A POWER CONTRACT ruling is withdrawn.

The Internal Revenue Service notified the taxpayer that it is withdrawing a private ruling it issued earlier this year that said a company buying an operating wind farm did not have to allocate part of the purchase price to a long-term power contract that came with the project. The power contract required the electricity sold under it come from the particular wind farm. The ruling analogized the situation to where someone buys a building in which tenants have leased office space. Part of the purchase price does not have to be allocated to the leases. Instead, the building comes subject to the leases; the leases are a burden on ownership. The purchase price is treated as a cost of the building.

An IRS branch chief said last April shortly after the PPA ruling was made public: “We have a saying [at the IRS] that you know you issued a bad ruling if 70 people ask you for a copy the next day.”

Before the ruling, most companies would have allocated value to the power contract to the extent it is “in the money,” meaning the contact entitles the holder to a higher electricity price than he can fetch currently in the market.

CALIFORNIA explained further in early September in what circumstances it will treat the transfer of an interest in a solar project as a trigger to start collecting property taxes on the project.

Solar generating equipment is effectively exempted from annual property taxes in California, but it becomes subject to such taxes if there is a sale of the project or change in control of the project company that owns the project after construction. Property tax rates vary by county. They can be as high as 2% of assessed value.

The State Board of Equalization proposed revisions to the property tax assessor’s manual and released a separate opinion letter on September 5 in response to questions from solar companies.

The assessor’s manual would say the following.

The sale of a solar project or an interest in the company that owns the project during construction will not trigger property taxes. Entering into a tax equity transaction structured as a sale-leaseback within three months after the project is first placed in service or a partnership flip will not trigger property taxes. There is no deadline to enter into the partnership flip transaction. (An inverted lease does not trigger property taxes because it is not a sale of the project.)

However, property taxes will be triggered when a developer who has sold and leased back his project exercises an option to repurchase the project. There is a risk that the “flip” in a partnership flip transaction will trigger such taxes. However, a board official said that was not the intention and said the language will be fixed.

The opinion letter clarifies how to determine whether there has been a change of control in situations where a project is owned through tiers of partnerships and a partner in an upper-tier partnership sells his interest. The letter says one should multiply the ownership interest that someone is acquiring by the percentage interest each partnership owns in the partnership below it down the ownership chain. Thus, for example, if D acquires a 10% interest in a partnership that owns 50% of another partnership that owns the solar project, then D acquired 10% x 50% = 5% of the partnership that owns the project. If D did not already own a large enough interest that, when combined with the additional 5% would increase its interest to more than 50%, then there is no change in control.

The board plans to use the same approach to determine whether there has been an indirect change in control of a corporation.

The board’s guidance is not binding on local assessors who administer the property tax. The board is taking comments on the latest draft until September 25.

In a separate development, some California cities and counties are trying to collect real estate transfer taxes when a single-member limited liability company that owns real estate is transferred.

The tax at the county level is 55¢ per every $500 in value, and cities within counties may impose an additional tax at half the county rate. The tax is triggered by recording an instrument transferring ownership of real estate. When an LLC is sold, nothing is recorded.

San Francisco amended its transfer tax ordinance in 2008 to require taxes to be paid after a sale of more than a 50% ownership interest in a single-member LLC that owns real estate despite the fact that no transfer instrument is recorded. (The sale will also trigger a reassessment for annual property tax purposes.) Los Angeles County has not amended its ordinance, but the county recorder interprets the existing ordinance to require a transfer tax to be paid when a controlling interest is transferred in a legal entity that owns real estate. The recorder says state law gives the county the right to collect taxes in such cases.

A TAX EQUITY TRANSACTION with aggressive features was struck down by a US appeals court in August.

The decision calls into question whether a “fixed-flip partnership” structure that has been used to finance some wind and solar projects works, at least in its earliest form.

The decision may also require rethinking of some “pay-go” structures where tax equity investors pay for tax credits as the credits are received.

