New Tax Incentives for Energy

New Tax Incentives for Energy

November 01, 2008 | By Keith Martin in Washington, DC

The massive Wall Street rescue package approved by the US Congress in early October included a series of tax incentives for energy projects. Some are merely extensions of existing incentives. Others are new.

Solar energy emerged as a big winner.

Congress extended a 30% tax credit for commercial and residential solar projects by another eight years through 2016. It made other changes that should make larger developers and tax equity investors more likely to be able to use the tax credit. It eliminated a barrier to utility ownership of solar projects. It also eliminated a cap on tax credits for homeowners who buy solar panels, which should lead to more direct sales of panels to homeowners in the future.

Wind farm developers were given another year through 2009 to complete projects to qualify for production tax credits on the electricity output. Developers of most other types of power plants that use renewable energy were given another two years through 2010.

The shorter extension for wind may reflect the shifting politics of wind in Congress. Congress gave the wind industry the choice of a one- or two-year extension, but the two-year extension would have come with a cap of 35% of project cost on the total benefit that each wind farm can receive from tax credits. The industry chose the shorter time period. It will try to extend the deadline again in 2009.

Most project developers cannot use the tax subsidies on their projects. Most barter them to institutional investors in exchange for capital to build projects, either by bringing the investors in as partners to own the projects and allocating them the tax benefits or, in the case of some solar projects, by selling and leasing back the projects. There has been a sharp contraction in the supply of available tax equity since mid-September. The collapse in the debt markets has led to a contraction in all types of capital available. There are discussions underway with Congress about interim measures that would allow developers to convert the subsidies more directly into cash, perhaps as part of an economic stimulus bill in a “lame-duck session” in November or early in the next Congress that takes office in late January. There is some sympathy from Congressional staff, but any such relief is considered a heavy lift politically.

Coal was another big winner in the Wall Street bailout bill.

The bailout bill includes a long list of tax incentives to use coal. The House was adamantly opposed to any such incentives. However, it ended up with its back against a wall after the House first rejected the larger bank rescue measure, causing stock prices to plummet. The Senate then sent the bill back to the House for a second vote, but this time with a large package of energy tax incentives appended, including for coal. The House was in no position to say no.


The bailout bill made five changes in the current tax incentives for solar energy.

Companies that buy solar equipment for commercial use can claim 30% of the cost in the year the equipment is put into service. This is called an investment tax credit. The credit is a direct offset against taxes the company would otherwise have to pay. The deadline to put equipment in service to qualify had been December 2008. The bailout bill extended it eight years through 2016. After 2016, the credit will fall back to a “permanent” level of 10% unless the deadline is extended again by Congress.

The bill also made it easier for corporations to use the investment credit. The United States has essentially two corporate income tax systems. Corporations compute their regular income taxes and then their alternative minimum taxes using a broader definition of taxable income and a lower rate, and they pay essentially whichever amount is greater. The rule had been that the solar credit could be used to reduce regular taxes by as much as 75%, but not below the level at which minimum taxes kick in. The bailout bill eliminated the bar against using credits to offset minimum taxes. The 75% limit on how low regular taxes can be reduced will remain in place. The change applies to tax credits on equipment completed in tax years starting after October 3, 2008. Thus, for example, a corporation that pays taxes on a calendar-year basis would benefit from the rule change on solar equipment put into service starting in 2009.

The ability to use tax credits against minimum taxes mainly helps larger developers. They will be more likely to be able to use the tax credits directly rather than have to enter into complicated tax equity transactions. It may also make potential tax equity investors more likely to commit to solar projects that require future funding before the investor knows whether it will be on the minimum tax. Tax credits that cannot be used in the year equipment goes into service can be carried back one year and forward for as many as 20 years.

Regulated utilities will be able to claim tax credits on solar equipment put in service after February 13, 2008. In cases where work on a project started before February 13, the credit can be claimed only on the work after February 13. Tax credits could not be claimed in the past on “public utility property.” A solar project fell into that category if the rates for sale of electricity from the project were set by a public utility commission on a rate-of-return basis.

