The renewable tax credit transfer market will accelerate with new government guidance; public hearing and comments deadlines are scheduled for August

Risk allocation puts the usual premium on sponsors with a balance sheet and/or recapture insurance coverage

While the guidelines provide clear rules and examples, many foot faults are present

On June 14, 2023, the Treasury Department and Internal Revenue Service issued long-awaited guidance on the transferability of certain renewable energy-related federal tax credits. The guidance takes the form of a notice of proposed rulemaking, proposed regulations, and an online Q&A, with a public hearing to follow in August.

Under new Code Section 6418, eligible taxpayers can elect to transfer all or any specified portion of eligible tax credits to one or more unrelated buyers for cash consideration. While the tax credits can be sold to more than one buyer, subsequent transfers by the buyer are prohibited.

This alert highlights several practical issues raised by the guidance, which should allow participants waiting for more clarity to proceed.

Individual Buyers Left Out

• The guidance applies the Code Section 49 at risk rules and Section 50(b) tax-exempt use rules, generally restricting sellers in calculating the amount of tax credits for sale, and Code Section 469 passive activity rules, generally restricting buyer’s use of such tax credits, in various contexts. On the buyer side, these rules appear to be more restrictive than the limitations that would apply to identical tax credits in an allocation, rather than sale, context. Suffice to say, this will prohibit individuals from taking part in the transfer market for practical purposes outside of fact patterns of very limited application.
• While this result may not be surprising since such rules currently severely restrict individuals from participating in traditional federal tax credit equity structures, there was some hope for a different outcome due to the stated policy goal of increasing renewable energy investment (not to mention the Inflation Reduction Act’s general departure from decades of case law precedent and IRS enforcement action prohibiting sales of federal tax credits with the enactment of Section 6418).

Lessees Cannot Sell the Tax Credits

• A lessee cannot transfer the credit. With the prevalence of the master lease (inverted lease) structure in tax equity transactions, this prohibition created an unexpected roadblock for deal participants who have been structuring tax equity transactions with backstop type sale provisions for almost a year now. This presents developers, at least in the inverted lease context, with a choice of utilizing a traditional tax equity structure for the purpose of obtaining a tax-free step up in basis to fair market value, or forgoing the step up for less financing but also less structure complexity. The standard partnership flip project sale into a tax equity type of holding company structure could still remain a viable alternative.
• As the transfer is generally made on a property-by-property basis by election, creative structuring, in theory, could allow for a lessor to retain certain property and sell the related tax credits (e.g., on portfolios with more than one solar installation/project, or even with large projects that go online on a block-by-block basis assuming the “energy project” election is not made – a term that future guidance will need to provide more clarity on).
• However, this seems to be an ivory tower conclusion currently, and the practical reality is that too many unknown issues could be raised by such out of the box structuring, including the fact that conservative institutional investors may refuse to participate in such a structure until clear objective guidance is published addressing the same.

Bonus Credits Cannot Be Sold Separately

• Bonus credits cannot be sold separately from the underlying base credit. This is more problematic for certain adders – for example, the energy community adder rules are now out and amount to simply checking a location on a website. Others (e.g., the low-income community or domestic content adder) require more extensive and subjective application and qualification procedures which makes when and how such adders can be transferred difficult to ascertain. Projects hoping to transfer such credits may need to be creative in compensating buyers for such uncertainty and qualification risk. Tax equity transactions that closed prior to the guidance’s issuance may also need to be revisited, as provisions in such transaction documents commonly attempted to bifurcate the bonus credit away from the base credit in order to allow the sponsor to separately sell such adders.

