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#1: Perspectives on Investing in Power Development in the ERCOT
Market: The ERCOT market structure has been criticized for not providing adequate price signals  to build new generation. Is the recent increase in price ceiling high enough to trigger  construction of new generation? Will low gas prices drive new builds, or are they  expected to stay too low to provide adequate profit margins to justify new projects?  Are further market structure adjustments needed?

Panelists
Ann Banks, Chief Commercial Officer, SUMMIT POWER GROUP
Bill Brod, Commercial Director, AES CORPORATION
Patrick Woodson, Chief Development Officer, E. ON CLIMATE & RENEWABLES

#2: Perspectives on Financing ERCOT Market Projects: Why has so little power plant construction gone on recently in ERCOT? Do the current market conditions favor financing power plants in Texas? What needs to happen to motivate investors and financial institutions to commit resources in ERCOT? Leading  private equity investors and lenders will share their perspectives on the ERCOT market.

Panelists

Milton L. Holloway, Ph.D., President & Chief Operating Officer, CENTER FOR THE  COMMERCIALIZATION OF ELECTRIC TECHNOLOGIES
Jeff D. Hunter, Executive Vice President & Chief Financial Officer, USPOWERGEN
John Jones, Managing Director, Power & Renewable Energy, GE FINANCIAL SERVICES
Tuan Pham, President, POWERFIN PARTNERS

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By Robert A. Webb, Esq.

            The Public Utility Commission of Texas (PUCT) has been wrestling since the summer of 2011 with the problem of providing sufficient incentives to get new generating plants built to serve load within the Electric Reliability Council of Texas (ERCOT) grid.  Unlike most other states, Texas has continued to experience substantial growth in both peak demand for electricity and total annual electric consumption, especially within ERCOT.   In its competitive market ERCOT must rely on market forces to provide enough incentives for construction of new generating capacity.  On June 1, ERCOT filed with the PUC a report on providing sufficient new generation in ERCOT that it had commissioned from the Brattle Group.  This report summarizes the background to that Brattle Report and the Texas PUC proceedings regarding that Report through October 31, 2012.

The Problems of Project Financing for ERCOT Generation

            The weakness in U.S. financial markets has made it difficult to finance new generating capacity in ERCOT because both its wholesale and retail segments are competitive free markets without the security of monopoly territories and captive customers (except for municipal electric systems and rural cooperatives).  Therefore, the security offered to regulated utility monopolies, including the ability to ask for higher rates if costs increase, are not available to generating plants serving ERCOT and those that invest in those plants.  This lack of utility protection from free markets has frightened traditional sources of electric utility capital, which look for a protected long-term revenue stream from sales of electricity.  

The Difficulties Posed by a Wholesale Electric Market Energy-Only Pricing

            Beginning in 1999, ERCOT has been transformed from a traditional market of regulated monopoly utilities into an unbundled market of generators, wires utilities and retail electric providers (REPs).[1] Only the wires companies remain “electric utilities” with rate and certificate regulation by the Public Utility Commission.  Generation companies sell into competitive wholesale markets under general supervision by the PUCT and specific protocols established by ERCOT itself.  REPs compete for retail customers in a competitive market under service rules established and enforced by the PUCT and the market protocols set by ERCOT, but REP prices are set by bilateral contracts with end-users, with a safety net of providers of last resort.

Under the competitive market model in ERCOT, new generation typically is built with project financing and is subject to full market risk without rate base guarantees.  Generators sell directly to REPs, or to power marketers who act as intermediaries for REPs, under bilateral contracts or into either the day-ahead or spot markets administered by ERCOT.  Unfortunately, most power purchase agreements (PPAs) are limited in term because any given REP has difficulty making a long term contract with a generation for the simple reason it cannot get a long-term contract with its retail customers.  Without long term power purchase commitments, a generator cannot give investors a guaranteed long-term revenue stream to provide payments of debt or returns on equity.  Collectively, the same aggregate market still exists, but only with the “captive customers” of a utility monopoly can a generator access this collective security for the benefit of its investors.

The market price of wholesale power in ERCOT is unknown as to generators with bilateral contracts because these contracts are confidential to the parties.  However, the spot and day-ahead market prices are known because they are set on the basis of bid stack matching performed by ERCOT and released to the marketplace in essentially real time.  Unfortunately, these are energy-only prices, adjusted for nodal values at the time of sale.  Economic theory tells us that energy-only prices will be based upon marginal cost of production reflected in each generator’s bid with an actual price determined by the highest accepted bid.

The Arithmetic of Average Cost Pricing Versus Marginal Cost Pricing

            The problem with energy-only pricing of electricity is one of simple arithmetic.  Under traditional utility ratemaking all the costs for a test year, including allowed return on investment, are determined in a rate case and then allocated to the various rate classes.  After that, the costs allocated to capacity are divided by the test year capacity billing units, and the costs allocated to energy are divided by test year sales volumes in each class.  Thus, price is based on average cost rather than marginal cost.  Therefore, unless there is a mistake in projected billing units, the utility expects to recover its total costs of both energy and capacity.  In other words, average cost multiplied by reasonable projected volumes equal recovery of total costs of the utility.  Even if actual sales volumes were either somewhat above or below test year figures, lower volumes are accompanied by lower variable costs, while higher volumes produce additional revenue to help cover higher costs.

