Massachusetts energy storage report

Friday, September 23, 2016

A Massachusetts state energy office has issued a report finding that Massachusetts has the potential to develop for 600 MW of energy storage by 2025, which could lower costs, reduce carbon emissions, and improve grid reliability. Legislation earlier this year authorized the creation of an energy storage procurement target; the Department of Energy Resource’s State of Charge report could lead to further policy changes supportive of storage.

While electricity has traditionally been challenging to store efficiently, advanced energy storage technologies – such as batteries, flywheels, thermal and compressed air technologies – now allow utilities and consumers to store and release energy as needed. Last year, the Baker-Polito administration launched an Energy Storage Initiative to advance the energy storage segment of the Massachusetts clean energy industry.

This summer, the Massachusetts legislature enacted a broad energy diversification law, authorizing among other things the creation of an energy storage procurement target, if the Department of Energy Resources deems such a target prudent.  Section 15 of H.4568 requires the Department of Energy Resources to determine, by December 31, 2016, whether to set “appropriate targets for electric companies to procure viable and cost-effective energy storage systems” to be achieved by January 1, 2020. If the Department finds it appropriate to adopt procurement targets, the law requires it to do so by July 1, 2017, with reevaluations of the procurement targets not less than every 3 years.

Meanwhile, on September 16, 2016, the administration released its State of Charge report. The report found that energy storage could yield significant cost savings for Massachusetts ratepayers, reduce the impacts of peak demand on the state’s energy infrastructure, and enable improved integration of renewable resources and reduced carbon emissions.

The report recommends policy changes, ranging from regional coordination on energy storage, broadening the Alternative Portfolio Standard (APS) with respect to advanced energy storage, to using energy storage in existing energy efficiency programs or as a utility grid modernization asset, and seeking “renewables plus storage” contracts in future long-term clean energy procurements.

According to the report, adopting these recommendations could yield 600 MW of advanced energy storage technologies deployed on the Massachusetts grid by 2025, with projected ratepayer cost savings of over $800 million and approximately 350,000 metric tons reduction in greenhouse emissions over a 10 year time span.

The Department of Energy Resources will now hold a stakeholder engagement process relating to energy storage, starting with a meeting scheduled for September 27. DOER is expected to determine whether Massachusetts should establish an energy storage procurement target before the end of 2016.


NY blueprint for offshore wind master plan

Monday, September 19, 2016

A New York state energy office has released its Blueprint for the New York State Offshore Wind Master Plan.

The New York State Energy Research and Development Authority, known as NYSERDA, promotes energy efficiency and the use of renewable energy sources.  It mission is to advance innovative energy solutions in ways that improve New York's economy and environment.

New York recently adopted a Clean Energy Standard, which will require that 50% of New York State’s electricity come from renewable resources by 2030.  NYSERDA has described offshore wind as playing "a critical role in turning this aggressive goal into a reality."  NYSERDA has been tasked with leading the state's development of a master plan for New York offshore wind development.

On September 15, 2016, NYSERDA released its Blueprint for the New York State Offshore Wind Master Plan.  The Blueprint presents NYSERDA’s vision of the process, steps, and timeline to develop the master plan.  While the Master Plan's release is scheduled for 2017, NYSERDA noted that releasing an initial Blueprint serves to outline New York State’s comprehensive offshore wind strategy and advance the State’s Reforming the Energy Vision (REV) strategy to build a cleaner, more resilient, and affordable energy system for all New Yorkers.

NYSERDA has also expressed interest in bidding in an auction to be held by the U.S. Bureau of Ocean Energy Management, for the right to lease offshore wind development sites in federal waters over the Outer Continental Shelf.  The 81,000-acre lease area is located south of Long Island, off the Rockaway Peninsula.  BOEM is expected to hold the lease sale later this year.

NHPUC considers PSNH divestiture auction format

Thursday, September 15, 2016

As the New Hampshire Public Utilities Commission prepares for an auction of the state's largest utility’s generating assets, its auction advisor J.P. Morgan has recommended a broad public auction of the assets, using a two phase structure.

At issue are the generation facilities owned by Public Service Company of New Hampshire d/b/a Eversource Energy (Eversource).  Following a legislative finding that divestiture is in the public interest at the present time, on July 1, 2016, the Commission issued Order No. 25,920 approving the 2015 Public Service Company of New Hampshire Restructuring and Rate Stabilization Agreement and the Partial Litigation Settlement Agreement. Those settlement agreements called for the Commission to open an expedited proceeding to oversee the process of auctioning the Eversource generation facilities.

On September 7, 2016, the Commission opened a proceeding to implement the divestiture process for the generation facilities of Eversource as approved in Order 25,920. In its Order of Notice opening the auction process docket, the Commission noted a primary objective of obtaining the highest possible sale value of the generation facilities in order to minimize the level of stranded costs ultimately paid by Eversource customers. It also noted a secondary objective, to the extent not inconsistent with the primary objective, to accommodate the participation of municipalities that host generation assets and to fairly allocate among individual assets the sale price of any assets that are sold as a group.

