FERC policy on hydropower license term

U.S. hydropower regulators have issued a new policy setting a default term of 40 years for original and new hydropower licenses, while identifying three circumstances that could warrant longer or shorter terms.  The Federal Energy Regulatory Commission's revised policy statement on establishing license terms could reduce cost and uncertainty for hydroelectric projects under its jurisdiction.

Federal law gives the Federal Energy Regulatory Commission jurisdiction over licensing most hydroelectric projects located at non-federal dams.  Section 6 of the Federal Power Act authorizes the Commission to issue hydropower licenses for a term not to exceed 50 years, but leaves the Commission some discretion to issue licenses for shorter terms.  

Prior to the October 19, 2017 policy statement, the Commission’s policy for projects located at non-federal dams was to offer a 30-year term where there is little or no authorized redevelopment, new construction, or environmental mitigation and enhancement; a 40-year term for a license involving a moderate amount of these activities; and a 50-year term where there is an extensive amount of such activity.  The Commission has found that measures including the construction of pumped storage facilities, fish passage facilities, fish hatcheries, substantial recreation facilities, dams, and powerhouses warranted longer license terms.

But after licensees and other stakeholders contested license terms in several recent cases, on November 17, 2016, the Commission issued a notice of inquiry seeking comments on whether, and if so how, it should revise its license term policy in effect at that time. As characterized by the Commission, most hydropower industry commenters supported the certainty offered by longer default terms, while most environmental groups, individuals, and resource agencies opposed them on various grounds.

On October 19, 2017, the Commission issued its Policy Statement on Establishing License Terms for Hydroelectric Projects. The new policy establishes a 40-year default license term for original and new licenses under the Commission’s jurisdiction with exceptions for coordination, deference to generally-supported comprehensive settlement agreements, and consideration of previously-authorized voluntary actions.  According to the policy statement, these exceptions will apply:

• When necessary to coordinate license terms for projects located in the same river basin;
  
• When a license term is explicitly agreed upon in a generally supported comprehensive settlement agreement, provided that there is no conflict with coordination of license terms for projects located within the same river basin; and
  
• When significant measures are required under the license to be issued, or significant measures were voluntarily implemented during the prior license term, provided it does not conflict with coordination of license terms for projects located within the same river basin.

According to a presentation by Commission staff, the new policy "will provide greater certainty to licensees, resource agencies, and other stakeholders," will reduce administrative costs and provide licensees longer license terms to recoup costs, and could encourage licensees to voluntarily make improvements or agree with stakeholders to a license settlement agreement.

According to the Commission, it will apply this new policy to licenses issued following the date of its publication in the Federal Register with no retroactive application.  While the Commission said it would not entertain applications to amend existing licenses to extend their license terms simply on the basis of this new license term policy, it noted that license applicants with pending license applications may file a comprehensive settlement agreement, or an addendum to an existing agreement, that includes an explicitly agreed upon license term, or may make a filing demonstrating why the Commission should award them a longer license term.

Maine utility water supply inquiry

As Maine utility regulators consider how drought and other factors affect water utility supplies, staff at the Maine Public Utilities Commission have again requested comments and information on water supply emergencies and regulatory responses.  The feedback will inform a preliminary staff recommendation to be released in January 2017, which could lead to changes in how Maine regulates water utility supplies.

Drought and water shortage are affecting parts of the U.S., including much of New England.  In October, the Maine Public Utilities Commission issued a Notice of Inquiry (NOI) into water supply issues.  The Commission requested information about water supply problems, potential solutions, and development of plans to address any problems identified.  Specifically, the Commission posed 14 questions about water supply emergencies, plus 9 more questions about how the Commission should respond to water supply emergencies.  The Commission requested responses to these questions by November 4, 2016.

Some Maine water utilities responded to the Commission's water supply Notice of Inquiry, but many did not file a public response.  In a November 28, 2016 Procedural Order, Commission staff expressed a firm belief "that the more input the Commission receives from affected parties, the greater the likelihood that the final outcome in this Inquiry will meet the needs of those affected parties."  Accordingly, the procedural order invites any entity that did not initially respond to the NOI to do so by December 23, 2016.

The November 28 procedural order establishes a schedule for the remainder of the inquiry.  Staff intends to issue a Preliminary Recommendation in January, to which interested persons will be invited to respond during February, whether orally or in writing.  The schedule contemplates that staff would incorporate written and oral comments regarding the Preliminary Recommendation into a Final Recommendation in March, for presentation to the Commissioners during April.

The Commission has docketed the Maine water supply inquiry as Docket No. 2016-000233.

FERC considers hydro license term policy

U.S. hydropower regulators have requested public comments on whether to revise a policy setting the length of license terms for hydroelectric projects.  The Federal Energy Regulatory Commission's notice of inquiry could lead to changes in how the Commission sets license terms.

Under Section 6 of the Federal Power Act, the Commission may issue hydropower licenses for a term not to exceed 50 years.  Original licenses have no minimum license term.  Section 15(e) of the Federal Power Act provides that any new license (i.e. relicense) shall be for a term that the Commission determines to be in the public interest, but not less than 30 years or more than 50 years.