The case is called Historic Boardwalk Hall LLC v. Commissioner.

The New Jersey Sports and Exposition Authority, or NJSEA, took on renovation of a sports arena and hall called East Hall in Atlantic City that was originally built in the late 1920’s and was the site of the Miss America pageant starting in 1933. The renovation work began in 1998. The state issued $49.5 million in bonds and used another $22 million from the New Jersey Casino Reinvestment Development Authority to fund the work.

Since East Hall is listed as a national historic landmark by the US government, the work qualified potentially for tax credits for 20% of the cost. The tax credits are claimed in the year the renovation work is completed. The state was not in a position to use the tax credits, so it essentially bartered them for capital to help fund the project in a tax equity transaction.

The transaction was complicated. NJSEA first leased East Hall from the Atlantic County Improvement Authority for 87 years at $1 a year. NJSEA then subleased East Hall to a partnership in which NJSEA retained a 0.1% interest. The partnership allocated 99.9% of depreciation and tax credits to Pitney Bowes. Pitney Bowes was also entitled to annual preferred cash distributions of 3% of the capital it contributed for an interest in the partnership. NJSEA had a call option to repurchase the Pitney Bowes interest after five years for the market value of the interest, but not less than any part of the 3% preferred cash return that Pitney Bowes had failed to receive. Pitney Bowes had a “put” to force NJSEA to buy the interest after seven years at the same price that NJSEA would have had to pay under the call option. (The options were never exercised.)

Pitney Bowes made capital contributions for its interest in the partnership. The first capital contribution, shortly before renovation was completed, was just $650,000. It contributed roughly another $19 million in three installments later as tax credits were received.

The partnership guaranteed Pitney Bowes that it would receive the expected tax benefits. NJSEA guaranteed Pitney Bowes that it would cover any cost overruns or operating cost deficits on the project.

NJSEA described the transaction as a “sale of historic tax credits” in the offering materials and other documents while marketing the transaction. The court said Pitney Bowes was not a real partner and was just attempting to buy tax benefits.

A partnership requires an intention to join together for the purpose of sharing in the profits and losses of a genuine business. Pitney Bowes was not exposed to operating losses because of the NJSEA guarantees. The court said it had no meaningful downside risk: it was not required to make its capital contributions, after the first $650,000, until after it had verified the amount of tax credits it was being allocated for each period. It was assured of receiving the tax benefits because of the tax indemnity. The tax benefits were not even at risk from the possibility the project might not be completed because the project was essentially fully funded by NJSEA before Pitney Bowes invested. Its capital contribution went to pay a developer fee to NJSEA and buy a guaranteed investment contract from an insurance company to ensure money would be available to buy out Pitney Bowes after the tax credit recapture period.

The court said that any upside potential for Pitney Bowes was illusory. In theory, the company could continue to share in cash, but in practice, the court said, the partnership was expected to lose money and avoided a write down of its assets only after persuading its accountants that the state would make good on the losses.

This is the second tax equity transaction involving tax credits for historic renovations with which the courts have found fault in a little over a year. A different US appeals court rejected a transaction in a case called Virginia Historic Tax Credit Fund 2001 LP et al v. Commissioner in 2011. (For earlier coverage, see the June 2011 NewsWire starting at page 29.)

GILLETTE opened the door to possible refund claims for companies operating in multiple US states.

Each US state taxes income earned in the state. Because the states have different approaches to determining how much income a large company operating nationally earned in each, there is the potential for double taxation. A House subcommittee recommended in 1965 that Congress impose a uniform apportionment regime on the states. State tax administrators from nine states drafted a multistate tax compact in 1967 in an effort to avoid federal action. The multistate compact adopts a three-factor formula in which a company apportions income to the state based on the share of the company’s total property, payroll and sales in the state. The three factors are given equal weight.

California adopted the multistate compact in 1974. However, in 1993, its changed its law to require double weighting be given to the sales factor.

