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?

Hydropower Regulatory Efficiency Act of 2012

Last week the U.S. House of Representatives unanimously passed H.R. 5892, the Hydropower Regulatory Efficiency Act of 2012. The bill, introduced by Rep. Cathy McMorris Rodgers of Washington, is designed to implement a variety of measures promoting the production of electricity from small and conduit hydropower projects.

The bill opens with a series of Congressional findings regarding hydropower in the U.S.:

Congress finds that--

(1) the hydropower industry currently employs approximately 300,000 workers across the United States;

(2) hydropower is the largest source of clean, renewable electricity in the United States;

(3) as of the date of enactment of this Act, hydropower resources, including pumped storage facilities, provide--
(A) nearly 7 percent of the electricity generated in the United States; and
(B) approximately 100,000 megawatts of electric capacity in the United States;

(4) only 3 percent of the 80,000 dams in the United States generate electricity, so there is substantial potential for adding hydropower generation to nonpowered dams; and

(5) according to one study, by utilizing currently untapped resources, the United States could add approximately 60,000 megawatts of new hydropower capacity by 2025, which could create 700,000 new jobs over the next 13 years.

The bill goes on to implement a series of regulatory changes, including:

• Increasing the maximum size of hydro projects eligible for exemption from licensing from 5 MW to 10 MW 
• Promoting conduit hydropower – projects involving adding generation to existing pipes and canals
• Allowing FERC to extend a 3-year preliminary permit by up to 2 more years if the permittee worked diligently and in good faith
• Requiring FERC to investigate the development of a 2-year licensure process for developing hydropower at currently-unpowered dams and closed-loop pumped storage projects, and if feasible test the shortened process on one or more pilot projects
• Requiring the U.S. Department of Energy to study the potential of pumped storage to back up intermittent renewables and provide reliability, and to produce new hydropower from existing conduits

H.R. 5892 is now before the Senate for its consideration.

Electricity and natural gas market links

Concerns over the increasing interdependence of natural gas and electricity markets in the United States have prompted federal regulators to schedule a series of technical conferences on the subject for next month.

In recent years, natural gas has increased its share of the energy mix used to generate electricity.  Usage of coal, historically the dominant fuel used to generate electricity, is declining, while natural gas pricing is historically low.  This shift to increased reliance on natural gas is also driven in part by the growth of intermittent renewable energy resources like wind which may need natural gas to back them up when the wind isn't blowing.

At the same time, investigations into the blackouts and reliability problems like those affecting Texas and the Southwest in February of 2011 suggest that a lack of coordination between the electricity and gas industries may be partly responsible for the outages.

On February 3, 2012, Federal Energy Regulatory Commission Commissioner Philip Moeller issued a letter posing a series of questions concerning gas-electric interdependence.  His questions included what role the FERC should play in overseeing better coordination between the two industries, what regional differences might affect this coordination, and differences in how electricity and gas are traded in their respective markets.

In response to Commissioner Moeller's letter, a variety of stakeholders submitted comments.  Many commenters suggested that significant regional differences exist in both how markets operate and how their coordination could be improved.

As a result, the FERC has scheduled a series of regionally-oriented technical conferences for August:

• Central (generally the areas controlled by Midwest Independent Transmission System Operator Inc. (MISO), Southwest Power Pool, Inc. (SPP) and Electric Reliability Council of Texas (ERCOT)), to be held August 6, 2012, in St. Louis, MO
• Northeast (generally the area controlled by ISO New England, Inc.), to be held August 20, 2012, in Boston, MA
• Southeast (generally the areas controlled by Southern Company, Duke and Progress Energy, TVA, as well as other areas south of PJM Interconnection, L.L.C. (PJM) and East of SPP and ERCOT), to be held August 23, 2012, at FERC headquarters in Washington, DC
• West (generally the Western Interconnection), to be held August 28, 2012, in Portland, OR
• Mid-Atlantic (generally the areas controlled by New York Independent System Operator Inc. (NYISO), PJM and related areas), to be held August 30, 2012, at FERC headquarters in Washington, DC

FERC anticipates that each conference will be organized as a roundtable discussion regarding the sharing of information and communications, scheduling, market structures and rules, and reliability concerns.  The Commission has encouraged those interested in attending a conference to register by July 19, 2012.

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.

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?

Removing WA's Condit dam, recap

A major dam removal project is underway on the White Salmon River in the state of Washington.  Video footage of its breach (made available by National Geographic) shows something few living humans have seen but which is already recur in the near future: the removal of a major dam and associated dewatering of its impoundment.

In 1913, the Northwestern Electric Company built the Condit Hydroelectric Project to provide electricity to a nearby paper company and even to feed Portland, Oregon.  The dam was rated at 14.7 MW of nameplate capacity - a far cry from the Hoover Dam (2080 MW) or Grand Coulee Dam (6809 MW), but nevertheless a major dam in terms of its power production and significance.

In 1996, increasing pressure on dam owner PacifiCorp to install fish ladders and perform modifications for environmental compliance led PacifiCorp to seek the dam's decommissioning and removal.  In 2010, the Federal Energy Regulatory Commission approved the removal of the Condit Dam.  In late 2011, contractors breached the dam, draining the upstream impoundment.

If you haven't seen a dam breach before, or if you are simply impressed by the immense power of moving water, you may appreciate the National Geographic video footage of the Condit Dam's breach and the resulting rush of water and sediment.

Now that the Condit Dam has been removed, remediation and restoration efforts are under way.  You can track those efforts on the Washington State Department of Ecology's website, as well as on PacifiCorp's website.

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?

