FERC Order 2222 opens wholesale markets to distributed energy resource aggregators

U.S. electric utility regulators have issued an order requiring the nation's regional organized wholesale electric markets to allow participation by portfolios of solar projects and other distributed energy resources. The Federal Energy Regulatory Commission's Order 2222 finds that existing regional electricity market rules are unjust and unreasonable in light of barriers that they present to the participation of DER aggregations in these markets, and requires regional grid operators to revise their tariffs to accomodate distributed energy resource aggregators. While further process and uncertainty remain ahead, FERC Order 2222 should facilitate the development of distributed energy resources by removing barriers to electricity market participation.

As defined by the FERC, distributed energy resources (DER) encompass a variety of types of technology when installed on the distribution system, a distribution subsystem or behind a customer meter. Typically less than 10,000 kilowatts in capacity for each installation, DER technologies include solar photovoltaic systems and other distributed generation or intermittent generation, electric storage, electric vehicles and their charging equipment, thermal storage, and other consumer-side measures like demand response and energy efficiency. The U.S. is experiencing significant growth in the number and size of DERs installed on the system, due to factors including federal tax incentives and state incentives, as well as considerations of reliability and utility rate design.

Through Order 2222, issued on September 17, 2020, FERC has now found "that existing RTO/ISO market rules are unjust and unreasonable in light of barriers that they present to the participation of distributed energy resource aggregations in the RTO/ISO markets, which reduce competition and fail to ensure just and reasonable rates." As a result, the Commission adopted a final rule requiring regional transmission organizations and other organized wholesale market operators to establish DER aggregators as a type of market participant, to allow them to register their DERs under one or more participation models that accommodate the physical and operational characteristics of those resources and to participate in the regional organized wholesale capacity, energy and ancillary services markets. Order 2222 allows DERs to aggregate together to satisfy minimum size and performance requirements that they might not meet individually.

The boundaries between federal and state jurisdiction over DERs arise as a matter of federal law, and have occasionally been tested -- most recently in connection with FERC Order 841, governing storage. As noted by the Commission, its Order 2222 final rule "builds off the DC Circuit Court’s recent ruling on Order No. 841, in which the court affirmed the Commission’s exclusive jurisdiction over the regional wholesale power markets and the criteria for participation in those markets." Order 2222 prohibits state regulators from broadly excluding DERs from participating in regional markets, but gives state retail regulatory authorities some power by creating a "small utility opt-in", as well as respecting states regulators’ current ability to prohibit aggregators from bidding retail customers’ demand response into regional markets. Regarding interconnection, Order 222 explains that "state and local authorities remain responsible for the interconnection of individual DERs for the purpose of participating in wholesale markets through a DER aggregation."

The final rule largely tracks a 2016 proposed rule developed by FERC staff, with some changes. The regulator appears excited to take this step. According to a fact sheet issued by the Commission under the title, "FERC Order No. 2222: A New Day for Distributed Energy Resources", Order 2222 "will help usher in the electric grid of the future and promote competition in electric markets by removing the barriers preventing distributed energy resources (DERs) from competing on a level playing field in the organized capacity, energy and ancillary services markets run by regional grid operators."

Order 2222's final rule will take effect 90 days after its publication in the Federal Register. Grid operators will then have 270 days within which they must submit to FERC a compliance filing and a plan for timely implementation of the final rule. While Order 2222 and federal laws place some constraints on what the grid operators may propose, each regional transmission organization or independent system operator has some leeway to develop and propose solutions it views as tailored to its own markets and needs. This feature of federalism will likely result in some diversity in terms of regional designs, to be considered through regional stakeholder discussion and the Commission's regulatory processes.

Considering a Green New Deal

Will 2019 bring a "Green New Deal" for the U.S. or individual states?

President Franklin D. Roosevelt championed the original "New Deal" in the 1930s, as a series of federal reforms and measures designed to lift the U.S. economy out of the Great Depression. The First New Deal included banking and securities law reforms, funding for emergency relief operations by states and cities, and a Civil Works Administration. Later in the Roosevelt administration, a Second New Deal included labor law reforms, significantly increased federal employment through the Works Progress Administration jobs relief program, and the Social Security Act, among other measures.

More recently, the notion of a "Green New Deal" has emerged from a variety of sources. While the details of what constitutes a Green New Deal vary depending on the proponent, the basic concept most proposals have in common is a significant investment in clean energy to spur employment and revenue. For example:

• Mark Hertsgaard's 1998 book Earth Odyssey culminated with his vision of a "Global Green Deal" to transform global economies based on the New Deal.
• New York Times columnist Thomas Friedman has been credited with coining the "Green New Deal" phrase in a pair of opinion pieces in 2007. At the time, Friedman envisioned the government as "not funding projects, as in the original New Deal, but seeding basic research, providing loan guarantees where needed, and setting standards, taxes and incentives" to spawn business opportunities in clean power.
• In his 2008 presidential campaign, President Obama proposed addressing the nation's economic crisis by using green investments to promote new jobs, and the 2009 stimulus act included substantial measures along these lines which have been called a Green New Deal.
• In 2009, a United Nations program published a report calling for a "Global Green New Deal," again seeking transformation of global economies through investment in clean energy, systems and infrastructure.

The idea of a Green New Deal has again found some traction in 2019, although the details of what might be included remain unclear, as does the likelihood of its adoption. In 2018, as part of her successful campaign, now-Representative Alexandria Ocasio-Cortez proposed a federal "Green New Deal" to address climate change. While the concept does not appear to have been fully embraced by Congress, state legislation proposing state-level Green New Deals has started to arise. For example, Maine state Representative Chloe Maxmin has proposed a bill whose title has been published as LR 1034, "An Act To Establish a Green New Deal for Maine."

