US, Canada grid security and resilience strategy

The governments of the United States and Canada have released a joint strategy for ensuring the security and resilience of their electric grid.  In recognition of the interconnected nature of the North American electric grid, the document, "Joint United States-Canada Electric Grid Security and Resilience Strategy," describes the nations' shared goals and objectives.  An action plan released alongside the strategy presents U.S. steps and milestones toward achieving the strategy's desired outcomes.

The joint strategy centers on a vision of "a secure and resilient electric grid that is able to withstand hazards and recover efficiently from disruptions."  Recognizing that this grid is made up of a variety of interconnected entities -- including federal, territorial, municipal, co-operative, and investor-owned and operated utilities -- the strategy identifies three overarching goals:

• Protect Today’s Electric Grid and Enhance Preparedness: A secure and resilient electric grid that protects system assets and critical functions and is able to withstand and recover rapidly from disruptions is a priority for the governments of both the United States and Canada.
• Manage Contingencies and Enhance Response and Recovery Efforts: The Strategy sets out a shared approach for enhancing continuity and response capabilities, supporting mutual aid arrangements such as cyber mutual assistance across a diverse set of stakeholders, understanding interdependencies, and expanding available tools for recovery and rebuilding. 
• Build a More Secure and Resilient Future Electric Grid: The United States and Canada are working to build a more secure and resilient electric grid that is responsive to a variety of threats, hazards, and vulnerabilities, including increased threats from climate change. To achieve this, the electric grid will need to be more flexible and agile, with an architecture into which new technologies may be readily incorporated.

Beyond the joint strategy, each participating country has also developed its own individual action plan describing steps and milestones toward the strategic goals.  The U.S. National Electric Grid Security and Resilience Action Plan was released concurrently with the Strategy.

The action plan is generally non-binding on the U.S., and it is unclear whether the incoming Trump administration would adopt the plan, as opposed to revising or scrapping it.  Nevertheless the joint U.S.-Canada grid security and resilience strategy and the U.S. action plan may inform future efforts to strengthen the North American electric grid against risk and disturbance.

ISO-NE winter electricity supply 2016-2017

New England should have sufficient electricity supplies to meet consumer demand this winter, according to regional power grid operator ISO New England, Inc.  But because natural gas pipeline constraints could limit electricity production, the grid operator has implemented a Winter Reliability Program to help ensure supply meets demand.

ISO-NE is the regional transmission organization responsible for most of New England's electric grid.  In that role, it forecasts electricity demand, and operates markets to match up generation with demand.

On December 5, 2016, ISO-NE released a statement addressing winter 2016-2017 with respect to electricity reliability.  The grid operator projects that at normal winter temperatures of about 7 degrees Fahrenheit, peak demand will reach 21,340 MW, or 22,028 MW if extreme winter weather of 2 degrees F occurs.  This would be above the 2015-2016 winter peak demand of 19,545 MW (February 14, 2016, from the hour from 6 to 7 p.m.), and below the all-time regional winter peak of 22,818 MW (a cold snap on January 15, 2004).

According to the grid operator, electricity supplies should be sufficient to meet consumer demand this winter -- but natural gas pipeline constraints and other factors create risks that could affect reliability.  Natural gas generated 49% of the region's electricity in 2015, and natural gas-fired power plants represent about 44% (or 14,850 megawatts) of the region's total generating capacity. But ISO-NE views about 3,450 MW of natural gas-fired generating capacity as "at risk" this winter due to the insufficiency of the region's natural gas infrastructure.  Despite some new pipeline projects and the present availability of liquified natural gas (LNG), the region faces the loss of 1,500 MW of coal- and oil-fired generation this spring with the closure of the Brayton Point Power Station in Massachusetts.

ISO-NE touts its 2016-2017 Winter Reliability Program as designed to address these "multiple risks" of pipeline constraints and non-gas unit retirement. As previously approved by the Federal Energy Regulatory Commission, the program will run from December 1, 2016 to February 28, 2017, and includes an oil inventory component, an LNG component, and a demand response component.

In light of this planning, and barring "unexpected resource outages or fuel delivery constraints," ISO-NE projects New England's electricity supplies should be sufficient this winter to meet consumer demand.

NY considers ESCO reforms

New York utility regulators have launched consideration of reforms to how retail electricity suppliers called energy service companies or ESCOs operate in that state.  A December 2, 2016 notice issued by the New York Department of Public Service describes a history of "substantial overcharges and deceptive practices by the ESCO industry harming New York consumers," and establishes a process to "push ahead with reforms to ensure that ESCOs provide useful, value-added, economical services to New York consumers."  New York's ESCO reform process will play out in conjunction with other state initiatives, such as the Reforming the Energy Vision program.

As described in the Notice of Evidentiary and Collaborative Tracks and Deadline for Initial Testimony and Exhibits, the New York Public Service Commission initially opened up the energy services market to retail competition "to spur innovation in the creation of value-added products, particularly energy efficiency services that regulated rates may not provide, and to create commodity price competition that would result in efficiencies."  The notice summarizes the regulatory philosophies driving the historic decision to separate monopoly services (transmission and distribution) from competitive services (energy commodity), and the expectation that robust competitive markets would yield societal benefits.

But based on its "considerable experience with the offering of retail service to mass market customers by ESCOs," in 2014 the Commission determined "that the retail markets serving mass-market customers are not providing sufficient competition or innovation to properly serve consumers."  In the Commission's view, its subsequent efforts to realign the retail market have not succeeded: "customer abuses and overcharging persist, and there has been little innovation, particularly in the provision of energy efficiency and energy management services.  Commodity price differentiation has not worked, and the market for differentiated services is immature or non-existent."

