Acadia proposes parking reservation system

Acadia National Park in coastal Maine has released a draft planning document presenting possible actions to address increasing visitor vehicle traffic. The park's Draft Transportation Plan and Environmental Impact Statement proposes to adopt a timed-entry reservation system for some parking lots and roads in the park. The issue raises questions about infrastructure in national parks, and how to balance competing interests in resource management.

A coastal scene near Acadia National Park.

According to the National Park Service, annual visitation to Acadia National park grew by 58% between 2006 and 2016, exceeding 3 million visits per year. Most of these visits occur from June to October. But while visitor traffic has increased, some park infrastructure hasn't kept up with demand. For example, the Park Service has said that parking spaces in many areas are insufficient to meet visitor needs, and that increased traffic volumes and speeds have created safety issues, resource protection concerns, and adverse impacts to visitor enjoyment.

To address these issues, the National Park Service has proposed changes to how it manages Acadia National Park. On April 26, 2018, Acadia National Park posted its Draft Transportation Plan and Environmental Impact Statement (EIS). It identifies a preferred alternative (labeled "Alternative C" in the report) and proposed action focused on management of certain corridors within the park .

Alternative C would start by establishing a timed-entry reservation system for the Ocean Drive corridor, Cadillac Summit Road, and the Jordan Pond House North Lot during peak use season, with an adaptive management strategy that could lead to an expansion of the area within which reservations would be required. Alternative C also includes an eventual elimination of right-lane parking along the Park Loop Road, plus changes to some parking lots, among other items.

Beyond the corridor management plan presented as Alternative C, the Draft Transportation Plan also considers alternatives including taking no action, a site-specific management approach, and systemwide management of the Park Loop Road.

The National Park Service has invited public comments on Acadia's Draft Transportation Plan and EIS until June 26. The agency will hold public meetings and information sessions in the area, as well as a virtual online session.

FERC Order 845 reforms interconnection process

U.S. utility regulators have issued an order adopting a final rule reforming the procedures through which electric generators obtain interconnections to the utility grid. The Federal Energy Regulatory Commission's Order No. 845 adopts a final rule which implements ten specific reforms designed to provide interconnection customers better information and more options, in the hopes that transmission providers will better be able to focus on interconnection requests that are likely to reach commercial operation.

Generally speaking, generators need to interconnect to the utility grid (and to consumers) for their power to be valuable. Under the Federal Power Act, many generator interconnections are subject to regulation by the Commission. In December 2016, the Commission issued a Notice of Proposed Rulemaking proposing 14 sets of reforms to its interconnection regulations. In that notice, the Commission cited changes to the electric power industry since the Commission issued its Order No. 2003 governing interconnections, and concerns including long queues and delays for interconnection studies, and a lack of certainty around timing and costs.

As a result, in 2016 the Commission preliminarily found that the interconnection process may hinder the timely development of new generation, and thereby stifle wholesale competition, resulting in rates, terms, and conditions that are not just and reasonable or are unduly discriminatory or preferential. The Commission also preliminarily found the interconnection process could result in uncertainty and inaccurate information, and a potential for discrimination as new technologies enter the market.

Now, following a technical conference and 63 public comments, the Commission issued its order adopting the final rule on April 19, 2018. The final order adopted many of the Commission's 2016 proposals, while deviating from that earlier proposal in some regards.

Among other items, the final rule includes two sets of reforms designed to improve certainty for interconnection customers, four aimed at promoting more informed interconnection decisions, and four designed to enhance the interconnection process.

The Commission also decide to revise its pro forma Large Generator Interconnection Procedures and  Large Generator Interconnection Agreement, to mitigate concerns about systemic inefficiencies, discriminatory utility practices, and time spent on interconnection requests that are unlikely to reach commercial operation.

The final rule, codified as 18 C.F.R. Part 37, will become effective 75 days after its publication in the Federal Register.

Maine citizen petition for greenhouse gas rules

Maine environmental regulators have initiated a rulemaking, after receiving a citizen petition asking for rules to reduce Maine's greenhouse gas emissions by at least 8 percent per year.

According to an April 25, 2018 announcement by the Maine Department of Environmental Protection, on January 24 of this year the Department received a "Citizen Petition for Rulemaking to Require the Maine Department of Environmental Protection to Fulfill its Statutory, Constitutional, and Public Trust Obligations to Reduce Greenhouse Gas Emissions Along a Trajectory that is Based on the Best Climate Science and that will Reduce the Impacts of Climate Change in Maine".

