To date, efforts to incentivize and build a grid that accommodates a greater share of renewables have been slow. Renewable power developers cannot obtain financing and sign long-term contracts unless they know transmission is secured for their project, while utilities and other transmission developers will not invest in transmission unless they are assured of cost-recovery and a reasonable return. Furthermore, inefficient interconnection procedures have created a backlog of renewables projects that are unable to proceed while waiting in the transmission queue. Some states are even considering a roll back of their renewable portfolio standard (“RPS”) requirements due to high compliance costs.

As described below, the effort continues to improve renewable transmission access. Indeed, with this in mind, the Federal Energy Regulatory Commission (FERC) conducted a technical conference on March 15, 2011, to consider issues related to generator lead lines and the ownership of and priority access rights to new transmission projects.

Through Order Nos. 888 and 890, the FERC addressed deficiencies in the transmission planning process and implemented open access reforms, including the adoption of a pro forma open access transmission tariff (“OATT”) and planning and interconnection obligations. On June 17, 2010, FERC issued a Notice of Proposed Rulemaking (“NOPR”) aimed at further improving the effectiveness of regional transmission planning and the efficiency of resulting transmission development by establishing a closer link between transmission planning and cost allocation processes.

Under the NOPR, FERC proposed a variety of reforms including a focus on regional planning, consideration of public policy (including state RPS), rights of non-incumbent utilities to construct and own facilities, and cost allocation. At the same time, FERC issued two orders – Southwest Power Pool (“SPP”) “Highway/Byway” and Central Transmission v. PJM complaint – further clarifying permissible cost allocation and, in turn, the rights of non-incumbent utilities to own, operate and seek cost-of-service rates for regional expansion plan projects.

Furthermore, in terms of incentive-based rate treatments for transmission projects, the Energy Policy Act of 2005 added a new section (§ 219) to the Federal Power Act (“FPA”), directing FERC to develop incentive-based rate treatments for transmission of electric energy in interstate commerce. In response, FERC issued Order No. 679 and identified specific permissible incentives, to be approved by FERC on a case-by-case analysis, including but not limited to: (1) incentive rates of return on equity; (2) full recovery of prudently incurred construction work in progress, pre-operations costs, and costs of abandoned facilities; and (3) use of hypothetical capital structures, accelerated depreciation and accumulated deferred income taxes.

To be eligible for these incentives, facilities must either ensure reliability or reduce the cost of delivered power by reducing transmission congestion, with a presumption that this requirement is satisfied if the project has been included in a RTO’s regional transmission expansion plans or if the project’s host state has a formal siting process considered Section 219 requirements.Facilities also must demonstrate a nexus between the risks and challenges to develop the project and the requested incentives looking at the total package of incentives and whether the project is routine. FERC has, at times, interpreted this broadly, granting incentives to a project developed “in order to provide the infrastructure to meet state renewable energy standards” and to ensure reliable service to growing regional load.

FERC has also indicated that it is willing to consider innovative structures that spur large-scale renewable transmission investment, if the project addresses open access and affiliate issues. Indeed, FERC has issued several declaratory orders on innovative structures, most notably in regards to merchant transmission lines with negotiated rates, where an anchor tenant is selected pre-open season to demonstrate project financial viability. In the Chinook Order, for example, FERC established a test for approving future merchant transmission lines, under which it considers: (1) the reasonableness of rates; (2) the potential for undue discrimination and affiliate preference; and (3) regional reliability and operational efficiency requirements.

On January 21, 2010, moreover, FERC issued a Notice of Inquiry (“NOI”) and comments have been received regarding barriers to the integration of variable energy resources (“VERs”) into wholesale power grid. FERC recognized the existence of problems related to the inability of VERs to store and control electrical output and ramp, noting that the output from VERs is often negatively correlated to demand curve. FERC stated its objective to eliminate unnecessary barriers to transmission service and access to wholesale power markets for VERs and to increase efficiency. In the NOI, FERC sought comments on a number of issues, including data and forecasting; scheduling incentives and flexibility (such as intra-hour scheduling and balancing considerations), capacity market barriers, and curtailment issues.

In terms of interconnection queue reform, FERC has attempted to address some of the perceived shortcomings of Order No. 2003, which established standardized interconnection procedures based on a “first come, first serve” allocation. This method has increasingly led to developers holding queue positions for projects that may not be commercially viable causing interconnection request backlogs. In response, several RTOs/ISOs have instituted “queue reforms”, including studying projects in “clusters” and increasing deposit and milestone requirements, to implement more efficient interconnection procedures and eliminate potentially non-viable projects.

