Energy Legal Blog

In a December 15 order FERC authorized Exelon Generating (ExGen) to make market-priced power sales to its Commonwealth Edison (ComEd) public utility affiliate in an auction process that was itself recently endorsed by an administrative judge of the Illinois Commerce Commission (ICC).  The evolution of the FERC order as well as the proposed order of ICC judge is noteworthy not only because it resolves a process in which various aspects of Illinois state government were aligned in opposition to each other, but also in that it produces a wholesale power supply model that may become an increasingly common alternative to the routine of a vertically integrated public utility generating power for most, if not all, of its retail demand.

In 1997 Illinois enacted the Illinois Electric Service Customer Choice and Rate Relief Law (Restructuring Law), which resulted in ComEd divesting all of its thermal generation and spinning off its nuclear generation to ExGen, reducing its retail rates by 20 percent and freezing all tariffed electricity rates for bundled retail customers from 1997 through 2006.  During this rate freeze, ComEd has sourced its retail demand from ExGen, under a supply agreement that will expire at the end of 2006.  After 2006, the ICC expected that ComEd would market source its retail demand, including provider of last resort retail service.  Based on that expectation, ComEd and the ICC staff developed a single clearing-price auction from which ComEd could purchase from various suppliers power to satisfy increments up to 35 percent of its retail load.  Although the auction represented a thoughtful consensus of many stakeholders throughout the Prairie State, it nevertheless rankled Governor Blagojevich, Attorney General (AG) Lisa Madigan, and the Citizens Utility Board (CUB) apparently for no other apparent reason than the auction would surely result in a politically unpopular increase in prices over existing retail rates that had been frozen for nearly ten years.

In a December 5 proposed order the ICC judge approved (with few and minor exceptions) tariff provisions implementing the auction proposal and dismissed the AG’s and CUB’s opposition.   The first auction would be held in September 2006 and would be repeated annually thereafter.  It would be open to all eligible suppliers, including ComEd affiliate ExGen, which would, in turn, require compliance with FERC’s so-called Edgar and Allegheny principles for market-priced wholesales between affiliates.  Earlier in October, ComEd and ExGen had jointly sought FERC’s approval of service agreements and standardized forward contracts that would permit ExGen to make market-priced sales to ComEd in the event ExGen was selected in the auction.  FERC granted that approval based on findings that (1) the auction process was transparently designed through stakeholder collaboration, (2) the auction products — full requirements supply for three size categories of retail customers — were clearly defined, (3) an auction manager alone, independent of ComEd and ExGen, selected winning bids, and (4) the independent auction manager, together with ICC staff will oversee the operation and fairness of the auction.

A number of trends suggest that ComEd’s experience before the ICC and FERC may increasingly become a standard model for wholesale power procurement.  Either in connection with programs introducing retail choice or as a condition on approval of any one of the growing number of utility mergers, traditional utilities are being required to divest some or all of their generation, while still retaining some retail service obligations.  Many will be required by local regulators to demonstrate through auction-like procedures that they are servicing retail customers with the lowest-cost sources of power.  At the same time, to the extent they continue to possess generation in an affiliate and wish to bid into their affiliated utility’s auction, then FERC will require satisfaction of the four Edgar/Allegheny principles to prevent over-priced purchases from an affiliate.  Interestingly, in its rejection of the Illinois AG’s contention that the proposed auction should be scrapped in favor of direct ComEd negotiations with ExGen and other suppliers, FERC emphasized that it “adopted the Edgar/Allegheny principles . . . to avoid the potential for affiliate abuse that could result if affiliates bilaterally negotiated contracts in private direct negotiations.

In light of these trends, there is also likely to develop soon a robust market for independent auction managers.  [FERC Docket No. ER06-43]

FERC has denied Southern Company permission to amend its OATT to limit Southern's liability to transmission customers and third parties for damages ― whether direct, indirect, or punitive ― resulting from service interruptions, except in cases of gross negligence or intentional misconduct.  FERC also denied Southern's proposal to change its indemnification standard to gross negligence. 

