BOEM advances California offshore wind leasing

Friday, August 26, 2016

U.S. ocean energy managers are moving closer to leasing sites in federal waters offshore California for wind energy development.  Acting in response to a lease area requested by Trident Winds, LLC, this month the Bureau of Ocean Energy Management (BOEM) issued a Request for Interest in that area to evaluate whether any other developer is interested in competing for a lease.

Trident Winds has initiated development of a commercial scale offshore wind farm off Point Estero, California.  Its Morro Bay or MBO Project would be located in federal waters about 33 nautical miles northwest of Morro Bay; the site features water depths of 2,600 to 3,300 feet.  In light of these site conditions, Trident Winds' proposed project would consist of 100 floating foundations, each supporting a wind turbine generating 7-8 megawatts of energy.  Electricity would be brought ashore via a single transmission cable.

Trident Winds requested a commercial wind lease from BOEM on January 14, 2016, covering a 67,963-acre proposed lease area.  Because BOEM had not previously solicited interest in leasing this area, BOEM treated Trident Winds' request as "unsolicited."  Under BOEM's offshore renewable energy program, when presented with an unsolicited lease request, BOEM first evaluates whether the developer is qualified to hold a lease on the Outer Continental Shelf.  In the case of Trident Winds, BOEM made this determination following consultation with the state of California.

Following this qualification determination, BOEM's next step is to determine whether it is appropriate to issue the company a lease on a non-competitive basis, or whether a competitive process is required.  To inform this competitive interest determination, on August 17, 2016, BOEM published a Potential Commercial Leasing for Wind Power on the Outer Continental Shelf (OCS) Offshore California, Request for Interest in the Federal Register, with a 30-day public comment period.  If BOEM finds competitive interest, it will initiate a competitive leasing process for the California site. If no expressions of interest are received, BOEM will proceed with its noncompetitive leasing process.

At the same time, BOEM is also seeking public comment on the project proposal, its potential environmental consequences, and other uses of the project area such as navigation, fishing, military activities, recreation.   BOEM will also use responses to shape its decisionmaking and to flag potential issues for analysis under the National Environmental Policy Act.

So far, BOEM has awarded 11 commercial wind energy leases for sites off the Atlantic coast, nine of which came from competitive lease sales that generated about $16 million in winning bids.  BOEM has also recently announced proposed lease sales for sites offshore North Carolina and New York.  In the Pacific, BOEM is evaluating 3 unsolicited lease requests offshore Hawaii and has published a Call for Interest in Hawaiian site leasing.

Vermont adopts Renewable Energy Standard

Thursday, August 25, 2016

This summer Vermont energy regulators issued an order implementing a Renewable Energy Standard.  This standard, or RES, requires Vermont electric utilities to procure an increasing share of electricity from renewable sources. 

Under a 2015 law called Act 56 (formerly called bill H.40), the Vermont Legislature directed the Public Service Board to issue an order implementing the RES to take effect on January 1, 2017.  Act 56 set certain rules for the RES, but left other issues to the Board.  Following working group meetings, workshops, and opportunities for written comment, the Board adopted the RES by order dated June 28, 2016.

The RES sets targets for utility procurement of renewable energy, starting at 55% of the electricity sold to customers from renewable sources in 2017, increasing gradually to 75% in 2032.   Of these amounts, at least 1% must come from new, distributed renewable generators, such as net-metering systems, rising to l0% by 2032.

The RES also establishes a category of "energy transformation projects," to encourage utility investment in projects that directly reduce customers' fossil-fuel consumption.  Energy transformation projects might include measures like weatherization, biomass heating, cold-climate heat pumps, demand management, or clean vehicle technologies.  To satisfy this requirement, utilities must demonstrate fossil-fuel savings equivalent to 2% of their annual retail sales (increasing to 12% by 2032) or procure an equal amount of additional renewable generation.  The Board has described the energy transformation project program as the first of its kind in the U.S.

Most states have adopted binding renewable portfolio standards for electricity supply.  Before the enactment of Act 56 and the Board's adoption of the RES, Vermont had renewable goals under its Sustainably Priced Energy Enterprise Development or SPEED program, but no mandatory renewable portfolio standard.

Under the act, the Vermont Public Service Board order adopting the RES will take effect on January 1, 2017.

Massachusetts develops next solar incentive

Wednesday, August 24, 2016

The Massachusetts Department of Energy Resources (DOER) is designing a new solar incentive program to encourage the continued development of solar renewable energy generating sources by residential, commercial, governmental and industrial electricity customers, based on a state law enacted this spring. The so-called "next solar initiative" program could affect the pace of solar photovoltaic project development in Massachusetts, as policymakers seek a smooth transition from the current SREC II program as it reaches full capacity.

On April 11, 2016, Governor Charlie Baker signed into law An Act Relative to Solar Energy, also known as Chapter 75 of the Acts of 2016.  The law preserved and expanded net metering, preserving the value of that policy for projects developed by residential, small commercial, municipal and government customers.

As described by the Baker administration, the law also allows DOER and the Department of Public Utilities to "gradually transition the solar industry to a more self-sustaining model." In particular, section 11 of the act directed 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 throughout the commonwealth."

The law prescribed twelve requisite characteristics of the solar incentive program, but left the creation of rules and regulations to DOER.  Some criteria are process-oriented, such as that the program "promotes the orderly transition to a stable and self-sustaining solar market at a reasonable cost to ratepayers," or considers underlying system costs, environmental benefits, energy demand reduction and other avoided costs provided by solar renewable energy generating facilities.

Other criteria define structural requirements for the program, such as that it "relies on market-based mechanisms or price signals as much as possible to set incentive levels," "differentiates incentive levels to support diverse installation types and sizes that provide unique benefits," and "features a known or easily estimated budget to achieve program goals through use of a declining adjustable block incentive, a competitive procurement model, tariff or other declining incentive framework."  The law also requires the program to promote investor confidence through long-term incentive revenue certainty and market stability.

After the solar bill's enactment, DOER held two public listening sessions, and solicited comments on the development of the "next solar incentive" through June 30, 2016.  Many commenters expressed support for a continuation of the SREC framework, such as "SREC III."  Other comments focused on locational issues, such as proposing policies to deter the development of projects located on farmland or other undeveloped "greenfield" sites.

DOER is expected to release a first draft of its next solar incentive program this summer.

DesertLink transmission project wins rate incentives under Section 219

Tuesday, August 23, 2016

Federal energy regulators have granted a petition by the developer of a proposed electric transmission project in Nevada for certain transmission rate incentives available under federal law.  On August 19, the Federal Energy Regulatory Commission ruled on DesertLink, LLC's petition for declaratory order, with respect to DesertLink's new Harry Allen to Eldorado 500 kV transmission project.  The order grants DesertLink's requests for transmission rate incentives under section 219 of the Federal Power Act, and illustrates how those incentives operate.

DesertLink, a member of the LS Power Group, is the developer of a transmission project to be located in Nevada, but connected to a substation in the grid controlled by the California Independent System Operator Corporation.  CAISO designated the project for competitive bidding under its 2013-2014 transmission plan, and in January 2016 selected DesertLink as the approved project sponsor under its Order No. 1000-based process for eligible transmission developers to submit bids to develop and construct certain transmission projects.  The project is designed to have an in-service date of May 2020.

Rate incentives can be available to promote capital investments in certain transmission infrastructure.  The Federal Power Act authorizes the Federal Energy Regulatory Commission to regulate the transmission and wholesale sales of electricity in interstate commerce.  Through the Energy Policy Act of 2005, Congress added a new section 219 to the Federal Power Act, directing the Commission to create rules establishing incentive-based rate treatments.  The Commission's Order No. 679 sets forth the processes by which a public utility may seek transmission rate incentives under section 219, and the Commission has issued a Transmission Incentives Policy Statement offering guidance on how it evaluates applications for transmission rate incentives.

