MORE CONSTRUCTION-START ISSUES are likely to be addressed by the Internal Revenue Service this fall.
Wind, geothermal, biomass, landfill gas, incremental hydroelectric and ocean energy projects in the United States must be under construction by year end to qualify for federal tax credits. The IRS issued guidance in April about what it means to start construction, but many people still have questions.
The questions are mainly in two areas.
First, once a project is considered under construction, the remaining work must be continuous. It is not always clear what continuous means. For example, is it continuous where some work is done, but then stops until the local utility can catch up on building substation improvements or network upgrades that must be completed before the project can connect to the grid?
Second, it is not clear in what circumstances someone who buys a project, after this year, on which another developer started construction in 2013 can claim tax credits.
The IRS branch for these issues has been given a “tentative green light” to issue additional guidance. The guidance is “not that far along” yet, but, if issued, will come out in the fall.
On continuous work, there was talk earlier about releasing examples showing how the IRS views different fact patterns, but the agency has moved away from examples and is now focused on adding more detail to the guidance it already published.
On transfer issues, the US Treasury Department took the position under the section 1603 cash grant program that any project on which significant physical work started in time at the site or factory would remain “grandfathered” no matter how many times the project changes hands before completion. However, it was concerned about developers who started construction of projects by stockpiling wind turbines or solar panels that they then sprinkled among multiple projects in increments that amount to more than 5% of each project’s cost. The Treasury did not want to encourage trafficking in stockpiled equipment as a way of conferring grandfather rights on future projects, so it required the original developer to retain more than a 20% interest in any project to which it contributes such equipment, unless the later sale of the project is a sale of a real project and not a project company that is mere wrapping paper for the stockpiled equipment. Tax equity transactions are not a problem.
The new guidance will probably allow retention of grandfather rights after most transfers.
The government believes that the requirement that there must be “continuous efforts” after this year on projects that start construction by incurring costs will protect against bare trafficking in stockpiled equipment.
THE SECTION 1603 PROGRAM is attracting more litigation.
Three new lawsuits have been filed in the last two months. Eight suits are now pending. All the cases have been filed in the US Court of Federal Claims.
A ninth lawsuit was withdrawn earlier this year “with prejudice” after the US Treasury filed a counter-claim charging the company that brought the suit with fraud.
The oldest pending suit has been pending since July 2012. No dates have been set for trials. The government has filed motions to dismiss four of the cases.
In one of the new lawsuits, Blue Heron Properties, LLC complained in late July that it was shortchanged on grants paid on two solar systems installed on the roofs of apartment buildings. This is the second suit involving a Dallas electrical contractor, RCIAC, that installs solar systems. Bret Heron, the managing member of the LLC that brought suit, paid RCIAC $10.50 a watt in 2010 for a solar system installed at an apartment complex and applied for a grant on the full amount, which Treasury paid the same year.
Heron then bought three more systems installed on other apartment buildings in 2011 at prices ranging from $9.52 to $10.50 a watt and applied for grants on them at the full prices after the systems went into service in the first half of 2012.
Treasury paid the full grant requested on the first system ($9.52 a watt), but accepted bases of only $5.56 and $5.43 a watt on the next two. The Treasury posted benchmarks on its website in late June 2011 suggesting that it thought the market value of systems put in service in the first quarter 2011 ranged from $4 to $7 a watt, depending on the size of the system. The two systems on which Heron feels shortchanged were 205 kilowatts and 294 kilowatts. The June 2011 benchmark for such systems was $5 a watt. Heron argues that Treasury had no discretion but to honor what he had in fact paid RCIAC for the systems.
In the most recent suit, filed in early August, Anaergia, a fuel cell company, complained that it was shortchanged on grants on two fuel cells that it installed at municipal wastewater treatment plants in Ontario and San Jose, California. Treasury paid $1.6 million less in total than the grants for which the company applied on the two fuel cells, mainly by excluding the cost of gas conditioning equipment. The fuel cells use methane gas that the municipalities produce by putting sewage sludge through anaerobic digesters, but the gas must be cleaned before use in the fuel cells. The Treasury’s position is that only the fuel cell qualifies for a grant, and not equipment used in “the production or refining” of the gas.
