FERC workshop on abandoned mine pumped storage

Federal hydropower regulators have scheduled a workshop to explore potential opportunities for development of closed-loop pumped storage projects at abandoned mine sites, as required by the America's Water Infrastructure Act of 2018.

Enacted by Congress and signed by President Trump in October 2018, the Act 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. Among other requirements, the Act directed the Commission to issue a rule establishing an expedited process for issuing and amending licenses for closed-loop pumped storage projects under this section.

The Act also includes provisions designed to facilitate exploration of the use of abandoned mine sites for pumped storage projects. Section 3004 of the Act requires the Commission to 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. In November 2018, the Commission docketed its action on Closed-loop Pumped Storage Projects at Abandoned Mines Guidance as Docket No. AD19-8-000 and established a schedule for rulemaking, public comment, and issuance of guidance.

The Commission has now issued a Notice of Workshop in the abandoned mine pumped storage docket, scheduled for April 4, 2019. The notice states that the workshop will involve roundtable discussions by panelists, moderated by Commission staff. The agenda for the workshop includes discussion of how to identify sites for development of closed-loop pumped storage projects at abandoned mines, as well as the benefits and challenges associated with the use of abandoned mines for pumped storage. The agenda also includes time for soliciting feedback from the workshop panel and other participants on what types of information would be most helpful to include in the guidance mandated by the Act.

Can challenges or prize competitions solve water supply problems?

How can challenges or prize competitions help society address barriers that may prevent long-term access to low-cost water supplies?

The U.S. Department of Energy's Office of Energy Efficiency and Renewable Energy (EERE) has published a Request for Information, seeking information from the public to understand the key technical and other barriers that may prevent long-term access to low-cost water supplies that could be best addressed through challenges and prize competitions.

Water is essential for human health, economic growth, and agricultural productivity, and plays significant roles in the U.S. energy sector. The Department of Energy uses the term "energy-water nexus" to describe the interconnected nature of energy and water systems. While the U.S. has generally benefited from access to low-cost water supplies, according to the Energy Department, "new challenges are emerging that, if left unaddressed, could threaten this paradigm" including competing uses and water quality problems.

The Energy Department operates a variety of programs to advance domestic energy policy, including programs focused on research and development and grant funding. But could the Department of Energy be more effective by offering challenges or prize competitions? Unlike traditional R&D funding in which participants are selected up front with funding provided at the beginning in order to pursue a target or goal, challenges and prize competitions typically define a problem and offer a reward to anyone finding a solution.

Challenges and prize competitions have been adopted by the federal government as well as private actors. Since 2010, federal entities have awarded millions of dollars in prize money and other incentives through over 740 challenges and prize competitions, and nonprofits and private companies have launched many more.

In a Request for Information published in the Federal Register on March 19, 2018, the Energy Department identified challenges and prize competitions as "tools and approaches the Federal government and others can use to engage a broad range of stakeholders, including the general public, to develop solutions to difficult problems. Challenges and prize competitions rely on competitive structures to drive innovation among participants and usually offer rewards (financial and/or other) to winners and/or finalists."

Through the request, the Energy Department asks for public feedback on a variety of issues relating to using prizes and challenges to solve problems around the energy-water nexus, including an identification of challenges whose solution would allow for a significant increase in the volume of available water produced from non-traditional sources, significant improvements in industrial and power-sector water efficiency, or reductions in the cost to treat and deliver drinking water and wastewater to consumers without harming water quality.

Responses to the Request for Information are due no later than 5:00 p.m. (ET) on May 14, 2018.

Maine considers water shortage readiness

In the midst of a regulatory inquiry into Maine water utilities' ability to prepare for and respond to water supply emergencies, agency staff have issued a preliminary recommendation intended to stimulate further discussion and comment -- which could ultimately lead to changes in how Maine regulates water utilities and water supply.

2016 brought drought to much of Maine. According to a Notice of Inquiry issued by the Maine Public Utilities Commission that year, the drought posed special challenges for some of Maine's water systems with limited sources of supply -- especially those with significant seasonal demands, antiquated infrastructure, or high levels of non-revenue water. In response, the Commission opened an inquiry to gather information that will allow it to identify problems and identify collaborative and proactive solutions. The Commission received responsive comments from about a dozen water utilities, and staff conducted additional research on the topic.

On March 5, 2018, the Commission staff issued its Preliminary Recommendation in regard to the Inquiry. The document describes its recommendations as preliminary and “intended to stimulate further discussion and comment on the issues raised in the document”. It says its intended audience “is broader than the usual participants in Commission proceedings and includes entities that may not be familiar with Commission practices and governing statutes.”

Findings in the 36-page Preliminary Recommendation include:

• Maine’s 152 water utilities responded well to the 2016 drought.
• Most of Maine's water utilities should be allowed to make their own decisions regarding water supply emergencies.
• Most Maine water utilities have the ability to adequately prepare for, and respond to, a water supply emergency.
• Water supply emergencies are not amenable to a one-size-fits-all approach because of the wide variety of potential circumstances.
• All Maine water utilities should be required to prepare some sort of Emergency Response Plan, and all that experience a water supply emergency should be required to prepare an after-action report.
• Water utilities need clearly-defined authority to respond to a water supply emergency -- ideally in the utility's Terms and Conditions.
• Various entities can provide help to a water utility that needs assistance preparing for, and responding to, a water supply emergency. Support can come from neighboring systems, membership organizations, and state agencies.
• State agencies should work cooperatively to support water utilities before, during, and after a water supply emergency.
• Effective communication before and during a water supply emergency is critical.
• Some Maine water utilities are more vulnerable to a water supply emergency and may need assistance -- especially those with a limited source of supply, aging infrastructure, high levels of non-revenue/unaccounted-for water, seasonal demands, and lack of metered service. Other challenges include a lack of resources, recalcitrant customers, and local socioeconomic factors, or excessively prioritizing low rates over critical system improvements.

