WIND, GEOTHERMAL, BIOMASS, landfill gas, incremental hydroelectric and ocean energy projects in the United States will qualify for tax credits if they are under construction by year end under a bill that cleared Congress on January 1.
This is expected to lead to a rush to start construction of projects later this year.
The owners of such projects will have a choice between two tax credits: production tax credits of 2.2¢ a kilowatt hour on the electricity output for 10 years for wind and geothermal and 1.1¢ for other projects or an investment tax credit for 30% of the project cost. The production tax credit is adjusted each year for inflation. Any investment tax credit is taken fully in the year a project is completed, with the exception that it can be taken on contractor payments during construction for projects that are expected to take at least two years to build.
There is no deadline to complete the projects. It will be up to the Internal Revenue Service to decide what it means for a project to be under construction.
Congressional sources say the intention was for the IRS to follow the same rules as under the Treasury cash grant program for renewable energy projects. Under that program, a project is under construction when the developer has either started “physical work of a significant nature” or “incurred” more than 5% of the project cost.
IRS and Treasury sources confirm that use of the Treasury cash grant definition is likely, but caution that no final decision has been made.
Guidance is expected to take several months.
A meeting among Treasury and IRS and Hill staff is expected shortly to make sure everyone is on the same page.
The IRS will have to decide whether to test when construction has started at wind farms on a turbine-by-turbine basis or by looking at the entire project. The IRS treats each wind turbine, pad and tower as a separate “facility” for production tax credit purposes. Under the Treasury cash grant program, a developer could choose to treat multiple units of property on a single site that will be operated as a larger unit as a single unit of property for testing when construction started, making it easier to treat an entire project as under construction.
The same bill that extended tax credits also extended a 50% depreciation bonus for another year for all new equipment placed in service in 2013. Thus, solar and fuel cell projects would also qualify. The bonus is the ability to deduct 50% of the equipment cost immediately. The other 50% is depreciated normally.
Assets like thermal power plants and transmission lines that would normally be depreciated over 15 or 20 years will have an extra year through 2014 to be completed and qualify for the bonus. However, the bonus can only be claimed on the share of depreciable basis built up through December 2013.
Among other changes, the bill allows projects on Indian reservations to be depreciated more rapidly — for example, for wind and solar facilities over three years instead of five years — for projects placed in service by December 2013.
It authorizes the Treasury to allocate another $3.5 billion in new markets tax credits for each of 2012 and 2013. New markets tax credits are credits of 39% claimed over seven years on investments in low-income areas.
Companies do not have to pay corporate income taxes on 9% of income from their manufacturing operations in the United States. Generating electricity is considered manufacturing. This has the effect of reducing the corporate income tax rate on income from such manufacturing to slightly less than 32%. Companies manufacturing in Puerto Rico qualified for the exclusion through 2011. The bill extends the exclusion for Puerto Rican manufacturing for another two years through 2013.
The bill gives electric utilities another year to sell transmission assets to independent transmission companies and receive an 8-year “spread” on the gain. A utility would normally be taxed fully on the gain in the year of sale. A special rule allows the gain to be reported over eight years. The special rule expired for asset sales after 2011. The bill extends it through December 2013. Congress wants to encourage regulated utilities to divest their transmission assets.
Wind and geothermal lobbyists say they will try to extend production tax credits again as part of any corporate tax reform bill that is taken up in 2013 or 2014 by Congress.
The American Wind Energy Association told Congress in December that it can accept a phase out of production tax credits for wind farms over six years. Under its proposed phase out, projects put in service in 2014 would qualify for 90% of the normal credit, in 2015 for 80%, in 2016 for 70%, in 2017 or 2018 for 60%, and there would be no tax credits for projects completed after that.
Projects that start construction by 2013 would not be affected.
Senator Charles Grassley (R-Iowa), one of the original authors of the production tax credit statute, responded that the credits should phase out over three years.
SEQUESTRATION will take a bite out of Treasury cash grants paid on renewable energy projects on or after March 1, 2013, unless Congress delays the start further.
Automatic spending cuts of $984 billion over nine years were scheduled to take effect on January 2. On January 1, Congress delayed the start by two months and agreed to $24 billion in specific spending cuts and tax increases to pay for the delay.
The US Office of Management and Budget said last September that Treasury cash grants will be subject to a 7.6% haircut if sequestration goes into effect.