The conventional wisdom is that letting utilities claim tax credits will mean fewer opportunities in the future for independent solar companies. Utility-scale solar projects exist today because of so-called solar set asides in a few states. There are 26 states with mandatory “renewable portfolio standards” that require electric utilities to supply a certain percentage of their electricity from renewable sources. Some of the states require that a share come specifically from solar energy. To the extent utilities choose to generate the electricity themselves, that will leave fewer opportunities for independent developers.

The truth is almost certainly more complicated. The solar industry did not fight the utilities on the change in law. Utility holding companies could already benefit from the 30% solar credit by owning projects through unregulated affiliates. What a utility could not do was claim a tax credit and put the project into the rate base on which the utility is allowed by its regulators to earn a return. Some industry experts have speculated that there will be a shift in the role played by independent developers from selling electricity to utilities to developing and selling projects to utilities — a so-called build-and-transfer model. Some utilities may also become more interested in solar as a form of distributed generation. Utilities grow by making new investments that add to rate base. Utilities may be more interested in owning solar panels on roofs of big-box stores, office buildings and homes in the future because they can now qualify for tax credits and put the panels into rate base.

The bailout bill should increase demand for solar panels from homeowners. Homeowners qualified in the past for a residential tax credit for 30% of the cost of photovoltaic panels and solar hot water heaters. The maximum credit that could be claimed on each type of equipment was $2,000. The bill eliminated the cap on solar panels but left it in place on solar hot water heaters. The cap has been eliminated only for solar panels installed after 2008. Congress also extended the deadline to claim residential tax credits on new solar panels and hot water heaters through 2016. The deadline had been December 2008.

Homeowners who pay minimum taxes had been able to use residential credits against such taxes, but not after 2007. The bailout bill restored the ability retroactively to the start of 2008.

Any homeowner who claims a residential credit must reduce the tax basis in his house by the amount of the credit.

Many roofers and installers focus on the residential market. Several large solar companies do as well, but with the intention of owning solar panels put on roofs of houses. They either lease the panels to the homeowners or sign contracts to sell them electricity. Lifting the cap on the tax credit a homeowner can claim may make some homeowners more likely to own panels, since it brings down the cost of panels to homeowners who choose to purchase the panels when they are new. However, there should still remain a healthy residential solar business since an independent solar company owning the panels can claim depreciation worth roughly another 26% of the cost of the panels and share the tax savings with the homeowner by charging a reduced rent or price for electricity.

Other Renewables

Companies that generate electricity from wind, geothermal steam or fluid, biomass, landfill gas, municipal solid waste or from incremental additions to existing hydroelectric facilities qualify for production tax credits on the electricity output. The credits are 1¢ or 2.1¢ a kilowatt hour, depending on the energy source. They are 2.1¢ a kilowatt hour for wind, geothermal steam or fluid and “closed-loop” biomass (plants grown exclusively to be used as fuel in power plants). They are 1¢ a kilowatt hour for other projects. Those are the tax credit figures for electricity generated during 2008. The credit amount is adjusted each year for inflation.

The deadline to place projects in service to qualify was December 2008.

The bailout bill extended it through 2009 for wind farms and through 2010 for other types of renewable energy facilities. Tax credits can be claimed on the electricity output for the first 10 years after a project is placed in service.

Congress also made the tax credit available for the first time at the 1¢ level to developers of projects that use “marine or hydrokinetic” energy to generate electricity. Such projects must be placed in service between October 3, 2008 and December 31, 2011 to qualify. “Marine or hydrokinetic” energy means waves, tides, currents or temperature differentials in oceans and free-flowing water in rivers, lakes, streams and irrigation canals. A project cannot involve a dam or other structure that impounds water. It must have a nameplate capacity of at least 150 kilowatts.