Commission staff has requested written comments by March 30. It said it is considering holding between two and five workshops across Maine to solicit oral comments about the Preliminary Recommendation, after which it will draft a Final Recommendation for the Commission’s review.

Maine utility water supply inquiry

As Maine utility regulators consider how drought and other factors affect water utility supplies, staff at the Maine Public Utilities Commission have again requested comments and information on water supply emergencies and regulatory responses.  The feedback will inform a preliminary staff recommendation to be released in January 2017, which could lead to changes in how Maine regulates water utility supplies.

Drought and water shortage are affecting parts of the U.S., including much of New England.  In October, the Maine Public Utilities Commission issued a Notice of Inquiry (NOI) into water supply issues.  The Commission requested information about water supply problems, potential solutions, and development of plans to address any problems identified.  Specifically, the Commission posed 14 questions about water supply emergencies, plus 9 more questions about how the Commission should respond to water supply emergencies.  The Commission requested responses to these questions by November 4, 2016.

Some Maine water utilities responded to the Commission's water supply Notice of Inquiry, but many did not file a public response.  In a November 28, 2016 Procedural Order, Commission staff expressed a firm belief "that the more input the Commission receives from affected parties, the greater the likelihood that the final outcome in this Inquiry will meet the needs of those affected parties."  Accordingly, the procedural order invites any entity that did not initially respond to the NOI to do so by December 23, 2016.

The November 28 procedural order establishes a schedule for the remainder of the inquiry.  Staff intends to issue a Preliminary Recommendation in January, to which interested persons will be invited to respond during February, whether orally or in writing.  The schedule contemplates that staff would incorporate written and oral comments regarding the Preliminary Recommendation into a Final Recommendation in March, for presentation to the Commissioners during April.

The Commission has docketed the Maine water supply inquiry as Docket No. 2016-000233.

Drought and state water utility regulation

As drought affects parts of the U.S., some state regulators have expressed concerns over whether shortages will cause water supply emergencies for water utilities.  A recent Notice of Inquiry issued by the Maine Public Utilities Commission illustrates one approach to regulation of water supply management.

New England is abnormally dry this fall.  According to the U.S. Drought Monitor's National Drought Summary for October 11, 2016, "All areas except extreme northern Maine are now in abnormally dry or drought status. Moderate drought was expanded over eastern New York and Vermont while severe drought was expanded in southern New York and northern New Jersey."

Drought can mean water shortages, both for water utilities and for their customers.  As noted by the Maine Public Utilities Commission in an October 5, 2016 Notice of Inquiry into water supply issues, "Some are as of Maine are currently experiencing the impacts of drought. Some of Maine's water systems, which are located in areas where sources of supply are limited , are particularly challenged during dry conditions. In addition to a limited source of supply, some of these systems may also be disproportionately affected by seasonal demands, antiquated infrastructure, and/or high levels of non-revenue water."

As a result, the Commission opened an inquiry "to gather information that will allow it to identify problems which may exist, solicit input on ways to address any problems that are identified, and work collaboratively and proactively with Maine's water utilities and their customers, as well as other State agencies and interested persons and organizations, to develop a plan for addressing the problems that are identified."  The Commission also indicated interest in challenges other than drought that may significantly constrain a utility's source of supply.

The Commission divided its questions into two primary categories.  The first set seeks information to help the Commission to identify current and potential water supply problems and specific solutions to those problems.  These questions relate to recent water supply problems and their impacts, utility responses like voluntary or mandatory conservation measures, and communications with state agencies.

The Commission's second set of questions seeks input on what procedural steps the Commission should take to best address those problems.  This second set focuses on "the extent to which the Commission should be proactively involved in the development of a plan to deal with water supply emergencies and how the Commission should respond when a water supply emergency occurs."
 
The Commission requested that comments and responses be filed in Docket No. 2016-00233 by November 4, 2016.

Alta, snowmaking pipes and conduit hydro power

Federal energy regulators have issued Alta Ski Area a written determination that its proposed micro-hydropower project will not be required to be licensed under the Federal Power Act.  If developed, Alta's project would be one of the first to generate electricity from a snowmaking water supply pipeline.

Most grid-connected hydropower projects in the U.S. fall under the Federal Power Act, and generally require a license or exemption from the Federal Energy Regulatory Commission.  The process of securing an original license or exemption for a new project can take years and have high costs.  But under a 2013 law, some so-called "conduit" hydro projects -- using pipelines and other existing manmade water conveyances -- can be developed and operated without a license or exemption.  The Hydropower Regulatory Efficiency Act of 2013 defined criteria for the Commission to declare a project to be a "qualifying conduit hydropower facility," and provided that such facilities are not required to be licensed or exempted from licensing under the Federal Power Act.  Key factors include the use of a non-federally owned, 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.  If the Commission determines that a project qualifies, it can be built and maintained without a FERC license or exemption.

