NY offshore wind lease auction set

Monday, October 31, 2016

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

Friday, October 28, 2016

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

Thursday, October 27, 2016

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

Monday, October 24, 2016

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

Thursday, October 20, 2016

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

Wednesday, October 19, 2016

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

Tuesday, October 18, 2016

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

Tuesday, October 11, 2016

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

Tuesday, October 4, 2016

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.