Stanford declines to divest fossil fuels

Thursday, April 28, 2016

Should university endowments be invested in fossil fuel companies?  Or should they divest such holdings? Universities across the U.S. are considering these questions.  In the latest development, Stanford University's Board of Trustees has released a statement on climate change, describing the university's initiatives to battle climate change, but declining to divest Stanford's roughly $22 billion endowment from the fossil fuel industry.

In the April 25 statement, the Board describes climate change as "among the most serious challenges of our time."  The statement lists various elements of Stanford's strategic approach to combating climate change, including a $500 million transformative campus energy system, commitments to invest in solar, other renewable energy, wastewater recovery, green transportation, and energy efficiency in campus buildings.  The statement also announces the creation of a new climate task force to be composed of undergraduates, graduate students, faculty and staff, to solicit ideas for further action.

Much of the statement is structured as a response to a proposal by student organization Fossil Free Stanford that the university divest its endowment from the fossil fuel industry.  The trustees cite the university's Statement on Investment Responsibility as outlining a specific set of criteria by which the trustees may evaluate whether a company is inflicting social injury in a manner that warrants consideration of divestment.  The statement notes the establishment of an Advisory Panel on Investment Responsibility and Licensing, which studied the issues and made a recommendation to the Board’s Special Committee on Investment Responsibility, which in turn made a recommendation to the trustees.

According to the statement, the advisory panel "recommended divestment of companies whose primary business is oil sands extraction, a method that studies have found requires more water, and releases more carbon into the atmosphere, than other forms of fossil fuel extraction."  It cites Stanford Management Company as saying that the Stanford endowment has no direct exposure to companies whose primary business is oil sands extraction, so the trustees had no action to take on this point.

On the broader fossil fuel industry, the panel "concluded that it could not evaluate whether the social injury caused by the fossil fuel industry outweighs the social benefit it provides, and therefore did not recommend divestment."  The trustees agreed that the criteria were not met, and declined to divest.

That said, the statement expressed the trustees' belief "that the global community must develop effective alternatives to fossil fuels at sufficient scale, so that fossil fuels will not continue to be extracted and used at the present rate... the long-term solution is for all of us to reduce our consumption of fossil fuel resources and develop effective alternatives."

But despite investment and progress in research, including by Stanford, the trustees note that "at the present moment oil and gas remain integral components of the global economy, essential to the daily lives of billions of people in both developed and emerging economies."  The statement also notes the efforts of some oil and gas companies to explore alternatives.  The statement notes that "the trustees do not believe that a credible case can be made for divesting from the fossil fuel industry until there are competitive and readily available alternatives."

The statement also notes that the university's investment program does take climate change into consideration when evaluating the economic attractiveness of various investments.  In the trustees' words, "Prudent investors acknowledge that the world is beginning a transition away from carbon-based energy sources and that pricing for fossil fuels will reflect this transition."  The statement also notes the efforts of the endowment managers to "identify and support industry best practices that, in addition to positively impacting investment results, may pay significant environmental dividends."

This is not the first time Stanford has considered divesting from fossil fuels.  In 2014, after pressure from Fossil Free Stanford, the trustees announced a decision that Stanford would not make direct investments in coal mining companies, in recognition of "the availability of alternate energy sources with lower greenhouse gas emissions than coal."

FERC staff recommends against Bear River dam

Wednesday, April 27, 2016

Staff of the U.S. Federal Energy Regulatory Commission have recommended against licensing a dam, reservoir, and hydropower project proposed for the Bear River near Preston, Idaho.

The case involves a 2013 application by Twin Lakes Canal Company to the FERC for a license to construct, operate, and maintain the Bear River Narrows Project.  The project would be located on the main stem of the Bear River in Franklin County, Idaho, about 9 miles northeast of the city of Preston. It would feature a 109-foot-high dam impounding a 362-acre reservoir, and a powerhouse with an installed capacity of 10 megawatts and estimated average annual generation of of 48,531 megawatt-hours of electricity.  The reservoir would also be used to provide up to 5,000 acre-feet of water to Twin Lakes’ irrigation system during dry years.

Under the Federal Power Act, the FERC is charged with processing licenses for most hydropower projects in the U.S.  Federal law guides the FERC in this duty.  Sections 4(e) and 10(a)(1) of that act require the Commission to give equal consideration to the power development purposes and to the purposes of energy conservation; the protection of, mitigation of damage to, and enhancement of fish and wildlife; the protection of recreational opportunities; and the preservation of other aspects of environmental quality.  The Commission can only issue licenses that in its judgment are best adapted to a comprehensive plan for improving or developing a waterway or waterways for all beneficial public uses.  Additionally, the National Environmental Policy Act of 1969 requires the agency to analyze and document the environmental effects of proposed federal actions such as granting Twin Lakes' application.

Commission staff released its final environmental impact statement on Twin Lakes' license application on April 27, 2016.  That document, called an EIS, analyzes the effects of proposed project construction and operation, and recommends conditions for any license that may be issued for the project.

In the Bear River Narrows Project EIS, FERC staff considered Twin Lakes’ proposal for licensing, as well as three alternatives: (1) no-action (i.e. not licensing the project, so it can't be constructed); (2) the applicant’s proposal with staff modifications (staff licensing alternative); and (3) the staff licensing alternative with an additional condition requested by the Bureau of Land Management.

The EIS notes the existence of four Commission-licensed hydroelectric facilities located on the Bear River in Idaho with a combined installed capacity of more than 78 MW, including the Oneida development directly upstream.  It also notes uses of the "Oneida Narrows" section of the Bear River that would be flooded by the Bear River Narrows Project impoundment, including a recreational trout fishery and boating opportunities, and habitat for sensitive wildlife species.

Based on a review of the anticipated environmental and economic effects of the proposed project and its alternatives, as well as the agency and public comments filed on this project, staff recommends no action (license denial) as the preferred alternative.  In staff's words, "The overall, unavoidable adverse environmental effects of both action alternatives would outweigh the power and water storage benefits of the project."

For these reasons, FERC staff concluded that "any license issued for the proposed project could not be best adapted to a comprehensive plan for improving or developing the Bear River for all of its beneficial public uses, especially its substantial public recreation use at the proposed project site. We, therefore, recommend license denial."

Twin Lakes Canal Company's application to the Commission for a license to construct the project remains pending.

Maine enacts biomass energy support

Thursday, April 21, 2016

Maine has adopted a new law to support the state's biomass energy industry.  Governor Paul LePage has signed LD 1676, An Act To Establish a Process for the Procurement of Biomass Resources, as emergency legislation.  As a result, the bill has been enacted into law as Public Law, Chapter 483, from the 127th Maine Legislature.

The Maine State House.

The bill directs the Maine Public Utilities Commission to initiate a competitive solicitation as soon as practicable.  That solicitation will ask for proposals for 2-year contracts for up to 80 megawatts of biomass resources.  To qualify, a biomass resource must be a source of electrical generation fueled by wood, wood waste or landfill gas that produces energy that may be physically delivered to the ISO New England or Northern Maine Independent System Administrator markets.  A resource must also operate at least at a 50% capacity for 60 days prior to the initiation of a competitive solicitation and continues to operate at that capacity except for planned and forced outages.

The law gives the Commission some direction on how to select proposals for contracting.  It requires the Commission to seek to ensure, "to the maximum extent possible" that a contract provides benefits to ratepayers as well as in-state economic development benefits, reduces greenhouse gas emissions, promotes fuel diversity, and supports or improves grid reliability.

The costs of the contracts, other than above-market costs, and all direct financial benefits from the contracts must be allocated to ratepayers according to Maine's statute on allocation of costs and benefits of long-term energy contracts.  Above-market costs will be paid for from a cost recovery fund created by the new law, which allocates up to $13.4 million from the unappropriated surplus of the state's General Fund. 

FERC grid modernization session

Wednesday, April 20, 2016

U.S. federal energy regulators convene tomorrow to discuss modernization of the nation’s electric power grid.

Recent years have brought significant changes in technology and the ways we use energy.  From distributed energy resources like solar panels to a variety of "smart grid" applications, society has new tools that may be able to improve the nation's energy sector.  As a result, state and federal energy regulators are considering "grid modernization."  Issues in play can include whether improvements to the nation’s electric power grid are appropriate, and if so, how to fund them.