Municipal utilities, electric cooperatives and Indian tribes do not benefit from tax subsidies because they do not usually pay federal income taxes. The bailout bill authorized $800 million in “clean renewable energy bonds” as an alternative. These are bonds that can be issued to finance power plants that would qualify for production tax credits if they were privately owned. A project must be owned by a municipal utility, electric cooperative or Indian tribe. The borrower does not have to pay interest. The lender receives tax credits from the federal government instead. Since the tax credits are equivalent to interest, they must be reported as income by the lender.

Congress authorized $800 million in such bonds in 2006 and 2007. The limit was later increased to $1.2 billion. The first-round allocations of bond authority by the Internal Revenue Service were disappointing. The IRS received 701 applications to finance 786 projects. It approved bonds for 33 solar projects, 13 wind farms, 13 landfill gas facilities, 12 biomass facilities and six hydropower plants. The largest single bond allocation was $33 million. The average allocation was just a few million dollars.

Since the projects also qualify for depreciation deductions if privately owned, many municipal utilities, coops and Indian tribes would do better to put the projects in private hands, but take advantage of a “safe harbor” in the existing tax rules that lets them buy the electricity while coming close economically to the rights a lessee would have over the project.

Congress tinkered with the rules affecting various types of projects.

The tax code said anyone using municipal solid waste to generate electricity can claim production tax credits only if he “burns” the waste. The bailout bill changed the word to “uses.” Developers who plan to gasify garbage and run the gas through gas turbines — rather than use direct incineration — had sought the change. Some developers add additional generating capacity to existing biomass power plants. Tax credits could not be claimed in the past on the additional electricity output unless the original plant went into service after October 22, 2004 or the upgrades were so extensive as to turn the original plant into a new facility. The bailout bill makes clear that tax credits can be claimed on the electricity from any “new unit” added to an existing biomass plant after October 3, 2008.

The bill reworked the rules for when production tax credits can be claimed on the incremental electricity output from “efficiency improvements or additions to capacity” at existing dams. Anyone adding capacity at an existing dam that was not used previously to generate electricity had to show there would not be “any enlargement of a bypass channel, or the impoundment or any withholding of any additional water from the natural stream channel” as a consequence of installing turbines.

Developers struggled with this test. The bailout bill changed it. After 2008, a developer adding new equipment at an existing non-hydroelectric dam will have to show that the dam was operated for “flood control, navigation, or water supply” and was not being used on October 3, 2008 to generate electricity. The IRS must certify that the project will not increase the water surface elevation.

The bill lets investment tax credits on geothermal projects be claimed against alternative minimum taxes. Geothermal developers have a choice of claiming production tax credits of 2.1¢ a kilowatt hour on the first 10 years of electricity output from their projects or taking an investment tax credit for 10% of the project cost in the year the project is first placed in service. Almost all developers choose production tax credits. If the owner of the project pays minimum taxes, it may be unable to use production tax credits. They can be used against minimum taxes only for the first four years after the project is placed in service. The bailout bill lets the full investment credit be used against minimum taxes. The change is unlikely to cause a switch because of the large disparity in value between production tax credits and the investment credit.

Cogeneration, Fuel Cells and Small Gas Turbines

Cogeneration facilities are power plants that produce two useful forms of energy from a single fuel. An example is a power plant that burns coal under a boiler to produce steam. Some of the steam might be used as process heat at an adjacent factory and the rest is run through a turbine to generate electricity. The bailout bill provides a 10% investment tax credit for new cogeneration units put in service after October 3, 2008. If work started before that date, then the credit can be claimed only on the work after October 3.

The full credit can be claimed on cogeneration units of up to 15 megawatts in capacity. The credit is reduced as the capacity approaches 50 megawatts. There is no credit for units over 50 megawatts. For units between 15 and 50 megawatts, the credit must be multiplied by a fraction. The numerator is 15 megawatts and the actual capacity is in the denominator. Thus, only a 3.75% investment credit can be claimed on a 40-megawatt unit (10% x 15/40). The owner must reduce his basis in the cogeneration unit for depreciation by half the tax credit.

To qualify for an investment credit, at least 20% of the energy output must be “useful” thermal energy, meaning steam put to use directly as steam and not used to generate electricity.

