Wind Market Update
The US wind market is expected to boom for at least the next 12 months now that the US government has extended a “production tax credit” that is essential for wind projects in the United States.
Projects must be put into service by December 2005 to qualify. The earlier deadline to complete projects had been December 2003, and there were questions about whether the extension — when Congress got around to passing it — would be retroactive so that plants put into service before the credit was extended in September 2004 would qualify for tax credits. They do.
The American Wind Energy Association estimates that wind developers will require another $2 to $3 billion in capital in the next 12 months to finance new projects.
The tax credit is 1.8¢ a kilowatt hour and can be claimed on the electricity sold to third parties from wind farms for 10 years after a plant is put into service. The tax savings from the credit are worth about 33.5% of the capital cost of a typical project in present-value terms. The credit is adjusted each year for inflation. The figure 1.8¢ is the credit for 2004.
In early October, Congress also eased a problem with the “alternative minimum tax.” Corporations in the United States must compute both their regular income taxes at a 35% rate and “alternative minimum taxes” at a 20% rate but on a broader definition of taxable income. They pay essentially whichever amount is greater.
Production tax credits cannot be used to reduce a corporation’s regular income taxes below the level at which the alternative minimum tax kicks in. This is now causing problems for some larger wind developers and is also a source of concern for potential equity investors in wind deals. Congress voted before adjourning for the US presidential elections to allow production tax credits to be used against minimum taxes, but only for the first four years after a wind farm is originally placed in service, and then only for projects that are put into service after President Bush signs the bill. He is expected to sign it in late October or early November.
Wind developers are facing a deadline of December 2004 to qualify for a “depreciation bonus” on their projects.
The US government made a limited-time offer after the terrorist attacks on the World Trade Center and the Pentagon. Anyone investing in new plant and equipment in the United States during a “window period” that runs from September 11, 2001 through 2004 or 2005, depending on the investment, can deduct as much as 50% of the cost of new assets in the year they are put into service. The balance of the cost is deducted over the normal depreciation period.
Wind farms must be put into service by December 2004 to qualify. It is possible in a wind farm to put some of the turbines into service in 2004 even though others might not get into service until 2005. The federal tax savings from the bonus are worth 2.61% of the capital cost of a wind project. The bonus can also be claimed in some US states. At last count, 25 states that otherwise piggyback their income taxes on the federal system had “decoupled” and were not allowing the bonus, and another six states were only allowing a partial bonus.
The Internal Revenue Service is reassessing whether any state tax credits cause a “haircut” in the federal production tax credit. It has committed on its current business plan to issue guidance by next June 30.
One of the most important questions for any investor in a wind project to ask on due diligence is whether the project benefited from government grants, tax-exempt financing, subsidized energy financing or any “other credit.” If so, then the federal production tax credit is reduced by the portion of the capital costs of the project that were paid for with these benefits. For example, if 90% of the project costs were financed with tax-exempt bonds, then the federal tax credit is reduced by 90%.
The IRS has said in a series of private letter rulings that various state benefits do not require a haircut. The agency released the latest such ruling in early October involving a state program to encourage wind development, probably in Oregon. Utilities in the state are required to collect a “public purposes charge” as part of electricity rates to cover, among other things, the above-market costs of renewable energy. The money collected is paid into a trust fund, and a state agency has authority to direct how the money is spent. In the case addressed in the ruling, a partnership that is developing a wind project agreed to transfer all the environmental attributes from its electricity — for example, greenhouse gas credits — to the trust in exchange for an “advance payment.” The advance payment “vests”— does not have to be paid back — as the project delivers electricity to an in-state utility that has agreed to purchase it. Any part of the advance payment that has not vested by year 15 must be paid back.
The IRS ruled that the advance payment is not a government grant, tax-exempt financing, subsidized energy financing or “other credit.” It said the arrangement is not a “grant” because there remains a possibility that some or all of it might have to be repaid.
The partnership also qualifies for a “business energy tax credit” equal to a percentage of the capital cost of the project. (Wind projects in Oregon qualify for a 35% tax credit, but no more than $10 million per project. The credit is claimed over five years.)