Incremental hydropower tax incentives

Upgrading existing hydroelectric facilities to improve their efficiency or capacity can be cost-effective.  Not only will the plant produce more electricity more efficiently, but the upgrades may qualify the facility for a tax incentive designed to spur the development of new renewable electricity generation.  For example, installing inflatable flashboards or high-efficiency turbine runners could qualify a project for an energy production tax credit of 1.1¢/kWh. 

As part of the sweeping Energy Policy Act of 2005, Congress amended section 45 of the Internal Revenue Code to expand the renewable electricity production tax credit (or PTC) to incremental production gains from efficiency improvements or capacity additions to existing hydroelectric facilities.  Eligible improvements must be placed in service after August 8, 2005, and before January 1, 2014. 

To qualify incremental hydroelectric generation for the tax credit, the project owner applies to the Federal Energy Regulatory Commission under section 1301(c).  The Commission is required to certify the “historic average annual hydropower production” and the “percentage of average annual hydropower production at the facility attributable to the efficiency improvements or additions of capacity” placed in service during that time period.  The applicant is then able to take the production tax credit for the incremental amount of electric energy produced as a result of the upgrades.

While a credit of 1.1¢/kWh may seem small, hydroelectric projects typically produce relatively large amounts of electric energy at a relatively low operating cost.  Depending on the energy market, at times the tax credit may be worth half as much as the value of the underlying energy.  Also, in this context, the tax credit is only available for the incremental generation produced above the historic baseline; thus allowing incremental hydropower production to qualify for the PTC arguably rewards investment in upgrades.

At the same time, the continued availability of the tax credit for any kind of renewable electricity is in doubt.  Under current law, most renewable resources must be placed in service by the end of 2013 to qualify for the production tax credit.  Wind energy projects must be placed in service by the end of 2012.  Congress is considering whether to renew the tax credit, as it has done a number of times since it was first enacted in 1992.   According to a Congressional Budget Office report released this month, tax credits for renewable energy sources cost the government $1.4 billion in fiscal year 2011.

Quick draw for hydrokinetic priority

Last year, I noted the "gold rush" aspect of hydrokinetic energy development in the US, as developers raced to the Federal Energy Regulatory Commission to file claims on promising sites.  Some of the most obvious areas for hydrokinetic development, such as the Mississippi River system, generated hundreds of applications for preliminary permits which would grant exclusive rights to study the site and prepare a first-priority license application within three years.

In some cases, multiple developers applied for a preliminary permit for the same site.  Whoever files a valid application first is given first priority; developers filing an application for the same site later face an uphill battle as competing applicants.

In the heat of the gold rush, sometimes multiple applications come in with identical filing times.  How does FERC resolve these disputes?  A quick draw?

A random drawing, as it turns out.  As long as the Commission believes that none of the applicants’ plans is better adapted than the others to develop, conserve, and utilize in the public interest the water resources of the region at issue, FERC uses a random drawing to resolve disputes over who gets to count as having been there first.

The Commission has used random drawings to assign priority to competing applications with identical filing times since at least 2009, when it granted first priority for a site to the city of Angoon, Alaska, defeating the cities of Petersburg and Wrangell.  Since then, it has issued notices announcing filing priority for preliminary permit application at least 33 more times, most recently resolving ten disputes by random drawing this past Wednesday.

The need for such a mechanism highlights the booming interest in many high-value sites for generating innovative hydroelectricity without building new dams.  The hydrokinetic quick draw may be a sign that the most promising sites have attracted competitive interest, even if the means of picking a temporary winner (typically a term of three years) is ultimately random.

EPA finalizes utility air emission regulations

New federal environmental regulations on utility air emissions have been finalized, but their impact on electricity costs and grid reliability remains to be seen.  The US Environmental Protection Agency has released its final rule for power plant air emissions.  (Here's EPA's Final Rule, a 1,117-page PDF.)  These rules, formally known as the Mercury and Air Toxics Standards or MATS, are also known as "utility MACT" because they require many utility generation units to use "maximum achievable control technology".  The rule gives utility electric generation plants three years to comply with tighter air pollution control requirements.

Even before the rule was finalized, it provoked controversy over how it could impact electricity prices and the reliability of the US electric grid.  According to the US Energy Information Administration, in 2010 coal was used to generate about 45% of the electricity consumed in the United States.  The nation's electric reliability organization, NERC, released a report suggesting the new rules would force the early retirement of a significant portion of the nation's coal-fired generating stations.  In NERC's analysis, if EPA's air rules force needed generators to shut down, the reliability of the electric grid could be at risk.

EPA and the Department of Energy disputed NERC's assumptions.  Ultimately, EPA issued its final rule on December 21, 2011.

President Obama expressed his support for EPA's new rule.  In a Presidential Memorandum, President Obama described how the new rules would improve air quality and public health.  President Obama also explicitly addressed the linkage between these rules and grid reliability:

These new standards will promote the transition to a cleaner and more efficient U.S. electric power system. This system as a whole is critical infrastructure that plays a key role in the functioning of all facets of the U.S. economy, and maintaining its stability and reliability is of critical importance. It is therefore crucial that implementation of the MATS Rule proceed in a cost-effective manner that ensures electric reliability.

Analyses conducted by the EPA and the Department of Energy (DOE) indicate that the MATS Rule is not anticipated to compromise electric generating resource adequacy in any region of the country. The Clean Air Act offers a number of implementation flexibilities, and the EPA has a long and successful history of using those flexibilities to ensure a smooth transition to cleaner technologies.

The President also directed a coordinated process to plan and execute measures needed to implement the rule while maintaining the reliability of the electric power system.  This process should be designed to "promote predictability and reduce uncertainty," and should include engagement and coordination with a broad array of stakeholders including the DOE, the Federal Energy Regulatory Commission, state utility regulators, regional transmission organizations, the North American Electric Reliability Corporation and regional electric reliability organizations, other grid planning authorities, and electric utilities.

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.