STATE-MANDATED POWER CONTRACTS remain under a cloud after a US  appeals court said in early June that Maryland cannot force utilities to sign  long-term power contracts at different prices than the wholesale power  prices in PJM, the regional wholesale power market.

The decision was in a case called PPL EnergyPlus, LLC v. Nazarian.

A federal district court reached the same conclusion last fall about a  similar capacity auction in New Jersey. The New Jersey decision has been  appealed to a different US appeals court than the one that heard the  Maryland case.

According to the courts, the state actions violate the supremacy clause  of the US constitution because they effectively establish a price for electricity sold at wholesale. The Federal Energy Regulatory Commission has exclusive jurisdiction to regulate  the prices for such electricity.

A decision in the New Jersey appeal is  expected imminently. The issue could end up  before the US Supreme Court, although the court  has discretion whether to hear appeals.

The cases are significant beyond Maryland  and New Jersey because they may raise questions  about the enforceability of other state programs  that require utilities to sign long-term power  contracts to the extent they affect the price at  which utilities must buy wholesale power. The  issue is whether any such effects on pricing are  so great as to require federal preemption.

TAX CREDITS for renewable energy remain in  limbo in Congress.

Senator Harry Reid (D-Nevada), the Senate  majority leader, suggested at a press conference  in early June that the Senate is unlikely to take up  a bill before late November at the earliest to  extend the deadline to start construction of new  wind, geothermal, biomass, landfill gas and ocean  energy projects by another two years through  December 2015 to qualify for federal tax credits.  Such projects had to be under construction by  December 2013 to qualify. The Senate tax-writing  committee voted on April 3 to allow another two  years through 2015 to start construction.  However, Republicans blocked the bill from being  taken up by the full Senate after Reid prevented  Republicans from offering an amendment to  repeal an excise tax on medical devices that is  part of the funding for Obamacare.

The construction-start language is part of a  broader tax extenders bill that would extend  more than 50 tax benefits that expired in 2013 or  are scheduled to expire this year.

It is possible Congress will find a way to deal  with the issues in a “lame duck” session after the  November elections. It is also possible, if the  November elections give the Republicans control  over both houses of Congress, that Republicans  will want to push unfinished business into the  new Congress that starts in January 2015 when  they will be in control.

Meanwhile, the Internal Revenue Service is  expected to release additional guidance in July  on how much work had to be done in 2013 for a  project to be considered under construction  under the “physical work test.” The guidance is  being drafted by the US Treasury and is currently  expected to take the form of questions and  answers.

There were two ways to start construction  of projects in 2013. One was by incurring at least  5% of the project cost. The other was by starting  physical work of a significant nature.

The tax equity market has largely shut down  for projects that relied on physical work while the  market waits for the new guidance.

Meanwhile, the IRS has decided not to issue  any private letter rulings on construction-start  issues after accepting a number of ruling  requests and then deciding that they were all  too factual.

TREASURY CASH GRANT LITIGATION is moving  closer to resolution.

There are 20 pending lawsuits against the  US Treasury Department by companies that put  new renewable energy facilities in service after  2008 and chose to be paid 30% of the “basis” the  companies had in the facilities in cash rather than  claim tax credits. All of the companies received  smaller cash payments than they applied for. The  Treasury was authorized to make the payments  under section 1603 of the American Recovery and  Reinvestment Tax Act. Many renewable energy  projects are financed in a way that lets the owner  use the fair market value as his basis for calculating tax benefits (and, by extension, section 1603  payments in lieu of tax credits) rather than the  cost to build the project. This has led to many  disputes with Treasury about how to determine  the value.

The government filed motions for summary  judgment in eight of the pending cases in late  May. A summary judgment motion is a request  for the court to decide the cases based on legal  briefs from both parties. The procedure is used in cases where the facts are not  in dispute.

It should lead to decisions in at least some  of the cases this year.

The oldest case has been pending since July  2012. All of the cases have been filed in the US  Court of Federal Claims. One case filed earlier  than July 2012 was withdrawn by the solar  company that filed it after the government  accused the company of fraud.

The remaining cases raise five significant  issues.

Many of the suits challenge the Treasury’s  cost-up approach to determining value. The  Treasury has appeared to base some grant  payments on what a project cost to build and  then adding a profit margin that it considers  reasonable.

