Energy Legal Blog

Divided FERC Affirms Primacy of Contract in Proposed New Regulation

In a December 27 rulemaking, two of three sitting FERC commissioners propose to eliminate the agency’s regulation in effect since 1963 that requires the parties to contracts subject to its Natural Gas (NGA) or Federal Power (FPA) Acts’ jurisdiction to include in their agreements prescribed language indicating whether they intend the seller to have the right unilaterally to change the rate or other material terms of their agreement.  In lieu of that requirement, a new rule would require only that the contractual parties state in their contract whether it is their intent that any unilateral proposal to change their agreement be allowed to take effect if shown to meet the just and reasonable standard of the NGA and FPA.  Absent expression of this intent, contracts other than pro forma transmission or transportation agreements will be interpreted as not authorizing unilateral changes unless the proposed change is shown not only to be just and reasonable, but also shown to be demanded by the greater public interest.  To be considered, public comments on this proposed change must be filed with FERC within 30 days of publication in the Federal Register — most likely early February.  If adopted in a final rule, the new rule of contract interpretation will apply to all non-form contracts executed 30 days or more after publication of the final rule in the Federal Register.

The proposed rule reflects the fact that, unlike common carrier regulation under which a tariff rate for a service is the only lawful rate for that service, the NGA and FPA implement a contract carrier form of regulation under which contracts (and not uniform tariffs) often establish the rates and terms of service in the first instance.  Interpreting these regulatory regimes, nearly 50 years ago the Supreme Court articulated the so-called Mobile-Sierra doctrine that bars FERC from unilaterally changing a contract rate and term under the NGA and FPA unless the change is required by the public interest.   Consonant with contract carriage and the Mobile-Sierra doctrine, it follows that the parties to a contract can agree to permit or to bar unilateral modifications to their bargains, and that, absent such an agreement, the default should be no unilateral changes to contracts under the NGA and FPA other than standard tariff service agreements for transportation and transmission.

Although sensible in the context of contract carriage, the proposed new rule will nevertheless engender controversy and criticism.  Exhibit A is the strongly worded dissent of FERC Commission Kelly.  By making no unilateral change — i.e., the public interest standard — the default, the majority, in Commissioner Kelly’s opinion, “turns the statute on its head.”  In the event of contract silence, she would have made just and reasonable the standard for unilateral changes, especially in instances where it is FERC itself or an interested non-party to the contract that is proposing the contract modification.  [Standard of Review for Modifications to Jurisdictional Agreements, 113 FERC ¶ 61,317 (2005)]

Mergers, Acquisition and Transmission Management Plans Sail through FERC

In stark contrast to the protracted merger proceedings of recent years, FERC approved MidAmerican Energy Holdings’ acquisition of PacifiCorp, and the merger of Duke and Cinergy, with no strings attached and only five months after the proposals were filed with the agency.  At the same meeting, FERC also affirmed its previous approval of the contested PSEG-Exelon merger.  Concurrently, FERC blessed MidAmerican's and  Duke’s proposals to hire independent operators for their transmission grids, but these measures were not a condition of the utilities' respective mergers. 

Not more than a few years ago, FERC routinely leveraged its gatekeeper control over mergers to force merger applicants to take other steps to the agency’s liking.  A favored step of late was requiring the utilities to join an RTO, which FERC required of AEP when it acquired CSW.  But FERC did not use it leverage in connection with these latest transactions.  None was even set for evidentiary hearing.  Exelon and PSEG had chosen to be proactive regarding any market power concerns and had proposed divestiture of generation, but the other applicants did not take this step.  They proved to be right, as FERC was satisfied that none of these transactions would harm competition, rates or regulation.  However, these utility mergers still require authorization from other regulators, including affected state regulators.

FERC separately approved Duke and MidAmerican's proposals to hire independent transmission coordinators to perform open-access transmission functions, including calculation and posting of total and available capacity, processing of transmission and interconnection service requests, operation of the OASIS, and coordination of transmission planning.  The utilities would retain other authority, however, including the setting of prices for transmission services.  FERC approved both proposals because it found they would increase transparency in the provision of transmission services.  FERC accepted Duke's proposal without condition, and MidAmerican's proposal subject to further steps by the utility.