For several years, the Federal Energy Regulatory Commission has considered grid modernization issues.  Now, the Commission has scheduled a grid modernization event for tomorrow.

At the Commission's April meeting, it will hear from representatives from the U.S. Department of Energy, including Patricia A. Hoffman, assistant secretary for the Office of Electricity Delivery and Energy Reliability, and Roland Risser, acting deputy assistant secretary for Renewable Power.  The Energy Department will also offer panelists from its National Renewable Energy Laboratory, Pacific Northwest National Laboratory, Idaho National Laboratory, Sandia National Laboratories, and Lawrence Berkeley National Laboratory. 

Following the FERC meeting, the panelists will be available for a post-meeting information session on the work of the Grid Modernization Laboratory Consortium.  Panelists are expected to discuss devices and integrated systems, sensing and measurement, system operations, control and power flow, design and planning tools, security and resilience, and institutional support.

Supreme Court rules on state energy incentives

Tuesday, April 19, 2016

The U.S. Supreme Court has released its ruling on a case affecting how states may provide incentives for electric power generation.  In Hughes v. Talen Energy Marketing, LLC, the Court upheld a lower court's ruling invalidating a Maryland program to subsidize construction of new power plants.  The ruling provides important insight into how the Court views the boundary between federal and state jurisdiction over energy matters.

The Supreme Court of the United States.

The Hughes case involved a new Maryland program to encourage in-state generation capacity, and its relationship to federally blessed capacity market.  Under the Federal Power Act, the Federal Energy Regulatory Commission has exclusive jurisdiction over wholesale sales of electricity in the interstate market, while States regulate retail electricity sales. 

For years,  Mid-Atlantic regional grid operator PJM Interconnection has held capacity auctions to identify need for new generation and compensate generators for development.  PJM's auctions have been approved by the Federal Energy Regulatory Commission under the Federal Power Act.  But due to concern that the PJM auction was failing to encourage development of sufficient new in-state generation, Maryland enacted its own regulatory program.  Under that state program, Maryland held a competitive process to select a developer for a new power plant, and required load-serving entities to enter into a 20-year pricing contract (called a "contract for differences") with the developer.  The developer would still sell its capacity to PJM, but would receive extra money under the state program to make up the difference between the PJM market price and the contract price.

But incumbent generators challenged the new Maryland program; a federal district court issued a declaratory judgment holding that Maryland's program improperly sets the rate the developer receives for interstate wholesale capacity sales to PJM.  On appeal, the Fourth Circuit affirmed, finding that Maryland's program was preempted because it impermissibly conflicts with FERC policies.  The case then came to the Supreme Court of the United States.

The Supreme Court's April 19, 2016 decision affirms the lower courts' rulings.  The Court agreed with the Fourth Circuit's judgment "that Maryland's program sets an interstate wholesale rate, contravening the FPA's division of authority between state and federal regulators."  In the majority opinion's words, "States may not seek to achieve ends, however legitimate, through regulatory means that intrude on FERC's authority over interstate wholesale rates, as Maryland has done here."

The Hughes ruling sheds light on how the Court might view other state programs to incentivize new or clean generation.  That said, the Court emphasized that its holding in Hughes is limited -- that it rejected Maryland's program "only because it disregards an interstate wholesale rate required by FERC."  The Court explicitly said it would not address "the permissibility of various other measures States might employ to encourage development of new or clean generation," such as tax incentives, land grants, direct subsidies, construction of state-owned generation facilities, or re-regulation of the energy sector.

The majority opinion concludes with a reminder that "[s]o long as a State does not condition payment of funds on capacity clearing the auction, the State's program would not suffer from the fatal defect that renders Maryland's program unacceptable."  This suggests one potential path for permissible state incentives for electric power generation.

US Quadrennial Energy Review second round

Friday, April 15, 2016

The U.S. Department of Energy is holding a series of public meetings centered on the topic of the second installment of its Quadrennial Energy Review, an integrated study of the U.S. electricity system from generation through end use.

On January 9, 2014, President Obama issued a Presidential Memorandum establishing a task force and directing the administration to conduct a Quadrennial Energy Review (QER).  The task force was directed to “gather ideas and advice from state and local governments, tribes, large and small businesses, universities, national laboratories, nongovernmental and labor organizations, consumers, and other stakeholders and interested parties...”  This input is designed to inform a report to the President that includes the following:

  • Provides an integrated view of, and recommendations for, Federal energy policy in the context of economic, environmental, occupational, security, and health and safety priorities, with attention in the first report given to the challenges facing the Nation’s energy infrastructures.
  • Reviews the adequacy of existing executive and legislative actions and recommends additional executive and legislative actions, as appropriate.
  • Assesses and recommends priorities for research, development, and demonstration programs to support key energy innovation goals.
  • Identifies analytical tools and data needed to support further policy development and implementation.
The QER Task Force released the first installment of the Quadrennial Energy Review in 2015, “Energy Transmission, Storage, and Distribution Infrastructure”.  This volume reviewed U.S. infrastructure for transmission, storage, and distribution, including liquid and natural gas pipelines, the grid, and shared transport such as rail, waterways, and ports, and noted "the critical enabling role of electricity."

Based on this role, the Administration determined that the second installment of the QER will focus on the electricity system, including "not just physical structures, but also a range of actors and institutions." A stakeholder briefing memorandum for the QER's second round describes consideration of fuel choices, distributed and centralized generation, physical and cyber vulnerabilities, federal, state, and local policy direction, expectations of residential and commercial consumers, and a review of existing and evolving business models for a range of entities throughout the system.  The second installment is expected to result in a set of findings and policy recommendations to help guide the modernization of the nation’s electric grid and ensure its continued reliability, safety, security, affordability, and environmental performance through 2040.

As part of this process, the Department of Energy is holding a series of stakeholder engagement meetings.  Meetings will include a mix of panel discussions and public comment opportunities.

The first meeting of QER's second installment was held in Washington, D.C., on February 4.  Future meetings include:

Boston, Massachusetts -- April 15, 2016
Salt Lake City, Utah -- April 25, 2016
Des Moines, Iowa -- May 6, 2016
Austin, Texas -- May 9, 2016
Los Angeles, California -- May 10, 2016
Atlanta, Georgia -- May 24, 2016

NH regulation of solar PPAs, leases

Thursday, April 14, 2016

As distributed energy resources like solar panels become more widely adopted, how do typical solar business models like solar power purchase agreements or solar leases match up to state utility laws?  While the answer may vary from state to state, an order issued by the New Hampshire Public Utilities Commission earlier this year found found that offering solar power purchase agreements or solar leases to customers in New Hampshire would not subject a solar company to Commission regulation under any of several theories.  The order finding no regulation required is consistent with other state policy and precedent supporting distributed generation, and could be a model for other states.

Federal law controls some many aspects of the U.S. electricity industry, but states can and do regulate public utilities and competitive electric power suppliers.  Knowing who these state-regulated utilities and suppliers were was straightforward under the dominant utility models of the twentieth century.  But as new technologies like solar photovoltaic panels or other distributed energy resources become more widely adopted, and new business models like solar power purchase agreements and solar leases arise, their regulatory status can be uncertain.  If a solar company installs solar panels on a customer's roofs, and sells that customers the power produced, will it be regulated like a public utility or supplier under state law?  What if the company leases the panels to the customer?

The New Hampshire Public Utilities Commission recently addressed these questions in answering a 2015 petition by Vivint Solar, Inc.  In that petition, Vivint asked the New Hampshire Public Utilities Commission for a declaratory ruling that it would not regulate Vivint as a public utility, competitive electric power supplier, or limited producer of electrical energy under state law, for offering solar power purchase agreements or solar leases to residential customers in New Hampshire.

In a January 15, 2016 order -- Order No. 25,859 -- the Commission granted Vivint's petition.  First, the Commission noted the value of regulatory certainty:
We believe it is important for a party planning to do business in the state to have a vehicle through which it may clarify its regulatory status prior to entering the marketplace, provided that it can describe in sufficient detail its business plans and practices and these plans and practices are not hypothetical or speculative.
Next, the Commission concluded that the operations described by Vivint would not constitute sales to or for the "public" within the meaning of the statutory definition of "public utility."  Key factors recited in the order included the "conditional nature and relative complexity of Vivint’s relationships with its customers."