There is no such ability to equal, at least roughly, total cost recovery for new generation in an energy-only market.  The principal reason is that inflation normally means new plant costs more than old plant costs.  Under that assumption the marginal cost of energy in a market of both new and older plants cannot bridge the gap of increased costs of new plant unless the new plant is much more efficient than average plant.  Studies introduced into discussions at the PUCT on incentivizing new generation demonstrate that this happy offset of greater efficiency to the greater unit cost of new plants rarely occurs for any of the generation technologies currently available for the ERCOT market.  In fact the Brattle Report and other sources demonstrate that the opposite is true.

Shortcomings of Energy-Only Pricing in Incentivizing Peak Generation

            Historically, it has been cost-prohibitive to store electricity for future use.  Capacitors and similar devices can provide limited stored electricity to correct power factors or aid in control of transmission frequencies, but for the most part electricity must be generated at levels to meet total system load at all times.  When generating reserves are exhausted, or forced outages drop significant generation off-line, the grid must instantly shed load or risk the collapse of the entire grid.  As a practical matter, this means system dispatch must be able to drop load under a demand response plan or simply cut off circuits with enough cumulative load to restore system balance and maintain voltage levels and frequency.

Absent cost-effective storage of large amounts of electricity, utilities in Texas traditionally have turned to simple cycle gas turbines as an insurance policy for adequate peak capacity on their systems.  For a regulated public utility the capital costs of these turbines were recovered in capacity payments from customers.  The capability of these turbines was assumed to be needed only a few hours in the average year.  Their higher heat rates required more fuel and their maintenance costs were spread over far fewer MWH, but the fixed costs recovered in rate base carried the bulk of the costs of this peak load insurance.

When utility companies were unbundled, and generation of all types was on its own for cost recovery, the simple cycle gas turbine no longer made sense for competitive generators.    The ERCOT Independent Market Monitor (IMM) has reported that in the last ten years the model gas peaking unit has only recovered an adequate return once (in the record heat of 2011).  In some years many simple cycle turbines might not have run at all, except to ensure the unit was still operational.  While ERCOT generators no longer make public the cost of operations of their generating units, FERC reports from Texas electric utilities outside ERCOT confirm the minimal usage of simple cycle gas turbines in recent years.

Some utility systems have found that it is cheaper to use kinetic energy from pumped-storage reservoirs for peak power.  The idea is to take power produced at night (or other times when power demand is low and prices are cheap) to pump water into a reservoir at higher elevation.  The water is released at times peak power is needed at virtually no variable cost.  Capital costs and the energy to pump the water uphill are recovered in the overall cost of service.  Again, this may not work in ERCOT and would also be difficult because of water use and lack to natural elevation in ERCOT. Alternative electric storage technologies are being developed but will not be available for significant peaking power for a few years. 

A Short History of Incentive Payments for ERCOT Generators

            While market profits were sufficient to attract investment in new generation power in the initial years of the ERCOT free market, the situation has changed due to a number of external factors.  Nuclear plants have been plagued with breakdowns and natural disasters, coal and lignite plants face more stringent environmental rules, and gas plants face the paradox that very low gas prices make investments in new gas capacity riskier because even very old existing gas capacity can afford to keep running and new, more expensive plants cannot project adequate earnings, especially with their vulnerability to volatile natural gas prices and potential expenses related to their carbon emissions.  Renewable resources have their own problems.  Wind in West Texas tends to blow in the winter and at night, which does not match periods of peak load.  Congress appears to be ready to allow wind production tax credits to expire at year-end, severely impacting wind power economics.  Solar power production does track peak load periods but has until very recently been more expensive than other alternatives.  In addition system operators complain of “intermittency” of both wind and solar electric production.

As a consequence of this combination of factors, construction of new generation to serve ERCOT has virtually come to a complete halt.  With the exception of a major coal plant whose completion has been delayed by a serious accident, new fossil-fueled generation is not in the schedule until 2014.  Most of the wind and solar units for the next two years face delay or cancellation because of uncertainty as to tax credits for investment or production. The only exceptions are municipalities and cooperatives, which can rely on their control of retail rates and freedom from retail competition to support new generation.

The slowing pace of generation additions in ERCOT and its consequent impact on forecast reserve margins has been apparent for a while, but it was the record heat of 2011 and the unanticipated sharp growth in ERCOT system peak load that got the PUCT moving at a faster pace.  Docket No. 37897 had been initiated to examine the potential impact of proposed EPA regulations on coal, lignite and natural gas units, especially on the older units.  Workshops built around the initial study of the Brattle Group began in February 2011 and continued through August.  The Commission Staff then pulled together an amended rule on price caps, which was adopted on June 28, 2012.  The ERCOT price cap was raised from $3,000 to $4,500 per MWH, to be effective August 1, 2012.  The commissioners then opened a second rulemaking in Docket No. 40268 to consider further increases in the price cap, which was adopted on October 25, 2012. 

The Sudden Emergence of Support for a Capacity Payment

            After their work on the potential impact of tougher EPA rules on generation serving ERCOT, the Brattle Group was hired by ERCOT to provide a comprehensive report on what would be necessary in the way of additional incentives to get investors to finance sufficient new generation, or alternatives like demand response programs, to maintain the target reserve margin established by ERCOT.  That Report was delivered on June 1, 2012, and was filed by ERCOT in Docket No. 37897.  The lengthy Report presented a number of alternatives but chiefly focused on raising the price cap level and modifying other techniques of dealing with peak load (such as pricing reserves released into the market at peak periods).

