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.

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.

Tide Mill Institute 2018 symposium

Tide Mill Institute holds its 14th annual conference on November 10, 2018, in Beverly, Massachusetts. The symposium -- "Creating Tide Mills -- Then and Now", features educators, historians, environmentalists, archeologists and others interested in tidal power and its history.

Tide Mill Institute exists to advance the appreciation of tide mill history and technology by encouraging research, by promoting appropriate re-uses of former tide mill sites, and by fostering communication among tide mill enthusiasts. Since 2005, the Institute has held an annual symposium on the past, present, and future uses of tidal energy.

This year's conference topics focus on how humans historically extracted power from the tides, as well as on efforts to use this power again in the current era. Speakers and discussions will address topics including:

• Medieval vertical and horizontal millwheels and their diffusion from mainland Europe.
• Fresh-water tidal rice mills in South Carolina.
• An in-stream tidal device in New York’s East River supplying power to the grid.
• Proposed perpetual tidal power system for Salem Massachusetts.
• A tide mill at the heart of the 1775 Battle of Brooklyn.
• Winter storm surges damage historic tide mills in Massachusetts and New York.
• Recreating gearing features of two early North Shore tide mills.
• A new tidal energy canal for Boston?
• The structure of tide mill dams.

Tide Mill Institute's 2018 symposium will be held on Saturday, November 10, 2018, from 8:30 am to 4:00 pm, at the Cummings Center in Beverly, Massachusetts. Registration materials are available on Tide Mill Institute's website. Lunch is included; attendees are encouraged to register by November 1.

Laos dam construction and collapse

A dam under construction in Laos as part of a hydropower scheme has collapsed, causing flooding and damage.

At issue is the Xe-Pian Xe-Namnoy project, a 410-megawatt hydroelectric power project under development for Xe-Pian Xe-Namnoy Power Company (PNPC). PNPC is a joint venture among the government of Laos and construction and power companies from South Korea and Thailand. The project, whose construction costs are estimated at about $1 billion, involves the construction of three primary dams to form reservoirs. Construction of the system was reportedly 90% complete, with commercial operation projected for 2019, and an agreement in place agreement to export 90% of project power to Thailand. The project has been touted for the degree of international investment involved, although some have criticized the project for insufficient local benefits.

From an engineering perspective, the project's primary dams impound water in a large reservoir. The project also includes three auxiliary "saddle dams" near several heads of the reservoir, essentially to prevent the reservoir from spilling down the impoundment's back side as it fills.

A map of the project, found at http://www.pnpclaos.com/index.php/en/project/maps

Project maps posted online by PNPC show saddle dams on three of the main reservoir's western branches.

Another project map found at http://www.pnpclaos.com/index.php/en/project/maps

One of these smaller saddle dams reportedly failed on July 23, 2018, allegedly due to severe rains. Saddle Dam D -- a facility 8 meters wide, 770 meters long and 16 meters high -- was built to support water diversion around the project's reservoir. But the structure reportedly fractured, causing water to spill downstream to the Xe Pian river outside of the project's intended path of water flow. According to the prime minister of Laos, at least 26 people have died and 131 are missing from the resulting flooding, and several villages .

Response and recovery actions are ongoing. The dam collapse highlights the importance of safety in dam construction and reservoir operations, as did the February 2017 failure of the Oroville Dam's spillway in California.

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 hydro dam safety post-Oroville

As federal hydropower regulators examine how a California dam's spillway failed, an independent forensic team has released its final report on the Oroville Dam spillway incident -- and regulators have asked all other hydropower licensees to review the report and hold internal discussions on how the findings may apply to their own facilities and overall dam safety program.

Oroville Dam is a 770-foot high earthfill embankment dam on the Feather River in Northern California. Its service spillway was severely damaged during operations on February 7, 2017; water levels continued to rise, eventually overtopping and eroding the emergency spillway, threatening the stability of the structure on February 12, 2017.  Over 180,000 people were evacuated.