At least two suits challenge whether part of  what was paid for a utility-scale power project  must be allocated to the power purchase agreement with a utility. Any amount allocated to the  power contract would not qualify for a grant. The  IRS ruled privately in 2012 that a power purchase  agreement that can only be performed by  supplying electricity from a specific project has  no value separate from the project on the theory  that the contract is like a tenant lease of a building. No one buying a building would allocate  part of the purchase price to the tenant lease.  The entire purchase price is treated as basis in  the building. The IRS quickly thought better of  applying the analogy to power contracts and  withdrew the ruling.

The issue in at least one suit is whether the  Treasury is required by law to accept what outside  appraisers say is the fair market value of a project. Other suits involving projects that were sold to  bank leasing companies and leased back raise the  issue whether part of what the bank leasing  companies paid must be treated as purchase  price for an intangible asset like going concern  value rather than the power plant. Grants are not  paid on intangible assets.

Finally, the latest suit, filed in mid-May, involved a 17.6-megawatt wind  farm near the Anchorage, Alaska airport whose  developer, Fire Island Wind, LLC, spent $5.3  million to dismantle an old navigational system  and buy the air traffic controllers a new Doppler  radar so that the developer could get clearance  from the Federal Aviation Administration to put  up its wind turbines. The developer treated the  $5.3 million as a cost of the wind turbines. The  Treasury would not let the amount be included  in basis for calculating the cash grant on the  project.

The statute oflimitations to file suit against theTreasury is six years fromwhen a company is notified its grant has been approved for payment. Ifthe government starts losing some ofthe cases, other suits can be expected.

In a separate development, the IRS said in early June that companies may not claim an investment tax credit to make up for haircuts in grant amounts due to sequestration. Grants approved for payment through September this year are subject to a 7.3% haircut as part of a Congressional budget deal in 2012 to keep the federal government open. Sequestration will continue past September, but potentially at a different percentage.Somedevelopersmust have tried to claimtax credits forthe shortfall.The IRS said this is not allowed.The tax basis the project owner uses to depreciate the project must be reduced by one half the grant. The IRS said the basis reduction is for half the actual grant paid —after sequestration.The IRS announcement is in Notice 2014-39.

REITS can own some solar equipment, the IRS  said.

An IRS proposal in early May to make it easier  for real estate investment trusts to invest in solar  was disappointing, but may not be the last word.  The IRS is collecting comments through August  12. The proposal would let REITs that own buildings also own solar panels on the building that  are used to supply electricity to the building occupants. It is not clear the  proposal would allow REITs to own solar panels  in other situations.

REITs are corporations or trusts that do not  have to pay income taxes on their earnings to  the extent the earnings are distributed each  year to shareholders.

The renewable energy industry is interested in REITs potentially as a source of cheaper  capital. Congress created REITs in 1960 as a way  for small investors to invest in large-scale real  estate projects. Small investors pool their  investments in the REIT and are treated essentially as if they had invested in the real estate  projects directly without a corporate-level tax  being taken out along the way.

The challenge for renewable energy is that  a REIT must hold at least 75% real property or  interests in real property. Examples of such  assets are land, site leases, buildings and  mortgages secured by real property.

The IRS, with the active encouragement of  the White House and Department of Energy,  issued proposed regulations in May redefining  what qualifies as “real property” for REIT  purposes. Under the new definition, solar equipment qualifies as a “structural component” of  a building if it performs a utility-like function  for the building, such as providing electricity,  and the electricity is part of what the building  occupants get for their rent for the use of space.  In addition, the REIT must own both the solar  equipment and the building, and it must expect  the solar equipment to remain permanently in  place.

The IRS and US Treasury are still thinking  about whether it makes a difference if some of  the electricity is supplied to the local utility, for  example, through net metering. However, in an  example showing how the new definition  works, the IRS said that a solar system mounted  on the ground next to a building whose electricity it supplies is considered a structural component of the building,even though the tenant transfers excess electricity “occasionally” to the local utility.

The IRS said in another example that the  land, underground gathering lines, concrete base  and metal racks that hold the solar panels in place  at a utility-scale project qualify as real property,  but the solar panels do not. The agency drew a  line around what qualifies at a utility-scale project  in the same place as the market already draws it  under the existing definition.