For these reasons, on December 2, 2016, the Commission gave public notice that it "continues to examine measures that must be taken to ensure that these customers receive valuable services and pay just and reasonable rates for commodity and other services."  Among the measures identified for consideration by the Commission are:

• whether ESCOs should be completely prohibited from serving their current products to mass-market customers;
• whether the regulatory regime, rules and Uniform  Business Practices (UBP) applicable to ESCOs need to be modified to implement such a prohibition, to provide sufficient additional guidance as to acceptable rates and practices of ESCOs, or to create enforcement mechanisms to deter customer abuses and overcharging, including whether the Commission decision not to subject ESCOs to Article 4 of the Public Service Law should be revisited; and
• whether new ESCO rules and products can be developed that would provide sufficient real value to mass-market customers such that new products could be provided to them by ESCOs in the future in a manner that would ensure just and reasonable rates.

To pursue these efforts, the Commission established two procedural tracks.  An evidentiary track will consider the first two bullets listed above, while a "collaborative" track will focus on the third bullet. 

The Commission has previously described ESCO reforms as supportive of New York's Reforming the Energy Vision initiative, a comprehensive revisioning of the state's electricity sector.  In a February 2016 order, the Commission noted, "Development of markets in which vendors offer innovative services of value to consumers, and in which consumers can participate with confidence, is critically important to the success of the Reforming the Energy Vision (REV) initiative. Retail energy markets focused on commodity-only products, and in which ESCOs do not meet expectations of many customers, will thwart these objectives."

Initial pre-filed testimony and exhibits for the Track I evidentiary case on ESCO reforms are due on or before April 7, 2017.

Maryland considers offshore wind applications

Maryland moves closer to offshore wind development, as the state Public Service Commission reviews two applications for offshore wind projects.

The Maryland Offshore Energy Act of 2013 contains a number of provisions that would benefit a “qualified offshore wind project” that

1. is located on the outer continental shelf, between 10 and 30 miles off the Maryland coast, in an area that is designated for leasing by the Bureau of Ocean Energy Management within the U.S. Department of the Interior,
2. interconnects to the PJM Interconnection grid at a point located on the Delmarva peninsula, and
3. is approved by the Public Service Commission.

On February 25, 2016, the Maryland Public Service Commission opened an application period for Offshore Wind Projects.  While the original deadline was August 23, it was ultimately extended three times, until November 18, 2016.

On November 22, the Commission's consultant announced that two offshore wind project applications were submitted, found to be administratively complete, and found to have met the minimum threshold criteria. The applicants are (i) US Wind, Inc., a subsidiary of Toto Holding SpA, and (ii) Skipjack Offshore Wind, LLC, a subsidiary of Deepwater Wind Holdings, LLC.

The Commission then opened a docketed proceeding (Case Number 9431) to conduct a multi-part review to evaluate and compare the proposed offshore wind project applications submitted by US Wind and Skipjack.  Petitions to intervene in that proceeding are due by Monday, December 12, 2016.

FERC energy trading compliance white paper

Enforcement staff at the Federal Energy Regulatory Commission have released a white paper presenting their view of effective practices to ensure energy trading complies with prohibitions against market manipulation. The November 2016 document, “Staff White Paper On Effective Energy Trading Compliance Practices,” provides examples of compliance practices that Office of Enforcement staff have found effective in detecting and deterring market manipulation – as well as examples of ineffective compliance practices. Staff’s identification of these best practices and pitfalls can inform electric energy and natural gas market participants as they design, implement, and maintain strong compliance programs.

The Commission is charged with prohibiting market manipulation in jurisdictional electricity and gas markets. It has enunciated penalty guidelines, policy statements and regulations relating to preventing and penalizing market manipulation. These statements emphasize the importance of having an effective compliance program. As the Commission has described it, “For an organization’s compliance program to be deemed effective under the Penalty Guidelines, an organization must: (1) exercise due diligence to prevent and detect violations; and (2) otherwise promote an organizational culture that encourages a commitment to compliance with the law.”

The white paper provides additional insight into how the Office of Enforcement views compliance issues. It highlights the need for a “culture of compliance”:

For any compliance program to be effective, the organization must have a culture of compliance. Promoting a culture of compliance starts at the top, with a Chief Executive Officer and other executive officers who are committed to compliance and who demonstrate that commitment through action. The organization and the executive officers must be committed to promoting compliance at all levels by devoting the necessary resources to the organization’s compliance activities, implementing and enforcing rules and restrictions that are appropriate for the organization’s activities, ensuring that employees understand their compliance obligations, and continually assessing the effectiveness of the compliance practices.

The white paper then provides examples of effective compliance practices, organized into three categories. The first category focuses on designing an effective trading compliance program with a “strong foundation.” According to staff, this involves making “the appropriate decisions relating to: (1) the organizational structure and composition of the compliance function; (2) human resources issues, such as hiring standards, compensation, and discipline; (3) the types of training used to disseminate compliance information; and (4) the technological resources dedicated to the compliance function.”

The second category of practices identified by enforcement staff focuses on establishing, implementing, and enforcing effective practices to deter and detect market manipulation and other misconduct. In addition to implementing some or all of the practices described above in designing the organization’s compliance program, the white paper says organizations should also “(1) establish appropriate rules and restrictions for its traders that will further reduce the risk of misconduct; (2) consistently monitor trading activities for violations of those rules and for any other suspicious activity; and (3) strictly enforce all compliance rules and follow up on all potential issues.”

The third category focuses on assessing the performance of the compliance program on a regular basis. The Penalty Guidelines call for periodic evaluation of the effectiveness of the organization’s compliance program. The white paper provides additional color on staff’s views about assessment, calling for performance audits and taking action on all items identified in an audit.

The white paper finally identifies “ineffective trading compliance practices,” which staff said “generally reflect an organization’s failure to: (1) tailor its compliance program to the specific needs of its trading operation; (2) keep the compliance program up-to-date; (3) make compliance policies accessible to its employees both literally and from the prospective of employee comprehension; (4) place the appropriate emphasis on ensuring compliance; and (5) follow through on monitoring for violations and enforcing compliance-related rules.”