A report recently filed in the docket by Commission staff presents recommendations from its advisor J.P. Morgan on the auction design and process.  According to the report, these recommendations were designed to maximize the overall value of the transaction and the likelihood of the successful sale of each asset.

In Phase I, Eversource, the Commission, and its advisor would develop of a list of potential bidders who would be invited to respond to a Request for Qualifications (RFQ). Parties satisfying the requirements of the RFQ would be asked to execute a confidentiality agreement, after which they could review a Confidential Information Memorandum. This document would provide certain limited information about the assets, to let bidders develop a preliminary non-binding indication of interest. The report suggests this phase could take six weeks from launch to the submission of preliminary, non-binding proposals – potentially spanning from November 2016 into January 2017.

In Phase II, bidder indications of interest would be used to identify potential bidders likely to transact on terms most favorable to the seller. These “second round” bidders would have access to full due diligence. The report suggests allowing about 8 weeks for Phase II parties to conduct due diligence, mark up a draft purchase and sale agreement, and submit a final, binding proposal. The report suggests Phase II might run from January 2017 into March 2017.

Following the submission of final bids, the report suggests that the Commission select one or two parties per asset or group of assets for final negotiations, depending on the level of interest.

Written comments on the auction design and process are due by September 30, 2016. The Commission has said that the proceeding will culminate in a decision on auction results, and if necessary, a financing order authorizing securitization of stranded costs and stranded cost rates.

Kauai small conduit hydro exemption terminated

Wednesday, September 14, 2016

U.S. hydropower regulators have terminated an exemption from licensing for a small conduit hydroelectric facility proposed for development in Hawaii.

The case concerns the 5.3-megawatt Puu Lua Hydropower Project No. 14069.  Proposed  by Konohiki Hydro Power, LLC, the project would have been located on the Kōkeʻe Ditch Irrigation System on state-owned land on the island of Kauai.  As authorized by the Federal Energy Regulatory Commission in its 2012 order granting the Puu Lua project an exemption from the licensing requirements of Part I of the Federal Power Act, the project would have included two developments with powerhouses.

In granting the Puu Lua project's exemption, the Commission included provisions allowing it to terminate the exemption if certain conditions are not satisfied.  Article 8 of the exemption states the Commission may terminate the exemption if actual construction of any project works has not begun within two years or has not been completed within four years from the issuance date of the exemption.  In 2014, the exemptee successfully won a two-year extension to commence project construction, until April 12, 2016.  But according to the Commission's August 31, 2016 Order Terminating Exemption (Conduit), the developer failed to commence construction of the Puu Lua Hydropower Project prior to the deadline.

In addition to the construction deadlines, the exemption also included an article providing that the Commission may terminate the exemption "if, at any time, the exemptee does not hold sufficient property rights in the land or project works necessary to develop, maintain, and operate the project." This too proved problematic, as in November 2015 the State of Hawaii notified the Commission that the exemptee’s rights to use the property were cancelled effective January 1, 2015.  After the exemptee did not respond to a Commission request for documentation of its rights, Commission staff issued a notice of probable termination of the exemption for failure to commence project construction by the April 12, 2016 deadline, and for failure to possess sufficient property rights.

Ultimately, on August 31, 2016, the Commission issued its order terminating the project's exemption, "for failure to commence construction and maintain sufficient property rights."

U.S., China ratify Paris climate agreement

Tuesday, September 13, 2016

The U.S. has formally ratified the global climate change agreement reached in Paris last year, as has China.  This moves the Paris climate agreement closer to legal effectiveness -- but more nations must accept the pact before it can enter into force.

At issue is the Paris Agreement, an agreement brokered at the 21st Conference of the Parties of the United Nations Framework Convention on Climate Change (UNFCCC).  In December 2015, over 190 countries meeting under UNFCCC adopted the Paris Agreement agreement to limit global warming.  The Paris Agreement describes climate change as an "urgent threat" and a "common concern of humankind."  The agreement's aim is to strengthen global response to this threat, through a variety of means.  These include the creation of individual national commitments to reduce greenhouse gas emissions, increased adaptation to climate change, and assistance for developing nations.

But the Paris Agreement has not yet taken its full legal force, because it contains a provision limiting its effectiveness until enough nations agree to comply.  As is common for multilateral international agreements, the Paris Agreement calls for parties to express their consent to be bound by the agreement, by depositing instruments of ratification, acceptance, approval or accession with the depositary established by the convention.  In this way, the agreement draws a distinction between Parties -- those signing the Agreement -- and those nations which have deposited their ratification instruments. 