Some renewable energy companies have  been worried that any expansion of what is  considered real property for REIT purposes could  undermine other positions the industry has taken.  The industry treats solar projects as equipment  in order to claim Treasury cash grants, investment  tax credits and five-year accelerated depreciation  on the projects. These tax benefits can be claimed  only on equipment and not also on real property.  The US renewable energy sector has attracted a  large amount of foreign investment, including by  prominent European utilities. These investors are  not subject to US capital gains taxes when they  exit US projects unless the projects are considered  real property.

The IRS said it is redefining real property  solely for REIT purposes and said it does not  necessarily follow that real property must be  defined the same way for these other purposes.  It asked for comments on the extent to which the  various other uses of the term real property in the  US tax code should be reconciled.

The new definition will apply after the IRS  republishes it in final form. The agency has scheduled a public hearing on the new definition on  September 18.

Any requirement to show that rooftop systems  are expected to remain permanently in place  would complicate the ability to finance  rooftop systems in the tax equity market. A  tax equity investor must be able to prove he is  the tax owner of equipment to claim tax benefits on it. It is hard to prove tax ownership of  equipment that is bolted permanently to the  roof of someone else’s house.

A PARTLY CONTINGENT PURCHASE PRICE creates  tax complications.

Many developers sell projects that are still  under development for cash at closing plus  additional payments that are contingent on  reaching various milestones.

The developer usually reports its gain under  the installment method, meaning the gain is  reported over time as payments are received.

IRS regulations require the gain be calculated each year by taking the maximum purchase  price the developer might receive and subtracting  his basis in the project to determine the fraction  of the purchase price that would be gain. The  developer then reports that fraction of each  actual payment from the buyer as gain.

However, if the maximum purchase price is  unclear by the end of the year in which the sale  occurs, then the developer is supposed simply to  spread its basis in the project ratably over the  period that the purchase price will be paid. Thus,  for example, if the purchase price might be paid  over five years, the developer would subtract 20%  of its basis in the project each year from what the  buyer pays it that year.

One taxpayer who sold a company got the  IRS to rule that it could use a different method for  determining how much of each payment was  gain. The ruling is Private Letter Ruling 201417006.  The IRS made the ruling public in late April.

The buyer agreed to pay cash at closing,  assume liabilities and make additional payments  over the next seven years tied to growth in  company revenues.

Since the ultimate purchase price the seller  might pay was too uncertain, but the seller knew  it might receive payments for up to seven years,  it was required to spread its basis in the company  shares it sold ratably over seven years. This would  have led to a large gain in year one and a large  loss in year seven based on projections the seller  made assuming the company would continue to  grow at the same rate it had in the past.

Instead, the IRS let the seller allocate part of  its basis to each year over the seven-year period in the same pattern as the  seller expected to receive contingent payments.

IRS regulations allow the seller to use a different method for allocating basis if it can show  that he will probably recover basis at least  twice as fast under the alternative and the  method is reasonable. The seller must receive  IRS approval to use the method by asking for  a private ruling.

CORPORATE INVERSIONS are becoming more  common.

A corporate inversion is where a US corporation with substantial foreign operations reincorporates in a foreign country to reduce the amount  of taxes it has to pay in the United States on its  foreign earnings.

A wave of inversions early in the last decade  led Congress to take steps in 2004 to discourage  them. Now a new wave of inversions has led to  new hand wringing on Capitol Hill, but the  gridlock in Congress and the lack of consensus  about what action to take make any further  action unlikely, at least this year.

Forty one US multinational corporations  have reincorporated in lower tax countries since  1982. Of that number, at least 13 moved since  late September 2010, and another eight inversions were in the works as of late May. Of these  21 transactions, 11 involve reincorporation in  Ireland, three in the United Kingdom, three in  Holland and one each in Canada, Australia and  Germany.

The attraction is not only a lower tax rate  — the US corporate income tax rate is 35%  compared to 12.5% in Ireland and 20% in the  United Kingdom — but also the United States  taxes US corporations on their worldwide  earnings while the other countries impose  limited or no taxes on offshore income. Another  factor is the $1.95 trillion in earnings that US  multinational corporations have parked in  offshore holding companies and are unable to  use in the United States without triggering US income taxes. An inversion  could make the earnings easier to redeploy.

