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.

FERC sets carbon pricing and offshore wind tech conferences

U.S. federal electricity regulators have scheduled technical conferences for this autumn to discuss issues related to two major policy initiatives: carbon pricing in organized wholesale electricity markets, and offshore wind integration in regional transmission organizations and independent system operators (RTOs/ISOs). The Federal Energy Regulatory Commission's scheduling of two technical conferences on these topics signals its interest in exploring the interplay between state energy and environmental policies and federally jurisdictional markets.

One technical conference regarding Carbon Pricing in Organized Wholesale Electricity Markets (Docket No. AD20-14-000) will be held on September 30, 2020, "to discuss considerations related to state adoption of mechanisms to price carbon dioxide emissions, commonly referred to as carbon pricing, in regions with Commission-jurisdictional organized wholesale electricity markets." The case has its genesis in a request for such an event, filed on April 13, 2020, by a broad coalition including Advanced Energy Economy, the American Council on Renewable Energy, the American Wind Energy Association, Brookfield Renewable, Calpine Corporation, Competitive Power Ventures, Inc., the Electric Power Supply Association, the Independent Power Producers of New York, Inc., LS Power Associates, L.P., the Natural Gas Supply Association, NextEra Energy, Inc., PJM Power Providers Group, R Street Institute, and Vistra Energy Corp. A number of other utilities, RTOs, and state interests also expressed support, prior to the Commission's issuance of a public notice on June 17 scheduling the event.

Another technical conference regarding Offshore Wind Integration in RTOs/ISOs (Docket No. AD20-18-000), to be held October 27, 2020, will be convened "to discuss whether existing Commission transmission, interconnection, and merchant transmission facility frameworks in RTOs/ISOs can accommodate anticipated growth in offshore wind generation in an efficient and effective manner that safeguards open access transmission principles and to consider possible changes or improvements to the current framework should they be needed to accommodate such growth."

Beyond the fact that the Commission issued notices of both technical conferences on June 17, 2020, the proceedings also share a common focus on the effects of state energy and environmental policies on federally-jurisdictional activities. For now, the prevailing carbon pricing mechanisms -- such as the Regional Greenhouse Gas Initiative adopted by many northeastern states -- and the strongest policies favoring or requiring offshore wind development are arising as a matter of state law and policy, as opposed to federal law.

The boundaries between federal and state jurisdiction are viewed by many as long-settled, although a series of federal court and agency decisions have found specific state electricity procurement and subsidy laws to be preempted by federal regulation, and a case pending before the Commission asks it to find that most state net metering programs are preempted by federal law. Whether the Commission grants or denies the pending request, the June 17 notices of technical conferences on carbon pricing and offshore wind integration suggest continued federal interest in exploring the implications of state policies on FERC-jurisdictional markets.

FERC proposes revoking hydro license for noncompliance

U.S. hydropower regulators have proposed revoking a Michigan hydroelectric project's license under the Federal Power Act, following findings of violations of numerous license provisions, agency regulations and orders.

At issue is the Edenville Hydroelectric Project, No. 10808, located on the Tittabawassee and Tobacco Rivers by Wixom Lake in Michigan. The Federal Energy Regulatory Commission initially issued a license for the 4.8-megawatt Edenville project in 1998. That license was eventually transferred to a company named Boyce Hydro Power, LLC.

According to public records in the Commission docket for the license, "Boyce Hydro has a long history of non-compliance" with license terms and conditions and with related provisions in the Federal Power Act and Commission regulations and orders. Orders in the docket recite history including a 2017 Compliance Order finding noncompliance with respect to the adequacy of the project's spillway capacity and other matters. As noted in the docket, "The Commission’s primary concern has been the licensee’s longstanding failure to address the project’s inadequate spillway capacity, which currently is designed to pass only approximately 50 percent of the PMF. Failure of the Edenville dam could result in the loss of human life and the destruction of property and infrastructure."

The Commission has tools that it can use to compel compliance with its laws and regulations. For example, on November 20, 2017, Commission staff issued an order requiring the licensee to cease generating at the Edenville Project.

Beyond ordering the project to stop generating power, the Commission can revoke a license. Section 31(b) of the Federal Power Act allows the Commission to issue an order revoking a license, after providing notice and an opportunity for an evidentiary hearing, if it finds that a licensee knowingly violated a final compliance order and was given a reasonable time to comply with that order before the revocation proceeding was commenced. 