The unit must have an energy conversion ratio of more than 60%. There is always an energy loss when fuel is converted into electricity. The conversion efficiency requirement is waived for units that are designed to run on biomass. There is no minimum conversion ratio for such units, but only a fraction of the tax credit can be claimed if the conversion ratio is less than 60%. In such cases, the credit must be multiplied by the actual conversion ratio divided by 60.

Fuel cell power plants qualify currently for a 30% investment tax credit, but must be in service by December 2008.The bailout bill extended the deadline by another eight years through 2016. The fuel cell plant must have an electricity-only generation efficiency of more than 30%.The credit is capped, after the bailout bill, at $3,000 per kilowatt of generating capacity.

Small gas turbines of less than two megawatts in size qualify currently for a 10% investment credit. The credit can be claimed not only on the cost of the gas turbine, but also related equipment. The gas turbine must be “stationary.” It must have a conversion efficiency of at least 26%. The deadline had been the end of this year to place such turbines in service. The bailout bill extended it another eight years through 2016. The credit is capped at $200,000 per megawatt of capacity.

Congress dropped a restriction that would have denied tax credits on cogeneration units, fuel cells and small gas turbines that are owned by regulated utilities. Companies will also be able to use the tax credits on projects completed after this year as an offset against minimum taxes.


Coal developers were not expecting much from Congress, but ended up with a maze of potential tax incentives for use of coal.

There is already an investment tax credit for investing in new IGCC (integrated gasification combined-cycle) power plants. The credit can only be claimed on equipment at the front end of such a plant that is “necessary for the gasification of coal, including any coal handling and gas separation equipment.” The credit is 20% of cost. The total amount that can be claimed in credits nationwide is $800 million. Developers hoping to claim credits must apply to the IRS for an allocation. No credits remain for IGCC projects that use bituminous coal. Another $133.5 million in credits remain for IGCC projects that use sub-bituminous coal and $133 million for projects that use lignite. Applications for the remaining credits were due at the US Department of Energy by October 31. Part two of the application must be submitted to the IRS by March 2, 2009. The IRS relies heavily on the Department of Energy to select the winning bidders.

There are no additional credits for IGCC plants in the bailout bill.

However, the bill increased a separate investment tax credit for other power projects that use “advanced” technologies to generate electricity from coal. The credit was 15%. It has been doubled to 30% for new projects after the original credits are exhausted. Congress authorized $500 million in credits originally in August 2005. Of that amount, $125 million in credits remain to be awarded by the IRS. Applications had to be at the Department of Energy by October 29.

The bailout bill authorized another $1.25 billion in tax credits for such projects. The IRS is expected to start taking applications for them next year.

Companies applying must be able to show that their projects will sequester at least 65% of carbon dioxide emissions. Congress directed the IRS to give the “highest priority,” in making awards, to a ranking of applicants by percentage of CO2 sequestered and to give a “high priority” to applicants who have a research partnership with a college or university.

A project can be a new power plant or a retrofit or repowering of an existing plant. To be considered an “advanced” technology, the project must have a design net heat rate of 8,350 Btus/kWh or better with at least 40% efficiency of energy conversion. The plant must also be designed to meet certain pollution standards, including 99% removal of sulfur dioxide and 90% removal of mercury. The tax code has a series of assumptions that must be made in calculating the heat rate. The fuel must be at least 75% coal. The plant must have a nameplate capacity of at least 400 megawatts.

The bailout bill also increased a separate existing investment tax credit for gasification projects. The credit can be claimed on new facilities that gasify any “solid or liquid product from coal, petroleum residue, biomass, or other materials which are recovered for their energy or feedstock value.” The equipment must turn the material into a “synthesis gas” composed primarily of carbon monoxide and hydrogen. The credit was 20% of the equipment cost. The bailout bill increased it to 30%.