Congress amended the tax code in 2004 to  make it more painful for US companies to invert.  In cases where the shareholders of the former US  corporation continue to own at least 80% of new  foreign parent company by vote or value, the  foreign corporation is treated as a US company  for tax purposes, so any benefit from inversion is  eliminated. If the shareholders of the former US  corporation retain at least 60% of the new foreign  corporation, then a toll charge is collected on any  appreciation in asset value when the company  leaves the US tax net. The toll charge cannot be  offset by using tax attributes such as net operating losses and foreign tax credits. In addition,  some executives of the inverted company may  have to pay an excise tax at a 20% rate on the  value of their stock options and stock-based  compensation when the company leaves the US  tax net.

However, a US company can avoid the tax  penalties if the affiliated group of companies  headed by the new foreign parent company has  substantial business activities in the new parent’s  home country. In that case, it is not considered to  have inverted.

Given these rules, two types of inversions are  still possible.

One is a “self inversion” where the US corporation simply reincorporates abroad and has  substantial business activities in its new home  country. Such inversions are rare. The IRS interpreted substantial business activities in 2012 to  mean at least 25% of the affiliated group’s sales,  assets, income and employees must generally be  in the country where the new foreign parent  corporation is incorporated.

Most recent transactions involve mergers of  a US and foreign corporation where the shareholders of the foreign corporation continue to  own more than 20% of the combined entity. In  the typical “acquisition inversion,” the US  company combines with a smaller foreign  company. The combined company can choose a third country as its new  tax home. The executive team usually remains in  the United States.

The chairman of the Senate tax-writing  committee, Ron Wyden (R-Oregon), said in an  op-ed piece in the Wall Street Journal in early May  that he plans to try to put a halt to inversions by  merger by requiring the shareholders of the  foreign corporation to own at least 50% of the  combined entity. This would leave the door open  only to mergers of equals or takeovers of US  corporations by larger foreign corporations.

Chiquita Brands International is moving  overseas in a merger with Irish rival Ffyfes PLC,  which is based in Ireland. The combined company  will be a tax resident of Ireland. Chiquita shareholders would own 50.7% of the combined  company. The deal is not expected to close until  later this year.

Neither Orrin Hatch (R-Utah), the ranking  Republican on the Senate tax-writing committee,  nor Dave Camp (R-Michigan), the chairman of the  House tax-writing committee, joined Wyden in  threatening action. Republicans say the only way  to stop inversions is to reduce US corporate  income taxes to bring them in line with lower  taxes in other countries.

This is in contrast to 2002 when Senator Charles  Gras sley   (R- Iowa) ,   then  rank ing  Republican on the Senate tax-writing committee,  joined the committee chairman, Max Baucus  (D-Montana), in a joint statement that Congress  would act to shut down inversions effective the  day of the statement: March 21, 2002. However,  the final bill did not become law until 2004, by  which time there was a new Congress. Thus, the  final effective date slipped to a date early in the  new Congress: March 4, 2003.

The Wyden proposal is similar to a proposal  that the Obama administration made in its  budget message to Congress in March. Senator  Carl Levin (D-Michigan) and his brother,  Congressman Sander Levin (D-Michigan), the  ranking Democrat on the House tax-writing  committee, intro-duced nearly identical bills in May to do the same  thing. The bill would also continue to treat a  re-domiciled company as a US company for tax  purposes if it remains managed and controlled  from the US and at least 25% of its employees,  employee compensation or assets are located or  derived in the United States.

Meanwhile, the IRS tightened the existing  rules in late April by issuing a notice that said  inversions would trigger US toll charges on US  shareholders who receive shares in the combined  new company as consideration for their shares in  what was formerly treated as a “killer B”  tax-exempt reorganization. The notice is Notice  2014-32.

The popularity of re-incorporations in Ireland  is starting to worry the Irish government, as it  could undermine Ireland’s insistence that it is  not a tax haven. Some companies that have  set up tax residence in Ireland use a “double  Irish” structure to shift profits from Ireland to  Bermuda to reduce taxes even further.

CHILEAN PROJECTS are expected to face higher  taxes.

A tax reform bill that Chilean President  Michelle Bachelet submitted to the National  Congress in April would increase the corporate  income tax rate from 20% to 25% over four years.  The new rates will be 21% in 2014, 22.5% in 2015,  24% in 2016 and 25% in 2017.

The bill is expected to be approved in  September.

It would also impose thin capitalization rules  that will limit the extent to which developers can  “strip” earnings from Chilean projects by pulling  them out as interest on shareholder debt. In the  future, interest paid by a Chilean company on  loans from related parties would be re-characterized as dividends to the extent the company has  a debt-equity ratio of more than three to one.  Debt from third parties would be counted in  determining whether the company is too highly  leveraged, but the only interest that would be  treated as dividends is interest on loans from  related parties.

