Bonneville Holding Transmission Open Season to Speed Interconnections

Transmission providers and customers alike are increasingly complaining about the lengthy queues for interconnecting to the transmission grid.  Scores of generator projects sign up for interconnection service, which is then delayed for years while the transmission provider conducts an array of studies.  To clear backlog on its transmission network, the Bonneville Power Administration is conducting a Network Open Season for transmission service that asks customers to commit to the transmission service they are seeking. 

At present BPA’s transmission queue includes requests by 25 customers for approximately 180 applications for transmission service totaling about 8,500 MW of new capacity, but BPA states that many of these service requests are speculative.  Under its new procedure, BPA will give all customers applying for transmission service by May 15, 2008, a precedent service agreement.  If a customer signs the binding agreement and remits the required financial security by June 16, 2008, BPA commits to providing the service, so long as it can provide the service at its rolled-in rate and complete its environmental study obligations.  BPA also will assume the study costs itself and arrange financing for any required transmission facilities, instead of requiring customers to front these costs.  However, if a customer declines the offer, BPA will withdraw its service requests from the transmission request queue, while allowing the customer to participate in future Network Open Seasons.

In December 2007, the Federal Energy Regulatory Commission held a technical conference focusing on transmission queue logjams.  The interconnection queue process is governed by Order No. 2003, which standardized the agreements and procedures related to the interconnection of large generating facilities based on a first-come, first-served process.  However, the surge of new generation projects, including many based on wind and other forms of renewable energy, have led to long interconnection queues that transmission providers are now debating how to expedite. 

Southern California Edison Asks FERC to Step into Arizona Transmission Siting Dispute

In the first test of the "backstop" transmission siting authority given to FERC in the Energy Policy Act of 2005 (EPAct 2005), Southern California Edison (SCE) recently discussed with FERC staff the siting of a 230-mile, 500 kV transmission line from the Palo Verde nuclear plant near Phoenix, Arizona to Devers, California, near Palm Springs (known as the Palo Verde-Devers II Line).  SCE representatives met with FERC staffers to begin a "pre-filing" consultation process in advance of filing an application for FERC to approve the proposed siting of the line. 

California covets the line as a means to bring more power into the state, and the California Public Utilities Commission (CPUC) approved the line.  However, SCE's plans hit a obstacle at the Arizona Corporation Commission (ACC).  The ACC rejected SCE's application in May 2007, stating it refused to allow SCE to plug a "230-mile extension cord" into Arizona's generation supply.  The ACC found the line would cost Arizona ratepayers $242 million, could have detrimental environmental impacts, and would significantly reduce available generation in the state, which has a rapidly growing population. 

Arizona's rejection of the line will test the extent of FERC's authority under the national interest electric transmission corridors (NIETC) provisions of EPAct 2005.  Under these provisions, Congress gave FERC authority for the first time to approve, in certain circumstances, the siting of transmission lines in areas of congestion, designated as NIETCs by the US Department of Energy.  These circumstance include when a state public utility commission has "withheld approval for more than 1 year" after a siting application is filed.  In a controversial 2006 rulemaking decision, FERC interpreted the word "withheld" in the statute to mean "deny," indicating that FERC believes it has authority to approve siting of a transmission line even when a state has rejected the line.  This order has been appealed to the US Court of Appeals for the Fourth Circuit.

Following the meeting with SCE, FERC emphasized that no application has yet been filed.  FERC also contacted the CPUC and ACC to inform them of the meeting and seek their input as to whether FERC has authority in this case.  If SCE eventually files an application, FERC will review the records developed before the CPUC and ACC, coordinate actions required by federal law, including federal environmental review, and conduct an independent evaluation.  FERC must issue a decision within one year of the filing of the application.

FERC Tweaks Open-Access Reforms in Order No. 890-A

In late December FERC issued Order No. 890-A, clarifying and modifying the reforms it made in Order No. 890 to open-access transmission requirements originally established by Order Nos. 888 and 889 and revising the associated pro forma open access transmission tariff. 

In the primary clarifications and modifications, FERC:

• affirmed a tiered approach to calculating energy and generator imbalance charges, while revising the calculation itself:  imbalance charges should be based on the last 10 MW dispatched by the transmission provider for any purpose, rather than the last 10 MW dispatched to serve native load;
• affirmed lifting the price cap on reassignments of transmission capacity for all transmission customers through October 2010 (though the price cap lift may be extended based on a required FERC staff report due in May 2010);
• clarified that the control area of an off-system resource must be identified before it can qualify as a "network" resource, but deferred revising the minimum lead time for undesigating network resources; and
• clarified posting requirements related to processing of service requests and the time frame for implementation of transmission rollover rights reforms. 

As with Order No. 890, transmission providers must submit compliance filings to incorporate the modifications contained in Order No. 890-A—within 60 days of the order's publication in the Federal Register for non-RTO/ISO transmission providers whose facilities are not within an RTO/ISO footprint, and within 90 days for RTO/ISO transmission providers.

Incentive Rates to Support Transmission from Midwest Wind Projects

The Federal Energy Regulatory Commission (FERC) granted Xcel Energy Services, Inc.’s request for incentive transmission rates as part of Xcel’s plan for a $1 billion upgrade of its transmission grid inside the territory of the Midwest Independent Transmission System Operator (Midwest ISO).  The upgrades will help Xcel’s utilities meet state renewable electricity standards and serve increased power demand in the Upper Midwest.

Reflecting concerns that the Nation's transmission grid was not being adequately maintained and expanded, the Energy Policy Act of 2005 directed FERC to develop incentive-based rate provisions for transmission projects.  FERC did so in a later rulemaking, establishing numerous rates incentives comprising cost recovery, accelerated depreciation, and higher rates of return on equity for assets operated by ISOs/RTOs.  Utilities can establish eligibility for these incentives by demonstrating a relationship between the incentive sought and the transmission investments being made.   

Xcel proposed changes to its transmission rate formula under the Midwest ISO tariff to avail itself of two of the incentive rates.  FERC approved the proposal, which will grant Xcel (1) recovery of return on 100% of prudently incurred construction work in progress and (2) recovery of prudently incurred costs of transmission facilities that are canceled or abandoned for reasons beyond the control of Excel and its parent, the NSP companies.  FERC stated that the transmission upgrades will help bring renewable energy projects on-line, in compliance with various state renewable energy procurement requirements.  Xcel Energy has stated that it is seeking to build transmission to accommodate between 300 and 700 MWs of wind power.

