Maine PUC considers NTA coordinator

Maine utility regulators have launched an investigation into the designation of a "Non-Transmission Alternative Coordinator."  The case could shape whether and how Maine coordinates alternatives to electric transmission line development.

Non-transmission alternatives or NTAs are smart grid programs and technologies that complement and improve operation of existing electricity transmission systems, deferring or eliminating the need for upgrades to the transmission system.  NTAs can an deliver improvements to the grid at a lower cost than some transmission projects.  Distributed generation, storage, and demand response can play roles in NTA projects.

In Maine, legislative policy supports selecting NTAs over transmission development if an NTA can meet an identified reliability need at a lower cost to consumers than the proposed transmission project.  But under current law, no single entity formally coordinates or is required to postulate alternatives to transmission development.

In previous cases, the Maine Public Utilities Commission has investigated the need for a smart grid coordinator, approved a non-transmission alternative pilot project in the Boothbay region, and considered the scope of what an NTA Coordinator might do.  From these dockets, a vision has emerged of the NTA Coordinator as an entity that would develop cost-effective alternatives to transmission projects.  Under this vision, the NTA Coordinator would address the policy and goals of the Maine's Smart Grid Policy Act to “improve the overall reliability and efficiency of the electric system, reduce ratepayers’ costs in a way that improves the overall efficiency of electric energy resources, reduce and better manage energy consumption and reduce greenhouse gas emissions.”

But key questions remain, including whether and how an NTA Coordinator will be designated, the scope of its functions and duties.  Another fundamental question is whether these functions will be performed by transmission and distribution utilities, or by some third party entity.

In a Notice of Investigation dated April 4, 2016, the Maine Public Utilities Commission opened its investigation into these questions.  The notice describes the proceeding as focused on one approach to economically optimizing the electric system between generation and transmission:

Specifically, through this proceeding, the Commission expects to address this legislative policy by (1) developing the framework for selecting a NTA Coordinator and (2) determining the scope of the NTA Coordinator’s functions and duties. The Commission will also resolve the question of whether a third party entity or the transmission and distribution (T&D) utilities should perform the NTA Coordinator functions. This investigation will also address the role of an Advisory Planning Committee (APC) and the process for NTA development both within a CPCN proceeding and for transmission and distribution projects that are not required to file a CPCN petition. Finally, an end-product of this proceeding will be either the contours of an RFP or that of a rate incentive proposal should the Commission determine that the utility and not a third party should perform the functions of an NTA Coordinator.

Along with the notice of investigation, the Commission also issued "Strawman" and "Process Chart" documents for comment.

The notice set deadlines for filing petitions to intervene by April 21, 2016, and for comments on the Strawman and Process Chart by April 28, 2016.  An initial case conference was scheduled for May 12, 2016.

Waterbury hydro need and economics

A recent order issuing a new hydropower license to Green Mountain Power Corporation's Waterbury Hydroelectric Project sheds insight into the project's operations and economics.

The Waterbury project is located at a dam built in 1938, and licensed for hydropower development since 1954.  After a 16-year relicensing process, the Federal Energy Regulatory Commission issued a new license for the project in February 2016, authorizing 5.52 megawatts of generating capacity.  That relicensing process illustrates how the Commission considers the need for power from the project, as well as project economics, when considering whether to relicense a hydropower project.

By regulation, the Commission's process for reviewing a license application includes an evaluation of the "need of the applicant over the short and long term for the electricity generated by the project or projects to serve its customers."  In the Waterbury project's relicensing case, this consideration of the applicant's "need for power" involved observations about the project's expected output as well as the regional power market.  The order notes historic average generation from the Waterbury Project of 17,562 MWh annually, but observes that under the new license average annual generation will be reduced to 14,767 MWh.

The order then states, "Electricity generated from the Waterbury Project will help supply the power needs in northern Vermont."  It also cites a 10-year forecast by electric reliability organization North American Electric Reliability Corporation (NERC) showing summer peak demand in the region is expected to increase at an average rate of 0.84 percent per year between 2014 and 2023.  Based on this, the order concludes that "the project's power will help meet the regional need for power."

The Commission's process for determining whether to issue a new license for an existing hydroelectric project also includes consideration of public interest factors, such as the economic benefits of project power.  A 1995 decision established the Commission’s approach to evaluating the economics of hydropower projects.  Under that approach, the Commission uses current costs to compare the costs of the project and likely alternative power with no forecasts concerning potential future inflation, escalation, or deflation beyond the license issuance date.  The Commission has described the basic purpose of this economic analysis as to provide a general estimate of the potential power benefits and the costs of a project, and of reasonable alternatives to project power, "to support an informed decision concerning what is in the public interest with respect to a proposed license."

