LARGE BATTERIES at wind and solar projects qualify potentially for investment tax credits.

The Internal Revenue Service said in a private ruling made public in late October that the owner of a new wind farm can claim a 30% investment tax credit on the cost of a large bank of lithium ion batteries installed at the project. The IRS decided the storage device is part of the generating equipment since it operates essentially as a knob on a motor by helping to control how much electricity from the wind farm is fed into the grid. The ruling is Private Letter Ruling 201142005.

The storage device will also be used to provide regulation services to the grid. However, less than 3% of the charge for the device on average is expected to come each year from the grid. The project is expected to get roughly a 20% boost in revenue from the device through both price arbitrage and regulation services.

The storage device is on the low side of the main transformer that the project uses to step up the electricity to transmission voltage. It is owned by the same legal entity that owns the wind farm. It helped that the device is not treated as transmission equipment for regulatory purposes by the grid.

The IRS has another ruling request pending involving a large battery installed at a wind farm that is already in operation. The battery in that case is expected to get roughly 15% of its annual charge from the grid.

The agency is still working out where to draw the line on tax subsidies for storage devices at renewable energy facilities.

MOST CALIFORNIA SOLAR PROJECTS remain exempted from annual property taxes, even if they are transferred during construction, according to draft guidelines the State Board of Equalization issued in mid-October.

California collects annual property taxes that are generally at least 1% of the assessed value of power projects. The actual rate varies by county. However, a project must be assessed first, and there is a one-time exemption for solar projects from assessment. Ordinarily, a project is subject to final assessment at the end of construction. Transferring a project also triggers an assessment.

Questions have come up whether the one-time exemption is used up if a solar project is transferred during construction.

The State Board of Equalization said it is not. However, utility-scale projects may not be able to benefit from the exemption. Most projects are assessed at the county level. The new guidelines do not apply to projects that are assessed at the state level. Projects that are 50 megawatts or larger in size are assessed at the state level if they are owned by “electrical corporations,” meaning power companies — or affiliates of such power companies — that make retail sales of electricity rather than sell all of their electricity at wholesale.

The new guidelines are also unclear about whether a change in ownership of the solar company during construction or a sale-leaseback of a project after construction is ignored. Most sale-leasebacks are done within three months after a project is put into service.

The SBOE is accepting comments on the guidelines through November 23, 2011. A public meeting will be held in January 2012.

FEDERAL BANK REGULATORS released 298 pages of regulations in October to implement a “Volcker rule” that is supposed to bar banks from engaging in proprietary trading and taking equity positions in private equity and hedge funds.

The regulations are not expected to prevent banks from investing as tax equity participants in renewable energy projects, according to Adam Gale, a bank regulatory lawyer in the Chadbourne New York office.

Gale said the key for a bank participating in a partnership flip transaction is it must have an ownership interest in the operating company itself or in a parent holding company whose only assets are majority interests in operating companies. It is important that the bank’s investment be in an operating company as opposed to a “covered fund.” If the bank were to invest in an intermediate entity that is not the operating company (or is not a parent holding company whose sole asset is a majority interest in an operating company), then “the intermediate entity would probably fall within the definition of a ‘covered fund,’ and the Volcker rule general prohibition against bank investments in covered funds would apply,” Gale said.

Proprietary trading, which is also banned, is defined in the new regulations as short-term trading, meaning investing in positions held fewer than 60 days. If a bank makes a tax equity investment with the intention of selling all or part of the investment within 60 days, then it is possible that the investment could be considered proprietary trading.

POWER PLANTS THAT USE SOLID WASTE as fuel can be financed in the tax-exempt bond market.

The IRS made it easier in August for fuel to qualify as “solid waste.”

Tax-exempt financing is normally reserved for schools, roads, hospitals and other public facilities. However, it can also be used to finance 13 other types of projects that are privately owned. One of the 13 categories is a “solid waste disposal facility.” Tax-exempt financing has been used in the past under this provision to finance expensive pollution control equipment at the back end of large coal-fired power plants. It has also been used to finance equipment through the boiler at the front end of power plants that burn culm or gob, two forms of waste coal. Culm is dirt that was brought up many years ago from underground mining of anthracite coal and left in a pile above ground. The dirt contains coal residues that can be removed through modern processes. Gob is similar material from underground mining of bituminous coal.