Under its Article 21, the Paris Agreement "shall enter into force on the thirtieth day after the date on which at least 55 Parties to the Convention accounting in total for at least an estimated 55 percent of the total global greenhouse gas emissions have deposited their instruments of ratification, acceptance, approval or accession."  Practically speaking, this means that as new countries submit their ratifications, the convention's secretariat must calculate the total greenhouse gas emissions of Parties that have ratified the Paris Agreement, as a percentage of global greenhouse gas emissions.  Once the 55 percent threshold is hit, the Paris Agreement will become legally effective and operational.  The UNFCCC has said that while it cannot predict when this will occur, "it is conceivable that the Agreement may enter into force before 2020."

On April 22, 2016, the Paris Agreement was opened for signature.  At the opening ceremony, 15 states deposited instruments of ratification.  By September 1, reportedly 24 states accounting for just over 1% of global greenhouse gas emissions had ratified the agreement.

The Paris Agreement's path to effectiveness advanced on September 3, when President Obama announced that the U.S. and China had formally joined the Paris agreement in a ceremony in China.  In recent years, these nations have been among the world's top emitters of carbon dioxide.  As described by the White House, "Both leaders expressed satisfaction with jointly joining the Paris climate agreement and pledged to work together and with other parties to bring the Paris agreement into force as early as possible."  The Obama administration also noted other recent U.S. climate actions taken jointly with China, including support for a proposed amendment to the Montreal Protocol to phase down the consumption and production of hydrofluorocarbons (HFCs) globally, and efforts to address international aviation emissions.

Following the U.S.-China announcement, the convention secretariat announced that as of September 7, 27 states had deposited instruments of ratification, acceptance or approval accounting in total for 39.08% of the total global greenhouse gas emissions.

US releases new offshore wind strategy

Monday, September 12, 2016

U.S. executive branch agencies have released an updated report presenting a national strategy to facilitate the domestic development of offshore wind energy.  According to the administration, the strategy could enable 86 gigawatts of U.S. offshore wind by 2050.

The new strategy document, "National Offshore Wind Strategy: Facilitating the Development of the Offshore Wind Industry in the United States", was prepared by the U.S. Department of Energy's Wind Energy Technologies Office and the Department of the Interior's Bureau of Ocean Energy Management. It builds on previous efforts, including the first national strategy for offshore wind released in 2011.

Consistent with previous Obama administration approaches, the revised U.S. offshore wind strategy rests on the premise that offshore wind energy can provide significant economic and environmental benefits.  Estimates suggest the nation's total offshore wind energy technical potential is roughly twice as large as our demand for electricity, and almost 80% of U.S. electricity demand is located in coastal states.  Offshore wind provides a low-carbon, fuel-free energy resource; if projects can produce power at low, long-term fixed costs, they can provide a hedge against fossil fuel volatility.

The new U.S. offshore wind strategy is designed to realize these benefits by overcoming challenges in three strategic themes: reducing costs and risks, supporting effective stewardship of U.S waters, and improving market conditions for offshore wind investment:

First, to be competitive in electricity markets, offshore wind costs and U.S.-specific technology risks need to be reduced. Second, environmental and regulatory uncertainties need to be addressed to reduce permitting risks and ensure effective stewardship of the OCS. Third, to increase understanding of the benefits of offshore wind to support near-term deployment, the full spectrum of the electricity system and other economic, social, and environmental costs and benefits of offshore wind need to be quantified and communicated to policymakers and stakeholders.
The report further describes seven action areas, and 34 specific actions, that the Energy and Interior Departments can take to support offshore wind development.

As noted in the report's introductory message, "There has never been a more exciting time for offshore wind in the United States."  States and some utilities are increasingly interested in procuring offshore wind energy.  In recent years, BOEM has awarded 11 commercial leases for offshore wind development that could support a total of 14.6 gigawatts of capacity.  Earlier this summer, Deepwater Wind completed construction of its 30-megawatt Block Island wind project, the nation's first offshore commercial wind farm.  That project is expected to enter commercial operation later this year.

FERC's PURPA questions

Friday, September 9, 2016

U.S. energy regulators have invited comments on two issues related to the implementation of the Public Utility Regulatory Policies Act of 1978 (PURPA): its so-called "one-mile rule," and minimum standards for PURPA-purchase contracts.  This opportunity for comment follows a technical conference held earlier this summer.

Congress enacted PURPA to encourage domestic cogeneration and renewable energy production, among other aims.  PURPA established a new class of generating facilities called qualifying facilities (QFs), and gave QFs special rate and regulatory treatment.  Under PURPA, QFs fall into two categories: qualifying small power production facilities and qualifying cogeneration facilities. 

PURPA defines a small power production facility as “a facility which is an eligible solar, wind, waste, or geothermal facility, or a facility which (i) produces electric energy solely by the use, as a primary energy source, of biomass, waste, renewable resources, geothermal resources, or any combination thereof; and (ii) has a power production capacity which, together with any other facilities located at the same site (as determined by the Commission), is not greater than 80 megawatts.”

