US Tax Laws Change — Again
A massive, 650-page corporate tax bill that the US Congress passed in mid-October before leaving Washington to campaign for reelection has many provisions that will affect the project finance community.
The bill will let US companies with earnings parked in offshore holding companies repatriate the earnings to the US and pay only a 5.25% income tax. The earnings must be brought back in cash and reinvested in the United States. Companies have through the end of the next tax year to take advantage of the provision.
Companies that own existing power plants that burn “biomass” to generate electricity have been given a windfall under the bill. They will be able to claim tax credits of 0.9¢ a kilowatt hour on the electricity they sell during the next five years starting next January 1. The electricity must be sold to a third party. It does not matter how old the power plant is. However, an energy tax credit cannot have already been claimed on the plant, and if any tax-exempt financing was used to pay the capital cost of the plant, there would be a reduction in the amount of the new tax credits. “Biomass” is material that was once living, like wood.
The bill may breathe new life into the domestic synfuel industry. Roughly 53 “coal agglomeration facilities” were built in the mid- to late 1990’s that apply chemicals to raw coal to make a synthetic fuel. Any such facilities that were put into service by June 1998 qualify potentially for tax credits through 2007 of $1.1036 an mmBtu on the synfuel they produce. The bill would allow tax credits of $4.375 a ton to be claimed on output from new synfuel plants put into service between sometime later this month or November when President Bush signs the bill and the end of December 2008. The credits can be claimed for 10 yearsafter the new plant goes into service. Existing coal agglomeration facilities can be rebuilt to qualify for the additional credits. Output from the new plants will have to satisfy a tougher definition of what qualifies as synfuel.
The bill will provide a boost to some power companies that use renewable fuels. Owners of wind farms receive a tax credit currently of 1.8¢ a kilowatt hour on the electricity they produce. The tax savings from this tax credit are equivalent to roughly a third of the capital cost of a typical wind project in present-value terms. Congress added biomass, geothermal energy, sunlight, water in irrigation ditches, landfill gas and municipal solid waste to the list of eligible fuels, but only gave power plant developers intending to use such fuels until the end of next year to get their projects in service. It remains to be seen how many new projects can be built in that time. For example, larger projects that use biomass usually take more than a year to construct. On the other hand, generators that produce electricity from landfill gas can be put into service more quickly.
Utilities have been given a window to shed transmission lines and spread the tax hit — if they dispose of the lines at a gain — over eight years. Any utility that wants to take advantage of this provision must act by the end of 2006.
Congress reduced the US tax rate on domestic “manufacturing” income by 3.15%, but the rate reduction will not be fully phased in until 2010. Congress requires itself to include a “tax complexity analysis” at the back of major tax bills. The analysis included with this measure commented dryly that the rules implementing the lower tax rate for manufacturing income will be “difficult” to draft and will burden “most small businesses” with the need to make complicated calculations. The analysis also noted that Canada had to repeal a similar law after it “led to numerous disputes and litigation between affected taxpayers and the Canadian tax authorities.”
Electricity generation and gas production are defined as “manufacturing,” but transmission and distribution of electricity and gas are not. US companies will have an incentive to treat income as from manufacturing but expenses as tied to other activities in order to use the expenses to offset a higher tax rate.
The bill goes a long way toward fixing a foreign tax credit problem for US multinationals. The United States taxes US companies on worldwide income. It gives them credit, in theory, for any taxes that were paid to other countries on their overseas earnings, but the foreign tax credit rules are so full of fine print that most US utilities and other capitalintensive companies are unable to use foreign tax credits in practice. The fix would not take effect until 2009.
There are other provisions to encourage more use of ethanol and biodiesel as vehicle fuel.
It is not clear, given the growing fiscal problems of the US government, whether some of the provisions that are not scheduled to take effect for several years will be fully implemented. This makes it difficult for companies to plan. The current Congress has not been satisfied with merely cutting taxes beyond what the federal government can currently afford, but it has moved with this bill to put in position further tax cuts five or seven years from now in an effort to bind the hands of future Congresses.
Most US power companies with projects in other countries own them through offshore holding companies in Holland, the Cayman Islands or similar jurisdictions. Income from the projects accumulates in the holding company and is reinvested offshore. This lets the US power company defer US taxes on the offshore earnings until they are brought back to the United States.
