Energy policy in the 2018 State of the Union

Wednesday, January 31, 2018

U.S. President Donald Trump delivered the 2018 edition of the State of the Union speech on January 30, 2018. Unlike many previous such addresses, this one barely covered energy policy, focusing instead on a variety of other matters. But the speech offers insight into the Trump administration's view of the national situation, as well as into its priorities.

Energy policy and resources have often featured prominently in previous State of the Union addresses, and in remarks in 2017 President Trump advocated for a national strategy of "energy dominance." By contrast, President Trump's 2018 State of the Union speech mentioned U.S. regulation, production, and trade in energy only briefly, emphasizing his deregulatory agenda and pro-export philosophy.

The Trump administration posted an online version of his 2018 remarks as prepared for delivery. In that version, only two sentences use the word "energy":
We have ended the war on American Energy — and we have ended the war on clean coal.  We are now an exporter of energy to the world.
A transcript released by the U.K. media source The Independent suggests President Trump stuck close to his script on this (and other points):
We have ended the war on American energy, and we have ended the war on beautiful clean coal. We are now very proudly an exporter of energy to the world. 
These statements appear to relate to announcements made over the last year. Back in March 2017, President Trump signed an executive order which he described as "putting an end to the war on coal. We’re going to have clean coal — really clean coal." The U.S. does export a significant amount of energy -- and last year the Energy Information Administration projected that the U.S. would likely become a net exporter of energy within several years "as petroleum liquid imports fall and natural gas exports rise." Subsequent developments over the last year have lent preliminary support to this prediction.

President Trump's 2018 State of the Union speech did not otherwise directly address energy policy. That said, he did emphasize policy goals and achievements with respect to economic factors, such as tax cuts, job creation in manufacturing and other sectors, and improved small business confidence, as well as matters like national defense and immigration.

It can be tempting to infer administrative priorities from what is or isn't covered in a speech like this. At the same time, any leader has limited time to cover a host of important topics. With respect to energy matters, the speech emphasizes the Trump administration's focus on reducing regulations and increasing exports of America-produced energy resources.

Nova Scotia tidal energy demonstration projects

Tuesday, January 30, 2018

The Canadian province of Nova Scotia is seeking applications from tidal energy project developers for permits for tidal energy demonstration projects.

Nova Scotia is home to significant tidal energy potential. According to the provincial Department of Energy, the Bay of Fundy tides offer "an estimated potential of up to 60,000 megawatts (MW) of energy, of which up to 2,500 MW may be extracted without significant impact on our marine environment." The province adopted a Marine Renewable Energy Strategy in 2012, and a legislative framework for marine renewable energy in 2015. It is home to the 20 megawatt barrage-based Annapolis Royal Tidal Power Plant, and has taken steps to encourage research and development into tidal energy technologies.

Opportunities for Nova Scotia tidal energy demonstration projects have just expanded again. On January 24, 2018, the province announced that applications are now available for tidal energy demonstration permits under a recent amendment to the provincial Marine Renewable-Energy Act. Under the amended Nova Scotia tidal energy demonstration program, a demonstration permit allows for the development of a project consisting of up to 5 megawatts of aggregate capacity. No more than 10 megawatts of total power can be authorized under the program, which targets two specific "areas of priority for marine renewable energy developments": Bay of Fundy and the Bras d’Or Lake inland-sea.

The Nova Scotia demonstration permit program is designed to create "another way for developers to test and prove their ideas for innovative new devices," while allowing regulatory oversight of environmental and other concerns. For example, developers still must obtain all applicable permits and approvals. For tidal projects that could generate two megawatts or more, the process includes an environmental assessment approval. At the same time, the amended program significantly expands the area of waters where tidal demonstration projects may be permitted, and gives permittees the opportunity to sell the electricity they generate.

Massachusetts picks Northern Pass bid

Thursday, January 25, 2018

According to a website associated with a clean energy solicitation for Massachusetts electric utilities, the bid committee has selected a proposal called "Northern Pass Transmission, Hydro" as the winning bid. While further steps lay ahead, the agreement that could result would represent a long-term commitment to purchase of about 9,450,000 megawatt-hours of clean energy annually for Massachusetts electric customers -- and lead to the development of a major new electric transmission line from Canada into New England.