In the past, material qualified as solid waste only if it was unused, unwanted or discarded material that had no value in the place where it is located. Thus, if there was a local market in culm or gob, the fuel did not qualify as solid waste. Power plant owners would pay to have the culm or gob transported or processed, but not for the underlying material.

The IRS has dropped the need to show material has no value. Material now qualifies as solid waste if it has been used previously or is considered residue from an agriculture, commercial or industrial process. However, material qualifies as a residue only if its market value is less than the value of the products or service from which the material is left over. Animal manure is considered “used” material.

Virgin material is never a solid waste. Hazardous and radioactive wastes do not qualify.

The equipment at a power plant that uses solid waste as fuel qualifies for tax-exempt financing only up to the point where the first marketable product is produced. In most power plants using waste, that first product is steam. Therefore, tax-exempt bonds can only to be used to finance equipment through the boiler. The power train does not qualify.

At least 65% of the fuel used in the power plant each year the tax-exempt bonds are expected to be outstanding must be solid waste. If the actual percentage dips below 65% in a year, then the bonds would have to be partially refunded. However, if the dip is caused by events outside the control of the plant operator, then he can wait to see whether he is above 65% in each of the next two years and add the excess in each of those years to the percentage in the bad year to get above the threshold. The annual testing does not start until the power plant is not only in service, but also is operating at close to its nameplate capacity.

The new rules apply to tax-exempt bonds issued on or after October 18, 2011.

A MUNICIPAL POWER PLANT can be financed partly in the tax-exempt bond market, the IRS said, even though a private power company operates the plant and takes part of the electricity under a long-term contract.

This may open the door to some new financing strategies for projects where a municipality is prepared to take only part of the electricity output.

The IRS said in a private ruling made public in July that a municipal utility could use tax-exempt bonds to pay the cost of new power plant that the municipal utility plans to own. The utility will let an electric cooperative operate the plant and sell the coop a share of the power under a long-term power purchase agreement. The IRS said the municipality could use tax-exempt financing for a fraction of the plant cost. The fraction is the expected share of the electricity that the municipal utility will retain over the term of the bonds as a percentage of nameplate capacity,

Tax-exempt bonds usually cannot be issued for projects that are put to more than 10% “private business use.” It is a private business use to sell the output to a private party, including an electric cooperative, under a bilateral contract. It may also be a private business use to let a private party operate the plant. However, in this case the IRS said the fact that the coop was the contract operator was not a problem because the municipal utility planned only to reimburse the coop for the actual costs to operate and then only for a share of those costs equal to the share of plant capacity retained by the municipal utility.

The ruling is Private Letter Ruling 201128010.

A ROOFTOP SOLAR SYSTEM may qualify only in part for an investment tax credit, the IRS said.

Many rooftop systems require a membrane underneath the solar panels that doubles as a roof. IRS regulations have two conflicting rules when it comes to such membranes. One is that investment tax credits cannot ordinarily be claimed on the cost of “buildings and structural components.” The other is that even though something looks like part of the building, it can be so specially engineered as to be part of the equipment being installed on top of it. The IRS said it is prepared in such cases to allow an investment credit on the membrane only to the extent of the incremental cost above what a membrane that serves solely as a roof would cost.

The IRS position is in Private Letter Ruling 201121005. The agency released the text in June. It is not clear the conclusion is correct.

Congress said when it first authorized an energy tax credit for solar equipment (on which the current investment credit is patterned) that such equipment qualifies for a tax credit “without regard to whether the equipment [is] a structural component of the building.”

There are two tax credits for rooftop solar systems. A system put to business use qualifies potentially for an investment tax credit for 30% of the “basis” the owner has in the system.

The other tax credit is a solar residential credit — also 30% — for systems owned by homeowners. IRS officials say there is no reduction in the solar residential credit where solar shingles or tiles are installed, even though they also function as a roof.

Meanwhile, the IRS told a homeowner in another private ruling made public in August that a solar residential credit can be claimed on the incremental cost of a condensing unit installed to cool a home using electricity from rooftop solar panels. The IRS let the homeowner claim a tax credit on the cost to modify the condensing unit to run on solar electricity directly without having to run the electricity through an inverter. The homeowner was able to claim a 10% tax credit on the remaining cost of the condensing unit as an energy efficiency improvement to a building. The ruling is Private Letter Ruling 201130003.