The bill lets US companies that repatriate earnings pay tax on them at only a 5.25% rate (or at a 3% rate for companies on the alternative minimum tax). This compares to a normal corporate tax rate of 35%. It is a limited-time offer. The lower tax rate will only apply to earnings that are repatriated during a one-year period. The company must choose either its tax year that straddles the date President Bush signs the bill (expected to be in late October or early November) or its next tax year (for example, 2005).
A company must bring back more earnings than it did on average each year during a “base period” to benefit from the lower rate. The lower rate would only apply to the “excess” repatriation above what the company bought back on average each year during the base period. The base period is the five tax years ending on or before June 30, 2003, but two years are dropped from the calculation: the years in which it repatriated the highest and the lowest amounts. Thus, for example, a company that pays taxes on a calendar-year basis would look at the period 1998 through 2002. It must count as earnings repatriated during the base period not only the cash dividends it received from offshore, but also certain other amounts like distributions of property in kind, distributions of cash that did not have to be reported as dividends because the earnings were taxed in an earlier year, and any “section 956 inclusions.” An example of a “section 956 inclusion” is where a US parent borrowed against cash that was parked in an offshore holding company with the result that it had effective use of the offshore earnings in the US. Such borrowing would have triggered a US tax on the offshore earnings that served as collateral for the loan to the US parent.
Earnings must be brought back in cash to benefit from the lower rate. The low rate would not apply to other types of offshore earnings on which the company might be taxed during the year. An example is passive income — like dividends or interest — earned by its offshore subsidiaries. This passive income is taxed immediately to the US parent under “subpart F” of the US tax code without waiting for the money to be repatriated to the United States.
A company cannot lend its offshore subsidiary money to pay the cash dividends. However, it can borrow from a bank. Any increases in shareholder or other related-party debt of offshore subsidiaries between October 3, 2004 and the end of the tax year in which the lower rate is being claimed are potentially a problem.
The company must reinvest the earnings in the United States “pursuant to” a reinvestment plan. The reinvestment plan must be approved by the company president, CEO or someone comparable before the repatriation occurs and the plan must also eventually be approved by the board or a similar body. The plan must provide for reinvestment of the earnings in the US “including as a source for the funding of worker hiring and training, infrastructure, research and development, capital investments, or the financial stabilization of the corporation for the purpose of job retention or creation.” Congress did not set a time limit on the reinvestment.
A company would not be able to use net operating losses or most tax credits to shelter the earnings from the 5.25% tax. There is a dollar limit of $500 million on the amount of earnings on which the company can pay tax at the special low rate. However, if the company can produce financial statements proving that it has more than $500 million in offshore earnings “permanently reinvested” outside the United States, then its cap is the higher figure.
Power plants that use three types of renewables — wind, “closed-loop” biomass, and poultry waste — qualify currently for section 45 tax credits of 1.8¢ a kilowatt hour for the electricity they produce. The credits run for 10 years from when a plant is originally placed in service. A plant must be put in service by the end of next year to qualify.“Closedloop” biomass is the term for plants that are grown exclusively to be used as fuel in a power facility. Congress envisioned so-called electricity farms when it first enacted the tax incentive in 1992. No power plants that use “closedloop” biomass have been built (at least none with long-term contracts to sell the electricity), according to the Internal Revenue Service.
The bill adds to the list of eligible fuels, and it drops poultry waste as a separate fuel that qualifies in its own right. If power plants using poultry waste are to qualify in the future, it must be as a subcategory of one of the other fuels.
The eligible fuels list now consists of the following: wind, closed-loop biomass, open-loop biomass, geothermal energy, solar energy, water in irrigation ditches and canals, landfill gas and municipal solid waste. Wind and closed-loop biomass projects will continue to qualify for 10 years of tax credits at 1.8¢ a kilowatt hour. This is the tax credit for electricity produced during 2004. The credit is adjusted each year for inflation. Such projects still face a deadline of the end of next year to be put in service.
The definition of what qualifies as a closed-loop biomass plant has been broadened. Existing coal-fired plants that are modified to co-fire with closed-loop biomass will qualify in the future. However, the modification plan must be accepted under the “biomass power rural development programs” or under a pilot program of the US Commodity Credit Corporation to qualify. The 1.8¢ credit would be calculated only on the fraction of the electricity output that is attributable to the biomass. This is done by setting up a ratio of the Btu content of the various fuels that are used to run the plant.
