FERC licensing post-Hoopa Valley Tribe ruling

In the wake of a January 2019 court ruling holding that the states and applicants for water quality certifications cannot indefinitely stall federal time limits for state action by repeatedly withdrawing and resubmitting their applications, federal energy regulators are being asked to rule that states have waived their rights to issue water quality certifications.

On January 25, 2019, the United States Court of Appeals for the District of Columbia Circuit issued an opinion in Hoopa Valley Tribe v. Federal Energy Regulatory Commission. The court’s basic holding addresses language in Section 401 of the Clean Water Act providing that a state’s water quality certification requirements shall be waived with respect to a federally jurisdictional application if the state “fails or refuses to act on a request for certification, within a reasonable period of time (which shall not exceed one year) after receipt of such request.” In its recent ruling, the court strictly construed the one year limit for state action, saying it couldn’t be gamed by repeatedly withdrawing and refiling the application, because that would usurp the federal regulatory scheme.

At issue in Hoopa Valley Tribe are PacifiCorp’s Klamath River hydropower facilities in California and Oregon. PacifiCorp applied for relicensing in 2004, and met all milestones except state water quality certification. A 2010 settlement agreement with a consortium of stakeholders included an agreement between the states and the licensee “to defer the one-year statutory limit for Section 401 approval by annually withdrawing-and-resubmitting the water quality certification requests that serve as a pre-requisite to FERC’s overarching review.” A Native American tribe (which was not a signatory to the settlement agreement) petitioned FERC for a declaratory order that California and Oregon had waived their Section 401 authority and that PacifiCorp had correspondingly failed to diligently prosecute its licensing application for the Project. FERC rejected the tribe’s petition.

On appeal, the DC Circuit said the issue was whether a state waives its Section 401 authority when, pursuant to an agreement between the state and applicant, an applicant repeatedly withdraws-and-resubmits its request for water quality certification over a period of time greater than one year. The court then said determining the effectiveness of this scheme was “an undemanding inquiry” given the statutory language which sets a maximum of one year for states to consider the certification request. The court says that each resubmitted request wasn’t really a “new” request, so FERC acted arbitrarily and capriciously in finding that the states hadn’t failed to act. The opinion offers strong language saying states’ “deliberate and contractual idleness” cannot be used to “usurp FERC’s control over whether and when a federal license will issue.” The court remanded the case to FERC with a directive to proceed with its review of, and licensing determination for, the project.

Now, parties are invoking the Hoopa Valley Tribe ruling in requests to the Commission for orders finding that states have waived their certification rights through the withdrawal-and-resubmission process. On February 28, 2019, Exelon Generation Company, LLC requested a declaratory order that Maryland has waived its authority to issue a water quality certification for Exelon's Conowingo Hydroelectric Project, by failing to timely act on Exelon's request for certification.

Similarly, in February, Dan Dinges, president and CEO of Cabot Oil & Gas Corporation, filed a letter with the Commission, urging prompt approval of the Constitution natural gas pipeline. Dinges described dhe Constitution Pipeline, of which Cabot is one of the developers, as having been blocked by the state of New York, and noted that the DC Circuit had held in abeyance a case relating to the Constitution pipeline’s certification pending action on the Hoopa Valley Tribe case because they raised “common questions of law.” In his letter, Dinges cites the Commission’s failure to act on the Vineyard Wind capacity auction waiver request, points to New England’s constrained pipelines and fuel security concerns, and argues that “the gamesmanship of the State of New York has never been more suspect” in the wake of the Hoopa Valley Tribe ruling. He urged the Commission to act on the Constitution Pipeline. Subsequently, the Commission posted notice allowing parties to the Constitution Pipeline case an opportunity to comment on the impact of the ruling on that case.

FERC relicenses Poe hydro project

The Federal Energy Regulatory Commission has issued an order issuing a new hydropower license to utility Pacific Gas & Electric Company for its Poe Hydroelectric Project.

The 143-megawatt project is located on the North Fork Feather River in northern California, and includes land within the Plumas National Forest. Originally licensed in 1953, the project includes two dams impounding reservoirs, a 33,000-foot-long pressure tunnel bypassing about 7.6 miles of the river, and a powerhouse with two turbines.

The Commission issued a new 40-year license for the Poe project to PG&E on December 17, 2018. In relicensing proceedings, the Commission considers a number of public interest factors, including the economic benefits of project power. In general, the Commission evaluates the economics of a hydropower project by comparing the current costs of the project to likely alternative power, without considering forecasts concerning potential future inflation, escalation, or deflation beyond the license issuance date. The Commission says the basic purpose of its economic analysis is to provide a general estimate of the potential power benefits and the costs of a project, and of reasonable alternatives to project power.

In the Poe project's case, the Commission noted that after considering mandatory conditions and other measures suggested by Commission staff, PG&E's annual cost of operating the project would be about $9,590,000. Assuming that the project would generate an average of 498,113 megawatt-hours of energy annually, this works out to $19.3 per megawatt-hour. By comparison, the Commission found that the project's the corresponding alternative energy cost plus the value of its dependable capacity gave this power a value of $50,800,000, or $102 per megawatt-hour in the first year of operation, the project would cost $41,210,000 or $82.7 per megawatt-hour less than the likely alternative cost of power.

FERC issues notices for America's Water Infrastructure Act of 2018 implementation

Federal hydropower regulators have issued a pair of notices framing the implementation of recently enacted legislation designed to streamline the processes for licensing some hydroelectric projects.