The so-called Massachusetts Section 83D process is one of several ongoing renewable energy procurements in New England. Legislation enacted in Massachusetts in 2016 amended the existing Green Communities Act to add a new Section 83D calling for joint utility procurement of significant amounts of "clean" energy, defined to include firm service hydroelectric generation. The Massachusetts electric distribution companies issued their Request for Proposals for Long-term Contracts for Clean Energy Projects pursuant to Section 83D on March 31, 2017, in coordination with the Massachusetts Department of Energy Resources.

The 83D solicitation called for bids by July 27, 2017. Public copies of the bids received, including a proposal labeled NPT Hydro, are posted on the program's website. The transmittal letter for the NPT Hydro project describes a joint proposal by Hydro-Quebec affiliate Hydro Renewable Energy Inc. and Northern Pass Transmission LLC. As described by Northern Pass in its bid and other documents, the project includes a new 192-mile transmission line importing 1,090 megawatts of firm clean energy from Quebec into New Hampshire. The proposal describes the project as shovel-ready, with a targeted in-service date of 2020.

According to the website, final acceptance of the bid and the award of a contract is conditional upon additional steps. These include the successful negotiation of the contract and required regulatory approval at the Massachusetts Department of Public Utilities. The notice also states that if this bid selected to advance to contract negotiation does not result in actual contracts, other bids may be selected for contract negotiations.

The siting of the project has been controversial for its impacts on the White Mountain National Forest and nearby northern New Hampshire forestlands, prompting a redesigned route with more cable mileage installed underground to address scenic impacts. The New Hampshire Site Evaluation Committee recently concluded hearings on applications for the Northern Pass Transmission project's development, with a decision by the Committee expected this year.

NYC tidal project asks for more time

The holder of a pilot license for a hydrokinetic energy project under development off New York City has asked federal regulators for a 5-year extension of the license term, and has signaled its intent to relicense the project.

At issue is Verdant Power's Roosevelt Island Tidal Energy (RITE) Project, located in the tidal East Channel of the East River between Manhattan and Long Island. The Federal Energy Regulatory Commission issued Verdant Power a 10-year pilot project license on January 23, 2012. The license describes a phased project, starting with deployment of three 35-kW hydrokinetic turbine-generator systems, and ultimately capable of scaling up to a total of 30 turbines, for a total nameplate capacity of 1,050 kilowatts. Hydrokinetic projects generate electricity from waves or directly from the flow of water in ocean currents, tides, or inland waterways, generally without creating new dams or impoundments.

The RITE Project's pilot license was the first to be issued by the Commission through a special hydrokinetic pilot project licensing process which it designed to let developers test technologies and sites without compromising the Commission’s oversight of the projects or limiting agency and stakeholder input. As defined by the Commission, a pilot project license authorizes the construction, operation, and maintenance of an original (i.e., unconstructed) hydrokinetic project that is:
  1. small (5 megawatts or less);
  2. easily removed or shut down quickly;
  3. located in a non-sensitive area; and
  4. has the primary purpose of testing new technologies or locating suitable generation sites.
Since the RITE Project's pilot license issued, Verdant says it has taken steps including maintaining a control room and ancillary equipment, conducting an in-water test of turbine rotor components, beta-tested environmental equipment, and beginning environmental monitoring as required by its license.

But the licensee would like more time. According to a letter filed with the Commission on December 29, 2017, "Verdant Power is poised to install the first phase of the licensed Pilot Project (Install B-1) in the 2019-20 timeframe. This installation will represent a significant milestone in the advancement of hydrokinetic energy in the US." In that letter, Verdant requested a 5-year extension of its pilot license. Also on December 29, Verdant Power submitted a document it described as its notice of intent to apply for a new license for the RITE project.

The docket remains open before the Commission.

New England Operational Fuel-Security Analysis released

Tuesday, January 23, 2018

The risk that power plants will run out of fuel is the foremost challenge to a reliable power grid in New England, according to the region's grid operator, and the region is vulnerable to the season-long outage of any of several major energy facilities.