The credit can be claimed on the gasification train at a plant that converts coal or biomass into synthesis gas. (A separate train must then turn the gas into transportation fuel.) “Biomass” is defined narrowly for this purpose. It includes only agricultural or plant waste, byproducts from wood or paper mill operations, and forest trimmings.

The total gasification credits that can be claimed nationwide were originally capped at $350 million. All $350 million has been allocated by the IRS. The bailout bill authorized $250 million more in credits.

It also tightened eligibility. Future gasification facilities must include equipment to separate and sequester at least 75% of the carbon dioxide emissions from the project. The credit may be recaptured if a project fails later to meet this sequestration threshold. Congress directed the IRS to give the “highest priority,” when allocating tax credits, to rankings of projects based on the percentage of CO2 sequestered and to give a “high priority” to any applicant who has entered into a research partnership with a college or university.

Projects that produce fuel from coal using the Fischer-Tropsch process qualify potentially for a separate “alternative fuels credit” of 50¢ a gallon, but only for fuel used in motor vehicles or motor boats. The bailout bill added aviation fuel to the list of eligible uses.

The alternative fuels credit is a credit against excise taxes on the fuel. The US government collects a “manufacturers” excise tax on some fuels when they leave the bulk transfer system. Fuels that escape manufacturers tax are subject to a retail excise tax when they are sold to the consumer. The alternative fuels credit is a credit against any retail tax. The IRS will refund the amount of the alternative fuels credit to the extent the credit exceeds the retail taxes the company has to pay.

The alternative fuels credit is available only through September 2009. The bailout bill extended it another three months to year end. Any coal-to-liquids plants must certify that at least 50% of CO2 emitted during production in the last three months of 2009 was separated and sequestered. The percentage will increase to 75% after 2009 if Congress extends the tax credit.

Coal-to-liquids companies were also given more time to sign binding construction contracts to build new plants and deduct half of the capital cost immediately. Half the cost of any new “qualified refinery” can be deducted in the year it goes into service. The portion of any coal-to-liquids plant that converts synthetic gas made from coal into a liquid fuel is such a refinery. The refinery must be under a binding construction contract by the end of 2009 to be built. It must be put into service by 2013. Its primary purpose must be to produce liquid fuel. The federal tax savings from the 50% immediate write-off are worth 2.6¢ or 3.6¢ per dollar of capital cost, depending on how rapidly the equipment would have been depreciated otherwise. The balance of the plant must be depreciated normally.

Separately, companies that convert coal or fly ash into fuel that is less polluting qualify potentially for “refined coal” credits today of $6.06 a ton. The credits can be claimed for 10 years after the facility that makes the refined coal is first put into service. The deadline to place such facilities in service had been December 2008. The bailout bill extended it by another year through 2009.

The bill also modified what is required to qualify as “refined coal.” Until now, the producer had to show at least a 20% reduction in at least two types of emissions from burning the refined coal compared to the raw coal and at least a 50% increase in value of the refined coal compared to the raw coal. There had to be at least a 20% reduction in nitrogen oxide emissions and either sulfur dioxide or mercury.

The need to show at least a 50% increase in value robbed the tax credit of much of its utility as an inducement to coal companies to invest in refined coal equipment. Coal prices fluctuate. So does the cost of allowances that an electric utility might otherwise have to buy to cover its emissions as an alternative to burning refined coal. Thus, no one investing in a refined coal facility today would be able to tell whether it will qualify for a full 10 years of tax credits.

The bailout bill dropped the market value test and increased the required reduction in nitrogen oxide emissions to 40%. A plant must still show at least a 20% reduction in either sulfur dioxide or mercury emissions. The change only applies to new refined coal facilities put into service in 2009. The IRS is working in the meantime on guidance. The guidance is expected to explain early next year how, and how often, the IRS expects companies to certify the pollution reductions.

