New Energy Incentives
A package of new tax incentives for energy projects is taking shape in the US Congress. Project developers and equity investors would be wise to take the new incentives into account in their planning.
The tax-writing committees in both the House and Senate approved separate packages of energy tax incentives in early April.
The House package is more expensive than the Senate. It would cost $18.1 billion over 10 years. The Senate incentives would cost $15.5 billion. There is only expected to be room for roughly $15 billion.
The tax incentives will be folded into a larger energy policy bill that is gradually winding through Congress. The energy bill passed the full House on April 11, but it will face greater difficulty in the Senate where it is tentatively scheduled for at least two weeks of debate in May. It must then go to a “conference committee” to iron out differences in approach between the two houses. A similar measure failed to make it to the president’s desk in the last Congress because the two houses were unable to reach agreement in conference. The hope is that things will be easier this time with both houses of Congress now under Republican control. However, there is no agreement, even among Republicans, about some of the more contentious issues. The betting by industry lobbyists is a bill will ultimately be enacted, although probably not until late in the year.
The House and Senate tax packages have many common features that are virtually certain to be in the final bill.
Both tax-writing committees voted for a nearly identical tax credit for new cogeneration facilities.
A “cogeneration” facility is a plant that produces two useful forms of energy from a single fuel. One of the outputs must be steam or another form of thermal energy. The other can be electricity or mechanical shaft power. The tax credit is 10% of the capital cost of the project.
To qualify, a plant must produce at least 20% useful thermal output, and it must have an energy conversion ratio greater than 70%. That means that the energy content of the electricity or mechanical power must be more than 70% of the energy content of the fuel used to produce it. (The conversion ratio must exceed 60% for smaller projects of 50 megawatts or less in size.) The 20% thermal output test may be hard for many companies to meet. The test to be a qualifying cogeneration facility under the Public Utility Regulatory Policies Act used to be only 5% useful steam output, and this was often difficult to reach.
The Senate committee waived both these requirements for plants that “generate electricity or mechanical power using back-pressure steam turbines in place of existing pressure-reducing valves or which make use of waste heat from industrial processes such as by using organic rankine, stirling, or kalina heat engine systems.” The House did not provide for a similar waiver.
Some cogeneration facilities will get less generous tax depreciation in the future. Any project for which a credit is “allowed” cannot be depreciated faster than over 15 years using the 150% declining-balance method (or over 22 years using the straight-line method for a project that is financed with tax-exempt debt). This will affect cogeneration facilities that burn culm, gob and other waste fuels.
The credit can only be claimed on new plants that are put into service during a window period that runs through 2006. The House and Senate disagree whether the window period should start with enactment of the bill or on January 1, 2004. As currently drafted, the effective date is a cliff. A project placed in service on the effective date would qualify for a full credit. One placed in service the day before would receive no credit.
The energy bill will extend an existing tax credit for generating electricity from alternative fuels.
The credit is currently 1.8¢ a kilowatt hour. It can be claimed currently by anyone generating electricity from wind, “closed-loop” biomass or poultry litter. The deadline for placing projects in service to qualify is December 2003. Credits run for 10 years after a project has been placed in service. The amount is adjusted each year for inflation. “Closed-loop” biomass refers to trees and other plants that are grown exclusively for use as fuel in power plants.
Both tax-writing committees voted to extend the deadline for placing such projects in service to December 2006. (However, the House extended it only for wind and closed-loop biomass projects – not poultry litter.)
Both committees also voted to add to the list of eligible fuels.
The House bill would add three new fuels: “open-loop” biomass, landfill gas and municipal solid waste. “Open-loop” biomass is “solid, nonhazardous, cellulosic waste material which is segregated from other waste material” and that falls into one of three categories. The categories are certain forest wastes, “solid wood waste materials” (like crates and construction wood wastes), and waste from agricultural sources. Municipal solid waste and paper that is commonly recycled are not considered “open-loop” biomass.
The Senate would add seven new fuels to the list of eligible fuels: “open-loop” biomass, livestock manure (and straw bedding), geothermal and solar energy, municipal biosolids, recycled sludge, municipal solid waste and small irrigation projects of up to five megawatts in capacity that generate electricity “without any dam or impoundment of water through an irrigation system canal or ditch.”