Jessica Power, co-head of the tax group at  Carey, a premier law firm in Santiago, said the  company would also be treated as having too  much debt to the extent interest and other  financing costs in a year exceed 50% of the  company’s taxable income before deducting such  costs. The thin capitalization rules would apply  starting on January 1, 2015. They will apply to  existing shareholder loans, said Power.

Many developers capitalize Chilean project  companies with debt in an effort to reduce the  Chilean taxes on their projects. By distributing  earnings as interest on such loans, the project  company can deduct the distributed earnings,  and interest paid cross border attracts a lower  withholding tax — 4% or 15% depending on the  facts — compared to 35% on dividends. These are  the statutory withholding rates. Actual withholding may be lower where the developer is a tax  resident of a country with a favorable tax treaty.

The tax reform bill would also move to  taxing shareholders in Chilean companies on  their shares of company earnings in the year the  earnings accrue even if the earnings are not  distributed until later. Earnings would be considered to accrue even before a dividend is declared,  according to Jessica Power. Thus, this would have  the effect of taxing shareholders on earnings that  a company retains for reinvestment.

Expenses on transactions with related  parties — for example, interest on shareholder  loans — would be deductible only in the year  actually paid.

Interest on loans to acquire equity interests  or bonds could not be deducted. Rather, it would  have to be capitalized into the basis in the equity  or debt instruments acquired. This would not  apply to borrowing to acquire assets.

A carbon tax would be imposed on emissions  from any boiler or turbine with a capacity of at  least 50 megawatts. The tax would be a minimum  of the Chilean peso equivalent of US$0.10 per ton  of particulate matter, nitrogen oxide or sulfur  dioxide emitted, according to Manuel José Garcia  with Carey. The tax rate could be higher under a formula tied to the  concentration of pollutants in the local area. The  tax on carbon dioxide emissions would be US$5  a ton. The tax would be an annual levy payable  for the first time in April 2018 on 2017 emissions.

A stamp tax collected on loans would increase  from the current range of 0.033% to 0.4% to  flat tax of 0.8% for any loan with a term of  more than two months.

ROOFTOP SOLAR has the potential to take away  about 7% of retail electricity sales from US utilities, according to a report by Bernstein Research,  an independent Wall Street research firm, in early  June.

The figure is only 2% if the current 30%  investment tax credit for solar equipment drops  to 10% after 2016 as currently scheduled and  only 1.6% if the credit is eliminated. All three  estimates assume that the cost of the average US  solar rooftop installation will fall to $2.20 a watt  compared to about $4.60 in the fourth quarter  2013. The figure $2.20 is what the average solar  system cost late last year in Germany.

Distributed solar generation today is just  0.2% of US electricity supply, leaving significant  room for growth under any of the forecasts.

More than 75% of current distributed solar  capacity is in five states: Hawaii, California,  Arizona, New Jersey and Massachusetts. The fact  that the amount of sunlight varies so significantly in the five states speaks to the importance  of retail electricity rates and state incentives in  driving rooftop installations.

Bernstein estimated the highest possible  percentage of distributed solar penetration in the  US is 24% assuming universal deployment by all  residential, commercial and industrial customers.  However, nearly 50% of residential properties  may not work for solar because of shade and  other physical barriers.

It calculated utility by utility which customers have the greatest incentive to install solar  given retail electricity rates and the potential  savings. The 11 utilities facing the greatest  danger and the percentage of retail electricity sales each could lose are as  follows: Arizona Public Service 34%, Public Service  Company of New Mexico 31%, Pacific Gas &  Electric 26%, San Diego Gas & Electric 25%,  United Illuminating Company 25%, Southern  California Edison 23%, Northeast Utilities 21%,  Hawaiian Electric Companies 20%, Central  Hudson 15%, Consolidated Edison 14% and  SCANA 14%.

Several of these utilities are protected by  state regulatory regimes that decouple the utilities’ revenue from electricity sales. If sales fall  below the forecast, then the regulators must  allow the utility to increase what it charges per  megawatt hour of electricity to stabilize revenues  at the target level.

The move to rooftop solar could also affect  prices for fossil fuels. According to Bernstein,  7% of US demand for natural gas is at risk as  well as 3% of US demand for western coals  and 1% of demand for eastern coals.