Section 219 and Order No. 679 require an applicant for rate incentives to show that “the facilities for which it seeks incentives either ensure reliability or reduce the cost of delivered power by reducing transmission congestion.”  Order No. 679 established a rebuttable presumption that this standard is met if:
(1) the transmission project results from a fair and open regional planning process that considers and evaluates the project for reliability and/or congestion and is found to be acceptable to the Commission; or (2) a project has received construction approval from an appropriate state commission or state siting authority.
Order No. 679 also requires an applicant to demonstrate that there is a nexus between the incentive being sought and the investment being made.  The Commission clarified in Order No. 679-A that this "nexus test" is met when an applicant demonstrates, on a project-specific basis, that the total package of incentives requested is “tailored to address the demonstrable risks or challenges faced by the applicant.”

In DesertLink's case, on May 11, 2016, the applicant applied for transmission rate incentives, including (1) deferred recovery of all prudently incurred precommercial costs through the creation of a regulatory asset (regulatory asset incentive); (2) full recovery of 100 percent of prudently-incurred costs, including pre-commercial expenses and construction costs, if the Project is abandoned for reasons beyond DesertLink’s control (abandonment incentive); (3) use of a hypothetical capital structure consisting of 50 percent debt and 50 percent equity until the Project achieves commercial operation (hypothetical capital structure incentive); and (4) a 50-basis point adder to DesertLink’s Return on Equity (ROE) for participating in a Regional Transmission Organization (RTO), namely, CAISO (RTO participation incentive).

Last week, the Commission granted DesertLink's petition.  First, the Commission found that DesertLink is entitled to the rebuttable presumption that the Project will ensure reliability or reduce the cost of delivered power by reducing transmission congestion, because the CAISO transmission planning process found annual production cost benefits of $9.4 million in 2019 to $8.4 million in 2024 and beyond, and annual capacity benefits of $19.7 million in 2020 to $8.8 million in 2025 and beyond.

Next, the Commission found that DesertLink had demonstrated that its total package of requested incentives is tailored to address the demonstrable risks or challenges faced by DesertLink.  The Commission found that the regulatory asset treatment of pre-commercial costs appropriately addresses the risks and challenges of the Project, because it provides DesertLink with added upfront regulatory certainty, reduces interest expenses, and assists in the construction of the Project.  On the abandonment incentive, the Commission found that recovery of abandonment costs was an effective means to encourage transmission development by reducing the risk of non-recovery of costs.  Regarding a hypothetical capital structure, the Commission noted that its use "will aid DesertLink in raising capital during the construction phase of the Project, and will assist DesertLink in maintaining low debt costs while its actual debt-to-equity ratio varies."  The Commission also found DesertLink would qualify for the RTO participation incentive, based on its commitment to become a member of CAISO and to transfer operational control of the project to CAISO after placing it in service.

The Commission's determination takes the form of a declaratory order granting authorization for the rate incentives, but it does not directly authorize DesertLink to include the incentives in its filed rates.  As the Commission noted, "While our determination on DesertLink's Petition establishes whether it qualifies for the requested transmission rate incentives, if DesertLink seeks to put these incentives into effect, it must submit a subsequent filing under section 205 of the FPA."  In such a case, the applicant will need to make a variety of showings before including certain incentives in its rate base, including the justness and reasonableness of costs relating to pre-commercial, formation, and plant abandonment.  Nevertheless, securing the declaratory order gives DesertLink greater certainty about its qualification for these key incentives for electric transmission development.

New Jersey FERC license surrender and dam removal

Monday, August 15, 2016

U.S. energy regulators have accepted an application to surrender the licensee for a New Jersey hydropower project.  Earlier this month, the Federal Energy Regulatory Commission accepted Great Bear Hydropower Inc.'s application to surrender its license for the Columbia Dam Project, located on the Paulins Kill.  While the Commission decision to accept license surrender does not necessarily mean the dam will be removed, it represents a significant step toward letting the dam owner pursue dam removal if it wishes.  The case also illustrates tensions between hydropower development and dam removal, which remain active in U.S. policy discussions, and the consequences of state jurisdiction following FERC license surrender.

On January 15, 1986, the Commission issued a 40-year license for the construction, operation, and maintenance of hydroelectric facilities at the existing Columbia Dam.  The project includes a 20-foot-high, 330-foot-long concrete dam, originally built by a utility in 1909.  The site was sold to the state in 1955, after which the original electric generation was discontinued.  Following the project's 1986 licensing by FERC, the licensee added a powerhouse containing two generating units with a total installed generating capacity of 530 kilowatts.

The dam remains owned by the state of New Jersey as part of the Columbia Wildlife Management Area, and the licensee has been operating the project under a long-term lease with the state. But significant efforts are under way to improve water quality in the Delaware River basin.  The Nature Conservancy has described a strategy for watershed restoration that features the Columbia Dam's removal as a key component.  After the state and The Nature Conservancy entered into an agreement to remove the dam, the licensee ultimately agreed to surrender its license and remove only its hydroelectric facilities originally added to the dam, leaving the state to perform any future dam removal.

Because the Columbia Dam Project is subject to Part 1 of the Federal Power Act, its license could not be surrendered without approval of the Federal Energy Regulatory Commission.  The licensee applied for surrender in October 2015.  The Commission granted that approval on August 10, 2016.

The FERC license surrender does not necessarily mean that the dam itself will be removed, although it does provide for decommissioning of the hydropower equipment.  The Commission accepted the licensee's proposal to remove the generating equipment, transformers from the powerhouse, and disconnect the electric connection to the local utility.  The license surrender will not be effective until the Commission agrees that the project’s facilities have been decommissioned in accordance with this surrender order.

As for the dam, the Commission noted, "It will be up to the state of New Jersey, the dam owner, to decide whether to remove the Columbia Dam, once the hydroelectric facilities have been decommissioned.  Dam removal would have some ecological, social, and economic benefits for the Paulins Kill watershed."  Following the effectiveness of license surrender, safety matters would primarily be state jurisdictional, and any dam removal would proceed primarily under state law.

While hydropower continues to play a significant role in the overall U.S. energy mix, with new and ongoing federal initiatives to increase hydropower generation, in some cases economics and environmental considerations may lead to the surrender of some project licenses.  This may be particularly true for some relatively small dams with fish passage issues facing relicensing in coming years.

NEPA guidance on greenhouse gas emissions

Thursday, August 11, 2016

Federal agencies have new guidance on how to address the effects of greenhouse gas emissions and climate change as those agencies satisfy their duties under the National Environmental Policy Act.  This month the White House Council on Environmental Quality or CEQ issued its Final Guidance for Federal Departments and Agencies on Consideration of Greenhouse Gas Emissions and the Effects of Climate Change in National Environmental Policy Act Reviews.  The document is designed to improve clarity and consistency in how federal agencies address climate change in the environmental impact assessment process under NEPA.

Enacted in 1970, NEPA generally requires agencies to consider the environmental effects of proposed agency actions, and to provide the public and decision makers with useful information regarding reasonable alternatives and mitigation measures.  To coordinate federal environmental efforts, NEPA also established CEQ within the Executive Office of the President.  CEQ is now charged with issuing mandatory regulations for NEPA implementation, as well as guidance documents such as the recent greenhouse gas guidance.

In its final greenhouse gas guidance, CEQ described climate change as "a fundamental environmental issue" whose effects fall squarely within NEPA's purview.  In CEQ's words, "Analyzing a proposed action’s GHG emissions and the effects of climate change relevant to a proposed action — particularly how climate change may change an action’s environmental effects — can provide useful information to decision makers and the public." CEQ views focused and effective consideration of climate change in NEPA reviews as enabling higher quality agency decisions.

To this end, CEQ offered guidance that:
when addressing climate change agencies should consider: (1) The potential effects of a proposed action on climate change as indicated by assessing GHG emissions (e.g., to include, where applicable, carbon sequestration); and, (2) The effects of climate change on a proposed action and its environmental impacts.
The guidance presents further information and interpretation on each of these points. For example, it recommends that agencies quantify the direct and indirect greenhouse gas emission resulting from a proposed agency action, as well as both short- and long-term adverse and beneficial effects.  The guidance also stated that "a NEPA review should consider an action in the context of the future state of the environment." 

In one sense, the final guidance is just guidance.  As CEQ noted, agencies have discretion in how they tailor their individual NEPA reviews to accommodate the guidance. CEQ directed that agencies should apply this guidance to all new proposed agency actions as of the initiation of NEPA review.  It suggested that agencies "should exercise judgment" when considering the application of the guidance to an on-going NEPA process, but that CEQ does not expect agencies to apply the guidance to concluded NEPA reviews, nor to any actions for which a final Environmental Impact Statement (EIS) or Environmental Assessment (EA) has been issued.