On February 15, 2018, the Commission issued an Order Proposing Revocation of License in the Edenville project's docket. In that order, the Commission noted that the licensee "has failed for many years to comply with significant license and safety requirements, notwithstanding having been given opportunities to come into compliance... The licensee failed to meet nearly all the obligations in the compliance order, even after Commission staff granted multiple extensions."

The Commission noted that public safety "would not be affected by revoking the license." It noted that if the Commission were to revoke the license, its jurisdiction would end, and authority over the site will pass to the State of Michigan’s dam regulatory authorities.

The Commission also noted that revocation of the project license "does not mandate removal or any modification of the dam," citing both its broad authority under the Federal Power Act and its general policy not to condition the effectiveness of a license revocation on a licensee that has shown its unwillingness to comply with other Commission orders.

The Commission set a 30-day deadline within which the licensee may request an evidentiary hearing before an Administrative Law Judge, after which the Commission will decide the matter.

FERC issues license for Monongahela Locks and Dam 4 project

U.S. hydropower regulators have issued an original license for a proposed 12-megawatt hydropower project, to be located at the U.S. Army Corps of Engineers’ Monongahela Locks and Dam 4 facility on the Monongahela River, in Pennsylvania.

On February 27, 2014, FFP New Hydro, LLC subsidiary Solia 4 Hydroelectric, LLC filed, pursuant to Part I of the Federal Power Act, an application for a license to construct, operate, and maintain the Monongahela Locks and Dam 4 Hydroelectric Project No. 13767.  The company is affiliated with US Renewables Group.

The project would be located at one of the nine existing lock and dam sites on the Monongahela River, which the Army Corps operates for commercial and recreational navigation.  If developed, new facilities for the project would include an intake channel, spill gates, a powerhouse housing two equally sized Kaplan turbine-generator units with a combined capacity of 12 MW, a tailrace channel, a substation, a transmission line, and an access road.  The project will operate in a run-of-release mode, using flows made available by the Corps that would normally be released through the Corps’ spillway gates

Under the Federal Power Act, the Federal Energy Regulatory Commission is charged with regulating and reviewing applications for most non-federal hydropower projects.  Because the project uses the water power or surplus water of a government dam, occupies federal land, and is located on the Monongahela River, which is a navigable waterway of the United States, the Commission concluded that the project is required to be licensed pursuant to section 23(b)(1) of the Federal Power Act.

On July 21, 2017, the Commission issued its Order Issuing Original License for the Monongahela Locks and Dam 4 project.  The license authorizes the installation of 12 MW of new, renewable energy capacity, while requiring a number of measures to protect water quality, fish, wildlife, recreation, and cultural resources at the project.  It bears a 50-year term, the maximum allowable for an original license under Section 6 of the Federal Power Act.

According to the order, as licensed with mandatory conditions and staff-recommended measures, the levelized annual cost of constructing and operating the project will be about $3,563,340, or $72.88/MWh.  Its expected average annual generation will be 48,894 MW. 

The Commission noted that the project as licensed is best adapted to a comprehensive plan for improving or developing the Monongahela River, "because: (1) issuance of an original license will serve to provide a beneficial and dependable source of electric energy; (2) the required environmental measures will protect and enhance fish and wildlife resources, water quality, recreation resources, and historic properties; and (3) the 12 MW of electric capacity will come from a renewable resource that does not contribute to atmospheric pollution."

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. 

Boom in FERC hydro relicensing

U.S. federal hydropower regulatory staff currently has a full workload processing original license, relicense, and exemption applications, as well as its compliance and dam safety work, according to testimony presented to the House Energy & Commerce Committee, Subcommittee on Energy -- and this workload is expected to increase as many hydro projects face relicensing proceedings.

The Federal Energy Regulatory Commission regulates over 1,600 non-federal hydropower projects located at over 2,500 dams, under Part I of the Federal Power Act.  These projects collectively represent about 56 gigawatts of hydropower capacity, over half of the nation's total hydropower capacity.

The Federal Power Act generally requires non-federal hydropower projects to be licensed by the Commission if they: (1) are located on a navigable waterway; (2) occupy federal land; (3) use surplus water from a federal dam; or (4) are located on non-navigable waters over which Congress has jurisdiction under the Commerce Clause, involve post-1935 construction, and affect interstate or foreign commerce.  Licenses are generally issued for terms of between 30 and 50 years, and are renewable.