FERC's approval of these proposals demonstrates its retreat from its policy under previous chairmen of encouraging participation in RTOs or ISOs.  Neither Duke nor MidAmerican is a member of an RTO or ISO and it would seem unlikely that either will join one soon.  Instead, they appear to be following the lead of Entergy, a forceful opponent of RTOs, which developed the independent transmission coordinator concept as an alternative to RTO or ISO participation.  The Entergy proposal went further than the latter two, however, as it also surrendered transmission pricing to the entity.  The common denominator of these proposals is that they eschew creation of organized, short-term energy or capacity markets, which have been a hallmark of RTO’s and ISOs, and which arguably increase competitive opportunities for power sellers and marketers.

Notably, Entergy has proposed hiring the Southwest Power Pool, an RTO, to serve as its ICT.  Duke would use Midwest ISO, another RTO, while MidAmerican has yet to select an entity.  See Duke Energy Asks FERC to Approve MISO as ICT for Duke Facilities; Entergy and SPP Come to Terms on ICT Agreement.  It will be worth monitoring to see whether these affiliations will mature into membership over time in the absence of merger conditions or other directives.

FERC Finalizes Wind Interconnection Standards

Wind developers and the transmission providers with whom they interconnect now have greater certainty regarding technical interconnection standards.  FERC's order comes several months after the North American Electric Reliability Council (NERC) had challenged FERC’s final rule regarding large wind plants' low-voltage ride-through capability, supervisory control and data acquisition (SCADA) capability, and maintenance of a certain reactive power factor.  NERC had argued that the earlier low-voltage ride-through standard, which requires generators to stay online for a specified time and at certain voltage levels when there is a disturbance on the transmission system, would have reduced the reliability of the electrical grid.

Following NERC's objections, the American Wind Energy Association (AWEA) and NERC negotiated a settlement that formed the basis of the standards that FERC has how adopted.  See AWEA and NERC Settle Reliability Dispute.  These provide for a transitional period for qualifying wind generators, requiring them to ride through low-voltage events down to a voltage of 0.15 per unit for normal clearing times up to a maximum of nine cycles.  After the transition period, wind generators would have to ride through low-voltage events down to a zero voltage level for location-specific clearing times up to a maximum of nine cycles, after which the generator could disconnect if necessary.  Despite objections from various parties, FERC let stand its conclusion from the previous order that wind generators must meet specified reactive power standards only if the transmission provider shows it is necessary to ensure the safety or reliability of the transmission system. 

Other battles remain for the wind energy industry, including the potentially seminal FERC proceeding exploring potential changes to its pro forma open access transmission tariff.  Wind energy interests are advocating for more flexible use of the grid to accommodate wind energy, while various other interests object to what they call preferential treatment for wind.  But a precedent may be established in the instant rule, as FERC stated it "is necessary to recognize the technical differences between wind plants and traditional plants to ensure that the entry of wind generation into markets is not unnecessarily inhibited." 

Of some concern for wind interests, however, is the partial dissent of Chairman Kelliher in this order.  He argued that exempting wind generators from the power factor standard applicable to other generators might threaten reliability and constituted an "undue preference" for wind generators. [Interconnection for Wind Energy, 113 FERC ¶ 61,254 (2005) (Order 661-A)]

Mass. Governor Announces New Carbon Dioxide Emissions Reduction Plan

After pulling out of the Regional Greenhouse Gas Initiative (RGGI) earlier this month, Massachusetts Gov. Mitt Romney (R) announced that the Bay State would pursue its own new carbon dioxide emissions (CO2) reduction plan.  The reductions go into effect January 1, 2006, but power generators will not be required to comply until 2007.

In particular, the plan targets Massachusetts' six oldest coal- and oil-fired power plants.  It calls for generators to cap emissions at 1997-99 levels, and includes a production limit of 1800 pounds/MWh.  The Governor's plan allows generators to meet limits by finding offsets in the Northeast region.  Additionally, the plan provides a "safety valve" meant to guard against excessive price increases:  If the price of available offsets reaches $6.50/ton for 12 months, then the generators would be able to shop for offsets anywhere in the world, and if the price reaches $10/ton, they could meet their obligations by paying into a new Greenhouse Gas Expendable Trust.  The money in the trust would be used to invest in CO2 emission offset projects.  The plan also includes reductions for sulfur dioxide, nitrogen oxides, and mercury.

