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."