Southern's proposal, submitted to FERC last October, contended that the revisions were appropriate in light of FERC's approval of similar limitations on liability and indemnification for the  regional transmission grids operated by the  ISO-New England, the Midwest ISO and the Southwest Power Pool.  In its view, Southern is similarly situated to these organized market entities with respect to liability.  Accordingly, Southern reasoned  that since potentially excessive damage awards for service interruptions are just as likely occurs in a stand-alone utility's  footprint as an RTO footprint, and since neither Southern Co. nor an RTO or ISO can deny service to particular customers based on the risk of potential damages associated with service interruptions to those customers, Southern should therefore enjoy the same protection against damages as does an RTO or ISO.  Southern also pointed out that service provided under its OATT is regulated solely by FERC.  Therefore, liability limits provided by states where Southern operates may not extend to service provided under its OATT.   

In denying Southern's requests, FERC explained that it limited service-interruption liability for RTOs and ISOs since those entities are regulated only by FERC, and would otherwise be subject to liability without limitations under state law.  While FERC acknowledged Southern's statement that liability limits in states where it operates may not apply to service it provides under its OATT, FERC rejected this argument based on Southern's failure to provide evidence to that effect.  FERC also pointed out that it has previously rejected indemnification provision amendments proposed by non-RTO transmission providers (for instance, attempts to change the liability standard from negligence to gross negligence).  

In its proposal to limit its liability, Southern referenced FERC's own stated intention to consider such proposals.  FERC had stated in its 2004 Reliability Policy Statement that it would consider proposals by public utilities on a case-by-case basis to amend their OATTs to include limitations on liability in light of its interpretation in the Policy Statement that a public utility's “Good Utility Practice” encompasses compliance NERC reliability standards and NERC compliance audit recommendations.  FERC had instructed that such proposals should address standards for liability as well as the types of damages for which the public utility may be liable.  The instant Southern order, together with a  recent order preventing Northeast Utilities' from amending its OATT's indemnification provisions, indicates that while FERC may be willing to review a stand-alone utility's proposal, any such utility seeking to cabin its liabilities will face a steep uphill battle.  [Southern Company Services, Inc., 113 FERC ¶ 61,239 (2005)]

State renewable portfolio standards (RPS) are becoming a significant driver of green power development, but the patchwork of different state laws renders it difficult for developers to grasp what opportunities exist in various states and develop a regional or national development strategy.  One region with greater internal coordination than others is New England, and the Rhode Island Public Utilities Commission (PUC) recently helped clarify the picture with its rules on implementation of the state’s renewable energy standard.

In 2007, load-servers subject to the obligation must obtain at least 3% of the electricity they sell at retail from renewable energy sources.  The minimum rises to 16% by 2019.  Eligible generators include wind, solar, geothermal, small hydro-electric, biomass, and ocean energy.  Waste-to-energy technologies are explicitly excluded.  The PUC will certify eligible renewable energy generators.  As in most of the other New England states, load-servers can satisfy their obligation by procuring renewable energy from anywhere within the NEPOOL control area, or from renewable energy delivered into the area. 

The rule also allows load-servers to bank renewable energy certificates for compliance in future years.  Other aspects of the rule reflect potential concern about whether adequate renewable resources will exist to allow compliance with the RPS.  The rule requires the PUC to examine in 2010 whether enough renewable resources exist to meet the increase in the RPS slated for 2011.  A similar proceeding may follow in 2014. 

The rule also provides for an alternative compliance payment of $50 per megawatt-hour (adjusted each year for inflation) to the Renewable Energy Development Fund.  The PUC may also impose sanctions, including revocation of a load-server’s license, for non-compliance with these regulations.

