USDA announces renewable and energy efficiency funding

Friday, March 29, 2013

The United States Department of Agriculture has announced a new round of funding for assistance to agricultural producers and rural small businesses for energy efficiency and renewable energy projects.  USDA's Rural Energy for America Program (REAP) offers eligible farms and businesses incentives to improve their energy efficiency or produce energy from renewable sources.

USDA's mission includes revitalization of rural economies to create opportunities for growth and prosperity, support innovative technologies, identify new markets for agricultural producers, and make better use of natural resources. Authorized by the 2008 farm bill (formally the Food, Conservation, and Energy Act of 2008), the USDA REAP program's goals are to help agricultural producers and rural small businesses reduce energy costs and consumption and help meet the nation's critical energy needs.  Through the end of the 2012 fiscal year, REAP has funded over 6,800 renewable energy and energy efficiency projects, feasibility studies, energy audits, and renewable energy development assistance projects.

Today USDA announced that it will accept applications for three REAP program categories:
USDA plans to make funding available despite the current federal budget sequestration, which appears to have cut REAP funding by at least $2 million in fiscal year 2013. 

Application requirements for REAP assistance vary depending on the type of assistance sought.  Those interested in applying for assistance can contact their local USDA office for more information, or consult a professional with experience working with the REAP program.

Preti Flaherty helps our clients evaluate whether REAP assistance is a good match for their businesses; I have assisted my clients in securing REAP funding for their energy projects.  Please contact us at 207-791-3000 for more information.

Linking North American carbon markets

Wednesday, March 27, 2013

As nations, states, and provinces establish carbon markets, there is considerable interest in establishing links between these markets.  Two of North America's leading carbon markets - one overseen by the California Air Resources Board (CARB), the other by the Canadian province of Quebec - appear to be on track to link their cap-and-trade systems by January 1, 2014.

A 2006 California law known as AB 32, the Global Warming Solutions Act, established a greenhouse gas cap-and-trade program.  The program covers major sources of greenhouse gas emissions in the California, including refineries, power plants, industrial facilities, and transportation fuels.  CARB established regulations which set an enforceable greenhouse gas emissions cap.  This cap will decline over time.  The law requires covered entities to acquire allowances issued by CARB to cover their carbon emissions.  These allowances are tradeable permits allowing the holder to emit a given amount of carbon dioxide or its equivalent.

Quebec joined the Western Climate Initiative (WCI) in April 2008, a group of American states and Canadian provinces that have decided to adopt a common approach toward addressing climate change.  WCI's goals include the creation of a North American market for trading carbon emission rights.  Each WCI member government first creates its own greenhouse gas emissions cap-and-trade system, then links to others through intergovernmental recognition agreements.

California and Quebec's programs are now in the process of linking up.  According to a recently-issued CARB document, California and Quebec have been working together to ensure that both systems' operations are compatible and will work together and without disruption to California-covered entities.

According to the notice, linkage between California and Quebec will need to be effective as of January 1, 2014.  In the interim, California and Quebec will hold a practice joint auction to test their auction platform, allow market participants to gain familiarity with the future procedures for a linked market, and to allow the jurisdictions to evaluate their readiness for the newly expanded market. 

This linkage would not directly affect other North American carbon markets, such as the Regional Greenhouse Gas Initiative or RGGI market.  RGGI represents an agreement by nine northeastern states to create a pooled carbon market.  Other jurisdictions could join the RGGI market, and it is possible that the RGGI market could one day merge with the CARB and Quebec markets to form a broader North American carbon market.  The linkage of the California and Quebec programs may serve as a test of the effectiveness of linking the various North American carbon markets.

Report: northeastern demand drives natural gas pipeline growth

Monday, March 25, 2013

A federal energy agency has highlighted the demand for natural gas in the northeastern United States.  The U.S. Energy Information Administration's report shows that over half of U.S. natural gas pipeline projects installed in 2012 were in the Northeast region.  Low-cost gas produced from the Marcellus shale formation, combined with increased demand for gas in the Northeast, are driving pipeline expansion - but significant bottlenecks remain, keeping New England's natural gas prices higher and more volatile than those in the rest of the country.