On October 23, 2018, President Trump signed the America's Water Infrastructure Act of 2018. The new law amends several portions of the Federal Power Act which govern how the Federal Energy Regulatory Commission issues preliminary permits, hydropower licenses, and approvals for qualifying conduit hydropower facilities. It also directs the Commission to:

• Issue a rule within 180 days establishing an expedited process for issuing and amending licenses for qualifying facilities at existing nonpowered dams that will seek to ensure a final decision by the Commission on an application for a license no later than two years after receipt of a completed application;
• Issue a rule within 180 days establishing an expedited process for issuing and amending licenses for closed-loop pumped storage projects that will seek to ensure a final decision by the Commission on an application for a license no later than two years after receipt of a completed application;
• Along with the Secretaries of the Army, Interior, and Agriculture, jointly develop a list of existing nonpowered federal dams that the Commission and the Secretaries agree have the greatest potential for non-federal hydropower development, to be published within 12 months; and
• Hold a workshop within 6 months to explore potential opportunities for development of closed-loop pumped storage projects at abandoned mine sites, and issue guidance within one year to assist applicants for licenses or preliminary permits for closed-loop pumped storage projects at abandoned mine sites.

On November 13, 2018, the Commission established three dockets in order to implement the requirements of the Act: RM19-6-000 (Licensing Regulations under America’s Water Infrastructure Act of 2018); AD19-7-000 (Nonpowered Dams List); and AD19-8-000 (Closed-loop Pumped Storage Projects at Abandoned Mines Guidance). The Commission's notice establishes a schedule with abbreviated deadlines for the development of these materials, with notices of proposed rulemaking for the expedited licensing processes expected in January or February 2019.

As part of the provisions calling for new expedited processes for issuing and amending licenses for qualifying facilities at existing nonpowered dams and closed-loop pumped storage projects, the new law also requires the Commission to convene an interagency task force, including appropriate federal and state agencies and Indian tribes, to coordinate the regulatory processes required to construct and operate these projects. Also on November 13, the Commission published a notice inviting these groups to request participation in the interagency task force. Federal and state agencies and Indian tribes who wish to participate on the interagency task force must file a statement of interest with the Commission by November 29, 2018.

Canada's Supreme Court rules for Quebec utility over energy contract

Canada's highest court has ruled that Quebec's provincial utility Hydro-Quebec cannot be required to renegotiate a long-term contract to buy power from a Labrador hydroelectric plant at below-market rates, even though the deal has yielded about 14 times more profit for Hydro-Quebec than for the Labrador generator.

At issue is the Churchill Falls hydroelectric plant on the upper Churchill River in Labrador, and a 1969 agreement between Hydro-Quebec and Churchill Falls (Labrador) Corporation Limited -- a company jointly owned by Newfoundland and Labrador Hydro and Hydro-Quebec. The Churchill Falls plant can generate 5,428 megawatts of power, and is one of the world's largest hydroelectric power stations.

According to former Premier of Newfoundland and Labrador Brian Tobin, during pre-construction negotiations, Hydro-Quebec told Churchill Falls that it would not allow the Labrador generator to "wheel" project power through the Hydro-Quebec grid, nor to build its own power line through Quebec to reach U.S. markets. As a result, under the terms of the 1969 agreement, Hydro-Quebec agreed to buy most of the project's power at the fixed price of $2.50 per megawatt-hour, to guarantee construction cost overruns, and to build transmission lines connecting the generators to markets, enabling the Labrador generator to sell power and to use debt financing to construct the plant. The original contract was set to expire in 2016, but included a renewal clause allowing Hydro-Quebec to extend the contract for an additional 25 years at a fixed price of $2 per megawatt-hour through 2041.

After the contract was signed, changes in the electricity market -- including oil price shocks in the 1970s, a decline in public confidence in nuclear power after a 1979 accident, and the U.S. Federal Energy Regulatory Commission's 1996 decision to require open access to transmission systems -- meant the contract's purchase price is now well below market prices. Because Hydro-Quebec sells electricity from the plant to third parties at market prices, Hydro-Quebec reaps substantial profits from the deal. For example, Hydro-Quebec reports that the average retail price for residential customers in St. John's, Newfoundland in 2018 is $120.30 per megawatt-hour. Canada's National Energy Board says the 2017 average wholesale prices for electricity imports were over $24 per megawatt-hour, with exports priced even higher at $38.58 per megawatt-hour -- over 19 times higher than the price Hydro-Quebec now pays Churchill Falls during the extended contract term. According to CBC, the contract has yielded about $28 billion in profits to Quebec, but just $2 billion for Newfoundland and Labrador.

Citing legal theories including a general duty of good faith, Nalcor Energy subsidiary Churchill Falls asked Canadian courts to order that the contract be renegotiated and the benefits be reallocated. After lower courts sided with Hydro-Quebec, the generator appealed to the Supreme Court of Canada.

On November 2, the Supreme Court of Canada rendered its judgment in the matter of Churchill Falls (Labrador) v. Hydro-Quebec. The high court found, by a 7 to 1 decision, for Hydro-Quebec, noting that the parties "bound themselves knowing full well what they were doing" and that Hydro-Quebec could insist on adhering to the contract despite the "unforeseen" increase in the power's market value.

The one dissenting judge characterized the contract as "relational" in nature, and thus said that both parties are subject to a duty of cooperation which Hydro-Quebec breached by failing to renegotiate and to more fully share the benefits of higher-than-expected market prices. He said that because "a profit imbalance of this nature and magnitude is beyond what the parties intended when they concluded the agreement", the parties had an implied obligation to cooperate in establishing a mechanism for the allocation of "extraordinary profits."

New law eases some hydro licensing processes

A recently-enacted federal law will make it easier for hydroelectric project developers to secure a license for new hydroelectric facilities at existing non-powered dams.

U.S. rivers are home to thousands of dams, most of which impound water but don't generate electricity. A 2013 report suggested only 3% of the nation's 80,000 dams were used to produce hydroelectric power. In an effort to facilitate the development of hydroelectric facilities at some of these non-powered dams, Congress recently enacted the America's Water Infrastructure Act of 2018.

