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.

FERC proposes FAST Act CEII rules

The Federal Energy Regulatory Commission has proposed amending its regulations designed to protect critical information about utility infrastructure.  If adopted, the new regulations would govern the treatment of Critical Energy/Electric Infrastructure Information (CEII) whose disclosure and misuse could put the electric grid at risk.

In the wake of the September 11, 2011 terrorist attacks, the Commission took steps to identify and protect sensitive information it considered "Critical Energy Infrastructure Information," or CEII.  In general, FERC defined CEII as specific engineering, vulnerability, or detailed design information about proposed or existing critical infrastructure (physical or virtual) that:

1. Relates details about the production, generation, transmission, or distribution of energy;
2. Could be useful to a person planning an attack on critical infrastructure;
3. Is exempt from mandatory disclosure under the Freedom of Information Act; and
4. Gives strategic information beyond the location of the critical infrastructure.

Some previously public material was designated as CEII, and going forward newly filed or issued documents had to be screened for CEII.  FERC also created a process to allow individuals with a valid or legitimate need to access CEII, while protecting it from other disclosure.

But last year, Congress weighed in on the protection of certain sensitive information about infrastructure.  The Fixing America's Surface Transportation (FAST) Act, signed into law on December 4, 2015, included provisions designed to improve the security and resilience of energy infrastructure in the face of emergencies.  In particular, the FAST Act added section 215A to the Federal Power Act, directing the Commission to issue regulations covering the security and sharing of "Critical Electric Infrastructure Information."

Federal Power Act section 215A(a)(3) defines the new term Critical Electric Infrastructure Information as:

information related to critical electric infrastructure, or proposed critical electrical infrastructure, generated by or provided to the Commission or other Federal agency, other than classified national security information... Such term includes information that qualifies as critical energy infrastructure information under the Commission’s regulations.

As interpreted by the Commission, this encompasses "not only information regarding the Bulk-Power System but also information regarding other energy infrastructure (i.e., gas pipelines, LNG, oil, and hydroelectric infrastructure) to the extent such information qualifies as Critical Energy Infrastructure Information under the Commission’s current regulations. "

On June 16, 2016, the Commission issued a Notice of Proposed Rulemaking, proposing to amend its regulations to implement the provisions of the FAST Act pertaining to the designation, protection and sharing of critical electric infrastructure information, and also proposing to amend its existing regulations pertaining to CEII. The proposed changes include criteria and procedures for designating information as CEII, a specific prohibition on unauthorized disclosure of that information, and sanctions for knowing and willful wrongful disclosure of CEII by federal personnel.

Comments on the Notice of Proposed Rulemaking are due 45 days after its publication in the Federal Register.

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 Order 800 eases hydropower regulations

The Federal Energy Regulatory Commission has issued an order streamlining its regulations for some small hydropower projects.  FERC Order No. 800 conforms the Commission's regulations to the Hydropower Regulatory Efficiency Act of 2013.  Between Order 800 and the Hydropower Efficiency Act, regulatory processes for developing some small hydropower projects have recently become easier.

Hydropower is one of the nation's most abundant sources of renewable energy -- and yet about 97 percent of the estimated 80,000 dams in the United States do not generate electricity.  While not all are great candidates for hydropower, some non-power dam sites offer significant opportunities to generate renewable electricity with minimal incremental environmental impact.

Congress had these dams in mind when it enacted the Hydropower Efficiency Act on August 9, 2013.  To encourage the use of these dams for electric generation, the Act aims to reduce the costs and regulatory burden on project developers during the project study and licensing stages.  In particular, the Act amended previous statutory provisions covering both preliminary permits and projects that are exempt from licensing.  These statutory changes prompted FERC to update its regulations to conform to the Hydropower Efficiency Act.