For the Waterbury project, as ultimately licensed with mandatory conditions and staff measures, the Commission concluded that:

• the levelized annual cost of operating the project is $711,735, or $48.20/MWh
• the proposed project would generate an average of 14,767 MWh of energy annually.
• average generation is multiplied by the alternative power cost of $44.12/MWh, for a total value of the project’s power is $651,520, in 2015 dollars.

Therefore, the Commission concluded that in the first year of operation, the project would cost $60,215, or $4.08/MWh, more than the likely alternative cost of power.  As the order notes, "Although staff’s analysis shows that the project as licensed herein would cost more to operate than the estimated cost of alternative power, it is the applicant who must decide whether to accept this license and any financial risk that entails."

The Commission did note that its consideration of public interest factors also considers that "hydroelectric projects offer unique operational benefits to the electric utility system", including ancillary services like stability and rapid response.  The order also notes that while staff did not explicitly account for the effects inflation may have on the future cost of electricity, hydropower generation is relatively insensitive to inflation compared to fossil fueled generators -- illustrating why "project economics is only one of the many public interest factors the Commission considers in determining whether or not, and under what conditions, to issue a license."

Merced River hydro relicensing Environmental Impact Statement released

Staff of the Federal Energy Regulatory Commission have released a final Environmental Impact Statement (EIS) evaluating proposals to relicense two hydroelectric power projects located on the Merced River in California.

The two projects are Merced Irrigation District’s existing 101.25 megawatt Merced River Project No. 2179-043, and Pacific Gas and Electric Company’s (PG&E) existing 3.4-MW Merced Falls Project No. 2467-020.  Prepared as part of the relicensing process for those projects, the Merced River EIS contains FERC staff evaluations of the applicants’ proposals and the alternatives for relicensing the Merced River and Merced Falls Hydroelectric Projects.  The staff’s recommendation is to relicense the project as proposed, with certain modifications, and additional measures recommended by the agencies.

The Federal Energy Regulatory Commission is authorized by the Federal Power Act to issue licenses for up to 50 years for the construction and operation of nonfederal hydroelectric development subject to its jurisdiction, on condition:

That the project adopted…shall be such as in the judgment of the Commission will be best adapted to a comprehensive plan for improving or developing a waterway or waterways for the use or benefit of interstate or foreign commerce, for the improvement and utilization of water-power development, for the adequate protection, mitigation, and enhancement of fish and wildlife (including related spawning grounds and habitat), and for other beneficial public uses, including irrigation, flood control, water supply, and recreational and other purposes referred to in section 4(e)…

The Commission may also require such other conditions not inconsistent with the FPA as may be found necessary to provide for the various public interests to be served by the project.  To assist in this evaluation, and as required by the National Environmental Policy Act, FERC staff prepares the EIS.  It is designed to record the view of governmental agencies, non-governmental organizations, affected Indian tribes, the public, the license applicants, and FERC staff.

In the Merced River cases, the licensees used FERC's Integrated Licensing Process (ILP) and filed relicensing applications in February 2012.  FERC elected to process the applications for the two projects together "because they: (1) are located contiguously on the Merced River; (2) the Merced Falls Project’s operation depends entirely on flows released by the upstream Merced River Project; and (3) downstream of the Merced River Project, the environmental effects of both projects are interrelated."

Each applicant proposed some modified environmental measures in its license application, but no new capacity and no new construction at the project.  In the Merced projects' 840-page final EIS, Commission staff noted that the "primary issues associated with relicensing the projects are flow regimes in project-affected reaches for aquatic resources, project effects on physical habitat for aquatic resources, protection of wildlife resources, recreation enhancements, and protection of cultural resources." After consideration, Commission staff recommended the staff alternative, which consists of measures included in Merced ID’s and PG&E’s proposals, as well as some of the mandatory conditions and recommendations made by other state and federal agencies and non-governmental organizations, plus additional measures developed by FERC staff:

We chose the staff alternative as the preferred alternative because: (1) the projects would provide a dependable source of electrical energy for the region; (2) the generation comes from a renewable resource that does not contribute to atmospheric pollution, including greenhouse gases; and (3) the recommended environmental measures proposed by Merced ID and PG&E, as modified by staff, would adequately protect and enhance environmental resources affected by the projects. The overall benefits of the staff alternatives would be worth the cost of the environmental measures.

Ultimately, the Merced River hydropower relicensing project EIS concludes that "issuing new licenses for the Merced River and Merced Falls Projects, with the environmental measures we recommend, would not be major federal actions significantly affecting the quality of the human environment."