The company argues that the fuel cells qualify independently for grants as “trash facilities” that use “municipal solid waste” to generate electricity. Treasury allows grants to be claimed on fuel processing equipment at the front end of such facilities. However, the Treasury cash grant rules are supposed to mimic what the IRS does for tax credits, and the IRS treats a power plant as a trash facility only if it uses municipal solid waste directly and not gas that an unrelated fuel supplier has made by running the waste through a digester.
There are rumors that another suit may be in the works challenging whether the US government has authority to reduce grants by the 8.7% sequestration percentage. Grants approved for payment on or after March 1 this year have been subject to a haircut of 8.7% under across-the-board spending cuts ordered by Congress. The percentage is expected to drop for grants approved after September 30. The Office of Management and Budget estimated in May that the new percentage will be 7.3%. However, it said it would update the estimate in August.
Treasury is allowing companies that are unhappy with the grants they were paid to pay back the money and claim tax credits instead. There does not appear to be a hard deadline to do so.
WIND FARMS accounted for 43% of new generating capacity built in the United States in 2012, but 2013 is expected to be a slow year while developers gear back up, according to a new report by Ryan Wiser and Mark Bolinger of the Lawrence Berkeley National Laboratory in early August.
The authors expect an uptick in projects that need financing in 2014 given the need to start construction of new projects by year end 2013 to qualify for federal tax credits. However, the outlook for 2015 and beyond is uncertain.
The US has 60,000 megawatts of installed wind capacity. Only 1.6 megawatts were added in the first quarter of 2013. Just 537 megawatts were under construction as of March 31 this year. The biggest gains in 2013 will be in natural gas and solar. The Solar Energy Industries Association reported that solar accounted for 49% of new electric generating capacity installed during the first quarter of 2013, and the fast-growing solar rooftop residential market grew by 53% year on year to the end of the first quarter.
Wind turbine prices are currently in the $950,000 to $1.3 million range per megawatt. The average installed cost per megawatt for wind farms completed in 2012 was $1.94 million. Merchant or quasi-merchant projects accounted for 19% of new wind capacity additions in 2012.
Electricity prices under long-term power contracts have fallen to the lowest levels since 2000 to 2005, but construction costs have increased since then, making the economics for wind projects more challenging. The average price for contracts signed in 2011 and 2012 was $40 a megawatt hour. The prices vary by region, with prices in the $50 to $90 range in the West, $20 to $40 in the interior of the country and $50 to $70 in the Great Lakes and Northeast.
Utilities in the Southwest and Texas signed another 1,500 megawatts of long-term contacts with wind companies in recent weeks at prices ranging from $22 to $33 a megawatt hour.
Renewable portfolio standards that require utilities in 29 states and the District of Columbia to supply a certain percentage of their electricity from renewable energy are expected to require only another 3,000 to 5,000 megawatts of renewable generating capacity each year during the period 2013 through 2020. The industry is fighting efforts by conservative interest groups to roll back these standards in various states, but so far the line has held.
Wind accounts for 20% of more of electricity supply in three states: Iowa (25%), South Dakota (24%) and Kansas (20%). This compares to an average of 4.4% nationwide. The top four states for new wind construction in 2012 were Texas, California, Kansas and Oklahoma.
ARIZONA is the latest battleground for rooftop solar companies and utilities.
Arizona Public Service asked the Arizona Corporation Commission in July for permission to charge customers who install rooftop solar panels $50 to $100 more a month on their utility bills as compensation for the ability to draw electricity at any time from the grid. The additional charges would only apply to customers who install solar systems after October 15.
The utility has 18,000 solar customers in its service territory currently. It is receiving 200 new applications a week.
It also asked the commission for permission to reduce the amount it credits customers who produce more electricity than they need and feed the excess back into the grid. The utility credits these customers under its “net metering” program at the same retail rate the customers pay to buy electricity from the utility. (Under a net metering program, a customer’s meter runs backwards as it feeds electricity into the grid.) The average solar customer pays 15.5¢ a kilowatt hour. The utility argues that it should not have to pay more than the market rate it can pay to buy power from large power plants.
The proposals would significantly alter the economics of installing solar. Some utilities are facing steady erosion in their rate bases as solar rooftop, fuel cell and small cogeneration or CHP companies pick off customers. The same battles are or will soon be fought in other states.