Order No. 800 formalizes the Commission's compliance procedures in its revised regulations on preliminary permits, small conduit hydroelectric facilities, and small hydroelectric power projects, and in a new subpart on qualifying conduit hydropower facilities.  Key changes include:

• New regulations recognize the Commission's new statutory authority to extend a preliminary permit once for not more than two additional years, allowing permittees up to 5 total years to complete their feasibility studies without facing possible competition for the site from others.
• Exempt small conduit hydroelectric facilities may now be located on federal lands, and all exempt small conduit hydroelectric facilities may now have an installed capacity of up to 40 megawatts.  Previously, non-municipal small conduit exemptions were limited to 15 megawatts.
• Exempt small hydroelectric power project facilities may now have an installed capacity of up to 10 megawatts.
• Qualifying conduit hydropower facilities, which do not require licensure under the Federal Power Act but do require the filing with FERC of a notice of intent to construct, are now covered under the regulations.

While several of these categories of facility appear similar, each is defined separately by statute.

• A small conduit hydroelectric facility, as defined in section 30 of the Federal Power Act, is an existing or proposed hydroelectric facility that utilizes for electric power generation the hydroelectric potential of a conduit, or any 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.
• A small hydroelectric power project, as defined in the Public Utilities Regulatory Policies Act of 1978 (PURPA), is a project that utilizes for electric generation the water potential of either an existing non-federal dam or a natural water feature (e.g., natural lake, water fall, gradient of a stream, etc.) without the need for a dam or man-made impoundment.
• A qualifying conduit hydropower facility, as defined in the Hydropower Efficiency Act, is a facility that meets the following qualifying criteria: (1) the facility would be constructed, operated, or maintained for the generation of electric power using only the hydroelectric potential of a non-federally owned conduit, without the need for a dam or impoundment; (2) the facility would have a total installed capacity that does not exceed 5 MW; and (3) the facility is not licensed under, or exempted from, the license requirements in Part I of the FPA on or before the date of enactment of the Hydropower Efficiency Act (i.e., August 9, 2013).

In Order 800, the Commission is merely formalizing several practices it has already adopted since the enactment of the Hydropower Efficiency Act.  For example, the Commission has issued two-year extensions to preliminary permit holders, granted a small conduit exemption on federal lands, and issued conduit facility determinations on whether proposed projects are qualifying conduit hydropower facilities.  Nevertheless, the Act and Order No. 800 work together to offer an easier regulatory path for developers of small hydropower projects without new dams.

Pittsfield NH dam repowering project

As governments and businesses consider the hydroelectric potential of existing non-powered dams, competition is heating up to claim and evaluate the best sites.  Federal regulators yesterday resolved a conflict between two developers by awarding a preliminary permit to a developer interested in studying the feasibility of repowering or rebuilding hydroelectric energy production at an existing mill dam on the Suncook River in Pittsfield, New Hampshire.

Another former mill dam in the heart of a New England village: the Doughty Dam in North Berwick, Maine.

Yesterday's order by the Federal Energy Regulatory Commission (9-page PDF) granted a preliminary permit to KC Hydro LLC of New Hampshire to study the feasibility of the Pittsfield Mill Dam Hydropower Project.  Originally built for industrial purposes, the Pittsfield Mill Dam is currently owned by the New Hampshire Department of Environmental Services.

As described in KC Hydro's original permit application (11-page PDF), the project concept involved either restoring an existing but mothballed 415 kW turbine which previously operated under an exemption from licensing, or installing entirely new facilities (potentially with a 530 kW capacity) to capture the hydroelectric potential of the water already impounded behind the dam.

After KC Hydro submitted its preliminary permit, another developer - AMENICO Green Solutions, LLC - applied for a competing preliminary permit for the same site.  AMENICO proposed a similar project, which focused on restoring the existing 415 kW turbine.  AMENICO noted that it had property rights to the site, which it claimed KC Hydro did not.

Noting that the applications were comparable, FERC recited its standard for resolving the competing claims:

Staff has reviewed the applications and found no basis for concluding that either applicant’s plan is superior to the other. Neither applicant has presented a plan based on detailed studies or the results of agency consultation. Where the plans of the applicants are equally well adapted to develop, conserve, and utilize in the public interest the water resources of the region, the Commission will favor the applicant with the earliest application acceptance date.

Because KC Hydro had applied first, FERC awarded the preliminary permit to KC Hydro.  In doing so, FERC noted that a permit applicant is not required to have obtained all access rights to a project site as a condition of receiving a preliminary permit.  However, FERC did note that a preliminary permit does not grant a right of entry onto any lands, so a permittee must obtain any necessary authorizations and comply with any applicable laws and regulations to conduct any field studies.