The Commission then analyzed its rules regarding competitive electric power suppliers, concluding that although Vivint might meet the regulatory definition of a supplier, that definition "should not be read in isolation but in the context of the overall purpose and effect" of the rules in their entirety.  The Commission then noted that those "Puc 2000" rules "seem intended to regulate  a set of relationships and related transactions that is quite different from those undertaken in the context of customer-sited, behind-the-meter, distributed generation development involving sales of electricity directly to the host customers pursuant to the terms and conditions of PPAs."

Finally, the Commission concluded that neither Vivint's PPAs nor solar leases should be subject to Commission regulation under the New Hampshire Limited Electrical Energy Producers Act.  The Commission interpreted that act's retail sales provisions "as applicable to sales of electricity off-site from the generation facilities," not "on-site and behind-the-meter" sales of power as contemplated by Vivint.

The New Hampshire Public Utilities Commission noted that while the petition and briefs in the case focused on the residential solar energy market, its analysis and conclusions "would not be different if the relevant customers were non - residential, assuming that the Systems were installed on the customers’ premises behind the utility retail electric meter, we re sized no larger than necessary to meet the customers’ reasonably anticipated electric consumption, and involved sales of electricity directly to the host customer or leases of the installed Systems to the host customer."

While the ruling technically applies to the company and facts asserted in the petition, it confirms the possibility of an important role for third-party involvement in distributed generation.

Massachusetts solar legislation signed

Wednesday, April 13, 2016

Massachusetts Governor Charlie Baker has signed a bill passed by the state legislature to expand the Massachusetts solar industry and establish a long-term framework for sustainable solar development.

The bill, An Act Relative to Solar Energy, preserves and expands net metering.  Net metering -- a customer's right to offset its solar power production against its consumption of electricity from the grid -- has been an important incentive for solar projects in Massachusetts, leading to the development of over 1,000 megawatts of solar capacity currently installed in Massachusetts.  Previous law set caps on how much solar capacity each utility was required to let its customers net meter against their load.  But at least one utility has reached its cap, cutting off future projects' access to net metering in that territory, and the other utilities are close behind.

In response to interest in preserving net metering, the bill signed into law on April 11 increases the state's solar net metering caps, which limit how much net metered capacity may be installed in each utility's service territory.  It raises the cap on publicly owned projects from 5% of utilities’ peak load to 8%, and lifts the cap on private net metered projects from 4% of utilities’ peak load to 7%.   

At the same time, the bill changes the value of net metering credits for some new projects.  When a net metered customer's solar system produces more electricity than the customer uses, the customer receives credit for its excess production.  Historically, that credit was at the full retail rate -- meaning the customer is credited the same amount for a kilowatt-hour exported to the grid as the customer pays the utility to buy that kilowatt-hour from the grid.  The fact that net metered generation is credited at the full retail rate, as opposed to any lesser amount, has helped net metering drive solar project development.

But some utilities have expressed concerns that net metering imposes costs on other customers who don't have net metered distributed generation.  In an effort to balance cost containment against effective incentives for solar development, the Massachusetts legislation sets the new credit value for most solar projects (other than residential, small commercial, municipal and government-owned) at 60% of the full retail rate once the state hits its goal of 1,600 megawatts of solar capacity.

But to "facilitate continued solar growth within communities around the Commonwealth," the bill preserves retail rate credits for municipal and government-owned projects.  It also continues to exempt residential and small commercial projects from the net metering cap and any net metering credit reductions.

Looking forward, the bill also requires the Department of Energy Resources (DOER) to "develop a statewide solar incentive program to encourage the continued development of solar renewable energy generating sources by residential, commercial, governmental and industrial electricity customers."  The bill gives the Department guidance on the characteristics of that program, including that it must be one which: "promotes the orderly transition to a stable and self-sustaining solar market at a reasonable cost to ratepayers," considers underlying system costs, takes into account electricity revenues and incentives, relies on market-based mechanisms or price signals, minimizes costs and barriers, features a declining incentive framework, differentiates incentive levels, "ensures that the utility customer realizes the direct benefits of the solar incentive program," considers the value of distributed generation and encourages solar generation where it benefits the distribution system, shares program costs collectively among all ratepayers, and promotes investor confidence through long-term incentive revenue certainty and market stability.

With the bill signed into law, the Department of Energy Resources is expected to open a rulemaking proceeding and solicit public comment on the development of the new solar incentive program.

Electric storage and wholesale markets

Tuesday, April 12, 2016

As electric energy storage technology improves in capability and cost-effectiveness, what barriers exist to electric storage resources' participation in organized electricity markets in the U.S.?  Staff of the Federal Energy Regulatory Commission have issued a series of data requests and a request for public comment in an effort to identify barriers that could lead to unjust and unreasonable wholesale electricity rates.

For purposes of this inquiry, Commission staff defines an electric storage resource as a facility that can receive electric energy from the grid and store it for later injection of electricity back to the grid. This includes all types of electric storage technologies, regardless of their size and storage medium, or whether they are interconnected to the transmission system, distribution system, or behind a customer meter.

Historically, electricity had to be consumed as soon as it was generated, and storing electricity was challenging and expensive.  But a new industry has grown up around electric storage.  Federal regulators have acted to support energy storage, such as in FERC Order No. 784 which lets cost-effective storage be paid fairly for the ancillary services it provides to the grid.

According to a series of April 11, 2016 letters from Commission staff to various regulated Regional Transmission Organization (RTO) and Independent System Operator (ISO) entities, "Commission staff has been examining the use of electric storage resources to help meet wholesale electricity needs for some time."  In light of "key developments in the technology and cost-effectiveness of electric storage resources," the letters express staff's interest in "examining whether barriers exist to the participation of electric storage resources in the capacity, energy, and ancillary service markets in the RTOs and ISOs potentially leading to unjust and unreasonable wholesale rates."  The letters also describe staff's expectation that if potential barriers exist, staff will examine whether any tariff changes are warranted.

A data request is attached to each letter.  In those data requests, staff seeks information on rules that affect the participation of electric storage resources in the markets.  These rules include those governing electric storage resources' eligibility to participate in the markets, the qualification and performance requirements for market participants, required bid parameters, and the treatment of electric storage resources when they are receiving electricity for later injection to the grid.

FERC staff's data requests are organized into 6 categories:
  • The Eligibility of Electric Storage Resources to be Market Participants
  • Qualification Criteria and Performance Requirements
  • Bid Parameters for Electric Storage Resources
  • Distribution-Connected and Aggregated Electric Storage Resources
  • When Electric Storage Resources are Receiving Electricity
  • Potential Changes to the Rules Affecting Electric Storage Resources
The letter requests a response to the data requests on or before May 2, 2016.  Concurrently, staff solicited public comment on the issues raised in the proceeding.

As noted in the data request letters, this is not the first time Commission staff has considered energy storage.  Will this round of regulatory process identify barriers to electric storage resources' participation in wholesale markets?  Will any barriers identified give rise to changes to grid operators' tariffs?  The case has been docketed as Docket No. AD16-20-000, Electric Storage Participation in Regions with Organized Wholesale Electric Markets

Federal dams and preliminary permits

Monday, April 11, 2016

U.S. federal entities own dams with untapped hydropower potential that could be developed by private parties -- but a recent regulatory decision highlights the difficulty of winning key approvals when the federal dam owner opposes the project.  The Federal Energy Regulatory Commission's April 5, 2016 denial of an application for a preliminary permit for the McNary Lock and Dam Project illustrates this dynamic.

The U.S. Army Corps of Engineers owns and operates a 980-megawatt hydroelectric project at the McNary Lock and Dam on the Columbia River in Oregon and Washington. The project was authorized by the River and Harbor Act of 1945, and all its power units have been in operation since 1957.

