Energy Legal Blog

Despite concerns about the paucity of detail in PJM's modified Regional Transmission Expansion Plan (RTEP), FERC has conditionally approved it effective retroactively to September 9 of this year. 

PJM filed the plan in early September, asking FERC to approve a new forward-looking planning process that is driven by economics as well as reliability considerations.  Several interests protested that the plan lacked adequate detail.  For example, it did not disclose when a proposed market solution to congestion could displace a project already incorporated into the RTEP.  Nor did it reveal how PJM proposed to measure market efficiency.  

While acknowledging that the RTEP revisions need fleshing out, FERC enumerated benefits offered by the new process that were absent under PJM's previous approach.  The benefits include its forward-looking planning and “more expansive view” of the planning process.  In particular, the revised RTEP process allows PJM to consider both market-based and rate-based solutions with equal weight when addressing congestion.  It also requires PJM to consider future market conditions when making such decisions.   

FERC directed PJM to clarify various ambiguities in its proposal.  How, for instance, did  PJM propose to evaluate long-term price forecasts and the efficacy of proposals to decongest the grid?  FERC declined to demand that PJM establish a deadline beyond which market solutions can no longer bump projects from the RTEP, and FERC agreed that PJM may continue to allocate the costs of economic upgrades to those who specifically benefit from the upgrades.   

FERC staff will convene a technical conference in the near future to examine the possibility of using demand-response/conservation resources as alternatives or complements to transmission expansion projects and how providers of demand response should be compensated.

Despite all the legislative efforts to beef up California's renewable portfolio standards (RPS) in recent months, the California Energy Commission (CEC) recently disclosed that the state's investor-owned utilities (IOU) are making little progress toward meeting the state's requirements that 20% of power supply must come from renewable energy sources by 2010.  In an draft update to its Integrated Energy Policy Report, released November 17, the CEC concluded that at the current pace, the state will fail to meet the 2010 goal, unless the IOUs take action now. 

According to the CEC, the primary and most obvious reason for the slow pace thus far has been a lack of construction of new transmission capable of  linking green resources with load ― an obstacle reported in other states as well.  In September, the California IOUs indicated to California Public Utilities Commission (CPUC) that they may fail to meet the RPS goals because of the state's limited transmission facilities.  The CEC report also notes that the California IOUs' renewable efforts have been hampered by green projects that have been abandoned or otherwise never began operations.  For example, according to the CEC's report, while the IOUs have signed contracts since the initial passage of the RPS in 2002 for as much as 4,095 MW of renewable capacity, only 242 MW of that capacity are on-line today.  Other obstacles cited by the CEC include:  the complexity of the CPUC's RPS program for IOUs; financing uncertainty; and slow progress in repowering aging wind facilities.

The CEC report also made recommendations to get the IOUs back on track, such as suggesting that the CPUC clarify its IOU RPS program, enforce RPS non-compliance penalties, expedite its review of already proposed renewable projects by Southern California Edison (SCE) and San Diego Gas & Electric, and work with the California ISO to compel SCE to meet the 2010 schedule for its Tehachapi renewable project.  The CEC also recommended that IOUs be required to procure 3% above what the RPS requires in order to compensate for potential contract failure.  The CEC has scheduled a workshop to be held December 7 to receive input on the draft report.

In the latest display of  handwringing after the expiration of long-term retail rate freezes, Delaware has indicated it may re-regulate its electricity markets.  These are more than idle thoughts by the state's government, as a General Assembly resolution requires the state to hire a consultant to study and report on the potential effects of re-regulation of the electric industry.

The interest in re-regulation is based on steep rate hikes for residential and industrial customers in 2006.  These increases, however, follow seven years during which prices were frozen at a reduced level initially prescribed in Delaware's restructuring legislation and then extended in connection with the state's approval of the merger between the parent companies of PEPCO and  Delmarva Power & Light.  This extended rate freeze thus insulated retail customers in Delaware from wholesale price changes. 

The consultant selected by Delaware is to analyze efforts in other states to re-regulate their electric power sectors, and discuss the potential benefits and disadvantages of re-regulation, including the economic costs to the state and the electric power industry as well as the effect on attaining environmental standards.  Responses to the state's request for proposals are due by December 19, 2006, and a contract will be awarded by January 15. 2007.

Considering the controversy surrounding the expiration of rate freezes in Maryland, and the role retail rate freezes had in the California energy crisis, the lesson for state regulators may be to avoid such artificial means of controlling power prices, as they too often simply postpone and distort price signals that should inform investments in generation, transmission, pollution control and other public goods.