The IRS declined to rule that the tax credit will not cause a “haircut” in the federal credit. It said the issue “cannot be readily resolved before published guidance is issued.”
The ruling is PLR 200439038.
The director of the Oregon Department of Energy wrote Greg Jenner, the assistant Treasury secretary for tax policy, a letter on September 27 urging the US government to issue the guidance quickly. He wants a conclusion that the Oregon business energy tax credit will not result in a haircut. Jenner used to be an aide to former Oregon Senator Bob Packwood (R).
The informal IRS position in the past has been tax credits that are tied to the cost of a project reduce the federal credit. Tax credits that are tied to the amount of output should not.
Thus, for example, the IRS ruled privately in 2001 that the owner of a wind project did not have to reduce his federal tax credit on account of receiving “renewable energy credits” — or RECs — from the state where the project is located. The RECs are tied to output. The IRS ruled privately in 2003 that no haircut is required by a project that receives state tax credits that are tied to the amount of property taxes the project pays and how many workers it employs.
Oregon argues that when the US tax code says there is a haircut for any “other credit,” Congress intended that a project would suffer a haircut only on account of other federal tax credits. IRS officials are still weighing the arguments. There is no clear evidence of what Congress intended. The IRS is looking at what inferences it can draw not only from the wording of the production tax credit, but also from a similarly worded statute that allows companies to claim tax credits for producing landfill gas and synthetic fuel from coal.
A company that bought a wind project recently in an asset sale by the bankrupt owner may not have done enough due diligence. The IRS said in a private letter ruling made public in early October that the new owner of the project is not allowed any production tax credits, at least until it amends the power purchase agreement to reset the price for a portion of the electricity sold to current market. The project is earning an above-market price currently for its electricity.
The ruling is PLR 200440001.
Congress voted in 1999, after lobbying by the California utilities, to deny production tax credits to any wind project that a taxpayer places in service after June 1999 to the extent the electricity is sold under a power sales agreement with a utility signed before 1987. The only exception is if the contract is amended to limit the electricity that can be sold under the contract at above-market prices to no more than the average annual quantity of electricity supplied under the contract in the five years 1994 through 1998 or to the estimate the contract gave for electricity output. “Above market” means for more than the avoided cost of the electricity to the utility — or the amount the utility would have had to spend itself to generate the electricity — at time of delivery.
The provision comes into play when an existing wind project is sold to a new owner.
Nevada requires electric utilities in the state to supply at least 5% of their power from renewables. The percentage is scheduled to increase to 15% by 2013. The two Nevada utilities have been unable to buy enough electricity from renewable suppliers to comply with the law because of impaired credit ratings. A project will have a harder time arranging financing without a creditworthy offtake contract.
The Nevada Public Utilities Commission voted on September 29 to order the two utilities to set up trust accounts. The commission will authorize the utilities to increase rates to cover their obligations to renewable suppliers plus set aside at least “three times the highest monthly payment” owed each eligible renewables supplier under its contract with the utility as a reserve.
Only projects on which construction started on or after July 1, 2001 qualify potentially for participation in the program.
The hope is the trust mechanism will allow such projects to obtain financing.
All payments under the power contract the project has with a utility will be made by the trust. The trust will remain in place at least until the utility has maintained an investment grade credit rating with Moody’s or Standard & Poor’s for 24 consecutive months. It will fall away earlier if the “original financing, including debt, equity, or both debt and equity, as applicable ... has been fully satisfied pursuant to its original terms.” The PUC will revisit the rates charged by the utility to its ratepayers once a year. Amounts remaining in the trust when the trust is extinguished will be returned to the utility, but will factor into what the utility is allowed to collect in rates going forward. The utilities will have to pay income taxes on the revenue they collect from ratepayers, even though the amounts are paid into trust, but they will receive offsetting tax deductions as amounts are paid for electricity.
It remains to be seen whether the trusts will satisfy the financial community. The protection the trusts provide is a reserve account equivalent to three months of power sales revenue. According to Ted Zink, a bankruptcy partner in the Chadbourne New York office, lenders to the power project remain at risk that the power sales contract with the utility might be rejected in bankruptcy.