These issues were discussed at Commission Open meetings and in a workshop in a new Docket No. 40480, which took place on July 27, 2012.  Brattle emphasized that one question the Commission should consider is what degree of reliability the Commission wanted in an ERCOT reserve margin as there would be a substantial difference in the peak prices necessary to maintain higher reserve margins.  Brattle also pointed out that relying exclusively on market-based energy-only pricing would be less reliable and more expensive than adding some form of a guaranteed capacity or reserve pricing specifically to attract additional resources to meet ERCOT’s peak load.  The Brattle Report listed a range of five types of incentives for either generating capacity or load reduction (or both) in their Table 18:

The commissioners were initially cool to any idea of capacity payments but agreed further workshops were necessary.  The next workshop was held on September 6, 2012, to address the reserve margin issue and the potential capacity payments.  The Commission also set yet another proceeding, Docket No. 40000, to address all the issues on adequate generation for ERCOT with further dockets to be set up for specific proposed rule changes.  Docket No. 40000 is designed to be a generic proceeding to work through what is likely to be a prolonged study of pricing and generation incentives in the ERCOT competitive market.

September 6, 2012, Second Workshop on Brattle Report

            At the September 6 Workshop, ERCOT filed a one page exhibit prepared by Brattle that answered PUC Chairman Nelson’s question about the cost to rate payers of alternative plans to provide generation incentives.  The Exhibit sets forth the following information:

“Brattle spokesman Sam Newell explained that even with a shift to a $9,000/MWH price cap and other modifications being addressed in Docket No. 40268, an energy-only price would produce total revenues of just $18.3 billion in an average weather year.  That revenue would be sufficient to support only an 8% reserve margin.  In Mr. Newell’s opinion, that low a reserve margin would produce “multiple” blackout conditions each year.  He suggested that “over a dozen” would be a likely number.  If capacity payments were added however, the total revenue requirement would increase only slightly, but the new capacity that would be built would significantly increase the reserve margin. At the same time the added capacity would cut the duration of high peak prices (which produces the significant decreases in energy-only revenues).”

While no work papers that the author knows of have been provided listing the assumptions in the calculations, the projected impact is significant.  By adding $2.1 billion in capacity payments, energy-only payments would drop to $16.3 billion (because of the new capacity engendered by the capacity payments), so the total cost to customers would only be $18.4 billion, a mere $100 million increase, while the reserve margin would go to 10%.  If the capacity payments were set at $4.7 billion, the energy-only revenues would drop to $14.0 billion. Therefore, the total cost to consumers would rise to $18.7 Billion, a $400 million increase, but the reserve margin would go to 14%, which would virtually eliminate any threat of blackouts.  The nature of the capacity payments and to whom they might go were not explained, and there were widely varying opinions as to how or whether such a system might work.

Prior to the second PUC workshop on the Brattle Report, approximately 30 parties filed proposals or comments related to the incentives presented in the Brattle Report.  The PUC invited Brattle and thirteen of the stakeholders that had filed comments to make presentations at the Second Workshop.  No renewable energy representatives or consumer representatives were invited (except representatives of large industrials and the Coalition of Cities Served by Oncor).  Unlike the First Workshop, there was no provision for public comment after the invited presentations.

On September 5, Brattle filed a chart summarizing the specific capacity payment positions of those parties filing support for a particular proposal or type of plan:

The various participants presented in three panels on September 6, 2012, after Brattle went over its initial summary of the capacity plans filed and suggested what it thought could be appropriate for ERCOT.  There were numerous questions from the commissioners and substantial interaction between presenters.  After the panels were finished, the Commission asked Brattle spokesman Sam Newell and the Independent Market Monitor (IMM) for ERCOT, Dan Jones, to respond.   As is the case with all Commission Open Meetings, which is the designation given both Brattle Report workshops, a reporter’s transcript was taken and the proceedings were televised. [2]

In preparation for a Commission discussion at the September 13 Open Meeting on where to go next with the Brattle recommendations, Commissioner Pablos filed a memo on September 12, 2012, including a set of comparisons he had requested ERCOT to prepare with the aid of Brattle.  He stated he wanted a road map for approaching the whole concept of additional incentives for new generation in ERCOT.  The result was the following tables[3]:

At the September 13, 2011, Open Meeting the commissioners had a broad discussion about Docket No. 40000.  They concluded that there was not enough information either to set a different ERCOT target reserve or to decide on a form of capacity payments to meet peak demands.  Staff was instructed to be ready with option for further workshops or new rulemakings at the September 28, 2012, Open Meeting.  Chairman Nelson also stated that the Commission would entertain at that meeting the proposed rule in Docket No. 40268, which would raise the ERCOT price cap in annual steps from May 1, 2013, though May 1, 2015, to as much as $9,000/MWH.

On September 19, ERCOT filed an updated CDR for ERCOT for 2013 through 2016, reflecting recently announced changes in generation construction plans and the availability of certain “moth-balled” gas and coal units.  The table summarizing these changes shows better reserve margins.  With the moth-balled capacity included, reserves are satisfactory; if such capacity is excluded, the numbers drop below the official reserve margin after 2013:

September 28 Open Meeting Postpones Vote on Docket No. 40268 Rule

            The day before the Open Meeting scheduled for September 28, Commissioner Anderson filed a memo to his fellow commissioners stating he was willing to vote for the proposed price cap revisions for 2013 and 2014 but that he believed that the further move to $9,000/MWH as of June 1, 2015, was premature due to the ongoing debate concerning a shift from energy-only pricing in ERCOT to a model implementing some form of capacity payments.  Chairman Nelson agreed that she wanted more time to consider developments, and Commissioner Pablos stated he shared that opinion, especially since Brattle had delivered a revised “road map” to changing the ERCOT wholesale market, which he had previously requested.  The Commissioners agreed that the vote on the rule would be postponed until October 25.