Title III of the Act relates to energy matters. One section of the Act extends the default term of preliminary permits for hydropower development from three to four years. The Act authorizes the Federal Energy Regulatory Commission to extend the period of a preliminary permit for up to four additional years, and to issue an additional permit under "extraordinary circumstances."

Another section of the Act speeds up the process through which the Commission evaluates proposals to develop "qualifying conduit hydropower facilities" and increases such a project's maximum installed capacity from 5 megawatts to 40 megawatts.

A third section of the Act requires the Commission to, within 180 days, issue a rule establishing an expedited process for issuing and amending licenses for hydroelectric facilities meeting defined criteria. These criteria require the "qualifying facilities" to be associated with an existing dam or other barrier operated for the control, release, or distribution of water for agricultural, municipal, navigational, industrial, commercial, environmental, recreational, aesthetic, drinking water, or flood control purposes, which as of the date of the Act's enactment was not generating electricity with Commission-licensed or exempted hydropower generating works. The Act also requires that the operation of these facilities must not result in any material change to the storage, release, or flow operations of the associated qualifying nonpowered dam.

The Act also includes provisions creating an establishing an expedited process for issuing and amending licenses for closed-loop pumped storage projects, and prescribing the considerations for setting the terms of new licenses for existing projects through the relicensing process.

The Act, which was introduced in the Senate as S.3021, was signed by President Trump on October 23, 2018, and became law the same day. The Commission has until April 2019 to issue the rules required by the Act.

FERC solicits panel members to resolve hydropower licensing study disputes

U.S. hydropower regulators have asked for volunteers interested in serving as panel members to assist in resolving disputes related to the scope of studies required for hydropower licensing.

Under federal law, the Federal Energy Regulatory Commission is tasked with processing applications for licenses for most hydropower projects located in the U.S. To process any given application, the Commission typically uses one of three different licensing processes. Since 2005, the Commission's "Integrated Licensing Process" or ILP has been the default choice.

Under the ILP, the applicant seeking a license files a proposed study plan describing the studies it intends to conduct to inform the Commission's review of its application. Studies might cover the project's impact on a variety of types of resources and issues, such as aquatic, terrestrial, cultural, recreational, geological, land management, engineering and socioeconomic topics. After a 90-day period of consultation with stakeholders and Commission staff, the applicant may file a revised study plan for Commission approval. Ultimately, the director of the Commission's Office of Energy Projects will issue a study determination approving the study plan with any modifications based on the record. Whatever studies are required by the Commission-approved study plan must be conducted by the applicant or its consultants.

The nature and extent of the studies required can be controversial. Stakeholders have opportunities to comment on the applicant's original study plan, to participate in consultation, and to comment to the Commission on the revised study plan.

Under the ILP, certain federal or state agencies or tribes also have the ability to request that a study dispute be referred to a dispute resolution panel. The three-member panel would consist of FERC staff, the agency or tribal representative referring the dispute, and an independent third person selected by the other two panelists from a list of subject-matter experts. The panel members make a finding with respect to each disputed study request, on the extent to which each study criteria set forth in the regulations is or is not met, and why. The panel then makes a recommendation to the Director of the Office of Energy Projects based on its findings.

On October 22, 2018, the Commission issued a notice requesting applications from those interested in being listed as potential panel members. The Commission previously compiled lists in 2004, 2010, and 2015. For the latest round, the Commission has requested applications by January 31, 2019.

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 Order 841 and electric storage markets

U.S. energy regulators have issued a final rule designed to help electric storage resources participate in the capacity, energy and ancillary services markets operated by regional grid operators. The Federal Energy Regulatory Commission said its Order No. 841 would remove barriers to the participation of electric storage resources in wholesale markets operated by regional transmission organization and independent system operators.

Electricity storage technologies have been around for some time, and some technologies like pumped hydropower storage have been deployed on a significant scale -- but new electric technologies are developing on top of these traditional technologies. New England's regional grid operator recently cited fast-responding energy storage devices as among the new technologies entering its markets. Many states have recognized the opportunities created by storage, and are enacting incentives to support its development and integration into microgrids. At the same time, regulators are grappling with how to fit energy storage resources into existing markets and incentive programs, like retail net metering.

The Federal Energy Regulatory Commission has considered electric storage for some time, including stakeholder workshops, data requests, and technical conferences. The Commission expressed concerns that barriers to electric storage resources participation in organized wholesale markets could lead to unjust and unreasonable wholesale electricity rates. In November 2016, the Commission proposed a rule to facilitate electric storage resources' participation in organized wholesale markets. In January 2017, the Commission issued a policy statement addressing how electric storage resources may provide services at a mix of cost-based and market-based rates.

In issuing Order No. 841 on February 15, 2018, the Commission adopted a final rule requiring each RTO and ISO to revise its tariff to establish a "participation model" for electric storage resources. As envisioned by the Commission, these participation models will consist of market rules that facilitate electric storage resources' participation in organized wholesale markets, while recognizing storage resources' physical and operational characteristics.

The new rule provides that each RTO and ISO must adopt its own participation model for electric storage resources, within certain guidelines. First, the participation model must ensure that storage resources using it are eligible to provide all capacity, energy, and ancillary services they are technically capable of providing. Second, the participation model must ensure that participating storage resources can be dispatched and can set the wholesale market clearing price as both a wholesale seller and wholesale buyer, consistent with rules that govern the conditions under which a resource can set the wholesale price. Third, the participation model must account for the physical and operational characteristics of electric storage resources through bidding parameters or other means Fourth, it must a minimum size requirement for participation in the RTO and ISO markets that does not exceed 100 kW.

The rule also requires that the sale of electric energy from the RTO or ISO market to an electric storage resource that the resource then resells back to those markets must be at the wholesale locational marginal price.

