Energy Legal Blog

Capacity Market Redesign: New England Settlement Approved, PJM Proceeding Continues

The vexatious issue of how to design electric power capacity markets passed a milestone when FERC recently approved a contested settlement establishing a forward capacity market (FCM) in ISO-New England (ISO-NE).  FCM replaced the controversial locational installed capacity (LICAP) proposal that the ISO-NE had proposed in March 2004.  Fierce opposition to LICAP, primarily from Connecticut, led to protracted negotiations, which culminated in the FCM settlement.  Having received FERC’s approval, FCM will replace the bid-based installed capacity requirement that has been in effect since 1998, but which drew criticism since its inception because it credited capacity that was not deliverable and suffered from other flaws.

Under FCM, ISO-NE will perform forecasts of needed capacity three years in advance of the delivery year and conduct an annual capacity auction to fulfill those needs. The auction will use a descending clock principle.  Suppliers will bid in response to an initial price of twice the cost of new entry for a generator.  If there are bids for more quantity than is needed, the auction administrator lowers the price and solicits another round of bids from suppliers.  When the quantity offered in supplier bids matches the quantity needed, the auction closes and the suppliers receive the price in the final round.  The ISO-NE will conduct its first auction in December 2007.  Generators will be paid for the capacity they sell, subject to (1) not receiving payment if the capacity is unavailable when called upon and (2) offsets for peak energy revenues received (based on those for a hypothetical generator), which is intended to offset payments by load servers for price spikes in the energy market. 

FCM's locational feature will allow prices to differ between import- and export-constrained zones within New England.  A controversial element of FCM is the use of a transition period lasting until ISO-NE fully implements FCM in 2010.  During the transition, generators will receive fixed payments increasing each year.  These fixed payments drew fire from regulators in some New England states who argued that the payments were excessive.  FERC, however, found that the settlement was just and reasonable, as it would help build new and maintain existing infrastructure in New England.  FERC also stated that the settlement conformed to Congress’ directive in the Energy Policy Act of 2005 that FERC consider state objections to the LICAP plan and to evaluate alternatives.

FERC had earlier signaled its favorable reaction to the FCM settlement in another, different approach to capacity market design involving PJM Interconnection’s Reliability Pricing Model.  That design would use a gradually sloping demand curve to price capacity and differentiate prices locationally based on deliverability in the face of transmission congestion.  While agreeing with core components of the plan, FERC urged the parties to attempt to reach a settlement.

Circumscribed Clean Water Act Protections Unlikely to Affect Hydroelectric Regulation

In companion cases, Rapanos v. US and Carabell v. US, a divided Supreme Court cabined Clean Water Act (CWA) jurisdiction, holding that the Act's protections for navigable waters do not extend to four Michigan wetlands lying near ditches or man-made drains that eventually empty into traditional navigable waters.  The CWA prohibits dumping dredged or fill material into “navigable waters” without a permit and defines “navigable waters” as “the waters of the United States, including the territorial seas,”  The Corps of Engineers' regulations implementing this prohibition broadly read "navigable waters" to comprise" tributaries” of such waters, and wetlands “adjacent” to such waters and tributaries.  The Supreme Court held that this construction went too far.  Four justices concluded that waters of the United States include only relatively permanent bodies of water, not intermittent or ephemeral channels.  Justice Kennedy (often the Court's swing vote) concurred, concluding that a water or wetland would be jurisdictional if it possesses a “significant nexus” to navigable waters.  In his view, when the Corps seeks to regulate wetlands based on adjacency to non-navigable tributaries, it must establish this significant nexus on a case-by-case basis. 

Regardless of its impact on the CWA jurisdiction, the Court's ruling is unlikely to alter FERC's interpretation of its mandatory hydroelectric licensing jurisdiction.  In most cases, conventional hydroelectric projects will involve more typical streams, not ditches, man-made drains or other "adjacent" water bodies.  Moreover, in non-conventional cases, such as pumped storage projects using ground water or intermittent streams, FERC has adopted a view that cabins its mandatory hydroelectric licensing jurisdiction consistent with Justice's Kennedy's nexus analysis. 