While the ability to count on a portfolio of power plants to generate power is considered the cornerstone of reliable electricity supply, ISO New England has noted several factors that make fuel security a growing concern for the region. These factors include the inadequacy of the region’s natural gas infrastructure to meet winter needs for both heating and power, and the retirement of many of the region’s coal, oil, and nuclear power plants due to economic and environmental pressures.

On January 17, 2018, ISO New England released its Operational Fuel-Security Analysis, a 56-page report studying the possible fuel security risks facing region's power plants under a wide range of hypothetical future scenarios. Prepared following about two years of study, the report found that maintaining the electric grid's reliability "is likely to become more challenging, especially if current power system trends continue."

The report considered a 23 possible range of possible future power resource combinations that could materialize for the winter period from December 1, 2024 through February 28, 2025, to examine whether enough fuel would be available to meet demand and to quantify the operational risks. Each scenario assumed no new natural gas pipeline capacity would be added to serve generators, but considered variation in five other key factors for power system reliability: resource retirements, LNG availability, oil tank inventories, imported electricity, and renewable resources.

ISO-NE chart of Hours of Emergency Actions under Modeled Scenarios, Ordered Least to Most, Operational Fuel-Security Analysis (2018)

The study identified six major conclusions:
  1. Outages: The region is vulnerable to the season-long outage of any of several major energy facilities.
  2. Stored fuels: Power system reliability is heavily dependent on LNG and electricity imports; more dual-fuel capability is also a key reliability factor, but permitting for construction and emissions is difficult.
  3. Logistics: The timely availability of fuel is critical, highlighting the importance of fuel-delivery logistics.
  4. Risk trends: All but four scenarios result in fuel shortages requiring load shedding, indicating the trends affecting New England’s power system may intensify the region’s fuel-security risk.
  5. Renewables: More renewable resources can help lessen the region’s fuel-security risk but are likely to drive coal- and oil-fired generation retirements, requiring high LNG imports to counteract the loss of stored fuels.
  6. Positive outcomes: Higher levels of LNG, imports, and renewables can minimize system stress and maintain reliability; to attain these higher levels, delivery assurances for LNG and electricity imports, as well as transmission expansion, will be needed.
According to ISO-NE, quantifying the level of risk over a wide range of possible combinations provides information the region can use to consider approaches to ensuring power system reliability. The grid operator has said it plans to engage with stakeholders, regulators, and policymakers through 2018 to discuss the operational fuel-security analysis -- and how much risk the ISO and region would be willing to tolerate.

Energy dept adopts grid emergency order rule

Wednesday, January 17, 2018

U.S. energy regulators have issued a final rule governing the procedures through which the Secretary of Energy may issue an emergency order under the Federal Power Act to respond to an electric grid security emergency.

Under the Fixing America's Surface Transportation Act of 2015, Congress authorized the Secretary of Energy to order emergency measures after the President declares a grid security emergency. Such an emergency could occur as the result of a physical attack, a cyber-attack using electronic communication, an electromagnetic pulse (EMP), or a geomagnetic storm event. The FAST Act added these powers to the Federal Power Act, which contained additional language authorizing the Secretary to order temporary emergency measures as needed to serve the public interest.

On January 10, the U.S. Department of Energy published its final rule governing grid security emergency orders.  According to the Department, the procedures established by this final rule "will ensure the expeditious issuance of emergency orders under the Federal Power Act." It says the final rule establishes a "consistent yet flexible set of procedures" for regulatory engagement with impacted parties as the Department issues emergency orders. The Department says it "expects that these emergency orders would be issued rarely," but emphasized its need for flexibility in tailoring a response to the particular circumstances of any grid disruption.

The new final rule is codified in 18 C.F.R. section 205.380 et seq.

FERC license surrender with facilities in place

Friday, January 12, 2018

When a federally licensed hydropower project is decommissioned, U.S. regulators have authority to accept or prescribe plans for the disposition of the project's dams, reservoirs, and other facilities -- and depending on the case, decommissioning plans could range from removing facilities and restoring the site, to leaving some facilities in place.

Under federal law, most U.S. hydropower projects are licensed by the Federal Energy Regulatory Commission – and a license cannot be surrendered without the Commission’s agreement. By regulation, a licensee applying to surrender its license must identify all project features – dams, reservoirs, power plants, transmission lines, etc. – and how they will be disposed.