Chairman Nelson also announced that after the Open Meeting on October 25 there would be another workshop.  Brattle had committed to file “composite” evaluations of the pending energy-only pricing proposals and those with some form of capacity payment.  The new Report was to be filed by Friday, October 19, with any responses due by noon on Tuesday, October 23, 2012. Brattle would present its report and answer questions from the Commission and Staff.

The Brattle filing of October 19, 2012, recommends going to a capacity pricing market design, but retention of scarcity pricing rules with price caps and other limits.  The details are lacking in the relatively brief slide presentation, but the capacity plan elements raise numerous issues for renewable generation and residential customers:

Subsumed in the Brattle list are potential questions of restrictions on contracts by wind or solar generators and the prospect of allocation of the bulk of increased costs to residential and small commercial customers.  There is no indication of reflecting the value of different levels of reliability in the prices to different groups of customers, who in a free market should pay to get their preferred level of reliability.  By transferring substantial revenues from energy prices set by the marketplace to required capacity payments under standards set by government, there is a substantial threat that the political influence of big consumers and fossil-fuel interest will produce “more of the same” in carbon discharges, water use, and other adverse environmental impacts.

The discussion at the October 25, 2012, Workshop was limited to two Brattle presentations and questions and responses of the commissioners and a few others from whom the Commission sought input.  While the discussion was animated, there were no opponents to the basic plans heard at the Workshop.  At the end of the session, Chairman Nelson announced that she had changed her position and with some reservations now supports the need for a capacity payment plan of some sort. She also announced that she would vote for the Staff proposed rule in Docket No. 40268.

The Commission then held their vote on the proposed rule.  They adopted Staff changes, which set price caps of $5,000/MWH as of June 1, 2013, $7,000/MWH as of June 1, 2014, and $9,000/MWH as of June 1, 2015.  They also adopted Commissioner Anderson’s suggestions to set the peaker net margin at $300,000/MW for 2013 and to establish a system for annual re-sets of that figure.  The Final Order on the amended rule, which was filed in Docket No. 40268 on October 30, contains a good summary of the positions taken by various stakeholders and the Commission’s response on each topic.

Further hearings or workshops have not yet been set, but ERCOT’s CEO Trip Doggett provided an adequacy update to the Texas House State Affairs Committee on October 24, 2012.[4]  A number of reports from the PUC and ERCOT are due to be filed before the 2013 Texas Legislature convenes in early January.  There may be a slowdown in PUC activity as the commissioners gauge the attitude of the members of the House and Senate on the ERCOT wholesale market structure proposals.

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The Butler Firm founder Clay Butler has been invited to be a panelist at the annual Texas Renewables Event scheduled for December 10 through December 13 at the Lost Pines Resort in Bastrop, Texas, just outside Austin. Clay will be on the Texas Legislative and Regulatory Policy Panel offering is insight and experience on Renewable policy and regulatory matter in Texas. Other panelist include Emily Duncan, Manager of Government Affairs, SEIA; Jeff Clark, Executive Director for the Wind Coalition; Colin Meehan, Clean Energy Analyst, Environmental Defense Fund; and Heidi VanGenderen, Director of Public Engagement, Office of the Secretary, U.S. Department of Energy.

For more information regarding Texas Renewables 2012 or to register: Click Here.

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By Clay A. Butler, Esq.

With the expiration of the 1603 program and the imminent expiration of the production tax credit in late 2012, the focus of federal tax-incentivized renewable energy development becomes the investment tax credit (“ITC”) and Modified Accelerated Cost-Recovery System (“MACRS”).  This article provides detailed answers to some frequently asked questions pertaining to the ITC and MACRS as it applies to solar energy projects.

1. What is the statutory authority for the ITC?

Section 48(a) of the Code provides for an energy credit equal to 30 percent of the cost basis of qualifying energy property placed in service before January 1, 2017.

Section 48(a)(3)(A)(i) of the Code provides that energy property includes equipment which uses solar energy to generate electricity, to heat or cool (or provide hot water for use in) a structure, or to provide solar process heat, excepting property used to generate energy for the purposes of heating a swimming pool.

Federal Income Tax Regulations § 1.48-9(a)(2) provides that in order to qualify as “energy property” under § 48 of the Code, property must be depreciable property with an estimated useful life when placed in service of at least three years and constructed after certain dates.

Section 1.48-9(d)(1) of the regulations provides as follows:

(d) Solar energy property–(1) In general. Energy property includes solar energy property. The term “solar energy property” includes equipment and materials (and parts related to the functioning of such equipment) that use solar energy directly to (i) generate electricity, (ii) heat or cool a building or structure, or (iii) provide hot water for use within a building or structure. Generally, those functions are accomplished through the use of equipment such as collectors (to absorb sunlight and create hot liquids or air), storage tanks (to store hot liquids), rockbeds (to store hot air), thermostats (to activate pumps or fans which circulate the hot liquids or air), and heat exchangers (to utilize hot liquids or air to create hot air or water). Property that uses, as an energy source, fuel or energy derived indirectly from solar energy, such as ocean thermal energy, fossil fuel, or wood, is not considered solar energy property.