The announcement says the petition was signed by 696 registered voters, was verified and certified, and therefore triggers a statutory requirement that the Department open a rulemaking. Materials posted as having been circulated along with the petition cite sponsors including 350 Maine, Citizens’ Climate Lobby, and Our Children’s Trust, These materials also link the Maine petition to a larger effort led by Our Children’s Trust, which is the force behind the Juliana v. U.S. kids’ climate lawsuit.

The announcement describes the rule requested by petition as creating a new "Greenhouse Gas Emission Standards" rule, which would set a statewide greenhouse gas emission limit for each year beginning in 2020, and would require submission of greenhouse gas emission reduction plans for certain stationary sources and vehicle fleets. According to the announcement, the proposed 8 percent per year reduction is equivalent to Maine reducing its greenhouse gas emissions to approximately 75 percent below 2003 levels by the year 2035.

The proposal would also establish a new rule addressing sulfur hexafluoride emissions from gas-insulated electrical switch gear, and amend ten existing rules to incorporate greenhouse gas standards and cross-reference the new Greenhouse Gas Emission Standards rule.

Maine law allows any person to petition an agency for the adoption or modification of any rule. When 150 or more registered Maine voters submit a petition to adopt or modify a rule, the agency is required to initiate appropriate rulemaking proceedings within 60 days. The Greenhouse Gas Petition Rulemaking will play out before the Maine Department of Environmental Protection.

New England colleges form solar buying partnership

A coalition of New England colleges has formed to purchase electricity from a solar farm in Farmington, Maine. The New England College Renewable Partnership describes itself as the first collaborative purchase of solar electricity in New England higher education.

The New England College Renewable Partnership includes Amherst, Bowdoin, Hampshire, Smith and Williams Colleges. According to an announcement by Amherst, Mount Holyoke and UMass Amherst had also participated in earlier discussions about the project, but later abandoned the project, while Bowdoin joined the group. 

The partnership is collaborating to purchase power from a 25-megawatt solar array under development by a subsidiary of NextEra Energy Resources. Its predicted annual output is about 46,000 megawatt-hours, under a 20-year contract.

Each of the participating colleges describes environmental, financial, and educational benefits from the project. For example, the power purchase agreement reportedly requires that all involved colleges and their student bodies be allowed access to the project site and its data. Initial power deliveries are expected in late 2019. The colleges also cite other benefits from the project, including advancement of their sustainability and climate action initiatives.

Interest in cooperative or collaborative procurement of energy products or projects is rising. By collaborating as purchasers of solar energy, the colleges may have achieved some advantages over their options if going alone. The New England College Renewable Partnership cites its model as providing "market access that would not have been available to individual institutions, offering a scalable model that other colleges and universities can follow."Amherst's announcement explained that while each school has small energy demands, by "increasing the number of schools in the partnership, the group was able to raise the total demand for renewable energy."

Will other institutions follow this model of collaborative procurement of renewable energy?

FERC natural gas pipeline policy under inquiry

U.S. energy infrastructure regulators have launched an inquiry to examine how they review and authorize interstate natural gas transportation facilities under federal law. The process before the Federal Energy Regulatory Commission could lead to changes to the Commission's policies on certification of new natural gas pipelines.

Section 7 of the Natural Gas Act requires any person seeking to construct or operate a facility for the transportation of natural gas in interstate commerce to obtain a certificate of public convenience and necessity from the Commission. The law directs the Commission to issue a certificate to any qualified applicant upon finding that the construction and operation of the proposed project—whether pipeline, storage, or liquefaction facilities—“is or will be required by the present or future public convenience and necessity.” Other laws, such as the National Environmental Policy Act, prescribe additional processes and criteria for environmental review.

The Commission has developed regulations implementing its certification process. In 1999, it issued its current Policy Statement on the topic, “Certification of New Interstate Natural Gas Pipeline Facilities – Statement of Policy” (Docket No. PL99-3-000). As recently described in a statement by Commissioner Chatterjee, "the Certificate Policy Statement has provided a flexible, effective framework for the Commission’s evaluation of natural gas pipeline projects." Proponents cite the value of regulatory predictability, with specific additional benefits including reduced energy prices and increased opportunities in gas production and manufacturing.