CEQ recommended that agencies review their NEPA procedures and propose any updates they deem necessary or appropriate to facilitate their consideration of greenhouse gas emissions and climate change.  Agency procedures to implement NEPA may be in the form of regulations, although they are not required to take that form.  CEQ's final guidance on greenhouse gas emissions may lead other federal agencies to revise regulations, policies, or implementing procedures to ensure full compliance with NEPA.

DOE Hydropower Vision report

Tuesday, August 9, 2016

The U.S. Department of Energy (DOE) has released a report on the future of domestic hydropower.  Its Hydropower Vision finds that U.S. hydropower could grow from 101 gigawatts of capacity in 2015 to nearly 150 gigawatts by 2050.  More than 50% of this growth could be realized by 2030, according to the report.  Much of the new capacity would come from pumped storage, with the remainder coming from upgrades to existing plants, adding power at existing dams and canals, and "limited development of new stream-reaches."

DOE's Wind and Water Power Technologies Office describes its report, Hydropower Vision: A New Chapter for America’s First Renewable Electricity Source, as presenting "a first-of-its-kind comprehen sive analysis to evaluate future pathways for low-carbon, renewable hydropower (hydropower generation and pumped storage) in the United States, focused on continued technical evolution, increased energy market value, and environmental sustainability." While it does not evaluate or recommend new policy actions, the report does analyze the "feasbility and certain benefits and costs of various credible scenarios, all of which could inform policy decisions at the federal, state, tribal, and local levels."

The report's Executive Summary presents an overview of the report, and its three "pillars" or foundational principles developed in collaboration with stakeholders: optimizing the value and power generation contribution of the existing hydropower fleet, exploring the feasibility of "credible long-term deployment scenarios for responsible growth of hydropower capacity and energy production," and sustainability.  Analyzing data and modeled scenarios, the report found that "under a credible modeled scenario in which technology advancement lowers capital and operating costs, innovative market mechanisms increase revenue and lower financing costs, and a combination of environmental considerations are taken into account—U.S. hydropower including PSH could grow from 101 GW of capacity in 2015 to 150 GW by 2050."

Chapter 1 of the Hydropower Vision describes how technical resource assessments and computational models can be used to interpret hydropower's future market potential.  It also evaluates potential innovations or nontraditional approaches to technology and project development that could affect the future development of new hydropower projects.

Chapter 2 of the Hydropower Vision presents a snapshot of the state of the U.S. hydropower industry as of year-end 2015, from the Energy Department's perspective.  It notes that hydropower generation and pumped storage have "provided a stable and consistently low-cost energy source throughout decades of fluctuations and fundamental shifts in the electric sector, supporting development of the U.S. power grid and the nation’s industrial growth in the 20th century and into the 21st century." The report points to 2015 data showing 2,198 active hydropower plants in the U.S. with a total capacity of 79.6 gigawatts, plus 42 pumped storage hydro plants totaling another 21.6 gigawatts.  In 2015, hydropower provided about 6.2% of net U.S. electricity generation, and 48% of all U.S. renewable power.

Chapter 3 of the report explores over 50 possible future scenarios for the hydropower industry, to assess the nation's hydropower potential.  It presents an extensive body of analysis, considering potential contributions over time to the electric sector of both the existing hydropower fleet and new hydropower deployment resulting from: upgrades at existing plants, powering of non-powered dams (NPD), pumped storage hydropower (PSH), and new stream-reach development (NSD).  It found that the greatest influence on potential growth scenarios comes from 3 variables: technological innovation, environmental considerations, and financial improvement.

The report's fourth chapter lays out a roadmap of 64 potential actions for stakeholder consideration, "to optimize hydropower’s continued contribution to a clean, reliable, low-carbon, domestic energy generation portfolio while ensuring that the nation’s natural resources are adequately protected or conserved."  These actions are organized around 5 topical areas: technology advancement, sustainable development and operation, enhanced revenue and market structures, regulatory process optimization, and enhanced collaboration, education, and outreach.

As noted by the Energy Department, while utility-scale battery storage projects are starting to be developed, most U.S. electricity storage capacity takes the form of pumped storage.  Flexible and reliable generating or storage resources can support efforts to integrate increasing amounts of intermittent renewable energy sources, like wind and solar, into the grid.

NH adopts Energy Efficiency Resource Standard

Friday, August 5, 2016

The New Hampshire Public Utilities Commission has approved a settlement agreement that establishes a statewide Energy Efficiency Resource Standard.  The Commission described the EERS as "a framework within which the Commission’s energy efficiency programs shall be implemented," effective January 1, 2018.

Historically, most of the Commission's energy efficiency work has been through New Hampshire's so-called Core programs, with savings goals set more based on how much funding is available than on overall savings potential.  But pressure has been mounting for change.  Studies have shown that "additional opportunities for cost-effective energy efficiency exist beyond those attained through the Core program."  In 2014, the Governor's Office of Energy Planning's 10-year State Energy Strategy called for an EERS "aimed at achieving all cost effective efficiency over a reasonable time frame."

Last year, the Commission opened a case to establish a policy that sets specific targets or goals for energy savings, which utility companies serving New Hampshire ratepayers must meet.  The Commission described the creation of an EERS as "an opportunity to set savings goals based on savings potential in addition to consideration of the funding level."  Following proposals by Commission staff, utilities, and advocates for sustainable energy and environmental goals, negotiations to resolve the case developed into an April 2016 settlement agreement.

On August 2, 2016, the New Hampshire Public Utilities Commission issued its Order No. 25,932, approving the EERS settlement agreement.  That order establishes a long-term goal of achieving all cost-effective energy efficiency, and a framework consisting of three-year planning periods and savings goals.  Initial EERS programs will be administered by electric and gas utilities. Specific programs will be subject to Commission approval, and must be shown to be cost effective.  The Commission also established a recovery mechanism to compensate the utilities for lost revenue related to the EERS programs.

For the first triennium of the EERS, the Commission adopted savings goals as a percentage of 2014 statewide delivered sales, intended to reach overall cumulative savings by 2020 of 3.1% of electric sales and 2.25% of gas sales, relative to the 2014 baseline year.  The existing Core program will also continue through next year; statewide savings goals for the "2017 Core-extension" will be 0.6% of 2014 statewide delivered sales for electric and 0.66% for gas.

The Commission noted that while all customers may face small short-term rate increases to recover the cost of an EERS, "customer bills will decrease when their energy consumption decreases as well as when the impact of consumption decreases are reflected in reduced grid and power procurement costs."

FERC declares QF rights

Thursday, August 4, 2016

Federal energy regulators have issued an advisory opinion regarding the rights of Qualifying Facility electric generators to sell power to their local utility under the Public Utility Regulatory Policies Act (PURPA).  The Federal Energy Regulatory Commission's declaratory ruling illustrates how the Commission interprets PURPA and QF rights, in the context of state renewable energy portfolio standards and

PURPA was enacted by Congress in 1978 to promote goals including energy conservation and greater production of domestic and renewable energy.  It established a new class of generating facilities called QFs, to receive special rate and regulatory treatment. A chief benefit of QF status is the
right to sell energy and capacity to a utility, usually at either at the utility's avoided cost or at a negotiated rate.  By regulation, QFs generally have the option to sell energy either "as-available," or as part of a long-term contract or other legally enforceable obligation for delivery of energy or capacity over a specified term.

The Federal Energy Regulatory Commission oversees this program, although state energy commissions play important roles.  Section 210 (H)(2)(A) and (B) of PURPA give the Commission discretionary power to enforce its PURPA rules, including the power to require state commissions and non-regulated utilities to comply.  But the Commission may also decline to initiate an enforcement action, on a case by case basis.

Earlier this year, a group of QFs filed a complaint to the Commission against the Connecticut Public Utilities Regulatory Authority.  Windham Solar LLC and Allco Finance Limited alleged that Connecticut law and PURA’s regulations violate the Commission's PURPA regulations regarding an electric utility’s mandatory purchase obligation and a QF’s ability to sell pursuant to a legally enforceable obligation. Complainants effectively alleged that they couldn’t get a long-term contract to sell energy and capacity at avoided cost rates on a forecasted basis, unless the energy and capacity were bundled with renewable energy certificates (RECs), or unless the energy and capacity were provided under a short-term contract not to exceed one year.