According to Commission guidance on hydropower license surrender, surrender applications for constructed projects should include a plan for decommissioning the project. The Commission requires decommissioning plans to address any dam safety or environmental concerns that could remain after the license is surrendered. But the nature and scope of decommissioning activities can vary, from leaving project features in-place for other uses, to removing project features restoring the site. The Commission encourages licensees considering a surrender application to consult with other regulatory agencies and stakeholders, in part to inform the development of a decommissioning plan.

An order issued in 2016 provides an example of a license surrender where facilities were allowed to be left in place. On May 3, 2016, the Commission issued an order accepting the surrender of the license for the 23-kilowatt Burnham Creek Hydroelectric Project in Washington. Originally licensed in 1987 for a 50-year term, the project facilities include a 20-foot-high earthen dam, a 5-acre reservoir, intake, penstock, powerhouse, generating unit, and transmission line. But the Burnham Creek project has not generated electricity since its power line was damaged by a windstorm in 2007.

In 2012, after consulting with various agencies and stakeholder entities, the project licensee filed an application to surrender her license, stating that the cost to repair the power line was too great when weighed against the benefits of the project. In her surrender application, the licensee proposed to leave the project "in place", in its current condition, with no ground-disturbing work, and without removing the dam, powerhouse, generating unit, or transmission line. No entity filed an objection to the proposed surrender.

The Commission issued its order accepting surrender about three years later. Because the licensee did not propose any ground-disturbing activities and would leave all project facilities in place, the Commission concluded that “the proposed surrender would have no effects to geology and soils, water quality, terrestrial resources, or land use.” For similar reasons, the Commission concluded that “surrendering the project would not constitute a major federal action significantly affecting the quality of the human environment,” reducing the environmental analysis required under federal law.

With respect to dam safety, the Commission noted several potential safety issues (including de-pressurizing the penstock, removing turbine or transformer oil from the powerhouse, and removing or securing the downed portion of transmission line), and made the surrender contingent upon the licensee showing that it had taken certain steps to address those concerns. The Commission also noted that the state of Washington would have jurisdiction over the facilities when, and if, the surrender is finalized.

In some cases, a FERC license surrender and decommissioning plan can entail dam removal. But surrender orders like that issued in the Burnham Creek case, or a similar order accepting surrender for the Columbia Dam project in New Jersey, illustrate the potential for surrendering a hydropower license while leaving most of a project’s facilities in place.

NH approves energy efficiency plan

Wednesday, January 10, 2018

Setting up a significant expansion of New Hampshire's energy efficiency programming, utility regulators have approved the implementation of a $176 million three-year energy efficiency plan for 2018 through 2020 for the state’s gas and electric utilities.

In 2016, the New Hampshire Public Utilities Commission established an Energy Efficiency Resource Standard or EERS, a framework within which the Commission’s energy efficiency programs would be implemented effective January 1, 2018. A group of gas and electric utilities filed a proposed a three-year plan in September 2017, modified in December by a settlement supported by all parties to the case before the Commission.

On January 2, 2018, the New Hampshire Public Utilities Commission issued its Order No. 26,095, approving that settlement. The order approves a three-year plan which "significantly expands the energy efficiency (“EE”) programs implemented for the past several years, known as the Core Programs, to meet the EERS goals established in the 2016 EERS Order."

The plan presents residential and commercial & industrial (including municipal) energy efficiency programs for 2018, 2019, and 2020. Its total three-year electric program budget is $146,115,000, and its total three- year gas program budget is $30,089,000, in each case allocated across customer sectors. These funds would come from charges on electricity and gas customers, plus proceeds from Regional Greenhouse Gas Initiative and regional Forward Capacity Market auctions. It also calls for annual plan updates, which are subject to review and approval by the Commission. 

The Commission found that as modified by the settlement agreement, the three-year plan was consistent with the public interest and with state laws governing energy efficiency and resource planning.

FERC ends DOE resilience rulemaking, opens new proceeding

Tuesday, January 9, 2018

U.S. energy regulators have terminated a fast-tracked proceeding opened last fall to consider rules proposed by the Department of Energy that would have compensated certain electric generating plants for reliability and resilience values; instead, the Federal Energy Regulatory Commission has opened a broader case to examine the resilience of the bulk power system.

