With this installment, we turn to a Special Update that was published in the September 2012 issue of the Project Finance NewsWire written by Chadbourne partner and co-head of the Project Finance Group, Keith Martin.
Prepaid Power Contracts
Developers are taking another look at prepaid power contracts as a way of reducing the cost of capital for utility-scale renewable energy projects.
The concept is simple and is not necessarily limited to use in the United States. The developer asks the utility that has signed a long-term contract to buy electricity from the project to prepay for a portion of the electricity in exchange for a discount on the electricity price.
Chances are the utility has a lower cost of capital than the project has. The prepayment is economically equivalent to a loan to the project by the utility that the project repays in kind by delivering the prepaid electricity. However, it is “soft” debt without all the tight default triggers that one normally finds in project debt. If there is a shortfall in electricity delivered compared to what was promised, the project can have as many as three years to make up the shortfall before there is a default, and its penalty after that is simply to pay the cost of replacement power.
At least four large wind farms with prepaid power contracts have been financed to date. In three of the projects, the prepayments raised roughly 50% of the capital cost of the project. Most of the remaining capital was raised in the US tax equity market. In one project, the prepayment was closer to 87% of the project cost.
The utilities in the four large transactions to date were municipal utilities or electric cooperatives. However, the strategy can also be used in projects that sell to investor-owned utilities and in large inside-the-fence projects.
Municipal gas utilities have used prepaid gas contracts since at least the 1990s to make advance purchases of multi-year quantities of natural gas. The utilities issue tax-exempt bonds to raise the money for the prepayments. They see the transactions as a form of hedging to lock in long-term gas supplies at low prices during periods when gas prices are expected to rise.
At least 33 gas prepayment bonds worth $23 billion have been issued since 2003 when the Internal Revenue Service made an exception to arbitrage restrictions that were an impediment to such bond issuances. The tax-exempt bond market is supposed to be limited to financing of roads, schools, hospitals and other public facilities. A municipality cannot borrow in the bond market at tax-exempt rates and then invest the bond proceeds in a way that earns a higher return, as that would increase bond volume and push up rates to finance public facilities. US tax regulations define impermissible arbitrage as including borrowing to purchase commodities. However, in 2003, the IRS made an exception in the arbitrage rules to permit prepaid gas and electricity transactions.
Under the IRS regulations, no arbitrage profit will be found where a municipal utility prepays for electricity as long as the municipal utility uses at least 90% of the electricity to supply retail customers in its historic service territory or to make wholesale sales to other municipal utilities that use the power to supply their own retail loads. A utility’s 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.
In August 2005, Congress wrote a slightly different version of the exception for prepaid gas deals directly into the US tax code as part of the Energy Policy Act of 2005. The statutory exemption only covers gas; Congress was silent about electricity. A Treasury official told Chadbourne at the time that he did not believe there was an intention to rule out prepaid electricity transactions and they can still be done under the exception in the IRS regulations.
Prepaid gas transactions are centered around the municipal bond offering. The gas supplier is usually a commodity unit of a large bank or investment bank that guarantees performance by the supplier, allowing the bonds to have the same credit rating as the bank or investment bank providing the guarantee. Credit downgrades for 15 banks in June 2012 led to a cut in ratings on 24 gas prepayment bonds worth about $19 billion.
Three electricity prepayment deals were done during the period 2003 through 2007 patterned on the gas model. Of these, the longest was a $1.4 billion purchase of six years’ of electricity by Memphis, Light, Gas & Water from the Tennessee Valley Authority in December 2003. Fayetteville, North Carolina entered into a two-year deal in November 2005. American Municipal Power-Ohio signed a six-year deal with J. Aron, a Goldman Sachs subsidiary, as the supplier in 2007.
In transactions using the gas model, the municipal utility pays in advance for all the gas or electricity it will be delivered over time.
The first prepaid electricity deal involving a wind farm closed in December 2006. The offtakers were two public utility districts and two electric cooperatives. No municipal bonds were issued to finance the prepayment. Such bonds were issued in the next three transactions, but unlike the gas model, they were not a central focus.
Under the structure as adapted for use by independent generators, the utility prepays for only a portion of the electricity to be delivered.
The structure works as follows.
The utility enters into a long-term contract to buy electricity. It pays at closing on the permanent financing for electricity to be delivered over the full term of the contract. The contract has a schedule showing the quantity of prepaid electricity each year. For example, the schedule might show a fixed annual quantity of megawatt hours of electricity for which the utility has paid in advance. The utility must pay on a current basis for any “excess” electricity the project delivers above the prepaid quantity as well as for any renewable energy credits, carbon credits and other intangibles. It can only prepay for electricity; thus, in contracts with both energy and capacity payments, the capacity payments could not be paid in advance. Sometimes the prepayment is merely a deposit against the future cost of the prepaid electricity, and an additional payment must be made as the prepaid electricity is delivered.
In most transactions, the utility receives a discount on the prepaid quantity for having paid in advance.