Within these statutory bounds, the Commission has discretion to set its own policy governing the term length of hydropower licenses.  At present, the Commission policy is to set a 50-year term for licenses issued for projects located at federal dams. For projects located at non-federal dams, the Commission’s current policy is to set a 30-year term where there is little or no authorized redevelopment, new construction, or environmental mitigation and enhancement; a 40-year term for a license involving a moderate amount of these activities; and a 50- year term where there is an extensive amount of such activity.

The Commission has described the purpose of this policy as "to ease the economic impact of new costs, promote balanced and comprehensive development of renewable power generating resources, and encourage licensees to be better environmental stewards."  But the lengths of new licenses have been contested in several recent relicensing proceedings, in which parties have argued that the Commission should have considered or given more weight to other factors.  These other factors proposed for consideration include capacity-related investments or environmental enhancements made by the licensee during the current license and before issuance of the new license; total cost of the relicensing process; losses in generation value related to environmental measures; the license terms of projects that the licensee states are similarly situated to its project; and the license term provided for in settlement agreements.

In a November 17, 2016 notice of inquiry, the Commission outlined five potential options that Commission staff has identified for establishing license terms:

(1) retain the existing license term policy; (2) add to the existing license term policy the consideration of measures implemented under the prior license; (3) replace the existing license term policy with a 50- year default license term unless the Commission determines that a lesser license term would be in the public interest (f or example, to better coordinate, to the extent feasible, the license terms for projects in the same river basin for future consideration of cumulative impacts); (4) add a more quantitative cost- based analysis to the existing license term policy ; and (5) alter current policy to accept the longer license term agreed upon in an applicable settlement agreement, when appropriate. 

The Commission now seeks comment on issues relating to license terms, due within 60 days from the Notice of Inquiry's November 25 publication in the Federal Register.

Maine opens net metering inquiry

The Maine Public Utilities Commission has issued a Notice of Inquiry to obtain feedback on whether its net energy billing rules should be modified, or other action taken to affect Maine's net metering policy.

Rooftop solar panels on a Maine business.

Under Chapter 313 of the Commission's rules, Maine electricity customers may net the output of qualified solar panels or other distributed generation resources against their utility loads.  To date, this rate treatment, known as "net energy billing," has been a major incentive for the development of solar photovoltaic and other customer-sited renewable energy projects in Maine.  Most other U.S. jurisdictions have adopted similar net metering programs.

But the Maine regulations provide for a review by the Commission of its rules once a utility gives notice that net metered capacity reaches 1% of peak demand.  Maine transmission and distribution utility Central Maine Power Company gave that notice earlier this year.

At a deliberative session held on June 14, the Commission unanimously decided to initiate an inquiry into the matter.  The Commission's 4-page Notice of Inquiry seeks comment and information on a list of specific issues related to the net metering rules.  Issues identified in that notice include possible changes to the value of net metering credits or the kinds of customer generating facilities may be net metered, grandfathering of existing systems, the adoption of consumer protection standards, and an alternative contracting structure:

1. In what respects (if at all) should Chapter 313 be revised, and what objective is each such revision intended to achieve?

2. In what respects (if at all) should there be revisions to the retail rate components that are netted such that less than the full retail rate (T&D and supply) would be netted, and what objectives are such revisions intended to achieve?

3. Should the Commission consider changes in the current kWh (660kW) threshold for qualified projects? What is the rationale for such a change?

4. If there are revisions to NEB, should existing NEB customers be “grandfathered” with respect to any future changes that affect NEB? Please provide the rationale for your answer, and, if yes, for how long should customers be grandfathered?

5. How can an NEB program be designed to track changes in the costs of distributed generation facilities?

6. Should issues of revenue loss and rate impacts be addressed through T&D utility rate design? How should rate design be approached--through cost of service, avoided cost, or a value of solar approach? Please discuss any equity issues that might arise from these approaches.

7. With respect to the structural app roach discussed in the Commission’s Report to the Legislature Regarding Market-Based Solar Policy Design Stakeholder Process Pursuant to Resolves 2015, ch. 37 (Jan. 30, 2016) (which was the basic structural approach that was considered by the Legislature last session through LD 1649) in which the output from solar facilities would be purchased and re-sold into the wholesale market, please comment on the statutory authority under which the Commission could implement such an approach. In the event the Commission has the statutory authority, should the Commission pursue such an approach and, if so, how should the purchase price be established for the various distributed generation resources that participate in NEB?

8. Should solar PV be treated differently than other NEB eligible resources with regard to any changes that might be adopted to the program?

9. How should any changes to NEB arising from CMP’s January 14, 2016 letter request for review apply to Emera Maine and the consumer-owned utilities?

10. Does the Commission have statutory authority to regulate or oversee lease arrangements or other custom er agreements that involve NEB? If so, should the Commission consider additional consumer protection standards with respect to distributed generation lease programs or other customer arrangements (i.e., sales of community solar project shares)?

11. Please comment on any other issues related to NEB?

The Commission requested comments on these issues by July 22, 2016.  Public comment and information will help inform the Commission's review of its Chapter 313 rules.