But perhaps there may be untapped hydropower potential at the site that could be developed.  In 2015, a company called Advanced Hydropower, Inc. applied to the Federal Energy Regulatory Commission for a preliminary permit, pursuant to section 4(f) of the Federal Power Act, to study the feasibility of the proposed McNary Dam Advanced Hydropower Project No. 14697.  That project would utilize the existing McNary Dam, plus new facilities including a 34-megawatt turbine.

But by an order dated April 5, 2016, the Commission denied Advanced Hydropower's application.  In doing so, the Commission cited judicial precedent that it "is not required to grant a preliminary permit application, so long as it articulates a rational basis for not doing so."  It then cited recent Commission decision denying preliminary permits for projects at federal facilities after receiving comments from the relevant federal entities indicating that no purpose would be served in issuing a permit because the federal entity would not approve modifications to its federal facilities.

Notably, in the McNary Lock and Dam case, the Corps filed timely motions to intervene and comments opposing the project.  In its order denying Advanced Hydropower's application, the Commission noted:
Here, because the Corps, which owns the McNary Lock and Dam facility and whose permission would be needed for the development of any project at that facility, has stated that it opposes the project, we find there is no purpose in issuing a preliminary permit here.
Based on the Corps' opposition to the project, the Commission thus denied Advanced Hydropower's application for a preliminary permit for the McNary Lock and Dam project.

Maine PUC considers NTA coordinator

Friday, April 8, 2016

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.

Maine Green Power offer provider selected

Thursday, April 7, 2016

Maine energy regulators have chosen a manager for the Maine Green Power program.  In an April 4, 2016 order, the Maine Public Utilities Commission selected 3Degrees Group, Inc. to manage the program.  3Degrees has operated the program since its 2013 launch, and now has the Commission's approval to run the program for another five-year term, with some changes to pricing, renewable energy certificate procurement, and risk mitigation procedures.

Maine's green power offer was established by a 2009 Maine law requiring the Commission to arrange for a green power offer -- a fully renewable competitive electricity supply option -- and to ensure its availability to residential and small commercial electricity customers.  Following a 2010 RFP, the Commission selected 3Degrees, Inc. to provide the first round green power offer.  Its program, named Maine Green Power, was officially launched in April 2013.  It featured blocks of 500 kilowatt-hours per month of renewable energy.  Its existing term of service expired on March 31, 2016.

Legislation enacted in 2015 extended the green power program's sunset date to April 1, 2021. On November 12, 2015, the Commission solicited proposals from providers to manage the program for a five-year term beginning on April 1, 2016.  According to the April 4, 2016 order selecting 3Degrees, the Commission evaluated proposals "based on cost considerations, non-cost aspects such as supplier experience, customer sign-up ease, and the potential use of renewable energy credits (RECs) from community-based renewable energy projects."

The Commission found "that the proposal submitted by 3Degrees, Inc. best suits the needs of the green power program."  According to the order, that proposal maintained the 500 kWh block structure, with a 19% increase in pricing.  3Degrees also proposed separate commercial pricing that includes a reduction in the per kWh price for higher usage.

The Commission also approved changes to the program's REC procurement and risk mitigation processes "in light of the five-year contract and the potential volatility in REC prices in future years":
Because of significant concerns about the price of Maine RECs in the next five years, particularly Maine Class I RECs, 3Degrees has proposed that it shall be required to use no less than $5.50 per REC of revenues paid by program participants for REC procurement purposes, as calculated as an average over the most recent three year period. At the proposed pricing for a residential customer of $8.95 for a 500 kWh block of green power, a customer would pay $17.90 for one REC. The 3Degrees proposal would require that no less than $5.50, or approximately 30%, of the funds paid by customers be spent directly on procuring RECs for the program.
The order also approved a risk mitigation mechanism.  If the procurement cost of Maine-based RECs exceeds $6.50 per REC on average (including Class I and Class II), 3Degrees could procure RECs from resources elsewhere in New England, or even from outside New England with Commission approval.  But because the program is promoted as Maine-based, the Commission directed 3Degrees to develop appropriate consumer education materials to explain the potential that, under certain circumstances, RECs may be sourced from outside of Maine or even the New England market.

Generator interconnection technical conference scheduled

Wednesday, April 6, 2016

The Federal Energy Regulatory Commission has scheduled a technical conference to generator interconnection issues, including interconnection of energy storage.

The case has its origins in a 2015 petition to the Commission by the American Wind Energy Association, seeking a rulemaking to revise certain provisions of the Commission's pro forma Large Generator Interconnection Procedures (“GIP”) and pro forma Large Generator Interconnection Agreement (“GIA”).

AWEA is a national trade association representing a broad range of entities with a common interest in encouraging the expansion and facilitation of wind energy resources in the United States. Its members include wind energy facility developers, owners and operators, construction contractors, turbine manufacturers, component suppliers, financiers, researchers, utilities, marketers, customers, and their advocates.

In that petition, the trade group argued:
the time is ripe for the Commission to make certain regulatory and policy changes to interconnection procedures in order to remedy unduly discriminatory and unreasonable barriers to generator market access that inhibit the development of electric generation to meet the growing needs of electricity customers, and to facilitate the current dramatic transformation of the electric generation system (driven, in part, by Federal and State policies) in a timely, reliable and cost-effective manner.
AWEA's petition called for a variety of reforms to the interconnection procedures and agreement, particularly aimed at improving "(a) certainty in the study/restudy process; (b) transparency in the interconnection process; (c) certainty of network upgrade costs; and (d) accountability in the interconnection process."  After many comments were submitted on the rulemaking petition, AWEA asked the Commission to hold a technical conference as a forum for "open discussion" among interested parties.

The Commission has now issued notice of a technical conference to be held on May 13.  According to the notice:
The purpose of this conference is to discuss select issues related to a petition for rulemaking submitted by the American Wind Energy Association (Docket No. RM15-21-000). In addition, the conference will explore other generator interconnection issues, including interconnection of energy storage.
The notice also states that discussions at the conference may involve issues raised in other proceedings pending before the Commission, including without limitation 8 sets of specifically listed cases:
  • E.ON Climate & Renewables North America LLC, Pioneer Trail Wind Farm, LLC, Settlers Trail Wind Farm, LLC v. Northern Indiana Public Service Company, Docket No. EL14-66-002;
  • Entergy Arkansas, Inc., Docket No. ER14-671-000;
  • Internal MISO Generators v. Midcontinent Independent System Operator, Inc., Docket No. EL15-99-000;
  • Midcontinent Independent System Operator, Inc., Docket No. ER16-675-000;
  • California Independent System Operator Corporation, Docket No. ER16-693-000;
  • ISO New England, Inc., Docket No. ER16-946-000;
  • Midcontinent Independent System Operator, Inc., Docket No. ER16-1120-000; and
  • Midcontinent Independent System Operator, Inc., Docket No. ER16-1211-000. 
The conference will be held on May 13 at Commission headquarters in Washington, DC.

U.S., China to sign Paris climate agreement

Tuesday, April 5, 2016

The U.S. and China have announced plans to sign the international climate change agreement reached in Paris last December.

The White House.

The Paris Agreement, adopted at the "COP21" U.N. Conference on Climate Change, establishes a framework for reducing global greenhouse gas emissions.  It takes effect once 55 countries accounting for at least 55% of global emissions formally commit to undertaking the low carbon measures it outlines.

According to a March 31 joint presidential statement on climate change, over the past 3 years, "climate change has become a pillar of the U.S.-China bilateral relationship."  The statement notes domestic efforts by the U.S. and China to "build green, low-carbon and climate-resilient economies", as well as the international action culminating in the December 2015 conference decision to adopt the Paris Agreement.

The joint statement declares that U.S. and China "will sign the Paris Agreement on April 22nd and take their respective domestic steps in order to join the Agreement as early as possible this year." April 22 represents the first day that the Paris Agreement will be formally open for signature by adopting nations.

A White House blog post describes this step as a "critical milestone" because it represents a commitment by "the world's two largest polluters" who account for 40% of global emissions.  According to that blog, this commitment places the 55% threshold for implementation "well within reach," "demonstrating to the international community that there is no turning back on the path towards a low carbon future." 