Some of those basic facts were contested by PURA and others, and the Commission noted a history of dispute and litigation among the complainants and Connecticut energy regulators. So the Commission declined to initiate an enforcement action on the complaint.

But the Commission did issue a declaratory ruling, reciting case law and interpretation on two points: the relationship between state RECs and PURPA, and QF opportunities to secure long-term contracts.  The Commission noted that RECs exist under state law and not PURPA, but that avoided cost contracts do not automatically include RECs.  It also noted that winning a competitive solicitation cannot be the only way a QF may be allowed to obtain long-term avoided cost rates.

The original comes with robust citations to precedent, omitted for convenience below:
4. The Commission has previously addressed issues regarding the relationship between state-created RECs and PURPA. The Commission has stated that the states have the authority to determine who owns RECs in the initial instance and how they are transferred, and has explained that the automatic transfer of RECs within a sale of power at wholesale must find its authority in state law, not PURPA. The Commission has also held, however, that a state regulatory authority may not assign ownership of RECs to utilities based on a logic that the avoided cost rates in PURPA contracts already compensate QFs for RECs in addition to compensating QFs for energy and capacity, because the avoided cost rates are, in fact, compensation just for energy and capacity. Moreover, while the Commission has made clear that states have the authority to regulate RECs, states cannot impede a QF’s ability to sell its output to an electric utility pursuant to PURPA. Thus, regardless of whether a QF has previously sold its RECs under a separate contract, that QF has the right to sell its output pursuant to a legally enforceable obligation.

5. The Commission has also held that “requiring a QF to win a competitive solicitation as a condition to obtaining a long-term contract imposes an unreasonable obstacle to obtaining a legally enforceable obligation.” The Commission likewise has determined a state regulation to be inconsistent with PURPA and the Commission’s PURPA regulations “to the extent that it offers the competitive solicitation process as the only means by which a QF . . . can obtain long-term avoided cost rates.” Accordingly, regardless of whether a QF has participated in a request for proposal, that QF has the right to obtain a legally enforceable obligation. 
As noted in the declaratory ruling, the Commission's "decision not to initiate an enforcement action means that Petitioners may themselves bring an enforcement action against the Connecticut Authority in the appropriate court."

NY Clean Energy Standard adopted

Wednesday, August 3, 2016

The New York Public Service Commission has issued an order adopting a clean energy standard.  The standard will require 50% of New York’s electricity to be generated by renewable sources by 2030.  This so-called "50 by 30" mandate is consistent with the State Energy Plan's strategy to reduce statewide greenhouse gas emissions by 40% by 2030.  It will also provide support for existing nuclear power plants said to be at risk for closure without state support.  This is a time of change for the New York energy industry, as the Clean Energy Standard adds to the regulatory and retail market changes that the state is already pursuing under its Reforming the Energy Vision or REV program.

The New York commission noted that the state has adopted "strongly proactive policies to combat climate change and modernize the electric system to improve the efficiency, affordability, resiliency, and sustainability of the system." The state's 2015 State Energy Plan called for the "50 by 30" goal for renewable energy.

In the Commission's words, it determined "that a series of deliberate and mandatory actions to build upon and enhance opportunities for consumer choice are necessary to achieve State environmental, public health, climate policy and economic goals; to enhance and animate voluntary retail markets for energy efficiency, clean energy and renewable resources; to preserve existing zero-emissions nuclear generation resources as a bridge to the clean energy future; to ensure a modern and resilient energy system; and to accomplish its objectives in a fair and cost-effective manner."

As a result, the Commission adopted a Clean Energy Standard or CES consisting of a Renewable Energy Standard and a Zero-Emissions Credit Requirement program.  The Commission also adopted supporting structures, which it describes as including:
(a) program and market structures to encourage consumer-initiated clean energy purchases or investments; (b) obligations on load serving entities to financially support new renewable generation resources to serve their retail customers; (c) a requirement for regular renewable energy credit (REC) procurement solicitations; (d) obligations on distribution utilities on behalf of all retail customers to continue to financially support the maintenance of certain existing at-risk small hydro, wind and biomass generation attributes; (e) a program to maximize the value potential of new offshore wind resources; and (f) obligations on load serving entities to financially support the preservation of existing at- risk nuclear zero-emissions attributes to serve their retail customers.
As described by Governor Andrew Cuomo, the program will feature a ramp-up of renewable power sourcing.  Utilities and other energy suppliers will be initially required to procure 26.32 percent of the state's total electricity load from renewable sources in 2017, increasing to 30.54 percent by 2021.  The Commission described the 50 by 30 goal as "not only part of a larger greenhouse gas goal, it is part of the State’s sweeping initiative to transform the way energy is produced, delivered, and consumed" through the REV process.

The Clean Energy Standard order also creates a Zero-Emissions Credit or ZEC requirement, along with a process through which state energy agency NYSERDA will offer qualifying nuclear facilities a multi-year contract for the purchase of ZECs, at a price ultimately derived from the calculations of "social cost of carbon."  NYSERDA will ultimately resell the ZECs to New York load serving entities, who will recover costs from ratepayers through commodity charges on customer bills.  The Commission described the ZEC mechanism as "the best way for the State to preserve the nuclear units’ environmental attributes while staying within the State’s jurisdictional boundaries. "

As described in the order, the Renewable Energy Standard and ZEC components "are interrelated but the goals are additive," meaning efforts to comply with the RES will not count toward the ZEC requirement, even if the combination will "contribute toward the State's comprehensive greenhouse gas reduction goals."

Offshore wind in Massachusetts energy bill

Tuesday, August 2, 2016

The Massachusetts legislature has enacted an energy bill that will require utilities to purchase offshore wind energy by 2027.  The legislation, known as H. 4568, "An Act to promote energy diversity," has been laid before Governor Charlie Baker for signature.

Earlier this session, the Massachusetts House and Senate had passed two different bills calling for renewable energy procurement.  A conference committee reported out the final bill, H. 4568, on July 31.  Through the newly enacted law, the Massachusetts legislature has added a new program of offshore wind energy procurement. 

The final enacted bill adds a new section 83C to the state's 2008 Green Communities Act.  Among other provisions, section 83C provides, "In order to facilitate the financing of offshore wind energy generation resources in the commonwealth, not later than June 30, 2017, every distribution company shall jointly and competitively solicit proposals for offshore wind energy generation; and, provided, that reasonable proposals have been received, shall enter into cost-effective long-term contracts."

Much of the solicitation and contracting process will occur pursuant to regulations yet to be promulgated by the Department of Public Utilities.  The law provides a framework for developing and approving the competitive bidding process, and requires the schedule to "ensure that the distribution companies enter into cost-effective long-term contracts for offshore wind energy generation equal to approximately 1,600 megawatts of aggregate nameplate capacity not later than June 30, 2027."  Individual solicitations must be seek proposals for 400 megawatts or more, and may be conducted jointly with other states.

Proposed long-term contracts are subject to the review and approval of the Department of Public Utilities.  The law requires the department of public utilities to weigh the potential costs and benefits of the proposed long-term contract, and directs it to approve a proposed long-term contract "if the department finds that the proposed contract is a cost-effective mechanism for procuring reliable renewable energy on a long-term basis," taking into account factors like reliability, mitigation of price volatility, cost-effectiveness, mitigation of environmental impacts, and economic development.

The law requires the implementing regulations to be adopted by the Department of Public Utilities to "provide for an annual remuneration for the contracting distribution company up to 2.75 per cent of the annual payments under the contract to compensate the company for accepting the financial obligation of the long-term contract."  It also entitles distribution companies to cost recovery of payments made under an approved long-term contract.  Utilities may elect to to use any energy purchased under such contracts for sale to its customers and retain renewable energy certificates for their use, or may sell the energy and RECs into the market.  Any proceeds from such market re-sales will be netted against the cost of contract payments, resulting in a credit or charge to all distribution customers through a uniform fully reconciling annual factor in distribution rates.

The law also provides a variety of "outs" or circumstances under which contracts might not result, such as if a "proposal’s terms and conditions would require the contract obligation to place an unreasonable burden" on a distribution company’s balance sheet.