The utility has a first lien allowing it foreclose on the project in the event the project defaults on the obligation to deliver the prepaid electricity. However, the project usually has three years to make up any shortfall before it is considered in breach and even then it is required to pay a cost of cover before the situation turns into a default.
The utility usually has an option to purchase the project at year 10 and again at the end of the power contract for fair market value determined upon exercise. The value is whatever the parties agree at the time or, failing agreement, what an appraiser concludes is the value. The value at year 10 is calculated by assuming the project will continue to benefit from or remain burdened by the remaining term of the power contract so as not to create any economic compulsion for the utility to exercise the option.
Limit on Prepayment
There is a limit on the size of the prepayment.
It is important that the developer not have to report the full prepayment as taxable income upon receipt. Companies must normally report cash payments from customers as taxable income no later than when the amounts are received. However, the IRS regulations have a special rule for advance payments to manufacturers of “goods.” Advance payments may be reported as the goods are delivered, provided the manufacturer reports them no more rapidly “for purposes of all his reports (including consolidated financial statements) to shareholders, partners, beneficiaries, other proprietors, and for credit purposes.”
In the case of “inventoriable goods,” a two-year clock begins to run on when the remaining advance payment must be reported as taxable income when two things are true. One is the manufacturer has on hand through inventory or available through his normal sources of supply the remaining quantity of goods for which the customer has prepaid. The other is the manufacturer has received a “substantial” advance payment. An advance payment is “substantial” when it equals or exceeds the expected cost to supply the goods.
The IRS treats electricity as “inventoriable goods.” Thus, the two-year clock has the potential to be triggered.
It is unclear whether an independent power project will be viewed as having available to it at inception — or at any time in the future — through normal sources of supply all of the electricity that was prepaid under the power contract. There is a spot market in electricity. The project can buy at some price the full output promised over the full term of the power contract. However, that cannot be what the IRS intended by this trigger. The reason for starting a two-year clock to run is that the IRS thought it inappropriate in certain situations to tax manufacturers fully on advance payments at time of receipt, but it did not want to let manufacturers play games with timing by spreading out income when they have all the inventory needed to supply an order either sitting in the warehouse or readily accessible by picking up a phone. The typical long-term power contract calls for scheduled deliveries over a particular time period. Electricity cannot be stored. Under the IRS regulations, the two-year clock does not start to run until the producer “[h]as on hand (or available to him in each year through his normal source of supply) goods of substantially similar kind or in sufficient quantity to satisfy the agreement in such year.” It would not satisfy the agreement for the project to supply the utility on day one with the full amount of electricity the utility requires over 20 years. The utility would bring a claim for breach of contract.
Two things must be true for the two-year clock to start to run. The other is that the advance payment must be “substantial.” It is substantial when it equals or exceeds the expected cost to supply the electricity. The logic behind this trigger is that the United States taxes businesses on income and, until the project has received a large enough payment to lock in a profit on the electricity that has been presold, it does not yet have any income to tax.
This has a bearing on how large a prepayment can be made. The expected cost to supply the electricity includes depreciation on the power plant. The expected costs to supply electricity should be allocated among all of the output. The test whether the prepayment is substantial should be applied by comparing the prepayment only to the costs that are allocated to the prepaid electricity.
If the remaining advance payment must be reported in full as income because of the two-year clock, then the project would have to report only the net amount after subtracting its expected cost to supply the remaining prepaid electricity.
The special IRS rules for advance payments have an interesting history. Section 452 of the US tax code — since repealed — allowed accrual taxpayers to elect to report prepaid income over the period it is earned. The section was enacted as part of the US tax code in 1954, but was retroactively repealed in June 1955 after Congress decided that the revenue loss would be many times greater than what was originally projected by the Treasury Department. The repeal was interpreted by the IRS and the courts as a direction from Congress that deferral of prepaid income would no longer be allowed. Three subsequent Supreme Court decisions during the period 1957 through 1961 — two involving automobile clubs and one a dance studio — confirmed that prepaid income had to be reported by an accrual taxpayer when it is received.
The Supreme Court cases dealt with payments for services, but created uncertainty about the effect of prepayments for goods. Some taxpayers worried that the decisions would require advance payments for goods to be reported immediately as income while the cost of goods sold would not be deductible until a future year.
In 1970, a presidential task force on business taxation recommended that the Treasury use its administrative authority to try to achieve greater conformity between taxable income and book income reported under US generally accepted accounting principles or GAAP. The IRS proposed the special rule for advance payments the same year. In February 1971, the IRS released a technical memorandum responding to comments that had been received from the public about the proposed advance payment rules. The memorandum said the accelerated inclusion rule for inventoriable goods was included “to prevent manipulation (lengthening the deferral period) by failure to deliver goods when the taxpayer has received substantial advance payments and has sufficient goods on hand to satisfy the agreement.” It said abuses of this kind were unlikely to involve goods that are not inventory. Presumably the problem with inventoriable goods is their fungibility invites manipulation by a factory with lots of orders to fill. The regulations were republished in final form the following month.