Geothermal and solar projects will qualify for credits of 1.8¢ a kWh, but only for five years.
Projects that use the other fuels — open-loop biomass, irrigation water, landfill gas and municipal solid waste — will qualify for credits of only 0.9¢ a kWh for five years. All credit amounts are adjusted for inflation. Projects that use the newly-eligible fuels must be put in service after President Bush signs the bill (expected in late October or early November) and no later than the end of 2005, with one exception. This does not allow much time. There is the possibility that Congress will extend the deadline again next year. The exception is that existing biomass plants — other than ones that use livestock or poultry manure — will be allowed to claim credits on their electricity sales for five years starting next year.
Credits tied to the newly-eligible fuels can only be claimed on electricity produced after 2004.
Companies on the alternative minimum tax have not been able to use section 45 credits in the past. The bill will let credits on new plants put into service after President Bush signs the bill be used against minimum taxes, but only for the first four years after the power plant is put into service.
Individuals, S corporations and closely-held C corporations also have a hard time using section 45 tax credits because of passive loss rules. This has not changed.
Plant owners who cannot use the tax credits have not been able to transfer them to other companies by using lease financing in the past. That’s because the law has required until now that the person claiming the tax credits must be both the “owner” of the power plant and the “producer” of the electricity. In a lease, the lessor is the owner and the lessee is the producer. However, in the future, lease financing can be used to transfer credits on plants that use open-loop biomass and on coal-fired power plants that cofire with closed-loop biomass.
Three types of matter are included under the heading “open-loop biomass.” One is livestock and poultry manure, and wood chips or other bedding for the disposition of manure. Another is “solid waste material, including waste pallets, crates, dunnage, manufacturing and construction wood wastes (other than pressure-treated, chemicallytreated, or painted wood wastes) and landscape or right-ofway tree trimmings.”The last type of fuel is “agricultural sources, including orchard tree crops, vineyard, grain, legumes, sugar, and other crop by-products or residues.”
Municipal solid waste, landfill gas and paper that is commonly recycled are specifically excluded. “Municipal solid waste,” which also qualifies for credits, includes not only garbage, but also “sludge from a waste treatment plant, water supply treatment plant, or air pollution control” device.
The bill could breathe new life into the domestic synfuel industry Producers of “refined coal” will qualify for tax credits of $4.375 a ton in future on output from new plants put into service starting when President Bush signs the bill through December 2008. This is about a fifth of the section 29 tax credit for which such plants used to qualify. The credits will run for 10 years after a plant is put into service.
“Refined coal” is defined as a “liquid, gaseous, or solid synthetic fuel produced from coal (including lignite) or high carbon fly ash.”The output must differ significantly in chemical composition from the raw coal or fly ash used to produce it in order to qualify as “synthetic fuel.”The bill says in one place that the fuel can be used as a “feedstock,” but suggests elsewhere that credits can only be claimed on fuel sold to someone who is expected to use it to make steam.
The output must have a market value at least 50% higher than the raw coal or fly ash used to produce it. This may be hard to do for a product that is supposed to compete with coal unless plant owners start with feedstocks with low value like fly ash or waste coal in culm or gob piles.
In addition, the output must reduce nitrogen oxide emissions and either sulfur dioxide or mercury emissions by at least 20% compared to the raw coal used to produce it or compared to “comparable coal predominantly available in the marketplace as of January 1, 2003.” Congress did not explain what emissions comparison is to be done when making synfuel from fly ash.
The tax credits can be used by companies that are on the alternative minimum tax — unlike past synfuel credits — but only for the first four years after a plant is put into service. Individuals, S corporations and closely-held C corporations will have a hard time using synfuel credits because of passive loss rules.
The bill will make it easier for electric utilities to shed all or part of their transmission grids. One obstacle to doing this to date has been that the utilities face potentially large tax bills if they have little unrecovered “tax basis” in the grids. In such situations, virtually everything they receive is taxable.
They must act by December 2006.
A utility that sells transmission lines or related equipment by then will have four years to reinvest the sales proceeds in other electric or gas utility property or another power or gas company. For example, the money can be put into power plants, gas wells, gas pipelines, electric transmission or distribution lines, an independent generator, or another utility. It could not be used to pay dividends or buy back stock from shareholders. Money spent on other utility property during the four years by an affiliate of the utility also counts as reinvestment. The utilities appear to have asked Congress to require them to reinvest to stave off directives from public utility commissions to return the money to ratepayers.