Utah conduit hydropower project qualifies

Monday, April 4, 2016

Federal energy regulators have issued a letter determining that a proposed Utah hydropower project meets criteria for development without needing a hydropower license.  Castle Valley Special Service District's proposed Ferron Water Treatment Plant Project would generate electricity using the pressure of water in an existing conduit entering a drinking water treatment plant.  As a result of a determination by the Federal Energy Regulatory Commission, the project can be developed without a FERC hydropower license.

On January 27, 2016, the Castle Valley Special Service District filed with the Federal Energy Regulatory Commission a notice of intent to construct a 6-kilowatt in-conduit hydroelectric net metered system.  The District is a tax exempt municipal government entity that, among other services, provides drinking water to the residents of Ferron City and Clawson Town.

That notice of intent described plans to harness or recover water pressure lost at the inlet to the District's proposed new Ferron Water Treatment Plant.  Water from the Millsite Reservoir would be transmitted to the treatment plant in a conduit owned by Ferron City and the District.  Excess pressure in the incoming untreated water would flow through a pressure reducing valve and turbine hydropower generator.

Under section 30 of the Federal Power Act (FPA), as amended by section 4 of the Hydropower Regulatory Efficiency Act of 2013 (HREA), a qualifying conduit hydropower facility -- one that is determined or deemed to meet defined criteria -- is not required to be licensed or exempted from licensing under the Federal Power Act.  These criteria include:
  • The conduit the facility uses a tunnel, canal, pipeline, aqueduct, flume, ditch, or similar manmade water conveyance that is operated for the distribution of water for agricultural, municipal, or industrial consumption and not primarily for the generation of electricity.
  • The facility is constructed, operated, or maintained for the generation of electric power and uses for such generation only the hydroelectric potential of a non-federally owned conduit.
  • The facility has an installed capacity that does not exceed 5 megawatts. 
  • On or before August 9, 2013, the facility is not licensed, or exempted from the licensing requirements of Part I of the FPA.

On February 2, 2016, the Federal Energy Regulatory Commission issued its notice of a preliminary determination that "the proposal satisfies the requirements for a qualifying conduit hydropower facility, which is not required to be licensed or exempted from licensing."

Following the expiration of comment and intervention deadlines, on March 28 the Commission issued its "written determination that the Ferron Water Treatment Plant Project meets the qualifying criteria under FPA section 30(a), and is not required to be licensed under Part I of the FPA."

As the FERC determination on the Ferron project notes, "Qualifying conduit hydropower facilities remain subject to other applicable federal, state, and local laws and regulations."  But the ability to develop an in-conduit hydropower project without needing a FERC license can give a significant boost to projects with suitable conduit water resources.

Maine renewable energy report released

Saturday, April 2, 2016

The Maine Public Utilities Commission has issued its latest annual report on Maine's use of renewable electricity, covering the 2014 calendar year.  The report shows the impact of Maine's renewable portfolio standard, a state law requiring electricity suppliers to source specified percentages of their electricity from renewable resources.  The report found that compliance costs have fallen nearly in half since 2013.

The Maine State House.

Since Maine's electric industry restructuring in 2000, state law has required competitive electricity providers -- retail suppliers -- to procure 30% of their load served from "eligible resources." These are generally defined in statute as renewable or cogeneration facilities.  A 2007 act of the Maine legislature added a mandate that specified percentages of electricity that supply Maine’s consumers be sourced from “new” renewable resources.  Generally, these are renewable facilities that have an in-service date, resumed operation or were refurbished after September 1, 2005.  This "Class I" renewable portfolio standard began at one percent of load in 2008, and increases in one percentage point each year until reaching ten percent in 2017.  The older "eligible resource" standard became known as "Class II."

The 2007 renewables law required the Public Utilities Commission to report annually to the legislature on the program and compliance.  Each year's report is based largely on the most recently filed Competitive Electricity Provider (CEP) annual compliance reports, which are filed each July, covering the prior calendar year.  So there is some lag between the events being tracked and the publication of the report.

The Commission has just released its report covering calendar year 2014. The report notes "approximately 75 certified facilities, with a total capacity of approximately 1220 MW," although some are not operating or are eligible for other states' renewable portfolio requirements.

In 2014, most suppliers complied with the Maine renewable portfolio requirement through the use of renewable energy certificates or RECs.  According to the report, RECs from 22 facilities were used by suppliers to comply with the 2014 new renewable resource requirement.  Of these, 18 are biomass, 3 are hydro, and 1 is a wind facility. 20 of the 22 facilities are located in Maine, one is located in Connecticut and one is located in Massachusetts. Maine facilities, mostly refurbished biomass plants, supplied 99% of the approximately 811,476 RECs purchased to meet the 2014 portfolio requirement.

For calendar year 2014, 78.05% of the Class I RPS requirement was satisfied through the purchase of RECs during that year, 0.0004 % was satisfied through an alternative compliance mechanism, 21.88% was satisfied using RECs banked from 2013 and 0.1130 % will be satisfied during a 2015 cure period allowed by rule. On top of this activity, 181,595 RECs were purchased in 2014 and banked for future use and an additional 8 RECs were purchased where the supplier did not indicate whether the certificates were to be banked or would not be used.

As the Commission notes in its report, "the prices for Maine Class I RECs declined substantially over the two years leading up to 2014. This has occurred because Maine’s portfolio requirement includes, as an eligible resource, refurbished biomass facilities (which are not generally eligible in other New England states)."

One result is that the annual cost of Class I compliance fell roughly in half since the last report, with a total cost of $14,296,249 in 2014 compared to just $6,947,269 in 2013.  The report describes the cost of Class I RECs used for compliance in 2014 as ranging from approximately $1.72 per MWh to $22.33 per MWh, with an average cost of $8.56 per MWh.  Adding $198 for one supplier who satisfied a portion of the portfolio requirement through alternative compliance mechanism at the rate of $66.16 per MWh, the report describes a total Class I compliance cost to ratepayers during 2014 of $6,947,269.  The Commission translated this into "an average rate impact of about 0.06 cents per kWh (or about 30 to 35 cents monthly for a typical residential bill). In percentage terms, this translates to a residential customer bill impact of about one half of 1%."

The report also describes the cost of Class II RECs used to satisfy the eligible resource portfolio requirement as ranging from $0.00 per MWh (some RECs were provided for free as part of an energy transaction) to $1.80 per MWh, with an average cost of $0.52 per MWh and a total cost of $1,834,314. According to the Commission, this translates into less than ten cents per month on a typical residential bill.

California floating offshore wind project proposed

Friday, April 1, 2016

The U.S. Bureau of Ocean Energy Management is moving toward the prospect of leasing sites for commercial wind energy development in federal waters offshore California.  According to a March 21 release by BOEM, a January 2016 request by Trident Winds, LLC for a lease will now trigger further steps in BOEM's leasing process.

Trident Winds filed its unsolicited lease request on January 14, 2016.  That request proposed a project to be located about 33 nautical miles northwest of Morro Bay.  The lease area proposed covers almost 68,000 acres in water depths of 2,600‐3,300 feet.  The project would generate up to 800 megawatts of power using about 100 floating foundations, each supporting a turbine that could produce up to 8 MW.  The project could be expanded to generate 1,000 megawatts at a later date, if additional transmission capacity and market off-take can be obtained.

On March 21, 2016, BOEM confirmed that Trident Winds is legally, technically, and financially qualified to hold an offshore wind energy lease in federal waters.

Under the agency's leasing process, its next step will be to publish a notice in the Federal Register to determine if there is competitive interest in the area requested. That Notice will also solicit comments and information on site conditions, commercial, military or other uses of the area and potential impacts of the proposed Trident Winds project.  BOEM expects to issue that Notice this summer.

Based on the information and expressions of interest received during the comment period on the Notice, BOEM will determine whether there is competitive interest in the area. If BOEM determines there is competitive interest, it will initiate its competitive leasing process. If no expressions of interest are received, BOEM will proceed with its noncompetitive leasing process.

So far, BOEM has awarded eleven commercial wind energy leases in federal waters off the Atlantic coast, nine of which were issued as a result of competitive lease sales.

FERC approves Berkshire Power settlement

Thursday, March 31, 2016

Federal energy regulators have approved a stipulation and consent agreement under which two companies admit violations of the Federal Power Act and regulations prohibiting energy market manipulation.