According to testimony presented to the House Energy & Commerce Committee, Subcommittee on Energy on May 3, 2017, the Commission's relicensing workload "has started to increase and will continue to remain high well into the 2030s."  Between fiscal years 2017 and 2030, the Commission projects that about 480 older projects will begin the pre-filing consultation stages of the relicensing process.  These projects facing relicensing represent about 45 percent of Commission-licensed projects, and one-third of jurisdictional licensed hydropower capacity.

The testimony also notes that some of these projects may face different standards in a relicensing context than were considered when their current or original licenses were issued.  Many projects now entering relicensing were first licensed in the early to mid-1980s, following the enactment of PURPA but prior to enactment of modern environmental standards.

For example, the Electric Consumers Protection Act of 1986 directed the Commission, when issuing licenses, to give equal consideration to power and development, energy conservation, fish and wildlife, recreational opportunities, and other aspects of environmental quality.  This mandate may not have applied to a 40-year license issued in 1982, but would come into play during a relicensing case initiated in 2017.

The House Subcommittee on Energy is considering discussion drafts and several pieces of legislation affecting hydropower, including the Hydropower Policy Modernization Act of 2017; the Promoting Hydropower Development at Existing Non-Powered Dams Act; the Promoting Closed-Loop Pumped Storage Hydropower Act; the Promoting Small Conduit Hydropower Facilities Act of 2017; and the Supporting Home Owner Rights Enforcement Act.

Nicatous Lodge proposes off-grid micro-hydro project

A Maine sporting camp has proposed developing an off-grid micro-hydropower project to provide it electricity.  Nicatous Lake Lodge and Cabins LLC proposes to develop the micro-hydro project at its remote property near Burlington, Maine.  A filing made by the camp earlier this spring has triggered a federal review process to evaluate whether the project will require a license or exemption under the Federal Power Act.

Under federal law, most hydropower projects cannot be constructed, operated, or maintained without licensing under the Federal Power Act.  But some projects -- typically off-grid or remote ones -- fall outside the Federal Power Act's jurisdiction.  To reduce uncertainty about what regulations might apply, Section 23(b)(1) of the Federal Power Act requires an entity proposing a new project to file with the Federal Energy Regulatory Commission either a hydropower license application, or a Declaration of Intention to determine if the proposed project requires a license.

When a developer files a Declaration of Intention with the Commission, the Federal Power Act requires the Commission to investigate and determine if the project would affect the interests of interstate or foreign commerce. The Commission also determines whether or not the project: (1) would be located on a navigable waterway; (2) would occupy public lands or reservations of the United States; (3) would utilize surplus water or water power from a government dam; or (4) would be located on a non-navigable stream over which Congress has Commerce Clause jurisdiction and would be constructed or enlarged after 1935.  Each of these evaluations supports a key jurisdictional finding under the Federal Power Act; collectively, they can determine whether or not licensing is required.

Other recently proposed micro-hydro projects illustrate how the Commission evaluates whether or not a license or exemption will be required.  For example, the Commission found that licensing or exemption was required for the Patton Colorado Hydropower Project, which would be grid-tied -- but that no license is required for the Egnaczak Net Zero Hydro Project in Massachusetts, which would have no connection to the interstate electric grid.

This jurisdictional determination is now underway for the Nicatous micro-hydro project.  On March 15, 2016, the sporting camp owner submitted a Declaration of Intention to the Federal Energy Regulatory Commission.  That Declaration of Intent describes the project site as about 15 miles away from the nearest electric utility grid, where Nicatous Stream leaves Nicatous Lake.  The project does not rely on a dam, although the remains of a former dam are located nearby.  Instead, an intake in the lake would supply water to a low head (60 inches or less) PowerPal micro-hydroelectric generator, rated at 1,000 watts power.  Power from the generator would be fed into the lodge's electric system, not which is not connected to any utility grid.

On May 10, 2016, the Commission issued its notice of the filing, setting a 30-day deadline for filing comments, protests, and motions to intervene.  Commission action on the filing could follow later this year.

FERC and microhydro licensing

Federal energy regulators have ruled that a micro-hydroelectric project proposed in New York cannot be constructed or operated without a license.