Gillette and five other companies sued the state for $34 million in refunds in 2010 arguing that they are entitled by law to use the formula in the multistate tax compact. A California appeals court agreed in a decision on July 24.

The court announced on August 9 that it would reconsider the decision. Estimates of the potential cost of the decision to California vary, but start at $100 million a year. The decision is expected to be appealed to the California Supreme Court and possibly ultimately to the US Supreme Court.

The state enacted a bill in July, shortly before the appeals court released its decision, withdrawing from the multistate compact and barring refund claims unless a company elected use of the apportionment formula in the multistate compact when it filed its tax return.

Refund claims are now expected in other states.

Fourteen of 20 states that belong to the multistate compact have moved away from the three-factor formula.

A majority of state tax advisers listening to a recent webinar on the subject said they are likely to advise their companies to pursue refund claims; 87% of participants said they would advise pursuing such claims in California and 78% said they would advise making claims in other states.

A LARGE SALES TAX ended up having to be paid on construction of an ethanol plant in Nebraska, but it could have been avoided if the construction contract had been drafted differently.

Bridgeport Ethanol paid a contractor $67 million to build an ethanol plant. Nebraska, like many states, exempts equipment purchased by a manufacturer for use in manufacturing from sales and use taxes. Unfortunately, the contractor in this case bought the building materials and then conveyed the completed plant to Bridgeport. The contractor is not the manufacturer. The contractor elected to be taxed as the consumer of the building materials, triggering a tax at the contractor level rather than on the higher price for the completed plant.

The Nebraska Supreme Court said in August that the ethanol company was out of luck. It rejected the company’s claim that the contactor was merely its purchasing agent. The statutory authorization for appointment of a purchasing agent is only available to non-profit organizations and schools. It did not matter, the court said, that Bridgeport had a duty to reimburse the contractor for the taxes the contractor paid.

The case is Bridgeport Ethanol LLC v. Nebraska Department of Revenue. The court released its decision on August 10.


The structure let Scottish Power “strip” earnings from its US subsidiary, PacifiCorp, during the period 2000 through 2002 by pulling the earnings out of the United States as interest on shareholder capital put in as debt and deduct the interest on the debt in both the United States and the United Kingdom. The company unwound the structure in late 2002 partly in response to a change in US tax regulations that would have caused the interest to be treated as dividends.

Scottish Power acquired PacifiCorp, a US utility, by setting up a chain of three entities and merging the bottom-tier entity into PacifiCorp with PacifiCorp as the surviving company. The PacifiCorp shareholders received $6.9 billion in Scottish Power stock and ADRs traded on the New York Stock Exchange.

The chain of three entities had at the top two wholly-owned UK subsidiaries, NA1 and NA2. Next down the chain was a Nevada general partnership called NAGP that Scottish Power elected to treat as a corporation for US tax purposes but that was viewed as a pass-through entity for tax purposes in the UK.

Immediately below NAGP was a US acquisition company that merged into PacifiCorp.

Scottish Power capitalized NAGP largely with debt. It made two loans for $4.9 billion to NAGP that NAGP used to acquire 75% of the Scottish Power shares used in the merger. The remaining 25% of the shares essentially came down the ownership chain as capital contributions (equity).

The debt was a $4 billion fixed-rate loan at 7.3% interest for a term of 12 years, and a floatingrate loan of $892 million at LIBOR plus 55 basis points for a term of 15 years. Both loans required quarterly payments of interest.

NAGP fell behind immediately and struggled to make interest payments because dividends from PacifiCorp to NAGP fell short of what was needed. Scottish Power converted the floatingrate debt into equity in NAGP in early 2002 after being advised by PricewaterhouseCoopers that it would be hard to support characterization of more than the $4 billion in fixed-rate notes as debt. It converted the fixed-rate debt into equity at the end of 2002.

In 2006, the IRS instructed its agents to challenge use of cross-border hybrid arrangements as a tier I enforcement issue. The IRS challenged $932 million in interest deductions claimed by the consolidated group of NAGP and PacifiCorp in the United States on grounds that the “debt” was in reality equity from the start.