Following the incident, an independent forensic team studied the incident. The independent forensic team's report was released on January 5, 2018. It found that the incident "was caused by a long-term systemic failure of the California Department of Water Resources (DWR), regulatory, and general industry practices to recognize and address inherent spillway design and construction weaknesses, poor bedrock quality, and deteriorated service spillway chute conditions."

On January 26, 2018, the Commission published a letter to licensees presenting the Oroville Dam Independent Forensic Team's final report. In that letter, the Commission asked licensees and their Chief Dam Safety Engineers/Coordinators to "read this report, share it with your senior executives as well as all your dam safety staff and discuss how the findings may apply to your own facilities and overall dam safety program.

According to the Commission, that report concludes that flaws in the Oroville Dam Spillway existed since construction that were missed by the owner, regulators, and consultants. In the Commission's words, "It is very clear that just because a project has operated successfully for a long period of time does not guarantee that it will continue to do so." Emphasizing a safety-oriented corporate culture, the Commission also highlighted the report's finding that "compliance with regulatory requirements is not sufficient to manage risk and meet dam owners' legal and ethical responsibilities." The Commission's letter to hydropower licensees and exemptees highlights the importance of communication between dam safety staff and senior executives as part of an Owner's Dam Safety Program, and stated its expectation that regulated dam owners will have internal discussions to ensure facility safety.

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.

Licensee seeks West Branch and Sysladobsis Dam amendment

A Maine dam owner has applied to federal regulators seeking to exclude from its hydropower license one of two dam-based developments which comprise the project.

At issue is the January 31, 2017 application of Woodland Pulp LLC to the Federal Energy Regulatory Commission for an amendment to the license for the West Branch Storage Dam Project.  The West Branch project was first licensed in 1980, and currently operates under a license issued by the Commission in 2016.  It includes two developments -- Sysladobsis and West Grand -- each of which operates as a water storage facility to provide flood storage and flow releases for downstream hydroelectric generation. 

As described in the license amendment application, the Sysladobsis development includes Sysladobsis Dam.  This dam is about 250 feet long and 9 feet high, consisting of three earth embankment sections, a small timber gate structure, and a fish passage facility.  The dam impounds the 5,400-acre Sysladobsis Lake; water released from the dam flows Sysladobsis Lake into the downstream West Grand impoundment, then into either Grand Lake Stream or Grand Lake Brook.  The project does not include any electricity generating facilities, but rather operates as part of a 112-year-old system of headwater storage dams in the St. Croix River watershed including Woodland Pulp LLC’s Forest City Project No. 2660 which the licensee has applied 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 licensee has requested FERC approval to remove the Sysladobsis development from the West Branch Project as a legal matter, and proposes "to remove the two wooden gates at the Sysladobsis Dam," but says it "does not propose to remove the Sysladobsis Dam as part of the amendment, and such removal is not necessary or appropriate."  Rather, the applicant asserts, "There will be no structural alteration of the dam, and there will be no discharge into the water. Once the gates are removed, the dam will no longer act as a water control structure for Sysladobsis Lake. Instead, impoundment levels and outflow will be determined by the natural precipitation cycle."

According to the licensee's application, "This change is necessary since operation of the Project as-is will no longer be economic under the new license issued March 15, 2016."  The licensee cited license terms and conditions including specific water level requirements and operating plans, reporting, and consultation requirements, "some with unreasonable time constraints."  The application notes, "As such Woodland cannot continue to fund and support the Sysladobsis development and incur increased losses on non-economically viable facility components."

In a separate docket, the Commission is considering an application by the same licensee to surrender its Forest City project license.

Fate of U.S.-Canada dam license in question

The holder of the U.S. federal hydropower license for a dam spanning the international border with Canada border has petitioned for approval to surrender that license, citing economic considerations.