The white paper is designed to supplement the Commission’s Policy Statements, but it explicitly does not require organizations to establish or follow any specific practices to receive compliance credit under the Penalty Guidelines if a violation occurs. Instead, according to the white paper, the existence of these practices in an organization’s compliance program may factor positively into the Commission’s consideration of whether the organization’s compliance program was effective. At the same time, the white paper notes that “adopting the effective practices described herein will not shield an organization from, or provide a defense to, an enforcement action if the Commission concludes, after an evaluation of the facts and circumstances involved, that it committed a violation,” although having an effective compliance program in place at the time of a violation could lead to a reduced penalty.

NPS updates oil and gas rights rules

The U.S. National Park Service has adopted a final rule updating its regulations governing the exercise of non-federal oil and gas rights. The NPS states that the rule improves its ability to protect park resources, values, and visitors from potential impacts associated with nonfederal oil and gas operations located within National Park Service units outside Alaska.

At issue are non-federal oil and gas rights within national park system units.  According to the NPS, these arise where the United States does not own the oil and gas interest, either because:

• The United States acquired the property from a grantor that did not own the oil and gas interest; or
• The United States acquired the property from a grantor that reserved the oil and gas interest from the conveyance.

Currently, 12 park system units are home to 534 non-federal oil and gas operations:

• Alibates Flint Quarries National Monument, Texas (5 operations)
• Aztec Ruins National Monument, New Mexico (4 operations)
• Big Cypress National Preserve, Florida (20 operations)
• Big Thicket National Preserve, Texas (39 operations)
• Big South Fork National River and Recreation Area, Tennessee/Kentucky (152 operations)
• Cumberland Gap National Historical Park, Tennessee (2 operations)
• Cuyahoga Valley National Park, Ohio (90 operations)
• Gauley River National Recreation Area, West Virginia (28 operations)
• Lake Meredith National Recreation Area, Texas (174 operations)
• New River Gorge National River, West Virginia (1 operation)
• Obed Wild and Scenic River, Tennessee (5 operations)
• Padre Island National Seashore, Texas (14 operations)

NPS has stated an expectation that future non-federal oil and gas operations within park boundaries could occur in up to 30 additional System units, based on "the presence of split estates, exploration and production occurring on adjacent or nearby lands, and likely increases in energy prices."

While the NPS promulgated regulations in 1978 governing the exercise of non-federal oil and gas rights, it had not updated these rules since then.  The final rule issued in November 2016 thus represents the first change in over 37 years.  Its changes include a broadening of scope, to cover all non-federal oil and gas operations within the boundary of a system unit outside of Alaska.
 This rule is effective December 5, 2016.

Maine considers community solar rules

As Maine utility regulators consider changes to the state’s net metering rule for solar panels and other customer-owned generation, revisions proposed by the Public Utilities Commission could change how consumers can participate in community and shared ownership solar projects.

For years, the Maine Public Utilities Commission’s rules have allowed “net energy billing,” a metering and billing mechanism that promotes the development and operation of smaller renewable generation facilities. Net metering is responsible for nearly all customer-owned solar power projects developed in Maine to date, including a handful of shared ownership or community solar farms. But as utility Central Maine Power Company reported that its customers' net metering reached 1% of peak load last year, the Commission launched a process to consider revisions to its net energy billing rules.

On September 14, 2016, the Commission released a Notice of Rulemaking along with proposed amendments to its rule. As proposed by the Commission, the amended rule would expand net energy billing in Maine in several ways. It would increases the size cap for an eligible facility by 50%, from 660 kilowatts to one megawatt. It would also recognize four different types of net energy billing arrangements that would be allowed: individual customer; customer leases; shared ownership; and community NEB.

Under the shared ownership model, each participating customer must have a shared ownership interest in the eligible facility under which the customers have joint responsibility for the costs of the shared ownership facility and have rights to the output of the shared ownership facility in proportion to their cost responsibilities. Under shared ownership net energy billing, the transmission and distribution utility would allocate the nettable energy of the shared ownership facility to customers in proportion to each customer’s ownership interest in the eligible facility.

The proposed rule would also explicitly allow for “community” net energy billing, a model that the Commission recognized as “increasing as a means to promote smaller solar installations.” The proposal suggests that community projects would have similarities to shared ownership projects, with additional registration and consumer protection provisions, but potentially with different ownership requirements.

The case over the rule change’s adoption remains pending for now. While some elements of the proposal would expand net metering opportunities, the proposal would also ratchet down the amount of energy that new projects could net against their T&D bill, from 100% in 2016 to 0% for new NEB customers after 2025. Elements of the Commission’s proposal remain controversial. Nevertheless the Commission’s proposal suggests a potential direction for future community solar projects in Maine.

FERC 2016 Report on Enforcement

The Federal Energy Regulatory Commission's enforcement program has shown consistency in recent years, according to a presentation by Office of Enforcement staff to the Commissioners.  On November 17, 2016, the Commission's Office of Enforcement released its 2016 Report on Enforcement.  This report, along with a presentation and two related white papers, provides insight into Commission staff’s views as well as emerging trends related to manipulation of FERC-jurisdictional markets.

Federal law charges the Commission with enforcing a variety of laws and regulations pertaining to utilities and energy matters.  These and related Commission policies include prohibitions on market manipulation.  Within the Commission, its Office of Enforcement houses various functions related to enforcing anti-market manipulation.

In its tenth annual Report on Enforcement, the Office of Enforcement provides information on the activities of all four OE Divisions: Analytics and Surveillance, Audits and Accounting, Energy Market Oversight, and Investigations.

As described in a related presentation by staff to the Commission:

A major theme reflected in this year’s Annual Report is the consistency in the Commission’s enforcement program. OE’s priorities have not changed over the past few years. We have focused, and will continue to focus, on four distinct areas: (1) fraud and market manipulation; (2) serious violations of the Reliability Standards; (3) anticompetitive conduct; and (4) conduct that threatens transparency in regulated markets.