The US Tax Court said in June that the loans in this case were real debt. The companies treated them as such for purposes of securities and other filings. The court reviewed a list of 11 factors that the US appeals court for the 9th circuit — which is where the case will be heard if it is appealed — uses to distinguish debt from equity. It said only one of the factors pointed to equity in the case of the fixed-rate debt and two for the floating- rate debt.

The case is NA General Partnership v. Commissioner. It is the first of a series of cases waiting for court dates involving billions of dollars in interest deductions. The US government has until at least mid-September to appeal.

SOUTH AFRICA is expected to see a significant number of renewable energy projects under its so-called REFIT program reach financial close shortly.

The program seeks to procure 18,000 megawatts of renewable energy over the next 20 years.

The first phase of the program to procure 3,725 megawatts by 2016 launched in August 2011. There are five “bidding rounds” in the first phase staggered from November 4, 2011 to August 13, 2013.

The program has attracted keen interest from developers, investors and engineering, procurement and construction contractors from across the globe, including the US, Germany, Italy, Spain, France, China and India.

Bids for 53 projects amounting to 2,128 megawatts were received by the Department of Energy in round 1. Of these, 28 bids, representing 1,416 megawatts, were selected as preferred bidders. These are made up of 18 solar photovoltaic projects, representing 631 megawatts, two concentrated solar power projects, with a combined capacity of 150 megawatts, and eight wind farms, representing 633 megawatts.

Financial close for these projects had originally been scheduled to occur by June 19, 2012 before the Department of Energy extended the date to the end of July. This date was then postponed by the Department of Energy citing the finalization of internal and regulatory approvals by various counterparties. Subsequently, the Department of Energy indicated that it would be sending requests to bidders for an extension of the bidding period beyond the August 31, 2012 bid validation period, effectively putting the market on notice that the financial-close period could extend beyond that date. Despite these delays, it is widely expected that the process for closing the first of the round 1 projects will commence soon.

Seventy-nine bids for 3,200 megawatts of capacity were submitted for round 2. Following the round 2 evaluation, 19 additional projects representing 1,043 megawatts have also been named as preferred bidders. These projects are made up of nine solar projects with a combined capacity of 417 megawatts, seven wind farms representing 562 megawatts and one 50-megawatt concentrated solar project. These projects are required to achieve financial close by December 13, 2012. Although the official line is that this deadline will be maintained, a delay is widely expected due to the delay in closing round 1 projects.

The round 2 projects were characterized by a significant reduction in bid tariffs compared to round 1. This was most notable among the solar photovoltaic projects, highlighting the extent to which the round 1 projects had benefited from the above-market tariffs under the program. Average prices of solar photovoltaic projects fell from 2.75¢ per kWh (SA rand) in round 1 to 1.65¢ per kWh (SA rand) in round 2.

The next round of bidding is currently scheduled for October 1, 2012, although once again it is widely expected that this date will slip.

Some 1,300 megawatts of capacity remain available for allocation under the first phase of the program, although Energy Minister Dipuo Peters recently announced that she would be issuing a further declaration “soon” extending the amount of capacity to be procured in the first phase beyond the 3,725 megawatts already in process.

THE US DEPARTMENT OF JUSTICE is expected to issue new guidance on the Foreign Corrupt Practices Act by October.

The Foreign Corrupt Practices Act makes it a crime for US citizens and companies to offer anything of value to a foreign official or official of an international public organization in an effort to win or retain business or secure any improper advantage. Foreign companies that raise equity in US capital markets are also subject to the statute.

The guidance is expected to address who is considered a “foreign official.” A US appeals court is considering whether employees of the government-owned telephone company in Haiti are foreign officials in a closelywatched case called United States v. Esquenzai. Two Terra Telecommunications Corp. executives were given long prison sentences — 15 years for the company president and seven years for a company vice president — for participating in a scheme to bribe Haiti Telco employees. As many as 60% of FCPA enforcement actions are based on the position that government-owned enterprises are instrumentalities of the government.