FERC Proposes Rules for Federal Eminent Domain in National Interest Electric Transmission Corridors

In a June 16 notice of proposed rulemaking (NOPR) FERC details how it proposes to implement its new authority under section 216 of the Federal Power Act, added by EPAct 2005, to issue federal permits for the construction of electric transmission facilities in Department of Energy (DOE)–designated National Interest Electric Transmission Corridors (NIETCs).  Previously, only states could authorize the taking of private property for electric transmission rights of way.  Public comments on the NOPR must be submitted by August 25, 2006. 

EPAct 2005 directed DOE to study electric transmission congestion and designate NIETCs.  Projects slated for NIETCs will receive special attention during review procedures.  DOE expects to finalize this study by mid-August.  [DOE Congestion Study to Identify National Interest Electric Transmission Corridors]  FERC, in turn, can issue permits to construct or modify transmission facilities in any DOE-designated NIETC provided that the state where the facilities would be located lacks the authority to site the facilities (or the applicant does not qualify for siting approval there), or the state either withholds approval for more than one year or attaches unreasonable or uneconomical conditions to its approval.  FERC must also find that the proposed project would be in the public interest, further national energy policy, and be used for interstate power transmission. 

FERC's proposed rule implements both authorities that EPAct 2005 granted directly to FERC and other authorities that DOE has delegated to the agency.  The proposed rule would require permit applicants to establish Participation Plans that facilitate stakeholder (e.g., landowner, local governments) involvement in the permitting process.  In addition, FERC proposes an extensive and mandatory pre-filing process, along the lines of what it requires for natural gas pipeline projects.  FERC intends that the majority of the heavy lifting, including required studies and meetings with other reviewing agencies and designation of at least three potential contractors for preparing environmental impact statements or assessments, be accomplished during this pre-filing process in order to streamline later application preparation.  Monthly status reports required as part of pre-filing, for instance, would carry some bite:  failure to submit a report, respond to a request for more information, or progress sufficiently toward permit issuance would allow FERC to terminate the pre-filing (without prejudice to refiling). 

The proposed rule also details the information FERC would require as part of the application, as well as general conditions that FERC would impose all permits issued under the new rule; specific conditions may be imposed on individual projects.   

FERC has also proposed to modify its rules implementing the National Environmental Policy Act (NEPA) to include electric transmission projects among the activities for which environmental information must be provided to the agency and for which FERC will complete an environmental assessment or environmental impact statement.  In addition, FERC's new NEPA rules would provide for specific environmental filing requirements (resource reports) for electric transmission facilities.   

In an effort to quell any rumbles from state commissions that FERC is overstepping its new jurisdiction, FERC Chairman Joe Kelliher's statements accompanying the proposed rule emphasized the rule's function as a backstop and supplement to state siting processes, to be used only when existing state processes fail to site needed transmission facilities.  FERC plans to issue a final rule by the time that DOE designates the NIETCs.

California to Guarantee Recovery of Transmission Investments Supporting Renewable Generation

The California PUC has approved a new mechanism to ensure that utilities recover their investments in interconnecting and transmitting power from renewable generation.  These investments will be recovered in rates to retail customers. 

The PUC action is based on a broad interpretation of California statutes that the PUC asserts allow it to develop cost recovery methods for transmission that supports renewable power.  California statutes encourage renewables by imposing a Renewable Portfolio Standards (RPS) and encouraging transmission to support renewables.  [See California PUC Proposals Aim to Put Ambitious Renewables Goals in Reach.]  Earlier PUC efforts to promote transmission from renewable generators became entangled in FERC's generator interconnection policies. 

FERC says that generators must pay the costs of generator tie lines and that generators must initially finance transmission network upgrades and then recoup their investment in the form of credits against future transmission charges.  The PUC is concerned that FERC's policy will not result in sufficient transmission for renewable generation, preventing the state from achieving its RPS goals.  This issue takes on particular urgency because of pending disputes over who pays for transmission to a potentially large wind power development in the Tehachapi region.  The wind developers say they cannot proceed under FERC's developer-upfront-payment model. 