Staff also published two white papers covering compliance practices and enforcement efforts:

• White Paper on Effective Energy Trading Compliance Practices
  
• White Paper on Anti-Market Manipulation Enforcement Efforts Ten Years After EPAct

Maine utility water supply inquiry

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

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

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

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

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

FERC considers hydro license term policy

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

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

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

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

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

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

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

Adding micro-hydro to licensed hydropower project

What happens when a FERC hydropower licensee applies for a preliminary permit to study the feasibility of developing a micro-hydro project, where the new project will be sited at an existing project's dam?  In a recent case involving the city of Aspen, Colorado, Commission staff dismissed the preliminary permit application, instead suggesting that the licensee apply to amend its existing license to include the proposed new capacity and facilities.  Because many other existing dams may be candidates for the installation of new hydropower facilities, the Aspen Micro Hydro Project case illustrates important dynamics of hydropower licensing under the Federal Power Act.

The case centers on a March 4, 2015 application by the City of Aspen for a preliminary permit, pursuant to section 4(f) of the Federal Power Act, to study the feasibility of developing the Aspen Micro Hydro Project.  Most grid-connected hydropower in the U.S. is regulated under the Federal Power Act, and requires approvals by the Federal Energy Regulatory Commission.  As described in Commission documents, the proposed Aspen project would include an existing concrete diversion dam and intake structure, plus proposed new equipment including a draft tube, 10- to 20-kilowatt turbine-generator unit, and associated facilities interconnected to an existing utility transmission line.  The application describes project values including energy production, protection of the city's water rights, and instream flow protection for environmental benefit.  As noted in the application, "Renewable projects such as the Aspen Micro Hydro Project will permit the City of Aspen to reduce its reliance on coal-fired energy and comports with the City’s goal of reducing its energy-related greenhouse gas emissions. A local facility also will provide tangible evidence to residents and visitors of Aspen’s commitment to renewable energy."

Crucially, as noted by the Commission, the dam proposed for use in the Aspen micro-hydro project is currently licensed as part of another hydropower project: the City of Aspen's Maroon Creek Project.   Commission staff have noted that "for licensed projects, such as the Maroon Creek Project, section 6 of the [Federal Power Act] prohibits the alteration of licensed project works without the mutual consent of the licensee and the Commission."  On April 16, 2015, Commission staff sent the city a letter explaining that because the proposed micro-hydro project would be sited within the existing project boundary of the city’s Maroon Creek Project, any application for a permit or license within the project boundary would be denied.  For this reason, Commission staff concluded that "a preliminary permit for the Aspen Project would serve no purpose."  Instead, Commission staff informed the city "that it could instead file an application to amend its existing license to add the Aspen Project’s proposed capacity and related facilities to the Maroon Creek Project." 

Over a year later, the city filed a status report describing its intention to "enter into a business relationship with T-Lazy Seven Ranch (T-Lazy), a Colorado ranching company, for joint development of the Aspen Project."  The status report describes plans to form a new limited liability company, and ultimately to amend the permit application to replace the city as applicant with the new company.

In a November 15, 2016 Order Dismissing Preliminary Permit Application, Commission staff noted that the purpose of a preliminary permit is "to encourage hydroelectric development by affording its holder priority of application (i.e., guaranteed first-to-file status) with respect to the filing of development applications for the affected site."  The order also notes that the prohibition in section 6 of the Federal Power Act against the alteration of licensed project works without the mutual consent of the licensee and the Commission applies, no matter whether it is the existing licensee or the new entity who seeks to pursue additional development within the project boundary of the Maroon Creek Project.  The Commission's consent to alter licensed project works would presumably come in the form of an order amending the Maroon Creek Project's license -- a consent not formally requested int the Aspen Project's docket.

Continuing to find that a preliminary permit for the Aspen Project would serve no purpose for these reasons, the order dismissed the city's permit application.  The order leaves the door open for the licensee to seek to amend the Maroon Creek Project's license, potentially in concert with an application to transfer the licensee to a new licensee or co-licensee.

Beyond the City of Aspen's interests in hydropower, the case has regulatory implications for other proposals to develop micro-hydro or new generating capacity at dams or other structures already part of FERC-licensed projects.  A Department of Energy report released earlier this year found significant national potential to increase hydropower capacity, including by adding power at existing dams and canals.  Where the existing assets are part of a FERC-licensed project, developers will be wise to be mindful of how the Commission interprets the Federal Power Act.

BLM rule for renewable energy leasing of federal lands

The federal Bureau of Land Management has issued a final rule establishing a competitive process for leasing federal lands for renewable energy development.  The Obama administration describes the rule as strengthening the agency's existing "Smart from the Start" leasing program, consistent with the president's Climate Action Plan.  But following the 2016 election, the future Trump administration could change the agency's course.

Part of the Department of the Interior, the BLM manages federal lands across the U.S.  While BLM lands have been used for mining for years, under the Obama administration BLM took steps to open up federal lands for leasing for renewable energy projects.  Under federal laws including the Federal Land Policy and Management Act (FLPMA) and the Mineral Leasing Act (MLA), BLM is authorized to issue what it calls "grants" -- easements, leases, licenses, and permits to occupy, use or traverse public lands for particular purposes -- for facilities for the generation, transmission, and distribution of electric energy, and oil and gas pipelines.

On November 10, BLM released its final rule, "Competitive Processes, Terms, and Conditions for Leasing Public Lands for Solar and WindEnergy Development and Technical Changes and Corrections for 43 CFR Parts 2800and 2880.”  It amends BLM's regulations governing rights-of-way issued under two federal laws.  BLM described the amendments as necessary to "facilitate responsible solar and wind energy development on BLM-managed public lands and to ensure that the American taxpayer receives fair market value for such development."