A EUROPEAN FINANCIAL TRANSACTIONS TAX moves closer.

Finance ministers from 10 countries said in  a joint statement in May that their countries will  impose a financial transactions tax starting  January 1, 2016. The 10 countries are Austria,  Belgium, Estonia, France, Germany, Greece, Italy,  Portugal, Slovakia and Spain. The tax will apply  initially to transfers of shares and other equity  instruments and to some derivatives transactions and then be expanded over time. The  countries are expected to finalize details of the  tax by the end of this year.

The European Union has been talking about  such a tax since September 2011. The original  proposal was for a tax of at least 0.1% on the  trading of shares and bonds and a tax of at least  0.01% on derivatives. For cross-border transactions between one party in a country with the tax  and another in a country without the tax, the  party in the country with the tax would be expected to pay the tax for both parties.

The United Kingdom and Sweden oppose  the tax and have complained about its extraterritorial reach.

France and Italy have moved ahead in the  meantime with a tax without waiting for the  other countries. France has been collecting a  0.2% tax on acquisitions of shares in Frenchlisted companies with market capitalizations  of more than €1 billion since August 1, 2012.  Italy began imposing a tax on transfers of  shares and other equity positions on  March 1, 2013.

EFFORTS TO SLOW RENEWABLE ENERGY fail in  three states, but lead to a freeze in one.

An organization backed by the wealthy Koch  brothers has been making a concerted push to  roll back renewable energy standards that require  utilities to supply a certain percentage of their  electricity from renewable energy in 29 states  and the District of Columbia. The effort has been  running into opposition from some Tea Party  groups that see distributed generation as a move  toward democratization of the electricity supply.

In Oklahoma, the lower house in the state  legislature failed in May to take up a bill that  would have imposed a three-year moratorium on  construction of new wind farms in the eastern  third of the state, effectively killing the bill for the  current session. The bill passed the state Senate  by 32 to 8 in March.

The Kansas house failed in early May by a  vote of 60 to 63 to phase out the state renewable  portfolio standard. The current standard requires  utilities to supply 20% of their electricity from  renewable energy by 2020. An effort to repeal the  standard failed earlier in the year. The latest vote  was on a compromise to increase the current 10%  target to 15% in 2016 and then to eliminate the  target after 2020.

A federal district court in Colorado rejected  claims in May by the Energy and Environment  Legal Institute that the Colorado renewable  portfolio standard violates the commerce clause of the US constitution. The Institute argued that Colorado is effectively forcing its policies on electricity generators  in neighboring states who want to supply  electricity to Colorado utilities, thereby inhibiting  interstate commerce. The court did not buy the  argument. The case is Energy and Environment  Legal Institute v. Epel.

TheOhiolegislature votedinMay tosuspend its renewable portfolio standard for two years while a legislative panel studies the issues. The state requires utilities to supply at least 25% of electricity from renewables by 2025. The action freezes the target at current levels through 2017. Ifthe legislature takes no further action afterthe panel reports its findings, then the 25% target would be reinstated, but utilities would have another two years until 2027 to comply.

A TAX PLANNING MEMO was not privileged and  had to be disclosed to the IRS after the company  shared the memo with its lenders.

The memo, written by Ernst & Young,  analyzed the tax consequences of a corporate  restructuring and weighed the strength of possible IRS challenges.

A federal district court in New York ordered  the memo turned over to the IRS in late May in a  case called Schaeffler v. United States. The case  is now before a US appeals court.

George F.W. Schaeffler owned 80% of a  three-tier chain of companies headquartered in  Germany that manufacture and distribute  bearings and other automotive and industrial  components.

The group made a tender offer for shares of  Continental AG, another German auto and industrial parts supplier. It expected to acquire less  than 50% of the shares, but ended up buying  89.9% at €70 to €75 a share for a total cost of €11  billion. The acquisition closed in July 2008. Over  the next seven months, the share price  plummeted to €11 a share. The acquisition was  financed by a consortium of banks. The falling  s h a r e   p r i c e   l e f t   t h e Schaeffler group close to insolvency and forced it  to refinance the debt and restructure.

Schaeffler hired Dentons and Ernst & Young  to help figure out a plan and advise on the tax  consequences. The restructuring took place over  the period 2009 to 2010. Ernst & Young wrote a  long tax planning memo as part of the process.