The PUC had previously tried to resolve the issue by requiring transmission providers to advance funding for these transmission lines, a position contrary to FERC policy.  That approach was rejected by the California courts as intruding into an area of exclusive FERC jurisdiction.  Then, last year, Southern California Edison raised this issue at FERC.  In response FERC offered as a partial solution guaranteeing recovery of investments in transmission network upgrades, but not in generation tie lines.  [See FERC Denies SoCal Ed Full Approval of Utility's Plan to Add Transmission, Use Wind to Reach RPS Goals]  The California PUC found FERC's partial solution insufficient to meet California RPS goals. 

Against this background, and at the request of the California utilities, the PUC has now adopted a new approach, which seeks to avoid a conflict with FERC.  Rather than requiring the California utilities to advance funds for transmission upgrades, the PUC simply guarantees that Golden State utilities will recover retail charges investments in transmission that are deemed necessary to meet California RPS goals – regardless of whether the transmission is a generator tie line or a network upgrade.  The combination of the RPS standards and guaranteed retail recovery of upfront transmission costs is certain to encourage renewable development and enable the utilities to advance funds for transmission investments.  Since California's three investor-owned utilities and the Cal ISO support this approach, it is likely that the utilities will accept the invitation. 

Entergy's Cost-Based Tariffs Rejected and Set for Hearing

On May 26, FERC rejected Entergy's proposed cost-based tariffs as unclear and confusing.  FERC then set the tariffs for an evidentiary hearing, and directed Entergy to submit a compliance filing resolving identified problems within 30 days.   FERC also rejected were Entergy's proposed cost-based rates for its marketing affiliate, EWO Marketing, because Entergy had failed to support the cost data associated with three of EWO's generators.  FERC, however, did accept Entergy's proposal to allow operating companies to negotiate cost-based rates for short-term transactions up to a ceiling equal to the incremental cost plus a 10% adder. 
 
Entergy initially decided not to pursue renewal of its market-based rate authorization last summer.  [See Entergy Will Not Renew Market-Based Rate Authority.]  In November of last year, the New Orleans-based holding company submitted two cost-based rate tariffs (one for all operating companies and the other for its marketing affiliates), which would apply to all sales of capacity and energy with terms of less than one year.  Entergy's proposed rates would have applied both within and outside its control area.

Volunteers for Green House Gas Reductions Not Volunteering

After determining the U.S. would not participate in the Kyoto treaty on global warming, the Bush Administration pursued other measures to limit climate-warming greenhouse gas (GHG) emissions, including two non-binding programs that US industry could volunteer to participate in.  In 2002, the Environmental Protection Agency offered the Climate Leaders program, and in 2003 the Department of Energy offered the awkwardly named Climate VISION (Voluntary Innovative Sector Initiatives: Opportunities Now).  In a recent report prepared for Senators John McCain (R-AZ) and John Kerry (D-MA), who are cosponsors of legislation that would set mandatory caps on GHG emissions, the U.S. Government Accountability Office concluded that both programs lack leadership and vision, not to mention accountability. 

Both Leaders and VISION contemplate that participants or their trade group representative set goals to reduce either total GHG emissions or emissions intensity (emissions per unit of output) below a base line.  According to GAO, however, as of late 2005, less than half of the 85 participants in EPA’s Leaders program had even set an emissions reduction goal, and only 5 had achieved them.  Moreover, EPA has no position or policy on what the consequences should be for not completing the project step on schedule.   While 14 of 15 trade association participants in DOE’s VISION program have set goals (which are not binding on members), DOE has no standard for determining baseline emissions and no procedures for tracking a participant’s progress toward its goal.  And like EPA, DOE never articulated the consequences for failing to make progress. 

In a paradigm of understatement, GAO opined that “to demonstrate the value of voluntary programs — as opposed to mandatory reductions — the agencies will need robust estimates of the programs’ effect on reducing emissions.”  Neither EPA nor DOE can produce even anemic estimates of emissions reductions. 

