The "Clean Energy" legislation under consideration in the U.S. Congress identifies investment in the United States' electric transmission grid as a key component of the nation's evolving energy policy. Both the bill already passed by the House of Representatives and the pending Senate counterpart recognize that new transmission infrastructure is essential to support increased reliance on renewable generation, to reduce greenhouse gas emissions, to enhance the capabilities of the grid, and to improve grid reliability.
To encourage transmission investments that will bring Clean Energy online, commenters have urged congressional action in three areas: transmission planning, siting of new transmission, and allocating the cost of new transmission to the beneficiaries of the project. Although the House and Senate Energy Bills address each of these subjects, some of the proposed changes are quite modest. But any shift in policy toward Clean Energy will encourage the Federal Energy Regulatory Commission ("FERC") to embark on, or strengthen, its own policy initiatives. Indeed, even if Congress does not pass Clean Energy legislation this year, FERC's transmission policy is expected to evolve in ways that will advance Clean Energy initiatives.
Both FERC and Congress have imposed new transmission planning requirements in recent years. As part of the American Recovery and Reinvestment Act of 2009 (better known as the "stimulus bill"), Congress allocated $80 million to the Department of Energy ("DOE"), Office of Electricity Delivery and Energy Reliability to "facilitate the development of regional plans" by conducting a resource assessment and analysis of future demand and transmission requirements. This includes technical assistance from DOE for the creation of "interconnection-based transmission plans" for the Eastern and Western Interconnections and for the Electric Reliability Council of Texas.
Over the past two years, FERC has expended substantial time and effort developing new rules and tariffs governing the transmission planning process. These rules require each transmission service provider to coordinate its transmission planning with stakeholders in an open and transparent manner. The new planning procedures also require coordination of planning on a regional scale; evaluation of "economic" projects (those that relieve congestion rather than address compliance with reliability criteria); and transmission cost allocation that (i) promotes new transmission investment, (ii) has general support from state and regional players, and (iii) fairly assigns costs.
On June 30, 2009, FERC issued a notice announcing that it will hold technical conferences in September 2009 to "determine the progress and benefits realized by each transmission provider's transmission planning process, obtain customer and other stakeholder input, and discuss any areas that may need improvement." The conferences will look at the need for planning on a regional and interconnection-wide basis to ensure "adequate and reliable supplies" and will focus on emerging challenges "such as the development of interregional transmission facilities, the integration of large amounts of location-constrained generation, and the interconnection of distributed energy resources."
Even though it is too soon to know whether FERC's existing transmission planning initiatives are accomplishing their stated goals, the House and Senate Energy Bills include new directives requiring FERC to supervise large-scale transmission planning for renewable energy. The House Energy Bill declares that regional electric grid planning should "facilitate the deployment of renewable and other zero-carbon and low carbon energy sources for generating electricity to reduce greenhouse gas emissions" in addition to several other policy goals. This planning must take all demand-side and supply-side options into account, including energy efficiency, distributed generation, smart grid technologies, and electricity storage. FERC is mandated to establish grid planning principles derived from these policies within one year.
Under the House Energy Bill, regional planning entities must submit initial regional plans within 18 months of a FERC rule. Within three years from passage of the bill, FERC must review the regional plans, conduct multiregional meetings, and report the results to Congress. The House Energy Bill stresses cooperation across regions and would require FERC to "incorporate and coordinate with any ongoing planning efforts undertaken pursuant to section 217 and Commission Order No. 890." The bill states that "in no case shall a multi-regional plan impose inclusion of a facility on a region that has submitted a valid plan that, after efforts to resolve the conflict, does not include such facility."
Under similar provisions of the Senate Energy Bill, FERC would promulgate a rule to promote clean energy policy goals such as the development of renewable generation, reduction of greenhouse gas emissions, and cost savings achieved through reduced transmission congestion. The bill also provides a schedule for FERC to implement those goals within one year. Transmission planning entities would develop regional plans within two years of FERC's rule. Plans would be updated every three years.