With its preliminary permit in hand, KC Hydro now has 3 years to investigate the site and apply for a full project license.  Will the Pittsfield dam ultimately be repowered?

Adding hydro to Army Corps dams

As an energy resource, hydroelectricity has great potential, but siting and environmental concerns make building a new dam in the U.S. difficult.  A new trend of adding renewable electric generation to existing non-hydroelectric dams may help the U.S. grow its hydropower production without building new dams.

Last month the Federal Energy Regulatory Commission issued a license for a new hydroelectric project in Vermont, the Townshend Dam Hydroelectric Project No. 13368.  The project, first proposed in 2010 by Blue Heron Hydro, LLC, involves the installation of hydroelectric turbine-generator arrays at the existing Townshend Dam on the West River near the town of Townshend, VT.  The Townshend Dam project is particularly interesting in that it represents a new model: upgrading existing dams without hydroelectric generation to be able to produce renewable electricity.

The U.S. Army Corps of Engineers owns and maintains the rock-and-earth-fill Townshend Dam, a structure 133 feet high and 1,700 feet long.  The Townshend Dam is part of a system of 14 dams that are operated to provide flood protection for the numerous communities along the Connecticut River.  In addition to flood control, the Corps operates Townshend Dam and Lake for fish and wildlife enhancement and recreation.

Blue Heron Hydro proposes to install twelve turbines and 77-kW submersible generators at the dam site, for a total of 924 kW.  As proposed, the turbines would not change the dam's current run-of-river operation but would rather divert water that currently spills over the dam to flow through the turbines, producing power.  A seasonal downstream fish passage facility would also be installed, primarily for Atlantic salmon.

FERC has now issued an original license for the project.  The license contains a variety of conditions and requirements, but grants Blue Heron Hydro the right to construct, operate, and maintain the project.

The Army Corps manages a portfolio of 693 dams, many of which do not currently have hydroelectric or hydrokinetic generation facilities installed.  Developers are exploring the opportunity to produce hydropower at many of these Army Corps sites, as well as at the thousands of other unpowered but existing dams across the country.  Will the near future bring more interest in adding hydroelectric generation to existing Army Corps dams?

"Small hydro" bill before Congress

Today the full U.S. House of Representatives considers a bill to create jobs and expand production of clean and renewable energy by eliminating red tape on hydropower projects in some small canals and pipelines.  Sponsored by Rep. Scott Tipton of Colorado, H.R. 2842 is better known as the Bureau of Reclamation Small Conduit Hydropower Development and Rural Jobs Act of 2011.

The U.S. Bureau of Reclamation is a federal water management agency within the Department of the Interior.  The Bureau has built over 600 dams and reservoirs in 17 Western states, and is the largest wholesaler of water in the country as well as the second largest producer of hydroelectric power in the western United States. The Bureau's 58 powerplants produce over 40 billion kilowatt hours annually, generating nearly a billion dollars in revenue for the federal government.

Beyond these traditional hydroelectric plants, the Bureau of Reclamation's infrastructure systems include canals and pipes holding water capable of producing hydroelectricity but which are not currently doing so.  H.R. 2842 would streamline the regulatory process and reduce administrative costs for small hydropower development at existing Bureau of Reclamation canals and pipes.  It would allow the Bureau to contract with water utilities or other small hydro developers to install up to 1.5 MW of electric generation equipment into an existing canal or conduit without triggering environmental review requirements under the National Environmental Policy Act (NEPA).  It would also direct the Bureau to offer preference to water user organizations for the development of such projects under a federal lease of power privilege.

Some environmentalists have criticized the bill for relaxing environmental protections, although the House Natural Resources Committee found that the environmental impact of adding hydropower to these assets would be minimal to none because they existing man-made facilities  on disturbed ground.  If the bill passes, the Congressional Budget Office estimates that it could generate $5 million in additional federal revenues through increased hydropower production over the next decade.

Additionally, the bill could be seen as empowering small hydro projects, although its current scope is limited to projects using existing Bureau of Reclamation canals and conduits.  Nevertheless, if the bill is enacted following today's House action, it could represent a tip toward renewed small hydro development in the U.S.

