Energy Legal Blog

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.

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. 

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.

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.

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.

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.