The proposed Henson Micro Hydroelectric Project would be located on the West Branch of Onondaga Creek, near Onondaga, New York.  It would include an existing 14-foot-high concrete dam, plus new construction including a penstock, a powerhouse, and a 10 kilowatt generating unit.  The dam was rebuilt in 2002, and had previously been used to power a grist mill.  The project developer, an individual, proposed to use the project power to provide electricity to his home and barn.
 
In his declaration of intention, the developer described himself and his approach to project development and compliance:

I would like to point out that I am not a corporation, or a rich man just a simple middle class Joe. I am an hourly employee at AT&T. Although blessed beyond what I actually deserve, I do not have a bunch of money that I could spend. In fact I am using funds recently obtained from a loss of use settlement from the NYS Workers Compensation Board to fund this. I am trying to do the right thing for the environment and save some money on my power bill. I am hoping that we can work this out to everyone’s satisfaction based upon the material and information that I currently have available. Of course, if additional information is required by you folks I will do everything to comply.

Identifying what approvals are necessary is a core step in developing any project.  Under section 23(b)(1) of the Federal Power Act, a non-federal hydroelectric project must be licensed by the Federal Energy Regulatory Commission (unless it has a still-valid pre-1920 federal permit) if it:

(a) is located on a navigable water of the United States;
(b) occupies lands or reservations of the United States;
(c) utilizes surplus water or waterpower from a government dam; or
(d) is located on a stream over which Congress has Commerce clause jurisdiction, is constructed or modified on or after August 26, 1935, and affects the interests of interstate or foreign commerce.

To reduce uncertainty over whether a project will require licensing, a developer may file a Declaration of Intention with the FERC describing the project.  Following public notice and an opportunity for protests, comments, and motions to intervene, FERC will rule on the jurisdictional questions raised by the declaration.

In the Henson project's case, the developer filed a Declaration of Intention on December 18, 2015.  That declaration was supplemented; after the second supplement, FERC issued its public notice of the declaration.  No protests, comments, or motions to intervene were filed.

On May 10, FERC issued its ruling on the declaration, finding that licensing is required.  FERC easily found that the project would not occupy any public lands or reservations of the United States or use surplus water or waterpower from a Federal government dam.  It found "insufficient evidence" to determine whether the West Branch of the Onondaga Creek is navigable.

However, FERC found that the West Branch of Onondaga Creek is a headwater or tributary of the Oswego River, a navigable water of the United States.  As a result, FERC concluded the project would be located on a "Commerce Clause stream."  FERC noted the project would be constructed after 1935.

FERC also concluded that the project would affect interstate commerce through its connection to the interstate grid, relying on precedent that "small hydroelectric projects that are connected to the interstate grid affect interstate commerce by displacing power from the grid, and the cumulative effect of the national class of these small projects is significant."  Thus even though the Hanson project's developer proposed using project power for the onsite home and barn, the fact that those buildings were grid-tied drove FERC to conclude that licensing was required. 

On this reasoning, FERC concluded that construction, operation, and maintenance would require a license.  As an alternative, FERC suggested the developer consider applying for an exemption from licensing as a small hydroelectric power project.


By contrast, another recent FERC decision concluded that a micro-hydro system proposed in Massachusetts did not require licensing, because (among other reasons) neither the project nor the structures it would serve would be grid-tied.  Thus whether or not the project and the facilities it serves are grid-tied or off-grid can be an important factor in whether a FERC hydropower license is required.

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.

Restoring old mill hydro sites and FERC licensure

Suppose you own an existing water powered mill complex whose hydromechanical facilities have not been operational for decades.  You would like to develop a hydropower project at the site, using the existing dam, headrace, and headgates, plus new equipment including two small generators, penstocks, and appurtenant facilities, to provide electricity to your home and workshop.  Do you need a license from the Federal Energy Regulatory Commission?

In the case of the Egnaczak Net Zero Hydro Project proposed for the outlet of the Hoosic River in Cheshire, Massachusetts, the FERC concluded that section 23(b)(1) of the Federal Power Act requires that project's owners to obtain a license for the project's construction, maintenance, and operation.  Proposed by Kenneth and Susan Egnaczak, the Egnaczak Net Zero Hydro Project would have a total generating capacity of 10.7 kilowatts.