The IRS is updating its regulations on when solar equipment put to business use qualifies for investment tax credits. The existing regulations date to 1980. The agency hopes to issue new regulations by June 2012. It is collecting comments in the meantime.

WIND FARMS IN PUERTO RICO and other US possessions qualify for accelerated US tax depreciation — and by extension, investment tax credits or Treasury cash grants — the IRS said in a private ruling.

However, the wind farm must have as its ultimate owners all US corporations or US citizens to receive the full subsidy. It is okay for such persons to own the project through a chain of limited liability companies or partnerships as long as all of the intermediate entities are “transparent” for US tax purposes.

Bringing in a local or foreign partner is a problem, unless the partner owns its interest through a US entity treated for US tax purposes as a corporation. It does not matter if any intermediate entities, including the project company, are formed outside the United States as long as they are considered transparent for US tax purposes.

The IRS issued a similar ruling earlier this year to the owner of a solar project in Puerto Rico. (See earlier coverage in the June 2011 Project Finance NewsWire at p. 21.) The new ruling is Private Letter Ruling is 201138018. The agency made it public in September.

MORE SUBSTATION EQUIPMENT than many companies thought earlier qualifies for a Treasury cash grant or investment tax credit at a wind or solar project.

Most developers filing for Treasury cash grants have been treating the cost of equipment through the transformer that steps up electricity to transmission voltage as eligible for cash grants.

The IRS said in an internal memo during the summer that it will also treat circuit breakers, surge arrestors and other equipment on the high side of the step-up transformer as eligible since the equipment protects the transformer from damage. It said the devices are “power conditioning” equipment. Such equipment qualifies for tax subsidies.

The position is in Chief Counsel Advice 201122018.

Ellen Neubauer, the cash grants program manager, said that companies cannot apply for additional grants on projects on which grants have already been paid.

INSTALLED SOLAR COSTS fell 17% in 2010 to $6.20 a watt on average for all “behind-the-meter” solar systems in the United States compared to 2009 in constant dollars, according to a September 2011 report by the Lawrence Berkeley National Laboratory.

The report said that “partial data” suggests the average cost fell another 11% in the first half of 2011 to $5.50 a watt. Costs for systems of 10 kilowatts or smaller in size ranged in 2010 from a low of $6.30 a watt in New Hampshire to $8.40 a watt in Utah. California and New Jersey, two states with the most amount of solar activity, were in the middle of this range.

Many rooftop solar systems are owned by third parties who sell electricity or lease the systems to building owners or homeowners and claim tax subsidies on the solar equipment that are then passed through to the customers in the form of a reduced electricity price or rent for use of the system. The report said that ownership by a third party added 30¢ a watt to the installed cost on average in 2010.

German homeowners paid significantly less for solar systems in 2010 than homeowners in the United States: smaller residential systems of 3 to 5 kilowatts in size cost $4.20 a watt on average, after installation, in Germany, compared to $6.90 a watt in the United States.

PERU extended a tax break in July that allows owners of wind, solar, biomass and small hydroelectric projects to depreciate the projects over five years. The tax break has been extended through 2020. At least 5% of new electricity production in Peru each year must come by law from such sources.

TAX STRATEGY PATENTS will no longer be issued by the United States under a bill that became law in September. The only exceptions are for patents on tax filing and preparation software and financial management software.

REITs can count income earned from selling carbon dioxide offset credits as good income, the IRS said.

REITs, or real estate investment trusts, are legal entities whose units are publicly traded. The capital raised is used to make real estate investments. The REIT is not taxed on its annual income, other than capital gains, as long as earnings are distributed to investors. Any tax is at the investor level.

To qualify as a REIT, the entity must satisfy several tests. There are both 95% and 75% income tests. At least 95% of the REIT’s income each year must be passive income and at least 75% must be passive income specifically from real estate investments. At least 75% of its assets must also be real estate, cash, cash items like receivables and government securities.

Congress gave the IRS broad authority in 2008 to treat other income as good income for both the 95% and 75% income tests “in appropriate cases consistent with the purposes of the REIT provisions.”