The final rule includes provisions to promote the use of preferred areas for solar and wind energy development.  These areas, called “designated leasing areas” (DLAs), are defined parcels of land with specific boundaries identified by the BLM land use planning process as being a preferred location for solar or wind energy that can be leased competitively for energy development.

The rule expands BLM's existing regulations, allowing BLM to offer lands competitively on its own initiative, both inside and outside DLAs, even in the absence of identified competition. Within DLAs, the rule will require competitive leasing procedures except in certain circumstances, when applications could be consider ed outside the competitive process. Outside DLAs, the BLM will have discretion whether to utilize competitive leasing procedures.

The final rule also updates payments charged by BLM, to ensure that it obtains fair market value for the use of public lands.  Updated fee structures include both an acreage rent and a megawatt-capacity fee.

Given the November 8 election results, it is unclear whether the Trump administration will continue in this direction.  While campaigning, President-elect Trump emphasized leasing more federal land for fossil fuel production.  The BLM renewable energy rule's future is thus in question.

Nova Scotia tidal turbine installed

A Canadian tidal power developer has installed a turbine at a test site in the Bay of Fundy. Cape Sharp Tidal's project off Nova Scotia could demonstrate the feasibility of larger-scale marine hydrokinetic power plants connected to the mainland electricity grid.

Cape Sharp Tidal is a joint venture between Canadian utility Emera Inc. and marine turbine manufacturer OpenHydro.  Its project entails a grid-connected 4-megawatt array consisting of two tidal turbines.  The project is located at the Fundy Ocean Research Center for Energy (FORCE) site.  Headquartered near Parrsboro, Nova Scotia, FORCE is Canada's leading research center for in-stream tidal energy, with demonstration berths, a grid interconnection capable of accepting tidal power, and environmental monitoring capabilities.

This week Cape Sharp Tidal deployed the project's first turbine-generator, a 2-megawatt OpenHydro unit.  In subsequent work, crews interconnected the turbine cable tail to the FORCE site's main interconnection cable, an existing 16MW subsea export cable connected to an onshore substation.

Previous efforts to develop hydrokinetic tidal energy projects in the Bay of Fundy have met with difficulty.  While the bay offers large and powerful tides, weather and sea conditions can prove challenging, as can obtaining environmental and regulatory approvals.  A test tidal turbine deployed in 2009 was quickly destroyed; the turbine installed this week was originally slated for installation earlier but was delayed due to concerns over impacts to fisheries and the environment.  This week's installation represents a concrete step forward for Canadian tidal power.

Cape Sharp Tidal intends to install and connect a second turbine at the FORCE site in 2017.  According to the developer, its future plans -- subject to regulatory and business approvals -- could include a commercial-scale project of up to 300 megawatts capacity within 15 years.

US designates alternative fuel corridors for transportation

U.S. federal highway administrators have announced the designation of 55 routes as "alternative fuel" corridors, capable of accommodating electric vehicles or those powered by hydrogen, propane, or natural gas.  The announcement sets the stage for further federal action supporting alternative transportation fuels.

An electric vehicle charging station, in an underground parking garage in Boston.

The U.S. Department of Transportation’s Federal Highway Administration (FHWA) oversees construction and maintenance of the nation's highways, bridges, and tunnels.  FHWA data suggests U.S. drivers travel over 3.15 trillion miles per year.  Overall, the U.S. transportation sector is a major consumer of energy, and among the largest contributors to domestic greenhouse gas emissions.  

Congress and the Obama administration are now pursuing strategies to reduce the transportation sector's greenhouse gas emissions.  Electric vehicles and alternative transportation fuels form one tool in these efforts.  Under a 2015 law -- Section 1413 of the Fixing America's Surface Transportation (FAST) Act -- the Secretary of Transportation is required to designate national electric vehicle (EV) charging, hydrogen, propane, and natural gas fueling corridors.  In July, the Department of Transportation asked states to nominate corridors along major highways, for EVs and other alternative fuels designated in the FAST Act.

In a November 3, 2016, announcement, the FHWA unveiled its designation of the nation's first alternative fuel corridors.  The network is nearly 85,000 miles long, and crosses 35 states.  Some corridors have been designed as "sign-ready," meaning alternative fueling stations are operational; these corridors are eligible to feature new signs showing where drivers can refuel.

The FHWA has posted maps of its alternative fuel corridors on its website.  The agency intends to add more miles in the future, as additional charging and fueling stations are built.

NY offshore wind lease auction set

The U.S. Bureau of Ocean Energy Management has issued a Final Sale Notice, setting December 15 as the date for auctioning the right to lease sites in federal waters off New York for commercial offshore wind development.

The U.S. federal government is pursuing a national strategy to facilitate the domestic development of offshore wind energy.  Under federal law, the Bureau of Ocean Energy Management is responsible for administering renewable energy project development on the offshore Outer Continental Shelf.  The strategy calls for BOEM to identify areas suitable for wind energy leasing, and to then offer leases through auctions or other sales.

BOEM is now moving forward with plans to auction leasing rights for an area offshore New York.  In June 2016, BOEM first issued a Proposed Sale Notice for leasing rights off New York.  BOEM solicited public comment on its proposal over the summer.

On October 27, 2016, BOEM announced the designation of a final New York Wind Energy Area, starting approximately 11.5 nautical miles from Jones Beach, NY, and running approximately 24 nm southeast.  The final New York Wind Energy Area differs from BOEM's earlier leasing proposal primarily in its removal of about 1,780 acres due to environmental concerns over sensitive habitat on a feature called Cholera Bank.