Whatever ultimate fate these proposals meet, the concept of stimulating the economy and improving environmental performance through investment in clean energy and other green infrastructure projects will likely remain on the table for the foreseeable future. Legislatures and policymakers will be faced with challenges and opportunities in crafting measures that will succeed, in terms of both enactment and actually making a difference. If nothing else, 2019 will bring continued discussion across all levels of government about how best to move the U.S. and individual states forward.

Maine microgrid legislation proposed

Could Maine unlock the potential of local energy grids through legislative action? As the 129th Maine Legislature begins its first regular session, legislators will consider at least one bill designed to encourage "microgrids." As an alternative or complement to traditional central electric utility development, microgrids are considered to be one key component of the "smart grid," capable of improving power reliability and quality, increasing system energy efficiency, and providing the possibility of grid-independence to individual end-user sites.

While the U.S. electric industry of the 20th century was characterized by consolidation of utility service into large utility service territories, microgrids represent an alternative or complementary model for connecting customers to energy resources. The U.S. Department of Energy defines a "microgrid" as "a group of interconnected loads and distributed energy resources within clearly defined electrical boundaries that acts as a single controllable entity with respect to the grid. A microgrid can connect and disconnect from the grid to enable it to operate in both grid-connected or island-mode.’’ The Energy Department notes that microgrids can provide consumers benefits such as backup for the grid in case of emergencies, cost reduction, energy independence, reduced environmental impacts, and integration of local resources like small-scale generation or electric storage. Other states, including New York and Massachusetts are taking action to facilitate the development of microgrids, as is the federal government.

The 129th Maine Legislature will consider a bill known as LD 13, An Act To Allow Microgrids That Are in the Public Interest. Sponsored by Representative Michael Devin of Newcastle, the bill defines a “new microgrid” as “a group of interconnected loads and distributed energy resources within clearly defined electrical boundaries that acts as a single controllable entity with respect to the electric grid and can connect and disconnect from the electric grid to enable the new microgrid to operate in both electric grid-connected mode and nongrid-connected mode, also referred to as island mode, and that is constructed after October 1, 2019.”

LD 13 would create a process through which the Maine Public Utilities Commission would approve the construction and operation of a new microgrid, if the Commission found that the operation of the new microgrid to be in the public interest and that other defined criteria were satisfied. These additional criteria include that the new microgrid will serve a total load of no more than 10 megawatts, that the small-scale electrical generation sources located close to where the generated electricity is used must meet Maine’s renewable portfolio standard, that there is a relationship between the proposed new microgrid operator and consumers within the area to be served by the proposed new microgrid, and that the reliability and security of the electric system will not be negatively affected. The criteria also require that the person proposing the new microgrid must have financial capacity and technical capability to operate the microgrid, and that the proponent can’t be an investor-owned transmission and distribution utility or its affiliate or affiliated interest.

LD 13 would also amend an existing law which currently gives transmission and distribution utilities the right to construct or maintain electric lines in, upon, along, over, across or under a road, street or other public way, but which generally makes it harder for entities other than transmission and distribution utilities to construct or maintain electric lines in roads. The amendment would extend the transmission and distribution utilities’ rights to a new category of people: those who construct, maintain or operate a new microgrid approved by the Commission.

The Legislature has referred LD 13 to its Joint Standing Committee on Energy, Utilities and Technology. As of January 3, the Committee had not yet scheduled a public hearing on the bill.

NJ approves offshore wind funding mechanism, rejects demonstration project

On December 18, the New Jersey Board of Public Utilities took two actions affecting offshore wind: approving the state’s Offshore Wind Renewable Energy Certificate (OREC) funding mechanism, but rejecting a petition by Nautilus Offshore Wind, LLC to install a 25 MW offshore wind demonstration project in state waters off the coast of Atlantic City. Meanwhile, developers have formed a new joint venture to develop offshore wind in federal waters farther offshore New Jersey.

New Jersey Governor Phil Murphy has set a goal of 3.5 gigawatts of offshore wind capacity by 2030, and in May 2018 he signed into law a renewable energy bill codifying that goal into statute. On September 17, 2018, the NJBPU opened the nation’s largest single-state solicitation to date, seeking 1,100 megawatts of offshore wind. Applications will be accepted through December 28, 2018. Winning projects will be compensated through the OREC mechanism approved this week, which requires electric companies to buy defined quantities of ORECs from offshore wind developers, much like a traditional renewable portfolio standard mechanism.

Also on December 18, the BPU rejected a 25 megawatt demonstration project proposed by Nautilus (under development by EDF Renewables and Fishermen’s Energy). The Nautilus project would feature three turbines in state waters about 2.8 miles offshore Atlantic City. But the BPU found the Nautilus project did not demonstrate the economic and environmental benefits required under the Offshore Wind Economic Development Act for the state to commit ratepayer funds. In particular, the BPU found that Nautilus didn’t provide sufficient information to substantiate claimed economic benefits, and further that Nautilus demanded a price that was too high given the unsubstantiated benefits.

But offshore wind development may soon occur farther offshore New Jersey. On December 19, 2018, EDF Renewables North America and Shell New Energies US LLC announced the formation of a 50/50 joint venture, Atlantic Shores Offshore Wind, LLC to co-develop offshore wind generation in federal waters offshore New Jersey. The site is about 8 miles offshore Atlantic City. At issue is the 183,353-acrea OCS-0499 lease area, the rights to which were initially auctioned by the federal Bureau of Ocean Energy Management in 2015. That auction was won by Toto Holding Group subsidiary US Wind Inc., with a winning bid of $1,006,240.

More recent federal auctions for offshore wind site leasing rights have brought much higher winning bids -- for example, a December 2018 auction for sites offshore Massachusetts brought in about $135 million for each of three lease areas, totaling over $405 million in winning bids for about 390,000 acres.

Feds reap $405 million offshore wind bidding bonanza

In what the Trump administration has called a "bidding bonanza", the latest federal auction of rights to lease ocean space for offshore wind development has brought $405 million in winning bids.