The IRS looked at a REIT that is a general partner in a partnership that owns standing timber. The partnership signed a three-year contract with a broker who buys and resells carbon dioxide offset credits. These are credits that companies buy to offset their greenhouse gas emissions. There are both “compliance” and “voluntary” markets for such offset credits. Companies that are required by law to have offsets buy and sell credits in the compliance market.

The REIT agreed in a contract it signed with the broker not to harvest any timber on certain parcels during the three-year term of the contract, other than thinning for forest management reasons. The broker is paying the REIT the public exchange price for carbon credits times the amount of carbon the trees are assumed to absorb. If the REIT harvests timber in violation of the contract, then it can substitute another parcel. Otherwise, it must repay the broker part of what it receives for carbon offsets as a penalty.

The IRS said that the carbon offset credits are so closely linked to the use of the underlying land that the payments the REIT receives for its offset credits under the contract should be treated as good income for both the 95% and 75% income tests. The IRS explained its position in Private Letter Ruling 201123005. The agency made the ruling public in late June. The IRS told another timber REIT the same thing in Private Letter Ruling 201123003.

The conclusions only hold for REITs that are not in the business of selling carbon offset credits. In the second ruling, the IRS said carbon credits are not inventory held for sale to customers. That ruling involved a US REIT that was selling carbon offset credits that it received from a foreign government for maintaining forests in a foreign country.

ANAEROBIC DIGESTER owners have been claiming refundable federal tax credits of 50¢ a gallon on methane made from hog and cattle manure and crop residue. The methane is used to generate electricity.

The IRS national office said in an internal memo that the agency made public in late August that the tax credits are not allowed. The memo is Chief Counsel Advice 201133010.

A tax credit of 50¢ can be claimed on each gallon of “alternative fuel mixture” that a company produces, provided the mixture is then sold to someone else for use as fuel or used directly as fuel by the company doing the mixing.

Manure and crop residue qualify as alternative fuels. Some companies mix a small amount of diesel fuel in with the manure or crop residue before it is fed through the biodigester and claim they have made an alternative fuel mixture. Others use atomizers to spray diesel fuel in the methane produced by the biodigester as the methane moves toward the generator where it is converted into electricity or else they add diesel fuel directly to the generator simultaneously with the methane.

The IRS said that in the first case where the diesel fuel is mixed with manure or crop residue before it is fed into the biodigester, the mixture is not being used a fuel. It said that in the second case where diesel fuel is sprayed into the fuel stream feeding the generator, no single alternative fuel mixture is produced. Two separate fuels —methane and diesel fuel — are consumed at the same time in the generator.

The alternative fuel mixture credit is a credit against federal excise taxes collected on gasoline, diesel and other fuels at the pump. However, the credit is refundable in cash or can be converted into an income tax credit if the taxpayer does not pay enough in excise taxes to absorb the full credit. The alternative fuel mixture credit is found in section 6426(e)(1) of the US tax code. It will expire at the end of December unless extended by Congress.

A DISTRICT COOLING SYSTEM, including underground pipes, can be depreciated over seven years, the IRS said.

A power company bought another company that owns a district cooling system in a large city. The system includes three plants for chilling water, a closed-loop system of underground pipes that run the water underneath a baseball stadium and downtown buildings and then back to the chillers to be re-chilled, and heat exchangers at each customer’s location to pull the cold temperature out of the water.

Equipment used to supply steam or water to customers must be depreciated over 20 years. Assets belonging to pipeline companies that transport gas, oil or other products to customers by pipeline are depreciated over 15 years. The IRS said the district cooling company is not in either business because it is not delivering steam or water to customers; the water is retained for use in the chillers.

The IRS also considered whether the underground pipes are part of the buildings to which they are connected. Buildings and similar “structural improvements” are depreciated over 39 years. However, it decided the pipes are equipment rather than buildings, even though the US Tax Court said in 1981 that a district cooling system that served a single apartment building was a structural component of the building. The Tax Court said the fact that the apartment building and the cooling system were owned by different taxpayers did not prevent it from being a structural improvement. The IRS said this case is different because the cooling system serves multiple customers and none of the customers has a right to take ownership of the pipes after a default.