Inflatable flashboards at hydro dams

Dam owners are increasingly enhancing their revenue by using inflatable flashboards to optimize their hydroelectric production.  This new technology offers dam owners and operators increased safety and increased hydroelectric generation, as well as opening the door to tax credits and other incentives.

Flashboards have traditionally been a palisade of wooden boards inserted into the top of a dam's crest.  Flashboards increase a dam's capacity to hold water.  They are typically used seasonally in temperate climates, and are removed before winter.  Flooding or even high water can wash flashboards away, impairing the dam's ability to hold water until they can be replaced.  Replacing flashboards can entail danger to personnel, and it might be a long time before water levels recede enough to allow safe reinstallation.  In the meantime, a dam's ability to safely store water can be reduced.


Inflatable flashboards allow operators to increase or decrease the effective height of the flashboard system remotely.  The ability to quickly and safely restore pond elevation after a high flow event translates into increased electricity generation.  For example, inflatable flashboards at the Deer Rips - Androscoggin 3 Hydroelectric Project on the Androscoggin River in Lewiston and Auburn, Maine, have been calculated as likely to increase electric generation by 4.56% compared to a historical baseline.

This incremental hydropower generation can be valuable to the dam owner.  Not only does it allow the facility to produce more electricity, but it may also qualify the project for federal and state tax incentives.  For example, Section 45 of the Internal Revenue Code provides a renewable energy tax credit to owners or operators of qualified renewable electric generation facilities.  That credit was extended to the incremental production gains from efficiency improvements or capacity additions developed between 2005 and 2013.  Developers can ask the Federal Energy Regulatory Commission to certify a historic baseline of power produced at existing dams, as well as the incremental increase in hydropower production due to qualifying investments.  Once FERC has issued this certification, dam owners can provide that to the Internal Revenue Service to receive the tax credit.

Wave, tidal energy potential in US waters

The U.S. Department of Energy released two reports last week documenting two of the nation's potential ocean energy resources: waves and tidal streams.  Hydrokinetic energy resources such as waves, tides, and currents may soon play an increasing role in US energy supply.

Although each of these reports was prepared in 2011, DOE is pointing to the reports as demonstrating the potential of conventional and innovative water power resources to generate electricity. In its statement promoting the reports, the Department of Energy noted that water power, including conventional hydropower and wave, tidal, and other water power resources, can potentially provide 15% of our nation's electricity by 2030 (up from 6% currently).  As DOE noted, the United States currently uses about 4,000 terawatt hours (TWh) of electricity per year.  Based on these reports, and other studies, DOE estimates that the maximum theoretical electric generation that could theoretically be produced from waves and tidal currents is approximately 1,420 TWh per year, approximately one-third of the nation's total annual electricity usage.

The wave energy assessment report, Mapping and Assessment of the United States Ocean Wave Energy Resource, was prepared by the Electric Power Research Institute (EPRI).  That report identified a total available wave energy resource of 2,650 TWh per year.  As in previous studies, Alaska's Pacific coast is the wave energy standout, hosting about half of the total available wave energy.  The west coast (Washington, Oregon, and California), the northern east coast (from Maine through North Carolina), and Hawaii also host significant wave energy resources.


The tidal stream report, Assessment of Energy Production Potential from Tidal Streams in the United States, was prepared by Georgia Tech Research Corp.  It describes the effort to create a national database of tidal stream energy potential.  The geographic distribution of the tidal stream resource is similar to that of wave energy: Alaska contains the largest number of locations with "considerably high kinetic power density", followed by Maine, Washington, Oregon, California, New Hampshire, Massachusetts, New York, New Jersey, North and South Carolina, Georgia, and Florida.  In total, the report identified 50 GW of tidal stream capacity nationwide, 47 GW of which is in Alaska.

The size of these resources is significant.  What remains to be seen is whether hydrokinetic energy can be generated in a cost-effective manner.  With significant research and developments ongoing, competitively-priced hydrokinetic power may soon be generated along US coasts.