FIXED-PRICE PURCHASE OPTIONS may receive more attention after a decision by the US Tax Court in a case involving LILOs and SILOs.
The court said 27 lease transactions that John Hancock Life Insurance Company did during the period 1997 through 2001 were not true leases for tax purposes and denied tax deductions for rent and depreciation that the company claimed.
Some of the transactions were cross-border lease-sublease deals called LILOs (for lease-in-lease-out) where mainly European municipalities or companies leased infrastructure assets to Hancock that Hancock subleased back to them. The remaining transactions were sale-leasebacks called SILOs where, at the end of the lease, the lessee had either to buy the assets or enter into a power contract or other “service contract” to continue buying the output from the leased facility. The parties selected three LILOs and four SILOs to litigate as test cases.
The government has won all six litigated LILO cases to date. A seventh case had a 10-day trial before the US Court of Federal Claims, but that court has not yet released a decision.
The Tax Court said that all of the Hancock LILOs and one of the SILOs were “financial arrangements” rather than real leases. In the other three SILOs, it said Hancock bought only a future interest in the leased assets.
The case is John Hancock Life Insurance Company v. Commissioner. The Tax Court released its decision in the case in early August.
Starting with the LILOs, Hancock leased assets for 38 years and subleased them back for 18, but the court said the terms were otherwise virtually identical. No money changed hands in practice during the sublease term other than a payment by Hancock to the European counterparty as a fee to enter into the transaction. The upfront amount Hancock paid the counterparty was never really at risk during the sublease term since the counterparty’s obligations to Hancock were fully defeased. Hancock argued that it had credit risk on the defeasance bank. The court called this risk “de minimis.”
The court said Hancock had basically a predetermined fixed return. The European counterparties had options at the end of each sublease to buy the remaining leasehold interest Hancock held in the assets for a fixed price. The court assumed the purchase options would be exercised after concluding exercise is a “reasonable likelihood.”
This view of purchase options is in line with a decision by the US appeals court for the federal circuit last January in a LILO case involving Consolidated Edison. The court in that case said it is a problem to give a lessee a fixed-price option to purchase equipment at the end of the lease term if exercise of the option is “reasonably expected.” Many tax lawyers believe the Con Ed court used the wrong standard. Most courts to date have allowed fixed-price purchase options without disturbing true lease treatment as long as exercise is not a foregone conclusion.
The Tax Court defended the approach: “Neither the Tax Court nor the Court of Appeals for the First Circuit [where the Hancock decision may be appealed] has ever set an ‘inevitable’ or similar threshold for determining whether a lessee will exercise a purchase option, and we decline to adopt such a standard here.” It insisted this is consistent not only with the approach taken in the federal circuit where the Con Ed case was heard, but also in the prestigious second circuit in New York.
Turning to the SILOs, the Tax Court said that in three of the four test SILOs, Hancock acquired only a future interest in the leased assets after the leases end. Hancock had little risk during the lease term because the lessees had defeased the rent even though this was not required by the documents, and Hancock was not directly a party to the defeasance arrangements. Although Hancock had no present interest in the assets, it acquired at least a future interest because the lessees seemed more likely to enter into service contracts to buy the output at the end of the lease terms rather than buy the assets.
Hancock said the Tax Court’s approach threatens all leveraged lease transactions. The court disagreed. It said the lessor in a typical lease has credit risk that the lessee will default on rent during the lease term. Hancock had no such risk because of defeasance. There are two types of defeasance: “legal defeasance” where the bank into which the lessee deposits money to pay future rent assumes the legal obligation to pay rent and the lessee is released, and “in-substance defeasance” where the lessee remains legally obligated. The distinction made no difference in this case.
One of the SILOs did not involve any defeasance, but the court felt the purchase option in that transaction was reasonably likely to be exercised. The court said Hancock had basically made a loan to the lessee in that case. Assuming exercise of the purchase option, Hancock had a predetermined return without regard to the asset value and no upside potential or downside risk tied to ownership.
