of those having been approved for inclusion in the program. Interested patent applicants should act quickly before the Pilot Program reaches capacity.


FERC Issues Revised Penalty Guidelines

After significant concerns raised by the energy industry and a suspension of the originally released guidelines, FERC issued a Revised Policy Statement on Penalty Guidelines in September 2010. The revised guidelines will be used in determining civil penalties, and FERC believes guidelines will add greater fairness, consistency, and transparency to enforcement actions.

FERC did not change the underlying factors that will be used to determine penalties as described in its enforcement policy statements, but instead applies specific weight to each factor (e.g., harm or risk of harm, efforts to remedy violations, prior history, self-reporting, and senior management involvement). The revised guidelines will not impact enforcement staff’s discretion to close investigations or self-reports. The guidelines will only apply to FERC Part 1b investigation and enforcement actions, and not to FERC’s review of NERC Notices of Penalty. The new guidelines will apply to all future violations and pending violations where settlement negotiations have not begun. FERC also directed a technical conference be held in one year to evaluate the use of the new guidelines.

The revised penalty guidelines include the following changes:

  • The base violation level for reliability violations has been reduced from 16 to six while increasing the risk of harm enhancements for reliability violations
  • The quantity of load lost in MWh from a violation will be evaluated instead of the monetary value of the load lost, but no penalties will be enforced for load shedding required by the Reliability Standards
  • Partial compliance credit will be given to entities having imperfect compliance programs in place
  • The provision that automatically removed compliance credit where senior-personnel participated, condoned, or willfully ignored a violation to prevent a company from being punished for the action of rogue employees has been eliminated
  • Mitigation credits will be issued separately for self-reports, cooperation, avoidance of trial-type hearings, and acceptance of responsibility
  • The modified guidelines include an intent requirement for violations of misrepresentation and false statements

FERC continued to model the revised guidelines after the U.S. Sentencing Guidelines, stating that they provide the best model because they focus on factors, such as the seriousness and remediation of a violation, and provide an appropriate analytical model. FERC emphasized that the use of the Sentencing Guidelines as a model did not mean FERC was attempting to criminalize conduct.

Chairman Jon Wellinghoff noted that FERC will not apply strict liability to penalize operators for shedding load, so long as the action was taken in compliance with rReliability sStandards. However, the loss of load will be taken “into account in determining the risk posed by a violation of a Reliability Standard that gave rise to the load shedding.” With respect to the NERC Notices of Penalty, the Chairman found that it was appropriate not to apply the penalty guidelines because FERC has an appellate role and it would be difficult to define which Notices of Penalty to apply the revised guidelines.

The revised penalty guidelines address many of the concerns raised by industry commenters while maintaining the basic foundation from the March guidelines. By unbundling mitigation credits for actions such as self-reports, cooperation, avoidance of trial-type proceedings, and acceptance of responsibility, FERC further emphasized that parties should be proactive in their response to enforcement issues. Similarly, the ability to get at least partial credit for compliance programs should encourage even the smallest entity to put a compliance structure in place. The revised guidelines give entities involved in enforcement proceedings a way to evaluate potential penalty exposure, which can be helpful when interacting with enforcement Staff and deciding when to pursue settlements.


Legal News is part of our ongoing commitment to providing legal insight to our clients and colleagues. If you have any questions about or would like to discuss these topics further, please contact your Foley attorney or any of the following individuals:

Authors and Editors

Ronald N. Carroll
Washington, D.C.
202.295.4091
rcarroll@foley.com   

Theodore T. Eidukas
Chicago, Illinois
312.832.4913
teidukas@foley.com

Thomas McCann Mullooly
Milwaukee, Wisconsin
414.297.5566
tmullooly@foley.com

Andrew M. Gross
Chicago, Illinois
312.832.4532
agross@foley.com

Jeffery R. Atkin
Los Angeles, California
213.972.4557
jatkin@foley.com

Andrew M. Jamieson
Washington, D.C.
202.672.5359
ajamieson@foley.com

Andrea J. Chambers
Washington, D.C.
202.295.4770
achambers@foley.com

Svetlana V. Lyubchenko
Washington, D.C.
202.672.5492
slyubchenko@foley.com

William D. Dufour III
Los Angeles, California
213.972.4729
bdufour@foley.com

Matthew E. Martin
Chicago, Illinois
312.832.4559
memartin@foley.com

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