Deadline for offshore wind grants

Friday, March 30, 2012

Today marks the deadline for applicants to submit letters of intent to the U.S. Department of Energy seeking funding for offshore wind energy development.  On March 1, 2012, Secretary of Energy Steven Chu announced a six-year $180 million initiative to deploy offshore wind projects in U.S. waters.  Subject to congressional appropriations, this program includes $20 million available this year to support up to four innovative offshore wind energy installations across the United States.

The U.S. Department of Energy believes that the U.S. is rich in offshore wind resources.  Some reports have identified over 4,000 gigawatts of potential capacity, which adds up to several percent of the U.S.'s existing electric generation capacity across all fuels and resources.

To speed the development of this resource, DOE has proposed a competitive solicitation for grant funding for "Advanced Technology Demonstration Projects".  The goal is to install innovative offshore wind systems in U.S. waters in the most rapid and responsible manner possible, and expedite the development and deployment of innovative offshore wind energy systems with a credible potential for lowering the levelized cost of energy (LCOE) below 10 ¢/kWh or the local "hurdle" price at which offshore wind can compete with other regional generation sources without subsidies.

Applications must include certain materials as specified in the Funding Opportunity Announcement (docketed as DE-FOA-0000410).  The Department has stated that it expects applications to come from world-class multi-sector consortia, including energy project developers, equipment suppliers, research institutions and marine installation specialists.  Grant funds may be used to cover up to 80 percent of a project’s design costs and 50 percent of the hardware and installation costs. Letters of intent are due on March 30 and applications are due on May 31, 2012.

Net metering and utility charges

Thursday, March 29, 2012

As more electricity customers are installing solar panels and other distributed generation, many are participating in net metering programs under which they can run their utility meter backwards -- but utilities are complaining that net metering customers don't pay their share of the grid's operating costs.

In states and utility territories where net metering is allowed, customers can use eligible distributed generation (typically renewable generation like solar photovoltaic or small-scale wind, or micro combined heat and power) to offset their consumption of electricity from the grid.  Even if the customer draws power from the grid at some times and injects power back onto the grid at other times, net metering or net energy billing allows the customer to offset distributed generation against purchases. 

While many states embrace net metering as a policy, some utilities complain that net metering customers can be free riders.  If a customer's solar panels produce as much power in a month as the customer consumed, net metering could credit that customer with a zero utility bill - even though at various times times, the customer relied on the grid for imports and exports.  As a result, some utilities are seeking to impose new charges on customers for net metering.  For example, last fall Virginia regulators approved part of utility Dominion's request to impose "standby" charges on certain net metering customers.  Solar advocates and other distributed generation interests typically oppose such charges as roadblocks to achieving the societal benefits of net metering.

The issue continues to simmer around the country.  California utility San Diego Gas & Electric Co. recently proposed adding a "network use charge" onto customers' bills.  SDG&E's concept was that the charge -- about $22 per month for the average net metering customer with a solar PV system -- would properly allocate the cost of maintaining the grid to these customers.  The utility argued that without the charge, net energy metering customers were being subsidized by all other customers.  Earlier this year, California regulators rejected the idea (see the 16-page order at the California Public Utilities Commission website), noting concerns that the proposed charge "may be inconsistent with current law, regardless of whether it is justified by cost causation principles or an analysis of the crosssubsidies inherent in current policies."  As a result, SDG&E refiled its rate application without the charge.

Incremental hydropower tax incentives

Wednesday, March 28, 2012

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.

Proposed Long Canyon energy project

Tuesday, March 27, 2012

Last week the Federal Energy Regulatory Commission accepted for filing an application for a preliminary permit for a pumped storage project in the Utah desert.  In January, Utah Independent Power, Inc. filed for a preliminary permit.  The Long Canyon Pumped Storage Project would entail two dams to store water drawn from the Colorado River near Moab, Utah.  (Here's a topographic map of the general location.)

A water pipe buried in the desert soil in Arches National Park, near Moab, Utah.

Pumped storage projects are one way to store energy.  Electricity that is generated can be converted into potential energy stored in water by pumping it uphill.  That energy, or most of it, can be captured and converted back into electricity on command.