The haircuts will not apply to any grant considered an “obligated balance” before sequestration starts. Based on past precedent, a grant would become an “obligated balance” only when a letter or email is sent by Treasury informing a company that its grant has been approved for payment.
Developers complain that it is unfair for the government to have held out a carrot for companies to engage in economic activity during the period 2009 through 2011 when projects had to be under construction to qualify for grants, and then reduce the size of the carrot after companies have already done what the government wanted.
Wind companies are urging the Office of Management and Budget to exempt projects that were in service before sequestration from the cuts. This would remove delays at Treasury in processing grant applications as a factor in where the cuts fall.
A CFIUS REPORT to Congress in December suggests that all proposed foreign investments in US energy projects or companies should be submitted to the government for review before the transactions close.
The report by the Committee on Foreign Investment in the United States — CFIUS for short — lists areas of potential national security concern with foreign investments in US companies and projects. It is an annual report on activities during 2011. For the first time, the report lists as areas of potential concern investments in US companies or projects that “involve various aspects of energy production, including extraction, generation, transmission, and distribution” and projects that are near US military bases or other sensitive US government facilities.
CFIUS was formed by President Gerald Ford in 1975. It is an inter-agency committee, headed by the Treasury Department, on which 16 agencies sit that reviews potential foreign investments in US companies for national security concerns. Submission of proposed deals is voluntary. However, the committee has authority to set aside transactions after the fact that were not submitted for review.
Review takes 30 days. Transactions that raise potential issues then move into an investigation phase that takes another 45 days.
The committee makes recommendations. The President has ultimate authority to block a transaction. Only two transactions have been formally rejected by the President. Transactions that run into trouble are usually withdrawn before they reach the need for a presidential decision.
Before 2006, at most one or two transactions a year were withdrawn. During the period 2006 through 2009, 64 transactions were withdrawn, or roughly 14% of the 469 transactions submitted to CFIUS for review during that period. From 2009 through 2011, the period covered by the latest report, 9% of transactions were withdrawn.
Some of the transactions withdrawn are later resubmitted. For example, there were 111 CFIUS filings in 2011. Of that number, 40, or 36%, took another 45 days beyond the initial 30 for an investigation. In eight, or 20% of the cases that went to investigation, the parties agreed to mitigation measures to address government concerns with the transactions. Because working out a mitigation agreement takes time, it can lead to withdrawal and later resubmission once the mitigation measures have been agreed.
The latest report is interesting for the large number of transactions that were submitted involving investments by long-standing US allies. The largest numbers of filings in 2011 by far were for in-bound US investments from the United Kingdom. The top 10 countries for which filings were made in 2011 and the numbers are United Kingdom (68), Canada (27), France (27), China (20), Israel (18), Japan (18), Holland (14), Sweden (14), Australia (8) and Spain (7).
Another interesting development is the report says for the first time that the US intelligence community believes with “moderate confidence” that one or more foreign governments have directed companies to acquire critical American technologies in a “coordinated strategy.” There were no details in the public report, but the details were shared with Congress. This adds a layer of complexity to evaluating proposed investments by Chinese companies.
In September, President Obama ordered Chinese-backed Ralls Corp. to divest a wind farm that the company bought in Oregon at which it hoped to deploy turbines by its affiliate, the Sany Electric Co. The wind farm is close to a US Navy base that provides training for drone aircraft. The company filed suit in federal district court in Washington in an effort to have the order set aside on grounds that it is an unconstitutional taking of private property without due process.
In the only other presidential action, the first President Bush rejected a proposed acquisition of MEMCO Manufacturing Inc., a supplier to Boeing, by the China National Aero-Technology Import and Export Corporation in 1990.
A proposed $257 million purchase of nearly all the assets of bankrupt US battery maker A123 by Chinese-backed Wanxiang American Corp. is also before CFIUS. The purchase was approved by the bankruptcy court of December 11. It is undergoing a 45-day investigation by CFIUS. The company said in a blog posting in late January that it expects to close on the purchase on February 1.
The defense part of the A123 business was sold to Navitas Systems LLC in Illinois. Wanxiang received approval from CFIUS last year for a $420 million investment for a minority stake in GreatPoint Energy near Boston. GreatPoint and China Wanxiang Holdings have entered into a joint venture to build a $1.25 billion plant in western China for converting coal into cleanerburning synthetic natural gas. Wanxiang has more than 3,000 employees in the United States. Several members of Congress have criticized the sale. Johnson Controls Inc., which lost the bid for the commercial assets, has hired a prominent Washington law firm to lobby against the sale. A123 received a $250 million loan guarantee from the US Department of Energy.
