Energy Legal Blog

On July 20, FERC issued its Final Rule implementing new transmission pricing provisions, aimed at creating new incentives for transmission investment and signaling an increasingly flexible transmission pricing policy.  After lamenting a sustained lack of investment in an aging transmission grid, in last year's Energy Policy Act of 2005 Congress directed FERC to develop transmission rates sufficient to induce investment.  FERC proposed incentive rates in a Notice of Proposed Rulemaking (NOPR) issued last November.  [See Rule Would Encourage Transmission Investment & Membership in Transcos & Transmission Organizations].  The Final Rule issued last week mostly adopts the NOPR.

Key provisions of the Final Rule include: 

• Incentive rates of return on equity for new transmission investment by public utilities (including both traditional utilities and stand-alone transmission companies, or transcos);
• Full recovery of prudently incurred construction work in progress;
• Full recovery of prudently incurred pre-operations costs;
• Full recovery of prudently incurred costs of transmission facilities that become abandoned or canceled;
• Use of hypothetical capital structures;
• Accumulated deferred income taxes for transcos;
• Adjustments to book value for transco sales/purchases;
• Accelerated depreciation;
• Deferred cost recovery for utilities precluded by retail rate freezes from passing through the costs of new transmission investments; and
• A continuation of the sometimes controversial approach of approving higher rates of return on equity for utilities that join and/or continue to be members of transmission organizations, including (but not limited to) RTOs and ISOs.

Public utilities must still obtain FERC approval to reap the benefit of any of these incentives.  The Final Rule also adopted a reporting requirement requiring public utilities that have received incentive rate treatment for specific projects to submit information regarding the level of actual transmission investment.   

In addition to the new rule, FERC applied it in granting investment incentives to American Electric Power Co. (“AEP”) and Allegheny Energy, Inc., for their proposed projects in the Mid-Atlantic region.  AEP's proposed 765-kV transmission line would stretch 550 miles between New Jersey and West Virginia, while Allegheny's proposed 500-kV line would link southwestern Pennsylvania and Virginia.  For both projects, FERC approved rates of return on equity at the “high end of the zone of reasonableness.”

FERC has adopted a final rule requiring organized electricity markets to offer load servers long-term firm transmission rights (FTR) in existing transmission capacity for a minimum of 10 years [Order No. 681].  In the Energy Policy Act of 2005 (EPAct 2005) Congress directed FERC to implement a new § 217(b)(4) of the Federal Power Act, which obligates FERC to use its authority to meet the “reasonable needs” of load serving entities to meet their long-term service obligations.  The new rule answers that directive and will likely become effective in late August.   

FTRs are used to manage the price risk of congestion charges in organized markets that manage congestion using locational marginal pricing (LMP).   The virtue of LMP is that it allows all generation resources in a market (as opposed to only the system operator’s resources) to participate in redispatch to manage congestion.  The disadvantage is that LMPs are ex post and can be volatile.  An FTR hedges volatility and uncertainty by flowing to its holder congestion revenues that largely (if not completely) offset LMP congestion charges.  Until now, however, FTRs have generally been available only for terms up to one year.   As a consequence, transmission customers in organized LMP transmission markets have been denied long-term transmission price certainty that is otherwise available to network and point-to-point customers in open-access markets.  FERC’s new requirement that all organized markets offer long-term FTRs in existing transmission capacity is directed at curing that deficiency.  This is significant since the absence of firm long-term transmission arrangements have deterred many power customers from committing to long-term power supply arrangements.    

While FERC originally proposed eight guidelines for designing and administering long-term FTRs, the final rule adopts only seven.  Long-term FTRs are to   

·        specify a source, a sink, and a quantity;

·        hedge against day-ahead locational marginal pricing congestion charges or other direct assignment of congestion costs for the period covered and quantity specified;

·        be made available to any party that pays for upgrades or expansions that create the underlying transmission capacity;

·        be offered for terms (and/or with renewal rights) sufficiently long to meet the needs of load-serving entities to hedge long-term power supply arrangements entered into in order to meet a service obligation;

·        be allocated to load servers before customers lacking a load service obligation;

·        be assignable to the successor to a load server; and

·        be allocated initially with no requirement that recipients participate in an auction. 