The bailout bill authorized separate tax credits of 34.48¢ an mmBtu to be claimed for a year — and, in some cases, a little longer — by anyone producing “steel industry fuel.” The facility that produces the steel industry fuel must either be a new facility or modified existing facility that was put into service during the period October 2008 through December 2009.“Steel industry fuel” is liquefied coal waste sludge that is used as a feedstock for producing coke at steel mills. The liquefied sludge must be “distributed on coal.” Credits can be claimed for only a year or, if longer, through December 2009. Steel companies must be hoping the credit will be extended. As with so many tax benefits, the initial step is to get in the tax code and then try to expand the provision.

There was already a more generous tax credit for building a new facility to produce coke or coke gas. That credit was 56.55¢ an mmBtu for the output from such a plant in 2007. The amount is adjusted each year for inflation; the IRS will not announce the 2008 amount until next April. The coke or coke gas credit can be claimed for four years after a facility is first placed in service. The facility must go into service by December 2009 to qualify. However, the amount of credit is capped at an average output of 23,200 mmBtus a day. To the extent there is overlap, the new tax credit for producing steel industry fuel cannot be claimed on any fuel that also qualifies for the existing credit for producing coke or coke gas.

Finally, the US government collects an excise tax on coal mined in the United States. The tax is $1.10 a ton on coal from underground mines and 55¢ a ton on coal from surface mines. However, the tax cannot exceed 4.4% of the sales price of the coal. The tax had been scheduled to drop to 50¢ a ton on coal from underground mines and 25¢ a ton on coal from surface mines, and the cap had been scheduled to fall to 2% of the sales price for the coal, in 2014. The bailout bill pushed back the date the tax will drop to 2019. Revenues from the tax are used to fund a trust that is short on money to pay “black lung” benefits to retired miners. The government calculated the expected present value of the shortfall as of October 5, 2008. If the shortfall is eliminated before 2019, then the tax rates will drop sooner.


Biofuels use in the United States is subsidized through tax credits. Farm-state Senators occupy senior positions on the Senate tax-writing committee, and the presidential campaign starts in Iowa where biofuels are important to voters.

The tax code distinguishes among five types of biofuels: ethanol and other alcohol fuels, biodiesel, renewable diesel, cellulosic biofuel and “liquid fuel derived from biomass.”

The first four fuels benefit potentially from income tax credits. Income tax credits are given to small producers of ethanol or agri-biodiesel, to anyone blending any of the three fuels with gasoline or diesel fuel and to service station owners who sell the first three fuels at retail, and to producers of cellulosic biofuel. The income tax credits for biodiesel and renewable diesel were scheduled to expire at year end. The bailout bill extended them for another year through 2009. The tax credits for ethanol and other alcohol fuels already run through 2010. The tax credit for cellulosic biofuel was just enacted in a farm bill last May and runs through 2012.

The income tax credit used to be higher for blending agri-biodiesel — as opposed to other kinds of biodiesel — or for selling agri-biodiesel at retail. It was $1 rather than 50¢ a gallon. The bailout bill increased the credit for all biodiesel to $1 a gallon, effective for biodiesel blended or sold after 2008. The bill also added camelina to the list of plants whose oil can be used to make agri-biodiesel. The list is still important for small producers of agri-biodiesel, who qualify for an income tax credit on their output. A producer is considered small only if he has the capacity to produce no more than 60 million gallons a year. According to Wikipedia, farmers in Montana have been turning to camelina as a cash crop that can be sold for its oil. The chairman of the Senate tax-writing committee is from Montana.

A number of biodiesel plants in the United States import plant oil from overseas and then export the biodiesel they produce to Europe. The bailout bill bars any income or excise tax credits from being claimed in the United States on any ethanol or other alcohol fuel or biodiesel that is “produced outside the United States for use as a fuel outside the United States.”The change is retroactive to May 15, 2008.

Congress waded into a controversy that the US Treasury Department tried to settle in April 2007 over what qualifies for tax credits of $1 a gallon as “renewable diesel.” The term had been defined in the US tax code as diesel fuel made from “biomass” using a thermal depolymerization process described in one of two testing manuals published by the American Society for Testing and Materials — D975 and D396. Oil refiners urged the Treasury to define “renewable diesel” more expansively to include diesel fuel made by mixing poultry parts or other biomass with oil in existing refineries. The Treasury agreed.