Under the Commission's process for evaluating conduit hydro projects, the developer must file a notice of intent to construct a qualifying conduit hydropower facility.  If the developer's filing demonstrates that the project meets the statutory criteria, the Commission will issue a notice of its preliminary decision that the project qualifies.  Following a 45-day period within which others may contest the determination, assuming no adverse facts are uncovered, the Commission issues a letter constituting its written determination that the proposed project meets the qualifying conduit hydropower facility criteria.

Alta's course before the Federal Energy Regulatory Commission followed this trail.  In May 2016, Alta filed its notice of intent to construct the Alta Micro-Hydro Project.  That notice and a supplemental filing described a project to tap the existing underground 6-inch-diameter snowmaking water supply pipeline delivering water from Cecret Lake to the Wildcat Pump House.  Parallel to that pipeline, Alta would add a new powerhouse with a 75-kilowatt turbine/generating unit.  Later that month, Commission staff issued a public notice that preliminarily determined that the project met the statutory criteria.  After the 45-day contest period, during which no interventions or comments were filed, in July the Commission issued Alta a written determination that the Alta Micro-Hydro Project meets the qualifying criteria under section 30(a) of the Federal Power Act, and is not required to be licensed under Part I of that law.

The Commission's letter reminds Alta that qualifying conduit hydropower facilities remain subject to other applicable federal, state, and local laws and regulations.  But the ability to develop a conduit hydropower project without requiring a license from the FERC will ease the project's regulatory path.  So far, most projects that have qualified for the conduit hydropower program have been proposed by water districts.  But as ski areas seek to align their operations with sustainability goals, adding low-impact renewable electricity generation may make sense for some.  If Alta's micro-hydro project is successful, other ski areas with existing snowmaking or other water infrastructure over a sufficient vertical drop may follow suit by developing their own conduit hydropower projects.

FERC staff recommends against Bear River dam

Staff of the U.S. Federal Energy Regulatory Commission have recommended against licensing a dam, reservoir, and hydropower project proposed for the Bear River near Preston, Idaho.

The case involves a 2013 application by Twin Lakes Canal Company to the FERC for a license to construct, operate, and maintain the Bear River Narrows Project.  The project would be located on the main stem of the Bear River in Franklin County, Idaho, about 9 miles northeast of the city of Preston. It would feature a 109-foot-high dam impounding a 362-acre reservoir, and a powerhouse with an installed capacity of 10 megawatts and estimated average annual generation of of 48,531 megawatt-hours of electricity.  The reservoir would also be used to provide up to 5,000 acre-feet of water to Twin Lakes’ irrigation system during dry years.

Under the Federal Power Act, the FERC is charged with processing licenses for most hydropower projects in the U.S.  Federal law guides the FERC in this duty.  Sections 4(e) and 10(a)(1) of that act require the Commission to give equal consideration to the power development purposes and to the purposes of energy conservation; the protection of, mitigation of damage to, and enhancement of fish and wildlife; the protection of recreational opportunities; and the preservation of other aspects of environmental quality.  The Commission can only issue licenses that in its judgment are best adapted to a comprehensive plan for improving or developing a waterway or waterways for all beneficial public uses.  Additionally, the National Environmental Policy Act of 1969 requires the agency to analyze and document the environmental effects of proposed federal actions such as granting Twin Lakes' application.

Commission staff released its final environmental impact statement on Twin Lakes' license application on April 27, 2016.  That document, called an EIS, analyzes the effects of proposed project construction and operation, and recommends conditions for any license that may be issued for the project.

In the Bear River Narrows Project EIS, FERC staff considered Twin Lakes’ proposal for licensing, as well as three alternatives: (1) no-action (i.e. not licensing the project, so it can't be constructed); (2) the applicant’s proposal with staff modifications (staff licensing alternative); and (3) the staff licensing alternative with an additional condition requested by the Bureau of Land Management.

The EIS notes the existence of four Commission-licensed hydroelectric facilities located on the Bear River in Idaho with a combined installed capacity of more than 78 MW, including the Oneida development directly upstream.  It also notes uses of the "Oneida Narrows" section of the Bear River that would be flooded by the Bear River Narrows Project impoundment, including a recreational trout fishery and boating opportunities, and habitat for sensitive wildlife species.

Based on a review of the anticipated environmental and economic effects of the proposed project and its alternatives, as well as the agency and public comments filed on this project, staff recommends no action (license denial) as the preferred alternative.  In staff's words, "The overall, unavoidable adverse environmental effects of both action alternatives would outweigh the power and water storage benefits of the project."

For these reasons, FERC staff concluded that "any license issued for the proposed project could not be best adapted to a comprehensive plan for improving or developing the Bear River for all of its beneficial public uses, especially its substantial public recreation use at the proposed project site. We, therefore, recommend license denial."

Twin Lakes Canal Company's application to the Commission for a license to construct the project remains pending.

Utah conduit hydropower project qualifies

Federal energy regulators have issued a letter determining that a proposed Utah hydropower project meets criteria for development without needing a hydropower license.  Castle Valley Special Service District's proposed Ferron Water Treatment Plant Project would generate electricity using the pressure of water in an existing conduit entering a drinking water treatment plant.  As a result of a determination by the Federal Energy Regulatory Commission, the project can be developed without a FERC hydropower license.