Graphic courtesy of the U.S. Energy Information Administration, available at

For the past several years, natural gas pipeline capacity in the U.S. has grown.  According to EIA, overall investment in domestic natural gas pipeline capacity slowed in 2012, but the northeast United States was home to the majority of growth.  Other than facilities for gathering, storing, and distributing natural gas, natural gas pipeline capacity expansions totaled $1.8 billion in capital expenditures in 2012, adding 4.5 billion cubic feet per day of new pipeline capacity and 367 miles of pipe.

Most projects placed in service in 2012 focused on removing constraints that blocked natural gas from the booming Marcellus shale gas from reaching markets in the Northeast.  Northeastern pipe additions accounted for two-thirds of all new pipeline mileage placed service in 2012.  These additions included large projects such as the Appalachian Gateway Project and the Sunrise Project, both of which are designed to transport natural gas from the Marcellus production zone to markets in the Northeast.

Despite this growth, the New England and New York markets still experience frequent pipeline constraints, meaning that inbound pipeline capacity is insufficient to transport enough gas to meet consumer demand many days per year.  This results in not only volatile natural gas pricing in New England, but fundamentally higher prices for consumers.  Because the price of natural gas in New England sets the price of electricity most of the time, the result is a double-whammy of high wholesale prices for both electricity and natural gas.

Further pipeline capacity expansions into New England could alleviate these bottlenecks, but it is unclear who will build the capacity or when it will occur.  Until it does, New England will remain exposed to high and volatile prices for natural gas and electricity.

Maine considers renewable feed-in tariff

Wednesday, March 20, 2013

The Maine legislature is set to consider a bill that would create a feed-in tariff for renewable energy.  Maine already has a renewable portfolio standard and other incentives for investment in renewable power production.  Will Maine add a feed-in tariff to the mix?
The Maine State House, home to a consideration of feed-in tariffs.
 A feed-in tariff is a policy tool intended to encourage investment in renewable energy technologies.  Feed-in tariffs typically offer long-term contracts under which utilities purchase power fromrenewable energy producers at predictable prices, often based on the cost of generation of each technology.  Where feed-in tariffs exist, developers of renewable energy projects gain certainty about the revenues their projects will create.  This certainty helps developers secure the financing they need to build projects.

A bill proposed by Maine state senator Christopher Johnson would require the state Public Utilities Commission to establish a renewable energy resources feed-in tariff program.  An Act To Establish the Renewable Energy Feed-in Tariff, also known as LD 1085, has the stated purpose of encouraging the rapid and sustainable development of renewable energy resources and technology for environmentally healthy generation of electricity.  Like feed-in tariffs in other jurisdictions, it would require that utilities purchase renewably produced electricity from all qualified suppliers.  It would have the Public Utilities Commission set the rate that electric utilities must pay for such power at a level sufficient to provide revenues to operate and to attract necessary capital and investment for small renewable electric generators.

Qualified suppliers would be limited to certain small renewable electric generators.  As defined in the bill, such generators would be limited to systems up to 500 kilowatts in size, that are majority owned by a person or entity that owns less than 500 kilowatts of electricity generating capacity in Maine, and that use solar photovoltaic panels or solar thermal or concentrating solar systems, generators fueled by methane from sewage treatment facilities, landfills or agricultural waste, generators fueled by combustion of biomass, tidal power projects, or wind energy.

Existing Maine law provides incentives for the generation of electricity from renewable resources.  Like most states, Maine has a renewable portfolio standard which requires electricity suppliers to source a specified portion of their power from renewable generators.  Maine also has a community-based renewable energy pilot program which functions like a feed-in tariff for eligible projects.  A feed-in tariff would add another incentive to build relatively small (non-utility-scale) projects.