Traditional biodiesel producers complained to Congress for fear of being muscled out of the still small biodiesel market by the oil majors. Congress responded in two ways. First, it broadened the definition. Renewable diesel will be defined after 2008 as any “liquid fuel” made using a process described in one of the two ASTM testing manuals “or any other equivalent standard” approved by the IRS.

Congress said that aviation fuel can qualify as renewable diesel. However, renewable diesel will no longer include any fuel made by “coprocessing” biomass with oil or other substances. The coprocessing ban went into effect on October 4.

Congress added “compressed or liquefied gas derived from biomass” as another type of alternative fuel that will qualify in the future for an excise tax credit. “Biomass” for this purpose means any organic material other than oil, gas and coal or byproducts of those three. An example is wood or garbage. The federal government collects excise taxes of as much as 24.4¢ a gallon on gasoline, diesel and other fuels. Excise tax credits of 50¢ a gallon can be claimed currently by companies selling liquefied petroleum gas, P series fuels, compressed or liquefied natural gas, liquefied hydrogen, and liquid fuel made from coal using the Fischer-Tropsch process. The credits apply only to sales through 2009, with the exception that they run through 2014 for liquefied hydrogen. The credits are refundable to the extent they exceed the amount the company owes in excise taxes.

The bailout bill should make pipelines more willing to carry biofuels. Many oil and gas pipelines are owned by master limited partnerships or MLPs. These are large partnerships whose units are traded on a stock exchange. The partnerships enjoy an advantage over corporations competing in the same line of business since the partnerships are not subject to income taxes. Their incomes are taxed to the partners directly. The key to qualifying as an MLP is to make sure that at least 90% of the gross income the MLP earns each year is considered eligible income.

The types of eligible income are mostly various forms of passive income. Examples are interest, dividends, rents from leasing out “real property” (as opposed to equipment), and gains from the sale of capital assets and real property. Pipelines will be able to count fees from transporting and storing ethanol, biodiesel and other alternative fuels as good income in the future.

Finally, the bill gives companies producing cellulosic biofuel or other alternative fuels more time to put new production facilities in service and qualify for an immediate tax deduction for half the cost. Such a deduction can already be claimed under section 168(l) of the US tax code on any new plant for making “cellulosic biomass ethanol.”The balance of the plant cost is depreciated normally. The accelerated deduction applies only to new plants put into service by 2012. The bailout bill broadened section 168(l) to apply to all cellulosic biofuel facilities — not just those that produce ethanol.

There is a separate right in section 179C of the tax code to deduct 50% of the cost of any new “qualified refinery” that is put into service by 2013. A production facility qualifies as such a refinery if it has a primary purpose of making liquid fuel using gas from biomass, among other permitted feedstocks. An example of gas from biomass is landfill gas. If a company cannot make the 2012 deadline for completing a cellulosic biofuel plant, then it might still qualify for an immediate deduction for 50% of the plant cost by treating the plant as a qualified refinery. However, to qualify, the plant must be under a binding construction contract by December 2009 to be built, and it must be completed by December 2013.

Carbon Sequestration

The bailout bill authorized tax credits of $10 and $20 a ton for sequestering carbon dioxide. It also let CO2 pipeline businesses be organized as master limited partnerships, which should make it cheaper to raise equity. The new tax credits are $10 a ton for CO2 captured and used as a tertiary injectant for enhanced oil recovery. They are $20 a ton for CO2 disposed in underground salt formations or coal seams that are not capable of being mined.

The IRS will track how much CO2 has been sequestered on account of the tax credits and announce when 75 million tons are reached. No more tax credits may be claimed after the year in which the 75-million-ton target is reached. Total US greenhouse gas emissions are about 7.2 billion tons a year, of which roughly a third comes from power plants.