It remains to be seen whether the new planning requirements proposed by Congress will simply add another layer to the already complex regime of transmission planning or whether a more coherent and integrated process will emerge. Regardless of whether Congress passes clean energy legislation this year, many of the transmission planning matters addressed by the House and Senate Energy Bills are likely to be raised in FERC's technical conferences scheduled for this fall.
Both the House and the Senate would expand FERC's authority to exercise its "backstop" authority under FPA Section 216. The Energy Policy Act of 2005 ("EPAct 2005") gave FERC "backstop" authority to issue permits for transmission facilities located in "national interest electric transmission corridors" designated by the Department of Energy. When it implemented FPA Section 216, FERC concluded that it could issue a construction permit not only when a state commission withheld approval of an application for more than one year but also when a state commission denied a permit within the statute's one-year time frame. In February 2009, in Piedmont Electric v. FERC, the Fourth Circuit rejected FERC's approach, finding that "when a state commission denies an application outright, it acts with transparency and engages in a legitimate use of its traditional powers," and thus FERC could not act as a "backstop" authority when a state denied an application.
The House Energy Bill revisits Piedmont Electric by authorizing FERC to issue certificates of public convenience and necessity for the construction or modification of transmission projects not only when a state commission delays action but also when it denies an application outright. In addition, rather than limit FERC's jurisdiction to "national interest electric transmission corridors," FERC's jurisdiction would be expanded to cover the entire United States portion of the Western Interconnection, which spans from the Pacific coast to the Great Plains, excluding most of Texas. The bill also requires increased coordination between federal agencies and voluntary coordination with state agencies, multistate entities, and Indian tribes, led by either FERC or the Department of the Interior.
The House Energy Bill would make an unusual distinction between FERC's role in the West and its role in the East. Limiting FERC's "backstop" authority to the Western Interconnection appears to respond to the different political concerns being expressed by Eastern and Western stakeholders. Specifically, stakeholders along the Eastern Seaboard have voiced concerns that broad federal "backstop" authority could disrupt potential offshore wind developments in the Atlantic by authorizing transmission projects to bring energy from wind resources in the West. In contrast, stakeholders in the West appear to welcome the interagency coordination required by the bill, which is intended to reduce the difficulties associated with permitting and completing projects on federal or other public lands.
In contrast, the Senate Energy Bill would give FERC the authority, nationwide, to certificate "high priority national transmission projects," which are projects that (1) operate above 300 kV (or that connect renewable energy projects directly to such a line), and (2) are included in a region-wide transmission plan. The bill gives states one year from the time of filing to approve the siting of such a line. FERC would then have jurisdiction over siting the line if a state has either failed to site the line or has denied the project's application.
Perhaps the most difficult challenge for a new transmission facility is identifying which stakeholders should pay for the new facility. This dilemma is particularly sharp in the case of renewable resources, where the best locations for wind farms could be hundreds of miles from customer loads. If a substantial portion of the cost of a new transmission line would be allocated to just a few customers, or to customers located in an undersized transmission zone, then stakeholders may decide that the project's cost exceeds its benefit. In contrast, the ability to successfully construct a new transmission project would be enhanced if its costs were spread across a broad region.
Unfortunately, the House Energy Bill is silent on cost allocation, and the Senate Energy Bill is limited. Specifically, the Senate Energy Bill merely directs FERC to conduct rulemaking proceedings to establish methodologies to pay for high-priority national transmission projects by allocating costs in a just and reasonable, nondiscriminatory manner. By itself, the Senate's general directive may not resolve these key cost-allocation questions.
In the meantime, FERC continues to address cost allocation matters by applying three principles. First, a transmission cost allocation proposal must show that it fairly assigns costs among participants, including those who cause them to be incurred and those who otherwise benefit from them. Second, the cost allocation proposal must provide adequate incentives to construct new transmission. Third, the cost allocation proposal should be generally supported by state authorities and participants across the region.
