Gregory K. Lawrence, Partner
McDermott Will & Emery LLP
(Contributing Editor)

FERC in recent decisions has significantly modified its open access rules, allowing renewable generators to participate in and subscribe to transmission capacity without having to go through open bidding for the capacity. This reduces regulatory uncertainty and improves the prospects of certain renewable power developers. However, policy is still evolving as FERC works to find the best way to bridge the gap through transmission development incentives, cost allocation directives, VER operational accommodations, and transmission reservations for anchor tenants and participant funders.

Development Incentives, Cost Allocation and Operational Reforms

Under Federal Power Act Section 219, applicants for transmission development incentives must show that their facilities “either ensure reliability or reduce the cost of delivered power by reducing transmission congestion.” Incentives involve the recovery of construction work in program, pre-construction and abandonment costs, regulatory asset and amortization treatment, and a boost to the return on equity. A rebuttable presumption exists that the test is satisfied if the transmission project is part of a regional transmission expansion plan or a state siting process considering these issues.

For incentivizing the massive capital necessary for interconnection projects, recovering construction costs remains the crucial issue. Cost recovery associated with greater development risk depends on a higher return on equity, which in turn depends on dealing with amortization and depreciation issues. One innovative proposal for cost allocation would be construction work in progress (CWIP) financing, which allows utilities to recover the financing costs, including rate of return, from ratepayers during the construction of new facilities. In essence, CWIP encourages utility management to pursue transmission construction that it otherwise might not because of undue financial risk.

Importantly, FERC lately has interpreted these requirements more broadly, such that incentives have been made available to transmission projects that were not directly proposed to relieve congestion or meet a specific reliability need. In late 2009, for example, Otter Tail Power Company was granted incentives for a project to meet state RPS and ensure the project can meet regional load growth reliably – a more liberal Section 219 interpretation.

In June 2010 FERC went further, issuing a Notice of Proposed Rulemaking (NOPR), which seeks to reform its electric transmission planning and cost allocation requirements for public utility transmission providers. Among other provisions, the NOPR provides equal treatment for incumbent and non-incumbent transmission providers. An incumbent provider would not be allowed to have a right of first refusal with respect to facilities that are included in a regional transmission plan and subject to FERC jurisdiction, and both incumbents and non-incumbents would share similar benefits and obligations commensurate with their participation, including the right to construct and own a facility sponsored in a regional transmission planning process.

This builds on the 2007 Commission Order No. 890, which sought to remedy the potential for undue discrimination in transmission planning activities by requiring each public utility transmission provider to develop a transmission planning process that satisfies nine principles of openness and transparency. The NOPR uses this opening to address current regulations for allocating costs of new transmission facilities, where the transmission provider that builds a new facility must open it up to companies that have not paid for its construction.

Under the NOPR, the cost of transmission facilities must be allocated to those within the transmission planning region that benefit from those facilities in a manner that is at least roughly commensurate with estimated benefits.

Those that receive no present or likely future benefit from transmission facilities must not be involuntarily allocated the costs of those facilities.

For VERs, such cost allocation considerations go to the heart of their ability to secure grid access in a way such that they are not treated in an unduly discriminatory manner. From the VER perspective, much of FERC’s current regulatory structure reflects an outdated power resource picture from the one emerging under state RPSs.

Equal access can be facilitated by faster power system dispatch and scheduling, larger and more geographically diverse balancing areas, and promotion of region-wide load following markets and ancillary services markets – particularly where Regional Transmission Organizations (RTOs) and Independent System Operators (ISOs) do not include VERs. In the NOPR, FERC therefore proposed to require each RTO, ISO and public utility transmission provider that is not in an RTO or ISO region to establish a method, or set of methods, for allocating the costs of new transmission facilities that are included in the regional transmission plan. Cost allocation methods may distinguish among facilities that are driven by needs associated with maintaining reliability, relieving congestion and achieving public policy requirements.