What stands out from the GAO report to Senators McCain and Kerry is the sparse participation by electric utilities.  While there are some notable participants, including AEP, PSEG, Entergy and Exelon, from this sector, which is the highest emitter of carbon dioxide, many other major utility emitters do not individually participate in these programs.   Public power may be poised to reverse this poor utility participation with the recent announcement that it has launched a “blue-ribbon, CEO-level task force to study global warming and to develop recommendations for dealing with it.”  It remains to be seen whether this study will result in reductions.

Back to the Vertically Integrated Electric Utility

Connecticut's legislature is deliberating an energy bill that would enable the state’s investor-owned utilities — Connecticut Light & Power and United Illuminating — to own generation once again.  Passage of the bill would signal a retreat from the Connecticut’s 1998 decision to promote power supply competition by severing ownership and control of generation from the monopoly wires businesses of power transmission and distribution. 

The proposed law would direct Connecticut's utility regulators to oversee three requests for proposals (RFPs) to supply the utilities' long-term resource needs.  The first RFP would ask the  electric utilities for at least 500 MW of peaking power plants and conservation measures; the second would open up to other power suppliers the peaking and demand-side requirements not proposed by the utilities; the third would seek non-peaking resources from all sources. 

Proponents of the energy bill contend that it would empower regulators to exercise more control over power supply costs and resulting prices.  In opposition, however, ISO-New England has countered that electric utilities should not re-enter the supply market and that the state should instead rely on the competitive supply market.  That reliance will stimulate more generation development and will concentrate risk on the developers and not customers, according to the ISO.  Other groups have objected that the RFP process as proposed is facially biased in favor of the utilities. 

Developers with state-approved generation projects in the pipeline have suspended further development pending implementation of the region’s proposed forward capacity market. Now that FERC has authorized implementation of that market, whether any of those projects get built may depend on whether the legislation comprising the RFPs is enacted.

What to Do about the High Costs of Organized Market Operators?

Customers aren’t happy with the high and rising operating costs of organized electric markets, including Regional Transmission Organizations and Independent System Operators.  Two recent FERC orders addressing complaints about the costs of the PJM Interconnection and ISO-New England are illustrative of the problem and indicative of its possible resolutions.

In one order PJM and its customers unanimously fixed charges for PJM's administrative costs.  These charges had soared as high as 48 cents per MW-hour in 2003.  In July 2005, PJM encountered howls of protest when it proposed to reduce these charges by only nine cents to 39 cents per MW-hour.  Nearly one year later in April 2006, PJM and its customers presented to FERC a proposed settlement that would further drop operating charges to 33 cents per MW-hour by June 1, 2006, 32 cents per MW-hour by January 1, 2007, 31 cents per MW-hour by January 1, 2008, and 30 cents per MW-hour as of January 1, 2011.  FERC’s approval of this arrangement makes PJM the only RTO or ISO with fixed, long-term rates.  Other RTOs and ISOs typically just pass on their administrative costs through formula rates to their customers. 

Separately, FERC recently reopened an inquiry into ISO-New England’s recovery of certain of its operating expenses.  Late last year FERC had accepted ISO-NE's proposal to recover from customers administrative costs, despite customer objections that the proposed charges inappropriately would recover lobbying outlays not properly chargeable to customers.  FERC initially rejected these arguments, despite acknowledging that it knew of “no clear distinction between educational and informational activities and lobbying activities" and admitting that it was unsure where to draw the line.  But FERC has now decided that ISO-NE must demonstrate in a paper hearing whether costs characterized as “external affairs” and “corporate communications” can properly be charged to customers. 

In tandem, these cases testify to a growing concern and interest in limiting the costs of organized market operators.   Failing that, customers may stop supporting FERC’s promotion of regional, independent system operators.