At issue is the Forest City Project, located on the East Branch of the St. Croix River which forms the international boundary between the United States and Canada.  The Project operates under conditions set by the International Joint Commission (IJC) in accordance with the Boundary Waters Treaty of 1909, as well as a license issued by the U.S. Federal Energy Regulatory Commission.  The project currently operates under a license issued on November 23, 2015.  That 30-year license expires on October 31, 2045.

Licensed by the Commission as Project No. 2660, the project includes the U.S. portions of a 540-foot-long, 12-foot-high earth dam, an impoundment spanning several lakes, and appurtenant facilities. There are no generating facilities located at the project; rather, the Forest City Project operates as part of a headwater storage system along with two other projects licensed to Woodland Pulp -- West Branch Project No. 2618 and Vanceboro Project No. 2492.  Two hydroelectric generation projects are located downstream on the St. Croix River from these storage facilities, the unlicensed Grand Falls and Woodland hydroelectric projects.

On December 23, 2016, Forest City Project licensee Woodland Pulp LLC applied to the Commission to surrender its license.  A cover letter attached to that application states, "Woodland Pulp has determined that the high cost of operating the Project pursuant to the new FERC license renders the Project uneconomical." In the surrender application itself, the company cited license provisions including new operating restrictions on reservoir pool elevation, a reservation of the Commission’s authority to require additional fishways if so prescribed by the Secretary of the Interior, and a requirement to develop a Historic Properties Management Plan (HPMP), as adding risk or cost.  As noted in the surrender application, "After a comprehensive review of the conditions in the License, the minimal contribution to downstream power generation, and the significant added cost and increased complexity of the License, coupled with the loss of flexibility required to comply with the License, Woodland Pulp has concluded that it is not economic for the company to continue to operate the project.

As described by the Commission in an April 6, 2017 public notice of the surrender application, the licensee proposes to remove the gates on the west side of the spillway.  According to the licensee, removing these gates will return water flow to natural flow conditions, and the Forest City Dam will no longer act as the water control structure for East Grand Lake, nor will it use, obstruct, or divert international boundary waters.

The Commission has docketed the surrender application as P-2660-028, and set deadlines for comments, protests, and interventions in the case.

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.

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.

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. 

Waterbury hydro need and economics

A recent order issuing a new hydropower license to Green Mountain Power Corporation's Waterbury Hydroelectric Project sheds insight into the project's operations and economics.

The Waterbury project is located at a dam built in 1938, and licensed for hydropower development since 1954.  After a 16-year relicensing process, the Federal Energy Regulatory Commission issued a new license for the project in February 2016, authorizing 5.52 megawatts of generating capacity.  That relicensing process illustrates how the Commission considers the need for power from the project, as well as project economics, when considering whether to relicense a hydropower project.

By regulation, the Commission's process for reviewing a license application includes an evaluation of the "need of the applicant over the short and long term for the electricity generated by the project or projects to serve its customers."  In the Waterbury project's relicensing case, this consideration of the applicant's "need for power" involved observations about the project's expected output as well as the regional power market.  The order notes historic average generation from the Waterbury Project of 17,562 MWh annually, but observes that under the new license average annual generation will be reduced to 14,767 MWh.

The order then states, "Electricity generated from the Waterbury Project will help supply the power needs in northern Vermont."  It also cites a 10-year forecast by electric reliability organization North American Electric Reliability Corporation (NERC) showing summer peak demand in the region is expected to increase at an average rate of 0.84 percent per year between 2014 and 2023.  Based on this, the order concludes that "the project's power will help meet the regional need for power."

The Commission's process for determining whether to issue a new license for an existing hydroelectric project also includes consideration of public interest factors, such as the economic benefits of project power.  A 1995 decision established the Commission’s approach to evaluating the economics of hydropower projects.  Under that approach, the Commission uses current costs to compare the costs of the project and likely alternative power with no forecasts concerning potential future inflation, escalation, or deflation beyond the license issuance date.  The Commission has described the basic purpose of this economic analysis as to provide a general estimate of the potential power benefits and the costs of a project, and of reasonable alternatives to project power, "to support an informed decision concerning what is in the public interest with respect to a proposed license."