2. What portion of the investment can be claimed?

On October 3, 2008, Congress, through the Energy Improvement and Extension Act, extended the energy ITC for solar projects through December 31, 2016.[1]  Internal Revenue Code Section 48 accordingly provides for a tax credit equal to 30 percent of the “basis” of eligible “energy property” that a tax filer places in service during the period from 2006 through 2016. Eligible “energy property” includes solar energy equipment as described above, but generally does not include buildings or structural components.[2] A tax credit is a dollar-for-dollar reduction in the income taxes that the person claiming the credit would otherwise have to pay the federal government. Determining the basis in the property is among the keys to accurately calculating the value of the ITC.

A company’s “basis” is the portion of its investment in eligible property upon which the ITC can be claimed. Basis is generally the cost of the property and, in certain circumstances, may also include a capitalized portion of other costs related to buying or producing the property (e.g., permitting, engineering, developers fees and interest during construction). In a simple example, if equipment costs $100,000, the solar credit would be 30 percent of the cost basis of $100,000, or $30,000.

In many cases, a solar project developer will not have sufficient tax liability to make immediate use of the ITC. In order to get value for the tax benefits associated with the project, the developer may engage in a ‘tax equity’ transaction. Such transactions involve a partnership or lease between the developer and tax equity investor. In some cases, basis for the ITC or 1603 award is calculated on the fair market value of the project. For example, a taxpayer that buys a project from a developer in an arm’s-length ‘sale-leaseback’ transaction may ordinarily use the purchase price as its basis.

The Treasury Department has published and posted to its Section 1603 website an outline of the process used by the Section 1603 review team to evaluate basis and the principles that guide the process.[3] Although these principles are published in the context of the 1603 cash grant, they are the same tax concepts used to determine tax basis for ITC purposes as well.

3. What is the evaluation process by the IRS?

As stated in Bryant v. Commissioner of Internal Revenue (790 F.2d 1463), “the courts have determined that in certain circumstances, a taxpayer’s stated cost for an asset does not reflect the true economic cost of that asset to the taxpayer and will be ignored for purposes of determining the basis of the asset.” For example, a stated cost may be inconsistent with the eligible property’s true basis “where a transaction is not conducted at arm’s-length by two economically self-interested parties or where a transaction is based upon ‘peculiar circumstances’ which influence the purchaser to agree to a price in excess of the property’s fair market value.”[4]

The first step the review team takes to evaluate the claimed basis for solar photovoltaic (PV) properties is to compare the claimed basis to certain benchmarks.[5]  The benchmarks used by the review team for solar PV cost basis are predicated on an open-market, arm’s-length transaction between two entirely unrelated parties with adverse economic interests, specifically with respect to setting the eligible property’s price.[6] The benchmarks are updated on a routine basis. As of the first quarter of 2011, benchmark solar PV market expectations are as follows[7]:

If claimed basis is deemed consistent with benchmark prices, the review team typically focuses the remainder of its cost review on examining line items provided in the detailed cost breakdown to ensure that only eligible items have been included and that no costs have been inappropriately attributed to the property.[8] If there are no ineligible items, the basis reflects only items appropriately attributable to the eligible property, and there is adequate documentation to support that the costs reflect actual costs, the cost basis is accepted.[9] If ineligible items are identified, they are removed, and the payment is based on the corrected amount. For example, although a project may necessitate a fence for security or a building for operations and maintenance, such costs are not eligible.[10]

4. How does the IRS treat related party transactions?

In addition to ensuring that only eligible costs are included, the review team looks at whether there are related party considerations, or other unusual circumstances, such as where the transaction determining basis may be influenced by other related transactions.[11]

Common examples of related party considerations include:

a. Owner/applicant is related to the developer, installer, or supplier (collectively referred to as the “developer”). The developer may be a separate, legally-organized business, but there is common ownership/control.

b. Owner/applicant is a party to one or more related transactions with the developer such that economic interests in the specific transaction determining basis may not be adverse. For example, the owner/applicant purchased the energy property from the developer and leased the property back to the developer under a sale-leaseback model.[12]

“Where such circumstances are present, the review team evaluates whether the claimed basis is consistent with the property’s fair market value. As one aspect of this evaluation, where related transactions or other unusual circumstances are present, the review team will consider the applicant’s allocation of the cost to the eligible property, relative to other ineligible assets, rights, or contracts that may have been explicitly or implicitly conveyed in the transaction(s). In this context, the owner/applicant may be asked to submit a more detailed cost breakdown. Specifically, original manufacturer’s invoices/costs to the developer should be provided for major equipment, subsequent markups by the developer should be enumerated, and any markups by the owner identified. The owner may also submit a detailed and credible third-party appraisal demonstrating that the claimed basis is consistent with a market transaction between unrelated parties with adverse economic interests.