BOEM's announcement also identified 14 companies that it has deemed legally, technically and financially qualified to participate in the New York lease sale:

• Avangrid Renewables, LLC
• CI-II NY Inc.
• DONG Energy Wind Power (U.S.) Inc.
• Innogy US Renewable Projects LLC
• wpd offshore Alpha LLC
• Deepwater Wind Hudson Canyon, LLC
• Energy Management, Inc.
• Convalt Energy LLC
• Clean Power Northeast Development Inc.
• New York State Energy Research and Development Authority
• Statoil Wind US LLC
• EDF Renewable Development, Inc.
• Fishermen’s Energy, LLC
• Sea Breeze Energy LLC 

BOEM will offer the lease as Lease OCS-A 0512, using a multiple-factor auction format.  Changes to the auction rules originally proposed include a 10% bidding credit for entities that establish that they are a “government authority” as defined in the Final Sale Notice, along with an adaptation to the auction format allowing bidders a “limited opportunity to revoke” a provisionally winning bid without penalty if the next-highest bid was submitted by a governmental entity.

Meanwhile, state energy agency NYSERDA is pursuing the New York State Offshore Wind Master Plan to advance offshore wind development in the state.  NYSERDA has expressed interest in bidding in a BOEM auction for project leasing rights, and was included in BOEM's list of entities qualified for the December 15 auction. Moreover, NYSERDA could be a beneficiary of the "government authority" provision in BOEM's Final Sale Notice; if so, it could receive a 10% credit on top of its cash bid.

BOEM will conduct the auction electronically, through a contractor, starting at 8:30 EST on December 15, 2016.

Massachusetts next generation solar incentive

The Massachusetts Department of Energy Resources is developing a new solar incentive program.  DOER released its proposal for the next generation of solar incentives on September 23, 2016. 

The 2016 legislation, An Act Relative to Solar Energy, included an extension and expansion of net metering, a policy which has supported the development of most solar projects in Massachusetts to date.  But because the state's solar renewable energy certificate (SREC) program is reaching its end, the recent law also directed the Department to "develop a statewide solar incentive program to encourage the continued development of solar renewable energy generating sources by residential, commercial, governmental and industrial electricity customers."

The 2016 law specified certain required characteristics of the "next generation" solar incentive program, including that it must be one which: "promotes the orderly transition to a stable and self-sustaining solar market at a reasonable cost to ratepayers," considers underlying system costs, takes into account electricity revenues and incentives, relies on market-based mechanisms or price signals, minimizes costs and barriers, features a declining incentive framework, differentiates incentive levels, "ensures that the utility customer realizes the direct benefits of the solar incentive program," considers the value of distributed generation and encourages solar generation where it benefits the distribution system, shares program costs collectively among all ratepayers, and promotes investor confidence through long-term incentive revenue certainty and market stability.

DOER released its "Next Generation Incentive Straw Proposal" on September 23.  Highlights include:

• DOER believes that a tariff-based incentive program would be best mechanism to continue supporting solar at the lowest cost to ratepayers.
• Incentive values would be based primarily on project size, with "adders" for different types of project (based on location, off-taker, or policy considerations like promoting energy storage).
• Project eligibility criteria include being connected to the electric grid in Massachusetts, interconnected on or after January 1, 2017, and not being qualified under the previous SREC I or SREC II programs.
• Siting criteria are included - for example, ground mounted projects would be prohibited if sited in certain wetlands, prime farmlands or forest land, or permanently protected open space.
• Changes to "solar canopy" policy, to allow solar canopies to be installed on agricultural land and over canals.
• Additional support for solar facilities serving low-income properties.

DOER noted that implementing this vision would require rulemaking by DOER, as well as a proceeding before the Department of Public Utilities regarding tariffs.

DOER is accepting written comments on the proposed program design until October 28, 2016.

Northern Pass Transmission public utility status

New Hampshire utility regulators have issued an order conditionally authorizing Northern Pass Transmission LLC to operate as a public utility, with respect to its proposed 192-mile, high-voltage electric transmission line from Canada into New Hampshire.  The New Hampshire Public Utilities Commission's Order No. 25,953 approves a settlement agreement between the transmission line developer and Commission staff.  Among its conditions are requirements that NPT obtain all necessary permits, contribute $20 million over 10 years to support energy efficiency and clean energy initiatives, and hold New Hampshire electric ratepayers harmless from costs associated with the possible regional allocation of costs for a portion of the Northern Pass transmission line.

Proposed by two companies affiliated under the Eversource family -- Northern Pass Transmission LLC and Public Service Company of New Hampshire d/b/a Eversource Energy -- the Northern Pass line would include new direct current transmission lines and an AC-DC converter station.  A variety of federal and state approvals are required for the line's development, including certification of site and facility by the state Site Evaluation Commission, plus several approvals from the Public Utilities Commission.

NPT secured one of those approvals this month, in the form of Public Utilities Commission Order No. 25,953, which conditionally authorizes NPT to operate as a public utilities in municipalities along its route.  In the Order, the Commission found "that NPT has the necessary technical, managerial, and financial expertise to operate as a public utility."

The Commission next found that the terms and conditions of a settlement agreement between Commission staff and NPT "ensure that granting NPT authority to commence business as a public utility is for the public good."

• First, the Commission noted public benefit, in the form of transparency, from the fact that the settlement recites a list of applicable statutes and rules.
• Second, the settlement called for a $20 million public interest payment, to be paid in installments of $2 million per year over the first 10 years of the operation of the Northern Pass Project; the Commission noted that this payment "will benefit customers by allowing the Commission to direct the use of this payment to energy efficiency programs and clean energy projects under its supervision."
• Third, the Commission noted that its grant of public utility status is conditioned on NPT procuring all necessary approvals for the Northern Pass Project, including obtaining a certificate of site and facility from the SEC.
• Finally, the Commission noted a provision in the settlement that "NPT must hold New Hampshire electric ratepayers harmless from costs associated with the possible regional allocation of costs for a portion of the Northern Pass transmission line."  The Commission expressed a belief "that the rate treatment provision applicable to the DC portion of the line could constitute a significant benefit to ratepayers in the event the ISO-NE designates this portion as eligible for regional cost recovery.