For the Waterbury project, as ultimately licensed with mandatory conditions and staff measures, the Commission concluded that:

• the levelized annual cost of operating the project is $711,735, or $48.20/MWh
• the proposed project would generate an average of 14,767 MWh of energy annually.
• average generation is multiplied by the alternative power cost of $44.12/MWh, for a total value of the project’s power is $651,520, in 2015 dollars.

Therefore, the Commission concluded that in the first year of operation, the project would cost $60,215, or $4.08/MWh, more than the likely alternative cost of power.  As the order notes, "Although staff’s analysis shows that the project as licensed herein would cost more to operate than the estimated cost of alternative power, it is the applicant who must decide whether to accept this license and any financial risk that entails."

The Commission did note that its consideration of public interest factors also considers that "hydroelectric projects offer unique operational benefits to the electric utility system", including ancillary services like stability and rapid response.  The order also notes that while staff did not explicitly account for the effects inflation may have on the future cost of electricity, hydropower generation is relatively insensitive to inflation compared to fossil fueled generators -- illustrating why "project economics is only one of the many public interest factors the Commission considers in determining whether or not, and under what conditions, to issue a license."

FERC relicenses Waterbury hydro project

More than 16 years after Green Mountain Power Corporation applied to the Federal Energy Regulatory Commission for a new license to continue operation and maintenance of its Waterbury Hydroelectric Project on the Little River in Vermont, the Commission has issued a new license for the project.

Waterbury dam and reservoir were built by the United States in 1938 to reduce flooding in the Winooski Valley, but are owned by the State of Vermont and operated by Green Mountain Power.  The Commission issued the original license for the project in 1954, effective September 1, 1951, for a period of 50 years.

That original license expired on August 31, 2001.  Two years before that date, Green Mountain Power applied for a new license to continue operation and maintenance of the project.  But relicensing a FERC-licensed hydropower project can be an involved process.  Environmental, conservation, and recreation-oriented groups intervened in the application case.  As the relicensing case progressed, the original license expired, after which Green Mountain Power operated the project under annual licenses pending the disposition of its license application.

Over time, the applicant revised its proposal, in part to propose a change to run-of-river operation as contemplated by the project's Vermont Department of Environmental Conservation water quality certification. Ultimately, on February 19, 2016, the Commission issued an order issuing a new license for the Waterbury Project for a period of 40 years.

In setting the 40-year license term for the Waterbury project's new license, the Commission noted its discretion under Section 15(e) of the Federal Power Act to issue new licenses for a term that the Commission determines to be in the public interest, but not less than 30 years or more than 50 years.  The order also notes the Commission's general policy "to establish 30-year terms for projects with little or no redevelopment, new construction, new capacity, or environmental mitigation and enhancement measures; 40-year terms for projects with a moderate amount of such activities; and 50-year terms for projects with extensive measures."

The Waterbury project relicensing case illustrates one potential path for what happens when a license expires for an existing FERC-licensed hydropower project.  According to the Commission, as of February 11, 2016, over 50 projects were pending relicensing, with an increase expected in applications for new licenses over the coming years.

FERC holds CO microhydro needs license

In an order issued earlier this month, the Federal Energy Regulatory Commission found that the developer of a micro-hydropower project proposed in Colorado must obtain a license for the Patton Colorado Hydropower Project's construction, maintenance, and operation.  The order illustrates one challenge facing small, distributed hydroelectric projects in the U.S.: a federal regulatory process that at times can treat microhydro projects much like traditional large dams, despite interest in a streamlined permitting process for small projects.

At issue is Section 23(b) of the Federal Power Act.  It provides that any person intending to construct project works on a non-navigable commerce clause water must file a declaration of their intention to do so with the Commission. Section 23(b) further provides that upon the filing of a Declaration of Intent, the Commission will investigate the proposed project, and, if it finds that the “interests of interstate or foreign commerce would be affected” by the proposed project, then the person intending to construct the project must obtain a Commission license before starting construction.