Under the Commission's so-called "one-mile rule" found in Section 292.204(a) of its regulations, small power production facilities are considered to be at the same site if they are located within one mile of each other, share the same energy resource, and are owned by the same person(s) or its affiliates.  In a September 6, 2016, Notice Inviting Post-Technical Conference Comments, the Commission asked for comments on whether this presumption should be made rebuttable or whether some different spacing requirement should be imposed.

The Commission also asked for comment on the appropriate minimum length of a PURPA purchase contract, or other required contract terms and conditions affecting the development of qualifying facilities (QFs).  To date, the Commission has not required any particular minimum contract length or other minimum contract provisions in PURPA-purchase contracts.

Comments in Docket No. A16-16-000 are due on or before November 7, 2016.

Vermont's new net metering program

Thursday, September 8, 2016

Acting under a 2014 law, this summer Vermont utility regulators established a revised net-metering program to take effect in 2017. In a pair of orders, the Vermont Public Service Board prospectively changed the rules governing net metering of solar panels and other distributed generation facilities.  The result is a revision of Vermont's net metering program.

Vermont defines what it calls “net-metering” as “the process of measuring the difference between the electricity supplied to a utility customer and the electricity supplied by the customer’s generation system during the customer’s billing period."  Under the current net-metering program, most net metering customers receive bill credits of either 19 or 20 cents per kilowatt-hour of energy produced by their system. Net-metering customers may also retain the associated renewable energy credits or RECs, and may choose to sell those RECs, transfer the RECs to the utility, or retire them themselves.

As noted by the Public Service Board, net-metering offers benefits for Vermont and ratepayers. It can provide renewable energy and support state greenhouse gas reduction goals. It can benefit ratepayers by avoiding line-losses, reducing capacity charges, and reducing transmission costs. Net-metering can also create local jobs for installers of net-metering systems.  As a result, distributed generation is booming in Vermont -- mostly in the form of net-metered solar photovoltaic installations. According to the Board, “The explosive growth of net-metering in Vermont— particularly due to the development of large net-metering projects— is a direct testament to how attractive the current net-metering incentives are.” The Board noted that the prior program will lead to the development of about 130 megawatts of net-metering capacity.

While net metering in Vermont has been governed by statute since 1998, that law changed in April 2014 when the state legislature passed Act 99 of 2014. That law required the Board to establish a revised net-metering program, pursuant to criteria and standards defined by the legislature.  Based on facts including the growth rate of net-metered capacity, the Board concluded that the current pace of net-metering program needs to be moderated so as to be sustainable in the long term and to mitigate associated rate impacts.

After study and a report by the Department of Public Service, workshops and opportunities for public comment in 2014 and 2015, on June 30, 2016, the Board issued its Order Adopting A Revised Net-Metering Program Pursuant to Act 99 of 2014.  That order laid out a vision for a revised program to be effective in 2017.  At the same time, the board emphasized that its decision was subject to a reconsideration period of 10 business days, during which time comments may be filed seeking reconsideration of the net-metering program.

The Board received over 100 comments in response. In its August 29 Order on Reconsideration, and an accompanying Attachment A, the Board made further changes to its program. For example, the June 30 order set an annual limit on the growth of net-metering installed capacity, with each year’s incremental limit defined as 4% of the state’s peak capacity. The Board described this provision as one of several “intended to manage the pace of development of net-metering systems in Vermont.” But many commenters argued that a 4% annual limit would create market disruptions and a “rush to the door” as applicants race to secure space within the annual quota.

With reconsideration now over, the Board's June 30 and August 29 orders define the new net-metering program that will take effect next year.  From the perspective of rates and bill credits, the new program adopted by the Board features three valuation components. The value of a credit is the sum of “(1) the applicable blended residential retail rate, (2) any applicable REC adjustor, and (3) any applicable siting adjustor.”

The Board defined the applicable blended residential retail rate as the lowest of three possible rates: (1) if the electric company does not have block pricing, the company’s general retail rate, (2) if an electric company uses block pricing, then a blend of those rates, or (3) the weighted average of the blended residential rates for all Vermont electric companies. Under this approach, the statewide average rate acts as a cap on the value of net-metering credits.

The Board adopted two adjustors – a REC adjustor and a siting adjustor – “to encourage and discourage certain behaviors through monetary incentives and to adjust the overall value of net-metering credits.” These adjustors are added to (or subtracted from) the applicable blended residential rate to yield the value of a credit.

The REC adjustor is designed to capture the value related to the customer retaining the RECs associated with net-metered energy. The Board set the values of the REC adjustors as positive (+3) cents per kWh for customers who transfer RECs to their utility and negative (-3) cents per kWh for customers who do not, for a net 6-cent difference between the total compensation received by customers who choose to retain RECs and customers who elect to transfer RECs. This difference matches the 6-cent alternative compliance price for Vermont’s distributed generation or Tier II standard under Vermont’s renewable energy standard statute.