Buyers Bear Recapture Risk and Due Diligence Emphasis

• While the Joint Committee on Taxation Bluebook indicated the buyer is responsible for recapture, industry participants were still hoping such risk would remain with the seller. Outside of the limited situation of indirect partnership dispositions (which still results in a recapture event to the transferring partner if triggered), the recapture risk is borne by the buyer, using the rationale that the buyer is the “taxpayer” for purposes of the transferred tax credits. While this is familiar territory for tax equity investors, whose allocated tax credits would be reduced in a recapture scenario, tax credit purchase transactions are now burdened with what amounts to the standard tax equity type of due diligence, including negotiation of transaction documents outside of a basic purchase agreement.
• The guidance provides that indemnity protections between the seller and buyer are permitted. Tax equity transactions historically have had robust indemnification provisions, which should remain the case even more so in purchase/sale transactions. Tax equity investors traditionally bear “structure risk” dealing with whether the investor is a partner for tax purposes – such risk is eliminated in the purchase scenario as the purchasing investor no longer needs to be a partner (subject to the caveat of a buyer partnership discussed below).
• If the buyer claims a larger credit amount than the seller could have, such “excessive credit transfer” will subject the buyer to a 20 percent penalty on the excess amount (in addition to the regular tax owed). All buyers are aggregated and treated as one for this purpose – if the seller retains any tax credits, the disallowance is first applied to the seller’s retained tax credits. A facts and circumstances reasonable cause exception to avoid this penalty is provided, further emphasizing the need for robust due diligence.
• Specific non-exclusive examples that may demonstrate reasonable cause include reviewing the seller’s records with respect to determining the tax credit amount, and reasonable reliance on third-party expert reports and representations from the seller. While not unique to this new tax credit transfer regime, the subjective and circular nature of such a standard is complex – for example, when is it not “reasonable” for buyers or other professionals to rely on other board certified and licensed professionals, such as an appraiser or independent engineer with specialized knowledge?
• Buyers thus need to remain vigilant about potential recapture causing events. For example, tax equity investors will not generally allow project level debt on investment tax credit transactions without some sort of lender forbearance agreement that provides that the lender will not cause a tax credit recapture event (such as foreclosing and taking direct ownership of the project). Buyers remain responsible for such a direct project level recapture event, which again aligns the tax credit transfer regime with tax equity due diligence and third-party negotiation requirements. The guidance is more lenient for the common back-leverage debt scenario.
• While similar interparty agreements between back leverage lenders and the tax equity investor are required for non-project level debt facilities to address tax credit recapture among other issues, the guidance provides that a partner disposing of its indirect interest in the project (e.g., the lender foreclosing and taking ownership of a partner’s partnership interest) will remain subject to the recapture liability rather than the buyer provided that other tax-exempt use rules are not otherwise implicated. However, the need to negotiate such lender related agreements is still implicated as not all recapture risk in even this scenario was eliminated to the buyer.
• While the recapture risk could place a premium on production tax credit deals (that are technically not subject to recapture or subjective basis risk), the burdensome process of needing to buy such tax credits on a yearly basis in line with sales of output may make such transactions more tedious.
• The insurance industry already has products in place to alleviate buyer concerns, but this is just another transaction cost in what may be a tight pricing market. Not unlike tax equity transactions, sponsor sellers with a balance sheet to backstop indemnities may be able to demand a pricing premium; other sponsors may need to compensate buyers with lower credit pricing to reward such risk and or/to allow the purchase of recapture insurance. While this seems logical, the guidance also includes anti-abuse type rules whereby low credit pricing could be questioned in terms of whether some sort of impermissible transfer by way of other than cash occurred (e.g., a barter for some sort of other service). What the IRS subjectively views as “below market” pricing could trigger some sort of audit review based on this factor alone which further stresses the importance of appropriate due diligence.