Under section 23(b)(1) of the Federal Power Act, 16 U.S.C. § 817(1), 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.

On May 11, 2015, as supplemented on November 10, 2015, Steve Patton filed a Declaration of Intention with the Commission concerning the proposed Patton Colorado Hydropower Project.  The project would be located on Colombine Creek, a feeder stream to the South Fork of the Rio Grande, near the town of South Fork, Mineral County, Colorado.  It would consist of an intake and pipes feeding a gravitation water vortex-type generating unit rated between 2 and 10 kilowatts with 2.5 feet of head, transmission line, and appurtenant facilities. The proposed project would be connected to the interstate electric grid.

In the case of the Patton Colorado Hydropower Project, the Commission found that licensure is required under the fourth prong of Section 23(b)(1) of the Federal Power Act, which itself has three components.

First, the Commission found that the Patton project would be located on a "Commerce Clause stream."  Specifically, the Commission found that Colombine Creek is a headwater or tributary of the South Fork of the Rio Grande, which is a tributary of the Rio Grande River, a navigable water of the United States.  Under a 1965 Supreme Court precedent, for purposes of FPA section 23(b)(1), the headwaters and tributaries of navigable rivers are Commerce Clause streams.

Second, the project would be constructed after August 26, 1935. 

Third, citing a 1992 opinion from the 11th Circuit Court of Appeals, the Commission noted, "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 the FPA section 23(b)(1)."  Thus the Commission concluded that the Patton Colorado Hydropower Project would affect interstate commerce through its connection to the interstate grid.

Based on these conclusions, the Commission found that in accordance with section 23(b)(1) of the Federal Power Act, the applicant must obtain a license for the construction, maintenance, and operation of the Patton Colorado Hydropower Project.  The Commission also ruled that no construction or operation of the project may commence until a license has been obtained.

Notably, the Commission was able to reach this conclusion without making a navigability finding for Colombine Creek itself.  In particular, the order notes "insufficient evidence to determine whether Colombine Creek is navigable." But because the Commission found licensing to be required on other grounds -- grounds derived from the ultimate navigability of a downstream river -- it did not make a navigability finding for the river reach where the project would be located.

The Commission's order did suggest that an easier path may be available for the Patton Colorado Hydropower Project.  In particular, the order notes that the project may be eligible for an exemption from licensing.  It suggests that the applicant consider applying for a small hydroelectric power project exemption of 10 megawatts (MW) or less.  This more limited approval could enable project development and operation through a more streamlined regulatory processes than that required for a full project license.

Incentives and policy support for microhydro projects are growing.  But as the Patton Colorado Hydropower Project case before the FERC illustrates, even small hydropower projects may be subject to federal regulation.  For some projects, an exemption may be available, but others may not be able to be developed without a FERC license.  Even an exemption can take time and expense to secure, and it can be hard to preduct the outcome of an application for an exemption.  How does this dynamic affect the rate of development of U.S. micro-hydropower projects?

Successive preliminary permit for Cave Run hydro project

Federal energy regulators have issued an order issuing a successive preliminary permit to Cave Run Energy, LLC for a proposed hydroelectric project to be located at a dam in Kentucky owned by the U.S. Army Corps of Engineers.

The Federal Power Act provides for federal regulation of most hydropower projects in the U.S. Under Section 4(f) of the Federal Power Act, 16 U.S.C. § 797(f), the Federal Energy Regulatory Commission is authorized to issue preliminary permits for the purpose of enabling prospective applicants for a hydropower license to secure data and prepare material supporting a license application as required by section 9 of the Federal Power Act.  As the Commission has said, "The purpose of a preliminary permit is to preserve the right of the permit holder to have the first priority in applying for a license for the project that is being studied."