An assistant US Treasury secretary, Marisa Lago, made a trip to Beijing in November to assure the Chinese that there is no general US policy against Chinese acquisitions of US companies.
IRAN TRADE SANCTIONS are getting tougher.
Non-US companies that thought they understood US trade sanctions for engaging in energyrelated transactions with Iran must now revisit them.
A new sanctions measure passed by Congress on January 1 and signed by President Obama the next day puts the energy, shipping and shipbuilding sectors generally off limits. US companies are already barred from trading with Iran. Thus, the new sanctions are aimed at companies outside the United States. Non-US companies that violate the sanctions and financial institutions that facilitate trading risk being locked out of the US economy.
Turkey complained that 20% of its natural gas comes from Iran, so that any sanctions against trade in natural gas would fall disproportionately on Turkish consumers. The new sanctions allow trade in Iranian natural gas to continue, but the money owed Iran would have to be credited to an account in a bank headquartered in the customer country.
The new sanctions apply to sales of Iranian oil and petroleum products, but only during periods when there is a large enough supply of oil and other such products available in global markets at prices that allow substitution for Iranian oil without undue hardship.
The new sanctions also bar trade with Iran in coal, precious metals, graphite, raw or semifinished metals such as aluminum and steel, and computer software for integrating industrial processes.
They will not take effect until July 1, 2013, giving companies time to wind down existing trade.
They come on top of other measures the US enacted last August that will require public companies to disclose in filings with the US Securities and Exchange Commission, starting February 6, 2013, any business activities that they or their affiliates have knowingly engaged in with Iran. The SEC does not have a clear definition of affiliate.
Also beginning February 6, buyers of Iranian oil will no longer be able to pay for the oil in cash. A “buy-local” provision requires that any money Iran is owed will have to be locked up inside an account in a bank in the customer country and used by Iran in that country to buy goods from the local economy. Most countries that buy Iranian oil are running trade deficits with Iran. The new measures should help reverse the deficits.
A NEW US TAX ON INVESTMENT INCOME should be factored into the economics of some transactions.
US individuals are subject to a new 3.8% tax on “net investment income” as of January 1.
The tax applies to anyone earning more than $250,000 a year in adjusted gross income for married couples filing joint returns. The threshold is $200,000 for single persons. The income levels are not adjusted for inflation, so more people will become subject to the tax over time.
The tax applies to interest, dividends, capital gains, rents, royalties and income from two types of businesses. The businesses are trading in financial instruments and commodities and any business in which the individual is considered a passive investor.
“Trading” means seeking to profit from short-term movements in prices. Electricity may be considered a commodity, but generating electricity for sale is not “trading” in electricity.
An individual owning an interest in a power project through a limited liability company or partnership may find his income subject to the tax because he is considered a passive investor. Unless he is engaged personally in the LLC or partnership business for a material number of hours each year, his role is normally considered passive. “Material” usually means more than 500 hours a year, but can be as few as more than 100 hours if his personal involvement in the business is not less than that of any other person.
The tax is on “net” investment income. Some directly-connected expenses can be deducted. An example is a fee that must be paid to a broker for arranging a sale that produced a capital gain.
A taxpayer who has net investment income but is over the income threshold at which the tax kicks in by a smaller amount than his net investment income is taxed only on the lower amount. For example, suppose a single person has adjusted gross income of $270,000 of which $90,000 is net investment income. He is only $70,000 over the threshold at which the tax starts to apply. The tax must be paid on only $70,000.
Partnerships will have to send more complicated forms to partners — so-called K-1s — each year breaking down the type of income the partners are allocated by the partnership.
Interest, dividends, rents and royalties retain their character when they pass through the partnership, but they will not count as investment income if received by a partnership in the ordinary course of its trade or business. Thus, for example, a partnership in the business of leasing solar panels to homeowners receives rent and interest on late rental payments. These amounts are not investment income to the partnership. Therefore, they are not investment income when they pass through to partners. However, any partner who is considered merely a passive investor would have to report all the income he is allocated by the partnership as investment income.
A partner selling his partnership interest at a gain must treat the gain as investment income. Capital gains from the sale of property held in a trade or business are not investment income. However, the Internal Revenue Service suggested in proposed regulations to implement the new tax in December that a partner generally is not considered to hold his partnership interest in a trade or business.