The case involves Berkshire Power Company LLC (Berkshire), and Power Plant Management Services LLC. Berkshire owns an approximately 245 MW natural gas-fired, combined-cycle generating facility in Agawam, Massachusetts. Berkshire hired PPMS to provide project management and administrative services at the plant.

According to Federal Energy Regulatory Commission documents, at the direction of a general manager hired by PPMS, "Berkshire Power engaged in a fraudulent scheme to perform unreported maintenance work and to conceal that work and associated maintenance outages from ISO-NE."  The documents allege that individuals at the plant scheduled maintenance work for times when the plant was unlikely to be dispatched, and then failed to notify ISO-NE about the work or the associated Plant unavailability.  In at least six instances, this led to representations to ISO New England dispatchers that the plant was starting up or was able to start up when it was, in fact, unavailable due to ongoing maintenance or other technical problems.

The Commission's Office of Enforcement initiated its investigation in June 2014, following a referral from the United States Attorney’s Office for the District of Massachusetts.  Following fact-finding, Enforcement concluded that Berkshire and PPMS violated section 222 of the Federal Power Act and the Commission’s Anti-Manipulation Rule by concealing its maintenance work and associated outages from ISO-NE. That rule prohibits any entity from using a fraudulent device, scheme, or artifice, or engaging in any act, practice, or course of business that operates or would operate as a fraud; with the requisite scienter; in connection with a transaction subject to the jurisdiction of the Commission.

Enforcement also concluded that Berkshire violated Commission regulations by violating provisions of the ISO-NE tariff requiring it to schedule and disclose plant maintenance and to accurately report on plant availability, and by making false and misleading representations to ISO-NE. Finally, Enforcement concluded that Berkshire violated Commission-approved reliability standards by withholding information regarding its planned maintenance outages and plant capabilities and availability.

According to the order, the Office of Enforcement, Berkshire, and PPMS have resolved the matter by a stipulation and consent agreement.  Under that deal, Berkshire and PPMS stipulate to the facts, admit the violations set out in the Agreement, and agree to pay a civil penalty of $2,000,000 to the United States Treasury. Berkshire agrees to pay to ISO-NE disgorgement of $1,012,563, plus interest. Berkshire further agrees to pay a civil penalty of $30,000 to the United States Treasury for its violations of the Reliability Standards.

In its March 30, 2016 order accepting that settlement, the Commission noted Enforcement's consideration of the factors in the Revised Policy Statement on Penalty Guidelines.  Factors cited here as supporting "the appropriate remedy" include "that both companies cooperated fully and comprehensively throughout the investigation, both accepted responsibility for their violations, and neither has a prior history of violations."  The order notes that the remedy also reflects that neither company had an effective compliance program in place during the relevant period, and that a high-level employee at the plant directed the scheme.

The order directs Berkshire and PPMS to make the disgorgement and civil penalty payments as required by the Agreement within ten business days of its Effective Date. ISO-NE was directed to allocate the disgorgement funds pro rata to network load during the applicable period. The order also directs Berkshire and PPMS to comply with the provisions in the Agreement also requiring them to implement procedures to improve compliance going forward, subject to monitoring via submission of semi-annual reports for at least one year.

West Branch storage project relicensed

Wednesday, March 30, 2016

Earlier this month U.S. hydropower regulators issued a new license for the West Branch Project, which includes water storage facilities on the West Branch of the St. Croix River in Maine.

The Federal Energy Regulatory Commission first issued an original license for the West Branch Project on September 4, 1980.  The project includes two developments, Sysladobsis and West Grand, that operate as water storage facilities to provide flood storage and flow releases for downstream hydroelectric generation.  The Sysladobsis Development uses Sysladobsis Lake as its impoundment.  The license describes the West Grand Development as composed of several natural lakes including Scraggly Lake, Keg Lake, Bottle Lake, Junior Lake, Junior Bay, Norway Lake, Pug Lake, Pocumcus Lake, Horseshoe Lake, and West Grand Lake. 

Dikes and dams are used to control and release water, first from Sysladobsis Lake into the downstream West Grand impoundment, then into either Grand Lake Stream or Grand Lake Brook.  Many of the dams and dikes at these sites are old -- the Sysladobsis dam, West Grand dam, and Farm Cove dike were constructed in 1861, 1836, and 1879, respectively, although all three have since been rebuilt.

Each of these developments operates in a seasonal store-and-release mode whereby water is stored to reduce downstream flooding during periods of high flow and released during periods of low flow to augment generation at the downstream hydroelectric projects.

The West Branch Project also operates as part of the larger St. Croix River headwater storage system.  This network of dams includes Woodland Pulp LLC’s Forest City Project No. 2660 and the recently relicensed Vanceboro Project No. 2492. Generation associated with these projects occurs at the Grand Falls and Woodland hydroelectric projects downstream on the St. Croix River.

The West Branch Project's original 1980 license was amended in 1987 to include the existing Farm Cove dike, but the original license expired on September 30, 2000.  Since then, the licensee has operated the project under an annual license pending the disposition of a new license application.

On March 19, 2009, the licensee filed, pursuant to sections 4(e) and 15 of the Federal Power Act (FPA), an application for a new license to continue operating and maintaining the West Branch Project. The licensee proposed to continue store-and-release operation with some changes, continue operating fishways and take other measures to promote fish populations, enhance a land use plan, and develop a historic properties management plan.

Fishery issues have been contentious in the St. Croix River system.  After opportunity for public comment, agency consultation, and preparation of an Environmental Assessment, the Maine Department of Inland Fisheries and Wildlife asked the Commission to delay its licensing decision until fishery management talks concluded.  After being notified by the Department that those talks had concluded, on March 15, 2016 the Commission issued Woodland Pulp a new license to continue operating and maintaining the West Branch Project. 

The new license requires a number of measures to protect and enhance water quality, aquatic habitat, fisheries resources, terrestrial resources, and recreation opportunities at the project. These include a requirement to operate the developments in store-and-release mode between defined pond elevations, to provide certain minimum flows of water, to develop an Operation Compliance Monitoring Plan, and to provide and enhance fish passage.

A list maintained by the Federal Energy Regulatory Commission shows over 1,000 active hydropower licenses.  Many of these licenses will expire in the near future, so relicensing activity for FERC-licensed hydroelectric projects is expected to increase. 

Colorado conduit hydropower project

Tuesday, March 29, 2016

A proposed hydroelectric project in Colorado has received a federal determination that it qualifies as a "qualifying conduit hydroelectric facility" and thus is not required to be licensed under Part I of the Federal Power Act.  The Park Farm Hydro Project illustrates the rapid pace with which the Federal Energy Regulatory Commission can act on conduit hydropower projects under a 2013 amendment to its law.

The Federal Power Act requires most hydropower projects to be licensed by the Federal Energy Regulatory Commission.  But Section 4 of the Hydropower Regulatory Efficiency Act of 2013 amended the Federal Power Act to facilitate "conduit hydropower" projects -- those generating electricity using only the hydroelectric potential of a non-federally owned conduit, such as a tunnel, canal, pipeline, aqueduct, flume, ditch, or similar manmade water conveyance that is operated for the distribution of water for agricultural, municipal, or industrial consumption, and is not primarily for the generation of electricity.  Reforms in 2013 exempted qualifying conduit hydropower facilities from needing a license, and established a fast process for to solicit public comment and confirm whether the new exemption applies.  In the ensuing years, a number of projects have qualified for this treatment.

On January 27, 2016, an applicant filed a notice of intent, pursuant to section 30(a) of the Federal Power Act, as amended by Section 4 of the Hydropower Regulatory Efficiency Act of 2013, to construct a qualifying conduit hydropower facility, the Park Farm Hydro Project, to be located near the Town of Kersey, in Weld County, Colorado.  The notice described a proposal to add ten 1-kilowatt Crossflow turbines alongside an existing "ditch drop" or conduit in the Lower Latham Ditch.

On February 2, 2016, the Commission issued its notice of preliminary determination that the proposal satisfies the requirements for a qualifying conduit hydropower facility, which is not required to be licensed or exempted from licensing.  The notice set a 30-day deadline for filing motions to intervene, and a 45-day deadline for filing comments contesting whether the facility meets the qualifying criteria.  No such comments or motions were received.