Schaeffler received a favorable private letter  ruling about the transaction from the IRS in  August 2010. The favorable ruling did not stop  the IRS from auditing the 2009 and 2010 tax  years of the company in 2012. The IRS asked for  all “tax opinions and tax analyses that discuss  the US tax consequences of any or all of steps of  the restructuring,” and it issued a separate  administrative summons to Ernst & Young  directly for “all documents created by Ernst &  Young” that relate to the refinancing and restructuring.

Both the company and Ernst & Young  responded that the tax memo was privileged.

US tax law recognizes two types of privileges. One is for attorney-client communications  about legal matters. Section 7525 of the US tax  code extends this privilege to communications  between a client and a “federally authorized tax  practitioner.” The other privilege is a workproduct privilege for documents prepared in  anticipation of litigation.

Both privileges may be lost if documents are  shared with third parties.

The bank consortium and Schaeffler entered  into an “Attorney Client Privilege Agreement”  during work on the transaction in which they  expressed a desire to share confidential  documents and analyses of the transaction  without waiving privileges. The Ernst & Young  memo was shared with the bank group. The  banks agreed to let Schaeffler pay up to €885  million in personal tax liabilities ahead of repaying the debt.

The court said the memo lost any attorneyclient privilege when it was shared with the  lenders. The privilege would not have been  / continued page 36 waived if the memo had been shared as part of an effort by the  parties to formulate a common legal strategy, but  theirs was a commercial interest rather than a  common legal interest. An example of a common  legal interest is where the parties could become  co-parties in litigation.

In contrast, any work-product privilege for  the memo was not waived by sharing the memo  with the banks. The work-product privilege is  waived only “when the disclosure is to an adversary or materially increases the likelihood of  disclosure to an adversary,” the court said. The  parties took steps to prevent the memo from  falling into the government’s hands by marking  it confidential and entering into the joint sharing  agreement.

However, the court said there was no workproduct privilege for the memo since the memo  was not prepared in anticipation of litigation.

Schaeffler argued it had good reason to  expect an IRS audit and eventual litigation.  The memo ran through the transaction steps  and their potential tax consequences, but —  the court said — there was no discussion of  any litigation strategy. It was a transaction  memo rather than a litigation memo.

MORE SOLAR PANELS from China and Taiwan will  be subject to US import duties, the US  Department of Commerce said in early June.

The duties are “countervailing” duties of  18.56% for panels made by Trina Solar, 35.21%  for Suntech panels and 35.21% for panels from  other manufacturers. These are preliminary  figures. The final duties will be settled in the fall.

Importers must begin posting cash deposits  immediately to cover the duties. The Commerce  Department is expected to announce by July 24  whether additional “anti-dumping” duties will  also be imposed on the products.

SolarWorld, which filed the complaint that  led to imposition of duties, says the Chinese solar  panels in question are being dumped in the  United States at 165.04% below their price in  other markets. It says the dumping margin on the affected Taiwanese  panels is 75.68%. This suggests that the  additional, anti-dumping duties could be large. The US already collects duties of 23.75% to  254.66% on imported Chinese solar cells. The  new duties apply to a different set of products:  Chinese and Taiwanese solar modules made with  cells “completed or partially manufactured”  outside the country where the modules are  completed.  SolarWorld complains that the existing  duties on Chinese solar cells are being circumvented by making solar panels in China using  cells made in Taiwan. Reports suggest that as  many as 70% of Chinese solar panel manufacturers that export panels to the United States use  cells made in Taiwan. The existing duties do not  cover Chinese modules made with non-Chinese  cells.

Although the latest duties also apply to solar  panels made in Taiwan, a questionnaire that was  sent to solar panel manufacturers in China and  Taiwan has led to speculation that solar modules  manufactured and assembled in Taiwan without  Chinese solar cells may be dropped from the case.  The questionnaire asked manufacturers whether  their cells are produced partly in China.

The US government is under pressure from  US solar companies that use Chinese panels to  try to work out a settlement with the Chinese  government.

Duties must be paid by the US importer of  record. The preliminary duties announced in early  June are subject to adjustment later in the year.  A final decision on the duties is not expected  before mid-October at the earliest. US importers  are retroactively liable for any difference plus  interest if the final duties are higher than the  preliminary amounts.

Under US tariff law, if the foreign manufacturer reimburses its customer for the duty,  then the reimbursement is itself collected as  an additional duty.