“Innovative Proposals”

Such innovative policies alone may not be enough to address the major challenge at hand: how to get geographically diverse wind and other resources to market while encouraging the development of large, inter-regional transmission projects. In recent orders FERC has addressed this issue by showing its willingness to entertain a more flexible approach to open access to the extent it supports transmission financing than it has in the past to facilitate the construction of needed transmission facilities.

For example, in Mountain States Transmission, FERC emphasized its commitment to the development of new transmission infra­structure, and stated that it remains “flexible” in evaluating new proposals for transmission development and pricing. FERC acknowledged the need for “innovative proposals” to develop new transmission projects, especially in regions with potential to deliver renewable energy to load centers, but added that this flexibility cannot “compromise consumer protections.”

The 2009 FERC decisions in the Zephyr and Chinook cases provided an impetus to the development of new transmission. In these cases, for the first time, FERC permitted up to 50 percent of the capacity in a transmission line still in the planning and development phase to be pre-sold to an anchor customer. The anchor customer was a wind developer that negotiated a rate covering a 25-year term for 50 percent of the project’s total capacity. FERC allowed the anchor customer to be established before an open season in order to demonstrate financial viability of project. Both projects committed to giving other customers the same rate, terms and conditions as the anchor customer. Prior to this order, FERC had required merchant transmission developers to sell all of a prospective transmission line’s capacity through an open-season process. This hindered project development because of a chicken and egg effect: potential subscribers were unwilling to commit significant resources until a transmission developer could show that the project had commercial support.

In the Milford case, Milford Wind Corridor, a developer of phased-in wind generation, filed a request to confirm its priority with respect to 1,000 MW worth of capacity on the 88 mile, 345 kV Milford transmission line connecting the generation to the grid. The wind generation was to be constructed in five phases, but the entire transmission would be available all at once. Rates were negotiated (i.e., not cost-of-service).

FERC granted the request, reasoning that Milford had specific plans and milestones for construction, with demonstration of material progress towards meeting the milestones for phased development of its generation. However, FERC indicated that Milford would have to make the unused capacity available to requesting third parties until Milford was ready to sue it for its generation, and to expand the line’s capacity to meet demand if sufficient capacity is not available.

Northeast Utilities Service Company (Northeast) and NSTAR Electric Company (NSTAR) requested a declaratory order approving the structure of a transaction involving a cost-based participant-funded transmission project that included a long-term bilateral transmission service agreement. FERC approved the transaction, explaining that the proposal did not contravene the Commission’s open access requirements in Order 890 and was not anticompetitive.

The Commission also found that providing for participant funding of a transmission facility with priority rights to use that facility is fully consistent with its long-standing open access policies. Importantly, FERC determined that Northeast and NSTAR, as owners of a non-merchant, cost-of-service rate line, could enter into a transaction granting another, unaffiliated entity priority rights to the first 1,200 MW of capacity on the new line without holding an open season and did not have to comply with the test set out in Chinook and Zephyr for merchant transmission proposals.

Clear Support

When taken together, FERC’s decisions in Otter Tail, Mountain States Transmission, Zephyr and Chinook, and Northeast and NSTAR indicate a clear pattern of support and regulatory innovation for VER access to the transmission grid. By endorsing regional transmission planning processes and cost recovery/allocation approaches that open the playing field for VERs, the Commission is on record as supporting the broader goals of eliminating unnecessary barriers to VER grid and market access and increasing the efficiency of VER utilization.

More “innovative proposals” to further this goal and link geographically diverse renewable power resources with the grid are sure to come including different financing incentives and transmission reservation structures.

About the Author

Gregory K. Lawrence is a partner in the Energy and Derivatives Markets Group of global law firm McDermott Will & Emery, and leads the firm’s Global Renewable Energy, Emissions and New (GREEN) Products group. Mr. Lawrence focuses his practice on regulatory proceedings, negotiations, governmental affairs and agency litigation relating to the wholesale and retail electricity and natural gas industries.