On March 22, 2016 -- less than 2 months after the applicant first filed its notice of intent -- the Commission issued a letter constituting its written determination that the Park Farm Hydro Project meets the qualifying criteria under Federal Power Act section 30(a), and is not required to be licensed under Part I of the FPA, although other federal, state, and local laws do apply.

This quick timing on the Park Farm project is consistent with other recent FERC action on proposed conduit hydropower projects.

Alaska tidal permit surrendered

Monday, March 28, 2016

Five years after applying for and receiving a preliminary permit to study a proposed Alaska tidal energy project, the project developer has surrendered that permit.

At issue is ORPC Alaska 2, LLC's proposed East Foreland Tidal Energy Project.  The developer first applied to the Federal Energy Regulatory Commission for a preliminary permit under Section 4(f) of the Federal Power Act on August 2, 2010. 

That application described a project site in middle Cook Inlet, a marine waterway of the northern Pacific Ocean. The proposed hydrokinetic project would lie offshore of the East Foreland, near the west coast of the Kenai Peninsula by Nikiski, Alaska.  The application described the site in middle Cook Inlet as offering a maximum tidal range of up to 9.20 meters, with geomorphology favorable to strong currents.  The application described the developer's intent to install a pilot or commercial project in a phased approach.

The FERC issued a first preliminary permit for the East Foreland project by order dated March 11, 2011.  As permitted, the East Foreland project would include a series of 150-kilowatt TideGen and/or 150-kW OCGen turbine-generator modules developed by ORPC, with a combined capacity between 5 megawatts (MW) and 100 MW, with an average annual generation between 13 and 340 gigawatt-hours.

Over the ensuing years, the permittee studied the site and the project and filed periodic reports to the Commission. The preliminary permit required the permittee to file a notice of intent and draft pilot license application within two years of the permit date, but ORPC requested and received a six-month extension

On March 3, 2013, the permittee filed a request for a successive preliminary permit for the East Foreland Tidal Energy Project.  The Commission granted a successive preliminary permit on June 16, 2014, describing a project with a combined capacity of no more than 5 megawatts.  Study and reporting activities continued.

But on December 11, 2015, the permittee filed a request for acceptance of its surrender of the East Foreland Tidal Energy Project's preliminary permit.  In that request, the permittee described its "significant progress in evaluating the feasibility of a tidal energy project at East Foreland, Alaska, over the past several years."

Yet the surrender request also described the headwinds that stalled the project:
Nonetheless, the strength of the conventional energy market in Alaska precludes timely integration of new technology, like tidal energy systems, and advancement of the Project at the pace established by the original Schedule of Activities. As a result, public and private funding sources have sought nearer-term market impact from their investments. This in turn has negatively affected ORPC’s ability to expeditiously gather site data during Alaska’s limited field season window and maintain pace with FERC milestones.
As a result, the request describes the permittee's decision to surrender the East Foreland tidal project's preliminary permit and "to continue our focus and dedication of resources towards technology optimization and development of near term market opportunities that are available to ORPC and its power system technology."

Wisconsin municipal hydro project license extended

Friday, March 25, 2016

Federal energy regulators have granted a Wisconsin city's request to extend its hydropower project license for five years to allow time for comprehensive river corridor planning.  The March 17 order was the result of a rehearing following a denial by agency staff.  It relies on a finding of "relatively unique facts," which include a stakeholder process that will inform the licensee's upcoming decision whether to continue an effort to seek a new license for the project, or to surrender the license.

At issue is the Federal Energy Regulatory Commission license held by the City of River Falls, Wisconsin, for the 375-kilowatt River Falls Project on the Kinnickinnic River.  The municipal hydro project's current 30-year license expires on August 31, 2018, and a relicensing process is already underway -- but the city is also considering alternatives including surrendering the license.  As a result, last year the City filed a request to extend the expiration date of its license by five years, until August 31, 2023.  The City asked for more time to work with stakeholders and the community to complete a comprehensive river corridor plan, and determine whether to relicense the project or surrender the license.

But on December 9, 2015, Commission staff issued an order denying the City’s request. The order noted that the Commission has granted extensions of license terms only in a few specific instances and under limited circumstances.  For example, the Commission has extended license terms to amortize the cost of substantial new improvements or substantial new environmental measures, to coordinate the expiration dates of licenses in the same river basin, or because of unique circumstances or circumstances beyond a licensee’s control -- factors it did not originally find applicable to this proceeding. 

The City filed a timely request for rehearing of this denial, which the Commission recently granted.  In its March 17, 2016 order extending the license term five years, the Commission noted that it "generally does not favor actions that delay the completion of licensing proceedings," and historically "has extended license terms only in very narrow circumstances."  But "given the relatively unique facts of this case", the Commission found that an extension of the license term was in the public interest.

The Commission cited a list of specific factors making this proceeding unique:
We find that the unique circumstances of this proceeding – the combination of unanimous stakeholder support for the extension, the tying of the extension to the development of a comprehensive river plan, and the fact that the licensee is a small municipality – demonstrate that a five year extension of the project license is in the public interest. All resource agencies and stakeholders support the City’s proposal to extend the license term in order to complete the corridor plan and decide whether to seek a subsequent license or surrender the project. This strong support and lack of any adverse comments demonstrates that the City is not requesting an extension of the license term merely to delay the preparation of a relicense application and to continue generating under more favorable terms.
It also noted an efficiency benefit from extending the license term, given the pending question: whether to relicense the project, or surrender the license:
Last, allowing the City time to determine if it should relicense or surrender prior to having to file a relicensing application is the most efficient use of resources. As a small municipality, the City may incur significant costs in preparing and processing a relicensing application despite the fact that it may later surrender its license.
The Commission's order extended the license term for the River Falls Hydroelectric Project to August 31, 2023.  Meanwhile, the comprehensive Kinnickinnic River corridor planning process will continue.  That process may inform the City's decision whether to relicense the River Falls project, surrender its license, or pursue some other alternative.

FERC rules off-grid micro-hydro needs no license

Thursday, March 24, 2016

Federal hydropower regulators have granted reconsideration of a 2015 order finding licensing required for an off-grid micro-hydropower project proposed in Massachusetts.  Based on newly submitted evidence that the proposed project would not be connected to an interstate grid, the order granting reconsideration finds that Section 23(b)(1) of the Federal Power Act does not require licensing of the proposed Egnaczak Net Zero Hydro Project.

The case involves a project proposed by Kenneth and Susan Egnaczak, to be located at an existing water-powered mill complex on the Hoosic River in Cheshire, Massachusetts.  The so-called "Egnaczak Net Zero Hydro Project" would have a total generating capacity of 10.7 kilowatts.  The power would be used at a home and workshop proposed for construction along the river.

Under Section 23(b)(1) of the Federal Power Act, an entity proposing a hydropower project must generally file with the Federal Energy Regulatory Commission either a hydropower license application, or a Declaration of Intention to determine if the proposed project requires a license.  The Egnaczaks filed a Declaration of Intention for the project in February 2015.  On September 11, 2015, Commission staff issued an order finding that the Federal Power Act requires a license to be issued for the project's construction, maintenance, and operation.

Section 23(b)(1) of the Federal Power Act requires a non-federal hydroelectric project to be licensed if it falls into any of four categories: (1) is located on “navigable waters of the United States;” (2) occupies lands or reservations of the United States; (3) uses surplus water or water power from a federal dam; or (4) is located on a non-navigable stream which is subject to the authority of Congress under the Commerce Clause, affects the interests of interstate or foreign commerce, and is constructed or enlarged after August 26, 1935.

In its September 2015 order on the Egnaczak project, Commission staff analyzed the facts as applied to these facts.  On category 1, staff found that there is insufficient evidence to determine whether the Hoosic River is navigable at the project site.  Staff readily dispensed with categories 2 and 3, finding that the project would neither occupy any public lands or reservations of the United States nor use surplus water or waterpower from a Federal government dam.