In an accompanying statement, Commissioner LaFleur described electric storage as "like a 'Swiss army knife' that can serve customers in multiple ways," including including providing energy, particularly in conjunction with variable renewable generation (example: Deepwater Wind has proposed offshore wind plus storage in response to the pending Massachusetts offshore wind solicitation) as well as providing frequency regulation and other ancillary services, and helping defer distribution and transmission needs. Commissioner Powelson noted its consistency with the Commission's "longstanding commitment to fostering innovation and competition by reducing and eliminating barriers to entry." Commissioner Glick said Order No. 841 "will facilitate the development of a class of technologies—ranging from batteries to pumped hydro—that has the potential to play a leading role in the transition to the electricity system of the future, but that has heretofore been hindered by market rules that were designed primarily to accommodate more conventional means of electric generation."

Once it takes effect, the final rule gives RTOs and ISOs 270 days to develop and file their proposed rule changes, and a year for their implementation.

Maine Gov. LePage's 2018 State of the State and energy policy

Maine Governor Paul R. LePage delivered his final State of the State address this evening. Here's a recap of some of his remarks on energy policy in previous speeches of that sort.

• In 2012, Governor LePage described Maine’s high energy costs as "one of the largest inhibitors, if not the biggest obstacle to job creation." He advocated an energy policy encompassing "all forms of energy."
• Energy did not appear in his 2013 speech, according to a transcript provided by the Portland Press Herald.
• In 2014, Governor LePage noted that "heating and electricity costs remain a major obstacle," with homeowners spending nearly double the national average on heating, and high electricity costs posting challenges to attracting business. He described efforts to expand natural gas pipeline capacity from Pennsylvania, and to connect to clean energy resources in Quebec.
• In 2015, Governor LePage used his speech to argue for lower electricity rates and home heating costs, as well as changes to Maine’s renewable energy policies.
• In 2016, Governor LePage released his speech in the form of a letter to the state legislature. As in previous speeches, his 2016 letter mentioned energy issues as a focus for -- or obstacle to -- economic development. Arguing that Maine's electricity prices are not competitive, he criticized legislative mandates supporting "long-term contracts for above-market rates." He also called for expansion of linear infrastructure like natural gas pipelines into New England and electric transmission lines to hydropower resources in Canada.
• Last year, he returned to delivering the speech to the legislature orally. His 2017 address included a section on energy matters, in which he criticized the Public Utilities Commission's decision to amend its rules governing net energy billing. He called upon lawmakers to agree to lower energy costs, to lower carbon dioxide levels in the most cost-effective manner, and to reduce our demand for oil.

Addendum as of 9 PM: WMTW has posted a transcript of Governor LePage's 2018 State of the State speech on its website, as prepared. That draft covers topics including "skyrocketing property taxes," Medicaid expansion, and fiscal responsibility. It calls for increased investment in Maine and workforce development. It proposes bonds focused on commercializing technologies, as well as on research and development, saying, "We must invest in commercialization as we do in research." However the prepared remarks did not mention energy, nor does it directly reference energy policy.

Nevertheless, the Bangor Daily News reports that his remarks as delivered did address energy, calling for lower energy prices.

FERC policy on hydropower license term

U.S. hydropower regulators have issued a new policy setting a default term of 40 years for original and new hydropower licenses, while identifying three circumstances that could warrant longer or shorter terms.  The Federal Energy Regulatory Commission's revised policy statement on establishing license terms could reduce cost and uncertainty for hydroelectric projects under its jurisdiction.

Federal law gives the Federal Energy Regulatory Commission jurisdiction over licensing most hydroelectric projects located at non-federal dams.  Section 6 of the Federal Power Act authorizes the Commission to issue hydropower licenses for a term not to exceed 50 years, but leaves the Commission some discretion to issue licenses for shorter terms.  

Prior to the October 19, 2017 policy statement, the Commission’s policy for projects located at non-federal dams was to offer a 30-year term where there is little or no authorized redevelopment, new construction, or environmental mitigation and enhancement; a 40-year term for a license involving a moderate amount of these activities; and a 50-year term where there is an extensive amount of such activity.  The Commission has found that measures including the construction of pumped storage facilities, fish passage facilities, fish hatcheries, substantial recreation facilities, dams, and powerhouses warranted longer license terms.

But after licensees and other stakeholders contested license terms in several recent cases, on November 17, 2016, the Commission issued a notice of inquiry seeking comments on whether, and if so how, it should revise its license term policy in effect at that time. As characterized by the Commission, most hydropower industry commenters supported the certainty offered by longer default terms, while most environmental groups, individuals, and resource agencies opposed them on various grounds.

On October 19, 2017, the Commission issued its Policy Statement on Establishing License Terms for Hydroelectric Projects. The new policy establishes a 40-year default license term for original and new licenses under the Commission’s jurisdiction with exceptions for coordination, deference to generally-supported comprehensive settlement agreements, and consideration of previously-authorized voluntary actions.  According to the policy statement, these exceptions will apply:

• When necessary to coordinate license terms for projects located in the same river basin;
  
• When a license term is explicitly agreed upon in a generally supported comprehensive settlement agreement, provided that there is no conflict with coordination of license terms for projects located within the same river basin; and
  
• When significant measures are required under the license to be issued, or significant measures were voluntarily implemented during the prior license term, provided it does not conflict with coordination of license terms for projects located within the same river basin.

According to a presentation by Commission staff, the new policy "will provide greater certainty to licensees, resource agencies, and other stakeholders," will reduce administrative costs and provide licensees longer license terms to recoup costs, and could encourage licensees to voluntarily make improvements or agree with stakeholders to a license settlement agreement.

According to the Commission, it will apply this new policy to licenses issued following the date of its publication in the Federal Register with no retroactive application.  While the Commission said it would not entertain applications to amend existing licenses to extend their license terms simply on the basis of this new license term policy, it noted that license applicants with pending license applications may file a comprehensive settlement agreement, or an addendum to an existing agreement, that includes an explicitly agreed upon license term, or may make a filing demonstrating why the Commission should award them a longer license term.