Partnerships and Syndications

• The guidance provides very clear rules with helpful examples, which should allow partnership sellers and buyers to proceed with very objective parameters. For example, the rules allow a partnership seller to specify which partner’s otherwise allocable share of tax credits is being sold and how to then allocate the tax-exempt income generated. The cash generated from sales can be used or distributed however the partnership chooses.
• Similar objective rules and examples are provided for a buyer partnership. Subsequent direct and indirect allocations of a purchased tax credit do not violate the one-time transfer prohibition. Purchased tax credits are treated as “extraordinary items” that must be allocated among the partners of the buyer partnership as of the time of the transfer, which is generally deemed to occur on the first date a cash payment is made. Thus, all partners need to be in the partnership on such date to avoid an issue. Purchased tax credits are then allocated to the partners in accordance with their share of the nondeductible expenditures used to fund the purchase price.
• What level of end-user comfort is needed in such a syndicated buyer partnership is an open question. While the rules provide objective guidelines in terms of when and how such purchased credits are allocated, subjective questions that are present in (and focused on) traditional tax equity partnerships are implicated. For example, could a syndication partnership set up for the business purpose of what amounts to selling the tax credits somehow run afoul of the subjective business purpose and disguised sale rules in tax credit case precedent, such as the Virginia Historic Tax Credit Fund state tax credit line of precedent? Will the market require a robust tax opinion in such scenario, thereby driving up transaction costs?
• An example in the proposed regulations speaks to this sort of partnership formed for the specific purpose of buying tax credits, but leaves out of the fact pattern a syndicator partner. The example itself should go a long way towards blessing such arrangements, but the IRS taking a contrary position when dealing with such issues would not be a new situation. For example, the IRS challenged allocations of federal historic tax credits as prohibited sales of federal tax credits to the point of freezing the entire tax equity market with its positions in Historic Boardwalk Hall, which was only rectified with the release of a subsequent safe harbor revenue procedure.
• Moreover, the guidance provides that tax credit brokers are allowed to participate in the market so long as the tax credits are not transferred to such brokers as an initial first step in the transfer process (as the subsequent transfer to an end user would violate the one-time transfer rule). Specifically, at no point can the federal “income tax ownership” be transferred to a broker. It is an open question if further distinction will be made at where this ownership line should be drawn. For example, can a third party enter into a purchase agreement with a seller and then transfer such rights prior to the transfer election being made? Does it matter under such analysis if 1) purchase price installments have been paid (which implicates rules in the buyer partnership context as noted above) and/or 2) the tax credit generating eligible property has been placed in service (which is when the investment tax credit vests for an allocated tax credit analysis; a production tax credit generally arises as electricity or the applicable source is sold)?
• Indirectly implicated is what effect the new transfer rules will have on established case law precedent and IRS enforcement action in traditional tax equity structures. The Inflation Reduction Act and guidance dances around certain of these issues by creating a fiction where the buyer is treated as the “taxpayer” – this avoids the issue of turning a federal tax credit into “property” that can be sold similar to a certificated state tax credit. This also provides a more logical explanation as to why the buyer of these federal tax credits does not need to report any price discount as income when utilized, unlike the well-established federal tax treatment of certificated state tax credits that provides the exact opposite (e.g., a buyer of a certificated state tax credit at $0.90 has to report $0.10 of income on use of such tax credit).

Other Administrative and Foot-Fault Issues

• The purchase price can only be paid in cash during the period commencing with the beginning of the seller’s tax year during which the applicable tax credit is generated and ending on the due date for filing the seller’s tax return with extensions. Thus, such period could be as long as 21.5 months or more (e.g., a calendar year partnership seller extending its return to Sept. 15). Tax equity transactions generally have pricing timing adjusters for failure to meet placement in service deadlines. Such mechanism will not work if advanced payments were made and then the project’s projected placement in service year changes. Tax credit purchase agreements executed prior to the June 14 guidance may require amendments or complete unwinds to line up with the rules to avoid foot faults (e.g., purchase agreements executed in 2022 where a portion of the purchase price was paid in 2022 for anticipated 2023 tax credits would not fall within the “paid in cash” safe harbor period). Advanced commitments, so long as cash is not transferred outside of the period outlined above, are permitted.
• The typical solar equity contribution schedule of 20 percent at a project’s mechanical completion makes purchase price schedules approximating the same a reasonable adjustment for most investment tax credit energy deals in terms of the timing of financing. In addition, the advance commitment blessing of the guidance will give lender parties the comfort necessary similar to having executed tax equity documents in place. Thus, typical project construction financing mechanisms should be similar in the tax equity versus purchase agreement scenario, with projects that allow for a more delayed funding mechanism possibly obtaining a tax credit pricing premium. Production tax credit deals, for which tax credits can only be paid for on a yearly basis within the cash paid safe harbor timing window, may have more significant project financing hurdles without further tax credit transfer rule modifications.
• Sellers can only make the transfer election on an original return, which includes extensions. Buyers, by contrast, may claim the purchased tax credit on an amended return.
• Buyers need to be aware that usage of the purchased tax credits is tied to the tax year of the seller. For example, a fiscal year seller could cause the tax credits to be available a year later than an uninformed buyer anticipated, regardless of when the tax credit was generated using a traditional placement in service analysis. For example, a solar project placed in service during November 2023 by an August fiscal year seller would generate credits first able to be used in a calendar year buyer’s 2024, instead of 2023, tax year. A buyer can use the tax credits it intends to purchase against its estimated tax liability.
• The pre-registration requirements, which are expansive and open-ended, are also tied to the taxable year the tax credits are generated and generally must be made on a property-by-property basis. For example, 50 rooftop installations could require 50 separate registration numbers outside of the “energy project” election. When such registration information needs updated is also not entirely clear – for example, a project is often sold into a tax equity partnership syndication structure on or before mechanical completion. Needing to update registration information could delay transactions and implicates unknown audit risk.