LD 1085 has not yet been scheduled for a public hearing.  It will likely come before the Joint Standing Committee on Energy, Utilities and Technology later this spring.

UAE opens first 100 MW solar project

Tuesday, March 19, 2013

The United Arab Emirates has recognized the start-up of its largest solar energy project to date.

The Shams 1 solar plant generates of electricity by concentrating solar thermal energy to vaporize a fluid into steam, which in turn spins a turbine.  Shams 1 can produce up to 100 megawatts of power, making the project the world's largest concentrating solar power projects.

Concentrating solar power, or CSP projects, use mirrors to heat a working fluid and ultimately to produce steam.  Shams 1 uses parabolic trough mirrors to focus the sun's energy on pipes full of a working fluid, while other concentrating solar projects focus mirrors on a central tower containing the working fluid.  That working fluid's heat is then exchanged into water, which vaporizes into superheated steam.  It is this steam that spins the turbine attached to an electric generator.  Concentrating solar thermal projects differ from those using photovoltaic technology, in which the sun's energy is converted into direct current electricity using specialized semiconductors.

Shams 1 was developed by Shams Power Company PJSC, a special purpose vehicle owned 60% by UAE-owned Masdar and 40% by the Total Abengoa Solar Emirates Investment Company, a vehicle in turn jointly owned by Total (50%) and Abengoa (50%).  These companies are said to have invested $600 million in building Shams 1.

With its commissioning, Shams 1 becomes the first utility-scale renewable power project in the UAE.  Other first and "biggests" include the largest financing transaction for a solar power project (US$600 million) the largest operating single pure concentrating solar plant in the world. 

UAE is blessed with energy resources.  For years, interest has focused on its oil and gas production.  Shams 1 is a small step toward resource diversification.  Will UAE continue to invest in alternative and renewable energy?

Maine may streamline tidal power permitting

Friday, March 15, 2013

The Maine legislature is considering a proposal to streamline the permitting process for some tidal energy projects. The bill, "An Act To Streamline the General Permit Process for Tidal Power", would relieve a perceived conflict between state and federal law over the permitting process.

Tidal energy has been harvested along the Maine coast for hundreds of years. While tide mills' heyday predated modern regulation of energy projects and their environmental impacts, anyone developing a modern tidal power project must navigate multiple layers of rules and requirements. The recent resurgence of interest in tidal energy has led to an often overlapping patchwork of regulations.

These rules can be hard to interpret, and occasionally lead to chicken-or-the-egg conundrums. For example, a 2009 Maine law created an expedited general permit process for certain small tidal power projects. Under that process, projects capable of generating up to 5 megawatts of power can qualify for an easier permitting path if their primary purpose is demonstrating or testing tidal technology. (By way of comparison, 5 megawatts is roughly equivalent to 6,705 horsepower - imagine what a tide miller could have done with that!)

Prior to filing a permit application with the Maine Department of Environmental Protection under the 2009 law, an applicant must first obtain a finding from the Federal Energy Regulatory Commission that the project will have no significant adverse impact on environmental quality. Unfortunately, before issuing that finding federal regulators want applicants to show that they are already seeking state approval. This regulatory conflict makes it hard for people who want to develop or redevelop a tidal resource to move forward.

To fix this problem, the DEP, Senator Mike Thibodeau of Waldo County, and Representative Joyce Maker of Calais proposed an amendment to Maine law. Their bill, known as LD 437, would enable the DEP to start processing an application without needing to wait for the federal environmental assessment. After a public hearing earlier this month, the legislature's Joint Standing Committee on Environment and Natural Resources voted to recommend that the bill ought to pass as amended.

Next steps for the tidal streamlining bill include consideration by the full Senate and House. Given the committee's vote, the bill seems likely to find further support in the two chambers. While its enactment may not launch a tide of new tidal power developments in Maine, relieving this piece of the regulatory tangle should help people test and demonstrate tidal power technologies old and new.