RC Byrd hydro project licensed at Army Corps locks and dam

Federal hydropower regulators have issued an original license to an Ohio city to construct, operate, and maintain a 50-megawatt hydroelectric project at an existing U.S. Army Corps of Engineers lock and dam site.  If developed as licensed, the City of Wadsworth, Ohio's Robert C. Byrd Hydroelectric Project will join other projects focused on adding hydroelectric generation to existing dams.

The Army Corps owns 21 locks and dams on the Ohio River, which it operates for commercial and recreational navigation.  These facilities include the RC Byrd Locks and Dam, originally built in the 1930s and renovated within the past 25 years.

On March 28, 2011, the City of Wadsworth, Ohio, applied to the Federal Energy Regulatory Commission for a license to construct, operate, and maintain the Robert C. Byrd Hydroelectric Project No. 12796.  As proposed by the city, the project would include new intake and tailrace structures along with a powerhouse holding two turbine generator units with a total installed capacity of 50 megwatts, but not the existing Army Corps dam.

On August 30, 2017, the Federal Energy Regulatory Commission issued its Order Issuing Original License for the RC Byrd Project.  The license, which authorizes the installation of 50 MW of new, renewable energy generation capacity, requires a number of measures to protect environmental resources at the project, including measures proposed by the licensee as well as additional terms and conditions developed by Commission staff and other agencies. 

According to the licensing order, the project will generate approximately 266,000 megawatt-hours per year, with a levelized annual cost of constructing and operating the project of about $40,586,280, or $152.58/MWh.  While the Commission found this to be more expensive than the cost of alternative power in the first year of licensure, the Commission also noted "that hydroelectric projects offer unique operational benefits to the electric utility system."  These ancillary service benefits "include the ability to help maintain the stability of a power system, such as by quickly adjusting power output to respond to rapid changes in system load; and to respond rapidly to a major utility system or regional blackout by providing a source of power to help restart the fossil-fuel generating stations and put them back on line."

Consistent with the Commission's general policy regarding license term for projects located on a federal dam, the Commission issued the RC Byrd Project license for a term of 50 years, the maximum allowable under the Federal Power Act.

If developed as licensed, the RC Byrd Project would be part of a trend toward adding hydroelectric generating facilities to existing dams owned by the Army Corps or other dam owners.  Congress and the Commission, as well as state agencies, have expressed support for adding hydropower to existing dams and lock structures.

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.

Maine PUC releases 2015 renewable report

Maine energy regulators have released a report on the state's electricity renewable portfolio standard, presenting data from 2015.  The Maine Public Utilities Commission's Annual Report on New Renewable Resource Portfolio Requirement - Report for 2015 Activity [PDF] provides a look at Maine's renewables law, now in its tenth year on the books.  It may also inform legislative discussions later this spring about the future of Maine's renewable portfolio standard.

In 2007, the Maine legislature enacted a law requiring that specified percentages of electricity that supply Maine’s consumers come from “new” or Class 1 renewable resources, ranging from 1% in 2008 to 10% in 2017.  The law also required the Commission to report annually to the legislative energy committee on the status of this requirement and related compliance matters.

According to the report, Maine suppliers sourced approximately 891,757 renewable energy certificates or RECs, from 30 facilities, to comply with the 2015 requirement.  Of these, 20 facilities were fueled by biomass, 4 by hydropower, 3 by wind and 1 by landfill gas.  25 out of the 30 facilities were located in Maine, with 2 in New York, and one each in Connecticut, Massachusetts, and Vermont.  By REC volume, 99% came from facilities located in Maine.

The report also estimates the cost to Maine ratepayers of Maine's new renewable resource portfolio requirement.  According to the report, the cost of RECs used for compliance in 2015 ranged from "approximately $2.00 per MWh to $42.50 per MWh, with an average cost of $13.16 per MWh and a total cost of $11,738,174."  Adding in $3,018 in alternative compliance payments by one supplier, the report estimates a total cost to ratepayers during 2015 of $11,741,192.  The report translates this total cost into "an average rate impact of about one-tenth of a cent per kWh. This is equivalent to about 55 cents per month, or 1%, for a typical residential customer; $50 per month for a medium commercial customer that uses 50,000 kWh per month; and $500 per month for a large commercial/industrial customer that uses 500,000 kWh per month."

Maine law also includes a Class 2 renewable portfolio standard, requiring an additional 30% of electricity come from existing renewables and other Class 2 resources.  According to the Commission's report, the average cost of a Class 2 REC in 2015 was $0.28 per MWh, with a total cost of $965,818.  The report notes that this is "equivalent to about 5 cents per month for a typical residential customer, and $4 and $40 per month for medium and large commercial/industrial customers with the usage levels described above, respectively."

This session, the 128th Maine Legislature is considering several bills that could affect Maine's renewable energy laws, including LD 532, An Act To Remove the 100-megawatt Limit on Hydroelectric Generators under the Renewable Resources Laws, as well as LD 1185, a concept draft which "proposes to enact measures designed to update Maine's renewable portfolio standards."

FERC 2-year licensing pilot workshop

The regulatory process for Federal Energy Regulatory Commission licensing of hydropower projects can take many years and significant expense -- but can it be improved following a two-year pilot process ordered by Congress?  After running a pilot process for one license application, the Commission has scheduled a workshop to discuss lessons learned from its pilot licensing process.

Under the Federal Power Act, the Commission is responsible for licensing most non-federal hydropower development in the U.S.  Concerned over the duration and expense of the regulatory process, Congress enacted the Hydropower Regulatory Efficiency Act of 2013, section 6 of which directed the Commission to investigate the feasibility of a two-year licensing process, develop criteria for identifying projects that may be appropriate for the process, and develop and implement pilot projects to test the process.