If the utility reinvests the full amount within four years, then its gain from the sale of its transmission equipment will be taxed ratably over eight years measured from the date of the original sale. If the utility fails to reinvest the full sales proceeds within that time, then it will be taxed on gain in the year of sale up to the amount it failed to reinvest. For example, if a utility sells a grid for $1,000X in which it has a “tax basis” of $100X, then it has a gain of $900X. If it reinvests all but $100X of the $1,000X in sales proceeds within four years, then it will be taxed in year one on $100X of gain plus a 1/8th share of the remaining $800X in gain. The rest of the gain will be spread over the balance of the next seven years.
The Joint Tax Committee estimated that the provision will be worth $3.9 billion in tax savings to utilities.
The grid must be sold to an “independent transmission company” to qualify for the eight-year spread. Only salesafter President Bush signs the bill qualify. 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 FERC defines it and whose own transmission facilities are placed under operational control of an ISO or RTO before 2007.
Congress reduced the tax rate on domestic manufacturing income by 3.15%, but the reduction will be phased in over time. Congress did not actually change the tax rate, but rather let companies deduct — or avoid paying tax on — as much as 9% of their domestic manufacturing income. With the corporate tax rate at 35%, this equates to a 3.15% reduction in tax rate.
The deduction is phased in. Only 3% of domestic manufacturing income may be deducted in tax years beginning in 2005 and 2006. The figure is 6% in 2007, 2008 and 2009. The full 9% deduction takes effect in 2010. Thus, any company with a November 30 tax year would not get any benefit from the deduction until its tax year that starts December 1, 2005.
The amount of deduction a company is allowed each year is capped. The limit is 50% of the wages reported on Form W2 for the year for its employees.
Domestic manufacturing income is broadly defined. The Senate floor manager of the bill, Senator Charles Grassley (R.-Iowa), grumbled at one point that every industry with a Republican lobbyist managed to have its activities defined as “manufacturing.” Qualifying income includes gross receipts from the “lease, rental, license, sale, exchange, or other disposition” of “tangible personal property,” computer software, sound recordings and films (but not those with explicit sex scenes) “manufactured, produced, grown, or extracted by the taxpayer in whole or in significant part within the United States.”
Electricity, natural gas, or potable water “produced by the taxpayer” in the United States qualify. So do “construction performed in the United States” and “engineering or architectural services performed in the United States for construction projects in the United States.”
Receipts from the transmission or distribution of electricity, gas or water do not qualify. Electricity traders do not have manufacturing income.
The Internal Revenue Service has been left to sort out the details, including how to allocate expenses among the various types of income and how to determine whether products that are assembled in the US out of parts made abroad or vice versa are US made. It is expected to have a difficult time.
Foreign Tax Credits
Most US utilities and other companies in heavy industries have a hard time using foreign tax credits. They are supposed to receive credit for taxes already paid abroad when calculating US taxes on their foreign earnings, but the fine print in the foreign tax credit rules is a problem. The main impediment is interest allocation. A company may think it earned $100X from its operations in Brazil. However, IRS regulations require the company to treat part of the interest it pays on its US borrowings as a cost of its foreign operations on the theory that money is fungible. Part of its domestic interest expense must be allocated to foreign operations in the same ratio as its assets are deployed in the US and abroad. By the time this occurs, the $100X from Brazil may be only $1X. Foreign tax credits can only be claimed in the United States in an amount equal to the US tax rate times the foreign source earnings — in this case, 35% times $1X, or 35¢, even though the company paid taxes in Brazil — and will be taxed in the United States — on $100X in earnings.
Another impediment is foreign earnings are put in 13 different “baskets.” Credits from one basket cannot be used to offset US taxes on income in another basket.
The bill reduces the number of foreign tax credit baskets to two — passive income and other, or “general limitation,” income — but not until tax years beginning after 2006.
It addresses the interest allocation problem by letting companies opt for a different formula for calculating the amount of domestic interest expense that is allocated to foreign operations.
The new formula should reduce the amount of interest allocated abroad in most cases. However, it is not as favorable a formula to the independent power industry as one that Congress passed in an earlier tax bill that President Clinton vetoed in 1999.