Utah Independent Power's application to FERC for a preliminary permit for the Long Canyon Pumped Storage Project (18-page PDF) provides some details on how the project might work.  Initially, water from the river would be pumped into the lower reservoir.  When electricity is abundant and low-priced, the project would consume electricity to pump water from the lower reservoir uphill to the upper reservoir.  When electricity is scarce or commands a high enough price, the project would release water downhill through turbines to produce up to 800 megawatts of hydroelectric energy.  In a typical pumped storage project, the same pumps used to send water uphill can be used as turbines when the water flows back down.  The owned of a pumped storage project seeks to earn profits by taking advantage of the difference between off-peak energy prices and the prices available during peak demand.

Now that the Commission has accepted the application for filing, the application is open for 60 days for public comment or a showing of interest in the site by a competing developer.  After that period, and after a technical and legal review of the application by Commission staff, the Commission may issue a preliminary permit to the applicant.  A preliminary permit does not authorize the permittee to actually construct anything; rather, it confers first priority of application for a license - what the Commission calls "guaranteed first-to-file status" - while the permittee studies the site and prepares to apply for a license, typically for a term of 3 years.

Grid readies for energy storage

Monday, March 26, 2012

New energy storage technologies have the potential to transform the electric grid.  Energy storage generally refers to a variety of approaches to storing energy in a form that can be converted back into usable electricity when needed.  Some of these technologies, such as pumped storage allow power to be produced and stored at a low cost, then released during times of higher price or demand.  Others, such as flywheels or batteries, are able to help balance and regulate supply and demand on the grid by providing a service known as frequency regulation.

Last fall, federal regulators issued an order requiring most US electric grid operators to change the way they compensate frequency regulation.  Historically, the way resources were paid for frequency regulation favored traditional generators able to ramp their production up and down to match demand in real time, even when alternative resources like energy storage could provide frequency regulation more efficiently and at a lower cost.  In Order No. 755, the Federal Energy Regulatory Commission held that the current frequency regulation compensation practices "result in rates that are unjust, unreasonable, and unduly discriminatory or preferential."

To remedy this flaw, the FERC required grid operators to change the way they pay for frequency regulation.  FERC required grid operators to propose new market rules by April 30, 2012, to take effect in late October 2012.

At least one regional grid operator thought it needed more time.  In November 2011, ISO New England Inc., the regional transmission organization for the six New England states, asked the Commission for nearly four months' additional time to develop and submit the revised tariff provisions.  Other stakeholders viewed as beneficiaries of Order 755 opposed the requested delay, including an electricity storage trade association and flywheel developer Beacon Power. However, the Commission denied the grid operator's request.

Grid operators of the nation's organized electric markets have now started to file their proposals on how to compensate energy storage and other frequency regulation resources.  PJM's proposal has been submitted to FERC, and other regions will follow shortly.  Given the Commission's ruling in Order No. 755, the energy storage market may grow significantly, as players figure out how to earn revenues by providing cost-effective frequency regulation.

What California's dry winter means

Friday, March 23, 2012

California relies heavily on winter snow accumulations to provide water for irrigation, hydropower, and domestic use.  As the mountain snowpack melts over the spring and summer, the water flows down to the inhabited foothills and lowlands, often stopping at one or more reservoirs along the way.  Managing water resources requires watching the water content of the snowpack, and this year's snowpack is below average.

According to the California Department of Water Resources, as of the end of February, snowpack water content is only 30 percent of historic readings for the date.  To explain this winter's unusually dry conditions, the Department points primarily to the weather.  Specifically, a persistent high pressure ridge along California's coast is credited with diverting most storms to the north.  Indeed, the state of Washington reports average and above-average snowpacks throughout most of the state.

25 million residents and 750,000 acres of irrigated farmland depend on the California snowpack for their water supply.  California's rivers are also home to 343 hydroelectric facilities, with a net installed capacity of 13,057 megawatts.  The State Water Project manages much of these flows, with a complex set of conduits, reservoirs, and storage basins.  However, the project cannot deliver as much water as consumers demand.  The project had previously projected that it could deliver about 60% of the requested water, but this projection has been slashed to 50% as a result of the dry winter.  Additionally, reservoirs are still holding water from last year, and are expected to be able to deliver water all summer, but continued dry winters will eventually eat into California's water storage.

What will California's dry winter mean for the future?

Will NJ stay in RGGI?