The US Chamber of Commerce has also been lobbying for an affirmative defense for companies with strong compliance programs.

PROJECTS ON US INDIAN RESERVATIONS qualify potentially for tax-exempt financing using “tribal economic development bonds.”

Congress authorized $2 billion in such bonds as part of the broader economic stimulus measures that were enacted at the start of the Obama administration in February 2009. The IRS allocated all $2 billion in bond authority in 2009 and 2010, with a deadline for the tribes receiving the authority to issue the bonds by the end of 2010. The IRS extended the deadline three times through March 2012. To date, only $197.2 million in bonds have been issued.

The IRS said in a notice in July that the remaining $1.8 billion in authority will be reallocated. There is no deadline to apply. The agency said it will consider requests for the bond authority on a rolling basis. The instructions for applying are in Notice 2012-48.

ADVANCED COAL power plants and gasification projects can apply for $685.5 million in federal tax credits.

Applications are due at the US Department of Energy by October 15, 2012 and at the IRS by February 15, 2013. The applications are submitted in two parts. The credits are 30% of the project cost. They are credits that were forfeited by developers after being originally allocated them as part of $1.3 billion in allocations in 2006 through 2009. The credits can be claimed on new IGCC (integrated-gasification combined-cycle) power plants and other power projects that use “advanced” technology to generate electricity from coal. At least 75% of the fuel used in the plant must be coal. The project must be placed in service within five years after credits are awarded. Projects receiving awards will be notified by May 15, 2013. Details are in Notice 2012-51.

BRAZIL said in June that it will limit collection of a 6% financial transactions tax, called the IOF, to loans of up to two years. Brazil increased the tax rate from 0.38% to 6% and extended the tax to loans of up to five years in March in an effort to discourage short-term dollar inflows that were hurting exports by causing the real to appreciate against the dollar. The government reversed course three months later after deciding it was more important to make it easier for Brazilian companies to borrow from foreign banks. The European financial crisis has caused a number of banks to withdraw from the market.

Meanwhile, BNDES, the Brazilian development bank, has suspended loans to purchase wind turbines that do not meet domestic content requirements. Turbines made in Brazil do not qualify for BNDES financing unless at least 40% of the components are made in Brazil.

ARGENTINA said in July that it is terminating its tax treaty with Spain effective at year end. It announced earlier in the year that it is terminating tax treaties with Chile, Austria and Switzerland. It said it hopes to negotiate new agreements that prevent companies from taking advantage of “loopholes” in the treaties.

MAURITIUS remains under pressure from India to modify a tax treaty between the two countries. The treaty lets Mauritius companies holding shares in Indian companies avoid capital taxes when the shares are sold.

The two governments held bilateral talks again in late August on revising the treaty. India wants Mauritius companies to have more substance in order to benefit from the treaty.

The uncertainty is harming the economies of both countries, the Mauritius finance minister said. Forty-two percent of investment into India during the period 2000 through 2011 went through Mauritius companies. The trade in offshore companies accounts for 5% of gross domestic product in Mauritius. India is particularly upset about “round tripping” where Indian residents circle investments in Indian companies through Mauritius to avoid capital gains taxes upon exit.

The Authority for Advance Rulings in India continues to respect the treaty in the meantime. It held in at least three cases in July and August that Mauritius companies could not be taxed on capital gains. The tribunal said that it did not matter that the capital gains will go untaxed in Mauritius.

Mauritius is targeting new business with Africa, where it has double taxation treaties with Botswana, Lesotho, Madagascar, Mozambique, Namibia, Rwanda, Senegal, Seychelles, South Africa, Swaziland, Tunisia, Uganda and Zimbabwe. Treaties with the Congo and Zambia are awaiting ratification, and treaties with Egypt, Ghana, Kenya, Malawi and Nigeria are awaiting signatures.