Parties Submit Joint Settlement of Pacific Intertie Dispute

On November 21, PacifiCorp, Pacific Gas and Electric Company (PG&E), the California Independent System Operator (CAISO), and several others proposed to FERC an uncontested settlement that would resolve disputes over a 94-mile segment of the Pacific AC Intertie (PACI) transmission line between Oregon and northern California.  Uniquely, the 94-mile line at issue is jointly owned by two utilities, one, PG&E,  inside the CAISO, and the other, PacifiCorp, outside of it.  Under the proposed settlement, PacifiCorp and PG&E agreed to share equally the transmission capacity over the PACI between Malin, Oregon and Round Mountain, California, with PacifiCorp eventually providing service on its portion of the line under its open-access transmission tariff (OATT).

The dispute over the PACI began earlier this year.  The two 500 kV lines that comprise the PACI are co-owned by several parties.  PacifiCorp owns the northern half of the 94-mile segment on the eastern line, and PG&E owns the southern half of that segment and has turned operational control of its capacity over to the CAISO.  Since 1967, PacifiCorp had leased its share of the capacity for a low, fixed amount to several California utilities under a 40-year agreement.  Those utilities, in turn, placed PacifiCorp's portion of the line, along with PG&E's portion of the line, under the CAISO's operational control. 

With the capacity lease set to expire by its terms in July 2007, PacifiCorp filed a notice of termination in May, and informed FERC that it intended to begin to offer service over its 47-mile segment under its OATT.  This filing drew opposition from California utilities, the California Public Utilities Commission, and the CAISO.  PG&E in turn proposed revisions to the operating agreements for the line.  In July, FERC ruled that neither PacifiCorp's nor PG&E's proposals had been shown to be just and reasonable and convened a paper hearing to sort out the details. 

With the December 31 end of the suspension period fast approaching, the parties agreed that PacifiCorp and PG&E would "swap" portions of the capacity each owns under a 20-year agreement, such that each party will have rights to half of the capacity on the entire 94-mile path.  PacifiCorp also agreed to lease a portion of its capacity back to PG&E for a ten-year period, with some capacity becoming available under PacifiCorp's OATT beginning in 2012.  PacifiCorp and the CAISO also filed a joint operating agreement for PacifiCorp's share of the line, which continues to provide for CAISO operation of the capacity.  Other agreements relating to the operation of the California-Oregon Interface were also modified to reflect the settlement arrangements, and changes were made to PG&E's Transmission Owner tariff to implement cost recovery under the ten-year lease.  The settlement will thus compensate PacifiCorp for use of its portion of the line, while keeping the capacity within the CAISO's operational control.  The Commission has yet to act on the settlement agreement, and will need to do so by the end of the year in order for the new arrangements to take effect when the existing arrangements expire.

FERC Makes Good on Rate Incentive Promises to Transmission Developers

At its November 15 meeting, FERC announced three decisions awarding several incentive mechanisms to transmission developers.  The orders were issued in response to requests from Southern California Edison Company (SCE), Baltimore Gas & Electric Company (BG&E), and Pepco Holdings, Inc. (PHI), and were among the first substantive decisions since FERC's transmission incentive rulemaking order earlier this year, Order No. 679.  To transmission developers who can show their projects would ensure reliability or reduce transmission congestion that decision, Order No. 679 proposed to provide increased transmission rate incentives, such as higher Returns on Equity (ROE), adders to the rate basis, and inclusion of 100% of Construction Work in Progress (CWIP) and abandoned facilities in rate base.  The transmission developers, in order to qualify, must demonstrate a "nexus" between the incentives sought and the investment being made, i.e., the applicant must show that the incentives are rationally related to the investments being proposed.

Two of the instant orders provided incentives for companies seeking to construct new facilities in the transmission-constrained Southern California and Mid-Atlantic regions.  SCE is building several projects in Southern California:  the Devers-Palo Verde II Project, which consists of two transmission lines; the Rancho Vista Project, which includes a new 500 kV substation; and the Tehachapi Project, which consists of over 200 miles of transmission lines and three new substations and will be used to bring renewable energy (predominantly wind) onto SCE's transmission system.  In its order, FERC found that SCE had satisfied the "nexus" standard of Order No. 679.  The agency went on to allow a 125-basis point ROE incentive for the Devers-Palo Verde II and Tehachapi Projects, and a 75-basis point ROE incentive for the Rancho Vista Project.

Similarly, BG&E is constructing two baseline transmission projects in Maryland.  While FERC granted BG&E's request for a total of 150-basis point adders (for membership in the PJM Interconnection and for constructing baseline transmission), FERC denied BG&E's request to include 100 percent of its CWIP in rate base.  FERC also established a technical conference to determine whether BG&E's projects satisfied Order No. 679's "nexus" test.

In FERC's third order, it granted a request from PHI, on behalf of its transmission-owning public utility affiliates, Atlantic City Electric Company, Delmarva Power and Light, and Potomac Electric Power Company, for a 50-basis point adder to its authorized ROE for continued membership in PJM.  The adder moves PHI's overall ROE up closer to ROEs granted for PJM transmission facilities placed in service since 2006.  FERC explained that granting PHI's request furthered the Energy Policy Act of 2005 directive that FERC encourage utilities to join RTOs and ISOs.

Initiatives Provide Transmission for Renewable Power

The California Energy Commission has initiated a Renewable Energy Transmission Initiative (RETI) to identify transmission projects needed to help the state meet its renewable energy development goals.  In a process similar to that already adopted in Texas, the RETI process entails identifying Competitive Renewable Energy Zones (CREZs) from which renewable energy could be brought to California consumers.  Not surprisingly for the power-importing state, CREZs could be outside as well as inside California, although designation of external CREZs to serve California may not be well received in neighboring states.

The RETI process should complement the California Independent System Operator’s (CAISO) development of transmission financing rules.  The CAISO’s FERC-approved trunkline proposal provides for sharing of costs between interconnecting renewable generators, together with subsidies from other transmission customers.  The CAISO is now working on a tariff proposal for the inelegantly named “Location Constrained Resource Interconnection” rules, and is expected to submit the proposal to FERC by the end of October. 

On the national stage, Senator Harry Reid, the Majority Leader from Nevada, has introduced a bill to promote renewable energy development.  The bill, S.2076, would require establishment of renewable energy zones and direct federal power administrations to identify the transmission needed to access renewable energy in the zones.  The prospects of the bill becoming law are uncertain.  At minimum, however, the bill signals increased awareness by senior policymakers of the need to foster transmission development to connect the nation’s vast renewable energy potential with the load centers in need of energy. 