Wednesday, March 21, 2012

The New Jersey Senate has passed a bill which would require the state to remain a member of the Regional Greenhouse Gas Initiative, the carbon cap-and-trade compact covering the Northeast and mid-Atlantic states. The bill, S. 1322, is described as clarifying the legislature's intent regarding NJ’s required participation in RGGI.

RGGI is the first major market-based greenhouse gas regulatory program in the United States.  RGGI represents a cooperative effort by Connecticut, Delaware, Maine, Maryland, Massachusetts, New Hampshire, New Jersey, New York, Rhode Island and Vermont.  These ten states agreed to cap and reduce their electrical energy sector's greenhouse gas emissions by 10% by 2018.  Each state was free to develop its own implementation of the compact, including both how carbon allowances would be allocated and how proceeds from their sale would be used.  For example, Maine chose to invest its share of RGGI auction proceeds in energy efficiency, managed by the Efficiency Maine Trust.  A February 2012 report found that, for every dollar of RGGI auction revenues that was invested in energy efficiency in 2010, participating states received $1.3 to $6.8 in total energy benefits, with a weighted average of $2.3 in return on investment.

Last year, NJ Governor Chris Christie vowed to remove New Jersey from RGGI, arguing that RGGI participation represents a tax without producing any measurable impact on the environment.  Democrats in the state legislature introduced legislation (A4108/S2946) to require NJ to remain in RGGI, but in August 2011 Gov. Christie vetoed that bill.

S. 1322 now faces debate before the New Jersey Assembly.  If it passes out of the Assembly, it will then face an anticipated veto from the governor.  Will New Jersey remain in RGGI?

Some Maine electricity prices fall

Tuesday, March 20, 2012

According to the Maine Public Utilities Commission, the price of electricity is falling for some customers. The Maine PUC recently set prices for standard offer electricity service for large commercial and industrial customers for next month. These prices - 3.2 cents/kWh for Central Maine Power customers and 3.1 cents/kWh for Bangor Hydro-Electric customers - are 10% lower than prices in March and 25% to 35% lower than prices one year ago.  Observers point to even lower wholesale power prices, driven largely by the availability of inexpensive natural gas.

In the late 1990s, Maine restructured its electricity market into two components: supply and delivery. Previously, Maine utilities operated both facilities for generating electricity (generation) and for delivering it to consumers (transmission and distribution). Today, thanks to the deregulation of generation and restructuring of the market, these functions are separate. In today's Maine marketplace, energy supply refers to buying the electricity itself from a competitive wholesale market, while delivery is the service provided by transmission and distribution utilities in delivering the energy to consumers.

Maine consumers are free to select a competitive electricity provider for their energy supply. As an alternative, customers can choose not to choose, instead automatically participating in a utility-wide pool of "default service" or "standard offer" electricity purchases. 

Maine recently revised the structure of standard offer service for large commercial and industrial customers.  Standard offer customers in these classes now pay a 2-part price for their energy supply: an energy charge indexed to wholesale power market prices, plus a capacity charge based on each customer’s peak usage.  On top of these standard offer charges, customers also pay their local utility to deliver the power.

Many larger consumers have found that they are able to procure electricity at a lower cost than the standard offer, either through a competitive supplier or by participating in the wholesale market directly. For others, the standard offer provides some certainty and medium-term price stability for energy purchases, although standard offer prices change monthly and can be more volatile than some competitive alternatives.

Cooling data centers with recycled water

Monday, March 19, 2012

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?

Maine energy efficiency bill faces hearings

Wednesday, March 14, 2012

Today a Maine legislative committee holds a public hearing on one of Governor LePage's energy bills for the 2012 session.  The Joint Standing Committee on Energy, Utilities and Technology will hear public testimony on LD 1864, "An Act To Improve Efficiency Maine Trust Programs To Reduce Heating Costs and Provide Energy Efficient Heating Options for Maine's Consumers".

This bill would modify the governance of the Efficiency Maine Trust, giving the Governor authority to choose which board member serves as chair.  It would remove the word "independent" from a description of the Trust's board, and would state that the Trust is "a body corporate and politic and a public instrumentality of the State.

It would also allow Maine's electric transmission and distribution utilities the opportunity to offer loans to their customers to support the installation of alternative heating systems.  The Trust could determine what systems might be eligible, but at least one utility has suggested electric-based systems like mini-split heat pumps, and several utilities have expressed interest in electric thermal storage.  Under LD 1864's vision, utilities could earn a guaranteed rate of return on their loans based on their weighted average cost of capital, likely at least 10%.  Utilities would be free to charge customers a lower financing rate if they choose, with the difference between financing payments received from customers and that guaranteed rate of return being funded by Efficiency Maine Trust.