On January 27, 2016, the Castle Valley Special Service District filed with the Federal Energy Regulatory Commission a notice of intent to construct a 6-kilowatt in-conduit hydroelectric net metered system.  The District is a tax exempt municipal government entity that, among other services, provides drinking water to the residents of Ferron City and Clawson Town.

That notice of intent described plans to harness or recover water pressure lost at the inlet to the District's proposed new Ferron Water Treatment Plant.  Water from the Millsite Reservoir would be transmitted to the treatment plant in a conduit owned by Ferron City and the District.  Excess pressure in the incoming untreated water would flow through a pressure reducing valve and turbine hydropower generator.

Under section 30 of the Federal Power Act (FPA), as amended by section 4 of the Hydropower Regulatory Efficiency Act of 2013 (HREA), a qualifying conduit hydropower facility -- one that is determined or deemed to meet defined criteria -- is not required to be licensed or exempted from licensing under the Federal Power Act.  These criteria include:

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

On February 2, 2016, the Federal Energy Regulatory Commission issued its notice of a preliminary determination that "the proposal satisfies the requirements for a qualifying conduit hydropower facility, which is not required to be licensed or exempted from licensing."

Following the expiration of comment and intervention deadlines, on March 28 the Commission issued its "written determination that the Ferron Water Treatment Plant Project meets the qualifying criteria under FPA section 30(a), and is not required to be licensed under Part I of the FPA."

As the FERC determination on the Ferron project notes, "Qualifying conduit hydropower facilities remain subject to other applicable federal, state, and local laws and regulations."  But the ability to develop an in-conduit hydropower project without needing a FERC license can give a significant boost to projects with suitable conduit water resources.

Restoring old mill hydro sites and FERC licensure

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

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

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

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

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

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

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

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

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

FERC requires licensure of Alaska hydropower project

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

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

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

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

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

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

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

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

Mojave Water Agency conduit hydropower project qualifies

A California wholesale water provider has received a written determination from federal regulators that its proposed hydroelectric power project qualifies for easier regulatory treatment under federal law.  The project entails replacing a pressure reducing valve on an existing water supply pipeline with a hydropower turbine and generator, to create renewable electric energy.  Crucially, its qualification as a conduit hydropower project under a 2013 federal law enables its construction without a license under the Federal Power Act.

Under the Federal Power Act, most hydropower projects must be licensed by the Federal Energy Regulatory Commission.  But the Hydropower Regulatory Efficiency Act of 2013 amended the Federal Power Act to ease the regulatory burden on certain projects described as "conduit hydropower" -- those generating electricity using only the hydroelectric potential of a non-federally owned conduit, such as a tunnel, canal, pipeline, aqueduct, flume, ditch, or similar manmade water conveyance that is operated for the distribution of water for agricultural, municipal, or industrial consumption, and is not primarily for the generation of electricity.  The 2013 reform law exempted qualifying conduit hydropower facilities from needing licensure, and created an expedited process for soliciting public comment and determining whether the exemption applies.

This reform has led to a resurgence of interest in developing in-conduit hydroelectric projects.  For projects meeting the qualifying criteria, the FERC can act swiftly in issuing a determination that no licensure is required.  In some cases, this determination can come less than 60 days after an applicant files its notice of intent.

FERC's first conduit hydro docket in fiscal year 2016, CD16-1, illustrates this pace.  In that docket, the Mojave Water Agency was able to secure a written determination that the project it proposed meets the qualifying criteria under section 30(a) of the Federal Power Act, and thus is not required to be licensed under Part I of the FPA.

Among other operations, the Mojave Water Agency stores and distributes water in California's High Desert region.  An existing 48-inch pipeline conveys raw water sourced from the State Water Project to the Mojave River Basin for groundwater recharge.  Currently, pressure is reduced through a sleeve valve before discharging the SWP water to the Mojave River Basin by gravity flow.  But under the proposed Deep Creek Hydroelectric project, a hydroelectric turbine will perform the pressure reducing function while powering a generator capable of producing renewable electric energy.  According to the Mojave Water Agency, the hydroelectric station capacity will be 800 kW, with annual estimated power generation of 5,424 MWh.

On October 13, 2015, the MWA applied to the FERC for a determination that the Deep Creek project is a Qualifying Conduit Hydropower Facility, meeting the requirements of section 30(a) of the Federal Power Act (FPA), as amended by section 4 of the Hydropower Regulatory Efficiency Act of 2013 (HREA).

On October 15, 2015, Commission staff issued a public notice that preliminarily determined that the project met the statutory criteria for a qualifying conduit hydropower facility, and thus was not required to be licensed under Part I of the FPA. The notice established a 45-day period for entities to contest whether the project met the criteria. No comments or interventions were filed in response to the notice.

As a result, on December 3 the FERC issued a letter constituting a written determination that the Deep Creek Hydroelectric Project meets the qualifying criteria under FPA section 30(a), and is not required to be licensed under Part I of the FPA.

Other proposed conduit projects have benefited from this quick timeline and relatively streamlined process.  Qualifying conduit hydropower facilities remain subject to other applicable federal, state, and local laws and regulations.