Generation-Friendly Transmission Companies to Reimburse for Network Upgrades

Independent electric transmission owners International Transmission Company (ITC) and Michigan Electric Transmission Company (METC), effective July 11, 2007, will reimburse qualifying interconnecting customers ― primarily new power generating units ―  100 % of the cost of transmission system upgrades for which interconnecting customers advance payment.  In a September 7 order the Federal Energy Regulatory Commission (FERC) approved amendments to the Midwest ISO tariff authorizing the two independent transmission companies to make these complete reimbursements to interconnecting customers who are qualified by reason of contractually committing to provide service for at least one year to Midwest ISO network customers or obtaining network resource designation at the time commercial operation begins.  Notably, the only opposition came from the former owners of ITC and METC, Detroit Edison and Consumers Energy, respectively, and the Michigan Public Power Agency.

The approach of ITC and METC was once FERC's standard practice; while the interconnecting customer could be required to advance full funding for the upgrades to the network needed to interconnect its new generator or transmission line, the customer would be reimbursed over time from transmission revenues. That was because system upgrades generally benefit everyone connected to the grid and those beneficiaries should all contribute to upgrades in proportion to their use of the gird.  Only when evidence to the contrary was introduced would there be less than complete reimbursement.

Under pressure from vertically integrated transmission owners, FERC strayed from this approach to cost allocation, grounded in the realities of a synchronously interconnected electric transmission system.  The approach of these truly independent transmission companies is refreshing.

Southeastern Group Undertakes Regional Transmission Planning

A group of utilities in the southeast ― where utilities have to date resisted forming regional transmission organizations ― have announced a proposal to develop an interregional transmission planning process.  Under the plan to be released September 14, the utilities will work jointly to collect data, coordinate planning assumptions, and address stakeholder study requests.  The coordinated efforts will provide a centralized information source for transmission users, who will no longer have to consult each transmission owner separately.  The effort answers FERC's Order No. 890, which mandated broader regional coordination of transmission planning. 

Involved in the efforts are several major utilities, including Duke Energy Carolinas, Entergy, Progress Energy Carolinas, South Carolina Electric & Gas, Southern Company, and the Tennessee Valley Authority, as well as a number of municipal transmission providers and electric coops.  The effort will build upon a few small regional planning groups that already exist in areas of the southeast, such as the North Carolina Transmission Planning Cooperative, but will allow broader information sharing and cooperation across the entire region.

Transmission Needed to Connect Burgeoning Renewable Generation

According to the Outlook of Renewable Energy in America report of the American Council on Renewable Energy, the United States by 2025 could have 248 GW of wind power and 100 GW of geothermal energy, in addition to 287 GW of other renewable energy, power and fuels.  "Renewable energy will not be a 'niche' source of America's energy in 2025," according to Robert Detchon, executive director of the Energy Future Coalition.  States such as Texas, Wyoming, New Mexico, and Colorado, where much of the increased wind generation is anticipated, and Nevada, California and Oregon, where much of the increased geothermal generation is anticipated, will likely require more transmission to deliver the renewable power to markets where it is needed. 

Utilities and governments in Europe, China and the United States could spend up to $150 billion on wind projects over the next five years, and the United States alone could invest $67.5 billion by 2015 to produce an anticipated total of 45,000 MW of wind capacity by that year.  According to a May survey conducted by the Geothermal Energy Association, up to 2,455 MW of new geothermal power plant capacity is currently under development in the United States, with 251 MW of capacity currently under construction.  Investment giant Merrill Lynch Commodity Partners recently closed on a $35 million deal with geothermal power developer Vulcan Power in order to finance the development of properties in California, Nevada and Oregon.  Calpine recently announced its intention to boost output at its Geysers geothermal facility in California to approximately 800 MW, and Nevada Power signed a 20-year power purchase agreement with Ormat Technologies for up to 30 MW from Ormat's proposed geothermal project development in northern Nevada. 

The world’s largest wind farm, located south of Abilene, Texas (population 115,000) already enjoyed access to sufficient transmission infrastructure necessary to bring the generation to a nearby market.  But for much future renewable energy development new transmission will be needed since renewable energy resources tend to be remote from load centers.

Several states, including Texas, California, Minnesota and Colorado are using a "zone" approach to transmission planning in order to incorporate renewable energy.  Driven by renewable portfolio standards in many states, the zone approach requires utilities to identify areas of renewable resources, plan the transmission capacity needed to reach those areas, and lobby state regulators to allow recovery of the investment in the required transmission.  Some believe that a federal initiative of this ilk would be necessary in order to tap the nation's vast renewable resources across the country.

Arizona Regulators Reject Cross-Border Transmission Line

The Arizona Corporation Commission (ACC) recently rejected an application by Southern California Edison Company (SCE) to construct a new transmission line from Devers, California to Palo Verde, Arizona.  The proposed Devers-Palo Verde No. 2 line ― a 230-mile, 1200 MW line estimated to cost approximately $600 million ― had already won approval of the California Public Utilities Commission (CPUC).  According to the CPUC, the line would serve as an important means of reducing the substantial congestion in southern California by expanding the transmission capacity into the area and allowing California utilities to import significant amounts of power from Arizona.  The ACC, on the other hand, dismissed the project as essentially allowing California to plug a "230-mile extension cord" into its generation supply, something the ACC found untenable at a time when Arizona's own population is growing rapidly. 

With both SCE and the CPUC considering appeals, the ACC's decision potentially sets up a fight under provisions of the Energy Policy Act of 2005 that allow FERC to site transmission facilities in certain Department of Energy (DOE)-designated National Interest Electric Transmission (NIET) Corridors for which state regulators have "withheld" approval for more than a year.  In a rulemaking issued late last year, FERC interpreted the word "withheld" in the statute to also mean "denied," thus potentially allowing transmission developers to bypass recalcitrant state regulators in favor of federal regulators.  In May, DOE proposed to designate an area encompassing the Devers-Palo Verde No. 2 line as a NIET corridor.

Long-Term Transmission Rights Arrive in Midwest ISO

The Energy Policy Act of 2005 (EPAct 2005) required FERC to enable load servers to obtain long-term transmission rights (LTTR).  Earlier versions of financial transmission rights offered in organized power markets were of short duration — typically monthly or yearly — which many load servers deemed inadequate for long-term planning and price certainty.  In its rulemaking to implement LTTRs, FERC directed organized market operators to prepare compliance plans consistent with FERC's guidelines.  Just as each organized market is idiosyncratic so too were the plans, and FERC is now addressing them, one by one.