On December 14, 2018, the federal Bureau of Ocean Energy Management conducted its eighth competitive lease auction for renewable energy in federal waters. At stake were the rights to lease three areas totaling about 390,000 acres over the Outer Continental Shelf offshore Massachusetts.
The three lease areas in question are located 19.8 nautical miles from Martha’s Vineyard, 16.7 nautical miles from Nantucket, and 44.5 nautical miles from Block Island. These sites were previously offered for leasing through a federal auction in 2015, but went unsold at that time.

Eleven companies participated in the auction by submitting bids, out of a total of nineteen companies that had been deemed qualified to bid. The three provisional winners were Equinor Wind US, LLC  and Mayflower Wind Energy, LLC (each bidding $135 million) and Vineyard Wind, LLC (bidding $135.1 million). These amounts are significantly higher than any previous federal auction for offshore wind sites has yielded; the previous record winning bid was just over $42 million in December 2016 for a lease area offshore New York.

After the Department of Justice and Federal Trade Commission perform an anti-competitiveness review of the auction results, each winning bidder will be required to pay the winning bid amount to the Bureau and to post financial assurance. In exchange, each winning bidder will receive a lease with a preliminary term of one year, during which the lessee may submit a Site Assessment Plan (SAP) to BOEM for approval. Under the regulations governing the federal leasing process, the SAP describes the buoys or other facilities a lessee plans to deploy to assess the lease area's wind resources and ocean conditions. After BOEM approves a lessee's SAP, the lessee may submit a detailed Construction and Operations Plan (COP) to BOEM within four and a half years for approval. When presented with a COP, BOEM will conduct an environmental review. Finally, after BOEM approves any COP, the lessee will have a 33-year term to construct and operate the project.

Report: 50 GW US electric storage potential

A recently adopted federal regulation aimed at helping electric storage resources participate in wholesale electricity markets could unlock 7,000 megawatts of storage potential -- or up to 50,000 megawatts if all benefits can be captured through state and federal action -- according to a report by consulting firm The Brattle Group.

The study is titled, “Getting to 50 GW? The Role of FERC Order 841, RTOs, States, and Utilities in Unlocking Storage’s Potential.” Released on February 22, 2018, the report concludes that electric storage market potential could grow to 50,000 MW within the next ten years, if storage costs continue to decline and state and federal regulatory policies continue to be supportive.

The Brattle report comes one week after the Federal Energy Regulatory Commission's issuance of Order No. 841, a final rule aimed at removing barriers to the participation of electric storage resources in wholesale markets operated by regional transmission organization and independent system operators. The Brattle report describes Order 841 as "an important step in unlocking the value in wholesale energy, ancillary services, and capacity markets," noting the consulting firm's finding that at least half of storage's total possible value can be achieved in wholesale electricity markets.

Crucially, the Brattle study finds that fully realizing the value of electric storage will require state policy reforms similar to those at the federal level. Generally speaking, wholesale electricity sales and interstate transmission are subject to federal jurisdiction, while retail sales and local distribution are subject to state jurisdiction. This split jurisdiction means that some value streams available through battery storage can be only captured at the state level -- for example benefits from deferring or avoiding investments in transmission and distribution infrastructure by using storage as a non-transmission alternative, or customer benefits like increased reliability and engagement with power supply.

Storage can also save customers money -- as noted in the report, avoiding retail rate demand changes is one of the primary business drivers for storage deployment by U.S. commercial and industrial customers. But these values can only be fully captured through state action to remove the barriers that remain.

Some states are acting to incentivize or require energy storage investments. California set a mandate of 1,325 megawatts of storage by 2020, and Oregon and Massachusetts have also set state storage mandates.

The report also covers implications for existing storage resources, most of which are hydropower. It finds that existing storage resources can provide substantial new capabilities, if they can be operated more flexibly than today. As noted in the report, "Increasing flexibility of existing hydro can be very valuable, reducing the need for new investments." The report also suggests that optimizing operating strategies could increase storage revenues by 2 to 5 times.

FERC performance report and budget request

A U.S. energy regulatory agency has published a report detailing its fiscal year 2017 performance and requesting an appropriation of $369,9000,000 in funds from Congress for fiscal year 2019, to be offset by fees on regulated industries.

The Federal Energy Regulatory Commission or FERC is an independent regulatory agency, housed within the U.S. Department of Energy. The Commission has statutory jurisdiction over many aspects of the nation's wholesale electricity, natural gas, hydropower, and oil pipeline sectors. 

FERC's FY 2019 Congressional Performance Budget Request / FY 2017 Annual Performance Report describes the Commission's mission assisting consumers in obtaining reliable, efficient, and sustainable energy services at a reasonable cost through appropriate regulatory and market means. It recites the Commission's 3 goals: ensuring just and reasonable rates, terms and conditions; promoting safe, reliable, secure and efficient infrastructure; and mission support through organizational excellence.

The Commission recovers the full cost of its operations through annual charges and filing fees assessed on the industries it regulates as authorized by the Federal Power Act (FPA) and the Omnibus Budget Reconciliation Act of 1986, which requires it to “assess and collect fees and annual charges in any fiscal year in amounts equal to all of the costs incurred . . . in that fiscal year.” This revenue offsets the Commission's appropriation, resulting in a net appropriation of zero.

The report projects a FY 2019 appropriation of $369,900,000 "for necessary expenses of the Federal Energy Regulatory Commission to carry out the provisions of the Department of Energy Organization Act." This represents an increase of $2,300,000, or about 0.6%, over the Commission's FY 2018 budget request. The report describes its activity as requiring 1,465 full-time equivalents (FTEs) to execute its mission in FY 2019.

US considers Arctic offshore oil exploration

U.S. regulators are evaluating an application by a company seeking to explore for oil in the Arctic.