Notably, the law's definitions of “Offshore wind developer” and “Offshore wind energy generation” place a variety of restrictions on projects eligible for contracting.  The definitions effectively require that projects be located on the Outer Continental Shelf, in a designated wind energy area for which an initial federal lease was issued on a competitive basis after January 1, 2012, have no turbine located within 10 miles of any inhabited area, and have a commercial operations date on or after January 1, 2018, that has been verified by the department of energy resources.  This effectively limits projects to a subset of those winning recent (or future) federal Bureau of Ocean Energy Management lease auction sales.

To date, no commercial offshore wind projects operate in U.S. waters, although Deepwater Wind is currently constructing the Block Island Wind Farm off Rhode Island.   Federal programs, along with some state incentives, are available to support qualifying offshore wind projects.

Maine biomass commission first meeting

Monday, August 1, 2016

A special commission formed by the Maine Legislature to study the economic, environmental and energy benefits of the state's biomass industry holds its first meeting this week.

The Maine State House, where the 2016 biomass resolve was enacted.

This spring, the Maine legislature enacted a resolve establishing the Commission to Study the Economic, Environmental and Energy Benefits of the Maine Biomass Industry. Known as Resolve 2015, chapter 85, the legislation established a study commission to examine the state's biomass energy resources, as well as public policy and economic proposals to create and maintain a sustainable future for the industry.

The Commission to Study the Economic, Environmental and Energy Benefits of the Maine Biomass Industry holds its first meeting tomorrow.  According to the agenda published for the first meeting, following introductions and a review of the resolve itself, the group will hear presentations from and hold discussion with a variety of people interested in biomass.  Presenters on the agenda include a Commissioner of the Maine Public Utilities Commission, the state's Public Advocate, and the executive director of the Efficiency Maine Trust.  Other speakers represent loggers, the wood pellet fuel industry, users of biomass energy fuels, the pulp and paper industry, and woodlot owners.  The agenda states that the meeting will also include a public comment period.

According to the agenda, possible future meeting dates for the Maine biomass commission include August 16 and August 30, 2016.

LIPA Deepwater offshore wind decision delayed

Tuesday, July 26, 2016

Long Island Power Authority has postponed a meeting of its trustees at which an offshore wind project was expected to be up for approval, after a state energy agency asked for delay to align the process with the expected release of new state energy policy documents.

Long Island Power Authority, or LIPA, is a municipal subdivision of the State of New York. It owns the retail electric transmission and distribution system (T&D) on Long Island, and oversees electric service provided by PSEG Long Island over those assets.

In 2015, PSEG Long Island issued a request for proposals for local resources to serve the South Fork areas of Long Island.  In response, offshore wind developer Deepwater Wind has proposed to supply capacity and renewable energy from the 90 megawatt, 15-turbine Deepwater ONE – South Fork offshore wind project, along with 15 megawatts of onshore lithium ion battery storage.

The Deepwater ONE - South Fork project would be developed in federal waters over the outer continental shelf; in July 2013, Deepwater won the rights to lease sites through the federal Bureau of Ocean Energy Management's first-ever competitive lease auction for offshore wind.  Project power would be delivered to LIPA’s existing substation in East Hampton, so the proposal could serve growing load on the South Fork without adding new transmission lines or fossil power plants.

As reported by the East Hampton Star earlier this month, LIPA has formally recommended to its board that it approve Deepwater's proposal.

But on July 19, 2016, LIPA issued a media advisory that its board meeting scheduled for the next day would be postponed.  The press release stated that LIPA
received a request late this evening by its partner agency NYSERDA (New York State Energy and Research Development Authority) to postpone tomorrow’s consideration of an off-shore wind farm to align the proposed Long Island project with the State’s off-shore wind master plan and the State’s Clean Energy Standard, both of which are scheduled to be released in the next several weeks.
NYSERDA is a public benefit corporation whose mission is to "Advance innovative energy solutions in ways that improve New York's economy and environment."

Governor Cuomo announced the creation of an Offshore Wind Master Plan in his 2016 State of the State address.  It followed his December 2, 2015 decision to direct the state Department of Public Service to design an enact a Clean Energy Standard mandating that 50 percent of all electricity consumed in New York in 2030 come from renewable sources.  Both the offshore wind master plan and the Clean Energy Standard remain under development by the administration.

In light of NYSERDA's request, LIPA postponed its July 20 board meeting.  LIPA's statement states an expectation "to reschedule the meeting after the release of the NYSERDA off-shore wind blueprint."  It closes with a reassurance that, "LIPA remains committed to its renewable energy goals and meeting the energy needs of the South Fork."  Meanwhile, for now Deepwater's proposal remains pending.

Alta, snowmaking pipes and conduit hydro power

Thursday, July 14, 2016

Federal energy regulators have issued Alta Ski Area a written determination that its proposed micro-hydropower project will not be required to be licensed under the Federal Power Act.  If developed, Alta's project would be one of the first to generate electricity from a snowmaking water supply pipeline.

Most grid-connected hydropower projects in the U.S. fall under the Federal Power Act, and generally require a license or exemption from the Federal Energy Regulatory Commission.  The process of securing an original license or exemption for a new project can take years and have high costs.  But under a 2013 law, some so-called "conduit" hydro projects -- using pipelines and other existing manmade water conveyances -- can be developed and operated without a license or exemption.  The Hydropower Regulatory Efficiency Act of 2013 defined criteria for the Commission to declare a project to be a "qualifying conduit hydropower facility," and provided that such facilities are not required to be licensed or exempted from licensing under the Federal Power Act.  Key factors include the use of a non-federally owned, 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.  If the Commission determines that a project qualifies, it can be built and maintained without a FERC license or exemption.

Under the Commission's process for evaluating conduit hydro projects, the developer must file a notice of intent to construct a qualifying conduit hydropower facility.  If the developer's filing demonstrates that the project meets the statutory criteria, the Commission will issue a notice of its preliminary decision that the project qualifies.  Following a 45-day period within which others may contest the determination, assuming no adverse facts are uncovered, the Commission issues a letter constituting its written determination that the proposed project meets the qualifying conduit hydropower facility criteria.

Alta's course before the Federal Energy Regulatory Commission followed this trail.  In May 2016, Alta filed its notice of intent to construct the Alta Micro-Hydro Project.  That notice and a supplemental filing described a project to tap the existing underground 6-inch-diameter snowmaking water supply pipeline delivering water from Cecret Lake to the Wildcat Pump House.  Parallel to that pipeline, Alta would add a new powerhouse with a 75-kilowatt turbine/generating unit.  Later that month, Commission staff issued a public notice that preliminarily determined that the project met the statutory criteria.  After the 45-day contest period, during which no interventions or comments were filed, in July the Commission issued Alta a written determination that the Alta Micro-Hydro Project meets the qualifying criteria under section 30(a) of the Federal Power Act, and is not required to be licensed under Part I of that law.

The Commission's letter reminds Alta that qualifying conduit hydropower facilities remain subject to other applicable federal, state, and local laws and regulations.  But the ability to develop a conduit hydropower project without requiring a license from the FERC will ease the project's regulatory path.  So far, most projects that have qualified for the conduit hydropower program have been proposed by water districts.  But as ski areas seek to align their operations with sustainability goals, adding low-impact renewable electricity generation may make sense for some.  If Alta's micro-hydro project is successful, other ski areas with existing snowmaking or other water infrastructure over a sufficient vertical drop may follow suit by developing their own conduit hydropower projects.

Maine tidal project preliminary permit issued

Tuesday, July 12, 2016

A tidal energy developer has been granted a preliminary permit to study a proposed project in Western Passage, near the city of Eastport, Maine.

Under the Federal Power Act, most grid-connected tidal power projects require licensing by the Federal Energy Regulatory Commission.  Section 4(f) of the Federal Power Act authorizes the Commission  to issue preliminary permits to allow prospective applicants for a hydropower license time to secure the data and perform the acts required to prepare a license application.  A preliminary permit preserves the holder's right to have first priority in applying for a license for the project being studied.