The ruling is Private Letter Ruling 201131010. The IRS made it public in August.

A DEPRECIATION BONUS was allowed on a new hydrogen pipeline, even though the hydrogen company effectively committed to build the pipeline before the depreciation bonus became available in 2008.

The hydrogen company wanted to claim a 50% depreciation bonus, meaning deduct half the pipeline cost immediately and depreciate the remaining cost over 15 years. A depreciation bonus cannot be claimed if the company signed a binding contact to “acquire” the pipeline before 2008. The IRS said the fact that the company had a contract in 2007 to supply hydrogen to a customer and the contract required it to construct and own a pipeline to deliver the hydrogen to the customer did not mean the hydrogen company committed to “acquire” the pipeline in 2007. For one thing, the company did not “acquire” the pipeline; it built a new pipeline. The IRS also said the contract provision that made the hydrogen supplier responsible for the pipeline merely addressed how costs would be allocated between the hydrogen company and the customer.

The ruling is Private Letter Ruling 201140002. The IRS made it public in mid-October.

BIOFUEL producers may soon have access to additional financing from the US government of up to $510 million over the next three years for construction of new, or retrofitting of existing, plants to produce “drop-in” biofuel.

“Drop-in” biofuel is biofuel that can be mixed with petroleum-based fuel without any problems. The Department of Energy has committed to seek $170 million in new appropriations while the Department of Agriculture and the Navy will each “repurpose” $170 million of already appropriated funds.

An executive steering group made up of representatives from all three departments is still working out the details of the program. Either the Department of Energy or the Navy is expected to contract directly with developers of biofuel plants pursuant to the Defense Production Act. This legislation, enacted at the start of the Korean War, gives the president broad authority to contract and spend funds for national defense. It has been used by the US military in the last two decades to promote innovative military technologies. The Navy is expected to be the offtaker of the biofuel produced. However, it is not clear whether the Navy will be able to commit to an offtake arrangement whose term exceeds five years.

The Department of Agriculture’s commitment to “repurpose” $170 million in alreadyappropriated funds for the program is being made under the Commodity Credit Corporation Charter Act that authorizes the government to stabilize farm prices and income. This suggests its role may not be directly funding the construction of biofuel plants but rather providing price stability of the feedstock for biofuel production.

MINOR MEMOS. There is a chance that any jobs bill on which Congress is able to agree this year will extend a 100% “depreciation bonus” through December 2012. The bonus is the ability to deduct the entire cost of new equipment in the year the equipment is put in service. (For renewable energy projects that benefit from Treasury cash grants or investment credits, 85% of the cost could be deducted.) There would be no other depreciation. President Obama called on Congress in September to extend the 100% bonus. Obama is a Democrat. Eric Cantor, the majority leader in the House, which is Republican controlled, identified the bonus as an area of “potential common agreement” . . . . Europe is considering a financial transactions tax of 0.1% on shares and bonds and 0.01% on derivatives. The European Commission released a formal proposal on September 28. The proposal must be approved by all 27 European Union members to be imposed. Britain is expected to veto the proposal unless it can opt out. One option under discussion is to impose the tax only in the parts of Europe that use the euro. All financial institutions that are tax residents of countries imposing the tax would have to pay it on transactions in which they are involved, even if the transaction is carried out abroad. Sweden experimented with a financial transactions tax from 1984 to 1991. The tax was reported to have led to an 85% drop in transaction volumes . . . . The parent company of Virgin Airways is moving its trademarks and other brands to Switzerland in a move that is expected to reduce UK taxes for the group . . . . The IRS analyzed in an interesting internal memo made public in August whether a power company could calculate its income from a contract to supply electricity to an aluminum smelter by marking the contract to its market value at the end of each year and reporting the gain or loss as its income. A “dealer in commodities” can use that approach to calculate its income. Electricity is a commodity for this purpose. However, in the particular case, which was under audit, the IRS said what looked in form like a contract to sell electricity was really a tolling agreement. The smelter supplied the fuel the power company used. Therefore, mark-tomarket accounting could not be used for it. The IRS also said the decision whether to use markto- market accounting can be made by each legal entity separately even in cases where all the entities join in filing a consolidated federal income tax return. The memo is Chief Counsel Advice 201132021.