On June 12, the federal Bureau of Ocean Energy Management or BOEM announced that it had deemed Eni US Operating Co.'s exploration plan (or EP) to be submitted, and invited public comment on the plan. The company is a subsidiary of the Italian gas and oil company Eni S.p.A.

Under federal law, an Exploration Plan describes all exploration activities planned by the operator for a specific lease or leases, including information on locations, timing, drilling processes, and actions to be taken to meet safety and environmental standards and to protect access to subsistence resources. 

According to its Exploration Plan for the Nikaitchuq North Project dated March 2017, Eni proposes to drill into submerged lands on the Outer Continental Shelf beneath the Beaufort Sea, from its existing Spy Island drillsite which is located in Alaska state-jurisdictional waters.  Eni has secured federal leases for the "Alaska – Harrison Bay Block 6423 Unit".

BOEM's decision to deem the Exploration Plan as submitted triggers various deadlines:

• BOEM has opened a 10-day public comment window to provide information on issues that should be examined in the application's Environmental Assessment.  This window closes at midnight Eastern Time on Thursday, June 22.
• BOEM opened a 21-day public comment window for comments on the Exploration Plan itself.  This window closes at midnight Eastern Time on Monday, July 3.
• BOEM has 30 days within which it must evaluate the Exploration Plan, including a site-specific Environmental Assessment under the National Environmental Policy Act. By the end of the 30-day period BOEM may approve the EP, require modifications to the EP, or disapprove the EP.

While the Obama administration placed an indefinite hold on further leasing in much of the Beaufort Sea and other U.S. Arctic waters in December 2016, the Trump administration has expressed interest in reversing this decision in favor of expanded U.S. Arctic oil exploration and production.  The Arctic Ocean is home to significant fossil fuel resources, but environmental and logistical concerns have recently proved challenging. 

FERC to hold session on state policies, wholesale markets

U.S. energy regulators have scheduled a two-day technical conference to consider how state energy policies affect wholesale electricity markets.

In a March 3 notice of technical conference, the Federal Energy Regulatory Commission gave public notice that it will hold a technical conference on May 1 and 2, 2017.  The notice describes tensions between competitive wholesale energy and capacity markets and state policies.  On the one hand, the Commission noted, "Competitive wholesale energy and capacity markets bring value to customers by efficiently pricing energy and capacity , taking into account the operational needs and the dynamics of the transmission system , and providing transparent signals for investment and retirement of resources."  Generally speaking, these wholesale competitive markets currently select resources based on principles of operational and economic efficiency without specific regard to resource type

But on the other hand, the Commission notes recent increases in "interest by state policy makers to pursue policies that prioritize certain resources or resource attributes" (such as renewable resources, or in-state resources).  That has led to what the Commission calls an "open question": "how the competitive wholesale markets, particularly in states or regions that restructured their retail electricity service, can select resources of interest to state policy makers while preserving the benefits of regional markets and economic resource selection." These topics have come up in discussions relating to several eastern regional transmission organizations and independent system operators, such as the IMAPP process in New England, and similar efforts in PJM and NYISO to consider the integration of public policy into markets.

To foster further FERC-level discussion about the development of regional solutions that "reconcile the competitive market framework with the increasing interest by states to support particular resources or resource attributes," the Commission has scheduled the May 1-2 technical conference. The notice specifically references a range in potential long-term expectations regarding the relative roles of wholesale markets and state policies in shaping the resource mix -- ranging from no state role on the one end, to state authority over resource selection that must be accounted for in wholesale market design -- and a variety of potential solutions in between.

Anyone who wishes to participate in the conference may submit a nomination form to FERC online by 5:00 p.m. on March 17, 2017. 

BLM rule for renewable energy leasing of federal lands

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

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

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

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

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

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

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

Federal dams, nonfederal hydro, and preliminary permits

Can a hydropower developer obtain a preliminary permit from the Federal Energy Regulatory Commission for a project to be located at a federal dam, where the federal entity owning the dam says it opposes the project?  In a series of recent decisions, the Commission has denied preliminary permits in these circumstances, saying there is no purpose in issuing a preliminary permit.

U.S. federal law generally encourages the development of hydropower at existing dams.  Under sections 4(e) and 4(f) of the Federal Power Act, the Commission has general authority to issue preliminary permits and licenses for hydropower projects located at federal dams and facilities.  There are limits on this jurisdiction, such as if federal development of hydropower generation at the site is authorized, or if Congress otherwise unambiguously withdraws the Commission’s jurisdiction over its development.

The Commission also has discretion to deny a preliminary permit application, so long as it articulates a rational basis for its decision.  Through recent precedent, one basis the Commission has developed for denying applications is if the project would rely on modifications to federal facilities, but the federal entity says it would not approve those modifications or opposes the project.

For example, on April 25, 2016, Loxbridge Partners, LLC applied to the Commission for a preliminary permit to study the feasibility of the proposed McNary Second Powerhouse Project No. 14777. The project would be located at the U.S. Army Corps of Engineers’ McNary Lock and Dam facility on the Columbia River in Oregon.  On May 16, 2016, Commission staff asked the Corps for its opinion on whether non-federal development is authorized at McNary Dam, and if so, whether Loxbridge’s proposal would interfere with existing dam operations or improvement plans.  The Corps responded that it believed the Commission does not have jurisdiction to issue a preliminary permit or license for the site, and that the Corps opposed Loxbridge's proposed project on the ground that it would interfere with the Corps’ operation of McNary Dam.  The Corps asked the Commission to reject the permit application.