On December 4, 2015, ORPC Maine, LLC applied for a preliminary permit to study the feasibility of the proposed Western Passage Tidal Energy Project No. 14743.  As described in that application, the project would include fifteen of ORPC's proprietary 500-kilowatt hydrokinetic marine turbine-generator units for a combined capacity of 7.5 megawatts, along with anchoring and mooring systems, and transmission lines running ashore to an existing distribution line.  The materials describe an estimated average annual generation of 2.6 to 3.53 gigawatt-hours.

The Commission granted that preliminary permit by an order dated July 13, 2016.  In that order, the Commission addressed comments filed by the Maine Department of Environmental Protection, the U.S. Department of the Interior, the Passamaquoddy Tribe, and an individual.

In its comments, the tribe raised concerns over what the Commission calls "site banking".  As described by the Commission, the essence of its policy against site banking is that "an entity that is unwilling or unable to develop a site should not be permitted to maintain the exclusive right to develop it."  In some cases, the Commission invokes its policy against site banking to deny applications for successive preliminary permits.

The tribe questioned whether ORPC Maine should be granted a new preliminary permit when it has held two prior preliminary permits for the site of the proposed Western Passage Project -- the first issued in 2007, and a successive permit in 2011 -- without ever filing a development application. 

But in ORPC's case, the Commission noted that the project site has been unencumbered by a permit since ORPC's most recent permit expired in 2013, and that no other entity has filed a preliminary permit or development application for the site.  The Commission concluded that "a sufficient amount of time has passed for any other entity interested in developing the Western Passage Project site to have filed a preliminary permit or development application for the site and none has done so. Consequently, issuing a permit at this time to ORPC Maine for this site would not contribute to site banking."

ISONE External Market Monitor report 2015

Monday, July 11, 2016

A report by the New England electricity market's external monitor has found that "the markets performed competitively in 2015."

ISO New England operates wholesale electricity markets covering most of New England.  It employs two independent market monitors -- one internal to ISO-NE, one a hired external consultant -- to regularly review, analyze, and report on market results, and offer recommendations on market improvements.

Potomac Economics serves as the External Market Monitor for ISO-NE. In this role, it is charged with evaluating the competitive performance, design, and operation of the wholesale electricity markets operated by ISO-NE.  Last month, the external market monitor released its "2015 Assessment of the ISO New England Electricity Markets" (102-page PDF), presenting its perspective on the New England electricity markets.

Among other findings, the report notes that energy market trends "have been dominated by reductions in fuel prices over the last two years.  In particular, from 2014 to 2015:
  • Natural gas prices declined more than 40 percent, falling to multi -year lows in mid -2015 largely because of higher shale production from the Marcellus and Utica regions; and
  • Fuel oil prices fell by more than 35 percent because of increased global supply, and world liquefied natural gas (LNG) prices have fallen similarly. These reductions helped limit the increase in natural gas prices during tight gas supply conditions in the winter. 
The report notes that as a result, energy prices dropped 35 percent over the same time.  According to the external market monitor, "The strong relationship between energy and natural gas prices indicated by these results is expected in a well-functioning, competitive market. Natural gas-fired resources were the marginal source of supply in most intervals in 2015 and competition compels suppliers submit offers consistent with their marginal costs, most of which are resources’ fuel costs."

ISO New England's internal market monitor released its 2015 Annual Markets Report earlier this year.  That report similarly found that overall, "the ISO New England capacity, energy, and ancillary service markets performed well in 2015."

Maine biomass commission to meet

Thursday, July 7, 2016

A commission charged by the Maine legislature to study the state's biomass energy industry will hold its first meeting next month.  The study committee's work will result in a report to the legislature, and could include recommended changes to state law.

The Maine State House.

At the end of its 2016 session, the Maine legislature enacted a resolve establishing the Commission to Study the Economic, Environmental and Energy Benefits of the Maine Biomass Industry.  The resolve directed the commission to:
1. Review and evaluate the economic, environmental and energy benefits of Maine's biomass resources, as well as public policy and economic proposals to create and maintain a sustainable future for the Maine biomass industry;
2. Consider the interconnection of economic markets for biomass and forest products and the energy policy of the State;
3. Consider whether the environmental, economic and energy benefits of biomass support updating the State's energy policy to strengthen and increase the role that biomass and the forest products industry play throughout the State;
4. Consider the costs of implementing any recommendations and the effect of leaving current policies in place; and
5. Examine any other issues to further the purposes of the study. 
The Maine biomass commission has now been formed, and has scheduled its first meeting for August 2, 2016.  As prescribed by the resolve, its membership includes a mix of legislators and others interested in the state's biomass energy policy.

The resolve directed the biomass study commission to submit a report and any suggested implementing legislation for committee consideration by December 6, 2016.

Biomass was a hot topic in the past legislative session.  On a separate track, this spring the Maine legislature enacted a law establishing a long-term contracting program for biomass-fueled power plants.  The Maine Public Utilities Commission has issued a request for proposals under that program, with contract proposals due on or before July 29, 2016.

FERC Order 826 increases penalty power

Tuesday, July 5, 2016

Acting under a 2015 law, the Federal Energy Regulatory Commission has released an interim final rule increasing the maximum civil monetary penalties that it can assess for violations of statutes, rules, and orders within the Commission’ s jurisdiction.  FERC Order No. 826 effectively raises the Commission's maximum penalty authority by nearly 20 percent, to $1,193,970.

FERC, along with some other federal agencies, is authorized by statute to impose civil monetary penalties for violations of Federal law and regulations.  In some cases, the maximum penalty is set and specified in dollars.  But the 1990 enactment by Congress of the Federal Civil Penalties Inflation Adjustment Act established a mechanism to allow for regular adjustment for inflation of civil monetary penalties, primarily to support enforcement and maintain the deterrent effect of civil monetary penalties.

Congress revamped that mechanism last year by enacting the Federal Civil Penalties Inflation Adjustment Act Improvements Act (FCPIA) of 2015.  The FCPIA of 2015 amends the 1990 law, requiring federal agencies to adjust the level of civil monetary penalties through rulemaking to reflect inflation in order to maintain the deterrent effect on regulated entities.

Specifically, the 2015 adjustment act requires the head of each federal agency to issue an “interim final rule” by July 1, 2016 adjusting for inflation each civil monetary penalty provided by law within the agency’s jurisdiction.  The process is driven by changes in the U.S. Department of Labor’s Consumer Price Index for all-urban consumers (CPI-U), relative to the baseline used the last time the penalties were set.  After a "catch-up" round when the penalties are initially adjusted under the 2015 law, the law requires agencies to update penalty amounts on an annual basis every January 15.

In response, on June 29, the Federal Energy Regulatory Commission issued Order No. 826.  In Order 826, the FERC noted the previous maximum civil monetary penalty authority of up to $1,000,000 per violation, per day under section 316A(b) of the Federal Power Act.  The Commission then found that inflation during the relevant period -- the ten years from October 2005 through October 2015 -- inflation was 19.397 percent.  Accordingly, the Commission increased the Commission's maximum penalty authority to $1,193,970.

In Order No. 826, FERC also adjusted its maximum civil monetary penalties for other violations, including violations of Sections 31(c) and 315(a) of the Federal Power Act, Section 22 of the Natural Gas Act, and sections of the Natural Gas Policy Act of 1978 and the Interstate Commerce Act.

The regulation is effective upon its publication in the Federal Register.

NH net metering under review

Friday, July 1, 2016

New Hampshire utility regulators have paused their review of a utility’s proposed changes to rates for customers with solar and other distributed energy resources, pending a more holistic review of the state’s net metering policy. Interest now focuses on Docket DE 16-576, in which the Commission may develop new alternative net metering tariffs or other regulatory mechanisms applicable to customer-sited generation.

Under New Hampshire law, the net energy metering section of the Limited Electrical Energy Producers Act, each electric distribution utility must make standard tariffs providing for net energy metering available to eligible customer-generators in accordance Public Utilities Commission regulation.

On April 29, 2016, distribution company Unitil Energy Systems, Inc. (Unitil) filed a petition to the New Hampshire Public Utilities Commission seeking authority to, among other things, implement new permanent delivery rates for distribution service, beginning June 1, 2016. Among Unitil’s proposed changes was a new tariff schedule for Domestic Distributed Energy Resources, called Schedule DDER, applicable to certain residential customers with renewable distributed generation systems installed behind the retail meter. If adopted, it would change how Unitil’s customers may net meter solar panels and other eligible distributed generation.