Pursuant to section 23(b)(1) of the Federal Power Act, a non-federal hydroelectric project must be licensed (unless it has a still-valid pre-1920 federal permit) if it:

(a) is located on a navigable water of the United States;
(b) occupies lands or reservations of the United States;
(c) utilizes surplus water or waterpower from a government dam; or
(d) is located on a stream over which Congress has Commerce Clause jurisdiction, is constructed or modified on or after August 26, 1935, and affects the interests of interstate or foreign commerce.

The fourth prong itself has three main elements: project located on a Commerce Clause stream, post-1935 construction or modification, affecting interstate commerce.  In this case, FERC concluded that the Egnaczak project satisfied the fourth prong.

First, FERC found that the Egnaczak project is located on a Commerce Clause stream.  Under a 1965 Supreme Court ruling, for purposes of Federal Power Act section 23(b)(1), Commerce Clause streams are the headwaters and tributaries of navigable waters of the United States.  While FERC declined to determine whether the Hoosic River is navigable at the site of the project, it concluded that downstream segments of the Hoosic are navigable, as is the Hudson River into which the Hoosic flows.

Second, FERC next found that installing new hydroelectric generating capacity constitutes post-1935 construction within the meaning of Federal Power Act section 23(b)(1). 

Third, FERC found that the project would offset both electrical and heating needs that would have been otherwise supplied by the interstate grid -- and thus that the project would affect the interests of interstate commerce.  A footnote notes, "It is well settled that small hydroelectric projects that are connected to the interstate grid affect interstate commerce by displacing power from the grid, and the cumulative effect of the national class of these small projects is significant for purposes of FPA section 23(b)(1)."

FERC concluded that because the project would be located on a Commerce Clause stream, would be constructed after 1935, and would affect interstate commerce through its connection to the interstate grid, Section 23(b)(1) of the Federal Power Act requires Kenneth and Susan Egnaczak to obtain a license for the project's construction, maintenance, and operation.  The FERC order also suggests the project may be eligible to obtain an exemption from licensing as a small hydroelectric power project of 10 megawatts or less, and encourages the applicants to investigate the requirements for securing an exemption from licensure.

FERC requires licensure of Alaska hydropower project

What happens when federal hydropower regulators discover an unlicensed project subject to their jurisdiction?  A recent case involving a dam at a remote Alaskan fish hatchery ended with an order requiring the project owner to pursue licensure.

At issue is the Hidden Falls Lake Project, located within the Tongass National Forest on Kasnyku Bay on the eastern shore of Baranof Island near Sitka, Alaska.  The project is owned by the Alaska Department of Fish and Game, who installed a 250-kilowatt generator and related equipment in 1982 to power its Hidden Falls fish hatchery.  (A nearby larger Kasnyku Lake project contemplated by the federal government in 1969 never came to fruition.)

Most non-federal hydropower projects in the U.S. must be licensed by the Federal Energy Regulatory Commission.  Under section 23(b)(1) of the Federal Power Act, a non-federal hydroelectric project without a still-valid pre-1920 federal permit must be licensed if it:

(a) is located on a navigable water of the United States;
(b) occupies lands or reservations of the United States;
(c) utilizes surplus water or waterpower from a government dam; or
(d) is located on a stream over which Congress has Commerce Clause jurisdiction, is constructed or modified on or after August 26, 1935, and affects the interests of interstate or foreign commerce.

Part of the Hidden Falls Lake project -- the intake, penstock, 250-kW hydroelectric generator, powerhouse, and distribution lines -- are located on U.S. Forest Service lands. The Forest Service’s documentation states that a minor license application for the Hidden Falls Lake Project was filed with the Commission in 1981, but the Commission said it did not have any records of this application or of any subsequent Commission jurisdictional determination for this project.

But FERC did apparently know about the project.  In 1989, seven years after the project's generator was installed, the Commission initiated an investigation into the jurisdictional status of the project, suggesting it was "unlicensed" or "unauthorized."  Yet that unlicensed hydropower project investigation docket then went dormant until 2015.  Last year, the Forest Service informed the Commission that it had identified the project while conducting environmental reviews in support of a renewal of the Alaska agency's special use permit for the hatchery.  Thus the investigation resumed.

The Commission issued its final order in the case on January 28, 2016.  Because the project intake, penstock, hydroelectric generator, powerhouse, and distribution lines occupy public lands of the United States, the Commission concluded that the Alaska agency must obtain a license for construction, maintenance, and continued operation of the Hidden Falls Lake Project.  The Commission ordered the Alaska agency to file within 90 days a schedule for submitting a license application within 36 months.