On September 2, 2016, the Commission denied Loxbridge's preliminary permit application.  It cited recent decisions in which "the Commission has denied preliminary permits for projects at federal facilities after the federal entities indicated that no purpose would be served in issuing a permit because the federal entity would not approve modifications to its federal facilities."  One of these decisions cited, Advanced Hydropower, Inc., 155 FERC ¶ 61,007 (2016), even relates to a different proposal for non-federal hydropower development at the McNary Dam.  The Commission also noted that "because the Corps, which owns the McNary Lock and Dam facility and whose permission would be needed for the development of any project at that facility, has stated that it opposes the project, there is no purpose in issuing a preliminary permit."

The Commission has issued similar denials with respect to Rivertec Partners LLC's proposed Clearwater Hydroelectric Project No. 14753 to be located at the Corps' Dworshak Dam in Idaho, Owyhee Hydro, LLC's proposed Anderson Ranch Pumped Storage Hydroelectric Project No. 14648 to be located at a Bureau of Reclamation dam in Idaho, and Symphony Hydro LLC's proposed Project No. 14627 to be located at the Corps' Upper St. Anthony Falls Lock and Dam on the Mississippi River near Minneapolis.

The policy highlights the importance for project developers of cultivating good relations with federal agencies owning dams and other facilities with hydropower development potential.

NEPA guidance on greenhouse gas emissions

Federal agencies have new guidance on how to address the effects of greenhouse gas emissions and climate change as those agencies satisfy their duties under the National Environmental Policy Act.  This month the White House Council on Environmental Quality or CEQ issued its Final Guidance for Federal Departments and Agencies on Consideration of Greenhouse Gas Emissions and the Effects of Climate Change in National Environmental Policy Act Reviews.  The document is designed to improve clarity and consistency in how federal agencies address climate change in the environmental impact assessment process under NEPA.

Enacted in 1970, NEPA generally requires agencies to consider the environmental effects of proposed agency actions, and to provide the public and decision makers with useful information regarding reasonable alternatives and mitigation measures.  To coordinate federal environmental efforts, NEPA also established CEQ within the Executive Office of the President.  CEQ is now charged with issuing mandatory regulations for NEPA implementation, as well as guidance documents such as the recent greenhouse gas guidance.

In its final greenhouse gas guidance, CEQ described climate change as "a fundamental environmental issue" whose effects fall squarely within NEPA's purview.  In CEQ's words, "Analyzing a proposed action’s GHG emissions and the effects of climate change relevant to a proposed action — particularly how climate change may change an action’s environmental effects — can provide useful information to decision makers and the public." CEQ views focused and effective consideration of climate change in NEPA reviews as enabling higher quality agency decisions.

To this end, CEQ offered guidance that:

when addressing climate change agencies should consider: (1) The potential effects of a proposed action on climate change as indicated by assessing GHG emissions (e.g., to include, where applicable, carbon sequestration); and, (2) The effects of climate change on a proposed action and its environmental impacts.

The guidance presents further information and interpretation on each of these points. For example, it recommends that agencies quantify the direct and indirect greenhouse gas emission resulting from a proposed agency action, as well as both short- and long-term adverse and beneficial effects.  The guidance also stated that "a NEPA review should consider an action in the context of the future state of the environment." 

In one sense, the final guidance is just guidance.  As CEQ noted, agencies have discretion in how they tailor their individual NEPA reviews to accommodate the guidance. CEQ directed that agencies should apply this guidance to all new proposed agency actions as of the initiation of NEPA review.  It suggested that agencies "should exercise judgment" when considering the application of the guidance to an on-going NEPA process, but that CEQ does not expect agencies to apply the guidance to concluded NEPA reviews, nor to any actions for which a final Environmental Impact Statement (EIS) or Environmental Assessment (EA) has been issued.

CEQ recommended that agencies review their NEPA procedures and propose any updates they deem necessary or appropriate to facilitate their consideration of greenhouse gas emissions and climate change.  Agency procedures to implement NEPA may be in the form of regulations, although they are not required to take that form.  CEQ's final guidance on greenhouse gas emissions may lead other federal agencies to revise regulations, policies, or implementing procedures to ensure full compliance with NEPA.

Supreme Court rules on state energy incentives

The U.S. Supreme Court has released its ruling on a case affecting how states may provide incentives for electric power generation.  In Hughes v. Talen Energy Marketing, LLC, the Court upheld a lower court's ruling invalidating a Maryland program to subsidize construction of new power plants.  The ruling provides important insight into how the Court views the boundary between federal and state jurisdiction over energy matters.

The Supreme Court of the United States.

The Hughes case involved a new Maryland program to encourage in-state generation capacity, and its relationship to federally blessed capacity market.  Under the Federal Power Act, the Federal Energy Regulatory Commission has exclusive jurisdiction over wholesale sales of electricity in the interstate market, while States regulate retail electricity sales. 

For years,  Mid-Atlantic regional grid operator PJM Interconnection has held capacity auctions to identify need for new generation and compensate generators for development.  PJM's auctions have been approved by the Federal Energy Regulatory Commission under the Federal Power Act.  But due to concern that the PJM auction was failing to encourage development of sufficient new in-state generation, Maryland enacted its own regulatory program.  Under that state program, Maryland held a competitive process to select a developer for a new power plant, and required load-serving entities to enter into a 20-year pricing contract (called a "contract for differences") with the developer.  The developer would still sell its capacity to PJM, but would receive extra money under the state program to make up the difference between the PJM market price and the contract price.

But incumbent generators challenged the new Maryland program; a federal district court issued a declaratory judgment holding that Maryland's program improperly sets the rate the developer receives for interstate wholesale capacity sales to PJM.  On appeal, the Fourth Circuit affirmed, finding that Maryland's program was preempted because it impermissibly conflicts with FERC policies.  The case then came to the Supreme Court of the United States.

The Supreme Court's April 19, 2016 decision affirms the lower courts' rulings.  The Court agreed with the Fourth Circuit's judgment "that Maryland's program sets an interstate wholesale rate, contravening the FPA's division of authority between state and federal regulators."  In the majority opinion's words, "States may not seek to achieve ends, however legitimate, through regulatory means that intrude on FERC's authority over interstate wholesale rates, as Maryland has done here."