FERC authorizes mine drainage microhydro

The Federal Energy Regulatory Commission has issued a hydropower license to a project whose turbines generate electricity from acid mine drainage. The micro-hydropower license issued to the Antrim Treatment Trust illustrates this unusual approach to the twin challenges of mine remediation and renewable energy.

The power of falling water, in the White Mountain National Forest in New Hampshire.

In the 1980s, Antrim Mining, Inc. operated a surface bituminous coal mine in Pennsylvania.  When water draining through the mine and into streams and rivers was found to exceed pollution limits, the Commonwealth of Pennsylvania charged the company with violations of mining and reclamation law.  The charges led to a series of settlements through which Antrim agreed to improved water treatment facilities, including an off-the-grid hydroelectric facility.  This micro-hydro plant would be powered by treated effluent flowing downhill out of lagoons.  Antrim created the Antrim Treatment Trust to manage treatment of the mine water in 1991, then went out of business.

In an attempt to reduce the cost of treating the site's severe acid mine drainage, the Babb Creek Watershed Association identified micro-hydropower as an option for the site.  In 2008, the association received an Energy Harvest Grant from the Pennsylvania Department of Environmental Protection.  This $428,710 award was designed to support the installation of two hydroelectric turbines on the treatment plant's discharge, which was completed in 2012.

While the Federal Power Act requires most hydropower projects to secure a license from the Federal Energy Regulatory Commission, some off-grid hydropower projects that do not use the waters of the United States do not require licensure.  In 2010, the Antrim Treatment Trust filed a Declaration of
Intent for a 40-kilowatt grid-connected project, but quickly revised its project to be off-grid after the Commission issued an order finding that a license was required for the grid-connected project.  Once the project was off-grid, the Commission ruled that no license was required.

The Antrim treatment plant seems to have then operated one turbine, but left the second turbine non-operational. A 2012 article in the Williamsport Sun-Gazette suggested that with both turbines running and selling power into the electricity grid, the treatment plant could cut $12,000 in annual power costs and make $10,000 per year in new revenue.  But this could require a FERC license, because the project would become connected to the utility grid.

The Trust appears to have decided that these economics were worth pursuing, because in 2013 it filed an application for a project license for a 40-kilowatt project.  In the application, Antrim Trust proposed to bring a second identical turbine (currently in place but non-operational) online by installing additional indoor wiring with appurtenances within the existing powerhouse and treatment plant, and operate both turbines as a grid-connected project using the treated and/or untreated water.

As licensed, the Commission estimates the annual cost to develop and maintain the proposed 40-kW project is $9,356 or $37.42/megawatt-hour (MWh).  The project will generate an estimated average of 250 MWh of energy annually.  Based on Commission staff’s view of the alternative cost of power ($56.93/MWh), the total value of the project’s power is $14,233 in 2013 dollars.  To determine whether the proposed project is currently economically beneficial, staff subtracts the project’s cost from the value of the project’s power. Therefore, in the first year of operation, the project is expected to cost $4,877 or $19.51/MWh less than the likely alternative cost of power - demonstrating economic benefit.

Micro-hydropower projects can make economic sense in some mine drainage situations and other places where water treatment is required and a suitable vertical drop or pressure is available.  In Antrim's case, the project's success can partially be explained by the existence and purpose of the Trust, as well as the DEP grant to support project construction.  If treated and untreated mine drainage can be used to generate hydroelectricity, what other unusual sources of power will arise?

Obama administration releases National Climate Assessment

The Obama administration has released its third National Climate Assessment, a document designed as a public presentation of the administration's comprehensive scientific assessment of how climate change is impacting the U.S. people and economy.

A view from the Lincoln Memorial to U.S. Capitol, in Washington, D.C.

The National Climate Assessment summarizes the impacts of climate change on the United States, now and in the future.  Produced as a collaboration between over 300 experts guided by the 60-member National Climate Assessment and Development Advisory Committee, the report was extensively reviewed by the public and experts, including federal agencies and a panel of the National Academy of Sciences.

The National Climate Assessment has a broad scope, in terms of both types of impacts and regions covered.  Thematically, it analyzes impacts on seven sectors – human health, water, energy, transportation, agriculture, forests, and ecosystems – and on the bigger-picture interactions between these sectors.  Geographically, the report also assesses key impacts on all U.S. regions: Northeast, Southeast and Caribbean, Midwest, Great Plains, Southwest, Northwest, Alaska, Hawai'i and Pacific Islands, as well as a more general look at coasts and oceans.

The report states that that increased scientific scrutiny has led to "increased certainty that we are now seeing impacts associated with human-induced climate change":

While scientists continue to refine projections of the future, observations unequivocally show that climate is changing and that the warming of the past 50 years is primarily due to human-induced emissions of heat-trapping gases. These emissions come mainly from burning coal, oil, and gas, with additional contributions from forest clearing and some agricultural practices.

Outcomes predicted under possible future scenarios include continued increases in average air and water temperatures, changes in rainfall and precipitation patterns, air quality decreases, sea level rise, and ocean acidification.  These changes can disrupt systems for food production, harm human health, or damage property and risk safety through flooding.

The National Climate Assessment also summarizes options for responding to climate change.  These include mitigation: reducing the amount and speed of future climate change by reducing emissions of heat-trapping gases or removing carbon dioxide from the atmosphere.  Efforts to limit emissions or promote carbon sequestration are considered mitigation efforts.  Other possible responses focus on adaptation: preparing for and adjusting to new conditions -- for example, building levees and seawalls, or promoting farmers' growth of crops more suitable to the changing conditions.