On September 29, 2017, Secretary of Energy Rick Perry directed the Commission to consider a proposed rulemaking to ensure that "traditional baseload resources, such as coal and nuclear" are rewarded for their reliability and resilience attributes. As proposed, the rule would have required grid operators to set rates for compensation paid to certain "grid reliability and resiliency resources" with a 90-day fuel supply on site and capable of providing "essential energy and ancillary reliability services, including but not limited to voltage support, frequency services, operating reserves, and reactive power."

The request under Section 403 of the Department of Energy Organization Act bore an expedited timeline. The Commission solicited public comments on the proposed rulemaking, and Commission staff issued a series of questions to frame the discussion. Many comments expressed concerns that rapid changes to wholesale markets could have harmful or perverse effects, and prior to yesterday's most seated Commissioners had publicly expressed reservations.

On January 8, 2018, the Commission issued its Order Terminating Rulemaking Proceeding, Initiating New Proceeding, and Establishing Additional Procedures.  In doing so, it recognized "that we must remain vigilant with respect to resilience challenges, because affordable and reliable electricity is vital to the country’s economic and national security." The order recites a history of the evolution of the electric power industry and the Commission's efforts to help ensure bulk power system resilience, including the adoption of NERC reliability standards, reforms to capacity markets and gas-electric coordination.

But the Commission found that neither the Department of Energy's proposed rulemaking nor the record in the case satisfied a key legal standard for Commission action under Section 206 of the Federal Power Act. Specifically, it concluded that the existing tariffs had not been demonstrated to be unjust, unreasonable, unduly discriminatory or preferential.

The Commission also noted potential problems with the proposed rule. For example, it said that allowing all eligible resources to receive a cost-of -service rate regardless of need or cost to the system had not been demonstrated to be just and reasonable, and that the proposed rule's on-site 90-day fuel supply requirement hadn't been shown not to be unduly discriminatory or preferential -- but that it would exclude some resources with resilience attributes.

At the same time, the order states, "The resilience of the bulk power system will remain a priority of this Commission." It continued, "Although the Proposed Rule failed to satisfy the fundamental legal requirements of section 206 of the FPA, the Proposed Rule and the record developed to date have shed additional light on resilience more generally and on the need for further examination by the Commission and market participants of the risks that the bulk power system faces and possible ways to address those risks in the changing electric markets." Noting "a variety of economic, environmental, and policy drivers that are changing the way electricity is procured and used," the Commission said these changes "present new opportunities and challenges regarding the reliability, affordability, and environmental profile of each region’s electric system."

To address these changes, the Commission initiated a new proceeding, Docket No. AD18- 7-000, to take additional steps to explore resilience issues in organized wholesale electricity markets. According to the order, the goal of this proceeding is: "(1) to develop a common understanding among the Commission, industry, and others of what resilience of the bulk power system means and requires; (2) to understand how each RTO and ISO assesses resilience in its geographic footprint; and (3) to use this information to evaluate whether additional Commission action regarding resilience is appropriate at this time."

The Commission directed six regional transmission organizations and independent system operators to respond within 60 days with comments on the definition of resilience, plus how they assess and mitigate threats to resilience. The Commission also solicited public comment within 30 days of the grid operators' due date.

FERC denies petition re Maine ownership of Forest City dam

Monday, January 8, 2018

A privately owned dam and reservoir spanning the U.S.-Canada border licensed as a hydropower development would continue to require licensing even if owned by a Maine state agency, according to federal regulators -- a ruling which could cast doubt on whether the state will acquire the facilities as has been conditionally authorized.

The Forest City Project on the East Branch of the St. Croix River currently operates under a license issued by the Federal Energy Regulatory Commission to Woodland Pulp LLC on November 23, 2015. While the project does not include electric generation facilities, the Commission has held that its project works are part of a complete unit of development or improvement which includes separate, unlicensed generation facilities.