If a small hydropower project on a remote Alaskan island is subject to FERC licensure, how many other unlicensed hydropower projects might be out there?  How many other unlicensed hydropower projects might there be on Forest Service or other federal lands?  While FERC investigations of unlicensed hydropower projects are relatively rare, with most years seeing only a handful of public active investigations, could there be other existing projects like the Hidden Falls Lake Project?

Court ruling cuts demand response uncertainty

Yesterday the U.S. Supreme Court issued an opinion upholding federal regulation of the compensation paid for wholesale electricity demand response.  The Court's opinion, FERC v. Electric Power Supply Assn., hinges on the distinction between wholesale and retail sales of electricity.  It provides the latest look at the boundary between federal and state jurisdiction over the electric grid.

Under the Federal Power Act, the Federal Energy Regulatory Commission is authorized to regulate "the sale of electric energy at wholesale in interstate commerce."  Its jurisdiction under the Federal Power Act does not extend to "any other sale of electric energy," such as a retail sale.  Traditionally, sales of energy directly to users are viewed as retail sales subject to state ratemaking jurisdiction, while sales of energy for resale are viewed as wholesale sales subject to federal ratemaking jurisdiction.

The case before the Supreme Court arose from a challenge by a group of generators to FERC Order No. 745.  Through that order, FERC adopted a rule requiring wholesale market operators to compensate cost-effective demand response resources for their performance at the same price paid to generators.  Last year, the D.C. Circuit Court of Appeals vacated FERC Order No. 745 on the ground that FERC lacked jurisdiction to set rates for this kind of demand response.  The D.C. Circuit implied that "wholesale" demand response was really retail in nature and thus subject only to state ratemaking jurisdiction.  FERC appealed this decision to the Supreme Court.

As described in the Supreme Court opinion, the appeal presented two legal issues:

First, and fundamen­tally, does the FPA permit FERC to regulate these demand response transactions at all, or does any such rule impinge on the States’ authority? Second, even if FERC has the requisite statutory power, did the Commission fail to justify adequately why demand response providers and electricity producers should receive the same compensa­tion? The court below ruled against FERC on both scores. We disagree.

In analyzing the first issue, the majority found that compensation for demand response directly affects wholesale prices -- "Indeed, it is hard to think of a practice that does so more."  The majority found, "A FERC regulation does not run afoul of section 824(b)’s prescription just because it affects―even substantially―the quantity or terms of retail sales."  The Court finally noted that FERC had offered substantial reasoning and arguments in support of its conclusion that demand response should be paid comparably to generation, and thus that FERC's actions satisfied the applicable standard that they not be "arbitrary and capricious."

The case now returns to the D.C. Circuit for further proceedings consistent with the Supreme Court's opinion. The most widespread direct impact of the Supreme Court in FERC v. EPSA will likely be a reduction to the uncertainty that has hung over the markets since the D.C. Circuit decision.  Market participants, consumers, aggregators, and grid operators have all been awaiting the ruling.  Some market changes, such as ISO New England's implementation of full integration of demand response, had been delayed pending a decision from the Court, as regional wholesale demand response programs hinge on FERC approvals under the Federal Power Act.  With the jurisdictional question resolved, these changes, and other refinements to regional transmission organizations' wholesale demand response programs, can now get back on track.

Cross-border infrastructure and presidential permits

A recent report casts doubt on whether proposed federal legislation would actually accelerate decisions on the siting of cross-border energy infrastructure.

Cross-border pipelines and electric transmission lines play an important role in the North American energy industry.  Under U.S. law, cross-border energy infrastructure projects require a presidential permit and a finding of consistency with the national interest.  Executive orders give the State Department jurisdiction over cross-border oil pipelines, the Department of Energy jurisdiction over electric transmission lines, and the Federal Energy Regulatory Commission jurisdiction over natural gas pipelines. 

Recent projects like the Keystone XL pipeline have focused attention on the presidential permit process, as that project's presidential permit application has remained pending for years.  Some have raised questions about the scope of agency review and perceived differences in the approaches taken by the State Department, Energy Department, and FERC.