The proposed IRS regulations will require complicated calculations to determine the share of gain any partner has when selling his partnership interest that will be subject to the 3.8% tax. The calculations are supposed to put the selling partner in the same position as if he had sold his share of the partnership assets directly. The partnership may have a different “basis” in its assets than the partner has in his partnership interest. The adjustments are intended to calculate his gain as if the partnership made a deemed sale of its assets and allocated the partner his share of gain immediately before the partner sold his partnership interest.
The tax is in section 1411 of the US tax code.
FIXED-PRICE PURCHASE OPTIONS could spell trouble in some equipment leases.
A US appeals court in Washington suggested in January that it is a problem to give a lessee an option to purchase equipment at the end of the lease term if exercise of the option is “reasonably expected.” The court said the lessee will be considered the tax owner of the equipment from inception.
This is a different standard than the market has been using.
Nearly all tax counsel have viewed purchase options as a problem only if exercise by the lessee is “reasonably certain”: for example, because the exercise price is expected to be below the equipment value at the time or because other facts will compel the lessee to exercise.
The decision may spell trouble for leases with fixed-price purchase options in transactions that would be reviewed by the US appeals court for the federal circuit. The United States is divided into 11 geographic circuits, one District of Columbia circuit and one federal circuit. Cases heard first in the US claims court are appealed to the federal circuit.
The case involved Consolidated Edison in New York. The company entered into a complicated cross-border lease transaction called a LILO in 1997 with Dutch electric utility EZH. The utility leased a 47.47% undivided interest in a gas-fired combined-cycle power plant to Con Ed for 43.2 years and then subleased it back for 20.1 years. Con Ed paid $120 million in rent under the head lease at inception. It agreed to pay another $831.5 million in rent on the last day of the term if EZH had not exercised an option before then to buy out the Con Ed leasehold interest.
EZH had an option to purchase the leasehold interest at the end of the 20.1-year sublease for $215 million.
Con Ed had an appraisal from Deloitte that concluded there was no economic compulsion on EZH to exercise because the leasehold interest was expected to be worth less at the end of the sublease than the option price. However, the court was not persuaded because EZH was expected to have slightly more than the $215 million option price available to it by then in two defeasance accounts into which the initial rent payment was deposited, “rendering the option effectively costless to EZH.” The court said the appraiser also failed to address the consequences to EZH of not exercising the option.
The court said the question is whether exercise is “highly probable” — whether someone in Con Ed’s position would have “reasonably expected that outcome.”
It pointed to statements by Con Ed to its accountants, Price Waterhouse, when the transaction closed that exercise was “reasonably assured” and by the outside financial advisers in a transaction structure memo when the deal was being put together that “it is reasonable to assume . . . that [EZH] will exercise the purchase option.”
The case is an example of how bad facts make bad law.
Nevertheless, it may make some tax equity investors more wary of fixed-price purchase options.
It is a reminder to insist on careful analyses in appraisals.
It should not affect transactions with options to purchase at fair market value determined when the option is exercised. It may affect the choice of venue when litigating tax cases in tax equity transactions.
CALIFORNIA said a property tax exemption for new solar facilities applies not only to solar panels mounted on rooftops, but also to largescale solar projects.
New solar systems in California enjoy a one-time exemption from property tax assessment. An assessment will be triggered if the project is later resold or there is a change in control of the company owning the project. Property taxes vary by county. They can be as high as 2% of assessed value, and must be paid annually.
The State Board of Equalization rejected a suggestion by Inyo and Riverside counties in November that the exemption does not apply to utility-scale projects.
In December, the board released a set of final guidelines for local property tax assessors about the solar tax exemption.
The exemption grew out of a ballot initiative called Proposition 7 that the California voters passed in 1980 and that was later implemented by the state legislature as section 73 of the state tax code. It has had to be periodically renewed by the legislature and will expire at the end of 2016 unless renewed again.
The exemption applies only to “active solar systems” that are assessed locally. California assesses power plants that are 50 megawatts or larger in size and are owned by “electric corporations” at the state level. Other projects, including solar projects that are “qualifying facilities” for federal regulatory purposes (which covers most solar projects of up to 80 megawatts in size) are assessed locally.
According to the guidelines, if a builder completes a new house with a solar system on the roof and has not sold the house by the lien date when real property is assessed, then the builder will use up the one-time solar exemption, and anyone buying the house later will have to pay annual property taxes on the system.