In the SPP, for example, as a customer progresses through the queues, deposit levels increase and the milestone requirements become more detailed. Once a project progresses to the final “facility study” stage, the relevant customer provides a letter of credit for its network upgrade costs share. “Interim” interconnection service is also provided for “ready to go” project; provided that there is sufficient stability and reliability margin.

Emphasizing the critical importance of these transmission issues, on March 15, 2011, FERC held a notice of technical conference regarding lead lines and the ownership of and priority access rights to new transmission projects – independent, merchant and utility-sponsored – and new business models for developing, owning, and operating electric transmission infrastructure including project owners seeking priority access to the transmission capacity it develops. FERC received a variety of presentations, including how the economics of a proposed project are affected by the Commission’s current affiliate rules and pricing structures (e.g., cost-based or negotiated rates) and the need for and appropriate application of priority access mechanisms, such as open seasons and anchor shipper/tenant arrangements, balanced with FERC’s open access and affiliate rules. Panelists included representatives from transmission developers, renewable power developers, utilities and other market participants.

Panelists described the difficulties in “right-sizing” or “up-sizing” new transmission. Because independent transmission developers design projects to suit the needs of customers that are both creditworthy and willing to commit to a service agreement, the capacity on the line may not be as great as system planners would otherwise desire. Discussion included the notion that independent transmission developers must carefully size projects in order to obtain financing and do not have captive customers from which to recover the costs of excess capacity. Certain participants also remarked that “first movers” – those who conceive of and obtain customers for new transmission projects – should receive benefits associated with shouldering these unique risks, including incentives and priority rights to the transmission they sponsor.

Concerns were expressed regarding right-sizing and single-use of new lines, which may not be optimal for system planning overall or in keeping with open access principles. FERC staff questioned participants about the tension between approving priority rights for certain customers on independent transmission projects and the FERC’s long-standing open access and non-discrimination requirements. Questions were raised as to whether open seasons were the appropriate method to “right size” transmission lines and avoid allocation disputes. Several participants remarked that FERC’s existing rules, including open access requirements and the availability of the FPA Section 206 compliant process, are sufficient protections and thus obviate the need to add regulatory layers to govern emerging business models necessary to develop needed transmission infrastructure.

An important topic included whether FERC should allow developers to have exclusive priority rights to the generator lead line for a period of time. This issue is of particular concern for wind developers because they may phase construction of several wind farms over a period of years and connect all of the facilities to the same lead line to the grid. If a third party (i.e., a competitor) can demand access to the lead line before all of the developer’s wind farms are complete, then the third party can effectively bump the developer’s planned wind generation off the line if there is insufficient capacity. Again, these issues were weighed against FERC’s open access polices and whether exceptions are required in certain circumstances. With this in mind, certain participants suggested that, rather than granting waivers, the FERC should consider a “slimmed down” radial line OATT or other lightened forms of regulation to accommodate tight construction and financing requirements typical of new generation development.

Participants also discussed the regulatory structure and its impact on potential partnerships between incumbent utilities and independent transmission developers to coordinate and construct transmission assets that serve both the interest of generation developers and broader regional planning needs. When utilities develop transmission, they also need alternative structures to meet different demands, including RPS requirements, and rate recovery for their outlay of capital.

FERC has issued a notice and will accept written comments until May 5, 2011, on the issues addressed in the technical conference issues. FERC may, thereafter, issue further guidance on the regulatory treatment of these transmission facilities. Although the issues are complex and interrelated, FERC and other market participants are focusing on these critical initiatives to encourage and streamline transmission infrastructure development and generator interconnection in order to meet national, regional and state requirements and goals.

About the Author

Gregory K. Lawrence is a partner in the Energy and Commodities group of the law firm Cadwalader, Wickersham & Taft LLP. Mr. Lawrence focuses his practice on regulatory proceedings, projects, negotiations, enforcement and agency litigation relating to the wholesale and retail electricity and natural gas industries. Mr. Lawrence thanks Joseph Williams, special counsel, and Dolly Donnelly, associate, with the Energy & Commodities group for their significant contribution to this article. The views expressed herein are solely those of the authors.