As a result, several members of Congress have proposed legislation designed to accelerate the permitting process.  These bills include:

• the Keystone XL Pipeline Approval Act (S. 1): passed in Congress but vetoed by President Obama
• the American Energy Renaissance Act of 2015 (S. 791 and H.R. 1487)
• the North American Energy Infrastructure Act (S. 1228)

These bills take various approaches, including limiting agency jurisdiction over cross-border energy infrastructure or the scope of agency review, or setting strict deadlines for agency action following completion of environmental review.

Could federal legislation like this speed up the process for reviewing proposed cross-border pipeline and electric transmission projects?  A recent report by the Congressional Research Service suggests that overall timelines for project review are driven by the scope of the environmental review process, not by delays following that environmental review or agency idiosyncrasies.

In particular, the report found that agency review is "driven largely by the National Environmental Policy Act (NEPA)", which requires federal agencies to consider the environmental impacts before acting.  Moreover, the report notes that the same NEPA requirements apply to all three:

Faced with Presidential Permit applications for energy projects of similar physical scope, the agencies appear to perform NEPA reviews of similar proportion. Very short, smaller projects are generally reviewed more narrowly and quickly, whereas multi-state projects of large capacity are subject to more expansive environmental review and tend to face much greater public scrutiny and comment—regardless of which agency has jurisdiction. 

The report also found that NEPA review is the key driver of overall permitting decision timelines:

As long as agencies apply NEPA to Presidential Permitting decisions, changes to the delineation of, or jurisdiction over, the border-crossing portion of large projects for permitting purposes may not change the scope of project environmental review. The imposition of decision deadlines on the permitting agencies after NEPA review is complete, either for national interest or public interest determination, could provide greater process certainty to stakeholders. However, the overall project review would still be contingent on the completion of NEPA review. Thus, the effects of legislative proposals to change cross-border infrastructure permitting on the review or approval of future border crossing energy infrastructure projects are open to debate. 

It's unclear how the Congressional Research Service report will affect pending legislation.  Likely more influential may be any final action by the State Department on the Keystone XL project's application for a presidential permit.  Nevertheless, interest in cross-border energy trade will likely continue to grow.

FERC testifies on EPA carbon regulations and electric reliability

The U.S. Environmental Protection Agency's proposed Clean Power Plan rule is projected to limit carbon dioxide emissions from power plants, improve human health and save money -- but will it jeopardize the reliability of the nation's electricity grid?

Poorly implemented carbon regulations could increase the risk of widespread power outages, but this risk can be managed, according to testimony offered by the Commissioners of the Federal Energy Regulatory Commission to the House Energy & Commerce Subcommittee on Energy & Power earlier this week.

In her written testimony, Acting Chairman Cheryl LaFleur acknowledged concerns that EPA's carbon rule may have an "adverse impact on the overall reliability of the bulk power system."  Noting that EPA's plan leaves much of the implementation to individual states, she suggested that the FERC work closely with states to consider how state implementation plans will affect the operation of the grid. 

Commissioner Philip Moeller's testimony was more critical of EPA's proposed rule, which he described as infringing upon the FERC's jurisdiction over electric system reliability.  Noting that electricity markets are interstate in nature, Commissioner Moeller warned that "the proposal’s state-by-state approach results in an enforcement regime that would be awkward at best, and potentially very inefficient and expensive."  He also expressed skepticism at the plan's inclusion of increased use of existing natural gas-fired generation as one "building block" states may use to reduce their power sector's carbon intensity.  Commissioner Moeller also pointed to EPA's Mercury and Air Toxics Standards (MATS) rule as giving him reliability concerns.  On the positive side, he urged state regulators to speed adoption of real-time pricing at the retail level, so consumers can feel price signals that could reduce the overall cost of energy.  Commissioner Moeller concluded with a plea that FERC be given a formal role in EPA's regulation of the electric power sector.

Commissioner John Norris testified that EPA's proposed rule is "an important first step that addresses climate change by appropriately seeking to reduce carbon emitted by our nation’s electric power system."  While he acknowledges that transitioning to a low-carbon economy is challenging, he expressed confidence that "we as a nation should be well positioned to meet those challenges."  Commissioner Norris cited the MATS standards as an example of our readiness: while EPA's MATS rule led to the retirement of many older, inefficient coal-fired power plants, the grid has generally responded in a way that will maintain reliability.  Commissioner Norris urged cooperation with electric reliability organization North American Electric Reliability Corporation (NERC) and states, and to be flexible in making market rule changes to enable states, regional transmission organizations and other system planners to meet resource adequacy requirements.