In the Cave Run case, on March 23, 2012, Cave Run Energy, LLC filed an application to the Commission for a preliminary permit to study the Cave Run Dam Hydroelectric Project.  The project would be located at the U.S. Army Corps of Engineers’ Cave Run Dam on the Licking River in Rowan and Bath Counties, Kentucky.  As described in that application, it would include a bifurcation structure to be constructed at the end of the dam’s outlet conduit, a powerhouse containing two turbine/generating units with a total capacity of 6.0 megawatts, a penstock and a 12.7-kilovolt transmission line.  The proposed project would use surplus water released from the Cave Run dam by the Corps.

The Commission granted Cave Run Energy a preliminary permit by order dated July 13, 2012.  That order provided that the preliminary permit was effective "for a period effective the first day of the month in which this permit is issued, and ending either 36 months from the effective date or on the date that a development application submitted by the permittee has been accepted for filing, whichever occurs first."   In the ensuing months, the applicant conducted studies and outreach, and filed a pre-application document and notice of intent to file a license application for the project.

On August 13, 2015, Cave Run Energy filed an application for a successive preliminary permit for the project.  While many aspects of the project described in the 2015 application were similar to those described in 2012, the generators' total capacity was revised to 4.95 megawatts.

After a public notice period, on February 11, 2016, the Commission issued a successive preliminary permit to Cave Run Energy for two more years.  The order granting the successive preliminary permit notes the Commission's policy to "grant successive permits if it concludes that the applicant has diligently pursued the requirements of its prior permits."  The order cites information provided by the applicant demonstrating progress with the analysis of the project’s feasibility, and towards the development of its proposed project, including the filing of a notice of intent and preapplication document.

As in some previous orders, the order granting Cave Run Energy a successive preliminary permit explains the Commission's reasoning in setting a two-year term for the successive permit.  It notes that the Hydropower Regulatory Efficiency Act of 2013 authorizes the Commission to extend preliminary permit terms for not more than two additional years if the Commission finds that the permittee has carried out activities under the permit and with reasonable diligence.  The order observes that this legislation suggests that "five years is a sufficient maximum period to prepare a development application."  Accordingly, it granted Cave Run Energy a successive preliminary permit for a 24-month term.

FERC dam license transfers, death and estates

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

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

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

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

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

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

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

Section 242 hydroelectric incentive program funding

For the first time, the U.S. Department of Energy has funding for its Section 242 hydroelectric incentive program.  The program, arising from Section 242 of the Energy Policy Act of 2005,  provides incentive payments for adding new turbines or other hydroelectric generating devices to existing sites. The Department is accepting applications for the incentive payments through February 1, 2016.

In 2005, as part of the Energy Policy Act of 2005, Congress created the Section 242 hydroelectric incentive program to support the expansion of hydropower energy development at existing dams and impoundments.  Section 242 establishes an incentive for qualified hydroelectric facilities, defined as "a turbine or other generating device owned or solely operated by a non-Federal entity which generates hydroelectric energy for sale and which is added to an existing dam or conduit."  The incentive is set at up to 1.8 cents per kilowatt-hour of net electric energy generated and sold by a qualified hydroelectric facility, indexed for inflation (about 2.3 cents per kilowatt-hour today) up to a maximum of $750,000 per year, for a specified 10-year period.

To get this money, an owner or operator must apply for the incentive payments.  An application for an incentive payment for electric energy generated and sold in a calendar year must be filed during the applications period defined by the Department of Energy in the Federal Register.  But according to the Energy Department's final guidance for the Section 242 program, "DOE will accept applications and make payments to qualified hydroelectric facilities in years when appropriations are available for this purpose."  Until recently, no such appropriations were available.

In Congressional appropriations for Federal fiscal year 2015, the Department of Energy received funds to support this hydroelectric incentive program for the first time. As shown in the conference report to the law that made appropriations for Fiscal Year 2015, Congress appropriated $3,960,000 for conventional hydropower under section 242 of EPAct 2005.