Court Confirms Hydro Licensees Must Certify for Water Discharges

A unanimous Supreme Court in S.D. Warren Co. v. Maine Board of Environmental Protection upheld the requirement that hydro licensees must certify under § 401of the Clean Water Act (CWA).  CWA § 401 requires a water quality certificate for any activity that would cause a "discharge" into navigable waters.  Warren (the license applicant) argued that § 401 certificates were not required for its multiple hydro projects because the projects only take water from a lake, run the water through a turbine and then return it to the lake.  In Warren's view, this did not amount to a "discharge."  Warren based its position on the high court's interpretation of CWA § 402 in South Fla Water Management Dist. v. Miccosukee Tribe.  CWA § 402 established the National Pollution Discharge Elimination System and requires a permit for the "discharge of any pollutant."  Miccosukee held that pumping water from one part of a water body to another is not a discharge of a pollutant under § 402, and Warren sought to extend that reasoning to § 401.  The Supreme Court rejected Warren’s attempted extension.  According to the court, § 402 and § 401 are not interchangeable and § 402's term "discharge of a pollutant" is narrower than § 401's term "discharge." 

This is fairly settled § 401/hydro licensing law.  Although § 401 does not define "discharge," and although the precise question raised by Warren had not yet been addressed, FERC, EPA, and the various state Water Quality Certification Entities have all long considered releases from hydro dams as discharges implicating § 401.  In fact, FERC will not issue a hydro license without a § 401 certificate or waiver.  By holding that Miccosukee does not limit the scope of § 401, the Supreme Court provided greater clarity on these issues.

Kentucky PSC Allows Utilities to Leave Midwest ISO

The Kentucky PSC has cleared the way for Louisville Gas & Electric (LG&E) and Kentucky Utilities (KU) to withdraw from Midwest ISO (MISO), [Kentucky PSC order], granting its approval of the utilities' request on May 31.  FERC approved the withdrawal earlier this year [LG&E and KU Ask to Leave MISO; MISO Defections ― Do They Signal a Sea Change at FERC on RTO Membership?].  The utilities plan to move ahead with an alternative transition management plan, dubbed the "transmission owner reliability coordination option," under which they will contract for services rather than join another transmission group.  The Tennessee Valley Authority is lined up to act as the utilities' reliability coordinator, while the Southwest Power Pool will administer their open access transmission tariffs, effectively acting as the independent transmission coordinator.   

The Kentucky PSC based its decision on several cost-benefit analyses submitted by both the MISO and the utilities; the PSC determined that the utilities' analysis' assumptions and inputs were more reasonable.  The PSC also determined that the utilities should not be required to hold harmless any retail customers from additional costs incurred after their exit from MISO, and agreed with the utilities that their participation in MISO had decreased the PSC's regulatory authority.   

PSC Chairman Mark David Goss dissented from the decision.  He argued that Kentucky should cooperate with what he characterized as "inevitable electricity policy" ― regulation of electric power on a regional basis, reflecting the growing presence of MISO and PJM.  He also warned against the potential loss of the utilities' market based rate authority, and the impact this might have on sales revenues.  His concerns indicate where battle lines may be drawn in future cases involving utilities' attempts to exit ISOs and RTOs.

FERC Certifies that Hydro Facilities Qualify for Tax Credit

On May 31, FERC issued to PacifiCorp the Commission's first certification of increased hydroelectric power production under EPAct 2005, a necessary step in obtaining a renewable energy income tax credit.  EPAct 2005 provides such a tax credit for certain efficiency improvements or additions of capacity to existing hydroelectric facilities.

Under the FERC licensing process, capacity additions and efficiency improvements are different.  A capacity addition would ordinarily require amending the FERC license, because it would change the project capacity authorized under the license.  In contrast, an efficiency improvement might only involve a repair with more efficient equipment, and so ordinarily would not require a license amendment.  But, while FERC licensing treats the two differently, the tax code treats them similarly.  Either the addition or the improvement could increase power production, and either can qualify for the tax credit.  Moreover, the addition or improvement qualifies for the tax credit if it is placed in service between August 8, 2005 and January 1, 2008.  What controls is the in service date and it does not appear to matter when FERC approved the addition or improvement. 

To qualify for the tax credit, the taxpayer/licensee must obtain FERC certification of the increased power production due to the improvement or addition.  To obtain FERC certification, the applicant must submit:  (1) data about the project's historic average annual hydropower production baseline; (2) supporting calculations and water flow data; and (3) information regarding the efficiency upgrade or capacity addition. 