Mid-Atlantic electric grid operator plans $2.4 billion in upgrades due to fossil-fuel plant retirements

Tuesday, March 12, 2013

The operator of the mid-Atlantic electric grid has announced a need for $2.4 billion in grid upgrades to keep the lights on in the coming years, as fossil-fueled generators shut down.

PJM Interconnection LLC is the regional transmission organization that manages wholesale electricity markets and the transmission grid in all or parts of 13 states and the District of Columbia, covering about 60 million people.  In that role, PJM works with electric utilities and merchant generators to identify upgrades needed to maintain reliable electric service throughout its territory.  In 2012, PJM authorized more than 750 electric transmission improvement projects with a total cost of more than $5 billion.

PJM released its annual regional transmission expansion plan on March 7.  In that plan, PJM identified three major trends driving the need for further grid upgrades: upcoming power plant retirements, the rapid switch to natural gas, and the growth of wind power to meet states’ renewable energy requirements.

Of these, the large-scale retirement of fossil-fueled power plants may pose the greatest challenge.  Power plant operators must inform PJM if they plan to close their plants, and are doing so in droves.  PJM received 104 retirement requests between November 2011 and December 2012.  In all, these requests signal intents to shutter 13,868 megawatts of generation.  Retirement requests continue to roll in; in January 2013 alone, an additional 1,697 megawatts of generation filed notices of intents to retire.  This tide of closures is driven largely by relatively low electricity prices and increased costs for coal- and oil-fired generation due to environmental and emissions regulations. 

At the same time, 2012 brought a record amount of new generation to the PJM market, primarily fueled by natural gas. Meanwhile, the addition of new renewable resources to the grid - such as wind-powered generators - adds another layer of challenge, as these renewable projects are often located in relatively remote areas far from consumers in urban centers.

PJM must ensure enough power to keep its customers' lights on, a task that requires both having enough operating generators and the right amount of transmission to connect generators to customers.  As a result, PJM has identified 130 projects needed to maintain reliability.  These projects include new transmission lines, line rebuilds, equipment upgrades, and new and expanded substations, and substation additions.

Much of PJM's analysis is based on assumptions about which generation plants will close, which new generation plants will be built and come online, and how much consumer demand for electricity will grow.  Will PJM's predictions come true?  If so, consumers will bear the cost of PJM's identified grid fixes.

Senate climate bill proposes carbon fee

Monday, March 11, 2013

Senators Barbara Boxer of California and Bernie Sanders of Vermont have introduced climate legislation that would impose a fee of $20 per ton of carbon or methane equivalent emitted.  The Climate Protection Act of 2013 provides measures designed to "address climate disruptions, reduce carbon pollution, enhance the use of clean energy, and promote resilience in the infrastructure of the United States".  What does the Senate climate bill do -- and what are its chances of passage?

The centerpiece of the Climate Protection Act of 2013 is a fee imposed by the Administrator of the U.S. Environmental Protection Agency on carbon emissions.  Starting in 2014, the carbon pollution fee would be $20 per ton of carbon dioxide or equivalent.  For the next 10 years, the fee would increase by 5.6 percent per year, after which it would hold steady at about $34 per ton.

The fee would apply to any manufacturer, producer, or importer of a carbon polluting substance, defined as coal (including lignite and peat), petroleum and any petroleum product, or natural gas that releases greenhouse gas emissions when combusted or used.  The fee would apply whether the carbon polluting substance is produced in the U.S. or is imported.  As designed, it would be an "upstream" fee, meaning only the first producer or importer of the substance would have to pay the fee directly; subsequent users would not be liable for the fee, although they would likely pay a higher price to acquire the fuel as the the upstream entity passes its costs along.