Changes to net metering policy can be controversial.  Consumers and solar advocates typically support net metering as a key incentive for solar project development, even if it might undercompensate consumers relative to the value of solar.  But some utilities oppose net metering, arguing that it hurts their revenues or shifts costs to customers without solar panels.  Debate over the issue led the New Hampshire legislature to enact a net metering bill, House Bill 1116, earlier this year. Signed by Governor Hassan on May 2, 2016, House Bill 1116 amended several provisions of RSA 362-A:9.

Among the new statutory language is new paragraph XVI, requiring the Commission, within a ten month period, to initiate and conclude a proceeding to develop new alternative net metering tariffs, which may include other regulatory mechanisms and tariffs, taking into consideration a number of specified factors deemed relevant to such development. By Order of Notice issued on May 19, 2016, the Commission opened Docket DE 16-576 to conduct this holistic review of net metering.  That case remains ongoing.

Given the overlap between the holistic net metering case and Unitil’s proposed Schedule DDER, on June 9, the New Hampshire Public Utilities Commission issued an order suspending the investigation of, and staying any litigation regarding, Unitil’s proposed tariff schedule. In its June 9 order suspending the investigation, the Commission concluded that “it it would be inconsistent with the intent of HB 1116 and would represent an inefficient allocation of limited Staff, stakeholder, and Unitil ratepayer resources to address rate design proposals directly affecting net-metered customer-generators in this proceeding as well as in Docket DE 16-576.”

In the Commission’s words, it initiated Docket DE 16-576 based on the legislative mandate “to conduct a proceeding involving all regulated electric distribution utilities to develop new alternative net metering tariffs, which may include other regulatory mechanisms.” Noting that Schedule DDER is effectively a net metering tariff, the Commission found that separately reviewing, evaluating, and litigating Schedule DDER in both the Unitil docket and Docket DE 16-576 would impose additional burdens on the limited resources of Staff and its consultant, as well as on those of other parties and stakeholders, and “could result in conflicting schedules, redundant discovery, and potentially inconsistent results in the separate proceedings.”

The Commission noted that under the HB 1116 amendments to the net metering law, “net metering will continue indefinitely and without limit, unless and until otherwise determined by the Commission in the proceeding we have opened as Docket DE 16-576… In effect, customer -generators will continue to participate in net metering under RSA 362-A:9 even in excess of the 100 megawatt “cap,” but those above this statutory limit ultimately will be subject to the new alternative net metering tariffs approved by the Commission in Docket DE 16-576.”

Accordingly, the Commission placed the suspension and stay of the Unitil case in effect until the completion of Docket DE 16-576.  The net metering review in that case remains pending, with a schedule set through the coming winter.

Hydro license transfers and fitness

Thursday, June 30, 2016

U.S. hydropower regulators have approved the transfer of the license for an Idaho hydroelectric project, despite an argument that the transferee is not fit to operate the project. At issue is the Smith Creek Project, No. 8436, located on Smith Creek in the Panhandle National Forest in Idaho.

The Federal Energy Regulatory Commission issued a 50-year license for the project in 1987, which was transferred to Eugene Water & Electric Board in 2000. Earlier this year, EWEB applied to the Commission for a transfer of the Smith Creek project license to Smith Creek Hydro, LLCAmerican Whitewater opposed the transfer, raising arguments including that Smith Creek did not meet the Commission's "fitness standard".

On June 23, 2016, the Commission issued an order approving the Smith Creek license transfer.  In that order, the Commission noted that while Section 8 of the Federal Power Act governs license transfers, it does not articulate a standard for approving a transfer application.  Under Commission precedent, a transfer may be approved on a showing that the transferee is qualified to hold the license and operate the project, and that a transfer is in the public interest.  According to the Commission, an applicant's fitness, including its prior performance as licensee, is a relevant factor to be considered in a licensing decision.  In performing a fitness inquiry, the Commission typically takes a broad look at conduct by affiliated entities: "The Commission does not separate the identities of partners and partnerships where matters of fitness to receive a license are concerned. In fact, the Commission has consistently examined the conduct of the persons controlling and directing licensees and exemptees in this context."

In the Smith Creek case, American Whitewater argued that "Smith Creek is unfit to hold a license based on compliance issues at the Power Creek Project No. 11243, the Cascade Creek Project No. 12495, and the unlicensed Electron Hydroelectric Project."  The group pointed to a fatality by avalanche during the Power Creek project construction, the fact that the Cascade Creek project was issued preliminary permits but was never licensed, and that litigation was pending relating to the alleged Endangered Species Act violations at the Electron project.

While the Commission does not list Smith Creek as a licensee on any of these projects, it did consider these allegations relating to entities now or formerly affiliated with Smith Creek.  But the Commission declined to find a lack of fitness of the transferee.  It distinguished the issues raised by American Whitewater, noted the transferee's responsiveness to Commission staff inquiries, and overall compliance with the Commission.  The Commission described denial of a license application on the ground of lack of fitness as "a strong sanction, particularly since the Commission has the means to secure license compliance, including civil penalties."  It therefore approved the Smith Creek license transfer.

Whitestone hydrokinetic license surrendered

Wednesday, June 29, 2016

Despite efforts to offer a streamlined regulatory path for some demonstration hydropower projects, earlier this year the holder of a hydrokinetic pilot project license for a project proposed for the Tanana River in Alaska surrendered its license due to an inability to find financing. The case of the Whitestone Poncelet River-In-Stream-Energy-Conversion (RISEC) Pilot Project No. 13305 illustrates the Federal Energy Regulatory Commission’s hydrokinetic pilot project licensing process, the difficulties of testing and developing new hydropower technologies, and how the Commission handles pilot license surrender.

Whitestone Power and Communications, an assumed name of the Whitestone Community Association, had proposed the project as a 100-kilowatt demonstration of its proprietary hydrokinetic prototype technology. It was to be located on the Tanana River at its confluence with the Delta River, about 90 miles southeast of Fairbanks. A Poncelet undershot waterwheel and generator unit mounted on a floating platform, seasonally installed and moored to a cliff. Power produced would be supplied to the Golden Valley Electric Association grid.

The Federal Energy Regulatory Commission granted WPC a five-year pilot project license on October 19, 2012. In processing WPC’s application, the Commission used a hydrokinetic pilot project licensing process derived from from its Integrated Licensing Process. According to the Commission, the hydrokinetic pilot project licensing process was designed “to meet the needs of entities, such as Whitestone, who are interested in testing new hydropower technologies while minimizing the risk of adverse environmental impacts.” The Commission describes the goal of the pilot licensing process as “to allow developers to test new hydrokinetic technologies, to determine appropriate sites for these technologies, and to confirm the technology’s environmental and other effects without compromising the Commission’s oversight of the projects and limiting agency and stakeholder input.”

As outlined in a white paper prepared by Commission staff, a hydrokinetic pilot project should be: (1) small; (2) short term; (3) located in environmentally nonsensitive areas; (4) removable and able to be shut down on short notice; (5) removed, with the site restored, before the end of the license term (unless a new license is granted); and (6) initiated by a draft application in a form sufficient to support environmental analysis. After finding the WPC project met these standards, the Commission issued it a license in 2012. Article 301 of the license required the licensee to commence construction of the project works within two years from license issuance, i.e., by October 19, 2014.

Despite winning a license, the project was never built. In 2014, WPC asked for and received a two-year extension of the start-of-construction deadline, “due to unforeseen setbacks in obtaining the necessary financing to begin construction.” But in that order, the Commission reminded the licensee that, pursuant to section 13 of the Federal Power Act, the deadline for starting construction may only be extended once, for a period not exceeding two additional years. Therefore, the Commission noted its inability to grant any further extensions of time for the commencement of project construction.

But in September 2015 WPC applied to the Commission for surrender of its license. In its surrender application, WPC stated that it was unable to obtain the funding necessary to construct the project and had not constructed any project facilities.

In April 2016, the Commission granted WPC's surrender application without condition, citing the facts that the licensee had not commenced construction and that the project site remained unaltered.