These three principles can lead to widely varying results in individual proceedings. In March 2009, FERC upheld the New York ISO's process for regionalizing the cost of new "economic" transmission projects. Rejecting a challenge by the New York Regional Interconnect ("NYRI")—a company that proposed to build a 1,200 MW transmission line from upstate New York to the New York City region—FERC accepted New York ISO's emphasis on cost savings over other potential considerations such as accessing renewable generation. FERC also approved a "supermajority" voting provision under which a project's costs will not be regionalized unless 80 percent of New York ISO's transmission customers approve the project. Shortly after FERC's New York ISO order, NYRI withdrew its application with the New York Public Service Commission to build its project. Among the reasons given by NYRI was that the effect of FERC's ruling was to give certain larger transmission customers who opposed the project a veto power over such cost recovery.
In contrast, in June 2009, FERC accepted a proposal by Southwest Power Pool, Inc. ("SPP") to change its tariff's cost-allocation rules as applied to wind resources. Currently, if the cost of a transmission project exceeds a "safe harbor" cost per MW of net dependable capacity, the excess cost is not eligible for regional cost allocation but instead must be assigned directly to the customer requesting the project. Because of the intermittent nature of wind generation, the net dependable capacity of a wind resource is a fraction of its total nameplate capacity. Under SPP's current rules, much of the cost of a transmission project serving a wind resource had to be assigned directly to specific customers rather than be allocated across the entire region. Under its proposal, the "safe harbor" calculation for wind resources uses nameplate capacity instead of "net dependable capacity," thus reducing the costs paid directly by a project designed to bring wind energy to market. In addition, 67 percent of the cost of an upgrade to serve wind resources will be allocated to the entire SPP region (as compared to just 33 percent for other resources). FERC recognized that it was treating transmission projects differently based on the type of resources being accessed but found that SPP's "distinct treatment of these location-constrained resources is not unduly discriminatory" because of the unique challenges faced by renewable resources.
While transmission cost allocation has emerged as a significant issue, transmission rate matters have been seen as less of an impediment to getting transmission built—but that could change. EPAct 2005 established new FPA Section 219, which requires FERC to establish incentive-based rate treatment for the transmission that benefits consumers by ensuring reliability and reducing the cost of delivered power by reducing transmission congestion. In applying FPA Section 219, FERC has issued dozens of orders granting "rate" incentives such as higher returns on equity, an opportunity to recover costs associated with abandoned projects, and earning a return on construction work in progress.
Commissioners Wellinghoff and Kelly have issued separate opinions explaining that they would restrict the availability and extent of transmission rate incentives under FPA Section 219. This more restrictive approach may control FERC's incentive-rate policies when a fifth Commissioner is appointed by the new administration. However, FERC seems likely to continue approving incentive-rate treatment for transmission projects that access renewable resources or deploy new, advanced technologies.
FERC also has encouraged transmission projects that access renewable energy by significantly revising its policy on negotiated rates for merchant transmission companies. Under its previous policy, FERC required merchant transmission companies applying for negotiated rates to allocate all of their initial capacity through an "open season." In a recent order approving negotiated rates for two Transcos, Chinook Power Transmission, LLC and Zephyr Power Transmission, LLC, FERC authorized anchor customers to hold 50 percent of the initial capacity on each proposed line. The new policy recognizes that a binding-capacity commitment from a financially capable generation developer is often required to bring remote, renewable energy to market. Allowing such anchor customers to make financial commitments to use up to half of a project's capacity makes it much easier for merchant transmission projects to finance the construction of long-distance, bulk transmission facilities.
With respect to transmission cost allocation, Congress is proposing few, if any, changes. In contrast, FERC continues to reassess its transmission cost allocation policies, and further developments at FERC could be key to accessing Clean Energy resources.