In September, staff found that the project fell into the fourth category.  In the order, staff noted that it would be located on a non-navigable Commerce Clause stream, would be constructed after 1935, and would affect the interests of interstate commerce because the project would offset both electrical and heating needs for the applicants’ home and workshop that would have been otherwise supplied by the interstate grid.  The order cited judicial precedent, noting, "It is well settled that small hydroelectric projects that are connected to the interstate grid affect interstate commerce by displacing power from the grid, and the cumulative effect of the national class of these small projects is significant for purposes of FPA section 23(b)(1)." Staff therefore determined that the project requires licensing under FPA section 23(b)(1).

But on January 6, 2016, the applicants filed a request for reconsideration and additional evidence in support of their argument that the project does not require licensing.  This evidence focused on the fact that the project would not be connected to the interstate grid and thus would not affect interstate commerce.  As later described by the Commission:
They state that, because neither their home nor workshop has been constructed, they have no existing grid connection. Further, they explain that the project alone will power their home and workshop. The applicants state that the project would produce hydro-mechanical power using a waterwheel, Archimedes Screw, or turbine. The mechanical power would be connected to the hydro generator units to produce electricity or to power rotating equipment, such as a sawmill. In addition, the applicants state that they will use backup power from a fossil fuel electric generator and storage batteries, which would be charged by the hydro generators or the fossil fuel electric generator.
In a March 24, 2016 order, the Commission staff found that the applicants had demonstrated that the Net Zero Project would not be connected to an interstate grid.  That order finds that the micro-hydro project would not displace power that would otherwise be supplied by the grid and thus would not affect interstate commerce.  As a result, it concludes that "section 23(b)(1) of the FPA does not require licensing of the proposed Net Zero Project."

The March 24 order does include a warning: "if the project or the applicants’ unconstructed home or workshop are connected to the interstate grid in the future, section 23(b)(1) of the FPA would require licensing and the Commission could require the applicants to apply for a license under section 4(g) of the FPA."

Thus in at least this one case, the off-grid nature of the micro-hydro project was a critical factor in the order finding that Section 23(b)(1) of the Federal Power Act does not require licensing of the proposed Egnaczak Net Zero Hydro Project.  The key to the revised finding that the project would have no effect on interstate commerce appears to be the fact that power would be consumed in buildings not yet built, with no existing grid tie.

NY offshore wind zone announced

U.S. ocean energy regulators are advancing plans to lease sites off New York for potential commercial wind energy development.  The federal Bureau of Ocean Energy Management's designation of a Wind Energy Area could ultimately lead to the development of one or more offshore wind energy projects off Long Island.

While the U.S. still is not home to any operating commercial offshore wind projects, BOEM has issued 11 commercial wind energy leases off the Atlantic coast.  Leases awarded include two offshore New Jersey, two offshore Rhode Island-Massachusetts, another three offshore Massachusetts, one offshore Delaware, two offshore Maryland and one offshore Virginia.

In 2011, the New York Power Authority (NYPA) applied to BOEM for a commercial wind lease.  At that time, the public power authority proposed installing up to 194 wind turbines, each generating 3.6 megawatts, for a total project capacity of nearly 700 megawatts.

In January 2013, BOEM issued a Request for Interest to assess whether any other entities were parties interested in developing commercial wind facilities in the same area.  BOEM's review of the nominations of interest it received in response, including indications of interest from Fishermen’s Energy, LLC and Energy Management, Inc., led the agency to determine that there was competitive interest in the area.  As a result, BOEM initiated its competitive leasing process.

In 2014, BOEM published in the Federal Register a Call for Information and Nominations and a Notice of Intent to Prepare an Environmental Assessment, and has held stakeholder meetings.

The process took a step forward on March 16, 2016, when BOEM announced that it had completed the Area Identification process to delineate a Wind Energy Area (WEA) offshore New York. The wedge-shaped area covers approximately 127 square miles (81,130 acres, or 32,832 hectares), beginning about 11 nautical miles south of Long Beach, and extending about 26 nautical miles southeast along its longest portion.

Next steps in the offshore wind leasing process might include BOEM's publication of a Proposed Sale Notice for public comment, along with environmental assessment (EA) and agency consultations, followed by publication of a Final Sale Notice that announces the date, time, and specific conditions of the auction.  According to BOEM, its environmental review is expected to be completed later this year.

FERC to examine competitive transmission incentives

Wednesday, March 23, 2016

The Federal Energy Regulatory Commission has scheduled a Commissioner-led technical conference for this summer to discuss issues related to competitive transmission development processes.  At issue will be the use of cost containment provisions, the relationship of competitive transmission development to transmission incentives, and other ratemaking issues.

As part of the Energy Policy Act of 2005, Congress added section 219 to the Federal Power Act.  Section 219 directs the Commission to establish, by rule, incentive-based rate treatments to promote capital investment in certain transmission infrastructure.  The Commission's Order No. 679 sets forth processes by which a public utility may seek transmission rate incentives pursuant to section 219.  To qualify, an applicant must show that "the facilities for which it seeks incentives either ensure reliability or reduce the cost of delivered power by reducing transmission congestion" and also demonstrate a nexus between the incentives being sought and the investment being made.  Order No. 679-A clarified that this nexus test is satisfied when an applicant demonstrates that the total package of incentives requested is tailored to address the demonstrable risks or challenges faced by the applicant.

But a case decided earlier this year has led the Commission to reevaluate broader policy considerations relating to the role of cost containment proposals in competitive transmission development.   In a January 8, 2016 order, NextEra Energy Transmission West, LLC, 154 FERC ¶ 61,009, the Commission partially rejected a request by a public utility transmission owner for certain transmission rate incentives pursuant to section 219 and Order No. 679.  That case involved proposed transmission development under the California Independent System Operator Corporation (CAISO)'s competitive transmission developer selection process adopted to comply with Order No. 1000.

Most controversial in the "NEET West" case was a conditional adder to the utility's return on equity that would be triggered if the return on equity fell below the 10 percent that was the foundation for the utility's competitive bids for transmission project development.  On the specific facts and circumstances of that case, the Commission found that the utility had not provided adequate support for the "conditional ROE incentive" and therefore denied it.

But in ruling on the NEET West case, the Commission noted that "this case highlights broader policy considerations related to the potential benefits of cost containment proposals in the context of competitive transmission development." In the NEET West order, the Commission signaled its intent to convene a technical conference in the future to explore further such issues, including how they relate to a 2012 Policy Statement issued by the Commission providing additional guidance regarding its evaluation of applications for transmission rate incentives under section 219 of the Federal Power Act and Order No. 679.

The first specific issue identified in the NEET West order involves the relationship between an expectation stated in the Policy Statement and risks associated with cost containment proposals. The Policy Statement requires an applicant seeking an incentive ROE to demonstrate that the proposed project faces risks and challenges that are not either already accounted for in the applicant’s base ROE or addressed through risk-reducing incentives.  The Commission expressed interest in exploring more broadly "why cost containment-related risks would not be accounted for in a base ROE level below 10 percent and yet would be accounted for in a base ROE of 10 percent" as NEET West argued.

The second specific issue involves "whether and how risks voluntarily assumed through submittal of a cost containment proposal relate to the second expectation set forth in the Policy Statement." The Commission expects an applicant seeking an ROE incentive based on a project’s risks and challenges to demonstrate that it is taking appropriate steps and using appropriate mechanisms to minimize its risks during project development.  But it noted that NEET West "voluntarily submitted cost caps to make its bids to CAISO more attractive, which exposes NEET West’s shareholders to risks they would not have faced absent the cost caps."  The Commission expressed intent to explore "whether and how voluntarily assuming this type of risk is consistent with minimization of risk envisioned by the Policy Statement."

On March 17, the Commission denied a request by ITC Grid Development for a declaratory order on whether cost-capped bids that won a competitive transmission project selection process should automatically be considered just and reasonable.  But that same day, the Commission issued a Notice of Technical Conference in Docket No. AD16-18-000.  In a footnote, the notice states that topics to be discussed include, but are not limited to, those that the Commission described in its NEET West order.

The technical conference to explore these and related issues has now been scheduled for June 27 and 28, 2016, at the Commission ’s headquarters at 888 First Street, NE, Washington, DC 20426.