Energy Legal Blog

FERC Finalizes Rule Promoting Transmission Investments; Grants Incentive Rates to AEP and Allegheny

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."

Firm Transmission to Be Available for Terms of 10 Years in Organized Markets

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]

No Reverting to Pancaked Transmission Charges, FERC Warns MISO Ex Pats

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. 

All Users of PJM Transmission Grid Should Pay the Same Per-Unit Rate, FERC Judge Rules

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.  

Coast Guard to Set Standards for Offshore Wind Projects

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.

New Commissioners Add Western Tilt to FERC

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.

PJM Gets out Ahead with Long-Term Transmission Rights Plan

The PJM Interconnection has asked the FERC to bless a new program for offering transmission customers long-term financial rights to hedge the costs of transmission congestion.  PJM's proposal ostensibly responds to a February 2006 FERC rulemaking proposal that would require RTOs and ISOs that oversee organized power markets to make long-term financial transmission rights (LTTRs) available to all transmission customers, in accordance with eight general guidelines.  FERC plans to issue a final rule by August 8, 2006, a deadline that Congress mandated in EPAct 2005.   

Under PJM's current transmission rights scheme, transmission risk is hedged with auction revenue rights (ARRs) that are distributed or sold in two tranches.  The first gives preference to historical native load customers; the second stage allocates remaining capacity to network, qualifying transmission customers and other point-to-point transmission customers.  PJM's new proposal would split the first tranch in two.  In proposed "Stage 1A," PJM would offer 10-year some ARRs to network service users and certain other qualifying transmission customers.  "Stage 1B" would continue annual ARR allocations, retaining the priority for historical native load, as well as offering these annual ARRs to network service users and qualifying transmission.  PJM promotes this modified approach as offering flexibility:   Firm transmission customers can choose between the long-term 10-year hedges and the shorter, annual ones.   

Florida and Hawaii Pursue Singular Paths to Efficiency and Self-Sufficiency

Lacking renewable resources available to many other states, Florida is the most populous state without a renewable portfolio standard (RPS).    In lieu of an RPS, a new 4-year, $100 million law, Florida's Renewable Energy Technologies and Energy Efficiency Act, focuses more on incremental development of solar power, subsidizing purchases of energy efficient equipment, and providing technology grants.  The solar program will reduce initial costs for photovoltaic and thermal technology installations on commercial and residential buildings.  The renewable energy technologies grant program will provide matching funds for research and demonstration projects associated with the advancement of alternative fuel vehicles, renewable energy systems and other "next generation" energy technologies, including hydrogen, solar, biodiesel and ethanol.  The legislation also revises siting laws for generation and transmission, and creates the nine-member Florida Energy Commission, which will advise the Legislature on state energy policy based on the principles of reliability, efficiency, affordability and fuel diversity.

Hawaii’s energy situation likewise is unique.  Lacking both connections with the continental grid and a significant level of any indigenous energy resources, it depends heavily on oil imports.  The state already has an RPS.  But of late it has supplemented this with additional legislation intended to promote efficiency, renewable energy, and energy self-sufficiency.  Among many new steps are tax credits for solar and wind energy systems; a "pay-as-you-save" pilot project to provide a financing for purchases of residential solar hot water heater systems; a public benefits fund to support energy efficiency and conservation programs; a requirement that state agencies purchase energy efficient vehicles, install renewable energy devices, maximize usage of energy-saving contracts, and promote the uses of "green building" practices; an amendment to the RPS eliminating guaranteed utility profit provisions and authorizing the Hawaii Public Utilities Commission to penalize utilities for failing to meet the standards, which require 20% of energy to come from renewable sources by 2020; taking steps to develop alternate fuel standards; and other provisions promoting the use of biomass and hydrogen from renewable energy.

ERCOT Develops Renewable Energy Zones

The Electric Reliability Council of Texas (ERCOT) has begun the process of developing competitive renewable energy zones (CREZs) intended to deliver wind power to population centers throughout the state.  The CREZs will identify areas of Texas with the highest potential for wind power development.  Harvest areas of interest thus far include rural West Texas and the Panhandle, as well as in the Rio Grande Valley and along the Gulf Coast.

State law requires the Public Utility Commission of Texas (PUCT) to identify the CREZs.  Lending its technical expertise to the project, ERCOT is working in conjunction with consultants to identify the zones and perform cost-benefit analyses of their generating potential.  ERCOT will also analyze transmission options necessary to connect the various production areas with load centers, as well as initiate a study of ancillary service requirements, such as reactive power.  Once ERCOT completes the various studies, estimated to be in October or November 2006, ERCOT will provide all its data to the PUCT, which will make a final determination of CREZs in early 2007.  Identifying these zones will help Texas achieve its renewable portfolio standard of 5,880 MW of renewable energy online by 2015 [See Texas Ups Renewable Energy Requirements].