The reason for waiting to start the two-year clock until advance payments exceed the expected cost to supply the goods is that the tax laws tax income. Until that point, the manufacturer has a loss — not income. After that point, any further payments received are income.
IRS regulations require that the remaining advance payments be reported as income if the company that owns the project “ceases to exist” or if its liability under the power contract otherwise ends. Therefore, the unamortized portion of the prepayment would have to be reported as income if the purchase option is exercised by the utility before the term of the power contract ends. There is also a risk of accelerated reporting if the project company is a partnership for tax purposes and it terminates for tax purposes because of a sale of 50% of more of the profits and capital interests in the partnership.
In order to qualify as an advance payment, the power contract should require that the unamortized portion of the prepayment be returned if the contract terminates due to fault of the project company. The contract should include a schedule showing the quantity of electricity that has been prepaid each year. Because tax deferral is allowed only for advance payments for “goods,” the prepayment should only be for electricity. Any renewable energy credits, environmental allowances or other intangibles that will convey to the utility should be paid for as they are delivered.
The IRS is studying the tax treatment of prepaid forward contracts and may have more to say in the future about the timing for reporting the prepayment. In January 2008, the agency issued a revenue ruling analyzing the tax treatment of a forward contract for which the holder paid $100 on January 1, 2007, at a time when $100 was worth €75, requiring delivery to the holder of €75 plus a return three years later on January 1, 2010. The instrument paid the holder the dollar equivalent of €75 plus a compound stated rate of return, with conversion into dollars occurring at the exchange rate on January 1, 2010. The IRS said the instrument was in substance a euro-denominated loan by the holder to the issuer. The IRS said in a separate notice the same day that it is studying the tax treatment of prepaid forward contracts and it asked for comments on a list of questions, including whether the seller under a prepaid forward contract that is in fact a forward sale, rather than a loan, should be required to accrue income during the term of the forward contract and, if so, how the amount of income each year should be calculated.
Extra care must be taken in most prepaid power contracts to ensure that the contract will be treated by the US tax authorities as a true power contract rather than a lease or installment sale of the power plant or a partnership with the utility. The problem if the contract is not a power contract not only in form, but also in substance, is that tax benefits on the project could be lost to the developer. The US government provides tax subsidies to wind, solar and other renewable energy projects worth at least 56¢ per dollar of capital cost.
The power contract should say the parties intend it to be a “service contract within the meaning of section 7701(e)(3) of the Internal Revenue Code.” It should also be drafted to avoid four “foot faults.”
The four foot faults are as follows. First, neither the utility nor any of its affiliates can operate the project. Second, the utility cannot bear any “significant financial burden” if the project fails to perform (other than for reasons beyond the control of the project owner). This means basically that the utility should not be required to pay for electricity it does not receive. Third, it cannot receive “any significant financial benefit if the operating costs . . . are less than the standards of performance or operation under the contract.” This means the project cannot share any savings it achieves through introduction of technological or operating efficiencies with the utility. Finally, neither the utility nor any of its affiliates can have an option to buy the project at a “fixed and determinable price (other than for fair market value).”
Many US renewable energy projects are financed in the tax equity market. Such projects need to set the option price in practice at market value but not less than the amount the tax equity investor requires to reach its target yield. This may require referring to a termination value schedule. In one transaction with tax equity investors worried about violating the purchase option foot fault, the option for the utility to buy the project at the 10-year point in the contract was structured as an option to buy at fair market value, but the project owner could refuse to sell if market value was not at least the amount required to reach the tax equity yield. In the event of a refusal, the option would roll over to the next year, and so on, until the option either goes unexercised in a year or the market value is the higher of the two amounts. However, this is more complicated than is required. One utility has insisted on symmetry: if the option price has a floor, then it wants a cap. Such a “collar” raises questions whether the price is too close to a fixed price. Tax counsel have gotten comfortable by concluding that the ceiling and floor prices are so far out of the money that neither is expected to come into play in practice. The wider the band is above and below the option price, the better.
Another practical issue in deals is whether any of the operating costs of the project can be passed through to the utility under the contract. A straight pass through of all operating costs raises issues whether the utility will bear a financial burden if the project fails to perform or will benefit if operating costs are reduced. Most tax counsel are fine with a pass through of such things as property taxes and insurance premiums that are not tied to output.
Failure to avoid the foot faults is not the end of the world. Avoiding them ensures that a power contract to sell output from a cogeneration or alternative energy facility will be treated for tax purposes as a power contract rather than a lease of the project to the utility. It may still be possible to prove by other means. However, most tax equity investors prefer to play it safe.
Use of a prepaid power contract will make tax equity more expensive. Tax equity investors have tended to view the prepayment in tax equity transactions structured as partnership flips as equivalent to debt and required a yield premium. The premium runs to 700 basis points in the current market. It was 250 to 300 basis point before the economy crashed in late 2008.