In its plan, the Midwest ISO proposed not to allocated LTTRs directly to load servers, but instead to give them auction revenue rights (ARR).  A load server in the Midwest ISO can then choose whether to convert the ARRs to transmission rights or use them to collect the revenues from the sale of transmission rights in an auction.  The ARRs would have initial terms of one year each, but could be renewed annually for up to ten years.  FERC largely approved this approach. 

FERC went on to fault the Midwest ISO, however, for failing to fund fully its LTTR —that is, to ensure that the financial coverage offered would not change during its term.  While the Midwest ISO proposal would fully fund the ARRs, the associated transmission rights would not be fully funded, which could expose transmission users to revenue shortfalls, for example, when a transmission line goes out of service.  FERC directed the Midwest ISO to propose means for ensuring the transmission rights holder is fully compensated in all such instances. 

PJM was the first organized market operator to submit an LTTR compliance filing to FERC.  FERC approved PJM's LTTR proposal last fall, but also found that PJM had not met the full funding requirement.  PJM revised its proposal to use an "uplift" mechanism that distributes the shortfall costs to all financial transmission right holders to provide the revenue protection, and FERC sanctioned that approach. 

FERC also denied the demand of the Long Island Power Authority that it be allowed to obtain LTTRs in the PJM service territory.  LIPA only serves load outside the PJM territory, and PJM denied its requests for LTTRs.  LIPA argued its request was consistent with the EPAct and justifiable because it pays for its share of necessary transmission upgrades as well as the transmission service charge that covers the embedded costs of PJM transmission.  FERC agreed with PJM but not on the ground that LIPA only served load external to PJM.  Instead, FERC found that LIPA failed to meet the PJM prerequisite of having taken transmission service during a given reference year in the past and paying the embedded costs of the PJM transmission system. 

Department of Energy Proposes $9 Billion in Clean Energy Loans

Nine billion dollars could flow to guarantee loans to clean energy projects under a May 10 Department of Energy (DOE) Notice of Proposed Rulemaking (NOPR) under the Energy Policy Act of 2005. Each approved project could receive guarantees covering up to 80% of total project costs.  To be considered by the agency, written comments must be submitted within 45 days from notice in the Federal Register — likely late June or early July.

DOE proposes loan guarantees for ten categories of projects and technologies, including:  renewable energy systems; advanced fossil energy technology, including qualifying coal gasification systems; residential, industrial or transportation hydrogen fuel cell applications; advanced nuclear facilities, carbon capture and sequestration practices; efficiency in electrical generation, transmission and distribution; end-use efficiency technologies; production facilities for fuel efficient vehicles; pollution control equipment; and certain crude oil refineries.

Allocation of the $9 billion in loans will not be equally distributed among the ten categories; rather, $4 billion is reserved for central power stations, $4 billion for biofuels and clean transportation fuels, and only $1 billion for projects involving new technologies for electric transmission or renewable power generation systems.  According to DOE, precise allocation of the guarantees will depend upon the merits and benefits of a particular proposal and the accompanying statutory and regulatory requirements.

While the program is a positive development for the energy industry as a whole, efficient and fair implementation by DOE is critical, and that implementation is the specific subject-matter of the May 10 NOPR.  Provisions of particular interest to potential loan applicants include payment of the Credit Subsidy Cost, assessment of fees to loan recipients, rules on financial structure and eligibility of lenders, regulatory review, and default and audit rules.

Those industries now participating in eligible technologies and those planning expansion into clean energy projects can find public comment and public meeting procedures at Section III of the NOPR.

DOE Proposes Two National Interest Electric Transmission Corridors

Several months after FERC's issuance of a final rule setting out the procedures it will follow to determine whether to site transmission facilities in Department of Energy (DOE)-designated national interest electric transmission (NIET) corridors, DOE has proposed two NIET corridors for review and comment.  The "Mid-Atlantic Area National Corridor" encompasses certain counties in Maryland, New York, Ohio, Pennsylvania, Virginia, West Virginia, and all of New Jersey, Delaware and the District of Columbia.  The "Southwest Area National Corridor" includes counties in California, Arizona, and Nevada.  Public comments on the proposed designations may be filed with the DOE within sixty days of the proposal's publication in the Federal Register.  Final designation is expected by the end of the year, possibly accompanied or closely followed by more draft designations of corridors in the areas of New England, San Francisco and Seattle-Portland, areas that DOE is also considering for NIET corridor designation. 

Final designation of these two NIET corridors would pave the way for FERC to utilize the so-called “backstop” siting authority that Congress granted to the agency in the Energy Policy Act of 2005 (EPAct 2005).  In an amendment to the Federal Power Act, EPAct 2005 empowered FERC to issue permits for construction of transmission lines and condemn right of way for those transmission lines.  Until now, only state regulators and siting authorities possessed this authority. 

Final designation would also raise the chances that several transmission operators, whose 2006 requests for "early" NIET corridor designation were rejected by DOE, would see their proposed projects come closer to fruition.  Those projects include AEP's proposed Mountaineer Project from West Virginia to New Jersey, Allegheny Power's Trans-Allegheny Interstate Line Project from Pennsylvania to West Virginia, and SDG&E's Imperial Valley project in southern California.

FERC Tailors Transmission to Connect Renewables

In response to a carefully crafted petition from the California Independent System Operator, the Federal Energy Regulatory Commission took a large step toward facilitating development of the transmission needed to harness wind and other renewable energy sources that are remote from load centers.  With its order granting the CAISO’s petition for declaratory order, FERC approved a financing mechanism that is intended to solve the "chicken or egg" sequencing problem of development of transmission lines and renewable energy generators in areas such as the Tehachapi region of California.

The problem vexing renewable energy advocates is that wind, geothermal and other renewable generators must be built where natural conditions allow.  But wind and geothermal hot spots are often far from the energy-thirsty urban centers, and little transmission is available at these remote locations.  Since most renewable energy projects are much smaller than large hydro or fossil-fuel plants, individual generators can’t afford to develop major new transmission projects.  Nor have transmission owners been keen on building lines to locations where the development of generation is either marginal or uncertain. 

To break this transmission logjam, some states have created transmission development agencies.  But California entities have focused more on creating cost recovery mechanisms that would allow the state's transmission-owning utilities to develop the transmission themselves.  In 2005, Southern California Edison initally proposed a "trunk line" model, but FERC objected  because ratepayers would pay for the entire facility, and because the utility would retain control of it.  FERC solicited an alternative, and the CAISO responded with a program having the following key terms:

• The project must provide access to an area with significant potential for development of remote energy resources.
• Initial costs of qualifying interconnection facilities would be rolled into the transmission revenue requirement of the transmission owner that constructs the facility, subject to a cost cap to protect ratepayers. 
• Later costs would be paid pro rata by generators who interconnect with the line.
• The project would have to be approved through the CAISO transmission planning process.
• A minimum level of generators must commit to the line before it can proceed, and another batch must have shown interest in joining. 