Meanwhile, China rejected a claim by a Chinese foreign joint venture that dividends paid to a joint venture partner in Mauritius qualify for a reduced withholding tax rate of 5% under the Mauritius-China tax treaty. (Chinese withholding taxes on dividends are normally 10%.) The authorities concluded that the Mauritius company was merely a front for the real investor in another country because it had no employees, carried out no real business in Mauritius and had only $9.81 million in registered capital but invested $150 million in the joint venture, and only two of seven board members were domiciled in Mauritius.

A TAX OPINION cannot be relied on to avoid IRS penalties if the lawyer writing the opinion helped promote the transaction and receives fees that are tied to the tax benefits produced. The conflict of interest makes the opinion unreliable, the US Tax Court said in SAS Investment Partners v. Commissioner in June.

FOREIGN TAX CREDITS may soon be at issue in a case before the US Supreme Court.

PPL Corporation, the parent company of a Pennsylvania utility, asked the court in August to hear an appeal of whether the utility could claim windfall profits taxes it paid in the United Kingdom, after buying a privatized regional electric utility, as a credit against its income tax liability in the United States. The US allows foreign taxes to be credited, but only if they are income taxes in a US sense. The IRS has argued that the taxes are not creditable based on a reading of the UK statute. The IRS won on appeal in its dispute over the taxes with PPL Corporation, but lost in a similar case involving US utility Entergy, which had to pay windfall profits taxes on its shareholding in London Electricity. Both taxpayers won in the US Tax Court, but the cases were appealed to appeals courts in different parts of the United States based on where the taxpayers are located.

PPL argues that the IRS should look at the underlying substance of the UK tax rather than focus narrowly on the words in the UK windfall profits tax statute.

The British government collected a one-time tax on the “windfall profits” that the owners of the privatized utilities earned due to the initial bump up in share prices after privatization. The tax had to be paid in two installments in 1997 and 1998. The tax was 23% of the appreciation in value of each utility since privatization. The appreciation was calculated by comparing the amount paid for the shares at privatization to the company’s “value . . . in profit making terms” in 1997. This was defined as nine times the company’s average annual after-tax profits in the four years immediately following privatization.

Only “income taxes” may be credited. The IRS argues that the UK windfall profit tax fails because it was a tax on hypothetical appreciation in value of the regional utilities — rather than on actual gains — and the British government did not wait to collect the levy until the shareholders “realized” their gains by selling shares.

CARBON CREDITS did not have to be reported as income by a US real estate investment trust.

The REIT invests in timberland. Some of its investments are in a foreign country. It holds these investments through an offshore holding company. The country awarded carbon credits for owning forests that serve as a “sink” for absorbing carbon dioxide. The IRS said in a private letter ruling made public in July that a company receiving carbon credits from a government does not have to report the value as income upon receipt.

A later sale of the credits would trigger income. However, any sales proceeds in this case would not have to be reported in the US until the earnings are repatriated. The agency said they are not considered a form of passive income — called “subpart F income” — that the US would look through the holding company and tax without waiting for the income to come back to the United States.

The ruling is Private Letter Ruling 201228020.

DEVELOPERS who receive interests in projects in exchange for ongoing services should consider making a section 83(b) election to pay taxes on the interest upon receipt rather than waiting for it to vest fully.

Most power projects in the United States are owned by limited liability companies that are treated as partnerships for US tax purposes.

There are two kinds of partnership interests. A developer could receive an interest solely in partnership profits, or it could receive a capital interest that entitles the developer to a share of the asset value when the partnership liquidates. A developer receiving a capital interest in exchange for services must report the value as income after subtracting anything the developer had to pay for the interest. The interest is compensation for the services.

However, value does not have to be reported until there is nothing else he must do to earn it or, if earlier, when the developer first has a right to transfer the interest. The IRS allows the developer to choose to pay taxes upon receipt instead. This might make sense if the interest has a low current value but the value is expected to increase over time — for example, as construction of the project is completed. The developer can do this by filing a section 83(b) election with the IRS within 30 days after receipt of the interest.