The Board also adopted siting adjustors “to encourage net-metering customers to select more environmentally friendly sites for new net-metering systems.” The Board said siting adjustors will “encourage the environmentally beneficial siting of net-metering projects and thereby help ensure that such projects are in the public good,” and that siting adjustors will allow for better accounting of the benefits and costs of net-metering. For example, the initial siting adjustors provide greater financial incentives to construct net-metering systems up to 150 kW with limited environmental impacts, such as systems that are located on previously developed areas like roofs and parking lots. The siting adjustors will allow the Board to pace the development of net-metering systems over time.

The new program includes a biennial update process, by which the Board will determine the values of REC adjustors, siting adjustors, the state-wide blended residential rate, and the criteria applicable to different categories of net-metering systems. The Board described this section as designed “to ensure that: (1) the pace of deployment of net-metering systems is consistent with the state’s renewable energy goals, (2) net-metering does not result in undue rate impacts, (3) the program accounts for changes in costs of technology over time, and (4) net-metering does not result in cost shifts between net-metering customers and non-net-metering customers.” The Board may also conduct an update sooner than biennially at its own discretion or upon petition by the Department of Public Service.

The Board exempted pre-existing systems from certain requirements of the revised net-metering program, including non-bypassable charges, for a period of 10 years from the date the system was commissioned.  Pre-existing net-metering systems will continue to receive their existing incentive for that 10-year period, after which the value of a credit will be the applicable residential retail rate, without siting or REC adjustors.  The Board said it provided this exemption "in recognition that these systems were installed by customers who relied on a certain set of financial assumptions when they decided to engage in net-metering—a behavior the state has expressly sought to encourage in support of its renewable energy goals." After the 10-year period provided for in this section expires, customers using pre-existing systems will be required to pay non-bypassable charges.

The new program will be effective on January 1, 2017, unless or until it is superceded by a duly adopted rule.  The Board is expected to file its revised Attachment A with the state Secretary of State as a new proposed rule in due course.

ISO-NE offshore wind economic study

Wednesday, September 7, 2016

Regional electric grid operator ISO New England Inc. has released a report examining the economic impacts of adding significant offshore wind energy into the mainland grid.  Overall, the results project reductions in production costs, energy expense, CO2 emissions, average wholesale electricity prices, and congestion on key regional transmission interfaces, as offshore wind is added to the grid portfolio.  The study also suggests the scale of revenues available to the offshore wind industry from this scale of development.

The report in question is ISO-NE's 2015 Economic Study: Evaluation of Offshore Wind Deployment.  That report, released on September 2, 2016, presents the results of a study requested last year by the Massachusetts Clean Energy Center (CEC), focusing on the economic impact of up to 2,000 megawatts (MW) of offshore wind deployment into the Southeastern Massachusetts/Rhode Island (SEMA/RI) area. 

According to ISO-NE, the results of this study suggest that "offshore wind deployment could bring sizable economic and environmental benefits to New England."  The study found that while results were sensitive to assumptions like transmission constraints, fuel prices, and carbon allowance costs, overall offshore wind deployment would yield economic benefits.  Annual production cost savings would range from $104 million to $807 million depending on the scenario and scale of development,  while annual load-serving entity cost savings would range from $56 million to $491 million.

The study also found that adding offshore wind would reduce annual systemwide carbon dioxide emissions (by between 1,518 kilotons and 4,230 kilotons), because energy produced by offshore wind would mainly offset emission-producing thermal units.

The study also modeled revenues flowing to offshore wind facilities under the various scenarios, ranging a low of $83 million per year for 1,000 MW under the least favorable conditions, to $732 million with 2,000 MW of offshore wind and most favorable conditions.

While the U.S. is not yet home to any commercially operating utility-scale offshore wind project, interest in marine renewable energy resources is booming.  Deepwater Wind's project off Rhode Island's Block Island is expected to come online this year.  Massachusetts has recently enacted legislation calling for utility procurement of 1,600 megawatts of offshore wind; the developer of a project proposed off Massachusetts was recently acquired by a Danish investment fund; and federal efforts remain ongoing to lease sites on the Outer Continental Shelf for commercial offshore wind development.

Federal dams, nonfederal hydro, and preliminary permits

Tuesday, September 6, 2016

Can a hydropower developer obtain a preliminary permit from the Federal Energy Regulatory Commission for a project to be located at a federal dam, where the federal entity owning the dam says it opposes the project?  In a series of recent decisions, the Commission has denied preliminary permits in these circumstances, saying there is no purpose in issuing a preliminary permit.