Community-based renewable energy in Maine

An innovative program in Maine seeks to facilitate the development of community-based renewable energy projects.  The program offers significant incentives for the development of qualified electric generation projects of up to 10 MW in size.

In 2009, the Maine legislature enacted a law establishing the Community-Based Renewable Energy Pilot Program to encourage the sustainable development of community-based renewable energy.  By community-based, Maine's program targets locally-owned community-scale projects (as opposed to large-scale renewable projects owned primarily by out-of-state entities).

Under the program, qualified renewable energy projects can receive significant incentives including a long-term contract to sell the facility’s output to a Maine transmission and distribution utility for up to 20 years at average prices up to $100 per MWh (equivalent to 10¢ per kWh). This incentive is attractive because not only can the contract prices be above average market prices, but also the long-term power purchase agreement makes projects easier to finance by enhancing revenue certainty.

Eligible projects can apply to the Maine Public Utilities Commission for certification as community-based renewable energy projects. This process involves making public filings, negotiating with Commission staff, and demonstrating that the project meets the program’s qualification requirements. These include restrictions on resource type, nameplate capacity, and ownership.

Under the pilot program, eligible resources include:

• fuel cells
• tidal power
• solar energy
• wind systems
• geothermal systems
• hydroelectric generators
• generators fueled by landfill gas
• biomass generators whose fuel includes anaerobic digestion of agricultural products, byproducts or wastes.

Each individual project must not exceed 10 MW in nameplate capacity. Projects must also be primarily locally owned, meaning that 51% or more of the facility must be owned by Maine residents, governmental entities, businesses, or other qualifying local owners.

Once certified, a qualified project can choose either of two incentives: a long-term contract for the output of the facility with a transmission and distribution utility, or a renewable energy credit (REC) multiplier giving a 50% bonus in the amount of RECs produced.

To date, most have viewed the long-term contract as the more attractive option. Under this incentive, projects meeting the program’s requirements can obtain a contract at a fixed or variable price, provided that two criteria are met. First, the average price per kilowatt-hour must not exceed 10 cents. Second, the cost of the contract must not exceed the cost of the project plus a reasonable rate of return on investment as determined by the Commission. These contracts may be approved for up to 20 year terms.  Projects smaller than 1 MW can contract directly with the utility, while larger projects go through a competitive process held periodically by the Commission.

What will 2012 bring for Maine's community-based renewable energy pilot program?

Could net metering save municipal hydro?

Two dams on the Royal River in Yarmouth, Maine are one step closer to removal, as a majority of the town council agreed earlier this month that the dams should be removed.  The town owns two dams near Bridge Street and East Elm Street, which provided mechanical power to mills as early as 1816.  The Sparhawk Mill site near Bridge Street was upgraded to produce hydroelectricity in 1984, and operates as a privately-owned hydroelectric project exempt from most Federal Energy Regulatory Commission regulation.  Yarmouth has considered dam removal for several years, with concerns over fish habitat restoration as the driving factor.

The push to remove the dams comes despite the value of the sites' ability to generate renewable electricity.  A consultant hired by the town in 2010 estimated that the Bridge Street site could theoretically produce over $150,000 in annual hydropower revenues (7 page PDF), with $55,000 being a more realistic estimate of practical production from the existing facilities if they could be repaired and maintained.  In reaching this figure, the report assumed the then-current energy price of 7 cents per kilowatt-hour (kWh).  The report also assumed that the project could qualify for net metering, which the report defined as "unused power is purchased by the utility".

Maine's style of net metering at present is slightly different from that suggested in the report.  Under what Maine calls net energy billing, the owner of eligible renewable or micro combined heat and power (CHP) equipment can use the generation facility to offset its consumption of electricity from the grid, effectively running its electric meter backwards.  If a customer generates more electricity than it uses in any given month, the utility banks the excess amount as credits to be used within the next year.