After a January 6, 2014 solicitation for pilot projects, the Commission selected Free Flow Power Project 92, LLC's (FFP) proposed 5-megawatt project at the Kentucky River Authority's existing Lock & Dam No. 11 on the Kentucky River.  The January notice set minimum criteria and a process plan for projects that may be appropriate for licensing within a two-year process, including:

• The project must cause little to no change to existing surface and groundwater flows and uses;
• The project must not adversely affect federally listed threatened and endangered species;
• If the project is proposed to be located at or use a federal dam, the request to use the two-year process must include a letter from the dam owner saying the plan is feasible;
• If the project would use any public park, recreation area, or wildlife refuge, the request to use the two-year process must include a letter from the managing entity giving its approval to use the site; and
• For a closed-loop pumped storage project, the project must not be continuously connected to a naturally flowing water feature.

After trying a two-year pilot to abbreviate its hydropower project licensing process, the Commission has scheduled a workshop to discuss the pilot's effectiveness.

EPA FAQ on dam removal projects

The U.S. Environmental Protection Agency has released a document answering "Frequently Asked Questions" about the removal of obsolete dams. 

As noted by EPA, dams "provide important societal functions for drinking water supply, flood control, hydropower generation, and recreation."  EPA estimates that the U.S. is home to between 2,000,000 and 2,500,000 dams -- but that between 75% and 90% of these dams "no longer serve a functional purpose."  Given the expense of maintaining dams and their safety, and some negative social and environmental impacts of dams, there is some pressure to remove obsolete dams.  According to EPA, over 1,300 dams have been removed in the U.S. since the early 1900s, with over 60 removals in 2015 alone.

EPA framed its dam removal FAQ in this context, noting that its answers to these questions would support dam removal efforts.  The FAQ addresses 20 distinct topics, ranging from dams' impacts on water quality, permitting issues related to dam removal, and EPA-related funding that could be used to support dam removal.

For example, the FAQ discusses permitting under Section 404 of the Clean Water Act, including the use of individual permits or general permits, including Nationwide Permits.  The FAQ encourages project proponents to work closely with the Army Corps of Engineers regarding Section 404 permitting.  It describes how EPA would evaluate specific requirements for monitoring or testing, such as in the case of contaminated sediments behind the dam.  The FAQ also discusses other permitting requirements, such as state-issued water quality certifications pursuant to Section 401 of the Clean Water Act, and evaluations of consistency with coastal zone management plans under the Coastal Zone Management Act.

The FAQ also notes that various grants may be available for dam removal projects.  For example, grants under Section 319 of the Clean Water Act can be issued to states, territories, and tribes for dam removals.  EPA's Five Star Wetland and Urban Water Restoration Grant Program could also provide funding for river, wetlands, riparian, forest and coastal restoration, and wildlife conservation.  Other funding, such as under the Wetland Program Development Grant program, is available to build technical and programmatic capacity of state and tribal water agencies.  Finally, the FAQ notes that dam removals could be part of a Supplemental Environmental Project proposed in settlement of an environmental enforcement action.

As noted by EPA, the FAQs released in December 2016 do not impose legally binding requirements on anyone, and EPA retains the discretion to adopt approaches on a case-by-case basis that differ from those described in these FAQs where appropriate.  Nevertheless the document provides dam owners, regulators, and communities guidance on how EPA views dam removal proposals.

Kauai small conduit hydro exemption terminated

U.S. hydropower regulators have terminated an exemption from licensing for a small conduit hydroelectric facility proposed for development in Hawaii.

The case concerns the 5.3-megawatt Puu Lua Hydropower Project No. 14069.  Proposed  by Konohiki Hydro Power, LLC, the project would have been located on the Kōkeʻe Ditch Irrigation System on state-owned land on the island of Kauai.  As authorized by the Federal Energy Regulatory Commission in its 2012 order granting the Puu Lua project an exemption from the licensing requirements of Part I of the Federal Power Act, the project would have included two developments with powerhouses.

In granting the Puu Lua project's exemption, the Commission included provisions allowing it to terminate the exemption if certain conditions are not satisfied.  Article 8 of the exemption states the Commission may terminate the exemption if actual construction of any project works has not begun within two years or has not been completed within four years from the issuance date of the exemption.  In 2014, the exemptee successfully won a two-year extension to commence project construction, until April 12, 2016.  But according to the Commission's August 31, 2016 Order Terminating Exemption (Conduit), the developer failed to commence construction of the Puu Lua Hydropower Project prior to the deadline.

In addition to the construction deadlines, the exemption also included an article providing that the Commission may terminate the exemption "if, at any time, the exemptee does not hold sufficient property rights in the land or project works necessary to develop, maintain, and operate the project." This too proved problematic, as in November 2015 the State of Hawaii notified the Commission that the exemptee’s rights to use the property were cancelled effective January 1, 2015.  After the exemptee did not respond to a Commission request for documentation of its rights, Commission staff issued a notice of probable termination of the exemption for failure to commence project construction by the April 12, 2016 deadline, and for failure to possess sufficient property rights.

Ultimately, on August 31, 2016, the Commission issued its order terminating the project's exemption, "for failure to commence construction and maintain sufficient property rights."

DOE Hydropower Vision report

The U.S. Department of Energy (DOE) has released a report on the future of domestic hydropower.  Its Hydropower Vision finds that U.S. hydropower could grow from 101 gigawatts of capacity in 2015 to nearly 150 gigawatts by 2050.  More than 50% of this growth could be realized by 2030, according to the report.  Much of the new capacity would come from pumped storage, with the remainder coming from upgrades to existing plants, adding power at existing dams and canals, and "limited development of new stream-reaches."