FERC earlier had resisted advantaging renewable energy through favorable transmission rules.  But with its approval of the CAISO program, FERC acknowledges that location-constrained resources are unique and warrant different access rules. 

ColumbiaGrid Planning Agreement Wins FERC Acceptance

ColumbiaGrid, a non-profit membership corporation formed in 2006 to improve the planning and operation of the Northwest transmission grid, has received FERC acceptance of  its Planning and Expansion Function Agreement (Agreement) with its members and with Snohomish County PUD, a non-member party to the agreement.  ColumbiaGrid's current members are Avista Corp. (Avista), Bonneville Power Authority (BPA), Chelan County PUD, Grant County PUD, Puget Sound Energy (Puget Sound), Seattle City Light and Tacoma Power.  Completion of the Agreement comes as good news to parties that have weathered several stymied efforts to create such an organization in the northwest region.  

The Agreement took effect April 4 and requires ColumbiaGrid to prepare a 10-year transmission plan for its footprint within 30 months and to update that plan biennially.  Based on evaluations of its members' transmission systems, the plan will recommend capacity increases, single-system projects, expanded scope projects and non-transmission alternatives (e.g., generation additions or demand management) to the region's interconnected transmission systems.  In addition, ColumbiaGrid will coordinate multi-system project planning and stakeholder participation in the planning process.  Finally, ColumbiaGrid will assume BPA's planning obligations to the Western Reliability Coordinating Council. 

States Seek to Increase Renewable Energy Development

State governments have been busy of late seeking to increase renewable energy development and sales within their borders, mostly through the increasingly popular renewable portfolio standards that require utilities to include a certain percentage of renewable energy in the electric power sold to consumers.

Most recently, the Oregon State Senate approved SB 838 that would introduce a renewable portfolio standard to the state.  Oregon is today the most populous Western state without a renewable portfolio standard.   If enacted into law, the bill would require utilities to gradually increase their procurement of renewable energy up to the level of 25 percent of the energy they provide to consumers by the year 2025.  To stimulate development of other resources, the bill would limit the amount of the requirement that can be satisfied by hydroelectric generation, on which the Pacific Northwest already heavily relies.  To reduce the cost of the standard, the bill would cap the added cost of renewables at 4 percent on a utility’s annual revenue requirement.  The bill now goes to the Oregon House of Representatives for hearings.

In Colorado, Governor Bill Ritter signed a bill doubling the state’s renewable energy standard, which had been adopted through a voter ballot in 2004.  The new law increases the renewable energy procurement for utilities from 10% to 20% by the year 2020 and also establishes a 10% procurement requirement by 2020 for municipal utilities serving more than 40,000 customers and electric cooperatives.  The Governor also signed legislation compelling the state’s utilities to identify high-potential wind-energy locations by undertaking biennial reviews to designate “Energy Resource Zones” where transmission constraints hinder the delivery of electricity.  This requirement is intended to spur subsequent development of the transmission needed to bring renewable energy to load centers.

Wisconsin likewise moved to increase renewable energy development as Governor Jim Doyle signed several executive orders intended to boost renewable energy development and fight global warming.  The Governor previously announced a goal of Wisconsin obtaining 25 percent of its electricity and 25 percent of its transportation fuel from renewable fuels by 2025, although the state’s renewable portfolio standard calls for a more modest 10% procurement of renewable energy by 2015.  The executive orders create a new Office of Energy Independence whose objectives will include working with the state’s Public Service Commission on a potential multi-utility effort to build a integrated gasification combined cycle “clean coal” generator.  Another executive order created a Task Force on Global Warming to include a wide range of business, industry, government, energy and environment leaders to examine the effects of, and solutions to, global warming in Wisconsin. 

FERC Preserves ERCOT Independence, Even as Texas Congressman Pushes for FERC Regulation

Finding that two proposed transmission lines did not jeopardize the jurisdictional arrangement that keeps ERCOT outside of FERC regulation, on March 15, the Commission approved new transmission lines proposed by Cottonwood Energy Co. and Brazos Electric Power Cooperative.  Cottonwood plans to build an approximately 100-mile high voltage transmission line from a 1200 MW natural gas-fired generating facility in Deweyville, Texas (on the Texas-Louisiana border), which Cottonwood will interconnect with CenterPoint Energy Houston.  FERC's order disclaimed jurisdiction of the new line, because it would not interconnect with any non-ERCOT utilities and would not intermingle any ERCOT electricity with electricity from the Eastern Interconnection.

In a separate order issued the same day, FERC also approved Brazos's proposed transmission project.  Late last year, Brazos had proposed to construct a 345 kV, 70-mile alternating current transmission line from a planned new 750 MW coal-fired generating unit in Hugo, Oklahoma (which it originally planned to co-own with the Western Farmers Electric Coop ("WFEC")).  Brazos also planned to build a 375 MW high voltage direct current line to provide a connection between the Hugo generating unit and the Southwest Power Pool.  FERC's March 15 order approved the new intertie, directed interconnection of the Brazos line with local utility TXU, and directed TXU and CenterPoint Energy to provide transmission services to Brazos.  FERC made clear that its order would not make TXU, CenterPoint, or ERCOT a FERC-jurisdictional "public utility."  Interestingly enough, Brazos filed just a few days later asking FERC essentially to rescind these authorizations and terminate the proceeding.  Brazos explained that after continued negotiations with WFEC, the parties determined that Brazos will no longer own any part of the Hugo generating unit, and thus, Brazos no longer plans to build the approved transmission line.

Meanwhile, Texas Congressman Joe Barton (R), former chairman and current ranking member of the House Committee on Energy and Commerce, continued on his warpath that FERC should have jurisdiction over ERCOT.  Congressman Barton's concerns about ERCOT's independence arose in the wake of a proposed buyout of TXU.  Barton had posed several questions to FERC Chairman Joseph Kelliher (a former Barton Capitol Hill staffer) regarding the TXU buyout, many of which Kelliher stated he was unable to answer because no information has been filed with FERC regarding the proposed transaction.  Kelliher stated that FERC currently has only limited jurisdiction over utilities like TXU whose operations are confined to ERCOT, but made clear that he does not believe any expansion of FERC’s jurisdiction is needed.  If Congress did grant FERC authority to regulate ERCOT utilities, Kelliher stated he envisioned that FERC would have much the same jurisdiction over those utilities as it currently exercises over utilities that transmit and sell power across state lines — namely, regulating all rates, terms, and conditions of transmission and wholesale rates by investor-owned utilities, and overseeing certain corporate transactions, including mergers and acquisitions of jurisdictional facilities.  Whether Barton will continue to demand FERC jurisdiction over ERCOT remains to be seen.