In all, the report provides insight into the Administration’s approach to addressing climate change, and can help people and businesses both minimize risks and identify new opportunities.

The full National Climate Assessment can be explored on the government's climate change website globalchange.gov, or can be downloaded.  The entire report, downloaded in print quality resolution, clocks in at over 170 megabytes.

Report: climate change poses risks to US energy sector

Climate change poses significant risks to U.S. energy infrastructure, and the reliability and cost of the services it enables, according to a report released yesterday by the U.S. Department of Energy.

The report - U.S. Energy Sector Vulnerabilities to Climate Change and Extreme Weather Report (4.2MB PDF) was developed as part of the Obama Administration’s efforts to support national climate change adaptation planning and to advance the U.S. Department of Energy’s goal of promoting energy security. These efforts are embodied by the Interagency Climate Change Adaptation Task Force and Strategic Sustainability Planning process established under Executive Order 13514.

The report is predicated on the findings that the U.S. climate is changing, and that these changes impact energy resources and infrastructure. As the report states, "Climatic conditions are already affecting energy production and delivery in the United States, causing supply disruptions of varying lengths and magnitude and affecting infrastructure and operations dependent upon energy supply." The report provides over 30 recent examples of energy infrastructure adversely impacted by climate change-related events such as power plant outages due to high temperatures or low water availability, storm damage to transmission lines, oil wells, pipelines and generators, and flooding-related disruption of fuel transportation systems.

Building on these findings, the report identifies a broad set of risks posed by climate trends, including increasing temperatures, decreasing water availability, and increasing storms, sea level rise, and flooding, as well as the current and potential future impacts of these climate trends on the U.S. energy sector. According to the report, each of these trends will independently, and in some cases in combination, affect the ability of the United States to produce and transmit electricity from fossil, nuclear, and existing and emerging renewable energy sources. These changes are also projected to affect the nation’s demand for energy and its ability to access, produce, and distribute oil and natural gas.

In particular, significant risks identified include:

• Thermoelectric power generation facilities are at risk from decreasing water availability and increasing ambient air and water temperatures, which reduce the efficiency of cooling, increase the likelihood of exceeding water thermal intake or effluent limits that protect local ecology, and increase the risk of partial or full shutdowns of generation facilities
• Energy infrastructure located along the coast is at risk from sea level rise, increasing intensity of storms, and higher storm surge and flooding, potentially disrupting oil and gas production, refining, and distribution, as well as electricity generation and distribution
• Oil and gas production, including unconventional oil and gas production (which constitutes an expanding share of the nation’s energy supply) is vulnerable to decreasing water availability given the volumes of water required for enhanced oil recovery, hydraulic fracturing, and refining
• Renewable energy resources, particularly hydropower, bioenergy, and concentrating solar power can be affected by changing precipitation patterns, increasing frequency and intensity of droughts, and increasing temperatures
• Electricity transmission and distribution systems carry less current and operate less efficiently when ambient air temperatures are higher, and they may face increasing risks of physical damage from more intense and frequent storm events or wildfires
• Fuel transport by rail and barge is susceptible to increased interruption and delay during more frequent periods of drought and flooding that affect water levels in rivers and ports
• Onshore oil and gas operations in Arctic Alaska are vulnerable to thawing permafrost, which may cause damage to existing infrastructure and restrict seasonal access, while offshore operations could benefit from a longer sea ice-free season
• Increasing temperatures will likely increase electricity demand for cooling and decrease fuel oil and natural gas demand for heating

Looking on the brighter side, the report notes that while climate change will, on balance, create challenges and costs for the energy sector, there are potential benefits to the energy sector as well. Examples include reduced average heating loads during the winter in parts of the United States, such as New England, and the opening of new regions to offshore oil and gas exploration due to shrinking sea ice cover in the Arctic. The report also covers adaptation actions underway, as well as other major opportunities to prepare for climate change through adaptation. Nevertheless, on balance, the report finds that the magnitude of the challenge posed by climate change on an aging and already stressed U.S. energy system could outpace current adaptation efforts, unless a more comprehensive and accelerated approach is adopted. Will the U.S. follow that path? What measures will it include? Will it make a difference?

Maine funds available for anaerobic digestion

The state of Maine has announced funds available to help farmers reduce their agricultural impacts to water quality. State agencies have made up to $3 million available to enable low-interest loans to support eligible projects. These projects may include developing anaerobic digesters, as well as improved roof runoff structures, water and sediment control basins, composting facilities, and irrigation system water conservation.

Anaerobic digesters enable the conversion of organic materials such as manure and other agricultural wastes into biogas. Biogas, largely composed of methane, can be used as a fuel source comparable to natural gas. For example, it can be used to power an electric generator and thus to produce renewable electricity – all while making efficient use of manure and agricultural wastes that could otherwise harm water quality.

Two anaerobic digesters at Stonyvale Farm in Exeter, Maine.

Under the program, farmers will be able to borrow up to $450,000 at a fixed interest rate of 2 percent for up to 20 years to develop qualifying projects. The opportunity represents a partnership between the Maine Departments of Environmental Protection and Agriculture, Conservation and Forestry, the Finance Authority of Maine and the Maine Municipal Bond Bank. The initial seed money comes from the DEP-administered Clean Water State Revolving Fund. Since 1989, that fund has provided over $650 million in low-interest loans for water quality projects, primarily hosted by publicly owned wastewater treatment facilities.  For the newly-announced program, the fund will transfer up to $3 million to FAME, which will finance the loans.