Ultimately, the review team determines whether or not the claimed basis was properly calculated and/or properly represented fair market value, taking into account market expectations, the specifics of the application in question, and supporting documentation provided by the applicant. If the review team determines that the basis was not properly calculated or represented, the review team may adjust the basis […] to a level consistent with the review team’s view of the property’s true cost, as informed by documentation provided by the applicant and other relevant information and analysis.”[13]

5. Can developer fees paid for in the purchase be claimed?

Developer fees are common in renewable energy projects and often included in the project’s basis. In the typical arrangement, the project company that owns the project pays the company that did the actual development work a fee at the end of construction. Many solar companies finance their projects in a way that allows the ITC to be calculated on the market value of the project rather than its cost. The Treasury prefers a cost-plus approach to determine market value.[14] While appropriate markups are case-specific and can depend on the ultimate transaction price, the Treasury Department has stated that “appropriate markups typically fall in the range of 10 to 20 percent.[15]

6. Does debt financing affect the Company’s basis when calculating ITC?

Generally, borrowing money does not adversely affect the taxpayer’s basis in solar equipment. It does not matter whether the owner of a solar project pays for the project entirely out of his own pocket or borrows part of the cost from a bank or other lender.[16] One exception to this general rule is at-risk limitations.  The credit that can be claimed in situations may be limited where the owner borrows to pay for the equipment cost with a non-qualified lender or on a nonrecourse basis, meaning on terms where the lender has no claim against the borrower if he fails to repay the loan.

Under the Code, individuals (including partners and S corporation shareholders), estates, trusts, and certain closely held corporations (other than S corporations) are subject to what are known as the “at risk” rules. These rules limit the basis to which the 30% ITC (Section 49 of the Code) and depreciation deductions (Section 465 of the Code) are applied to only the amount for which the investor is considered to be personally at risk. An investor is not considered to be personally at risk for any “nonqualified nonrecourse financing” – e.g., a loan from a relative, or from the project sponsor – that is used to capitalize the project, and therefore must reduce both the project’s ITC basis and depreciable basis by the amount of any such loan. As the loan is repaid over time, the investor can correspondingly increase the basis that is at risk, and thereby gradually reclaim the foregone credits and deductions.[17]

Not all forms of nonrecourse financing trigger the at-risk rules. Investors are considered to be at risk for what is known as “qualified commercial financing” in Section 49 of the Code. Qualified commercial financing generally refers to loans that are borrowed on commercial terms from an unrelated person who is regularly engaged in the business of lending money. In other words, as long as a nonrecourse loan is obtained from a traditional lender (e.g., a bank) in an arms-length transaction, then the borrower will likely be considered at risk for repaying the loan, and will therefore not need to reduce the ITC under the at-risk rules in Section 49 of the Code.

7. What portion of the claimed credit may be recaptured?

Beginning on the date that a solar project is placed in service, Section 50 of the Internal Revenue Code requires complete or partial recapture of the tax credit in the first five years of service if the project “is disposed of, or otherwise ceases to be investment credit property with respect to the taxpayer.”[18] “‘Disposition’ means to transfer or otherwise relinquish ownership of property.”[19] To avoid tax credit recapture, the investor must retain ownership of the property for the five-year compliance period following the year a property is placed in service.[20]

The portion of the credit recaptured depends on how long the property was in service. The taxpayer is allowed twenty percent (20%) of the credit for each full year in which recovery property was actually in service.[21] Thus, if the property ceases to qualify for the credit after the four full years of service, 80% of the credit has been earned and 20% is to be recaptured. As a result, after five full years from the date the property is placed in service, no portion of the credit is subject to recapture. Rather than amend a previous year’s tax return, the taxpayer increases his tax liability by the amount of the recaptured credit in the year the recapture event occurs by completing and filing IRS Form 4255.[22]

8. How to mitigate risk of default by the off-taker?

Default by the party purchasing the power under a power purchase agreement or leasing the equipment under a solar lease is the biggest risk for recapture for an investor of a third-party financed solar project that leverages debt financing. As example, say a commercial lessee under a solar lease abandons the building where the energy equipment is located and stops making payments in year two.

The default by the lessee would lead to a foreclosure on the asset by the lender thus triggering recapture. Some lenders may enter into forbearance agreements with the tax equity investor however, it is unlikely and will certainly increase the transactional costs and overall levelized cost of energy “LCOE” of the project. A more likely solution is for the investor and lender to agree to some level of forbearance with an extended cure period. Here, the lender agrees to provide notice to the tax equity investor in an event of default, and the investor has the right to cure, or resolve, the deficiency.[23] Cure rights may distinguish non-monetary defaults from monetary defaults in which the developer is unable to meet its debt service obligation. In some instances, the lender may provide no forbearance for a monetary default but will forbear under other default events, such as when technical problems with the system temporarily halt or reduce system output.[24]

9. What income activities may be off-set by the ITC?

The IRS limits which businesses can be tax equity investors in solar projects through the Passive Activity Limitations (“PAL”).[25] The passive activity loss rules were enacted as part of the Tax Reform Act of 1986 in an effort by Congress to prevent the use of losses from activities in which an investor did not actively participate to offset that investor’s wage, interest and dividend income. Dependent on corporate entity type, PAL may limit the amount of tax credits and deductions an Investor can take in a single year. The PAL rules apply differently based on the taxpayer’s corporate entity type. Individuals and Pass-Through Entities are fully subject to the PAL, Closely Held C-Corps have a watered-down version of PAL and Widely-held C-Corps are not subject the PAL. Generally, if an entity cannot use all or part of its credits because of the tax liability limit the ITCs can be carried back one year and forward 20 years.[26]

The IRS lists two kinds of activities that classify as passive activities. The ?rst type is defined as an activity involving the conduct of a trade or business in which the taxpayer does not materially participate.[27] A taxpayer is treated as materially participating in the activity if, during the taxable year at issue, it satis?ed at least one of seven tests outlined in the Temporary Regulations.[28] Naturally, the IRS test for “material participation” is complex but as a good rule of thumb it requires engaging in over 500 hours of day-to-day management of the business over the year.[29]

Second, by de?nition the term passive activity includes “any rental activity.” Generally, the determination that a rental activity is a passive activity is not affected by whether or not the taxpayer materially participates.[30] According to the Internal Revenue Service (IRS), an activity is considered a rental activity if tangible property held in connection with the activity is used by customers or held for use by customers, and the gross income attributable to the activity represents amounts paid or to be paid for the use of such tangible property, without regard to whether customers’ use of the property is due to a lease or to a service contract or other arrangement that is not denominated a lease.[31]

Investing for tax equity purposes in a solar energy project will likely be classified as a passive activity under both the material participation analysis and rental activity analysis. Traditionally, tax equity investors do not materially participate in the day-to-day management of the solar project and therefore it may count as a passive activity. Further, PPAs or leases are likely to be considered rental activities[32] and, if the activity is determined to be a rental activity, it is a passive activity by de?nition.