Today's public hearing is scheduled to begin at 1:30 p.m.

LePage's 2012 Maine energy bills

Monday, March 12, 2012

Maine Governor Paul LePage has released his legislative proposals to address energy issues in Maine.  Among these bills is LD 1863, An Act To Lower the Price of Electricity for Maine Consumers. This bill would modify Maine's renewable portfolio standard, the law requiring electricity sold at retail in Maine to be sourced from an energy mix that includes renewable resources.  Specifically, it would eliminate an existing limitation that projects must be under 100 megawatts in size to qualify as renewable under Maine law.  (By comparison, Maine's largest dam is rated at 88.01 megawatts.  To give a sense of scale, one megawatt roughly powers 1000 households.)

LD 1863 would also modify Maine's long-term electricity contracting law, which allows the Public Utilities Commission to order Maine's investor-owned transmission and distribution utilities to enter into long-term contracts with certain renewable resources.  The legislature modified the long-term contracting law last session, and no contracts have been approved in the ensuing year; LD 1863 would make further changes, including making it "a primary consideration" whether any such contracts will lower the price of electricity to ratepayers over the life of the contract.

Governor LePage has also proposed other energy-related legislation, including LD 1864, An Act To Improve Efficiency Maine Trust Programs To Reduce Heating Costs and Provide Energy Efficient Heating Options for Maine's Consumers.  Efficiency Maine Trust manages Maine's energy efficiency programs.  LD 1864 would amend the Efficiency Maine Trust Act to change the governance and budget structures.  It would also shift the trust's programs away from its recent focus on reducing electric consumption, to encompass alternative heating sources - which could include heat pumps powered by electricity.

To Maine's electric transmission and distribution utilities, LD 1864 offers an opportunity to provide loans to customers for installation of qualifying heating systems.  Each utility could establish its own financing charges these for loans, and would earn a return on the loans based on its weighted average cost of capital - a figure that could be in excess of 10% - with any difference between the utility's weighted average cost of capital and any financing payments received from customers to be funded out of the electric system benefit charge managed by Efficiency Maine Trust.

The Joint Standing Committee on Energy, Utilities and Technology is expected to hold public hearings on these bills later this week.

Decision on Klamath dam removal delayed

Thursday, March 8, 2012

A contentious decision on whether four dams should be removed from the Klamath River Basin in California and Oregon may be delayed indefinitely pending Congressional guidance on how to balance the nation's policies governing hydroelectricity, fisheries, and dam removals.

Utility PacifiCorp owns four dams on the Klamath River and its tributaries whose license expired in 2006 and which are now targeted for removal.  After a lengthy and still-incomplete relicensing process and challenges by environmentalists, in 2010 PacifiCorp agreed to settle the dispute by seeking to remove the dams.  This settlement was documented in two key contracts, the Klamath Hydroelectric Settlement Agreement and the Klamath Basin Restoration Agreement.

These documents set March 31, 2012 as the deadline by which the Secretary of Interior must issue a so-called "Secretarial Determination" as to whether to go ahead with dam removal.  Unless the Secretarial Determination calls for the removal of the dams, it would be expected to require PacifiCorp to continue its application for a new hydropower license for the dams.

However, in the Klamath Basin case, the Secretary cannot issue a Secretarial Determination calling for dam removal unless Congress first passes legislation authorizing the determination.  Congress does not appear likely to take action on the issue in the near term, prompting Secretary of the Interior Ken Salazar to issue a press release last month announcing his decision to defer issuance of a secretarial determination.  In that release, Secretary Salazar stated, "Because Congress has not enacted legislation necessary to authorize a Secretarial Determination under the terms of the KHSA, there will not be a decision by March 31, 2012 on potential removal of the dams."

Now that a Secretarial Determination is no longer expected by March 31, stakeholders expect the final studies and environmental analysis will be released this spring.  Will Congress ultimately act on the Klamath River dam removal proposals?