With funding now available, the Energy Department is only accepting applications from owners and authorized operators of qualified hydroelectric facilities for hydroelectricity generated and sold in calendar year 2014. Applications for this round of Section 242 funding are due by February 1, 2016.

FERC hydro dam relicensing, timing and options

Under U.S. law, the Federal Energy Regulatory Commission has jurisdiction over most hydropower dams and projects.  The Federal Power Act directs the Commission to issue licenses for hydropower projects for a defined term of years, and provides the basis for the FERC hydro relicensing process.  The relicensing process can take years, and often must be started before a licensee has made final long-term plans for the project's fate.  For example, what if a FERC licensee is considering surrendering the license and removing the dam, at the same time that its existing license approaches expiration and a relicensing application is due?

A recent order by FERC staff under its delegated authority in City of River Falls, Wisconsin, P-10489-014, illustrates this dynamic.  The City of River Falls, Wisconsin, holds the license for the River Falls Project on the Kinnickinnic River, in Pierce County, Wisconsin.  When the license for the River Falls Project was issued, the Commission determined that a 30-year term was appropriate and in the public interest.  That current license expires on August 31, 2018.

Because the FERC hydropower relicensing process can take years -- or longer -- licensees who wish to retain licensure are required to start the planning, stakeholder, and application filing processes early.  In the River Falls case, a relicense application will be due by August 31, 2016.  To get the ball rolling, in 2013 the City filed a Notice of Intent (NOI) to relicense the project and Pre-Application Document (PAD) and elected the Commission’s Traditional Licensing Process (TLP).

Meanwhile, the City of River Falls is trying to evaluate the project's future.  The City is considering surrendering the license instead of continuing with relicensing, and to draft and adopt a Kinnickinnic River Corridor Planning Strategy to "reflect a single community vision for the river, with or without the hydroelectric project."

But the studies and deliberation required to evaluate dam relicensing, surrender, or alternatives take time.  Meanwhile, the clock ticks toward license expiration.  The City tried to buy 5 more years, by asking FERC to extend the termination date of its existing license, so that it expires on August 31, 2023.  As described by FERC:

The City states the additional time is needed so that it does not spend time and money relicensing the project only to determine through its Corridor Plan that the license should be surrendered and the project decommissioned. The City believes that a lengthy and expensive licensing process is the wrong process for making such a determination. The City explains that a decision about the future of the project would be made by the fall of 2017, and a notice of intent to relicense the project or a surrender application would be filed no later than August 31, 2018.

The City's request was supported by public commenters, mostly on the theory that an extension would allow time to explore license surrender and dam removal.

But as expressed in the order, the Commission saw "no reason why the City cannot evaluate both license surrender and relicensing in the remaining time it has to file a relicense application (due August 31, 2016). In fact, analysis of studies and feedback from agencies would help inform its decision of whether or not to continue to pursue the project."  In particular, the Commission did not view the simultaneous City's Corridor Plan process as "unique circumstances or circumstances beyond the City’s control that prevent it from making a determination by August 31, 2016... as to whether to relicense or to surrender the project."

The Commission also distinguished the River Falls case from precedent where it has extended other license terms, either to enable a licensee to amortize the cost of substantial improvements to project facilities or substantial new environmental measures, or to coordinate the license expiration date with the expiration dates of other licenses in the same river basin.

Ultimately, the Commission denied the City of River Falls, Wisconsin’s application to extend the license term for the River Falls Project from August 31, 2018, to August 31, 2023.  As noted in the Commission's order, the "City remains able to work on both a relicensing option and a surrender option while it develops its Corridor Plan should the City wish to do so."

The City has filed its Notice of Intent and Pre-Application Document, and has received Commission approval to use the Traditional Licensing Process.  Any relicense application will be due 2 years before the current license expires, or on August 31, 2016.  In the meantime, the City will presumably continue to explore its options, including license surrender and dam removal, or relicensing the project.