The Hughes ruling sheds light on how the Court might view other state programs to incentivize new or clean generation.  That said, the Court emphasized that its holding in Hughes is limited -- that it rejected Maryland's program "only because it disregards an interstate wholesale rate required by FERC."  The Court explicitly said it would not address "the permissibility of various other measures States might employ to encourage development of new or clean generation," such as tax incentives, land grants, direct subsidies, construction of state-owned generation facilities, or re-regulation of the energy sector.

The majority opinion concludes with a reminder that "[s]o long as a State does not condition payment of funds on capacity clearing the auction, the State's program would not suffer from the fatal defect that renders Maryland's program unacceptable."  This suggests one potential path for permissible state incentives for electric power generation.

FERC dam license transfers, death and estates

What happens when an individual person dies holding a Federal Energy Regulatory Commission license for a hydroelectric project?  While their will may specify an heir for the dam and project works, the process of inheriting a licensed dam can involve both state estate law and a license transfer through FERC.

The Federal Energy Regulatory Commission licenses hydroelectric projects under Part I of the Federal Power Act.  The Commission's most recent list shows over 1,000 projects with licenses.  While most are held by corporate or public entities, about 25 licenses are held directly by named individuals.  Most of these projects licensed to individuals have relatively small authorized generating capacities, but once licensed their operation and transfer are governed by federal processes.

State law usually controls what happens to property owned by an individual upon his or her death.  Suppose the licensee's will provides that the licensed hydroelectric project is transferred to another person.   That provision may be valid as a matter of state law, but as a matter of federal law the license only transfers if the Commission approves the transfer.

Practically speaking, this can mean that the estate of the licensee needs to file an application to FERC for the transfer of the project license.  A recent application relating to the Pine Creek Hydroelectric Project in Montana illustrates this process.

The Commission initially issued a 50-year license for the Pine Creek project to Howard and Mildred Carter, on July 25, 1986, with a present authorized generating capacity of 373 kW.  After Howard Carter's death, Mildred Carter was the surviving licensee on the project.  After Mildred Carter's subsequent death, a Montana state court started the probate process through which the project would transfer to Mrs. Carter's son Allen.  In October 2015, the Carter estate applied to the FERC for transfer of the license to Allen.  The Commission issued a public notice of the application for transfer of license and solicited comments, motions to intervene, and protests, none of which were filed.

The Commission approved the Pine Creek project license transfer on January 8, 2016.  The order includes a finding that transfer of the license for this project is consistent with the Commission's regulations and is in the public interest.  Its approval of the transfer was contingent upon: (1) transfer of title of the properties under license, transfer of all project files including all dam safety related documents, and delivery of all license instruments to the inheriting licensee, which shall be subject to the terms and conditions of the license as though it were the original licensee; and (2) the heir acknowledging acceptance of the order and its terms and conditions by signing and returning an acceptance sheet.  The license transfer order required the new licensee to submit certified copies of all instruments of conveyance and the signed acceptance sheet within 60 days.

While direct inheritance of FERC-licensed hydroelectric projects is relatively rare, similar issues can arise when corporate entities holding FERC licenses dissolve or otherwise "die."  Depending on the specific facts, more common changes in ownership of an entity holding a FERC license may also require some activity to remain in compliance with federal law.

Supreme Court rules on EPA power plant regulations

The Supreme Court of the United States has ruled that the U.S. Environmental Protection Agency acted unreasonably in developing new regulations on hazardous air emissions from power plants without considering the cost impact of those regulations.  This ruling reinjects uncertainty into EPA's "Mercury and Air Toxics Standards" and other efforts to regulate power plant emissions under the Clean Air Act.

The federal Clean Air Act was designed to improve environmental quality and human health, among other goals.  It broadly allows federal regulation of air emissions of pollutants of various types and from various sources.

Because certain specific provisions in the Clean Air Act applied specifically to power plants, Congress placed a special restriction on EPA's regulation of power plant emissions under Section 7412(n)(1)(A) of the Clean Air Act.  That provision allows EPA to regulate emissions of hazardous air pollutants from power plants under Section 7412 only if it “finds such regulation is appropriate and necessary.”  In 2000, after a study, EPA concluded that regulating power plants under Section 7412 was "appropriate and necessary."  EPA reaffirmed this finding in 2012, and promulgated standards for emissions from power plants.

Along with those standards, EPA issued a “Regulatory Impact Analysis” estimating that the regulation would force power plants to bear costs of $9.6 billion per year.  That analysis also found that while benefits were hard to fully quantify, estimated benefits were worth $4 to $6 million per year.  Based on this analysis, compliance costs to power plants were thus between 1,600 and 2,400 times as great as the quantifiable benefits from reduced emissions of hazardous air pollutants.  At the same time, EPA argued that it did not have to consider costs in establishing its standards.

Following the issuance of these standards, 23 states sought review of EPA’s rule in the D. C. Circuit Court of Appeals in a series of cases which were later consolidated.  The D.C. Circuit upheld EPA's refusal to consider costs in its decision to regulate, at which point petitioners appealed to the Supreme Court. As my partner Jeff Talbert explains, in a 5-4 decision issued June 29, the Supreme Court held that EPA interpreted §7412(n)(1)(A) unreasonably when it deemed cost irrelevant to the decision to regulate power plants.

So what does the Supreme Court's ruling mean for U.S. power plants?  Uncertainty -- but not necessarily freedom from regulation.  The Supreme Court remanded the case back to the D.C. Circuit for further consideration.  The D.C. Circuit could uphold the rule again (on new grounds, compliant with the Supreme Court's decision) -- or it could invalidate the rule based on the Supreme Court ruling.  If that happens, EPA will likely have to resume the process of developing new regulations for hazardous air emissions from power plants under Section 7412.