Under both bills, owners of existing facilities that use open-loop biomass to generate electricity would be able to claim tax credits for five years after the bill is enacted. An example is a power plant that burns wood. The credits would be at two-thirds the normal amount.
There are numerous complicated special rules in each bill that will have to be reconciled in conference.
For example, the House would allow owners of existing power plants that run on landfill gas to claim credits for five years on the electricity generated. The credits would be at two thirds the normal rate. The project could not double up on tax credits by also claiming section 29 tax credits for producing landfill gas (as well as section 45 credits for generating electricity from it). Anyone with an existing landfill gas project should be careful that this ban against doubling up on credits does not inadvertently rule out section 29 credits on which the landfill gas producer was counting. Section 45 credits are claimed by a different party – the company that purchases the landfill gas and uses it to generate electricity.
The House would allow section 45 credits to be used to offset taxes that a corporation owes under the “alternative minimum tax.” However, this would only apply to windmills that are put into service after the bill is enacted and then only for the first four years after the windmill commences service.
Lease financing is not used today for projects that qualify for section 45 tax credits. That’s because the statute denies any credits at all unless the same company that owns the project is also the “producer” of the electricity. The problem with a lease is the lessor is the owner and the lessee is the producer. Therefore, no one would be allowed tax credits. The House bill would allow the lessee or a contract operator to claim section 45 credits, but only for open-loop biomass projects that are already in service when the bill is enacted.
The Senate bill is a patchwork of special limits that were put in to try to keep the cost of the measure within bounds. It is a case study in how many different groups were able to keep their issues in play for conference with the House by claiming small placeholders that they hope can be fixed later. For example, under the Senate bill, open-loop biomass projects would only qualify for credits if put into service by the end of 2004. Projects that use other fuels would have until 2006.
Geothermal and solar projects would qualify for only five years of credits – not the normal 10 years.
The Senate would freeze the tax credit at 1.8¢ a kWh for all new projects – regardless of fuel type – that are put into service after the enactment date. There would be no further inflation adjustments after 2003 for such projects. This would affect not only projects that use newly-eligible fuels, but also new wind projects.
The Senate would let tax-exempt electric cooperatives, municipal utilities, state and local governments and Indian tribes sell the section 45 tax credits on projects they own to other taxpayers for cash. However, credits could be sold only once. A rural cooperative would have the option to treat the value of its credits as a payment against any loans the cooperative has from the US Rural Electric Service.
The energy bill will allow more time for taxpayers to place new projects in service to qualify for section 29 tax credits.
Such credits are an inducement for companies to look in unusual places for fuel. The current credit is $1.095 an mmBtu. Any new credits authorized by the bill will be only 51.7¢ an mmBtu. The House would adjust them for inflation starting with the credit amount for 2004. The Senate would not allow any inflation adjustment.
The bill will also allow additional credits to be claimed at a 51.7¢ rate on output from some existing projects.
The House bill would allow tax credits on output from new wells drilled through December 2006 that produce oil from shale or tar sands, or gas from geopressured brine, Devonian shale, coal seams or a tight formation. Output from existing wells would also qualify. Credits could be claimed on four years of output (but not past December 2009).
Landfill gas projects would also benefit. Gas from collection equipment put into service from July 1998 through December 2006 would qualify for five years of section 29 credits starting after the bill is enacted. (However, the credit would be only 34.5¢ for gas from landfills that are subject to new source performance standards that were issued in 1996 by the US Environmental Protection Agency.)
Taxpayers claiming credits under the House bill would be limited to credits on “average daily production” of 200 mcf over the tax year. An mcf is equivalent to 1.0276 mmBtus.
The Senate bill would allow credits to be claimed on output from new projects put into service after enactment through December 2006 that produce oil from shale or tar sands, gas from geopressured brine, Devonian shale, coal seams, tight formation or biomass. Credits could only be claimed for three years after a project is put into service.
The Senate would also allow section 29 credits for the first time for producing four additional fuels: liquid, gaseous or solid fuels from agricultural or animal waste, viscous oil, coalmine gas or “refined coal.” Projects to produce these fuels would qualify if they are placed in service during a window period running from the enactment date through December 2006. Credits could be claimed only for three years on the first two fuels, only through 2006 on coalmine gas, and for five years on refined coal.