U.S. federal law generally encourages the development of hydropower at existing dams.  Under sections 4(e) and 4(f) of the Federal Power Act, the Commission has general authority to issue preliminary permits and licenses for hydropower projects located at federal dams and facilities.  There are limits on this jurisdiction, such as if federal development of hydropower generation at the site is authorized, or if Congress otherwise unambiguously withdraws the Commission’s jurisdiction over its development.

The Commission also has discretion to deny a preliminary permit application, so long as it articulates a rational basis for its decision.  Through recent precedent, one basis the Commission has developed for denying applications is if the project would rely on modifications to federal facilities, but the federal entity says it would not approve those modifications or opposes the project.

For example, on April 25, 2016, Loxbridge Partners, LLC applied to the Commission for a preliminary permit to study the feasibility of the proposed McNary Second Powerhouse Project No. 14777. The project would be located at the U.S. Army Corps of Engineers’ McNary Lock and Dam facility on the Columbia River in Oregon.  On May 16, 2016, Commission staff asked the Corps for its opinion on whether non-federal development is authorized at McNary Dam, and if so, whether Loxbridge’s proposal would interfere with existing dam operations or improvement plans.  The Corps responded that it believed the Commission does not have jurisdiction to issue a preliminary permit or license for the site, and that the Corps opposed Loxbridge's proposed project on the ground that it would interfere with the Corps’ operation of McNary Dam.  The Corps asked the Commission to reject the permit application.

On September 2, 2016, the Commission denied Loxbridge's preliminary permit application.  It cited recent decisions in which "the Commission has denied preliminary permits for projects at federal facilities after the federal entities indicated that no purpose would be served in issuing a permit because the federal entity would not approve modifications to its federal facilities."  One of these decisions cited, Advanced Hydropower, Inc., 155 FERC ¶ 61,007 (2016), even relates to a different proposal for non-federal hydropower development at the McNary Dam.  The Commission also noted that "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, there is no purpose in issuing a preliminary permit."

The Commission has issued similar denials with respect to Rivertec Partners LLC's proposed Clearwater Hydroelectric Project No. 14753 to be located at the Corps' Dworshak Dam in Idaho, Owyhee Hydro, LLC's proposed Anderson Ranch Pumped Storage Hydroelectric Project No. 14648 to be located at a Bureau of Reclamation dam in Idaho, and Symphony Hydro LLC's proposed Project No. 14627 to be located at the Corps' Upper St. Anthony Falls Lock and Dam on the Mississippi River near Minneapolis.

The policy highlights the importance for project developers of cultivating good relations with federal agencies owning dams and other facilities with hydropower development potential.

Climate change and Katahdin Woods and Waters National Monument

Friday, September 2, 2016

President Obama has established the Katahdin Woods and Waters National Monument in Maine.  His presidential proclamation establishing the monument under federal law cites climate change in two ways: both as an object of study enabled by the monument's protection, and as a challenge against which the monument lands may have special resilience.

Federal law gives the President discretion and authority to establish national monuments, or to "declare by public proclamation historic landmarks, historic and prehistoric structures, and other objects of historic or scientific interest that are situated on land owned or controlled by the Federal Government to be national monuments."  The Antiquities Act of 1906 also allows the President to reserve parcels of land as a part of the national monuments.  While the use of this power can be controversial -- either generally or as applied to specific lands -- well over 100 sites have been designated since President Teddy Roosevelt established Devils Tower as the first national monument in 1906.

Over a century later, on August 24, 2016, in honor of the 100th anniversary of the National Park Service, President Obama used his authority under the Antiquities Act to establish the Katahdin Woods and Waters National Monument.  The new national monument, managed by the National Park Service, protects approximately 87,500 acres of north-central Maine.  It covers land recently donated to the U.S. by philanthropist Roxanne Quimby’s foundation, Elliotsville Plantation, Inc.  That foundation also donated $20 million to supplement federal funds for initial operational needs and infrastructure development at the monument, plus another $20 million in pledged future support.

Climate change and human responses have been a major theme of the Obama administration's policy, and they appear as well in the Maine monument proclamation.  In establishing Katahdin Woods and Waters National Monument, President Obama noted that the monument would enable scientific investigation of the effects of climate change across the boundaries between ecoregions:
Katahdin Woods and Waters possesses significant biodiversity. Spanning three ecoregions, it displays the transition between northern boreal and southern broadleaf deciduous forests, providing a unique and important opportunity for scientific investigation of the effects of climate change across ecotones.
The proclamation also notes the monument area's likely resilience to climate change:
Although significant portions of the area have been logged in recent years, the regenerating forests retain connectivity and provide significant biodiversity among plant and animal communities, enhancing their ecological resilience. With the complex matrix of microclimates represented, the area likely contains the attributes needed to sustain natural ecological function in the face of climate change, and provide natural strongholds for species into the future.
In a statement released along with the official proclamation, the White House noted, "In addition to protecting spectacular geology, significant biodiversity and recreational opportunities, the new monument will help support climate resiliency in the region. The protected area – together with the neighboring Baxter State Park to the west – will ensure that this large landscape remains intact, bolstering the forest’s resilience against the impacts of climate change."