One advantage gained by a net metering customer is that when generation offsets consumption, the customer saves on more than just the energy component of its electric bill.  In Maine's electricity market, customers pay for both the energy they use and what it costs to deliver that energy over transmission and distribution wires.  Today, the standard offer energy price for residential and small commercial customers in Central Maine Power's territory (including Yarmouth) is 7.4 cents per kWh.  The Maine Public Utilities Commission reports that delivery fees add another 6.47 cents per kWh for residential customers, or 6.3 cents for small commercial customers.  Thus the total cost to these customers of buying electricity and having it delivered is closer to 13.7 cents per kWh - nearly double that assumed in the town's report.  This higher figure may more accurately reflect what the town could save by net metering the Sparhawk Mill project's output against its consumption.

Maine also allows more than one customer to cooperate in net metering.  One eligible generation project can be used to offset consumption on up to 10 customer accounts, provided the participating customers establish partial ownership or an entitlement to the part of the project's output.  This shared ownership net metering lets eligible projects reach their full potential, even when they can produce more electricity than the primary owner needs in a year.

If the town can take the full value of net metering into account and find a way to benefit from the existing renewable generation at the Sparhawk site, the economics would tip towards keeping the Sparhawk project running.  There are other ways that project revenues could be boosted by smart participation in other energy programs, such as selling capacity or renewable energy certificates (RECs) if the project can be certified as renewable.

Would reevaluating the Royal River dam's hydropower potential lead the town to a different conclusion on whether the dam should be removed?  The Yarmouth town council is holding a workshop session on January 5 and a public hearing on January 19 to discuss next steps.

Alaska's Susitna hydro project revived

A large hydroelectric project proposed by Alaska's public power authority is moving closer to reality.  With over 600 megawatts of electric generating capacity, the Susitna-Watana Hydroelectric Project would be the largest dam built in the U.S. since 1966, when the Glen Canyon Dam was built on the Colorado River in Arizona.  If built, the Susitna project would represent a return to both mega-scale hydro and state-backed hydroelectric development in the United States.

The Susitna River project has been under consideration for nearly 50 years, although environmental concerns and the relatively low cost of oil dampened interest in the project for much of that time.  Increasing fossil fuel costs, renewable energy targets, and interest in exploiting the state's sovereign resources have now led to a revival of the project.  In 2011, Alaska state legislators unanimously approved funding for the Alaska Energy Authority to pursue the project.

The Alaska Energy Authority (AEA) was created by the Alaska Legislature as a public corporation of the state, albeit with a separate and independent legal existence.  AEA's missions include reducing the cost of electricity in Alaska, and constructing, acquiring, financing, and operating projects that utilize Alaska's natural resources to produce electricity and heat.

Renewed interest in the Susitna project comes partly in response to Alaska's renewable portfolio standard law.  In 2010, the Alaska Legislature enacted House Bill 306, creating a goal that the state receive 50% of its electric generation from renewable and alternative energy sources by 2025.  The project could also produce low-cost electricity, with generation costs projected to be lower than natural gas over the life of the project, possibly significantly lower once the project's financing is paid off.


AEA now plans to follow the traditional process for licensing hydroelectric projects through the Federal Energy Regulatory Commission.  AEA is expected to file its pre-application document with FERC on December 29, 2011, with the license review process expected to take up to six years.


If the Susitna project is built, it will be a departure from the recent trend of dam removal.  Some observers have argued that the era of building large-scale hydroelectric facilities in the United States ended decades ago, but the Susitna project could reverse that trend.  Moreover, the Susitna project would be built by a sovereign state government, echoing historic federal efforts like the Tennessee Valley Authority and Bonneville Power Authority.

Maryland dam faces sedimentation threat

In September 2011, Tropical Storm Lee caused flooding in the mid-Atlantic region.  The Susquehanna River rose far above its banks, causing disruptive floods in Pennsylvania and Maryland.  Near the river’s mouth into Chesapeake Bay, massive flooding threatened to breach the 572-megawatt Conowingo Dam.

With its flood gates wide open, the dam survived the flooding.  At peak flows, about 7 million gallons flowed through the dam every minute.  That water transported millions of tons of sediment from the Susquehanna watershed out into the bay, along with large amounts of trash and debris.

The impacts of the flood are still being assessed.  Under typical operations, the dam builds up about 2 million tons of sediment every year, or about two-thirds of the Susquehanna River's total sediment burden.  (Compare the dams currently being removed from the Elwha River in Washington, which had trapped an estimated 24 million cubic yards of sediment.)  Overall, four dams on the Susquehanna might hold up to 280 million tons of sediment.