On the positive side, the court rejected an IRS claim that the transactions lacked economic substance. Courts deny tax benefits in transactions that are entered into solely for tax reasons without any real business purpose or expectation of a return beyond the tax benefits. Congress has since written this requirement into the US tax code. The Hancock transactions preceded codification.
Hancock said it expected a pre-tax return in the LILOs of 2.54% to 4.33% if the purchase options were not exercised, and 2.83% to 3.43% if exercised. A government witness argued that Hancock has a pre-tax loss on the deals if the calculations are done correctly using present-value concepts. The court agreed the numbers should have been discounted, but was not persuaded by the government’s calculations. It also said Hancock had a clear business purpose: the need to fulfill its insurance policy and annuity obligations contributed significantly to its investment decisions.
The court called the LILOs and one of the four SILOs mere “financial arrangements” and recast them basically as loans by Hancock to the counterparties. In so doing, it not only denied the tax benefits Hancock claimed, but also required it to report the difference in what it paid and what it was expecting back as original issue discount over the life of the “loans.”
ANOTHER LEVERAGED PARTNERSHIP has come under attack.
Such transactions are sometimes used by sellers of assets to defer a tax on gain. Rather than make a direct sale, the seller and buyer both contribute assets to a partnership. The seller contributes the assets it intends to sell. In this particular case, the buyer contributed notes and cash for the purchase price. The partnership then borrowed the amount of the notes from a bank and distributed the amount to the seller.
The seller does not have to pay tax on the cash distribution as long as the distribution is not recast by the IRS as purchase price for a disguised sale of the assets to the partnership. It should not be as long as the seller is ultimately liable for the partnership-level debt.
Two special-purpose subsidiaries through which the buyer held its interest in the partnership guaranteed repayment of the loan. The seller agreed to indemnify the buyer’s subsidiaries if they had to pay on the guarantee. However, there was no requirement in the indemnity for the seller to maintain any particular net worth.
The IRS has challenged the transaction on audit. The IRS national office rejected the idea in an internal memo that the seller is ultimately on the hook for the partnership-level debt because no payments have to be made on the indemnity unless the buyer has had first to pay out on the guarantee. If the transaction runs into trouble, then the buyer would default on the guarantee, and the seller would not have to make a payment, the IRS said.
The IRS also does not believe that the seller should get a pass as a policy matter on re-characterization of the transaction as a disguised sale. Congress intended that these sorts of transactions would not be recast as disguised sales, the IRS said, only where a partner contributes to a partnership property that is already subject to debt and then receives a cash distribution or else the partnership borrows against the assets after the contribution to make the cash distribution. The IRS said the borrowing in this case is nothing more than an advance against the notes from the buyer.
The national office suggested that if its technical arguments fail, then the audit team should attack the transaction head on, either by recasting it as a borrowing by the buyer to buy the assets followed by formation of the partnership or by arguing that the transaction is in reality a sale.
The facts appear to match a transaction that the Tribune Co. did when it sold Newsday in 2008 in the hope of deferring tax on the gain for 10 years. It did a similar transaction in 2009 when it sold the Chicago Cubs. The IRS wants $190 million in back taxes on the Newsday sale plus a $38 million penalty and $17 million in interest through December 2012. The Tribune Co. said in a financial filing that it plans to take the case to IRS appeals. It is currently under audit in the Cubs transaction. The company warned that it could be liable for another $225 million in federal and state income taxes on the Cubs deal before penalties and interest.
The internal IRS memo is Chief Counsel Advice 201304013. The IRS released a redacted version in June.
The US Tax Court treated a similar transaction as a sale in 2010 after Chesapeake Corporation — now called Canal Corporation — conveyed the assets of a subsidiary that made paper products to Georgia Pacific using a leveraged partnership. See earlier coverage about the structure in the September 2010 NewsWire starting on page 17 and a “Special Update: Tax Issues in Project Sales” in June 2004.
SOLAR ROOFTOP SYSTEMS owned by solar companies and leased to homeowners are not “immovable” property and, therefore, the homeowners leasing them must pay a 4% sales tax on the rents, Louisiana said in a ruling in late June. The ruling is Revenue Ruling No. 13-006.