60% of the funds raised from the carbon pollution fee would be used to provide a monthly residential environmental rebate to legal residents of the United States.  The remainder would be used to create a Pollution Reduction Trust Fund. The Trust Fund would be divided up for five purposes.  $7.5 billion per year would go to the EPA to mitigate the economic impacts of the carbon pollution fee on energy-intensive and trade-exposed industries.  $5 billion shall be available to the Department of Energy to carry out a Weatherization Assistance Program for Low-Income Persons.  $1 billion would go to the Secretary of Labor for job training, education, and transition assistance for individuals employed by the fossil fuel industry.  $2 billion will go to the Advanced Research Projects Agency-Energy program.  The balance shall be used shall be used for federal budget deficit reduction, as would the entire Trust Fund after 2024.

To protect domestic industry against competitive harms caused by the carbon pollution fee, the Climate Protection Act of 2013 also includes a carbon equivalency fee on imports of carbon pollution-intensive goods.  Those goods would include iron, steel, a steel mill product (including pipe and tube), aluminum, cement, glass (including flat, container, and specialty glass and fiberglass), pulp, paper, a chemical, or an industrial ceramic, as well as any other goods whose production is deemed to have similar carbon intensity.

Funds raised the carbon equivalency fee would be split between the EPA and the Department of Transportation.  The EPA would use its share primarily to fund state and local programs that assist communities in adapting to climate change, improving the resiliency of critical infrastructure; and protecting environmental quality and wildlife.  EPA could also use the funds to meet international commitments made by the United States to assist with climate change adaptation.  The Department of Transportation's share would be used to fund state and local programs that assist communities in improving the resiliency of critical infrastructure and for projects that provide preferential parking for carpools, including the addition of electric vehicle charging stations.

Will the Climate Protection Act of 2013 pass?  Congress has previously considered several structures to encourage a shift to lower-carbon energy resources, ranging from creating a national cap-and-trade market to a carbon tax.  To date, none has passed, although individual states and regions have created cap-and-trade programs like the Regional Greenhouse Gas Initiative (RGGI) and the California Air Resources Board market.  President Obama called on Congress to address climate change and carbon emissions in his 2013 State of the Union address, and other jurisdictions such as the Canadian province of British Columbia have enacted a carbon tax.  Could the carbon fee and dividend structure proposed in the Climate Protection Act of 2013 be the solution?  At the least, it will provoke a national dialogue about carbon emissions and the federal government's role in managing them.

Keystone XL pipeline supplemental Environmental Impact Statement

Thursday, March 7, 2013

The proposed Keystone XL pipeline took a step forward this month, as the U.S. State Department released its evaluation of the project's potential environmental impacts.  The draft Supplemental Environmental Impact Statement (EIS) released on March 1, 2013 documents the State Department's analysis of the pipeline's impacts to environmental resources based on the currently proposed route.  The EIS is still preliminary, and is now subject to public comment.  Moreover, even a final EIS would not reach any conclusion as to whether the pipeline serves the national public interest, and the project would still need a presidential permit to ship oil across the US-Canadian border.  Nevertheless the draft EIS does suggest that any environmental impacts from the pipeline would be relatively minor.

The Keystone XL project is a proposed extension of an existing crude oil pipeline.  The $7 billion project would run from the Canadian province of Alberta to Texas, delivering Canadian crude to refineries on the U.S. Gulf Coast.  The oil shipped on the pipeline would likely include so-called synthetic crude derived from Canada's oil sands or "tar sands" resources.

The draft EIS (available from the State Department's website) makes a series of findings about the project's potential environmental impacts, ranging from direct impacts along the pipeline's route to indirect impacts like further development of the Alberta oil sands.  As the State Department found in its earlier environmental review, the supplemental EIS found that the pipeline would not have significant impacts to any resources along the proposed project route.

Notably, the draft EIS found that Keystone XL would not be likely to substantially increase the rate of development of the oil sands, nor would it likely increase the volume of crude oil refined in the Gulf Coast.  For example, the draft found that denial of the pipeline's presidential permit would not mean a reduction in oil production in Western Canada or from the Bakken formation; rather, oil producers would resort to other transportation modes such as pipelines to British Columbia or even rail shipment of crude.  For similar reasons, the draft EIS found that the Keystone XL pipeline would not substantively change global greenhouse gas emissions.