Gov. Romney's intent is to work side-by-side with the RGGI, which is an emissions reduction work-in-progress of nine Northeastern states, and includes a cap-and-trade system, without price caps.  The Governor explained that if Massachusetts joins the RGGI,  its regulations could be modified to act in coordination with RGGI's plan.  However, critics of the Governor's plan claim that it is not compatible with the RGGI plan, and that the RGGI plan would better protect ratepayers by auctioning allowances and using the money for energy efficiency improvements, instead of allowing plant owners to avoid pollution reductions by paying a fee.

FERC Strives to Make the Costs of RTO Membership Transparent

Responding to complaints that the cost of joining an RTO or ISO  is too high or unknown, on December 15 FERC issued Order No. 668, which will revise its Uniform System of Accounts and financial reporting requirements as they are used to publish the capital and operating costs of RTOs/ISOs and the cost to public utilities of  RTO/ISO membership.  In a statement, FERC Chair Joseph Kelliher promised that the rule "will make RTO costs more transparent and enable a cost comparison among RTOs, as well as between RTOs and traditional public utilities" transmission operations.  He also vowed to take additional steps if needed to achieve greater transparency.  The new rule joins other recent FERC proceedings intended to make RTOs and independent transmission organizations more palatable to utilities and their customers.  See Rule Would Encourage Transmission Investment & Membership in Transcos & Transmission Organizations.

The increased disclosure of expenses required by Order No. 668 is aimed at helping regulators ascertain a utility's RTO costs and determine whether they are excessive.  One of the primary criticisms of RTOs has been that the associated costs are too high or are not transparent.  These concerns have prompted some utilities to pull out of existing RTOs/ISOs.  See We Gotta Get Out of this Place: LG&E and KU Ask to Leave MISO.   FERC Commissioner Nora Brownell approached the issue from a different perspective, however, when she suggested that if RTOs/ISOs are taking on increasing responsibility for transmission grid and wholesale market operations, then the question might not be why are their costs increasing, but rather why aren't the costs of traditional utilities decreasing since the RTO or ISO is performing operations that they formerly did.

Order No. 668 establishes new capital and operating expense accounts to record what RTOs/ISOs bill their members and a separate accounts for expenses incurred in managing and monitoring regional market activity.  The new rule also provides for the recording of regional transmission and market operations, as well as new schedules for quarterly and annual financial reports for reporting revenues collected by RTOs.  The rule also provides utilities with several new sub-accounts, including three sub-accounts in which to record their share of costs billed to them by RTOs and a new revenue sub-account to record revenue received for providing transmission services.    The amended regulations will become final 30 days after publication in the Federal Register, likely sometime in late January or early February, and the accounting and financial reporting changes and updates will become effective on January 1, 2006.  [Docket No. RM04-12]

BLM Establishes Wind Energy Development Program

Implementing a recommendation of the President's National Energy Policy Development Group that federal agencies work to increase renewable energy production, last week the Bureau of Land Management (BLM) established a Wind Energy Development Program (Program) to promote wind energy generation on federal lands.  The Program purports to strike a balance between streamlining processes for the development of wind energy resources and protecting public lands’ wildlife and scenic resources.   

Finalized after numerous stakeholder meetings and rounds of comments over two years, the Program will administer the development of wind resources in 11 western states that jointly host vast wind energy potential:  Arizona, California, Colorado, Idaho, Montana, Nevada, New Mexico, Oregon, Utah, Washington and Wyoming.  BLM's management strategy for the Program consists of policies, which map how BLM will administer the Program and identify best management practices (BMP) for mitigating environmental impacts.  These policies and BMPs will apply to all wind energy development projects on BLM-administered public lands.   