10. How do the passive loss rules apply to different entity types?

The PAL fully applies to Estates, Trusts, Personal Service Companies, and Individuals.[33] With a Limited Liability Company (“LLC”), Partnership, Limited Liability Partnership (“LLP”), or S-Corp, the taxable gain or loss is passed through to the owners’ personal income tax return.[34]  For these entity types and individuals, the crux of the PAL states losses from passive activities can only be deducted against taxable income generated by passive activities.[35] In other words, individuals, estates, trusts, and pass-through entities, cannot deduct losses generated by passive activities against income generated from non-passive business activities. If the investor does not have sufficient passive income to offset the entire deduction, it shall carry the remaining deduction forward to offset against future passive income or until it can sell its interest in the activity.

The PAL rules impose less of a limitation on Closely Held C-Corps. A closely held corporation can deduct passive activity losses against all active income except portfolio income.[36] The IRS provides the following definition: “Closely held corporation. A corporation is a closely held corporation if at any time during the last half of the tax year more than 50% in value of its outstanding stock is directly or indirectly owned, by or for not more than five individuals, and the corporation is not a personal service corporation.”[37] Typically, Closely-Held C-Corporations investing in solar projects will not be hindered by PAL because they earn the majority of their taxable income through core activities, not portfolio income. Even if the solar tax equity investment is deemed a passive activity, the closely-held corporation can use the solar tax incentives to offset the core taxable income. Only income earned from stocks, bonds, and other similar “Portfolio Income” will be restricted from offset by PAL.[38]

Widely held corporations are free to invest in solar projects without fear of limitation by the PAL. The PAL is expressly limited to Individuals, Pass-Through Entities, and Closely Held Corporations.[39]

11. Do the AMT rules apply to the ITC?

The alternative minimum tax is a secondary tax system with separate rules and rates; taxpayers must pay the greater of either the AMT, or their regular taxes (including all tax credits and deductions). The AMT is designed to prevent individuals and corporations from reducing their income tax liability below a certain level (hence, it is a minimum tax level that must be paid). Prior to the American Recovery and Reinvestment Act of 2009, the AMT nullified potential benefits of the credits for some potential investors, primarily because corporations paying the AMT were not allowed to the take the ITC.[40] The Recovery Act of 2009 eliminated this barrier and the ITC is now allowed a full exemption from the AMT.[41]

12. What can be depreciated under the MACRS?

 Under the federal Modified Accelerated Cost-Recovery System (MACRS), businesses may recover investments in certain property through depreciation deductions. The MACRS establishes a set of class lives for various types of property, ranging from three to 50 years, over which the property may be depreciated. A number of renewable energy technologies are classified as five-year property under the MACRS,[42] which refers to 26 USC § 48(a)(3)(A), often known as the energy investment tax credit or ITC to define eligible property. Such property currently includes:

• a variety of solar-electric and solar-thermal technologies
• fuel cells and microturbines
• geothermal electric
• direct-use geothermal and geothermal heat pumps
• small wind (100 kW or less)
• combined heat and power (CHP).

As shown in the figure below, MACRS allows full depreciation of the asset over five years of project life, or six tax years. Depreciation of the asset can be further accelerated through “bonus depreciation,” which provides significant tax benefits in the first year of an asset life. The bonus depreciation reverts from 100% of the eligible plant in 2011 to 50% in 2012. These depreciation schedules are compared to a 20-year straight-line schedule (over the first six years only) to show the relative speed at which capital can be reduced in book value in order to lower taxes payable on income.

The five-year MACRS depreciation schedule provides a tax benefit equal to about 26% of system costs on a present value basis.[43] In comparison, straight-line depreciation provides a tax benefit value of 14% of system costs. When combined, the accelerated depreciation and the 30% ITC provide a combined tax benefit equal to about 50%–60% of the installed cost of a commercial PV system.[44] Approximately 85% of total solar installation costs are eligible for depreciation.

13. How is the MACRS deduction calculated?

For detailed information regarding the calculating the MACRS deduction for a solar project please see IRS Publication 946 (http://www.irs.gov/pub/irs-pdf/p946.pdf) and in particular Chapter 4 of Publication 946 (http://www.irs.gov/publications/p946/ch04.html). For further IRS guidance see IRS Publication 946, IRS Form 4562: Depreciation and Amortization”, and ”Instructions for Form 4562”.

According to the IRS, solar systems are classified as having a 5 year life and should thus use the 5-year property MACRS table to determine the amount of depreciation in each life. If a solar system is placed in service in the first three quarters of the year, use the “half-year convention” table. If the solar system is placed in service in Q4, use the “mid-quarter convention” table.