Louisiana allows a 50% tax credit on residential solar systems, up to a maximum credit of $12,500. The credit drops to 38% of the system cost for systems installed after 2013, up to a maximum of $9,500. Homeowners sometimes assign the tax credit to the solar company leasing them the systems. The ruling said that in such cases, the assigned tax credit is considered additional rent to the solar company and is also subject to the sales taxes.
ARGENTINA is replacing a list of countries considered tax havens with a new list of “cooperative jurisdictions” that share tax information with the Argentine tax authorities. Any countries not on the new list will be considered tax havens.
Higher withholding taxes apply on payments to tax havens, and arrangements with tax haven companies are not considered at arm’s length and are subject to greater scrutiny.
Many Latin American countries maintain such blacklists.
The current Argentine blacklist includes 88 jurisdictions, including Bermuda, the British Virgin Islands, Cayman Islands and Luxembourg. Bermuda and the Cayman Islands are no longer expected to be treated as tax havens after the new list is issued.
CURTAILMENTS may not prevent a power plant from being considered in service for tax purposes.
Solar, fuel cell and small cogeneration or CHP projects face deadlines to be put in service to qualify for investment tax credits.
The IRS said in private letter rulings that the agency made public in late June that two utility-scale solar photovoltaic projects will be in service notwithstanding that the local utility to whose grids the projects need to connect to get their electricity to market will not have completed part of the network upgrades required to accommodate the electricity on a segment of the grid due to litigation with local residents. The utility determined that the projects are able to deliver their full capacity despite not having made the upgrades to the segment. However, the projects may have to be curtailed while the segment is under construction.
The IRS said the projects will be considered in service even “if more frequent than anticipated curtailment . . . occurs due to the unanticipated delays” in completing the upgrades.
The rulings are Private Letter Rulings 201326008 and 201326009.
A PUERTO RICAN solar project will qualify for an investment tax credit and accelerated depreciation in the United States, the IRS said.
The IRS confirmed that a US limited liability company that is treated as a partnership for US tax purposes and that is developing a solar project in Puerto Rico will be able to claim the tax benefits when the project is completed. The partnership has two partners. Both are US corporations. Projects outside the United States do not normally qualify for these tax benefits. However, projects in Puerto Rico and other US possessions qualify if owned by US citizens or corporations. The ruling is Private Letter Ruling 201324006. It was released in June.
The IRS has issued other rulings recently about projects in Puerto Rico. For other coverage of this subject, see the June 2011 NewsWire starting on page 21 and the November 2011 NewsWire starting on page 13.
PURCHASE PRICE ALLOCATIONS usually cannot be changed later.
A US appeals court refused to let a poultry company that bought two poultry processing plants in Mississippi, and agreed with the sellers to schedules showing how the parties intended to allocate the purchase price, revise the allocations. It said section 1060(a) of the US tax code binds the parties to the original allocation unless the IRS agrees to a change. The buyer is depreciating one of the poultry processing plants over 39 years on a straight-line basis on the theory that the plant is a building. It is depreciating the other plant partly over seven years and partly over 15 years on the theory that the plant is equipment. It tried retroactively to treat the first plant also as equipment. The IRS objected. The appeals court said the US tax code provision binding the buyer and seller to the same purchase price allocations is important for preventing the government from being whipsawed by inconsistent treatment.
The case is PECO Foods, Inc. v. Commissioner. The appeals court released its decision in July.
TARGETED PARTNERSHIP ALLOCATIONS are starting to get attention.
Curt Wilson, the IRS associate chief counsel for partnerships, said, in response to questions at a tax conference in San Antonio in June, that the IRS will probably have to issue guidance at some point on such allocations. They are becoming more widespread in partnership agreements. Traditionally, partnership agreements have required that a “capital account” be maintained for each partner measuring what he put in and what he is allowed to take out of the partnership. When the partnership liquidates, each partner is distributed the balance in his capital account out of the proceeds from liquidating the partnership’s assets.
In a partnership with targeted allocations, the partners share in what is left when the partnership liquidates in whatever ratio their business deal is for sharing cash. Capital accounts are not used to divide up what remains.
IRS regulations require partners to use capital accounts for dividing up cash at liquidation unless sharing in some other ratio reflects the partners’ underlying economic interests in the partnership. The IRS has not explained how to determine the underlying economic interests, but its regulations suggest that the ratios in which the partners contribute capital and share income and losses are relevant in addition to how they have agreed to share cash flow.