While Lee removed several years' worth of sediment from the Conowingo Dam, more sediment builds up every year.  The Army Corps is concerned that the Susquehanna River dams have nearly reached their full capacity to hold sediment, and is launching a project to study what could be done, such as sediment dredging or remediation.

Headwater benefits charges affect hydropower projects

Suppose you own a federally-licensed dam and hydroelectric generation facilities on a river.  The amount of electricity you can produce is determined by factors including how much water is flowing through your turbines every second and the dam’s “head”, or effective height through which that water falls.  Over an entire year, the amount of power you can produce is also affected by how much water can be stored in the watershed above your dam, and how well you can regulate the flow of water through your turbines.  For example, if you can impound more floodwaters upstream instead of spilling excess water over the dam, you can maintain maximum flows through your powerhouse for a longer period of time than you otherwise could.

Now suppose someone else builds a dam upstream from your site that enables better storage and regulation of water flows through the river.  Setting aside any environmental impacts from that change in flow, one upside of the improved flow regulation is that you can produce more power at your dam thanks to the upstream improvements.

Under the Federal Power Act, you may be required to reimburse that upstream dam owner for an equitable part of the benefits you receive from its improvements.  Federal hydropower licenses typically include a provision requiring the licensee to reimburse the owner of an upstream improvement for these headwater benefits.

Under the Commission’s regulations, headwater benefits charges can be calculated using an “energy gains” methodology.  This analysis includes an assessment of the difference between the number of kilowatt-hours of energy produced at a downstream project with the headwater project and that which would be produced without the headwater project.  Alternatively, dam owners may negotiate an agreement on headwater benefits charges and present it to the Commission for approval as a settlement offer.

Large hydroelectric projects around the world

Hydroelectricity provides a significant amount of usable power across the world.  According to the U.S. Energy Information Administration, in 2008 hydroelectric generation produced 3,119,012 million kilowatt-hours, or 16% of the total electricity produced in the world.  In the U.S. between 1998 and 2009, hydroelectric generation produced between 6-9% of the nation's total electric generation, depending on water availability.

Hydroelectricity is also responsible for many of the largest generating facilities.  For example, the federal Grand Coulee Dam in Washington has a summer nameplate capacity of 7,079 megawatts, making it nearly twice as large as the next biggest U.S. power plant (Arizona's Palo Verde nuclear generating station).

Around the world, large hydroelectric projects produce immense amounts of power.  When China's Three Gorges Dam project on the Yangtze River is complete, it is projected to include 32 separate 700 megawatt generators, producing a total project capacity of 22.5 gigawatts.  This will make the Three Gorges Dam not only the largest hydroelectric dam in the world, but also the largest power station of any type.

Brazil's Itaipu Dam, producing up to about 14 gigawatts from the Paraná River along the Brazil-Paraguay border, is both the second largest hydroelectric plant and the world's second largest power station of any type.

Brazilian developers have also proposed the Belo Monte dam on the Amazonian Xingu River, which has received key environmental permits despite opposition on social and environmental grounds.  If built, Belo Monte would be able to produce up to about 11 gigawatts of power, making it the third largest hydroelectric facility in the world.  This week, a Brazilian judge issued a legal injunction against the Belo Monte development, noting the risk that fisheries would be damaged by its construction and operation.  Will Belo Monte become the world's third largest power plant?

Small hydro approved under fast process

This month, federal energy regulators approved a small hydroelectric project within two months of its formal proposal under an innovative streamlined regulatory path.

Recognizing the potential of small hydro projects, the Federal Energy Regulatory Commission (FERC) is interested in simplifying the regulatory process for small projects.  Last year, FERC signed a Memorandum of Understanding with the state of Colorado to streamline the procedures for developing small-scale hydropower projects in that state.  Colorado has identified hundreds of small (5 MW or smaller) or conduit hydropower projects (turbines in water pipes and irrigation canals) whose total capacity could exceed 1,400 MW.  Under the Memorandum of Understanding, Colorado is developing a pilot program to test ways to simplify the processes through which project developers obtain exemptions for small projects.  For example, the application is presented to multiple agencies for simultaneous comment, rather than a prolonged multi-agency back and forth process.