The IRS released sample language for making such elections in late June. The language is in Revenue Procedure 2012-29. The election can only be made for interests that have a readily ascertainable market value.

The downside is that if the developer ends up reporting the value of an interest that never vests — for example, because the developer failed to do the full work required to earn it — then he has a capital loss, but only for any amount he paid for the interest and not for the full income he had to report.

A MANAGEMENT CONTRACT for a private company to operate the portion of the electricity grid belonging to a municipal utility will not cause loss of the tax exemption on debt the utility used to finance the equipment, the IRS said.

Municipalities can issue tax-exempt bonds to finance schools, roads, hospitals and other public facilities. The bonds allow borrowing at a reduced interest rate because the bondholders do not have to pay federal income taxes on the interest. However, a municipality must be careful not to allow more than 10% “private business use” of property financed with the bonds or the tax exemption may be lost.

It is potentially private business use to hire a private company to operate the grid. The IRS issued guidelines in 1997 for municipalities to follow in drafting management contracts with private parties. A contract involving public utility property cannot run longer than 20 years or, if shorter, 80% of the expected useful life of the equipment. At least 80% of the services in each contract year must be compensated on a fixed-fee basis. No part of the fee can be tied to operating profits. A contract that merely passes through actual and direct costs of the contractor and reasonable administrative overhead is not a problem. The manager cannot have a relationship with the municipality that substantially limits the municipality’s ability to exercise its contract rights.

The IRS approved a proposed arrangement to manage a municipal electricity grid that departed from these guidelines in a private ruling that the agency made public in July. The ruling is Private Letter Ruling 201228029.

The contract had a term of 10 years. The municipal utility agreed to pay the grid manager periodic fixed payments, plus incentive payments that were tied to four performance metrics, plus reimburse the manager for its actual costs.

The contract raised issues because the “fixed” fee was not really fixed. It was subject to downward adjustment to the extent the manager failed to provide credit support or performed poorly. The manager could receive additional incentive payments tied to performance metrics. It could pass through charges from affiliates with a mark up at a rate of return approved by the Federal Energy Regulatory Commission.

The IRS said none of these features is a problem because none of them is tied to operating profits.

BARGE-MOUNTED POWER PLANTS are probably not “vessels” for tax purposes.

The IRS concluded that a floating casino was not a “vessel” in an internal legal memorandum that the agency made public in June. A vessel can be depreciated on an accelerated basis over 10 years. The IRS said the casino was essentially a building and had to be depreciated on a straight-line basis over 39 years. The most salient fact was that the US Coast Guard did not recognize it as a ship. The boat had hydraulic mooring claws holding it to land and was attached to land-based utilities through a series of wires, lines, cables and hoses. The Coast Guard said this meant it was “neither used nor practically capable of being used as transportation on water.”

The IRS memo is CCA 201225012.

MINOR MEMOS. A US carbon tax of $20 a ton would raise $1.5 trillion over the next 10 years, according to a study released in August by the Massachusetts Institute of Technology. The study assumed the tax would start in 2013 and increase in amount by 4% a year . . . . President Obama issued an executive order on August 30 setting a goal of installing another 40,000 megawatts of cogeneration facilities at industrial sites by 2020. A cogeneration facility is a power plant that produces two usable forms of energy — for example, steam and electricity — from a single fuel. The order directs various federal agencies to work on eliminating barriers to installation of such facilities, including through use of set asides under emissions trading programs, grants and loans and use of “output based approaches” to regulating pollution that recognize the emissions benefits of moving to cogeneration . . . . IRS statistics confirm a trend toward greater use of passthrough entities. The IRS large business and international division has responsibility for the 250,000 largest US taxpayers of whom 75% are now partnerships and other pass-through entities rather than traditional corporations. The IRS is trying to devote more resources to auditing companies with annual revenues of $10 to $250 million. Only 11.9% of such companies are audited currently.