But the ensuing 19 years have brought changes to the natural gas industry, as well as increased stakeholder interest in how the Commission reviews proposed new natural gas pipelines. The Commission cites a list of significant changes including "a revolution in natural gas production technology leading to dramatic increases in production"; new areas of major natural gas production and changes in the direction of pipeline system flows; "customers routinely entering into long-term precedent agreements for firm service during the formative stage of potential projects and the use of those precedent agreements as applicants’ principal evidence of the need for their projects"; increased use of natural gas for electric generation; increased concerns about siting and greenhouse gas impacts, and about the Commission's environmental review process.

New commissioners have also taken office. In December 2017, new Chairman McIntyre issued a statement suggesting the Commission would reexamine the 1999 policy statement as part of commitments he made during his Senate confirmation process.

Now, the Commission is following through on that promise. Its April 19, 2018 Notice of Inquiry seeks input on whether, and if so how, the Commission should revise its policies on how it evaluates whether there is a need for a proposed project, and its evaluation of a proposed project's environmental impacts and issues related to eminent domain and landowner interests. Finally, through the inquiry the Commission seeks input on potential procedural improvements to the certification process.

The Commission noted that while the inquiry is pending, the Commission intends to continue processing natural gas facility matters before it consistent with the 1999 policy statement, and to make determinations on the matters raised in those proceedings on a case-by-case basis.

BOEM proposes Massachusetts offshore wind lease auction

U.S. ocean energy regulators have announced the proposed lease sale of two new areas offshore Massachusetts for commercial wind energy leasing, totaling about 390,000 acres.

On April 6, 2018, U.S. Secretary of the Interior Ryan Zinke announced that the Bureau of Ocean Energy Management would publish a Proposed Sale Notice for Commercial Leasing for Wind Power on the Outer Continental Shelf Offshore Massachusetts on April 11, 2018.

Through that Proposed Sale Notice, BOEM described its plans to conduct Atlantic Wind Lease Sale 4A. That auction would offer two lease areas offshore Massachusetts for potential commercial wind energy development: Lease OCS-A 0502 consisting of 248,015 acres, and Lease OCS-A 0503 consisting of 140,554 acres. These lease areas were previously offered in 2015, but were not sold.

The Proposed Sale Notice solicits reaffirmations of continued interest from previously qualified prospective bidders -- including 11 entities that qualified to participate in the 2015 Massachusetts lease sale. It also solicits qualification packages from any prospective bidders that BOEM has not previously qualified for a Massachusetts lease sale. The proposal also comes with a 60-day public comment period.

Following the public comment period, if BOEM proceeds with the Massachusetts lease auction, the agency will eventually publish a Final Sale Notice announcing the time and date of the lease sale. 

To date, the Bureau of Ocean Energy Management has awarded 13 commercial offshore wind leases, including sites off every state from Massachusetts to North Carolina.

Virginia might join RGGI, if compatible

Will Virginia adopt regulations for greenhouse gas emissions trading that enable it to join nine other states participating in the Regional Greenhouse Gas Initiative?

The Regional Greenhouse Gas Initiative, or RGGI, is the first mandatory market-based program in the United States to reduce greenhouse gas emissions. RGGI was formed in 2007 by agreement of participating states. At present, nine states participate in RGGI: Connecticut, Delaware, Maine, Maryland, Massachusetts, New Hampshire, New York, Rhode Island, and Vermont. Each participating state has adopted regulations under its own state laws, based on a model rule which requires the electric power sector to cap and reduce CO₂ emissions, and which creates markets for trading emission allowances.

Virginia has not been a RGGI participant, but earlier this year the Virginia Department of Environmental Quality proposed a regulation to address carbon emissions from electric power generation. The proposed Virginia regulation would establish a Virginia component of a CO₂ Budget Trading Program, much like RGGI.

On April 9, 2018, the nine states participating in RGGI submitted comments on key key program elements identified in Virginia’s proposed regulation for emissions trading, including the regulatory compatibility of Virginia’s proposal with RGGI’s existing 2017 Model Rule. In those comments, the RGGI states encourage "Virginia’s progress towards implementing a market-based program to reduce greenhouse gas emissions" and cite benefits from both the RGGI program and expanding its trading markets.