DOE's Wind and Water Power Technologies Office describes its report, Hydropower Vision: A New Chapter for America’s First Renewable Electricity Source, as presenting "a first-of-its-kind comprehen sive analysis to evaluate future pathways for low-carbon, renewable hydropower (hydropower generation and pumped storage) in the United States, focused on continued technical evolution, increased energy market value, and environmental sustainability." While it does not evaluate or recommend new policy actions, the report does analyze the "feasbility and certain benefits and costs of various credible scenarios, all of which could inform policy decisions at the federal, state, tribal, and local levels."

The report's Executive Summary presents an overview of the report, and its three "pillars" or foundational principles developed in collaboration with stakeholders: optimizing the value and power generation contribution of the existing hydropower fleet, exploring the feasibility of "credible long-term deployment scenarios for responsible growth of hydropower capacity and energy production," and sustainability.  Analyzing data and modeled scenarios, the report found that "under a credible modeled scenario in which technology advancement lowers capital and operating costs, innovative market mechanisms increase revenue and lower financing costs, and a combination of environmental considerations are taken into account—U.S. hydropower including PSH could grow from 101 GW of capacity in 2015 to 150 GW by 2050."

Chapter 1 of the Hydropower Vision describes how technical resource assessments and computational models can be used to interpret hydropower's future market potential.  It also evaluates potential innovations or nontraditional approaches to technology and project development that could affect the future development of new hydropower projects.

Chapter 2 of the Hydropower Vision presents a snapshot of the state of the U.S. hydropower industry as of year-end 2015, from the Energy Department's perspective.  It notes that hydropower generation and pumped storage have "provided a stable and consistently low-cost energy source throughout decades of fluctuations and fundamental shifts in the electric sector, supporting development of the U.S. power grid and the nation’s industrial growth in the 20th century and into the 21st century." The report points to 2015 data showing 2,198 active hydropower plants in the U.S. with a total capacity of 79.6 gigawatts, plus 42 pumped storage hydro plants totaling another 21.6 gigawatts.  In 2015, hydropower provided about 6.2% of net U.S. electricity generation, and 48% of all U.S. renewable power.

Chapter 3 of the report explores over 50 possible future scenarios for the hydropower industry, to assess the nation's hydropower potential.  It presents an extensive body of analysis, considering potential contributions over time to the electric sector of both the existing hydropower fleet and new hydropower deployment resulting from: upgrades at existing plants, powering of non-powered dams (NPD), pumped storage hydropower (PSH), and new stream-reach development (NSD).  It found that the greatest influence on potential growth scenarios comes from 3 variables: technological innovation, environmental considerations, and financial improvement.

The report's fourth chapter lays out a roadmap of 64 potential actions for stakeholder consideration, "to optimize hydropower’s continued contribution to a clean, reliable, low-carbon, domestic energy generation portfolio while ensuring that the nation’s natural resources are adequately protected or conserved."  These actions are organized around 5 topical areas: technology advancement, sustainable development and operation, enhanced revenue and market structures, regulatory process optimization, and enhanced collaboration, education, and outreach.

As noted by the Energy Department, while utility-scale battery storage projects are starting to be developed, most U.S. electricity storage capacity takes the form of pumped storage.  Flexible and reliable generating or storage resources can support efforts to integrate increasing amounts of intermittent renewable energy sources, like wind and solar, into the grid.

Alta Ski Area conduit micro-hydro project

Alta Ski Area has proposed developing a micro-hydropower project along an existing pipeline, and hopes to benefit from a streamlined regulatory process.  Federal regulators have made a preliminary determination that the proposed Alta Micro-Hydro Project, in Alta, Utah, satisfies the requirements to be treated as a "qualifying conduit hydropower facility," which would not require licensing under the Federal Power Act.

Alta's proposed project would include a new powerhouse to be built along the existing underground 6-inch-diameter snowmaking water supply pipeline delivering water from Cecret Lake to the Wildcat Pump House, a new turbine/generating unit with an installed capacity of 75 kilowatts, intake and discharge pipes, and appurtenant facilities.  The unit is estimated to generate between 115 and 225 megawatt-hours annually.  There is no dam associated with the project.  Alta presented its micro-hydro project as part of a 2012 request to update its master plan, which the U.S. Forest Service accepted.

Ski areas with snowmaking capacity typically have existing pipelines and water infrastructure, coupled with significant vertical relief.  This can create opportunities to generate electricity using energy harvested from water flowing downhill through a pipeline, particularly if reducing system pressure (like a pressure relief valve) is otherwise needed. 

A 2013 law was designed to help small conduit-based hydropower projects by eliminating their need for a license or exemption from licensing issued by the Federal Energy Regulatory Commission.  Section 4 of the Hydropower Regulatory Efficiency Act of 2013 amended Section 30 of the Federal Power Act.  Section 30 now provides that a "qualifying conduit hydropower facility" -- one that is determined or deemed to meet defined criteria -- is not required to be licensed or exempted from licensing under the Federal Power Act.  These criteria include:

• The conduit the facility uses a tunnel, canal, pipeline, aqueduct, flume, ditch, or similar manmade water conveyance that is operated for the distribution of water for agricultural, municipal, or industrial consumption and not primarily for the generation of electricity.
• The facility is constructed, operated, or maintained for the generation of electric power and uses for such generation only the hydroelectric potential of a non-federally owned conduit.
• The facility has an installed capacity that does not exceed 5 megawatts. 
• On or before August 9, 2013, the facility is not licensed, or exempted from the licensing requirements of Part I of the FPA.

The Federal Energy Regulatory Commission administers this statute.  To start the regulatory process, on May 16, 2016, Alta filed a notice of intent to construct a qualifying conduit hydropower facility.  Alta supplemented its notice on May 20 to clarify that the project "will only operate when there is excess capacity available in the pipeline and when water is hydrologically available", generally after the winter snowmaking season, during spring runoff.  Alta also restated that the pipeline's main purpose will continue to be snowmaking.