While these rules provide much-needed clarity, failure to adhere may be catastrophic and will require sellers and buyers to put proper administrative procedures in place to avoid foot faults. The new transfer regime will expand the market to new buyers who may have viewed tax equity as either too complex or had other reasons to avoid these transactions, such as the accounting treatment of energy tax credit structures. However, it would be prudent for such buyers to approach such transactions with eyes wide open.

© 2023 BARNES & THORNBURG LLP

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The post Renewable Energy Tax Credit Transfer Guidance Provides Both Clarity And Pitfalls appeared first on The National Law Forum.

COVID-19 is impacting industries across the globe and clean energy is no exception. As the pandemic continues to influence economic relief efforts at both the state and federal level, states are beginning to offer specific forms of relief through their incentive programs.

Additionally, electric distribution companies in each state have declared COVID-19 a force majeure event, allowing extensions to interconnection milestones and in some cases payment schedules. Below are summaries of the specific relief efforts being offered by some states, and more details regarding electric distribution companies’ declaration of a force majeure event.

Massachusetts

The Massachusetts Department of Energy Resources (“DOER”) filed emergency regulations with the Secretary of State following its regulatory 400MW review of the Solar Massachusetts Renewable Target (“SMART”) Program on April 14, 2020. Among the regulations is a blanket extension of six months to all Solar Tariff Generation Units, including any projects that submit their applications before July 1, 2020, due to the ongoing impacts of COVID-19. More details are provided in the DOER’s Statement of Qualification Guideline.

The Massachusetts Department of Public Utilities has also developed a webpage with information and resources specific to COVID-19. The website includes information on the impacts of the electric distribution companies’ respective declarations of COVID-19 as a force majeure event.

New York

The New York State Energy and Environment agencies wrote a letter to the clean energy industry on April 1, 2020, expressing support for the clean energy industry, particularly as construction has been impacted by COVID-19. The agencies announced in the letter that they are seeking input from clean energy industry stakeholders so that the agencies and the industry can work together to form creative solutions. The letter is found on NYSERDA’s COVID-19 page.

Connecticut

In Connecticut, the Department of Energy and Environmental Protection (“DEEP”) is coordinating with governmental offices and stakeholders to offer webinars for clean energy contractors with information about available state and federal aid. Please check in with CT DEEP to find out more information on these offerings.

Maine

The Governor’s Energy Office (GEO) released a statement that the GEO is working with the Maine Public Utilities Commission (PUC) and clean energy stakeholders to answer questions and concerns that are related to COVID-19. Stakeholders that have questions and concerns should contact the GEO for further information.

Electric Distribution Companies’ Force Majeure Declaration

Several electric distribution companies have notified state’s public utilities commissions that COVID-19 is a force majeure event. By declaring a force majeure event, the electric distribution companies have allowed extensions to project milestone dates and in some cases interconnection payments. Electric distribution companies that have not formally declared COVID-19 a force majeure event have waived late fees and extended payment timelines. Individual projects should check in with the electric distribution company specific to the project to confirm how theirs may be impacted.

The post Northeast State Solar Programs in Light of COVID-19 appeared first on The National Law Forum.

Last week the Solar Energy Industries Association (SEIA) and George Washington University (GWU) issued a report estimating that the United States has reached 1 million solar installations and will surpass 2 million installations by 2018.  This is a 1,000-fold increase over 15 years as only 1,000 systems were installed in 2001, and these numbers highlight the tremendous growth experienced by the solar industry.  Of the 1 million PV systems, there are currently over 942,000 residential installations, nearly 57,000 PV installations at businesses, non-profits and government agencies, and over 1,500 utility-scale PV installations.  SEIA and GWU anticipate 4 million installations by 2020 and for the U.S. to be installing one million PV systems annually by 2025. To learn more about this solar milestone and the factors contributing to the solar industry’s growth, read on!