The RGGI states' comments also note the importance of ensuring that Virginia would be fully compatible with RGGI before entering it. The comments identify potential topics for assessing Virginia's potential compatibility as including "the alignment of key program elements, consistency in the use of regulatory language (such as the definitions of particular terms), and comparable stringency of the program as a whole." For example, the states encouraged Virginia to be more ambitious in setting a tighter state budget for annual covered carbon emissions than its proposed 33-34 million tons.

The Virginia Department of Environmental Quality's proposed carbon regulations remain pending before that agency.

ISO-NE Pay for Performance starts June 2018

The operator of New England's electric grid and wholesale electricity markets has adopted a new design for its capacity market, called “Pay For Performance” or PFP, which will become effective on June 1, 2018. As of that date, capacity payments will reward power resources that make investments to successfully boost performance during periods of system stress, while resources that don’t perform will forfeit capacity payments. According to grid operator ISO New England, Inc., these capacity market reforms represent “a significant evolution of the Forward Capacity Market.”

Since 2008, ISO-NE has operated a wholesale market for electric capacity, in addition to markets for energy and ancillary services. According to the grid operator, its Forward Capacity Market (FCM) ensures that the New England power system will have sufficient resources to meet the future demand for electricity. The market design features annual Forward Capacity Auctions held three years in advance of the operating period, in which resources compete to obtain a commitment to supply capacity in exchange for a market-priced capacity payment.

ISO-NE first proposed a version of PFP in 2014 as a means to address what it characterized as "capacity resource performance issues in New England." According to an article by ISO-NE's chief executive officer, ISO-NE felt that the prevailing capacity market design increasingly failed to incentivize resource performance during times of system stress. The grid operator reported "escalating incidents of poor generator performance that have threatened bulk power system reliability," and identified a "broken linkage" between capacity payments and actual performance under the previous rules.

According to ISO-NE, its Pay for Performance reform "firmly connects capacity payments to resource performance." It is designed to increase financial incentives for resource owners to make investments to ensure their resource’s reliability during periods of scarcity.

The Pay for Performance market design is based on a “two-settlement approach” such as is used in forward markets for electricity and other commodities.

In a first stage, a market participant takes on a Capacity Supply Obligation – a forward obligation to provide a specified amount of capacity from its resource – in exchange for a Capacity Base Payment. That base payment is determined by multiplying the resource’s Capacity Supply Obligation (in megawatts) by the relevant clearing price – either the clearing price from a Forward Capacity Auction or reconfiguration auction, or a bilateral contract price. Once a market participant has taken on a Capacity Supply Obligation in exchange for the Capacity Base Payment, the participant has a physical, resource-specific obligation to cover a share of the system’s energy and reserve requirements during reserve deficiencies.

In a second stage, the participant is subject to a settlement for deviations from its committed share. Under PFP, this second payment, which can be positive or negative, is called the Capacity Performance Payment. If a resource delivers more than its share of the system’s requirements during a capacity scarcity condition, it will be paid an additional amount for that incremental production; if it delivers less than its share, it must “buy out” of its position by paying other resources that did deliver.

Tariff revisions were accepted by the FERC in 2014 and 2015, and ISO-NE has subsequently developed further changes to its tariff to implement the program. The revised tariff is scheduled to take effect on June 1, 2018.

FERC tech conference on DER aggregation

How should distributed energy resources be allowed to aggregate and participate in organized wholesale electricity markets? How could increased adoption of distributed energy resources affect the bulk power system? U.S. energy regulators have announced a two-day technical conference to be held in April 2018 to discuss these and other issues relating to distributed energy resources.

Distributed energy resources, or DERs, are generally small, geographically dispersed electric resources, installed and operated on the distribution system at voltage levels below the typical bulk power system levels of 100kV. Traditional DERs have featured distributed generation like rooftop solar panels or on-site combined heat and power plants, but the term now encompasses other resources including energy efficiency, microgrids, and even new technologies like energy storage. These distributed energy resources can be cost-effective alternatives to traditional utility infrastructure and business models, and can also have reliability and environmental benefits.

The Federal Energy Regulatory Commission has scheduled a technical conference on DERs for April 10 and 11, 2018. According to a supplemental notice, the Commission hopes to gather additional information to inform its decision on DER aggregation reforms proposed in the Commission's 2016 Notice of Proposed Rulemaking on Electric Storage Participation in Markets Operated by Regional Transmission Organizations and Independent System Operators. The Commission also hopes to gather information on the potential effects of DERs on the bulk power system.