ARIZONA will start collecting property taxes in  2015 from solar companies that retain ownership  of rooftop solar systems and lease them to  customers after an effort failed in the legislature  to overturn the tax.

The tax is expected to run $152 a year for a  typical system, eating up about 42% of the $360  in annual savings a homeowner realizes by  adding solar. Leases may require homeowners to  reimburse the solar company for such taxes.

By statute, a system that a homeowner  owns and uses to generate electricity for his own  use is not considered to add to the value of the  house for property tax purposes. The Arizona  Department of Revenue said in a 2013 memo  that this provision does not provide any relief  from property taxes to a solar company that  owns a system independently from the house.

The solar company must value the system for  property tax purposes at 20% of its depreciated cost.

ETHANOL PLANTS must be depreciated over  seven years, the IRS said in May.

Some ethanol producers have been depreciating their plants over five years on the theory  that the plants are used to produce chemicals.  Assets used for the “manufacture of chemicals  and allied products” belong in asset class 28.0  and may be depreciated on an accelerated basis  over five years.

However, the IRS said such plants belong in  a different asset class, 49.5, used for “waste  reduction and resource recovery plants” as this  category includes equipment used to “process . . .  biomass to a . . . liquid . . . fuel.” The difference in  depreciation is worth 2¢ per dollar of capital cost.  The loss in tax subsidy to a typical ethanol plant  is about $4 million.

The IRS made the announcement in Rev. Rul.  2014-17. The ruling described a facility that  produces ethanol from corn and sells carbon  dioxide as a by-product.

The latest ruling does not come as a surprise.  The IRS released an internal legal memo in 2008 suggesting  that it was challenging ethanol producers on  their depreciation.

AN INDIVIDUAL WAS AT RISK for half a loan even  though he was unlikely to have to pay on his  guarantee of the loan and may not have been  able to do so.

Michael Moreno used a limited liability  company he owned to buy a Learjet for $7.9  million. The LLC borrowed the full purchase price  from GE Capital. Both Moreno and another  company with substantial assets of which  Moreno owned 98% guaranteed repayment of  the loan. It appears that the LLC was a disregarded entity for tax purposes.

Moreno claimed $4.775 million in depreciation on the jet in the year the LLC bought it. The  IRS disallowed the amount because it said  Moreno was not at risk for the purchase price.  Individuals, S corporations and closely-held C  corporations, meaning corporations in which five  or fewer shareholders own more than half the  stock, can claim losses only to the extent such  taxpayers are at risk. Ordinarily, the fact that an  individual personally guaranteed repayment of  a loan used to pay the purchase price means the  individual is at risk.

The IRS said the guarantee in this case was  illusory.

It pointed to internal GE Capital memos  showing that GE Capital looked solely to the  other, corporate guarantor and did not mention  Moreno as a possible source of repayment when  evaluating whether to make the loan. The IRS also  said Moreno had only $11,537 in liquid assets at  the time. Moreno said he had a net worth of $27  million consisting largely of shares in another  company. Finally, the IRS said that because  Moreno owned 98% of the corporation that was  the other guarantor, he would make sure it paid  on its guarantee before he had to do so.

A federal district court in Louisiana held in  late May for Moreno. It said the government cited  no legal authority that a guarantor must have liquid assets to  support its guarantee. Liquidity of assets is not  the test. It said the government also cited no  authority for its proposition that where there are  two sureties, and the evidence shows the lender  was looking only to one, the guarantee of the  other is ignored.

The court treated Moreno as at risk for half the  loan because of cross indemnities requiring  each guarantor to reimburse the other if there  is a claim. The case is Moreno v. United States.

MINOR MEMOS.The IRS may withdraw a private  letter ruling it issued in 2012 that said investment tax credits can be claimed on solar projects  owned by Indian tribes. The ruling involved an  inverted lease transaction. The issue is whether  such a project is “used by” the tribe. At least two  IRS branches are recommending withdrawing the  ruling. The ruling is Private Letter Ruling  201310001 . . . . An IRS branch chief warned that  the agency is looking more closely at captive  insurance pools. If participants in such a pool are  required to repay the pool with interest for any  claims that are paid by the pool, then the pool is  not really insurance and “premiums” paid to it  are not deductible. The branch chief, Sheryl Flum,  made the comment during an American Bar  Association webinar in late May.