The taxpayer claiming credits must own the industrial facility at which the CO2 is captured. At least 500,000 tons of CO2 must be captured at the facility per year. The owner can contract with someone else to use or dispose of the CO2. However, if the CO2 is not used or disposed properly, then the tax credits will have to be paid back to the IRS. The CO2 must be both captured and used or disposed of in the United States or a US possession like Puerto Rico or the US Virgin Islands. The dollar amount of the credits will be adjusted for inflation after 2009.

One impediment to greater carbon sequestration in the United States is lack of a network of pipelines to carry CO2. The bill will allow businesses that own CO2 pipelines to be organized as MLPs, meaning that the businesses can list units on a stock exchange and will not be subject to income taxes on their earnings. MLPs can raise equity more cheaply because of the tax advantage and because the units can be resold more easily than normal partnership interests. The key to qualifying as an MLP is to make sure that at least 90% of the gross income the MLP earns each year is considered eligible income. Eligible income includes income from producing, processing, transporting or marketing minerals and natural resources. The bailout bill added “industrial source carbon dioxide.” It was unclear in the past whether byproducts of producing, processing or transporting minerals or natural resources qualify.


The bailout bill gives electric utilities another year to shed all or part of their transmission assets. One obstacle to doing this has been that the utilities face potentially large tax bills if they have little unrecovered “tax basis” in the assets. In such situations, virtually all the compensation they receive is taxable.

Congress voted in October 2004 to let any utility that sells transmission lines or related equipment spread the income taxes on its gain over eight years. The utility must reinvest the sales proceeds in other electric or gas utility property or another power or gas company in the United States. The deadline to sell was originally 2006. It was later extended to 2007. The bailout bill extended it again through 2009.

The transmission assets must be sold to an “independent transmission company.” An independent transmission company can be an ISO (independent system operator), RTO (regional transmission organization) or other independent transmission provider approved by the Federal Energy Regulatory Commission, or any company that is not a “market participant” as the Federal Energy Regulatory Commission defines that term and whose own transmission facilities are put under operational control of an ISO or RTO within four years after the end of the tax year in which it acquires transmission assets from a utility.

Other Changes

Projects on Indian reservations qualify for more rapid depreciation. There is also a wage credit tied to the number of Indians hired to work on the project. Both benefits expired at the end of 2007. They have been extended through 2009.

Property that would have been depreciated over five years if it was built elsewhere — for example, a wind farm or solar project — can usually be depreciated over three years if built on a reservation. Most gas- and coal-fired power plants are depreciated over 15 or 20 years today. They qualify for 9- or 12- year depreciation if built on a reservation. Buildings are normally depreciated over 39 years, but 22 years if built on a reservation.

There is a separate annual wage credit tied to the number of Indians the project employs on the reservation. The credit is 20% of wages and employee health insurance costs paid during the year to employees who are enrolled members of Indian tribes and their spouses. “Substantially all” the work each employee does must be on the reservation. The worker must also live on or near the reservation where the services are performed. There are other restrictions.

Battery makers received a boost. The bill authorizes tax credits of $3,700 to $15,000 for buying a plug-in vehicle, depending on battery capacity and vehicle weight. The credits will phase out over the next two quarters after 250,000 vehicles are sold. If there were ever a strong move to plug-in hybrids, it would increase electricity usage in the United States, since the cars must be recharged over night.

Finally, the bill authorizes another $3.5 billion in “new markets tax credits” to be allocated by the US Treasury in 2009. New market credits are tax credits that store-front lenders — called community development enterprises or CDEs — can hold out as a carrot to raise equity from investors to use, in turn, to lend or invest in businesses in low-income areas. Investors receive a tax credit for 39% of the equity they invest in a CDE. The tax credit is claimed over seven years. The tax credit not only helps the CDE raise money to lend, but also makes it possible to lend at low interest rates. Many large banks have set up CDEs through which they lend to projects in rural and other parts of the country that qualify as low income. Investors often use leverage to increase the amount of tax credits in relation to the actual equity invested.

The Treasury announced 2008 awards of new markets tax credits on October 20. The agency awarded $3.5 billion in credits for 2008 to 70 CDEs out of 239 who applied.