In 2016, the licensee applied to the Commission to surrender its license and decommission the project because its operating costs as licensed would significantly exceed the downstream hydroelectric generation benefits. State-level interest in maintaining the existence of the impoundment led the Maine legislature to enact a resolve authorizing Maine Department of Inland Fisheries and Wildlife to assume ownership of the Forest City Dam if two conditions are satisfied: (1) the Commission finds that the Forest City Project will not require a license from the Commission if Maine DIFW owns the U.S. portion of the dam; and (2) Maine DIFW executes an agreement with Woodland Pulp that provides that Woodland Pulp and its successors will operate and maintain the Forest City Dam consistent with the manner in which the dam was operated in most recent 12 months, at the direction of the State, and at no cost to the State, for a period of 15 years.

After the Maine legislative resolve became law, the state agency and the licensee executed an operation and management agreement on July 27, 2017, and licensee petitioned the Federal Energy Regulatory Commission for a declaratory order declaring that if Woodland Pulp transfers ownership of the U.S. portion of the project to the Maine DIFW, DIFW will not require a license from the Commission to continue to operate and maintain the Forest City Dam.

But on December 21, 2017, the Commission denied the licensee's petition for a declaratory order to that effect. According to the Commission, this was the licensee's fourth petition seeking a ruling that the Forest City Project does not require licensing, with a fairly lengthy history of litigation. While the Commission noted its power to reexamine findings on jurisdiction where facts such as project ownership have changed, the Commission also noted that "ownership of project works by a state or state agency has no impact on a jurisdictional determination," and that "it is the potential effect on generation of an impoundment – and not its ownership or the operator’s specific intent – that guides our determination of whether a reservoir is necessary or appropriate to a given unit of development under FPA section 3(11) and operates for the purpose of developing electric power under FPA section 23(b)."

The Commission concluded, "we find that the Forest City Project would require licensing even if it was owned by Maine DIFW." In reaching this conclusion, it said, "We understand the concerns regarding Woodland Pulp’s proposed surrender of the Forest City Project and appreciate Woodland Pulp’s and the State of Maine’s effort to avoid adverse effects to local property owners and the local economy." But at the same time, "while we are sensitive to potential effects on local socioeconomics and the environment associated with Woodland Pulp’s proposed license surrender, we cannot consider these effects in determining whether we have jurisdiction over the project."

Given the Commission's ruling that transfering the project to a state agency would not affect its need for licensure, the 2017 state legislative resolve does not authorize the Maine Department of Inland Fisheries and Wildlife to assume ownership of the facility. The project's fate has yet to be determined; the licensee's petition to surrender the license remains pending before the Federal Energy Regulatory Commission.

US proposes offshore oil and gas leasing expansion

Friday, January 5, 2018

The Trump administration is taking steps that could ultimately lead to a significant expansion of U.S. outer continental shelf acreage available for oil and gas leasing.

Under federal law, the U.S. Bureau of Ocean Energy Management is charged with administering site leasing for energy development on the outer continental shelf. The Outer Continental Shelf Lands Act requires the Secretary of the Interior, through BOEM, to develop a five-year national plan for oil and gas sales in federal waters. The law requires the Secretary to balance criteria including environmental impacts, energy needs and resources, and adverse effects on the coastal zone.

On January 4, 2018, Secretary of the Interior Ryan Zinke announced a new Draft Proposed Program. He described its release as "an early step in a multi-year process to develop a final National OCS Program for 2019-2024," and as consistent with an April 2017 Executive Order implementing an "America-First Offshore Energy Strategy."

The Draft Proposed Program includes 47 potential lease sales -- the largest number of lease sales ever proposed for the National OCS Program’s 5-year lease schedule.  The plan includes 19 sales off Alaska, 7 in the Pacific Region, 12 in the Gulf of Mexico, and 9 in the Atlantic Region. Some of these areas have not seen leases sold in decades; for example, there have been no sales in the Atlantic since 1983 and there are no existing leases.

By contrast, the draft program includes 8 Atlantic lease sales between 2020 and 2024, covering federal waters offshore Maine, New Hampshire, Massachusetts, Connecticut, Rhode Island, New York, New Jersey, Delaware, Virginia, North Carolina, South Carolina, Georgia, and Florida. The Pacific leases would similarly be the first sold in that region since 1984.

According to the press release announcing the draft's release, "Inclusion of an area in the DPP is not a final indication that it will be included in the approved Program or offered in a lease sale, because many decision points still remain. By proposing to open these areas for consideration, the Secretary ensures that he will receive public input and analysis on all of the available OCS to better inform future decisions on the National OCS Program."