PacifiCorp, licensee of the Klamath Project No. 2082, did just that.  In November, 2005, PacifiCorp added a runner replacement; then in March 2006, it provided FERC with supporting calculations showing the increased power production due to that replacement.  FERC accepted the calculations and gave PacifiCorp the certification needed to filed for the tax credit.  FERC also said it would act on future certifications by delegated order. 

California PUC Proposals Aim to Put Ambitious Renewables Goals in Reach

California has one of the nation’s most ambitious renewable portfolio standards (RPS).  It requires the state’s utilities to procure 20% of their electric power from renewable resources by 2010.  Gov. Schwarzenegger has suggested raising this level even higher.  However, administrative complexities, transmission shortages (particularly in the wind-rich Tehachapi region), and other issues have slowed utilities' progress toward these goals.  With a series of decisions in late May, the California Public Utilities Commission (CPUC) hopes to accelerate RPS compliance.

The CPUC approved 2006 renewable energy procurement plans for PG&E, San Diego Gas & Electric and Southern California Edison.  In a decision with uncertain impact on independent renewable energy developers, the CPUC also encouraged the three large utilities to build their own renewable capacity. 

The CPUC also initiated a new rulemaking to address the annual RPS procurement cycle, reporting, compliance, and enforcement, as well as standard contract terms.  This rulemaking, however, would not resolve the issue of the use of renewable energy credits (RECs).  The state does not allow RPS compliance through trading and purchases of unbundled RECs (RECs sold separately from the energy produced by a generator).  The agency did, however, approve a proposal allowing delivery of the renewable energy anywhere in the state; previously renewable energy had to be delivered to the applicable utility’s service area to be credited toward RPS compliance.  This change should help facilitate renewable energy transactions.

Constellation Merger and Rate Increase in Jeopardy

Constellation Energy Group announced on May 31 that it has stopped the planning and integration process that it had undertaken to prepare for its proposed merger with FPL Group.  Constellation cited as reason for the delay the political climate in Maryland, where consumer advocate groups, members of the Maryland General Assembly, and others have voiced strong opposition to the merger that would occur at the same time Constellation-affiliate Baltimore Gas & Electric (BG&E) and other Maryland utilities implement significant retail rate increases.  See Constellation-FPL Merger Snags in Maryland.  Constellation did not give any indication when or if the merger integration process would begin again, which may signal the beginning of the end for the Constellation-FPL alliance.

In a related development, on June 2, a Maryland Circuit Court rejected a plan to phase in BG&E's proposed 72% rate increase over a 12-month period, as proposed by the company and Maryland Governor Robert Erhlich.  Rejecting the Maryland PSC's April 28 order, Circuit Court Judge Albert Matricciani ruled that the PSC had failed to consider the plan and had not allowed sufficient time for interested persons to intervene.   He sent the plan back to the PSC for a full administrative hearing.  It is unlikely that the PSC will be able to conduct a full hearing by its July 1 deadline for the rate increase.  In place of the rejected phase-in plan, Judge Matricciani directed that the PSC could either extend the retail rate cap or enforce its March 6 order, which would limit BG&E's increase to 21% and allow the company to recover any under-collected revenue over a two-year period.  In response, the PSC indicated it would not defer the end of the rate caps past July 1, which it viewed as ultimately more expensive for consumers and more likely to lead to protracted legal battles.  Its only option is thus to enforce its March 6 order. 

Proposed FERC Rule would Modify, Streamline Test for Market-Based Rate Authority

Two years after undertaking an evaluation of the adequacy of its procedures for granting market pricing authority only to sellers found to lack market power, FERC has finally proposed a rulemaking on the subject.  In April 2004, FERC put in place an interim market power analysis comprising two screens, and implemented a policy on market power mitigation.  The proposed rule would, for the most part, codify the interim analysis.  Changes proposed in the rulemaking relate more to the organization of the market power analysis and the procedures for submitting triennial reviews than to the substance of the analysis itself.    Public comments on the rulemaking must be submitted to FERC in early August, depending on when the proposed rule is published in the Federal Register. To read a complete summary of the NOPR please click here.