The operator of an organized market required by the rule to offer long-term FTRs is accorded reasonable discretion to determine how many long-term FTRs it will make available and how many it will instead offer for shorter terms. 

In the one jettisoned guideline, FERC had proposed a preference for load servers with long-term power supply arrangements over those with only short-term power supply arrangements.  Many had objected to that preference on the ground that determining what constituted a long-term power supply would impose an unwarranted burden on the market operator.  FERC agreed and eliminated this preference in favor of a more general preference that makes the long-term FTRs available to all load servers before customers lacking a load service obligation.  In the final rule, FERC also maintained its current practice of requiring that FTRs be made available to those who pay for transmission upgrades or expansions that create the capacity underlying the FTRs, regardless of load service obligation.   

RTOs and ISOs must revise their tariffs in accordance with the new rule within 180 days of the rule's publication in the Federal Register, or alternatively explain how their existing tariffs already satisfy the long-term FTR requirement.  As PJM has already submitted to FERC a proposal for offering long-term FTRs [link to blog article on this], it will now need to review that proposal to ensure it conforms to the seven guidelines of the final rule.  [FERC Docket No. RM06-8]

When FERC actively urged utilities to join RTOs and ISOs, it emphasized the need to end rate “pancaking” ― subjecting transmission customers to multiple transmission charges for long-distance power deliveries.  Pancaking has resurfaced in connection with Louisville Gas and Electric's and Kentucky Utilities' withdrawal from the Midwest ISO.   In its latest order authorizing the withdrawal, FERC emphasized the utilities needed to do more to ensure their municipal customers not become subject to rate “re-pancaking” when the two utilities resume operations outside of MISO.

In a previous order, FERC had conditioned the withdrawal on the utilities taking various steps required by MISO agreements, the utilities’ merger order, open access transmission obligations, and the standards of the Federal Power Act.  FERC did approve allowing the Southwest Power Pool to serve as the utilities’ Independent Transmission Organization, and the Tennessee Valley Authority as their Reliability Coordinator.  In the latest order, however, FERC directed the utilities to amend their open access transmission tariffs to state explicitly that existing customers will receive service subject to the same prices, terms and conditions that they would have received if the utilities had not withdrawn from MISO.  This includes providing transmission and ancillary services at “de-pancaked” rates to a group of Kentucky municipals that rely on the utilities’ transmission service.

While the case is complicated by the merger order that imposed other obligations on the utilities, it suggests that even though RTO membership remains voluntary, FERC intends to ensure the availability of RTO-type benefits, including independent operation of the transmission system and de-pancaked of rates. 

A FERC judge has ruled that the PJM Interconnection should phase out its nearly decade-old practice of setting transmission rates on a license-plate basis — each transmission customer paying a rate that recovers the embedded transmission investment in the zone where it takes delivery of power.  Instead, PJM should phase in transmission rates that charge all customers for use of existing transmission system the same per-unit rate set on a so-called postage-stamp basis because the cost to all is the same (just as a stamp costs the same whether a letter travels across town or across the country).  If FERC affirms the judge, the postage-stamp phase-in will begin retroactively as of April 1, 2006. 

Applying reasoning that should be equally applicable to all regionally operated transmission organizations like PJM, the judge explained that the high-voltage transmission system in such an organization constitutes an integrated network that is equally beneficial to all users who, for that reason, should pay the same per-unit rate.  In contrast, continued use of a license-plate rate in such a network gives a “free ride” to customers who take delivery in an area of low or under investment in the network while overcharging customers located in areas of high or adequate investment.  As a case in point the judge pointed to recent PJM addition AEP whose customers disproportionately have shouldered the cost of AEP’s investments in relatively higher-voltage existing facilities that benefit equally all shippers on the PJM grid.  To prevent “rate shock” to customers currently paying low license-plate rates, the phase-in limits transmission rate increases to 10 percent per year with any costs trapped during the transition deferred for recovery in later years.