14. Does taking a credit under the ITC affect the depreciable amount?

Qualifying solar energy equipment is eligible (described above in the ITC section) for a cost recovery period of five years. For equipment on which an Investment Tax Credit (ITC) or a 1603 Treasury Program grant is claimed, the owner must reduce the project’s depreciable basis by one-half the value of the ITC. This means the owner is able to deduct eighty-five percent (85%) of his or her tax basis.

*This article is for informational purposes only and not to be construed as legal or tax advice.

[1] Emergency Economic Stabilization Act of 2008, Pub. L. No. 110-343 (2009)., Div. B.

[2] 26 U.S.C. § 48(a)(5)(D)(i)(I-II).

[3] Office of the Fiscal Assistant Sec’y, Evaluating Cost Basis for Solar Photovoltaic Properties, available at http://www.treasury.gov/initiatives/recovery/Documents/N%20Evaluating_Cost_Basis_for_Solar_PV_Properties%20final.pdf.

[4] Lemmen v. Commissioner of Internal Revenue, 77 T.C. 1326, 1348 (1981).

[5] Office of the Fiscal Assistant Sec’y, supra note 3, at 1.

[6] Id at 1-2.

[7] Id. at 2.

[8] Id.

[9] Id.

[10] Id.

[11] Id.

[12] Id. at 3.

[13] Id.

[14] Solar Energy Indus. Ass’n, Cost Basis for the ITC and 1603 Applications (August 2012), available at http://www.seia.org/research-resources/cost-basis-itc-1603-applications.

[15] Id. at 4.

[16] Id.

[17] 26 U.S.C. § 49(a)(2)(A).

[18] I.R.C. § 50; See also Comptroller of the Currency, Department of Treasury, Community Developments Fact Sheet: Solar Energy Investment Tax Credits and Grants (September 2011), available at http://www.occ.gov/topics/community-affairs/publications/fact-sheets/fact-sheet-solar-energy-invest-tax-credits-grants.pdf.

[19] Rome I, Ltd., v. Comm’r, 96 T.C. 967, 704 (1991).

[20] Comptroller of the Currency, Department of Treasury, supra note 18, at 2.

[21] I.R.C. § 50; see also IRS Form 4255, General Instructions.

[22] I.R.C. § 50(a)(1)(A).

[23] Joel Meister, Sunny Dispositions: Modernizing Investment Tax Credit Recapture Rules for Solar Energy Project Finance After the Stimulus 23 (September 2012), available at http://solar.gwu.edu/Research/Meister_Sunny_Dispositions_ITC_Recapture.pdf.

[24] Id at 24.

[25] See Instructions for Form 8810; IRS Pub. No. 925

[26] See Form 3800, General Instructions.

[27] See IRS Pub. 925 at 2.

[28] Stephen B. Tracy, Passive Loss Issues in Connection with Solar Investments (February 2010), available at http://www.novoco.com/journal/2010/02/jtc_2010-02_retc_pg73.pdf.

[29] See IRS §465(c)(7)(C).

[30] Tracy, supra note 28.

[31] Id.

[32] Id.

[33] IRS Pub. No. 925 at 2.

[34] Id.; see also IRS Form 8810 and its Instructions.

[35] Id.

[36] Id.

[37] IRS Form 8810 at 1.

[38] Id.

[39] IRS Pub. No. 925 at 2.

[40] Paul Schwabe et al., Renewable Energy Project Financing: Impacts of the Financial Crisis and Federal Legislation 3 (July 2009).

[41] Mark Bolinger, Revealing the Hidden Value that the Federal Investment Tax Credit and Treasury Cash Grant Provide to Community Wind Projects 9 (January 2010).

[42] 26 USC § 168(e)(3)(B)(vi).

[43] Mark Bolinger, Financing Non-Residential Photovoltaic Projects: Options And Implications (2009). http://eetd.lbl.gov/EA/EMP/reports/lbnl-1410e.pdf.

[44] Mendelsohn, M., A Chicken In Every Pot: Is There Enough Tax Equity To Maintain The Re Market? (2010). https://financere.nrel.gov/finance/content/chicken-every-pot-there-enough-tax-equity-sustain-re-market.

The post Article: FAQ regarding the ITC and MACRS appeared first on Renewable Energy Law Firm | Solar & Wind Energy Attorneys | Austin TX.

The Butler Firm attorneys and consultants were selected as lead project council on a rare combined solar and wind project located in the US territory of Guam. For this project The Butler Firm will use it talents to advise and consult the lead developer Pacific Green Resources through the PPA and Interconnection negotiation process with the Guam Power Authority and stay on through complete implementation. The Butler Firm is also using its expertise to structure the finance and arrange the investors for this 15 MW project.

The post The Butler Firm lead council on 15 MW Solar and Wind Project in Guam appeared first on Renewable Energy Law Firm | Solar & Wind Energy Attorneys | Austin TX.

Analyzing Lease Sites and Deal Structures and Addressing Key Document Provisions

TBF Attorney Clay Butler has been invited to be a speaker for a national continuing legal education seminar to be held on September 12, 2012. Details below.

his CLE webinar will provide real property counsel with a review of possible deal structures and key legal issues involved in the drafting and negotiation of a solar lease. The panel will also outline practical considerations for counsel to property owners to maximize the benefits of a solar leasing opportunity.

The post Clay Butler to speak at National CLE – Solar Leases: Legal Considerations appeared first on Renewable Energy Law Firm | Solar & Wind Energy Attorneys | Austin TX.