Next steps for the Keystone XL project include a 45-day public comment period, after which the State Department will issue a final EIS.  Later this year, the State Department is expected to issue a so-called national interest determination, considering factors including foreign policy, economics, environmental concerns, and national security. This determination will involve consultation with other agencies, including the U.S. Departments of Defense, Justice, Interior, Commerce, Transportation, Energy, Homeland Security and the Environmental Protection Agency.  The final decision whether to allow the pipeline falls to President Obama.

Shell announces LNG plants for transportation sector

Wednesday, March 6, 2013

Energy company Royal Dutch Shell PLC has announced plans to build two liquified natural gas (LNG) plants in North America to produce fuel for marine and heavy-duty on-road transportation.

Shell, a global group of energy and petrochemicals companies, may be most famous for its roadside gas stations, but also operates businesses in crude oil and natural gas production, refining, marketing, and research and development. According to a press release issued yesterday, Shell and its affiliates now plan to develop two liquefaction units to turn natural gas into LNG.

By cooling natural gas to around -260°F, it can be liquefied.  The resulting LNG takes up significantly less volume than the gas did, making it easier to ship and store.  Unlike gas taken directly off a pipeline, LNG can also be used as a mobile fuel source for transportation.  Compared to oil-based fuels such as diesel and gasoline, LNG can be less expensive and may create fewer emissions of carbon dioxide and pollutants.

Shell's newly announced plants will be built in Geismar, Louisiana and Sarnia, Ontario, Canada.  The Geismar plant will supply LNG along the Mississippi River, the Intra-Coastal Waterway and to the offshore Gulf of Mexico and the onshore oil and gas exploration areas of Texas and Louisiana.  Shell is partnering with companies including subsidiaries of Martin Resource Management Corporation and Edison Chouest Offshore to supply LNG fuel to marine vessels that operate in the Gulf of Mexico.  Under Shell's vision, LNG produced at Geismar will be barged to Port Fourchon, Louisiana, where it will be bunkered into customer vessels.  Shell also announced plans for a similar liquefaction unit at its Shell Sarnia Manufacturing Centre in Sarnia, Ontario, Canada.  The Sarnia project is designed to supply LNG fuel to all five Great Lakes, their bordering U.S. states and Canadian provinces and the St. Lawrence Seaway.

Each facility will be relatively small-scale, capable of producing 250,000 tons of gas per year. According to Shell, pending final regulatory permitting, the liquefaction units may begin operations and production in about three years.  Shell is currently developing a similar gas processing facility in Alberta, Canada, and plans to sell LNG at truck stops in that province.

Several years ago, energy companies rushed to develop LNG import terminals in the U.S. to increase supplies of natural gas in the interstate pipeline system.  Hydraulic fracturing and the resulting development of feasible production of domestic natural gas from shale resources turned LNG imports' economics on their heads.  Now that natural gas in most of the U.S. is significantly cheaper than imported LNG, companies like Cheniere Energy Inc. are now seeking to export LNG to other countries.  Domestic use of LNG in the transportation sector represents an alternative way for energy companies to profit from the shale gas boom.

Utilities plan over $51.1 billion in transmission development

Tuesday, March 5, 2013

Growth in renewable electricity production will drive significant upgrades to the U.S. electric transmission grid, according to a study released by the Edison Electric Institute.  EEI's seventh annual "Transmission Projects: At a Glance" identifies over 150 transmission projects planned by EEI member utilities for development over the next decade.  According to the report, these projects entail investments of at least $51.1 billion through 2023.  While the transmission projects may advance multiple goals, the majority of the projected investments will be for projects supporting the integration of renewable resources into the grid.