On this basis, the Commission approved the settlement agreement in its entirety, adopted its conditions, and found that commencement of business as public utility subject to those terms and conditions will be for the public good.

Meanwhile, NPT continues to pursue other approvals, such as PUC approval for crossings of public waters, and the SEC certificate of site and facility itself.

Post-Aliso Canyon gas storage report

A task force has released its report on the safety of underground natural gas storage, following the Aliso Canyon leak in California.  The Interagency Task Force on Natural Gas Storage Safety was formed by Congress and the Obama administration to analyze what happened at Aliso Canyon and to recommend actions to reduce the likelihood of future leaks from underground natural gas storage facilities. Its final report, "Ensuring Safe and Reliable Underground Natural Gas Storage," presents the task force's findings.

Natural gas is an important fuel used for heat and electric power generation, currently meeting about 30% of U.S. energy needs, as well as industrial processes.  Over 400 natural gas storage facilities exist in the U.S., balancing supply and demand for the fuel, and providing quick access to large volumes of gas during times of high demand like cold snaps or heat waves.

On October 23, 2015, Southern California Gas Company (SoCalGas) discovered a methane leak from its Aliso Canyon Storage Field in Los Angeles County.  Drilled into a sandstone formation approximately 8,500 feet below ground, the Aliso Canyon facility is among the nation's largest natural gas storage facilities, with a total storage capacity of 86 billion cubic feet (bcf) of gas.  The leak, which became the largest such leak in U.S. history, continued for nearly four months until it was permanently sealed. The task force report states that the leak initially released approximately 53 metric tons of methane per hour, for a total of approximately 1,300 metric tons of methane per day.

The Aliso Canyon incident provoked intense concern about what happened, and how future events could be avoided.  Congress enacted the SAFE PIPES Act, and a group of administrative agencies convened as the Interagency Task Force on Natural Gas Storage Safety.

The task force has now released its report, which provides over 40 recommendations relating to well integrity, health and the environment, and reliability.  Key recommendations include development by gas storage operators of an evaluation program to develop a baseline for well status and generally phase out old wells with single-point-of-failure designs, preparing for leaks and coordinating on emergency response, and developing power system planners' and operators' understanding of the risks that gas storage disruptions could create for the electric system.

Meanwhile, a state investigation into the Aliso Canyon leak remains ongoing.

Massachusetts climate change executive order

Massachusetts Governor Charlie Baker signed an executive order last month setting a comprehensive approach to climate change.  Executive Order No. 569, Establishing An Integrated Climate Change Strategy for the Commonwealth, directs state agencies to take a portfolio of actions to reduce greenhouse gas emissions, protect against the impacts of climate change, and improve resilience.

The order opens with acknowledgements that climate change and associated extreme weather events present serious threats.  It also notes the state's Global Warming Solutions Act, and the greenhouse gas emissions limits mandated by that law -- a 25% reduction below 1990 levels, achieved by 2020.  Following a decision by the Massachusetts Supreme Judicial Court earlier this year, regulations under that law must establish "declining annual aggregate emissions" for greenhouse gases.

Turning to action items, Executive Order No. 569 requires the Secretary of Energy and Environmental Affairs to publish a "comprehensive energy plan" within 2 years, with an update every 5 years thereafter.

The executive order also requires the Department of Environmental Protection to issue regulations to ensure that Massachusetts meets the 2020 statewide emissions limit required by the Global Warming Solutions Act.   Pursuant to the executive order, these regulations must be finally promulgated by August 11, 2017.

Executive Order No. 569 also requires coordination between the state's Energy and Environmental Affairs and Public Safety offices, with respect to strengthening community resilience, preparing for the impacts of climate change, and preparing for and mitigating damage from extreme weather events.  Within 2 years, this coordination will result in a Climate Adaptation Plan presenting a statewide adaptation strategy.

Pan-Canadian carbon pricing approach

All Canadian jurisdictions will have put a price on carbon pollution by 2018, according to a speech earlier this month by Canadian Prime Minister Justin Trudeau. The federal government's "pan-Canadian approach" sets a nationwide benchmark, while giving provinces flexibility to choose a cap-and-trade system or a direct price on carbon pollution.

On October 3, Prime Minister Trudeau announced the approach.  He proposed a minimum pricing of $10 per tonne in 2018, rising by $10 each year to $50 per tonne in 2022.  Provinces and territories may choose a direct carbon tax consistent with that pricing, or may elect a cap-and-trade system capable of yielding emissions decreases in line with both Canada's federal target of 30% emissions reduction by 2030, and the reductions expected in jurisdictions that choose a price-based system.  For any jurisdiction failing to adopt price or cap and trade by 2018, the federal government will implement a price.  As announced, the policy will be revenue neutral for the federal government; all revenues will stay in the province or territory where they originated.

In further releases, the government called for a "common scope," meaning that pricing of greenhouse gas emissions will be applied to a common and broad set of sources to ensure effectiveness and minimize interprovincial competitiveness impacts.  The categorization of sources subject to British Columbia's carbon tax is cited as a minimal example of this scope.

The plan calls for a review of the carbon pricing program in 5 years, to ensure its effectiveness, confirm future price increases, and account for actions by other countries.

As of 2017, four provinces will already have carbon pricing compatible with these standards: Alberta, British Columbia, Ontario, and Quebec.  Meanwhile, U.S. efforts to regulate carbon emissions from the electric power sector -- through the Environmental Protection Agency's Clean Power Plan -- remain under judicial challenge.

Drought and state water utility regulation

As drought affects parts of the U.S., some state regulators have expressed concerns over whether shortages will cause water supply emergencies for water utilities.  A recent Notice of Inquiry issued by the Maine Public Utilities Commission illustrates one approach to regulation of water supply management.