Emera Maine proposes Swans Island Electric Coop acquisition

Thursday, September 1, 2016

Maine utility Emera Maine and Swan's Island Electric Cooperative have asked the Maine Public Utilities Commission for approval of Emera Maine's proposed acquisition of the island cooperative.  The electric companies say reducing electric rates for consumers is the motivation.

Swan's Island Electric Cooperative is a member-owned rural electric cooperative incorporated in 1949.  The cooperative provides electric service to approximately 560 meters in the island communities of Swan's Island and Frenchboro.  It receives electricity from the mainland Emera Maine system, via undersea cables running from Mount Desert Island.

In a petition filed September 1, Emera Maine and the cooperative and described a proposed transaction through which Emera Maine would acquire most of Swan's Island Electric Cooperative's assets, acquire all of its service territory, and provide electric service to all Swan's Island and Frenchboro customers. Swan's Island Electric Cooperative would cease providing utility service, wind up its affairs, and formally dissolve the Cooperative.

The petition states that the "primary benefit of the proposed transaction is that Swan's Island and Frenchboro ratepayers will receive immediate and substantial rate relief."  According to the petition, the costs of providing electricity to a remote island and small cooperative membership have led to high electricity rates for customers of the cooperative.

The petition notes that Swan's Island customers currently pay delivery charges of 12.343 cents per kilowatt hour and Frenchboro customers pay 15.917 cents per kilowatt hour.  Fixed meter charges add another $46.84 per month for Swan's Island customers (or $48.26 for Frenchboro.)  The petition contrasts these rates to "a typical residential customer in Emera's Bangor Hydro District", with a delivery charge of 10.770 cents per kilowatt hour and a minimum charge of $7.48 per month.

According to the petition, the cooperative's high rates prompted members to investigate the possibility of a merger with Emera.  This led to the August 31, 2016 execution of an Asset Purchase Agreement, under which Emera will purchase the bulk of the cooperative's assets, acquire its service territory and provide service to its current customers, subject to regulatory approval.  According to the petition, 90% of votes by cooperative members supported the transaction.

The petition describes Emera's commitments as including the installation of modern "smart meters" for all new cooperative customers, and notes anticipation that the undersea cables will need replacement "within the next several years at an estimated cost of $3.4 million."  Emera points to its experience providing service to remote areas, including the Cranberry Isles.

The transaction requires approval by the Maine Public Utilities Commission.  The Commission has docketed it as Docket No. 2016-00209.

ISO-NE Winter Reliability Program 2016-2017

As winter approaches, the operator of New England's wholesale electricity markets is preparing to run another seasonal Winter Reliability Program to address operational concerns related to fuel adequacy.

Since the winter of 2013-2014, ISO New England Inc. has operated a seasonal program to address winter fuel security and power system reliability concerns, relating largely to natural gas pipeline constraints.  After two initial program years, last fall the Federal Energy Regulatory Commission approved a three-year plan for ISO-NE's Winter Reliability Program.

That program, developed chiefly by market participant group New England Power Pool (NEPOOL), was designed to address reliability concerns through at least 2017-2018, when new “Pay-for-Performance” incentives and penalties in New England's redesigned capacity market are set to take effect.  The winter reliability program encourages generators fueled by oil and liquefied natural gas (LNG) to secure fuel before the winter season begins, by compensating them for some costs related to fuel inventory that remains unused at winter's end, and includes a demand response component.  According to ISO-NE, last year's participants included 77 oil-fired units, 8 LNG units, and 6 demand response assets.

The program's rules are specified in Appendix K to Section III of the ISO New England Inc. Transmission, Markets and Services Tariff.  As approved by FERC, the current program retains the three core components of the 2014-2015 Winter Reliability Program: (1) compensation for certain oil inventory that remains in New England following the end of each winter period; (2) end-of-season compensation for LNG contract volumes kept available for winter use but not actually called upon to produce energy; and (3) a supplemental demand response program.

ISO-NE has also published a memorandum describing payment rates for the 2016-2017 winter program.  Under its tariff, ISO-NE first determines a "Set Rate," representing partial compensation for the per-barrel carrying costs of stored fuel oil.  The Set Rate is translated into an equivalent rate for the other, non-oil services that are compensated through Appendix K.

Requests to participate in ISO New England's 2016-2017 Winter Reliability Program are due to ISO-NE by October 1, 2016

Kitty Hawk NC offshore wind leasing

Wednesday, August 31, 2016

The U.S. Department of the Interior has proposed leasing federal ocean space offshore North Carolina for commercial offshore wind development.  On August 12, 2016, the Bureau of Ocean Energy Management announced a proposed lease sale for the 122,405-acre Kitty Hawk Wind Energy Area.  The proposal could lead to leasing of sites offshore North Carolina for one or more marine renewable energy projects.