IRS guidance is not imminent. Wilson was skeptical whether any guidance the IRS issues would prove useful since anything the agency publishes is likely to be fairly rudimentary and uncontroversial. Conference attendees said even an IRS acknowledgment that such allocations are allowed would have value.
The agency will look into including the subject on its 2014 business plan. The business plan is a list of issues the IRS hopes to address in the coming year.
RESCISSIONS will not be addressed any time soon, the IRS said.
The agency had been considering whether to revise its existing policy on when two companies can unwind a transaction and be treated as if the transaction never occurred. It said Revenue Ruling 80-58 will remain the IRS’s guidance on the issue for the foreseeable future. Bill Alexander, the IRS associate chief counsel for corporations, made the comment at a New York Bar Association tax section meeting in late June.
Revenue Ruling 80-58 said that a sale of real estate in 1978 could be rescinded in the same year, and the buyer given all his money back when he could not get the land rezoned as he wanted, and the parties would be treated for tax purposes as if the sale never occurred. However, if the buyer waited until 1979 to rescind, then there was a completed sale in 1978 and returning the property in 1979 was a sale back to the original seller. The sales contract gave the buyer a right to rescind if he was unable to get the property rezoned. A rescission should put the parties back in the same position economically as if the transaction never occurred.
The IRS will not issue any private letter rulings on rescissions.
There is a risk when a buyer has a right to unwind a transaction that the buyer may not be considered the owner until the unwind right lapses. This is a potential issue in deals where it is important for the buyer to be a partner or owner before assets are placed in service to claim tax credits.
TAX-EXEMPT BONDS lost their tax exemption.
The IRS said in a technical advice memorandum issued to a bond issuer in late May, but not formally released yet to the public, that community development districts formed in Florida to issue tax-exempt bonds to finance real estate projects are not subdivisions of the state and, therefore, the interest on bonds issued by such districts must be reported by the bondholders as taxable income.
A technical advice memorandum is a ruling by the IRS national office to settle a dispute between a taxpayer and an IRS agent in an audit.
The IRS looked at 12 special districts set up to finance projects by billionaire real estate developer H. Gary Morse. Morse, family members and employees control the districts.
The IRS memorandum focused on one of the 12 districts that issued $426.2 million in bonds over time to finance a retirement community called The Village in Lake County in central Florida. The bond proceeds were used to buy real estate and a right to collect amenities fees from existing residents for use of recreational facilities like the golf course. Morse retained the rights to amenities fees from future residents.
The bond proceeds substantially exceeded the cost of the real estate. The bonds were issued in multiple tranches over time.
They were trading at an average yield of around 5% earlier this summer, or 2.07% above an index of benchmark municipal bonds with similar maturity. Holders as of April 30 included Goldman Sachs Asset Management and Nuveen Asset Management.
The National Association of Bond Lawyers says the decision could affect bonds issued by hundreds of similar entities.
MINOR MEMOS: Lease accounting in the United States is still on track to change. The accounting standards boards in the United States and Europe — FASB in the US and the IASB in Europe — are moving forward with a plan to eliminate distinctions between operating and capital leases for book purposes. Lessees would be required to treat leased assets essentially as owned, and the obligation to rent as a liability, on their balance sheets in any cases where the lessee is expected to have more than an insignificant portion of the economic benefits embedded in a leased asset under proposed guidance issued in August 2010 and updated in May this year. Existing leases will not be grandfathered once the change takes place . . . . The IRS said in an internal legal memo that two companies that cooperated on development of a product and jointly marketed it under a trademark held jointly and with documents that showed both company logos created a partnership and should have filed a US partnership return. They said in a side agreement that they did not intend to create a partnership. However, they split the income from product sales by charging costs against the revenue and then dividing up the revenue in one ratio until $X in operating profits was reached, and then in a different ratio. The IRS said they could not elect out of partnership treatment by filing an election under section 761 of the US tax code because the arrangement was not a mere investment partnership with a passive role and they were not joint owners of a property in a position to calculate their incomes from use of the property separately. The memo is Chief Counsel Advice 201323015. The IRS made it public in June.