Royal River dam history

Tuesday, March 6, 2012

The town of Yarmouth, Maine is considering what to do with two dams on the Royal River.  The town owns the dams near Bridge Street and East Elm Street; these dams, or their predecessors, were built as early as the mid-1700s to provide mechanical hydropower to the industrial mills that played a large part in the local and regional economy.  Since 1674, settlers used the Royal River's waters to power mills; as early as 1759, a dam at East Elm Street was used to impound water to power an iron mill.  The debate over whether to repair or remove the dams is grounded in the history of human use of the Royal River's hydropower resources.

One of the best historical texts on Maine's hydropower potential and resources is The Water-Power of Maine, a compilation of reports by the commissioners of the Hydrographic Survey of 1867 and its secretary, Walter Wells.  The report broadly identifies 1,955 "water-powers" based on a survey asking municipalities about the resources within their boundaries.

For Yarmouth, the report provides the following description along with a note that the information was "digested from Selectment's Returns":
They are called, - one, "Gooch's"; four, "Baker's"; one, the "Factory Fall".  All are situated on Royal's River; combined height, sixty-six feet in one mile.
Power estimated sufficient to grind seventy-five bushels of grain per hour each. Power is not all improved; mills work all the year; machinery not the best.
Stream connected with three small ponds. Range from lowest to highest water, eight feet. Effect of the improvement of the power upon the wealth of the town, excellent.
This snapshot gives us a good look at the water-power of Yarmouth in 1867. (Compare the elegant sign prepared by the Yarmouth Village Improvement Society in 2011, showing a map and images from industrial activities at four of the natural water-power sites in Yarmouth.) A twenty-first century visitor to Yarmouth might be surprised at the industrial history of the waterway, including a large pulp mill owned by the Forest Paper Company, textile mills, and other manufacturing concerns that employed the people of Yarmouth over the years.

140 years later, the Royal River's waters do not grind much grain, but at least two of the dams remain in the river. In 1984, the Sparhawk Mill near to the Bridge Street dam installed hydroelectric generation, although it is reportedly worse for the wear and produces little to no useful power. (Perhaps "machinery not the best" could have been said about the present-day site as well as it was in 1867.)

Dam removal advocates have labeled the dams "relics of an industrial age". Environmental advocates suggest that Yarmouth remove the dams, given the cost of maintaining them, their impacts to fish in the river, and the fact that they are not fully being used to produce renewable power.  Yet Yarmouth has a strong culture of interest in both sustainable energy (e.g. Yarmouth Energy Savers Committee) and historical preservation (e.g. Yarmouth Historical Society); the town's consultants found that the dams could generate some renewable electricity, and could be eligible for inclusion in national historic preservation districts.  Given the history and present risks and opportunities, will the people of Yarmouth choose to remove the Royal River dams?

"Small hydro" bill before Congress

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

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

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

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

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

Beacon Power sale approved by FERC

Monday, March 5, 2012

The Federal Energy Regulatory Commission has approved a transaction through which bankrupt flywheel energy storage firm Beacon Power will transfer its assets to new owners.

Beacon Power subsidiary Stephentown Regulation Services LLC built an energy storage system in Stephentown, New York.  The project bears a 20 MW nameplate capacity, and uses Beacon's patented flywheel technology to help the New York Independent System Operator balance the electric grid, providing regulation service under the grid operator's Limited Energy Storage Resource tariff.  Beacon was able to develop the program using a $43 million loan guarantee from the U.S. Department of Energy's loan program office in 2010, and benefits in theory from FERC Order No. 755, which required grid operators to pay more for fast-responding frequency regulation that Beacon Power's flywheels may be able to provide. Nevertheless, Beacon went bankrupt at the end of 2011.

Last month, private equity firm Rockland Power Partners proposed to buy the bankrupt company for $30.5 million: $5.5 million cash and a $25 million promissory note to the DOE.  Rockland says that it intends to continue operating the Stephentown plant and developing a second facility in Hazle Township, Pennsylvania.

As part of the deal, Stephentown Regulation Services LLC filed an application to FERC under section 203(a)(1) of the Federal Power Act requesting Commission authorization to transfer its flywheel facility and related interconnection facilities (the “Facility”) located in Stephentown, New York, together with Stephentown’s rights, title and interest in, to and under, various assets including its market-based rate authority, its books and records and other related jurisdictional agreements to Stephentown Spindle, LLC, a subsidiary of Rockland.