Yesterday the FERC issued its notice of preliminary determination of a qualifying conduit hydropower facility for Alta's project.  That notice examines the project relative to each of the four statutory criteria, and then provides the Commission's preliminary determination:

The proposed addition of the hydroelectric project along the existing water supply pipeline will not alter its primary consumptive purpose. Therefore, based upon the above criteria, Commission staff preliminarily determines that the proposal satisfies the requirements for a qualifying conduit hydropower facility, which is not required to be licensed or exempted from licensing.

The notice also sets a 30-day deadline for filing motions to intervene, and a 45-day deadline for filing comments contesting whether the facility meets the qualifying criteria and providing an evidentiary basis.

Other recently proposed conduit hydro projects have been determined to be qualifying conduit hydropower facilities, including a Colorado project using an existing "ditch drop," a Castle Valley, Utah water treatment project, a California wholesale water agency conduit project, and a New Hampshire water works.

Federal dams and preliminary permits

U.S. federal entities own dams with untapped hydropower potential that could be developed by private parties -- but a recent regulatory decision highlights the difficulty of winning key approvals when the federal dam owner opposes the project.  The Federal Energy Regulatory Commission's April 5, 2016 denial of an application for a preliminary permit for the McNary Lock and Dam Project illustrates this dynamic.

The U.S. Army Corps of Engineers owns and operates a 980-megawatt hydroelectric project at the McNary Lock and Dam on the Columbia River in Oregon and Washington. The project was authorized by the River and Harbor Act of 1945, and all its power units have been in operation since 1957.

But perhaps there may be untapped hydropower potential at the site that could be developed.  In 2015, a company called Advanced Hydropower, Inc. applied to the Federal Energy Regulatory Commission for a preliminary permit, pursuant to section 4(f) of the Federal Power Act, to study the feasibility of the proposed McNary Dam Advanced Hydropower Project No. 14697.  That project would utilize the existing McNary Dam, plus new facilities including a 34-megawatt turbine.

But by an order dated April 5, 2016, the Commission denied Advanced Hydropower's application.  In doing so, the Commission cited judicial precedent that it "is not required to grant a preliminary permit application, so long as it articulates a rational basis for not doing so."  It then cited recent Commission decision denying preliminary permits for projects at federal facilities after receiving comments from the relevant federal entities indicating that no purpose would be served in issuing a permit because the federal entity would not approve modifications to its federal facilities.

Notably, in the McNary Lock and Dam case, the Corps filed timely motions to intervene and comments opposing the project.  In its order denying Advanced Hydropower's application, the Commission noted:

Here, 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, we find there is no purpose in issuing a preliminary permit here.

Based on the Corps' opposition to the project, the Commission thus denied Advanced Hydropower's application for a preliminary permit for the McNary Lock and Dam project.

West Branch storage project relicensed

Earlier this month U.S. hydropower regulators issued a new license for the West Branch Project, which includes water storage facilities on the West Branch of the St. Croix River in Maine.

The Federal Energy Regulatory Commission first issued an original license for the West Branch Project on September 4, 1980.  The project includes two developments, Sysladobsis and West Grand, that operate as water storage facilities to provide flood storage and flow releases for downstream hydroelectric generation.  The Sysladobsis Development uses Sysladobsis Lake as its impoundment.  The license describes the West Grand Development as composed of several natural lakes including Scraggly Lake, Keg Lake, Bottle Lake, Junior Lake, Junior Bay, Norway Lake, Pug Lake, Pocumcus Lake, Horseshoe Lake, and West Grand Lake. 

Dikes and dams are used to control and release water, first from Sysladobsis Lake into the downstream West Grand impoundment, then into either Grand Lake Stream or Grand Lake Brook.  Many of the dams and dikes at these sites are old -- the Sysladobsis dam, West Grand dam, and Farm Cove dike were constructed in 1861, 1836, and 1879, respectively, although all three have since been rebuilt.

Each of these developments operates in a seasonal store-and-release mode whereby water is stored to reduce downstream flooding during periods of high flow and released during periods of low flow to augment generation at the downstream hydroelectric projects.

The West Branch Project also operates as part of the larger St. Croix River headwater storage system.  This network of dams includes Woodland Pulp LLC’s Forest City Project No. 2660 and the recently relicensed Vanceboro Project No. 2492. Generation associated with these projects occurs at the Grand Falls and Woodland hydroelectric projects downstream on the St. Croix River.

The West Branch Project's original 1980 license was amended in 1987 to include the existing Farm Cove dike, but the original license expired on September 30, 2000.  Since then, the licensee has operated the project under an annual license pending the disposition of a new license application.

On March 19, 2009, the licensee filed, pursuant to sections 4(e) and 15 of the Federal Power Act (FPA), an application for a new license to continue operating and maintaining the West Branch Project. The licensee proposed to continue store-and-release operation with some changes, continue operating fishways and take other measures to promote fish populations, enhance a land use plan, and develop a historic properties management plan.

Fishery issues have been contentious in the St. Croix River system.  After opportunity for public comment, agency consultation, and preparation of an Environmental Assessment, the Maine Department of Inland Fisheries and Wildlife asked the Commission to delay its licensing decision until fishery management talks concluded.  After being notified by the Department that those talks had concluded, on March 15, 2016 the Commission issued Woodland Pulp a new license to continue operating and maintaining the West Branch Project. 

The new license requires a number of measures to protect and enhance water quality, aquatic habitat, fisheries resources, terrestrial resources, and recreation opportunities at the project. These include a requirement to operate the developments in store-and-release mode between defined pond elevations, to provide certain minimum flows of water, to develop an Operation Compliance Monitoring Plan, and to provide and enhance fish passage.

A list maintained by the Federal Energy Regulatory Commission shows over 1,000 active hydropower licenses.  Many of these licenses will expire in the near future, so relicensing activity for FERC-licensed hydroelectric projects is expected to increase.