The policies identify certain lands where wind energy development will not be permitted.  These include Wilderness Areas, National Monuments, Wild and Scenic Rivers, and National Trails.  Thy also establish requirements for public involvement, consultation with other federal and state agencies, and government-to-government consultation; explain how project-level environmental review will occur; require entities seeking to develop wind energy projects on BLM-administered public lands to propose a project-specific Plan of Development (Plan) that incorporates all the BMPs; and require project operators to consult with BLM and other agencies on planned upgrades and to develop programs to monitor environmental conditions.  The BMPs, on the other hand, will be adopted as required elements of project-specific Plans or as conditions on right-of-way authorizations.  BMPs address various development activities, from site monitoring and testing, Plan development, and construction to operation and decommissioning.  The BMPs for project-specific Plan development identify required mitigation elements of the Plan needed to address potential impacts associated with subsequent phases of development, and consider impacts to wildlife, visual resources, noise, cultural and historic resources, and human health and safety. 

New Wholesale Power Procurement Model Emerges: All-Source Auctions

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 Pares Back Accounting & Record Keeping, but Retains Strict Transfer Pricing for Public Utility Holding Companies under PUHCA 2005

FERC Denies Southern Co. Limited Liability Provision in OATT

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)]

Rhode Island Regulators Implement Renewables Law

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.

Producers and Pipelines Team Up to Urge Changes in Natural Gas Infrastructure Development

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.

Cold Weather Package Ready for New England

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)]

DOE Report Questions Criteria for Commitment & Dispatch; Wary of Efficient Dispatch

The Department of Energy recently released The Value of Economic Dispatch, a report required by the Energy Policy Act of 2005 (EPAct 2005) that studies the economic dispatch procedures that electric utilities currently use.  In the Report, while DOE does identify potential improvements to those procedures and analyzes the benefits to be gained from implementing those improvements, the Report raises more questions than it answers.  Further, in the course of producing the report, DOE expanded on its EPAct 2005 charge to sound a cautionary note on replacing economic dispatch with efficient dispatch. 

To fulfill the EPAct 2005 mandate, DOE first established a new Office of Electricity Delivery and Energy Reliability (OEDER), which initiated the study by issuing a questionnaire to stakeholders.  The questions ranged from what types of economic dispatch procedures are used in various regions and whether those procedures vary by type of generator.  Targeted questions probed how procedures could be changed to encourage participation by non-utility generators (NUG) and asked what the effects, including effects on reliability, increased NUG participation might have on power grid operations. 

The results of the study highlighted the divergent views of traditional utilities and NUGs on the efficacy of economic dispatch.  Utilities contended that the existing economic dispatch procedures are appropriate and often mandated by state regulators or governing boards.  The utilities defended their procedures as minimizing total production and explained that this may result in a NUG not being committed or dispatched even when its short-run variable costs are lower than units that are committed and dispatched.  The utilities were at best opaque in their explanation of how dispatching units with higher variable costs or rejecting relatively lower price offers minimizes cost to ratepayers.

For their part, NUGs complained that economic dispatch procedures used by utilities discriminate in favor of utility-owned generation.  This disagreement prompted DOE to a focus on the real issues:  What considerations other than transparent measures of cost or offering price are being used in the unit commitment and dispatch process?  Are those considerations legitimate or simply interjected to bias the outcome?  Noting the unlevel playing field on which NUGs play in relation to utilities that control the dispatch process, DOE recommended that the FERC-State Joint Boards on Economic Dispatch as well as FERC's ongoing Order No. 888 review take up these important questions, which are posed but unanswered in the Report. 

Taking the report beyond the goals set for it by EPAct 2005, and responding to recent Congressional interest in efficient dispatch as a means to counteract high natural gas prices anticipated for this winter, DOE expressed skepticism.  Without detailing what is meant by efficient dispatch as opposed to economic dispatch, the Department posited that if efficient dispatch modifies economic dispatch, and economic dispatch already produces the lowest cost power supply, then what is the added benefit of efficient dispatch.  One leaves this discussion wondering whether the distinction is semantic only.  DOE also punted this debate for resolution by future FERC-State Joint Boards on Economic Dispatch.