The path to federal leasing of commercial wind development sites offshore North Carolina began in 2012, when the Bureau of Ocean Energy Management published a Call for Information and Nominations (or “Call”) in the Federal Register, to evaluate industry interest in commercial wind leases in three areas offshore North Carolina and to request comments regarding site conditions, resources and other uses within the Call areas.

In 2014, BOEM announced its identification of three Wind Energy Areas offshore North Carolina, including the Kitty Hawk, Wilmington West, and Wilmington East Wind Energy Areas.

In 2015, BOEM published an Environmental Assessment of potential environmental and socioeconomic impacts associated with issuing commercial wind leases and approving site assessment activities on the lease areas, followed by a revised Environmental Assessment and a "Finding of No Significant Impact."  This so-called FONSI concluded that reasonably foreseeable environmental effects associated with the commercial wind lease issuance and related activities would not significantly impact the environment.

Most recently, BOEM published a Proposed Sale Notice (PSN) and Request for Interest (RFI) for Commercial Leasing for Wind Power on the Outer Continental Shelf Offshore North Carolina in the Federal Register on August 16, 2016.  The notice applies to the Kitty Hawk Wind Energy Area. BOEM has rolled the Wilmington East and Wilmington West areas into its planning and leasing process for Call Areas offshore South Carolina, given their proximity and shared attributes.

If a developer is interested in bidding on the Kitty Hawk site lease rights, it must first submit a qualification package to BOEM.  If BOEM finds the developer to be legally, technically and financially qualified by the time the Final Sale Notice is published, the developer is eligible to participate in the lease sale.  Eligible bidders must notify BOEM within the 60-day comment period established by the notice.

Vineyard Wind offshore project changes hands

Tuesday, August 30, 2016

Danish fund management company Copenhagen Infrastructure Partners has acquired Offshore MW LLC, the holder of an offshore wind energy lease issued by the U.S. Bureau of Ocean Energy Management over an area south of Massachusetts.

Copenhagen Infrastructure Partners describes itself as a fund management company founded in 2012. On August 25, 2016, CIP announced that on behalf of its fund Copenhagen Infrastructure II it had acquired 100% of Offshore MW LLC.

Acquired company Offshore MW LLC is developing the Vineyard Wind project over the Outer Continental Shelf south of Massachusetts.  The site is part of the Massachusetts Wind Energy Area originally designated by BOEM for leasing in 2012.  Offshore MW won the lease rights through a competitive lease auction held by the Bureau of Ocean Energy Management on January 29, 2015, in which it submitted the winning bid for Lease Area OCS-A 0501.  That lease area covers 166,886 acres, or roughly 260 square miles of sea space in federal waters off Massachusetts. 

According to CIP, it will continue with the Massachusetts project's development.  The Vineyard Wind project could receive a boost from recently enacted Massachusetts legislation that will require utilities to purchase about 1,600 megawatts worth of offshore wind energy by 2027.  That law, known as H. 4568, "An Act to promote energy diversity," requires electric distribution companies to issue an initial joint competitive solicitation for offshore wind proposals by June 30, 2017.

Tide Mill Institute - 2016 Boston conference

Monday, August 29, 2016

The Tide Mill Institute will hold its 12th conference, Boston's Tidal Power: Periodic & Perpetual, on Saturday, November 12th, at the Metropolitan Waterworks Museum in Boston, Massachusetts.

Tide Mill Institute is nonprofit corporation, whose mission is:
  • to advance appreciation of the American and international heritage of tide mill technology;
  • to encourage research into the location and history of tide mill sites;
  • to serve as a repository for tide mill data for students, scholars, engineers and the general public and to support and expand the community of these tide mill stakeholders; and
  • to promote appropriate re-uses of old tide-mill sites and the development of the use of tides as an energy source.

Previous Tide Mill Institute symposia have included tours, presentations, and exhibits on the past, present and future of tidal power.  Topics range from archaeology and history to modern marine renewable energy projects and technology, from sites around the world.

Tide Mill Institute's 2016 conference will focus on Boston's tidal power heritage.  Presentations will illustrate historical tide mills, based on tide mill relics from the 18th century found during the "Big Dig” construction project, as well as the 19th century project along Back Bay that was designed and built to provide “perpetual power.”  Other invited speakers will describe millstone quarries, and tides and tidal power around the world.  The event will also include a tour of the Waterworks Museum, which interprets of one of the country’s earliest metropolitan water systems, as well as the annual meeting of Tide Mill Institute.

Space is limited at the venue, so register early by contacting Tide Mill Institute at info@tidemillinstitute.org, 207-946-4156, or 18 Hummingbird Hill – Greene ME 04236.  Please indicate your email address and phone number.

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."