“Refined coal” is defined as “liquid, gaseous, or solid synthetic fuel” from coal or lignite or fuel derived from high-carbon fly ash. Two things would have to be true for output from a project to qualify as “refined coal.” The nitrogen oxide, sulfur dioxide or mercury emissions from burning it would have to be at least 20% lower than the emissions from burning the raw coal used as feedstock, and it must have a “market value” at least 50% higher than the raw coal.
The Senate bill would also allow tax credits to be claimed through 2005 on output from existing coke batteries and coal gasification plants.
Prepaid Gas Deals
Some gas suppliers have been entering into long-term contracts to supply gas to municipal utilities. The utility prepays for the gas and is given a discount off the gas price for doing so. It borrows the funds to cover the prepayment in the tax-exempt bond market. The gas supplier gets access indirectly to money at tax-exempt borrowing rates.
These deals run afoul potentially of rules that bar a municipality from borrowing at tax-exempt rates and then reinvesting the proceeds in a commodity or other “investment-type property” that earns it a higher return than its cost to borrow. The discount off the gas price might be viewed as such an arbitrage profit.
The Internal Revenue Service proposed an exception from the arbitrage restrictions in April 2002.
The US Treasury Department is being actively lobbied to allow a similar exception for prepaid electricity deals – for example, where an independent power company signs a long-term contract to sell electricity to a municipal utility or electric cooperative.
Under the proposed IRS regulations last year, no arbitrage profit will be found as long as the municipal utility uses at least 95% of the gas to supply retail gas customers in its historic service territory or to generate electricity for customers whom it is required by federal or state law to serve. Its historic service territory is the area it served at all times during the five years leading up to when the tax-exempt bonds were issued.
The parties to such gas contracts usually also enter into a swap at the same time. Under the proposed IRS regulations, such swaps are okay as long as they are with third parties and the swaps stand as independent contracts. The swap will still be considered “independent” even though it terminates after a failure by the gas supplier to deliver gas for which the swap is a hedge.
Both tax-writing committees in the House and Senate voted to put an identical exception for pre-paid gas deals directly into the US tax code.
The exception would apply only to gas deals – not electricity.
Under it, the volume of gas secured by the prepayment in any year could not exceed the average annual gas volume purchased by retail customers of the utility or used by the utility to generate electricity for such customers – plus gas consumed to transport the gas. The testing period would be the five years ending before the calendar year in which the bonds are issued.
The utility would have to reduce the gas it is allowed to buy under the prepaid contract by any gas it has in storage on the date the bonds are issued and gas that it has a right to acquire during the contact term from other sources. This would include gas that the utility has under option. The parties could ask the IRS for a private letter ruling allowing a larger gas volume to accommodate expected population growth in the utility’s service area.
The energy bill will allow utilities that dispose of their transmission and distribution lines and related assets to pay tax on any gain ratably over eight years. This is called an 8-year spread.
The idea is to reduce the pain to utilities of divesting themselves of their transmission lines. The Federal Energy Regulatory Commission is pressing US utilities to transfer operating control at a minimum – and ownership if they prefer – of their transmission assets to large regional transmission organizations that would operate whole sections of the grid independently. These transfers are supposed to occur by December 2004.
A utility would be able to take advantage of the 8-year spread only on transmission and distribution assets that it sells to a qualified buyer. It would have to sell them either to an RTO (regional transmission organization), ISO (independent system operator) or other independent transmission company that has been approved by FERC. Alternatively, it could sell them to someone else as long as that someone else is determined by FERC not to be a “market participant” – meaning that it does not own power plants in the area served by the portion of the grid that it is purchasing and it assigns operational control over the assets to the nearest RTO or ISO. (There are special rules for transactions in Texas because the state is not part of the national electricity grid.)
Assets would have to be sold by 2006 to take advantage of the 8-year spread under the House bill. The Senate bill would allow another year through 2007.
Under the House bill, the utility would have to reinvest the sales proceeds in other utility property within four years after the sale. The other utility property could include such things as a power plant or a gas pipeline or shares of another power or gas company. The reinvestment could be done through an affiliate.
The sale of a utility company that owns transmission or distribution assets would also qualify for the spread.
Electric and gas companies have been pressing Congress for faster tax depreciation for their assets.
The House bill would allow faster tax depreciation for electric transmission and distribution assets. They are depreciated over 20 years today. Such assets put into service after the bill is enacted could be written off over 15 years. The faster depreciation could be claimed on existing assets that someone purchases after the bill is enacted.