FERC and EPA's Clean Power Plan

Following the U.S. Environmental Protection Agency's 2014 proposal to regulate carbon emissions from electric power plants and other major sources, federal energy regulators have scheduled a series of public technical conferences on how the Clean Power Plan may affect electric reliability, wholesale electric markets and operations, and energy infrastructure.

On June 2, 2014, the U.S. Environmental Protection Agency announced the Clean Power Plan, its proposed rule under Section 111(d) of the Clean Air Act to reduce carbon emissions from the nation's power plants.  Designed to reduce carbon emissions 30 percent below 2005 levels by 2030, EPA's proposal would impose limits on each state's rate of carbon emissions per megawatt-hour of electric energy generated.

The Federal Energy Regulatory Commission regulates the transmission and wholesale sales of electricity in interstate commerce, monitors energy markets, and protects the reliability of the high voltage interstate transmission system.  Acting out of concern over the possible impacts of the EPA Clean Power Plan on its regulated sector, on December 9, 2014, the Commission scheduled a series of technical conferences to develop public comment on these issues.

First, the Commission will hold a National Overview technical conference on February 19, 2015, at its Washington, DC headquarters.  Earlier this month, the Commission issued a supplemental notice describing the agenda for the National Overview.  After an introduction by EPA, the Commission expects to discuss:

• Electric reliability considerations: How will the Clean Power Plan affect electric reliability?  How can the U.S. sustain reliability as states and regions develop their plans to comply with the proposed carbon rule?  How could state, regional, and federal plans for compliance affect grid operations?  What tools are available to identify potential reliability impacts?  How can reliability planning processes and compliance planning efforts  coordinated to address potential issues?  What is the Commission's role in this area?
• Identifying and addressing infrastructure needs: What potential infrastructure needs may arise from various state or regional compliance approaches?  How can any infrastructure needs met in a timely manner in order to ensure system reliability?  How can relevant planning entities, industry, and states coordinate reliability and infrastructure planning and siting processes with state and/or regional environmental compliance efforts to ensure the adequate and timely development of new infrastructure?  Are additional mechanisms needed to ensure timely development of new infrastructure? Are adaptations to current Commission policies needed to facilitate the infrastructure needed for compliance with the proposed Clean Power Plan?
• Potential implications for Commission-jurisdictional markets:  How could potential compliance approaches to the proposed Clean Power Plan impact Commission-jurisdictional electric and natural gas markets?  What aspects, if any, of the wholesale and interstate markets would facilitate implementation of state or regional compliance plans?  What tools are available to address market issues as they arise?  What opportunities are available to coordinate compliance approaches with Commission-jurisdictional markets to meet the requirements of the proposed Clean Power Plan rule?

Following the National Overview, the Commission has scheduled three regional conferences in February and March 2015.

Setting fees for use of federal dams

Federally owned dams and other structures can create opportunities for private development of hydropower facilities, in exchange for a fee.  While fees charged to hydropower developers for using federally owned dams will likely remain stable in the near term, a look at the history of government dam use charges illustrates the process and dynamics involved in setting these fees.

Under federal law, many aspects of hydropower projects are regulated by the Federal Energy Regulatory Commission.  Section 10(e)(1) of the Federal Power Act (FPA) authorizes the Commission to collect annual charges from hydropower licensees whose projects make use of government dams or other structures owned by the United States.

Before 1984, the Commission assessed charges for the use of government dams and other United States structures on a case- by-case basis.  Typically, the Commission charged licensees half of the project's shared net benefit.  That net benefit was defined as the difference between the value of the power (taken as the least expensive alternative power) and the cost of project power (computed from the costs of building and operating the project). 

In 1984, the Commission issued Order No. 379, replacing its government dam use charges with graduated flat rates.  In that order, the Commission concluded that this method "best balances the statutory goals of providing a reasonable return to the Federal government, encouraging hydropower development, especially small projects, and minimizing costs to consumers."

Congress enacted the Electric Consumers Protection Act (ECPA) in 1986, which amended those portions of Section 10(e) of the FPA that authorize the Commission to collect government dam use charges.  ECPA adopted the method and rate levels of the Commission's new graduated flat rate structure as both the maximum allowable and the only federal dam use charges assessed by any U.S. agency. The Commission currently levies these maximum values, as it has since adopting them in 1984.

Section 10(e)(4) of the FPA requires the Commission to report to Congress every five years on whether the government dam use charges are appropriate.  The Commission's fifth and most recent report, dated October 17, 2013, concluded that the fees continue to provide reasonable compensation to the government.  The report noted that in the last five years some licenses for both constructed and unconstructed projects at government dams have been surrendered or terminated, but that there had been no indication that the dam-use fees played a role in such outcomes.  In addition, the Commission noted that it had issued 18 new licenses to projects located on government dams in the last five years that will be subject to these fees when they begin to generate power.

With a no-action recommendation by the Commission, Congress may choose not to amend Section 10(e) of the Federal Power Act in the near term.  However, the ECPA requires a periodic reassessment of the level of government dam use charges; the next mandatory report will come in 2018.  Moreover, Congress is interested in promoting new hydropower development, as is evidenced by its enactment of the Hydropower Regulatory Efficiency Act of 2013; Congress could, on its own, modify government dam use charges.  Nevertheless, for the near term, U.S. government dam use charges assessed under the Federal Power Act will likely remain stable.

Federal grants support microgrids

The U.S. Department of Energy has awarded over $8 million in funding for 7 microgrid projects.  Will microgrids play an increasing role in the U.S. electricity industry?

Solar photovoltaic panels can serve as distributed generation for microgrids.

Microgrids -- localized grids capable of operating as energy islands using distributed generation, energy storage, and distribution wires, as well as able to connect to the broader utility grid -- can offer participants and society at large significant value.  These benefits can include increased reliability against storm damage and infrastructure damage, reduced emissions of carbon and other pollutants, and reduced costs.