The new formula can be used in tax years beginning after 2008. Companies have that year to decide whether to switch to the new formula. Whatever they decide binds them for future years.
Congress called the new formula “worldwide fungibility,” but this is misleading. The formula merely reduces the amount of domestic interest expense that will be allocated abroad. In some cases, it reduces it to zero.
Under the new formula, a company starts with the interest expense of its “worldwide affiliated group,” defined as the interest expense for the year for itself and all its subsidiaries — both in the US and abroad — that are at least 80% owned by vote and value. It then multiplies this figure by the percentage of that group’s total assets that are outside the US. It then subtracts the portion of the interest expense of the offshore members of the group that would be allocated to foreign operations if those foreign members were a standalone operation.
Thus, for example, suppose a US power company and its US subsidiaries have domestic interest expense of $100X. Foreign interest expense of 80%-owned subsidiaries is $25X. Six percent of total assets are outside the US. The amount of domestic interest expense that would be allocated abroad under current law is $100X x 6% = $6X. However, under the new formula, it would be ($125X x 6%) - $25X = $0. (In fact, this equals -$17.5X, but the result cannot be less than zero.) The reduction part of the equation acts as a cap on the amount of domestic interest expense that will be allocated abroad. Mathematically, as long as foreign operations bear at least as heavy interest payment obligations (to unrelated lenders) on a proportionate basis as domestic operations, then there should be no allocation of domestic interest expense. It is only when foreign operations are less heavily debt financed that one gets an allocation of domestic interest expense.
The new provision is not as favorable to the independent power industry as one passed in 1999. The earlier provision would have let US companies take some US debt out of the calculation altogether. A company could have elected to treat any domestic subsidiary in the US whose debts are not “guaranteed (or otherwise supported)” by a related company as essentially a standalone enterprise. This could have helped independent power companies because they might have been able to ignore borrowing by special-purpose subsidiaries that use nonrecourse project financing to finance standalone projects.
The US government uses the tax laws currently in two ways to create a market for ethanol, a form of alcohol made from corn or other grains.
The first way is through a series of income tax credits. Companies that blend ethanol with gasoline are given a tax credit of 52¢ a gallon for the ethanol they use in such blending, provided the ethanol is at least 190 proof. (A smaller tax credit is allowed for ethanol of between 150 and 190 proof. There is no credit for using weaker alcohol.) A tax credit in the same amount can also be claimed by anyone who does not blend the ethanol with gasoline, but rather sells the ethanol directly at retail to consumers who will use it as fuel. Finally, small ethanol producers are allowed a tax credit of 10¢ a gallon for the ethanol they produce. This credit can only be claimed on 15 million of gallons of ethanol a year. A “small” producer is a company with a production capacity of no more than 30 million gallons a year.
The 52¢-figure for the credit is scheduled to drop to 51¢ in 2005.
These tax credits are not as valuable as they appear at first glance. Companies must add the dollar amount of the credits they claim to their taxable incomes.
The other way the US government encourages use of ethanol is by charging a lower excise tax on gasoline that is blended with ethanol. The federal gasoline excise tax is currently 18.3¢ a gallon. Blenders can forego the 52¢-a-gallon alcohol fuels credit and pay, instead, a reduced rate of excise tax on the blended fuel they produce — so-called gasohol. Gasohol that contains 10% ethanol is subject to excise tax at only 13.1¢ a gallon. Gasohol with less ethanol is taxed at higher rates. Most blenders choose the lower excise tax rather than the alcohol fuels credit.
The bill makes four changes.
It extends the alcohol fuels credits through 2010. The credits had been scheduled to expire at the end of 2007.
It also lets such credits be used for the first time by companies that are on the alternative minimum tax. This would be allowed starting in 2005.
It eliminates the lower excise tax for gasoline. The full excise tax will have to be paid in future in theory on gasohol, but blenders will have the choice of claiming a credit against the excise taxes of 51¢ per gallon of ethanol they use in making gasohol. The ethanol must be at least 190 proof. As before, a blender will have to choose either a savings on excise taxes or on his income taxes (by taking the alcohol fuels credit).