Commissioner Tony Clark testified that while the grid is more reliable than before, it remains vulnerable to cyberattack, physical security threats, and geomagnetic disturbances.  He also described environmental regulations as another source of risk, and warned of the "seismic" shift in EPA authority over the energy sector embodied in the rule.  Commissioner Clark described the Clean Power Plan as the most comprehensive reordering he has seen of the jurisdictional relationship between the federal government and states as it relates to the regulation of public utilities and energy development.  He painted a picture of states forced to choose between surrendering their authority over power plants willingly or losing it to federal supremacy.

Current FERC enforcement director Norman Bay also testified, noting that he was confirmed by the Senate as a Commissioner on July 15, but that he has not yet been sworn in.  His brief testimony focused on the need for cooperation between FERC, EPA, NERC, states, and regional transmission organizations to ensure reliability.

What happens next remains to be seen.  As expressed in the opening statements of Energy and Power Subcommittee Chairman Ed Whitfield and Energy and Commerce Committee Chairman Fred Upton, many remain concerned about what they perceive as an effort by EPA to assert control and new regulatory authorities over states’ electricity decision-making.  Will EPA's Clean Power Plan ultimately come into effect -- and if so, what path will it take?

FERC, BOEM marine hydrokinetic guidelines

Two key federal regulators of marine renewable energy production have issued an updated set of guidelines for regulatory aspects of marine and hydrokinetic energy projects.

The document, BOEM / FERC Guidelines on Regulation of Marine and Hydrokinetic Energy Projects on the OCS, is designed to to clarify jurisdictional responsibilities for marine and hydrokinetic projects on the Outer Continental Shelf (OCS) and to foster a cohesive, streamlined process that will help accelerate the development of MHK (i.e., wave, tidal, and ocean current) energy projects.

U.S. Coast Guard icebreaking tug THUNDER BAY at its home berth in Rockland, Maine.

The OCS includes all submerged lands, subsoil, and seabed lying between the seaward extent of the states' jurisdiction (approximately 3 nautical miles from shore, or 3 marine leagues for Texas and the Gulf coast of Florida) and the seaward extent of federal jurisdiction (approximately 200 nautical miles or more from shore).

As described in the guidelines, an MHK project generates electricity from the motion of waves or the unimpounded flow of tides, ocean currents, or inland waterways. (While ocean thermal energy conversion or OTEC projects also fall under the MHK umbrella, the new guidelines focus on ocean wave and ocean current technologies.)

The guidelines cover only MHK projects on the OCS. The guidelines therefore cover neither nearshore MHK projects in state-jurisdictional waters, nor offshore wind projects in federal or state waters. 
 
The guidelines published yesterday fit within the larger context of agreements between previously-sparring federal agencies.  BOEM regulates site leasing, while FERC regulates hydropower.  As marine hydrokinetic technologies improved to the point where developers began proposing commercial projects, tensions and inconsistency developed between how the two agencies regulated and interacted.

This situation led the U.S. Department of the Interior and FERC to execute a Memorandum of Understanding (MOU) in April 2009, recognizing each agency’s respective jurisdiction.  Under the agreement, BOEM has jurisdiction to issue leases on the OCS for MHK projects, while FERC has jurisdiction to issue licenses for these same projects. The agencies felt that the agreement established a cohesive, streamlined process to lease, license and regulate all renewable energy development activities on the OCS, including marine hydrokinetic sources.

FERC and BOEMs’ predecessor Minerals Management Service (MMS) issued the first set of joint guidelines in 2009. As part of MMS’s Guidelines for the Minerals Management Service Renewable Energy Framework, the agencies included an appendix presenting MMS / FERC Guidance on Regulation of Hydrokinetic Energy Projects on the OCS. That document covered procedures for obtaining leases and licenses, municipal preferences, fee structures, and procedures for pursuing hybrid projects (more than one form of renewable energy) or straddle projects (straddling the boundary dividing state waters and the OCS).

Yesterday’s announcement presents a refreshed version of these guidelines. The revised guidelines offer guidance on a number of key regulatory aspects of MHK development process. Since 2009, both FERC and BOEM have changed some of their processes in significant ways – for example, BOEM now allows research leases, and FERC has expedited its pilot project licensure process. The guidelines thus help developers and others in the marine community to understand the legal process for exploration and development of hydrokinetic ocean energy sites.