The Whitestone project was among the first to use the Commission’s hydrokinetic pilot project licensing process. But despite receiving expedited regulatory treatment in licensing, financing challenges led the licensee to surrender its license before the project could be constructed. Some other proposed hydrokinetic projects have been canceled or put on hold, following licensure; earlier this year, the Commission accepted license surrender for a Washington tidal power project licensed as a 10-year pilot project, after the public utility district proposing it found it economically infeasible. Another project -- an ocean wave energy farm off the Oregon coast -- surrendered its pilot license
 in 2014.

Edgartown's Muskeget tidal project faces questions

Tuesday, June 28, 2016

A municipal tidal power project proposed for the Massachusetts island of Martha's Vineyard faces federal deadlines if its licensing process is to continue.  The Muskeget Channel Tidal Energy Project, proposed by the Town of Edgartown, is seeking a pilot project license from the Federal Energy Regulatory Commission -- but faces questions from Commission staff.

On February 1, 2011, the Town of Edgartown filed, pursuant to the Commission’s pilot licensing procedures, a draft license application for the proposed Muskeget Channel Tidal Energy Project.  The project would feature an array of 14 marine hydrokinetic tidal turbines, with a commercial generating capacity of 5 megawatts or less.

But that license application remains incomplete.  On April 1, 2011, Commission staff issued a letter requesting that Edgartown provide additional information, including details about the proposed project and multiple plans, drawings, and reports.  Over the ensuing years, Edgartown filed some responsive information, but according to the Commission, Edgartown did not file the remaining information by the deadline or provide a schedule indicating when the information would be filed after the deadline was missed.

Over two years after the deadline, on April 21, 2016, Commission staff issued a letter requiring Edgartown to show cause, within 30 days, why Commission staff should not terminate the prefiling licensing process for the project.  According to the Commission, Edgartown did not respond, but Congressman William Keating asked the Commission to extend the show cause deadline until the Massachusetts Clean Energy Commission decides whether to award the project a grant.

In a June 2 letter, Commission staff directed Edgartown to, within 30 days, provide a schedule specifying when it will file with the Commission each of the outstanding items requested in Commission staff’s April 1, 2011 letter.  The letter says, "Upon receipt of this information, Commission staff will make a determination on how to proceed with the incomplete application for the Muskeget Channel Tidal Energy Project."  For now, the prelicensing process for the Muskeget tidal project remains pending.

BOEM Call for Hawaii offshore wind interest

Monday, June 27, 2016

U.S. ocean energy managers have asked for information to evaluate industry interest in leasing sites offshore Hawaii for commercial offshore wind development.

Under U.S. law, the Bureau of Ocean Energy Management (BOEM) is charged with managing energy activities on the federally controlled Outer Continental Shelf.  On June 22, Secretary of the Interior Sally Jewell announced that BOEM issued a Call for Information and Nominations for waters off Hawaii. The Call is designed to gauge the offshore wind industry's interest in acquiring commercial wind leases in two areas spanning approximately 485,000 acres of submerged lands in federal waters offshore Oahu. One parcel lies generally south of the island, while the other is to its northwest.

BOEM also published in the Federal Register a Notice of Intent (NOI) to Prepare an Environmental Assessment (EA) for the Hawaii Call area. The purpose of the NOI is to solicit public comment for determining issues and alternatives to be analyzed in the Environmental Assessment.

BOEM is also considering three unsolicited requests for site leases off Hawaii for floating offshore wind projects: two lease requests from AW Hawaii Wind, LLC (AWH), the AWH Oahu Northwest Project and the AWH Oahu South Project; and one from Progression Hawaii Offshore Wind, Inc. (Progression), the Progression South Coast of Oahu Project.

In other areas, BOEM has used Calls to shape the designation of Wind Energy Areas and ultimately the sale by competitive auction of leasing rights for commercial offshore wind development.  To date, BOEM’s offshore wind program has identified wind energy areas in federal waters off seven Atlantic states (including an area off New York designated in March) and awarded 11 commercial wind energy leases off that coast, including nine leases through competitive lease sales that generated about $16 million in winning bids.  Earlier this month, BOEM announced a proposed sale of leases for sites offshore New York.

FERC says Nicatous microhydro doesn't need license

Friday, June 24, 2016

Federal energy regulators have ruled that a micro-hydroelectric project proposed by a remote Maine sporting camp does not require licensing under the Federal Power Act. The Nicatous case illustrates one expedited regulatory path for off-grid micro-hydropower projects.

Nicatous Lake Lodge and Cabins, LLC has proposed the Nicatous Lodge Micro Hydroelectric Project. The one-kilowatt project would be located on Nicatous Stream in Maine, and would supply electricity to an off-grid sporting camp currently powered by a diesel generator.

The camp owner filed a Declaration of Intention concerning the proposed project on March 18, 2016. The Commission issued a notice of the Declaration of Intention on May 10, setting a 30-day public comment period.

On June 21, 2016, Commission staff issued an order ruling on the Declaration of Intention and finding that licensing is not required. As articulated by the Commission in that order, pursuant to section 23(b)(1) of the Federal Power Act, a non-federal hydroelectric project must be licensed (unless it has a still-valid pre-1920 federal permit) if it:
(a) is located on a navigable water of the United States;
(b) occupies lands or reservations of the United States;
(c) utilizes surplus water or waterpower from a government dam; or
(d) is located on a stream over which Congress has Commerce clause jurisdiction, is constructed or modified on or after August 26, 1935, and affects the interests of interstate or foreign commerce.
In this case, the order found “insufficient evidence to determine whether Nicatous Stream is navigable,” but determined that the stream is a headwater of the navigable Penobscot River, and thus “the project would be located on a Commerce Clause stream and also would be constructed after August 26, 1935.”

Crucially, the order found that the off-grid nature of the project – its lack of an interconnection to the interstate electric grid – meant that licensing was not required: “The project would not affect interstate commerce because it would not displace grid power nor would it connect to an interstate grid. Therefore, the project does not require licensing under section 23(b)(1) of the FPA.”

While licenses are available for hydropower projects under the Federal Power Act, the regulatory process for licensing is relatively lengthy and may require costly studies. A hydropower project that can be developed without a license thus has some advantages.

The Commission’s order includes a note emphasizing the relevance of a grid connection in licensing determinations for hydropower projects: “If the Nicatous Lodge property is connected to the interstate grid in the future or if other evidence sufficient to require licensing is found, section 23(b)(1) would require licensing. Under section 4(g) of the FPA, the project owner could then be required to apply for a license.” This note is consistent with Commission precedent finding that the existence or absence of a grid tie for a proposed microhydro project can determine whether hydropower licensing is required.

Canada NEB starts Energy East pipeline review

Canada's National Energy Board has ruled that the applications are complete for the Energy East Pipeline Project and a related gas project.  This determination starts the NEB's review process, under which the Board must issue its recommendations to the Minister of Natural Resources within 21 months.

The National Energy Board is an independent federal regulator of several parts of Canada's energy industry, including the regulation of pipelines, energy development and trade in the Canadian public interest.

As envisioned by proponents TransCanada and Energy East Pipeline Ltd., Energy East would be a 4,500-kilometer pipeline that will transport approximately 1.1 million barrels of crude oil per day from Alberta and Saskatchewan to the refineries of Eastern Canada and a marine terminal in New Brunswick.  Some existing natural gas pipeline would be converted to oil transportation pipeline, while other facilities would be newly built.  The project is motivated in part by a relative surplus of Western Canadian crude production, with relatively few ways to ship that crude to refineries or ports.

The related Eastern Mainline Project entails about 279 kilometers of new gas pipeline and related components, designed to let TransCanada continue to supply gas after the proposed transfer of certain Canadian Mainline facilities to Energy East Pipeline Ltd. for conversion to crude oil service.

On June 16, 2016, the National Energy Board announced its determination that due to the interconnections between the applications, the Energy East and Eastern Mainline projects are more effectively assessed within a single hearing process, with one record, reviewed by one Panel of Board Members.   It also deemed the applications complete to proceed to assessment and a public hearing, starting the 21-month review process.

The Panel must submit a report to the Minister of Natural Resources recommending whether or not the projects should proceed, or on what conditions. This report is due no later than March 16, 2018.  According to the NEB, the process will include hearings, panel sessions, and assessments of the upstream greenhouse gas emissions associated with the project.