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