Going-forward charges for investments in new transmission facilities will continue unchanged and be allocated directly to the customers for whose benefit the investments are made.  Generally, that means investments associated with new interconnections or services are charged to the interconnecting system or recipient of the new service, while network upgrades will be charged to all users on a postage-stamp basis.

In embracing postage-stamp rates for transmission, which had been championed by FERC’s staff, the judge rejected competing proposals that compared high-voltage  transmission to the interstate highway system, divided into higher-voltage “highways” investment in which would be charged equally to all PJM customer on a postage-stamp basis and into lower-voltage “byways” that would be paid for locally on a license-plate basis.  He also rejected the demands of PJM’s legacy transmission owning utilities and some consumer advocates who sought to perpetuate license-plate rates on the ground that investments in transmission were originally made to provide only local service.  That original purpose is no longer germane, having evolved into an integrated network “where no participant can obtain the benefits of being a part of a wide-scale electricity market without the other participants . . . .”  Although well-reasoned, the judge’s decision is likely to be challenge on appeal to the Commission.  

Following Congress’s passage in June of a compromise bill on the controversial Cape Wind project, the U.S. Coast Guard has jumped into the fray, by developing federal siting standards for the construction of offshore renewable energy projects.  The Office of Navigational Standards is drafting the standards, which are expected to be released sometime this fall. 

The Coast Guard’s authority over siting standards is derived from the June legislation that allowed the 420-MW Cape Wind project proposed to be built in Nantucket Sound to go forward.  Controversial because of safety and environmental concerns, and because it would potentially mar views from affluent Cape Cod, the Cape Wind project had been the object of bitter battles among locals and in the U.S. Senate.  In its compromise bill, Congress gave the Coast Guard the authority to assess the project’s safety, and required the Coast Guard to specify the criteria the Department of Interior will use in evaluating the safety of the Cape Wind project.  (An earlier bill championed by opponents of the project would have empowered Massachusetts governor and presidential aspirant Mitt Romney to veto Cape Wind.)  Although it was tasked only with developing standards for Cape Wind, the Coast Guard, in an expansion of its legislative mandate, decided to develop a uniform and permanent safety assessment regime to be used for all future offshore renewable energy projects. 

Reportedly, the Coast Guard’s standards will focus primarily on navigational safety, including an analysis of the types and sizes of vessels that typically traverse areas surrounding proposed projects, and on protecting marine ecosystems.  The Coast Guard may also require an evaluation of a project’s impact on radar systems.

Adding a distinctive western flavor to the Federal Energy Regulatory Commission, the Senate has approved three new FERC commissioners: Philip Moeller, Jon Wellinghoff and Marc Spitzer.  The new Commissioners' backgrounds includes government service and private sector engagements, but all three have connections to western states: Washington, Arizona and Nevada.  Current Commissioner Suedeen Kelly also hails from New Mexico.  This  westward tilt may signal a commitment to ensure that the western energy markets operate smoothly and not repeat the Western Energy Crisis of 2000-2001.  The addition of the three new Commissioners also will create a full slate of five Commissioners, for the first time in several years. 

Mr. Moeller comes to FERC after serving as the Washington representative for Alliant Energy Corp, and before then served as the energy policy advisor to former U.S. Senator Slade Gorton of Washington.  Mr. Moeller also served for 10 years as the Staff Coordinator for the Washington State Senate Committee on Energy, Utilities and Telecommunications.  He will serve a three-year term which expires on June 30, 2010.

Mr. Wellinghoff is currently a partner with a Nevada law firm.  He was Nevada's first Consumer Advocate and served as staff counsel to the Nevada Public Utilities Commission.  He will serve a one-year term, which will expire on June 30, 2008.

Mr. Spitzer, who has a background in tax law, served in the Arizona State Senate for 8 years before being elected to the Arizona Corporation Commission in 2000.  He will serve a four-year term, which expires on June 30, 2011.