Even if an area is offered in a lease sale, it may not draw commercial interest; even if leased, an area might not actually be used for exploration and production. But the draft plan significantly expands the acreage that would be available for leasing -- according to the Secretary, "the current program puts 94 percent of the OCS off limits," while the proposed program "proposes to make over 90 percent of the total OCS acreage and more than 98 percent of undiscovered, technically recoverable oil and gas resources in federal offshore areas available to consider for future exploration and development."

BOEM has solicited public comment on the draft plan, which will inform several further rounds of proposals and comment, before a Proposed Final Program (PFP) is considered. In the meantime, until a new program is finalized and adopted, the present 2017-2022 Five Year Program remains in effect.

VT considers standard offer program changes

Thursday, January 4, 2018

Vermont utility regulators are reviewing the effectiveness of a program which awards contracts to renewable energy providers for the sale of power to Vermont’s electric distribution utilities. The Vermont Public Utility Commission says its review of the state's standard-offer program could lead to changes to how it selects projects.

Vermont law establishes a standard-offer program for reasons including providing “support and incentives to locate renewable energy plants of small and moderate size in a manner that is distributed across the State’s electric grid, including locating such plants in areas that will provide benefit to the operation and management of that grid through such means as reducing line losses and addressing transmission and distribution constraints." The statute empowers the Commission to select resources for participation in the standard-offer program, and to set prices paid to standard-offer resources, “with a goal of ensuring timely development at the lowest feasible cost."

Between 2013 and 2017, the Commission (under its former name Vermont Public Service Board) conducted annual requests for proposals for distributed energy projects through the standard-offer program. Under its current market-based approach established in 2013, the Commission sets minimum requirements for responsive proposals and selects the lowest-priced eligible proposals in several technology categories.

But as the Commission noted in its December 29, 2017 order opening a proceeding to review the effectiveness of the standard-offer program, "The field of distributed generation in Vermont has evolved significantly since 2013, when the Commission first announced many of the requirements of the standard-offer RFP process." For example, the order notes "significant deployment of net-metered photovoltaic systems and other photovoltaic systems." The Commission says, "some areas of the state have experienced such significant growth in photovoltaic systems that portions of the distribution grid cannot accommodate additional generation resources without investments in additional infrastructure."

In this context, the Commission opened a proceeding "to generally assess the effectiveness of the current RFP process and the criteria that the Commission uses to award standard-offer contracts." In its order opening the proceeding, the Commission articulated a series of questions addressing project selection criteria and possible integration of energy storage systems.

The Commission requested comments by February 2, 2018, and stated its expectation "that any improvements to the standard-offer program developed in this proceeding would not take effect until the 2019 RFP, or later."

FERC may change natural gas pipeline policy

Wednesday, January 3, 2018

U.S. energy regulators have signaled potential changes to a decades-old policy on the certification and pricing of new interstate natural gas pipelines.

The Federal Energy Regulatory Commission is charged by the Natural Gas Act with regulating the transmission and sale of natural gas for resale in interstate commerce, and approving the siting and abandonment of interstate natural gas pipelines and storage facilities.

In 1999, the Commission issued a Statement of Policy "to provide the industry with guidance as to how the Commission will evaluate proposals for certificating new construction." The FERC's 1999 policy statement came about at a time when the Commission faced both pressure "to authorize new pipeline capacity to meet an anticipated increase in the demand for natural gas" and "to act with caution to avoid unnecessary rights-of-way and the potential for overbuilding with the consequent effects on existing pipelines and their captive customers." In adopting the 1999 policy statement, the Commission said its publication was intended "to provide more certainty as to how the Commission will analyze certificate applications to balance these concerns."

But the Commission could soon change its policies.  Last month, on December 21, 2017, Commission Chairman Kevin J. McIntyre issued a statement that the Commission will consider changes to the 1999 policy statement, "as part of a pledge he made during his Senate confirmation to take a fresh look at all aspects of the agency’s work."

According to that statement, while next steps will soon be announced and scheduled, "any review of this type would be thorough, and the Commission would invite the views of all stakeholders to ensure that FERC accurately and efficiently assesses the pipeline applications it receives."