Tax equity transactions to finance solar systems in the state should not be treated as a change in ownership that triggers an assessment. However, there are limits.
A sale-leaseback of a system within three months after the system was originally put in service is okay. However, an assessment will be triggered when the lessee exercises any purchase option. Partnership flip transactions, including the later flip down in the tax equity investor’s ownership interest, do not trigger an assessment. However, if the solar company or a third party later acquires more than a 50% interest in partnership profits and capital — other than the flip that occurs automatically under the partnership agreement — then an assessment will be triggered.
In a utility-scale plant, the solar “facility” that escapes property taxes is all the equipment through the step-up transformer.
Parking lot canopies qualify for the exemption as part of the solar system if they are built mainly to provide a mounting surface for solar panels while only incidentally providing shade for autos.
Leasing a solar system to a customer does not trigger an assessment. Neither does a change in the customer to whom the system is leased. The average homeowner in California remains in his house only seven years. A sale of the house to a new owner who assumes the lease will not subject the solar system to property taxes. However, the guidelines say that a buyout payment by the original customer to terminate the lease would trigger assessment. It is hard to understand the logic, since ownership of the system has not changed.
Contributing a solar system to a legal entity will trigger an assessment, unless each owner retains the same ownership percentage interest in the system after the contribution as before.
A change in control of an entity that owns the solar system will trigger assessment. The exemption will also be lost if the entity’s “original co-owners” cumulatively transfer more than 50% of their ownership interests in the legal entity.
Solar companies sometimes have an easement to put their systems on customer roofs in cases where the customer is merely leasing a system or buying electricity. The guidelines warn that the solar company may have a taxable possessory interest in the roof that is not covered from the property tax exemption for the solar equipment.
TREASURY CASH GRANTS are at issue in two more lawsuits.
W.E. Partners, LLC sued the US Treasury in the US claims court on January 22 in connection with the so-called section 1603 program under which owners of new renewable energy projects are paid 30% of the project cost by the Treasury in cash.
There are now five pending lawsuits under the program.
W.E. Partners built a small biomass-fired cogeneration facility to supply steam and electricity to a Perdue chicken rendering plant in North Carolina. The cogeneration facility cost $9 million and has the capacity to generate 495 kilowatts of electricity and 63,000 pounds per hour of steam.
The Treasury paid a grant of only $943,754 on the facility rather than the $2,711,331 the company was seeking.
The Treasury position in the past has been that the owner of a facility that uses biomass to generate both steam for industrial use and electricity is entitled to only a partial grant. The grant is a fraction of the full grant, with the fraction equal to the electricity as a percentage of total useful energy output. The legal basis for the position is unclear.
W.E. Partners argues that the steam should be ignored because all the steam passes first through the steam turbine to generate electricity before any of it is put to use by Perdue as steam.
Another developer, Nevada Controls LLC, sued the US Treasury in the US claims court on December 7.
Nevada Controls misread an email from the National Renewable Energy Laboratory, which reviews cash grant program applications under contract to the Treasury, in June 2010 to suggest that it did not have to file preliminary applications by September 30, 2012 for its remaining projects that were not yet in service.
The company submitted a preliminary grant application in early June 2010 for a small hydro project that the company said it expected to place in service the same month. Developers were obligated at the time to let the Treasury know of any remaining claims on the grant program by September 30, 2010. Projects put in service after 2010 qualified for grants only if they were under construction by December 2010.
Congress later extended these deadlines. NREL wrote back that that there was no need to file a preliminary grant application for such a project. “Given the proximity in time between your application and the date you expect to place the property in service, a determination of whether you have met the begun construction requirements would not serve any purpose and could delay a final determination with respect to your property once it is placed in service.” It asked the company to withdraw the application.
The company read the email to suggest it did not have to file preliminary applications for any of its projects.
It said it lost grants of $553,716 on four small wind turbines it placed in service in October 2012 and a small hydro project that it expects to complete in March 2013 due to the “US Treasury’s direction not to file” preliminary applications. Preliminary applications had to be filed for these projects by September 30, 2011.
PREPAID POWER CONTRACTS OR LEASES may create complications when assets are sold. Some wind and solar companies that sell electricity under long-term contracts are paid in advance by the offtakers or customers.