Senator John Breaux (D.-La.) was expected to ask for the same treatment in the Senate, but did not raise the issue in the Senate tax-writing committee. There is the possibility that it could be added to the energy bill as a “manager’s amendment” when the measure is taken up on the Senate floor.
Both bills in the House and Senate would allow gas gathering lines to be depreciated over seven years using the 200% declining-balance method in the future. This has been an area of controversy with the IRS. The IRS has been insisting that gathering lines must be depreciated over 15 years. Duke Energy and the True Oil Company won the right to use 7-year depreciation in court. Clajon Gas Co., L.P. and Saginaw Bay Pipeline Co. lost their cases. There would be no inference under the bill about what was the correct treatment until now. Gathering lines are the pipelines at gas fields that bring gas from many different wells to a central collection point.
Both bills would also allow natural gas distribution lines – for example, the gas mains that a local gas utility uses to serve customers – to be depreciated over 15 years rather than the 20 years that is used currently.
The bills would allow the same tax depreciation for all these assets both under the regular corporate income tax and the alternative minimum tax.
The Senate bill would provide new tax incentives for retrofitting or repowering existing coal-fired power plants – or for building brand new plants – with clean coal technologies. However, the provisions are almost impossibly complicated; they make a mockery of claims by Congress that it wants to simplify the US tax code.
There is no similar provision in the House bill.
There would be three different incentives.
The first is a production tax credit of 0.34¢ a kilowatt hour for generating electricity at existing coal-fired power plants that are retrofitted within the next 10 years to use clean coal technologies. Credits would be claimed on the electricity output for 10 years after a plant is returned to service. The plant could not have a nameplate capacity greater than 300 megawatts. Only 4,000 megawatts of capacity would qualify for this “retrofit” credit. Projects would have to be certified in advance by the Internal Revenue Service. The list of clean coal technologies includes advanced pulverized coal or atmospheric fluidized-bed combustion, pressurized fluidized-bed combustion and integrated gasification combined cycle. The bill imposes other requirements, such as maximum heat rates and emission tests. The project could not have received any clean coal technology money from the US Department of Energy.
The Senate bill would also provide an investment tax credit for 10% of the capital cost of new or retrofitted clean coal plants. (A company whose retrofitted plant qualifies for the production credit of 0.34¢ a kilowatt hour could not also claim this credit.) A project would have to jump through a series of hoops to qualify. The hoops vary depending on the technology. For example, a plant using pressurized fluidized-bed combustion must be placed in service by 2016, and its heat rate and carbon emissions must comply with standards set by statute. Only 500 megawatts of pressurized fluidized-bed combustion projects in total could qualify for the tax credit, and only 250 megawatts of such capacity put into service before 2009 would qualify. Projects would have to apply in advance to the IRS for confirmation they fit under the megawatt cap.
Finally, the Senate bill provides a production tax credit for the same projects that qualify potentially for the investment credit. This credit would run for 10 years. The amount would vary from 0.1¢ to 1.4¢ a kilowatt hour depending on when the power plant is placed in service and on its design net heat rate. Plants that produce fuel or chemicals from coal – rather than electricity – could also qualify. The credit would be claimed on each 3,413 Btus of fuel or chemicals produced.
Municipal utilities, electric cooperatives, Indian tribes and the Tennessee Valley Authority could also lay claim to some of the scarce credits. Since these entities do not pay taxes, they would be allowed to sell their tax credits for cash. However, the credits could only be sold once.
Projects on Indian reservations qualify currently for special rapid tax depreciation and wage credits tied to the number of Indians hired to work on the project. A project must be operating by December 2004 to qualify. The Senate bill would extend this deadline by another year through December 2005. There is no similar provision in the House bill.
Both bills would encourage new investment in fuel cell power plants.
The Senate would allow a tax credit for 30% of the capital cost of such projects. However, the amount claimed as a credit could not exceed $1,000 per kilowatt hour of generating capacity. The fuel cell power plant would have to have a capacity of at least 0.5 kilowatts and operate at least at a 30% generating efficiency. Credits could be claimed on projects put into service through December 2007.
The House bill has the same provision, except that the tax credit would be for only 10% of the capital cost and the project would have to be placed in service a year earlier (by December 2006).