For more information on the opportunity, contact either participating department, or consult a professional experienced with anaerobic digestion and state-funded incentive programs. The Preti Flaherty team advises clients on both the development of anaerobic digestion facilities and participation in government-backed loan programs. For more information, please contact Todd Griset at 207-623-5300.

Wyoming-Colorado water pipeline, hydropower

Federal regulators have upheld their rejection of a proposal to pipe water over 500 miles from southwestern Wyoming’s Green River and Flaming Gorge Reservoir to Colorado. The project, known formally as the Regional Watershed Supply Project but more commonly called the Flaming Gorge Pipeline, has been sent back to the drawing board.  The recent permit denial appears to rest largely on the vague and incomplete nature of the application, but it also points to possible gaps in how the federal government regulates water use and hydropower.

Water - a scarce but valuable resource in the American west.

 
The Regional Watershed Supply Project was originally proposed by private developer Million Conservation Resource Group to make new water supply available for use by municipalities, agriculture, and industries in southeastern Wyoming and the Front Range of Colorado. In 2008, the developer applied to the U.S. Army Corps of Engineers for a permit under Section 404 of the Clean Water Act. Under its Section 404 authority, the Army Corps regulates activities involving the discharge of dredged or fill material into waters of the U.S.

In July 2011, based on the record in the case, the Army Corps withdrew the pipeline application, saying in a public notice that the “primary purpose of the project may now change to electrical power generation”, an activity appropriately under the purview of the Federal Energy Regulatory Commission.

Wyco Power and Water Inc., the successor in interest to Million Conservation Resource Group, then applied to the Federal Energy Regulatory Commission for a preliminary permit for its project. By this time, the project concept included seven hydropower projects along the pipeline, including two pumped storage projects and five turbines within the pipeline. In response to the public notice of the permit application, over 200 comments expressly opposing the proposed project were submitted by the Governor of Wyoming, state agencies, counties, municipalities, water conservation districts, utilities, environmental or resource advocacy groups, and individuals.

In February, FERC dismissed Wyco’s request for a preliminary permit (3-page PDF) as premature, noting that the pipeline did not yet exist, nor did the applicant have authorizations for any specific route, nor had a route been substantially identified. FERC also noted that its only role associated with the proposed water supply pipeline would be to authorize the construction and operation of any proposed hydropower projects along the pipeline, not to authorize the siting of the pipeline itself.

Although Wyco asked FERC for a rehearing of its dismissal, yesterday the Commission upheld its earlier decision. In FERC’s order denying request for rehearing and clarification (9-page PDF), FERC reiterated that while it “regularly licenses discrete hydropower developments within substantial water conveyance systems, it has long been the Commission’s practice not to license the entire water conveyance system itself.”

So where does that leave Wyco? With both the Army Corps and FERC finding that the permits sought are premature, a logical next step would be to pin down a specific route and to seek authorizations from the federal, state, and private landowners whose property would be crossed. The developer has suggested that financing the project will be difficult without first obtaining some governmental approvals, and it may be hard to reach deals with landowners without having sufficient financial commitments. Nevertheless, FERC’s decision instructs Wyco that it may come back with a preliminary permit for the hydropower components of its pipeline project once the pipeline is more well-defined.

NPS promotes greener national parks

A new plan by the U.S. National Park Service seeks to improve the sustainability and energy efficiency of its holdings.  The NPS Green Parks Plan (16-page PDF)  outlines the service's plan to reduce its impact on the environment, mitigate the effects of climate change, and integrate sustainable practices throughout its operations.

Solar panels line a bathroom roof at Devil's Garden campground, Arches National Park, Utah.

While the park service is famed for the wild and scenic landscapes it protects - totaling over 84,000,000 acres - the NPS also manages the largest number of structures of any civilian agency in the federal government.  All told, the NPS portfolio of 397 national parks includes more than 67,000 structures with more than 50 million square feet of constructed space and more than 3,000 utility systems.  Each year, 2.6 billion gallons of water are consumed in national parks, and the service's annual energy costs average $44 million.

The Green Parks Plan identifies nine strategic goals:

• Continuously Improve Environmental Performance: meeting and exceeding the requirements of all applicable environmental laws
• Be Climate Friendly and Climate Ready: reducing greenhouse gas emissions and adapting facilities identified as at risk from climate change
• Be Energy Smart: improving facility energy performance and increasing reliance on renewable energy
• Be Water Wise: improving facility water use efficiency
• Green Our Rides: transforming the NPS fleet of vehicles and adopting greener transportation methods
• Buy Green and Reduce, Reuse, and Recycle: purchasing environmentally friendly products and increasing waste diversion and recycling
• Preserve Outdoor Values:minimizing the impact of facility operations on the external environment
• Adopt Best Practices:adopting sustainable best practices in all facility operations
• Foster Sustainability Beyond Our Boundaries:engaging visitors about sustainability and inviting their participation

The park service is looking forward to its centennial in 2016; in last year's NPS Call to Action, the service committed to reducing its carbon footprint before that date.  The park service views the Green Parks Plan as the roadmap for implementing that commitment.  While the fully-articulated Green Parks Plan is new, many parks have already adopted sustainability initiatives.  For example, campground facilities in Arches National Park use solar photovoltaic panels to power water pumps and light buildings.