Financial officers at wind developers report that they are getting expressions of interest to invest in wind deals from institutional investors who lack a tax base to use production tax credits. This has put more pressure on whether a partnership that owns a wind project can distribute cash disproportionately to a cash investor while preserving the production tax credits for other investors who can use them.
IRS regulations require that partners share in production tax credits in the same ratio as they share in “receipts” from electricity sales.
Many tax counsel believe — at least until the IRS says otherwise — that partners can share in cash however they want without affecting tax credits.
The IRS national office has no position yet. IRS officials start with a sense of uneasiness with any notion that a developer or cash investor might strip out cash while leaving tax benefits for a tax-base investor.
Cash can be distributed to a partner as a “guaranteed payment” without affecting tax credits. “Guaranteed payments” are amounts that the partnership commits to pay a partner each year as a return on his capital or as compensation for services. An example is where a partnership agreement directs that $250,000 a year be paid to partner X out of the first available cash. Remaining cash is shared among the partners in a different ratio. If there is too little cash in a year to make the guaranteed payment, then the shortfall is made up in later years. Guaranteed payments have no effect on how tax credits are shared. The key to a guaranteed payment is the amount owed to the partner does not depend on how much income the partnership earns. It is treated for tax purposes like a payment to a third party — for example, the interest the partnership pays a bank. Payments to third parties do not affect how tax credits are shared among the partners.
A US wind developer announced a plan to put wind turbines on farms and to organize the farmers into an electric cooperative to own the turbines. Coops are effectively exempted from federal income taxes on the income that they distribute (or are deemed to have distributed) each year as long as at least 85% of the income comes from the provision of services to members. The developer said he plans to preserve the production tax credits for institutions that will provide the financing and to pay the farmers a 30-year annuity. The structure will be a challenge to make work. Coops in rural areas — whether or not they are tax-exempt — qualify potentially for loans from the US Department of Agriculture with terms as long as 30 years at rates as low as 1/8th percent above the rate charged by the federal financing bank for interagency borrowing.
A common question recently is whether wind farms on Indian reservations qualify for production tax credits. A Texas wind company announced projects on two reservations near San Diego in early October.
Wind projects on Indian reservations qualify potentially for depreciation over three years rather than five years used by such projects off the reservation. The tax savings from the faster writeoffs are worth about 2.27¢ for each dollar of capital cost. Such a project also qualifies for a wage credit tied to the number of Indians hired to work on the project. The deadline for placing projects in service to qualify for these benefits is December 2005.
Production tax credits may only be claimed on electricity produced “within the United States.” Indian tribes are treated as sovereign nations for most tax purposes. There is some helpful case law that suggests a project on a reservation would qualify, but no clear answer.
Some US wind developers are looking at Canadian income funds and cross-border lease arrangements as a way to find cheaper capital.
A Canadian income fund is a trust formed in Canada that raises money in the Canadian capital markets and pools it for investment. Such trusts pay little US income tax on their earnings from US businesses in which they invest, and they are not subject to tax in Canada. This tax advantage means that the trusts can afford to pay at least 27% more than competing bidders for operating businesses. The problem US wind developers face when trying to tap such trusts is the trusts have no US tax base to use production tax credits, and the trusts are interested mainly in businesses that throw off a steady and predictable cash flow. The trusts may ultimately prove good cash investors alongside US institutions that can use production tax credits, at least for projects with long-term power sales agreements and a good operating history.
Cross-border leases, if they can be structured properly, involve ownership of wind turbines by an institution in another country and a lease of the turbines to a US wind company. The foreign lessor and the US wind company claim tax ownership of the turbines in their respective countries. This introduces an additional tax subsidy to the project. Such transactions only work with a lessor in a country that bases tax ownership largely on the form of the transaction. The foreign lessor advances the funds for the turbines and retains legal title to them during the lease term. The US wind company effectively prepays the rents and the exercise price for a repurchase option to be exercised when the lease ends. The prepayment is less than the full cost of the turbines; the difference is an upfront benefit to the US wind company. The US wind company remains the owner of the turbines for US tax purposes; the United States bases tax ownership on the underlying substance of the transaction. The structure leaves room for another financing — for example, to get value for the production tax credits — to be done in the United States.