New Mexico Promotes Transmission Solutions for Renewable Energy Development, Ups RPS

Developing renewable energy far from load centers demands construction of transmission.  But which comes first – the generation or the transmission?  Several Western states, including California and Texas, are addressing this issue, and New Mexico has recently adopted its solution.  The state enacted legislation that will create the New Mexico Renewable Energy Transmission Authority, a quasi-governmental agency that will plan, finance, acquire and build power lines and energy storage projects. 

The Authority will have power to designate transmission corridors, negotiate with other entities on the establishment of interstate corridors, and use eminent domain authority to help get projects built.  Eligible transmission projects must transmit at least 30% electricity from renewable sources within a year of commencing operations.  The Authority is not to undertake projects if public utilities or other private entities are performing the act or providing the services in question.  The legislation also establishes the procedures the Authority is to use in undertaking projects, and grants the Authority power to issue Renewable Energy Transmission Bonds to obtain financing.  Among other Western states, Wyoming also has a transmission authority that likewise is intended to help export electricity produced by state's energy resources.

New Mexico Governor Richardson also signed legislation increasing the state's renewable portfolio standards.  The state's previous RPS directed utilities to include, by 2011, a minimum of 10% renewable energy in the energy they sold at retail.  Under the new law, the goal has been set at 15% by 2015 and 20% by 2020.  In addition, rural electric cooperatives will now be subject to the RPS requirements, although at a lower level, needing to procure 10% of their power from renewable sources by 2021.  As has been the national trend of late, New Mexico will allow compliance to be achieved through the purchase of renewable energy credits.

California ISO Proposes Transmission Tailored to Renewable Energy

Picking up where one the state’s biggest utilities left off, the California Independent System Operator (CAISO) has proposed to FERC a new category of transmission that would facilitate development of renewable energy  ― particularly wind ― in regions short of adequate transmission capability.  If approved by FERC, the new type of transmission could bring on line further development of the productive Tehachapi region and help the state achieve its ambitious renewable portfolio standards. 

Driving the CAISO proposal is the fact that many of the most promising sites for wind energy development are far from existing transmission lines.  FERC’s transmission policies allocate most interconnection costs to the generator, which works against developers of remote wind farms.  The CAISO would lessen this entry barrier by allocating the initial costs of developing a multi-user interconnection line, or trunkline, to the regional transmission owner who, in turn, would recoup those costs over time through the CAISO’s transmission access charge.  Interconnecting generators would then pay their pro-rated share of the line’s costs once they start operations.  Other elements of the proposal are intended to limit cost impacts on ratepayers and ensure this type of transmission is used only for major projects.  

The proposal follows the efforts of Southern California Edison, which in 2005 sought FERC approval for rolling in the costs of a trunkline intended to allow interconnections with wind projects in the Tehachapi region.  In a split decision, FERC rejected the proposal on the grounds that the proposed roll-in did not benefit all transmission users, but there were indications that a proposal by the CAISO might be received more favorably. 

The leader in wind generation, Texas, has taken another path for developing needed transmission.  It will designate renewable energy development zones based on renewable energy potential, and then mandate transmission development from the zones to more populated areas.  Since most of Texas is not subject to FERC’s jurisdiction, however, that proposal did not require Washington's blessing.

Separately, FERC has been conducting a rulemaking to revise its Order 888 open-access tariff.  As part of the rulemaking, FERC has considered requiring transmitting utilities to offer a new category of conditional firm transmission service that would benefit wind and other intermittent sources of energy.  FERC is scheduled to discuss the rulemaking at its upcoming February ­­15 meeting and a final order will likely issue soon thereafter. 

Transco ITC Gets Boost from Alliant Sub's Voluntary Sale of Transmission Assets

With its decision to sell its transmission network to ITC Holdings Co. ("ITC"), Interstate Power & Light Company ("IP&L") ― a subsidiary of Alliant Energy ― became the first vertically integrated utility to volunteer to turn over its transmission assets to an independent transmission operator. 

ITC acquired its existing portfolio of transmission assets from utilities that had been ordered to divest them.  In contrast, IP&L's sale is based solely on perceived business interests.  IP&L has adopted the business strategy of avoiding heavy investment in transmission infrastructure while focusing on generation to meet growing Midwest power needs.  IP&L plans to use sale proceeds to finance new coal-fired and wind generation in Iowa.  Several other elements appear to have influenced IP&L's decision.  First, since ITC owns no generation, IP&L will not be competing with the transmission company for grid access.  Second, a hold-harmless clause in the sale agreement ensures that IP&L's retail customers will not experience increased rates due to the sale.   

FERC Proposes to Trim Applicability of Standards of Conduct to Both Electric Utility and Natural Gas Pipeline Energy Affiliates

In response to the court remand of FERC's Order No. 2004 standards of conduct as they apply to natural gas pipelines, a proposed rule to revise the standards of conduct has quickly followed FERC's interim rule on the subject, issued earlier this month.  The proposed rule would make permanent the interim rule.  The interim rule exempted from the standards of conduct restrictions on energy affiliates of natural gas pipelines. 

Application of the standards of conduct to energy affiliates of electric utilities was not challenged on appeal of Order No. 2004.  The proposed rule, however, suggests following the court's natural gas pipeline ruling and eliminating application to the energy affiliates of electric utilities as well as natural gas pipelines.  In the rulemaking proceeding, FERC will consider whether evidence of abuse or the potential for abuse involving electric utilities' energy affiliates justifies retaining the standards applicability to electric utility energy affiliates.  If FERC decides that this justification exists, then the standards will apply more broadly to electric utility operations than to natural gas pipelines. 

The proposed rule would make permanent provisions contained in the interim rule regarding other issues challenged on appeal but not addressed by the court.  These provisions include allowing risk management employees and lawyers to be shared between natural gas pipelines and their marketing affiliates, and requiring natural gas providers to post only those "discretionary acts" that waive adherence to tariff provisions.   

Finally, in an extension of FERC's Order 2004 policy that employees involved only in "bundled retail sales" were not considered "marketing affiliates" and thus not subject to the standards of conduct, the proposed rule would relax the standards of conduct as to public utilities' "planning" and "competitive solicitation" employees so that these employees can access non-public transmission information in connection with implementing state-mandated integrated resource planning and competitive solicitations.  The main focus of this proposal is on the electric transmission grid and issues of reliability and accurate long-term planning. 