The Energy Department runs a portfolio of microgrid activities ranging from direct research and development to building community support.  Most recently, the Department announced over $8 million in grant funding to support 7 microgrid projects.  The Department selected these projects based on their ability to develop advanced microgrid controllers and system designs for microgrids less than 10 megawatts:

• ALSTOM Grid, Inc.: about $1.2 million to research and design community microgrid systems for the Philadelphia Industrial Development Corporation and the Philadelphia Water Department, using portions of the former Philadelphia Navy Yard. 
• Burr Energy, LLC: about $1.2 million to design and build a resilient microgrid to allow the Olney, Maryland Town Center to operate for weeks in the event of a regional outage, and a second microgrid for multi-use commercial development in Maryland. 
• Commonwealth Edison Company (ComEd): about $1.2 million to develop and test a commercial-grade microgrid controller capable of controlling a system of two or more interconnected microgrids, serving civic infrastructure including police and fire department headquarters, transportation and healthcare facilities, and private residences. 
• Electric Power Research Institute (EPRI): about $1.2 million to develop a commercially-viable standardized microgrid controller that can allow a community to provide continuous power for critical loads. 
• General Electric Company (GE): about $1.2 million to develop an enhanced microgrid control system in Potsdam, New York, by adding new capabilities, such as frequency regulation. 
• TDX Power, Inc.: about $1.2 million to engineer, design, simulate, and build a microgrid control system on remote Saint Paul Island, an island located in the Bering Sea off mainland Alaska. 
• The University of California, Irvine (UCI): about $1.2 million for the Advanced Power and Energy Program at UCI to develop and test a generic microgrid controller intended to be readily adapted to manage a range of microgrid systems, and supporting the development of open source industry standards.

Each project also includes an awardee cost share ranging from 20 percent to about 50 percent.  Will the DOE funds lead to better and more widely adopted microgrids?

What federal shutdown means for energy

With Congress's failure to pass a budget, today the U.S. federal government entered shutdown mode.  For 800,000 federal workers, shutdown means being furloughed until Congress resolves the budget.  What does the shutdown mean for the energy sector?

Each federal agency is reacting differently to the shutdown.  For the Federal Energy Regulatory Commission, it means continued normal business operations - as long as it still has funds on hand.  What happens after that?  According to a contingency plan issued last week, when those funds run out, FERC will continue "only those excepted activities authorized by law" to the extent that they protect life and property.  These activities include the work of the Commissioners themselves, hydroelectric and liquefied natural gas inspections, managing the reliability of the nation's electric and gas systems, and monitoring market operations.

The U.S. Department of Energy faces similar impacts from the shutdown.  It has some funds remaining on hand, but when those funds run out, according to its "lapse in appropriations plan", of its 13,814 employees, only 1,113 excepted personnel and 11 Presidentially-appointed and Senate-confirmed employees will remain on the job.

The Bureau of Ocean Energy Management will continue some operations.  According to its contingency plan, between 35 – 40% of Bureau employees will continue to report for full time duty, and BOEM will continue to work on current offshore wind projects and other renewable energy plans.

Energy, environment, and the 2013 inauguration

This week U.S. President Barack Obama took the oath of office for his second term. The 57th presidential inauguration was celebrated in Washington, D.C. on January 21, 2013.  In his inaugural address, President Obama delivered calls for action on issues ranging from the federal budget to social policy.  His speech also offered a platform on environmental and energy issues.  What did the 2013 inaugural address say about environmental and energy policies?

The United States Capitol after the inauguration ceremonies on Martin Luther King Day, January 21, 2013.

Climate change featured prominently in President Obama's second inaugural address.  Drawing on the official transcript of the address provided by the White House:

We, the people, still believe that our obligations as Americans are not just to ourselves, but to all posterity. We will respond to the threat of climate change, knowing that the failure to do so would betray our children and future generations. (Applause.) Some may still deny the overwhelming judgment of science, but none can avoid the devastating impact of raging fires and crippling drought and more powerful storms.  

Exactly how he plans to address climate change remains to be seen.  Likely measures include further Environmental Protection Agency regulations covering emissions from coal plants, greater military use of renewable and alternative fuels and energy sources, and an emphasis on energy efficiency.

President Obama also advocated for greater use of sustainable energy resources:

The path towards sustainable energy sources will be long and sometimes difficult.  But America cannot resist this transition, we must lead it. We cannot cede to other nations the technology that will power new jobs and new industries, we must claim its promise. That’s how we will maintain our economic vitality and our national treasure -- our forests and waterways, our crop lands and snow-capped peaks. That is how we will preserve our planet, commanded to our care by God. That’s what will lend meaning to the creed our fathers once declared.

Because this paragraph immediately followed his remarks about the climate and natural disasters, the speech suggested greater reliance on renewable or sustainable energy as another response to climate change.  President Obama emphasized both the environmental and economic value of these alternative energy resources.

Left unsaid were the details on the path towards sustainable energy.  Will President Obama suggest a national program requiring the use of renewable electricity?  Congress enacted a renewable biofuels standard as part of the Energy Policy Act of 2005, and most states have enacted laws requiring utilities to source electricity from renewable sources.  To date, no proposed federal electric renewable portfolio standard has found traction in Congress.  What about federal tax credits and incentives for renewable energy, such as the renewable electricity production tax credit and investment tax credit?  Last year President Obama called for making the production tax credit permanent and refundable, meaning taxpayers would not need to have any income tax liability to benefit from the credit.

Based on President Obama's 2013 inaugural address, he will push for solutions with enthusiasm and vigor.  The ultimate proposals, and the paths towards their execution, may affect their chances of success.  Exactly what measures surface -- and which can either pass through Congress or, in the case of agency action, survive legal challenge -- will be revealed over the next four years.