Last week, FERC approved Colorado's first hydroelectric project under the Memorandum of Understanding.  Docketed as Project P-14230, the Meeker Wenschhof hydroelectric project will be developed on an existing ranch irrigation pipeline in northwestern Colorado.  Historically, water flowing through the pipe has been slowed by a valve before being stored in an underground cistern.  As approved by FERC, the rancher will install a 23-kilowatt turbine in place of the valve.  The project is expected to generate 100,000 kilowatt-hours per year on average.

The Meeker Wenschhof project's engineering details are interesting, making innovative and efficient use of the power of flowing water.  Equally interesting is the speed with which the project flew through the regulatory approval process, with the application granted just two months after it was filed with FERC.  Admittedly, this expedited process is currently limited to small hydro and conduit projects.  Nevertheless, the Meeker Wenschhof project's rapid approval illustrates how quickly the regulatory process can be completed if it is designed to accommodate developers' needs.

Susquehanna River flooding threatens dam, communities

Close on Hurricane Irene’s heels, the remnants of Tropical Storm Lee are dropping up to 10 inches of rain across the northeastern United States.  As we saw when Irene hit Vermont, storms like this can cause not only widespread flooding as streams rise above their banks, but even risk dam failure and more catastrophic flooding.

Now, the rains caused by Tropical Storm Lee have led authorities from Maryland to New York to order the evacuation of nearly 100,000 people.

Flooding along the Susquehanna River is responsible for a large portion of this risk.  Arising out of branches in upstate New York and western Pennsylvania, the 464-mile long Susquehanna is the longest river on the east coast to drain into the Atlantic Ocean.  The river overtopped retaining walls in Binghamton, NY earlier today, leading to road closures that effectively isolate the city.  Downstream, deepening floods have caused the evacuation of the entire city of Wilkes-Barre, PA.

The Susquehanna flooding has also impacted the Conowingo hydroelectric dam about 10 miles above the river’s mouth in Maryland.  With 11 turbines providing a nameplate capacity of 572 megawatts, the Conowingo dam is one of the nation's largest non-federal hydroelectric facilities.  Now operated by Exelon subsidiary Susquehanna Electric Company, the Conowingo Dam is threatened by the Susquehanna floodwaters.  As a result, 50 of the dam’s 53 flood control gates have been opened, causing authorities to evacuate people from the downstream communities of Havre de Grace and Port Deposit.  Area residents remember 1972's Hurricane Agnes, whose rains and flooding caused all 53 flood gates to be opened and the dam operator to prepare for a controlled breach of part of the dam.

As Lee’s rains move out of the area, water levels in the Susquehanna River will peak and then recede.  Time will tell how damaging the flood waters will be.         

July 15, 2011 - will Maine have a new largest dam?

Since 1954, Maine's largest-capacity hydroelectric dam has been the 85 megawatt Harris Dam on the Kennebec River - but it may soon lose its title to another project on the same river.

Water spills over the last falls on the Cathance River in Topsham, Maine.  These falls powered a sawmill as early as 1716.

Harris Dam may soon lose its title as Maine's largest dam -- but not because a new dam is being built.  Rather, dam owner FPL Energy Maine Hydro LLC -- a subsidiary of NextEra Energy Resources -- has embarked on a program to improve the efficiency of the three turbines at Wyman Dam, the next dam downstream from Harris.

Wyman Dam, currently rated at 83 megawatts capacity, was built in 1930, 24 years before the Harris Dam.  Improvements to two of the three Wyman turbine generators have already occurred, and NextEra now proposes to complete the project.

Between the recent efficiency upgrades and a closer look at older improvements, NextEra now thinks the overall licensed project capacity should increase from 83,700 kW to 88,010 kW, an increase of 4,310 kW.  NextEra has applied to the Federal Energy Regulatory Commission for a license amendment to reflect these upgrades.

Comments on this proposal are due by August 5, 2011.  If approved, Wyman Dam's newly-tallied 88 megawatts of capacity will slip past Harris Dam's 85 MW to become Maine's largest hydroelectric dam.