FERC Tinkers on Transmission Investment Incentives

Responding to concerns raised by state regulators, FERC closed out 2006 by amending its rules intended to induce investment in new transmission infrastructure.  FERC issued the original rule last July pursuant to EPAct 2005 (and the new FPA § 219), which decried a shortage of transmission investments and directed FERC to develop transmission incentives.  The original rule identified rate perquisites available to applicants that meet certain criteria.  While the incentives remain available to a broad range of investors, demonstrating eligibility has become more demanding. 

First, FERC clarified that its "nexus" requirement ─ that incentives must be tailored to meet the particular risks faced by the applicant ─ will be applied strictly, and will not be satisfied in every case.  Routine investments in the ordinary course of expanding an applicant's transmission system, for example, would be less likely to meet the nexus test than new projects presenting special challenges and encountering uncertain risks.  As opposed to the original approach, where the nexus test was applied to each incentive requested, now an applicant must demonstrate that the total package of incentives being applied for is tailored to address the demonstrable risks or challenges it faces.  In beefing up its nexus requirement, however, FERC declined to adopt a "but for" test ─ but for the incentives, the project would not be built ─ due to the difficulty of satisfying such a test.   

FERC also emphasized that it will not routinely grant an incentive ROE, and that any ROE it does grant will not always fall at the "top" of the zone of reasonableness.  In addition to justifying a higher ROE under the nexus test, an applicant must also justify where within the zone of reasonableness the return should lie.  FERC will continue to allow petitions for declaratory order seeking a specific ROE.  Finally, the new rule reaffirms the availability of an ROE incentive to transcos and to utilities that join or remain in ISOs and RTOs.   

Finally, the new rule seeks to alleviate state concerns that rebuttable presumptions, contained in the original rule, that would consider certain projects eligible for incentives, would not adequately measure whether the project would improve reliability or decrease congestion, as required by the FPA.  While FERC maintained a rebuttable presumption that a project is eligible for incentives if it results from a fair and open regional-planning process, or received state construction approval, if those processes do not consider whether the project ensures reliability or reduces congestion, then the applicant must independently validate that the project meets those criteria. 

Texas Coop Plans New DC Tie Between ERCOT and SPP

Brazos Electric Cooperative (Brazos) applied to FERC in October and again in November for the interconnection of a new 70-mile, 345 kV transmission line that would connect generation in Oklahoma with load in Texas.  The proposed line would be built in conjunction with Brazos's plans to construct a new 750 MW coal-fired generating unit near the Western Farmers Electric Cooperative's (WFEC) existing Hugo generating facility in Hugo, Oklahoma.  Brazos, an electric coop located in 68 counties across north Texas, and WFEC, which has service areas throughout Oklahoma, will jointly own the new Hugo unit.  In order for Brazos to bring this power from Hugo to the Electric Reliability Council of Texas (ERCOT), Brazos is planning to build the new DC intertie between ERCOT and the Southwest Power Pool (SPP), which will have an approximate capacity of 375 MW.  Accordingly, Brazos has asked FERC to order TXU Electric Delivery (TXU) to allow it to interconnect with TXU's system at the Valley South substation in north Texas.  Brazos also asked FERC to require TXU and CenterPoint Energy Houston Electric to offer transmission service for power flows over the new line into or out of ERCOT.  Brazos has asked FERC to issue a decision on its application by January 31, 2007.

The proposed DC intertie would be the third such interconnection between ERCOT and SPP.  In its application, Brazos took pains to emphasize that its proposed interconnection would maintain the fiction that ERCOT is outside of the interstate grid and not subject to most forms of FERC regulation.  To that end, Brazos specified that the intertie and the generating unit's switching station would be engineered such that the generating facility could generate only into either ERCOT or SPP, but not both at once.

Regional Operators Enjoy Flexibility in Selecting Cost Allocation Methodology

Disputes in the Midwest over allocating transmission costs date back to at least the mid 1980s, when competing interests fought over AEP's transmission equalization agreements and the transmission costs associated with the Rockport plant.  Recently FERC resolved for now another of those disputes, by accepting Midwest ISO's proposed allocation of the costs of new transmission infrastructure. 

Midwest ISO proposed to allocate the cost of: (1) lower voltage lines subregionally to all transmission customers in the designated pricing zones affected by the transmission project, and (2)  Extra High Voltage (EHV) ― 345 kV up to 765 kV ― 80% subregionally (like lower voltage facilities) and 20% systemwide on a load-ratio share basis (i.e., a postage-stamp basis).  FERC accepted this allocation on the ground that the EHV lines are the superhighways of the Midwest transmission grid. 

Midwest ISO is the third RTO for which FERC has engaged transmission cost allocation issues.  The others are New England and Southwest Power Pool.  FERC accepted a different approach for each.  Given that FERC has been flexible in allowing different approaches, future RTOs will be free to seek their own solutions to these often divisive issues. 

FERC also accepted Midwest ISO’s proposal for generation interconnection cost allocation, which makes generators responsible for 50% of the transmission upgrade costs if the generation output is committed to network customers or designated as a network resource.  Otherwise, the generator is responsible for 100% of the costs of transmission upgrades required for interconnection.  While FERC rejected arguments that this approach would “chill” generation investment, FERC still directed Midwest ISO to file, within 12 months, an informational report on its experience under this cost recovery methodology.  More to come on this front, as the issue is reopened with more data next year. 

ERCOT Report Lays Groundwork for Transmission to Support Wind Development

Texas moved closer to developing the additional transmission needed to deliver wind power to loads when the Electric Reliability Council of Texas (ERCOT) issued a report identifying geographic areas that the Public Utility Commission (PUCT) could designate as competitive renewable energy zones (CREZ) under Texas law.  After the CREZ are established, the law then requires construction of the necessary transmission facilities between the CREZ and urban areas.   

Texas currently has more installed wind generation, 2508 MW, than any other state, and this number is expected to rise to approximately 4850 MW by the end of 2007.  However, as in many other parts of the country, the areas where wind power has the greatest potential are far from energy-thirsty population centers.  Texas legislation enacted in 2005 is intended to facilitate the development of needed transmission infrastructure to support future wind power development.  To that end, ERCOT’s analysis concludes that most wind farms would likely be located in the Gulf Coast region, the Panhandle, central-western Texas (along the Abilene-Odessa corridor), and in the McCamey region in west Texas.  Each area has different strengths and weaknesses regarding expected production and transmission costs, capacity characteristics, and daily and seasonable variability of winds.  The report states that several new high-voltage 345-kV transmission lines and associated grid upgrades would be needed to support expected wind farm development.