New England is abnormally dry this fall.  According to the U.S. Drought Monitor's National Drought Summary for October 11, 2016, "All areas except extreme northern Maine are now in abnormally dry or drought status. Moderate drought was expanded over eastern New York and Vermont while severe drought was expanded in southern New York and northern New Jersey."

Drought can mean water shortages, both for water utilities and for their customers.  As noted by the Maine Public Utilities Commission in an October 5, 2016 Notice of Inquiry into water supply issues, "Some are as of Maine are currently experiencing the impacts of drought. Some of Maine's water systems, which are located in areas where sources of supply are limited , are particularly challenged during dry conditions. In addition to a limited source of supply, some of these systems may also be disproportionately affected by seasonal demands, antiquated infrastructure, and/or high levels of non-revenue water."

As a result, the Commission opened an inquiry "to gather information that will allow it to identify problems which may exist, solicit input on ways to address any problems that are identified, and work collaboratively and proactively with Maine's water utilities and their customers, as well as other State agencies and interested persons and organizations, to develop a plan for addressing the problems that are identified."  The Commission also indicated interest in challenges other than drought that may significantly constrain a utility's source of supply.

The Commission divided its questions into two primary categories.  The first set seeks information to help the Commission to identify current and potential water supply problems and specific solutions to those problems.  These questions relate to recent water supply problems and their impacts, utility responses like voluntary or mandatory conservation measures, and communications with state agencies.

The Commission's second set of questions seeks input on what procedural steps the Commission should take to best address those problems.  This second set focuses on "the extent to which the Commission should be proactively involved in the development of a plan to deal with water supply emergencies and how the Commission should respond when a water supply emergency occurs."
 
The Commission requested that comments and responses be filed in Docket No. 2016-00233 by November 4, 2016.

Substation security and the Garkane shooting

As the U.S. strengthens protections for its electricity grid, much of the discussion focuses on cybersecurity -- but physical security is also important, as shown by an attack on a Utah utility's substation.  On September 25, an unknown gunman fired at least 3 shots into a distribution system substation, damaging a transformer and causing power outages.  The incident may place renewed pressure on utilities to secure their infrastructure against vandalism and terrorism.

As reported by the Deseret News, the damage occurred at a substation owned by Garkane Energy Cooperative.  An assailant reportedly shot the main transformer's oil-cooled radiator system, causing the transformer to overheat and fail.  About 13,000 customers lost power across most of Kane and Garfield counties.  A spokesman for the cooperative said damage to the transformer could reach $1 million; repairs could take 6 to 12 months.  The utility has offered an unusually high reward -- $50,000 -- for information leading to the arrest of the shooter.

This is not the first time someone has used firearms to damage utility infrastructure.  Some incidents, such as the 2012 shotgunning of 167 insulating discs on Vermont's transmission system, may be considered vandalism.  Others, like the 2013 sniper shooting of a PG&E substation in San Jose, California, are considered terrorism.  That attack led the Federal Energy Regulatory Commission to implement new physical security protections for utility infrastructure known as CIP-014, through its Order No. 802.

The Garkane incident remains under investigation.  More broadly, it may strengthen calls for further hardening of the utility system against physical attack.  Meanwhile, efforts continue to strengthen cybersecurity protections for the grid.

Electric storage resources technical conference set

U.S. energy regulators have scheduled a technical conference to discuss electric storage resources and how they could fit into the electric grid -- and how they might be compensated for doing so.  The Federal Energy Regulatory Commission will convene the discussion on November 9, 2016.

An electric storage resource is a facility that can receive electric energy from the grid and store it for later injection of electricity back to the grid.  Different projects might use different storage mediums -- for example, batteries, flywheels, or pumped hydropower.  A storage resource could be as small as a household battery, or as large as gigawatt-scale pumped storage. Projects could be interconnected in various ways -- such as to the transmission system, distribution system, or behind a customer meter -- and could serve different markets, ranging from regional transmission organizations and independent system operators, to transmission or distribution utilities, to customers or end users of electricity.

While each energy storage resource configuration offers its own different advantages and disadvantages from various perspectives, overall the Commission has noted that "storage resources may fit into one or more of the traditional asset functions of generation, transmission, and distribution."  In the Commission's Notice of Technical Conference, it expressed a desire "to explore the circumstances under which it may be appropriate for electric storage resources to provide multiple services, whether the RTO/ISO tariffs need to include provisions to accommodate these business models, and how the Commission may ensure just and reasonable compensation for these resources in the RTO/ISO markets."

The specific subject of the conference described in the Notice is "the utilization of electric storage resources as transmission assets compensated through transmission rates, for grid support services that are compensated in other ways, and for multiple services."  The Notice also sets up discussion of other issues including

(1) potential models for cost recovery for electric storage resources utilized as transmission assets, while also selling energy, capacity or ancillary services at wholesale;

(2) potential models to enable an electric storage resource to provide a compensated grid support service (like a generator providing  ancillary services under a reliability must-run contract) rather than being compensated for providing transmission service; and

(3) practical considerations for electric storage resources providing multiple services at once (i.e., providing both wholesale service(s) and retail and/or end-use service(s)). 

FERC will webcast and transcribe the conference, in addition to allowing in-person attendance.  The Commision directed those wishing to participate to submit a nomination form online by 5:00 p.m. on October 14, 2016.

Energy storage is attracting increased interest.  In another open docket, the Commission issued a series of data requests and a request for public comment in an effort to identify barriers to electric storage resources' participation in organized electricity markets in the U.S that could lead to unjust and unreasonable wholesale electricity rates.  In 2009, then-Chairman Wellinghoff testified before the Senate Committee on Energy and Natural Resources on the role of grid-scale energy storage as it relates to U.S. energy and climate goals, including its ability to integrate variable resources such as wind and solar into the grid.  Meanwhile, states too are pursuing storage opportunities.  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.

Massachusetts energy storage report

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

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

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

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

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

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

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.