Finally, the bill also gives an excise tax credit for blenders who mix “biodiesel,” a mixture of diesel fuel with vegetable oil made from such things as soybeans, canola, coconut or hemp or with recycled cooking oil from restaurant kitchens. The biodiesel credit is 50¢ per gallon of vegetable or cooking oil used in producing the fuel. It increases to $1 a gallon if the oil is “agri-biodiesel.”The current federal excise tax on diesel fuel — that would be offset by means of the credit — is 24.3¢ a gallon.
The new biodiesel credit can only be claimed on sales of biodiesel during 2005 and 2006. Ethanol blenders will get the benefit of their excise tax credit through 2010.
Congress reduced the tax benefits that a US lessor can claim on property that it leases to a foreign entity or to a US taxexempt entity, government agency or Indian tribe. Any property that was leased at any time in the past to such a lessee also remains tainted. The changes are retroactive, and the announcement earlier in the year they were coming had already put a halt to a booming business in lease financing for municipal assets in the US and for electric and gas distribution systems, sewage systems, railroad cars and track and other assets in foreign countries, principally in Europe.
Lessors claim tax depreciation on their assets. That depreciation is less valuable in cases where the assets are leased to a “tax-exempt entity,” defined broadly to include government agencies, universities and other tax-exempt organizations, and foreign entities that are not subject to US income taxes. In such cases, the assets must be depreciated on a straight-line basis over the “class life” or over 125% of the lease term, whichever is longer.
The bill changes current law in three important ways. First,“lease term” has now been defined to include the term of any “service contract or similar arrangement” that the lessor enters into when the lease ends. An example is where a US institutional equity leases a power plant to a European utility and requires that the utility enter into or arrange for a follow-on power purchase agreement at the end of the lease term.
Second, certain high-technology computer-based equipment — like telephone switches — and software that could be written off in the past over three or five years is now subject to the 125%-of-lease-term override where the lessee is a tax-exempt entity.
Third, the bill bars US lessors from using depreciation and interest deductions from leasing transactions with entities that are not subject to US income taxes to shelter income from other sources if certain features are present in the lease like too much defeased debt or a fixed-price purchase option. Rather, they must carry any such losses forward to wait until income is generated in future years from such leases. This restriction is applied to each lease separately. Thus, losses from one leasing transaction cannot be used to shelter income from another such transaction. This rule also applies to depreciation and interest deductions tied to property that was once used under a tax-exempt lease. Such property remains tainted.
The new rules apply to leases entered into after March 12, 2004, with two exceptions. They apply to leases entered into with Indian tribes after October 3, 2004, and certain domestic rail leases in the United States are “grandfathered.” Amending an existing lease may bring it under the new rules if the amendments are considered substantial.
Transactions with Coops
Congress opened the door to certain types of transactions that the rest of the power industry has been hoping to do with electric coops. At the same time, it also gave coops the ability to expand their reach by making electricity sales to persons who are not members to order to make up for the loss of members. This last item is a carrot to encourage coops to open their grids to other power suppliers. However, the changes in law are temporary, making them of limited value until the next Congress decides whether to extend them. They only apply through the end of 2006.
A coop must be careful to ensure that at least 85% of its income each year is receipts from members “for the sole purpose” of meeting expenses.
Congress directed that coops be allowed to ignore several types of income in future when doing this 85% calculation. One such type is wheeling charges that the coop collects from others for moving electricity across its transmission or distribution lines, but only — in the case of transmission — if the wheeling services are provided on a nondiscriminatory basis under an open access transmission tariff or independent transmission provider agreement “approved or accepted” by the Federal Energy Regulatory Commission. Another type of income the coop can ignore is gain from the transfer of the coop’s interest in any nuclear decom missioning fund. This should make it easier for coops to shed their interests in nuclear power plants. Finally, coops will be allowed to enter into like-kind exchanges of assets — for example, a swap of one power plant for another power plant — without affecting the 85% calculation.
The bill also allows coops to enter into “load loss transactions” in the future. These are wholesale or retail sales of electricity to persons who are not coop members. Income from such sales will be counted as good income toward the 85% test. Only coops who offer nondiscriminatory open access to their systems will be allowed to do this. There is a limit on the amount of electricity that such a coop can sell to nonmembers. The limit is the amount of its “load loss,” calculated by adding up the shortfall in sales to its members each year over a seven-year period compared to a base year. The seven-year period starts with 2004 or, if later, the first year the coop offers nondiscriminatory open access.