FERC granted Stephentown's request last week, authorizing the transfer of Beacon's jurisdictional assets. Although there are a few remaining steps for Beacon and Rockland to figure out, this regulatory approval largely paves the way forward for the New York flywheel energy storage project to change hands to its new owners.

Obama: renewable energy tax credit reforms

Thursday, March 1, 2012

President Obama's proposal to reform the way the U.S. taxes businesses includes making the soon-to-lapse production tax credit (PTC) for generating renewable electricity both permanent and refundable.  If enacted, this proposal would support the renewable energy industry, but could lead to a change the way projects are financed.

Earlier this month, the President and the Department of the Treasury issued a joint report entitled, "The President's Framework for Business Tax Reform" (25-page PDF).  The report presents a plan to reform America’s system of business taxation.  It labels the U.S. tax system "uncompetitive and inefficient", noting that the U.S. has a relatively narrow corporate tax base further reduced by loopholes, tax expenditures, and tax planning, and that the nation has a high statutory tax rate.

The cure proposed in the report is presented as supporting the "competitiveness of American businesses and increasing incentives to invest and hire in the United States by lowering rates, cutting tax expenditures, and reducing complexity, while being fiscally responsible."  It offers five key elements of business tax reform:
  • Eliminate dozens of tax loopholes and subsidies, broaden the base and cut the corporate tax rate to spur growth in America
  • Strengthen American manufacturing and innovation
  • Strengthen the international tax system, including establishing a new minimum tax on foreign earnings, to encourage domestic investment
  • Simplify and cut taxes for America’s small businesses
  • Restore fiscal responsibility and not add a dime to the deficit
Each of these elements is treated in some depth in the report.  In the section presenting the President's "Framework for Reform" for the second element, strengthening manufacturing, the report says that the Framework would "[e]xtend, consolidate, and enhance key tax incentives to encourage investment in clean energy":
The President’s Framework would make permanent the tax credit for the production of renewable electricity, in order to provide a strong, consistent incentive to encourage investments in renewable energy technologies like wind and solar. As with the R&E Tax Credit, the United States has to date provided only a temporary production tax credit for renewable electricity generation. This approach has created an uncertain investment climate, undermined the effectiveness of our tax expenditures, and hindered the development of a clean energy sector in the United States. In addition, the structure of renewable production and investment tax credits has required many firms to invest in inefficient tax planning through tax equity structures so that they can benefit even when they do not have tax liability in a given year because of a lack of taxable income. The President’s Framework would address this issue by making the permanent production tax credit refundable. 
Several features of this proposal are worth noting.  First, the production tax credit would become permanent.  To date, the PTC has been enacted, expired, and re-enacted multiple times, although occasionally with breaks in between periods of eligibility.  The PTC soon faces expiration yet again.  Renewable energy developers say that the uncertainty over its future significantly chills interest and development in the renewable sector.  President Obama's plan to make the tax credit permanent would be a positive improvement from their perspective because it represents a longer-term commitment to stable tax treatment.  From the national perspective, this longer-term commitment may spur investment and jobs, although it faces challenge from those who do not believe permanent tax credits should be ever used to support renewable energy, let alone permanently.

Second, the PTC would be refundable.  This roughly means that if you qualify for the credit, you don't need any taxable income to be able to use the credit as an offset against tax liability; when a tax credit is refundable, you can often receive its value in the form of a check from the Treasury.  The non-refundable nature of the PTC and the related investment tax credit (ITC) at present has led to business structures that allow multiple entities to invest in a project while allocating specific tax benefits to those investors capable of using them.  According to the report, the result of the widespread use of these tax equity structures has been investment in inefficient tax planning.  President Obama's plan would eliminate one of the key reasons behind the tax equity structure commonly used today, and could change the scope of developers interested in proposing renewable energy projects.  For example, a developer with low or no U.S. tax liability would be able to reap the tax incentive without partnering with income-rich tax equity investors.  Tax equity structures may still have value even if this proposal passed, but it could lead to a change in the way renewable energy projects are financed.

The President's tax reform plan has yet to be fully reviewed by Congress, and many observers believe it nearly impossible that it would pass as currently conceived.  The renewable energy tax incentives at issue here may or may not be part of a final enacted tax reform plan.  For now, in an election year, this proposal has strengthened the President's alliance with the renewable energy industry, as he has cast himself as their best hope for extended and improved tax credits if reelected.