Strange bedfellows, the Interstate Natural Gas Association of America (“INGAA”) and the Natural Gas Supply Association (“NGSA”), together petitioned FERC to initiate a rulemaking to re-examine the parameters of blanket certificate authority and to make clear to the marketplace that shippers who make projects financially possible may enjoy preferential rates.  The petitioners explained that to ensure the adequacy of pipeline infrastructure in the future, FERC must act to make it easier for the industry to build capacity.

Specifically, the INGAA and NGSA suggested that FERC permit blanket authorization for mainline expansions where the expansion meets the dollar limits imposed by FERC's regulations.  The Parties stated that there should be little concern regarding the rate impact of this proposal because the dollar limits would cap the size of the projects that could be completed under the blanket authority provision.  Additionally, according to the petition, because FERC's rules require the posting of available capacity, this guarantees non-discriminatory treatment of new capacity.  Regarding the dollar limits, the Parties proposed that the limits be adjusted to reflect not only inflation, but also specific factors that can have a big impact on pipeline construction costs, such as complex permitting processes and environmental requirements.

INGAA and NGSA also urged that the blanket authorization provision be amended to allow blanket certificate eligibility for certain underground storage enhancements and takeaway facilities for LNG, and that FERC establish a policy that allows for predictable preferential treatment for shippers who underwrite the cost of a new facility through timely commitments.  According to the petitioners, this would allow sponsors and shippers the ability to negotiate without fear that their agreement containing a rate bargain for the foundation shippers will be undone, and would provide a strong incentive for shippers to become foundation shippers.

ISO-New England (“ISO-NE”) and its market participants labored in November to settle ISO-NE's plans for the upcoming winter.  Confronting hurricane-related natural gas shortages, ISO-NE proposed a package of temporary electricity market rules to ensure adequate power supplies in the Northeast in case of extreme cold weather.  In a November 30 order, FERC conditionally accepted these market rules, to be effective from December 1 through March 31. 

The centerpiece of the winter plan will allow the ISO-NE to require generators to “posture” or hold off-line their generation to ensure that these resources can be made available later during peak demand periods.  Generators whose units are postured would receive real-time operating reserve credits.  In an attempt to placate merchant generators' concerns that they would not recover all costs associated with posturing of their facilities, ISO-NE agreed to implement a “hold harmless” mechanism to compensate generators for certain direct fuel costs.  Despite strong protests from some power traders, FERC approved a cost allocation methodology that allocates the costs for posturing resources to all real-time load servers, as opposed to network load.

The winter plan would also eliminate the deviation penalty for emergency energy transactions in which suppliers import power from other control areas.  FERC also agreed to allow some additional flexibility in ISO-NE's electricity bidding rules, and it approved provisions that will permit generators to cope with fuel price volatility by reflecting current fuel costs in their supply offers and adjusting start-up and no-load fees daily rather than semi-monthly, in their bidding.  The bidding provisions faced strong protests by Connecticut Attorney General Richard Blumenthal (D), who argued that giving generators this type of flexibility would encourage them to sell their natural gas rather than using it to generate power.  Finally, FERC approved a supplemental winter demand response program that is designed to attract demand resources and incremental generation not currently registered with ISO-NE.  [ISO New England, Inc, 113 FERC ¶ 61,220 (2005)]

FERC's acceptance of the partial settlement on the winter plan comes on the heels of its acceptance of another ISO-NE proposal aimed at addressing possible cold weather shortages.  In a November 17 order, FERC approved a proposal to modify ISO-NE's “last resort requirement,” which would require generators that are off-line to use good utility practice in responding to requests to return to service from economic outages during cold weather.  In issuing its approval, FERC cited ISO-NE's and the generators' general agreement that de-listed generators have an obligation to return to service during cold weather shortages.  However, FERC denied generators' requests that these units be paid an increased capacity payment for returning to service.  [ISO New England, Inc., 113 FERC ¶ 61,175 (2005)]