They do not report the advance payments immediately as income but rather report income over time as the electricity is delivered. If the assets used to supply the prepaid electricity are later sold — for example, in a tax equity transaction — it is unclear what tax basis the buyer should take in the assets, according to a paper the tax section of the New York State Bar Association sent the IRS and Treasury in January.
The bar association said there are two possible answers.
One, which it called an “assumption approach,” is to treat the buyer as having assumed a contingent liability. For example, suppose a buyer pays $1.2 million for a solar project for whose electricity a customer has paid in advance, and the buyer is expected to have to spend $800,000 to deliver the electricity, but the actual amount the buyer will have to spend cannot be known with any certainty.
The buyer values the asset by subtracting this contingent liability. Therefore, were it not for the obligation to deliver the electricity without any further payments from the customer, he might pay $2 million for the project. Instead, he pays the net amount of $1.2 million and takes that as his basis in the project for depreciation. As he spends money in the future to deliver the prepaid electricity, he adds the amounts he spends to his basis in the assets. If he bought a project for $1.2 million in cash and assumed debt of $800,000 he would have a basis of $2 million. However, contingent liabilities do not go into basis until they are paid.
The bar association calls the other possible approach a “fragmentation approach.” The buyer would be treated as having paid the seller $2 million, but then having received $800,000 from the seller to assume the contingent liability. The buyer would have a basis of $2 million for depreciation. He would have immediate income of $800,000.
The bar association urged the IRS and Treasury to issue guidance. It called the issue one of “longstanding uncertainty.”
Its paper is called “Report on Treatment of ‘Deferred Revenue’ by the Buyer in Taxable Asset Acquisitions” and is dated January 7, 2013.
CHINA, which plans to install 10,000 megawatts of additional solar capacity this year and is on track to reach its current goal of 21,000 megawatts of solar generating capacity by 2015, may double the 2015 target to 40,000 megawatts, according China’s official Xinhua news agency. Analysts say that the increase is not enough to soak up the global glut of manufacturing capacity for solar panels.
The country plans to increase its wind capacity by 30% in 2013.
Total electric generating capacity from all sources increased by 58% from 2007 to 2012 and is currently 1,140 gigawatts. This compares to total generating capacity in the United States at the end of 2011 of 1,018 gigawatts.
HYDROGEN ENERGY CALIFORNIA was awarded the right to claim an investment tax credit of up to $103,564,000 by the IRS in January.
The credit is 30% of the eligible cost of a hydrogen-fueled power plant that the company plans to build in Kern County, California. The hydrogen will be produced from non-potable water using coal and petroleum as fuel. The plant will produce a low carbon fertilizer in addition to electricity. The carbon dioxide emissions will be captured and used for enhanced oil recovery. The project cost will be paid in part with the help of a $408 million grant from the US Department of Energy.
The investment tax credit is a special credit under section 48A of the US tax code for advanced coal projects. The project must be placed in service within five years after award of the tax credit.
The company will probably have to do a saleleaseback to get value for the tax credit.Alternatively, if it can find a strategic investor, it should be able to claim it on progress payments to contractors during construction.
CONDEMNATION PAYMENTS that an electric utility received from a highway authority to reimburse the utility for the cost of moving power lines and other utility equipment out of the path of a new turnpike did not have to be reported by the utility as income.
Amounts that a company receives in an “involuntary conversion” of its property to cash do not have to be reported as income as long as the amounts are reinvested within two years in similar property. The utility asked for a private ruling from the IRS confirming there was no income in its case. The ruling is Private Letter Ruling 201252010. The IRS made it public in late December.
MINOR MEMO: The median price for a rooftop solar system installed in the United States in 2011 was $6.13 a watt for residential and small commercial systems of 10 kilowatts or less, and $4.87 a watt for commercial systems larger than 100 kilowatts, according to a report by the US Department of Energy in November. The average cost for utility-scale solar photovoltaic projects was $3.42 a watt. Prices are falling at an accelerating rate. Prices declined 5% to 7% a year from 1998 through 2011, but at an 11% to 14% rate in the last year of that period and may have fallen by as much as 25% to 29% if one compares Q4 2010 to Q4 2011 prices. According to the Department of Energy, analysts expect global average module prices to be almost 50% lower in 2013 than in 2011: 74¢ a watt compared to $1.37 a watt in 2011. The department said there are no analyst projections for the balance of system costs. The report is called “Photovoltaic (PV) Pricing Trends: Historical, Recent, and Near-Term Projections.”