EEI is a trade association composed of investor-owned electric utilities.  Its members represent approximately 70 percent of the U.S. electric power industry.  EEI tracks transmission investment by its members.  According to the report, annual transmission investment is increasing, from 11.1 billion in 2011 to approximately $15.1 billion in 2013.  At the same time, EEI has revised its total future projection downward.  In 2012, EEI members reported $64 billion in planned transmission over the next decade, but changing projections of system needs have revised that number downward to $51.1 billion.

Under federal laws including the Energy Policy Act of 2005, utilities are given incentives to develop transmission lines and related assets.  These incentives are designed to ensuring a safe and reliable electric grid, but also reward utilities for developing projects to integrate renewable resources like wind farms into the grid.  Because ratepayers ultimately bear the cost of transmission infrastructure, the Federal Energy Regulatory Commission and state public utilities commission regulate utility proposals to expand the grid. 

According to EEI, most proposed transmission projects advance multiple goals.  The study shows that 76% of projects (approximately $38.7 billion) are pitched as supporting the integration of renewable resources. In the aggregate, these projects entail the addition or upgrade of 13,300 miles of transmission lines.  Similarly, most projects are designed to enable electricity to flow across state lines; 52% ($26.5 billion) represent large interstate transmission projects spanning multiple states.

Whether each project identified in the EEI report will be built remains to be seen.  As demand for electricity shifts -- whether due to energy efficiency improvements, a declining economy, or newly proposed generating projects -- the need for any given transmission line may diminish.  For example, last year the $2 billion Potomac Appalachian Transmission Highline (PATH) project was canceled after it was deemed unnecessary.  The proposed Northern Pass transmission project connecting Quebec to New Hampshire is facing significant opposition due to the siting of its planned route, as well as on environmental and economic grounds.  Nevertheless, the significant transmission development projected by EEI remains likely to occur in the aggregate.

Federal budget sequestration's impacts on energy industry, consumers

Friday, March 1, 2013

Unless Congress enacts a plan to reduce the federal budget deficit today, a procedure known as "sequestration" will take effect immediately, cutting government spending until the budget can be resolved.  What will sequestration mean for the energy industry and consumers?

Under the Budget Control Act of 2011 (BCA), sequestration automatically kicks in unless the Joint Select Committee on Deficit Reduction proposes a plan to reduce the deficit by $1.2 trillion, and Congress subsequently enacts that plan.  For fiscal year 2013, sequestration could mean spending cuts of $85 billion over the remaining seven months of the fiscal year.  According to the federal Office of Management and Budget, nondefense program spending will be cut by about 9%.

Each federal agency's operations will be affected by the sequestration.  The OMB Report Pursuant to the Sequestration Transparency Act of 2012 (394-page PDF) details likely cuts, including reductions in funding available under the U.S. Department of Energy's High Energy Cost Grants program.  The High Energy Costs Grant program provides funding for improving and providing energy generation, transmission and distribution facilities serving communities with average home energy costs exceeding 275% of the national average.  For example, the Maine island of Monhegan's electric utility won a $420,154 grant under this program to replace the island's current switchgear, add a smaller, 40 kW generator to the power station's fleet, and add a 13 kW solar photovoltaic array to the power station's roof.

The sequestration could also slash funding for the U.S. Department of Agriculture's Rural Energy for America Program (REAP)REAP provides assistance to agricultural producers and rural small businesses to complete energy projects, including renewable energy systems, energy efficiency improvements, renewable energy development, energy audits, and feasibility studies

Other programs affected include the DOE's Energy Efficiency and Renewable Energy program, from which $148 million could be cut.  Likewise, the Low Income Home Energy Assistance Program (LIHEAP), which helps keep families safe and healthy through initiatives that assist families with energy costs, faces $285 million in cuts.

The funding reductions will also mean cuts to DOE's energy-efficiency and cybersecurity programs.  Likewise, the processing of applications for development of oil, gas, and coal on federal lands and waters would slow down as agency employees are furloughed.  

Will Congress act to avert sequestration?  If it takes effect, how long will it be until Congress enacts a compliant deficit reduction plan?  What price will society pay?