The PUCT is expected to make CREZ determinations in early 2007.  Any designations will be based on a wide range of factors, including costs of transmission construction and ancillary services, wind energy strength and benefits, and the financial support for proposed projects.

FERC Conditionally Approves PJM RTEP Process Modifications

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.

Federal-State Tension Accompanies FERC's Final Rule on Backstop Transmission Siting

FERC has issued a Final Rule establishing procedures that it will use for permitting construction of transmission lines in National Interest Electric Transmission Corridors (NIET) corridors.  In EPAct 2005, Congress authorized the Department of Energy to designate NIET corridors in congested areas of the high-voltage power grid.  Congress, in turn, granted FERC new authority to permit construction of transmission lines within designated NIET corridors in instances when a state permitting authority either has not acted or is unable to act on an application for siting authority.  The federal permit is controversial because it confers on the permit recipient a new federal right of eminent domain to condemn private property for rights of way ― a right previously available only from state and local authorities.   

Most elements of the Final Rule track an earlier proposed rule.  FERC must find that the proposed facilities would meet five basic criteria, including reducing congestion and enhancing energy independence.  Applicants for permits must file Participation Plans to maximize stakeholder contributions, and engage in a prefiling process at FERC.  The Final Rule does change this prefiling process.  Under the proposed rule, while an applicant was required to wait one year after applying to state or local authorities before filing its permit application at FERC, it could nevertheless begin the prefiling activities at FERC earlier, concurrent with ongoing state siting proceedings.  In response to loud outcry from state regulatory agencies concerned that FERC would effectively commandeer ongoing state review of transmission projects in NIET corridors, the Final Rule now prohibits both filing an application and initiating prefiling activities at FERC before one year following the beginning of state proceedings.   

Another controversial provision related to the states was resolved in favor of a stronger FERC authority.  EPAct allows FERC to grant a permit where a state has "withheld approval" of transmission facilities.  FERC determined that "withheld approval" applies both to where states deny permits and where states fail to act on permits.  While FERC Chair Kelliher supported this decision, calling it a reasonable interpretation, Commissioner Kelly disagreed, arguing that the interpretation leaves states with little choice: either permit the facilities or FERC will do it for you.  Kelliher pointed out that FERC could have legally implemented a process that ran simultaneously with state processes, but did not do so.  The practical result of this middle ground, however, is a lengthier permitting process – Kelliher admitted that projects that fail to win state siting approval face another 20 months of regulatory review at FERC. 

Divided FERC Approves Incentive for New England Transmission

FERC voted by a 3-2 margin to raise by 100 basis points (1%) returns on equity invested in New England electric transmission that ISO New England identifies as necessary.  The Republican majority, including FERC Chair Joseph Kelliher, concluded that incentive rates were needed to encourage transmission expansion and reduce regional congestion; the Democratic dissenters contended that, even if targeted investment incentives may be warranted, across-the-board increases in transmission investment returns had not been justified.

The order reverses a FERC judge’s May 2005 decision that such transmission incentives should only be awarded to projects that would not be built “but for” the incentives.  In the Energy Policy Act of 2005 Congress directed FERC to develop transmission rates sufficient to induce investment.  In July 2006 FERC finalized a transmission pricing rule intended to induce investment in transmission without requiring the “but for” predicate that the judge endorsed.  By rejecting the “but for” requirement, the FERC majority appears to have been persuaded that ISO New England’s 2004 regional transmission planning ensures that the benefits of new transmission and congestion relief justify the added expense.
The dissenters were unwilling to buy so completely into the ISO New England planning process.  Commissioner Suedeen Kelly found the majority’s decision troubling because transmission owners would be able to get the 100-basis point adder regardless of whether it was in fact necessary for a given project to be constructed or the specific benefits from the project.  Commissioner Jon Wellinghoff expressed similar concerns, adding that such transmission incentives should be limited to those projects that provided incremental benefits such as energy efficiency. 

FERC Approves ITC Acquisition of Michigan Transco

For the first time, FERC has granted approval of one independent transmission company's purchase of another; it authorized ITC Holdings, the parent of ITCTransmission, to acquire Michigan Transco Holdings, the parent of Michigan Electric Transmission.  As a result, ITC will become the largest Transco in the U.S. and one of the ten largest transmission providers in the nation, with more than 20,000 MW of peak load and almost 20 percent of the peak load of the Midwest ISO.   

The same order, the first issued under FERC's new EPAct 2005 merger authority, also authorized an intra-corporate reorganization of Michigan Electric and Trans-Elect NTD Path 15 that will occur before the ITC acquisition.   

FERC to Consider Settlement in PJM Capacity Market Redesign

Thirteen months after the PJM Interconnection proposed to FERC the Reliability Pricing Model (RPM), a redesign of its capacity market, the nation’s largest RTO and many of its members submitted to FERC a proposed settlement agreement to create a new capacity market.  The submitting parties asked FERC to approve the settlement by December 22, 2005, so that it can take effect by June 1, 2007.

The settlement agreement uses many of the concepts included in the proposal PJM had submitted to FERC, but applies them differently, often in a way less favorable to generators.  A sloping demand curve – which combined with generator bids determines capacity prices – continues to be part of the market design, but the pricing points are suppressed.  Instead of procuring capacity four years in advance, as originally proposed, the settlement would require only three-year forward procurement.  The proposed settlement would ultimately create 23 locational deliverability areas (LDAs) reflecting transmission constraints.  Recognition of LDAs then allows capacity prices to vary between regions to reflect constraints on deliverability.  However, all of the LDAs would not take effect until the 2010-2011 delivery year, leaving in place until then awkwardly shaped LDAs with internal constraints, such as the Rest-of-Market LDA that groups together Dominion-Virginia Power and other areas that are separated by significant transmission constraints.  Other modifications include addition of the Fixed Resource Requirement, which allows utilities to opt out of the RPM and instead self-supply capacity, whether from their own resources or through bilateral arrangements. 

The proposed settlement is the result of four months of settlement talks that began a few weeks after FERC’s April 20, 2006 order finding the existing capacity rules to be unjust and unreasonable. 

New PJM Market Efficiency Analysis Synthesizes Economic and Reliability Planning

Expanding on changes made to its regional transmission expansion plan (RTEP) process last June, the PJM interconnection has asked FERC to approve further RTEP adjustments intended to coordinate economic planning with reliability planning in a "forward-looking market efficiency analysis."  

The June changes projected RTEP's planning horizon fifte