What does the Green Parks Plan mean?  For the park service, it may lead to improved sustainability and lower operating costs.  For greentech businesses, it may mean opportunities to install energy efficiency and renewable energy projects, or to sell greener vehicles.  For park visitors, it should mean cleaner air and water, and more opportunities to participate in sustainability.  Expect the park service to release periodic updates on its progress toward achieving the nine goals of the Green Parks Plan.

spring-fed small hydro in Idaho?

Small-scale hydroelectric projects are receiving renewed interest as society looks for cost-effective ways to produce electricity using local, renewable resources.  Depending on available sites and on what alterntative resources might be available, microhydro or small-scale hydroelectric projects can fit the bill.  Even if you own a first-class site for a microhydro project, before you can build or operate your project, you need to understand what federal and state regulations may apply.  Some small hydro projects are treated much like full-scale dam-based hydropower projects, while others (like small projects using existing conduits, pipes or canals) can get an easier regulatory path to approval.

A small hydro project proposed near Grace, Idaho illustrates some of these regulatory considerations, and the importance of understanding how regulators apply the rules.  Grace is a town of about 1,000 people located in Idaho's Gem Valley.  The Bear River runs through the valley on its course flowing out of Bear Lake, around the Bear River Range by Soda Springs, and then south through Grace into Utah's Cache Valley.  In the early twentieth century, recognizing the area's water resources and topographic variation, a series of dams, diversion pipes and powerhouses were built along the Bear River to produce hydroelectricity.  One side effect was that a stretch of river known as Black Canyon was largely dewatered, as an aqueduct carried the water around the canyon to a downstream powerhouse.  Ultimately, Utah Power and Light (and then PacifiCorp) came to operate these assets, and chose to remove one of the dams, an aqueduct and one powerhouse in 2006 and 2007, and to provide some increased flows through the Black Canyon section.

There may be ways to generate hydroelectricity in Grace without diverting water away from the Bear River. Last month, a local farmer with interests in canals and hydro development proposed a new hydro project near Grace.  The Gilbert Hydropower Project proposed to capture the flows of several natural springs and pipe this water about 700 feet to a turbine/generator unit.  Currently, the water is partially used for pasture irrigation with the unused portion flowing into the Bear River; the developer proposes to install a 24‐inch diameter above-ground pipeline to send the water to a Pelton turbine attached to a 75 kW generator.

In its application to the Federal Energy Regulatory Commission (docketed by FERC as Project No. 14367-000), the project developer requested an exemption from the licensing requirements of the Federal Power Act under the so-called "5 megawatt exemption" rule.  That rule allows the Commission to exempt small hydroelectric projects with an installed capacity of 5 megawatts or less that: (1) are located at the site of any dam in existence on or before July 22, 2005, and that use the water power potential of such dam for the generation of electricity; or (2) use a “natural water feature” to generate electricity, without the need for any dam or impoundment.

FERC dismissed the Gilbert project's request for an exemption, noting, "Because [the] project would utilize the flows of a natural spring that travel through 700 feet of pipe to reach the proposed turbine/generator unit, it would neither be at the site of an existing dam nor use the flows from a natural water feature", and thus was ineligible for an exemption.  However, FERC did invite the Gilbert developers to convert their exemption application to a license application, which the developers did earlier this month.  The developers now have until June 18, 2012, to submit the additional information needed for a complete license application.

What's in the future for Grace, Idaho?  What role could using nontraditional water resources such as springs play there or elsewhere in our energy future?

Cooling data centers with recycled water

Data centers are cropping up around the country, providing centralized computer server and storage capacity for both internet superstars like Google and Facebook as well as a much longer list of brick-and-mortar businesses.  Data centers can consume significant amounts of electricity, so data center owners work hard to manage their energy costs and improve their energy efficiency.

Much of a data center's energy budget goes to keeping the servers and the building's airspace cool.  Traditionally, this might include mechanical chillers -- effectively, powerful air conditioning units.  To manage energy costs and environmental footprints, some data centers are turning to more passive cooling resources.  Google recently announced that it is using recycled gray water from a local public water treatment facility to cool its data center in Douglas County, Georgia. 

The Douglasville-Douglas County Water and Sewer Authority collects wastewater from local communities, treats it, and releases it into the Chattahoochee River.  Google worked with the water and sewer authority to divert up to 30% of the water that would otherwise flow into the river to a special side-stream treatment plant.  Once cleaned, this water is piped about 5 miles to Google's data center, where it is used for cooling.

Google's data center relies primarily on evaporative cooling.  It takes energy to evaporate liquid water; as a consequence, you can use evaporating water to remove heat from air or other materials.  (Think of the cooling effect of a dry breeze on wet skin.)  Much of the water evaporates through this cooling process; Google sends any remaining cooling water to an on-site effluent treatment plant, from which the water is returned to the Chattahoochee River.

Using recycled water to cool data centers can save energy compared to mechanical chillers.  Where clean water is scarce or expensive, the ability to use recycled water for cooling could also open up new capacity for data centers.  Will more data centers turn to recycled gray water for evaporative cooling and energy cost management?

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.