Two Paths to a Future Powered by Integrated Gasification Combined Cycle

Both California and Pennsylvania recently put forward energy plans that are likely to speed implementation of highly efficient and low-polluting technologies for generating electricity from gasified coal.  The 2005 Integrated Energy Policy that the California Energy Commission ("CEC") adopted at the end of November would indirectly have this effect by requiring the Golden State's utilities to procure power only from generating stations that meet Governor Schwarzenegger's (R) greenhouse gas ("GHG") performance standards, which integrated gasification combined cycle ("IGCC") units can but traditional coal-fired plants cannot.  Fast on the heals of the CEC Policy, Pennsylvania Governor Rendell (D) unveiled his Energy Deployment for a Growing Economy ("EDGE") initiative to provide low-interest loans for IGCC units and a moratorium on required pollution controls on existing coal-fired plants whose owners commit before 2007 to install IGCC by the beginning of 2013.  The Rendell proposal likely will require Environmental Protection Agency ("EPA") approval of the moratorium on pollution controls at existing plants as that would extend by two years the 2010 emission reduction directive of EPA's recently announced Clean Air Interstate Rule ("CAIR").

California is the 6th largest economy in the world and the 17th largest emitter of GHG.  Every two years the CEC updates California's energy plan.  The 2005 plan imposes on utility power procurements the GHG performance standards that Governor Schwarzenegger established last June.  Those standard aim to reduce GHG emissions to 2000 levels by 2010, to 1990 levels by 2020, and to 80 percent of 1990 levels by 2050.  These standards effectively rule out procurements from traditional coal-fired plants and cast into doubt the viability of several dozen non-IGCC coal-fired projects (including some under construction) that are designed to serve the enormous California market.  Another project targeted to the California electricity market, the 1,300-mile Frontier transmission line that would link Powder River Basin coal deposits in Wyoming with California, may also be jeopardized by implementation of the GHG performance standards.

Because the capital cost of an IGCC plant runs 20-plus percent higher than for a traditional coal-fired unit, some have predicted that, in order to access the abundant coal reserves in the west, California would likely need to invest in some early IGCC plants to help demonstrate and establish the technology.  But then comes along the Pennsylvania initiative.  If it garners EPA buy in, EDGE could provide precisely the stimulus that IGCC requires, not only in Pennsylvania and California, but also in other markets with abundant coal reserves.   The program will give new and retrofit IGCC projects priority access to nearly $ 1 billion in low-interest loans form the Keystone State's Economic Development Financing and Energy Development Authorities.  Two of the leading IGCC technology providers, General Electric and Shell Oil, have committed to Governor Rendell that they will guarantee the performance of their equipment in connection with the EDGE program.

Nearly 10 percent of Pennsylvania electric generation capacity is coal-fired units that will need to discontinue operations or invest in costly pollution controls beginning in 2010 under CAIR.  [See Maryland Governor Proposes Plan to Reduce Plant Emissions] Each of these will be a candidate for conversion to IGCC under Governor Rendell's initiative.  When coal is gasified pollutants can be removed more economically and efficiently than they can be removed from the pulverized coal burned in traditional plants.  IGCC plants also emit significantly less carbon dioxide, the GHG principally responsible for global warming.

Maryland Governor Proposes Plan to Reduce Plant Emissions

Earlier this month, Maryland Governor Erlich (R) proposed the Maryland Clean Power Rule ("MCP Rule"), which would mandate constant emission controls and greatly diminish nitrogen oxide (NOx), sulfur dioxide (SO2) and mercury emissions from Maryland power plants, years ahead of the U.S. Environmental Protection Agency's Clean Air Interstate Rule (CAIR) and Clean Air Mercury Rule.  Under the MCP Rule, by 2010, NOx emissions would be reduced by 45,000 tons per year (69%); SO2 emissions would be reduced by 205,000 tons per year (85%); and mercury emissions would be reduced by 1,400 pounds per year (70%), with a second phase of controls reducing mercury emissions by 90% by 2018.  The limits imposed by the MCP Rule also would help cut fine particulate matter emissions and help the state to meet federal standards, as called for in CAIR by 2010.

The MCP Rule's emission limits would have the biggest impact on Maryland's six largest coal-fired power stations, three of which are owned by Constellation Energy and three by Mirant. According to the Governor's office, these six stations produce 95% of the state's power plant emissions.   Under the MCP Rule, plants would have to add pollution controls to meet the emission reductions instead of buying out-of-state emissions allowances.  Companies would be permitted to average emissions among their plants, but would not be able to trade with other companies.

The MCP Rule is expected to be published in the Maryland Register sometime in early 2006 and hearings on it will be held in the spring by the state's Department of Environment.