While currently only supplying 1 percent of U.S. electricity generation, solar energy accounted for 30 percent of new capacity last year and is expected to continue developing.  This growth has profoundly affected the job sector, where solar jobs grew 123 percent in the past five years and created 1 in 83 new U.S. jobs in 2015.  Overall, the solar industry now employs over 200,000 Americans, three times more jobs than U.S. coal mining.

Multiple factors were credited for playing a role in the U.S. reaching 1 million solar installations, including lower installation costs and predictable, stable federal and state policies.  In the last ten years, installation costs have dropped more than 70 percent, driven by declining solar module prices.  Enacted in 2008, the solar Investment Tax Credit (ITC), a 30 percent tax credit for solar systems on residential and commercial properties, was extended in December through 2021.  Meanwhile, state policies such as net-metering and renewable portfolio standards (RPS) have allowed solar to enter markets.  Currently, 44 states have net metering policies and 29 have RPS policies.

One challenge for the future of solar is the inability of lower-income households to benefit from solar due to a multitude of barriers, including a high rate of renters, multi-tenant buildings, and a lack of access to financing.

The post U.S. Solar Installations Reach 1 Million appeared first on The National Law Forum.

The City of San Francisco announced today that it will now mandate solar photovoltaic or solar water panels on all new residential and commercial buildings of 10 floors or less. The City’s renewable energy ordinance makes San Francisco the first major city in the country to require solar panels on new construction.

Will San Francisco’s action spur Cal/OSHA to take a renewed look at workplace safety in the solar industry?  Indeed, as solar installations increase rapidly throughout the country, perhaps Federal OSHA will dust off its Green Job Hazards guidance in light of what appears to be a continued movement toward renewable energy sources and the inevitable increase in workplace hazards that occurs when industries rapidly expand.

The post San Francisco Mandates Solar Power on New Buildings appeared first on The National Law Forum.

An increasing number of retail, office, industrial and warehouse/distribution property owners are utilizing electricity generated by on-site photovoltaic (also referred to as “pv” or “solar”) systems to meet a portion of their properties’ electrical energy needs. The pv systems can be located on the roofs of buildings, in parking fields, on open areas of the property or on two or more of these locations.

One of the most common methods that property owners are using to obtain such on-site solar-generated electricity is to enter into a power purchase agreement, often referred to as a “PPA,” with a solar developer, frequently referred to as a “provider.” In a PPA, the property owner, often called a “host,” provides leasehold or license rights on its property to the provider for the installation and operation of the pv system, and the provider sells the electricity that the pv system generates to the host. The provider generally owns all of the governmental and utility company incentives provided in connection with the pv system, and the host usually owns the net metering rights for the pv system.

However, the negotiation of a PPA frequently takes more time and is more complex than the economic benefits of the PPA to the provider and the host warrant. One of the major reasons for this problem is that the typical initial letter of intent (“LOI”) for a PPA transaction frequently fails to address the issues that often cause the most difficulty when the host and provider attempt to negotiate and finalize the PPA itself. The balance of this article sets forth several of these additional issues that should be included in a PPA LOI and explores methods of ameliorating the conflicts they create between the provider and the host.

Electricity Rate Cap

Many LOIs include a cap on the rate that the provider will charge the host for the electricity that the pv system generates. The cap usually provides that the rate that the provider charges to the host cannot exceed the rate that that host’s regulated local electrical utility, referred to in this article as the “Utility,” or the host’s third-party power supplier, charges the host for electricity at the property in question.

However, in setting this cap, it is important to remember that the Utility charges the host, whether or not the host also has a third-party power supplier, for many items other than the electricity itself, some of which are based on electricity consumption and some of which are static. Accordingly, when the host and provider agree on the rate cap in the LOI, they should clearly state what portions of the Utility and third-party power provider rate are included in determining the cap.

Interconnection Agreement

In order to operate a pv system and to obtain net metering for the excess electricity that the pv system generates, the Utility requires that its customer, usually the host, sign an interconnection agreement. The terms of the interconnection agreement are set forth in the Utility’s tariff and are, hence, non-negotiable. While the host must sign the interconnection agreement, most of the undertakings in the interconnection agreement are the responsibility of the provider under the PPA. Accordingly, the LOI should provide that the host will sign the interconnection agreement and that each party will agree to perform its obligations under the interconnection agreement, while indemnifying the other party for its failure to do so.

Purchase Of Excess Electricity

Pv systems by their nature cannot provide all of a property’s electricity needs all of the time. Additionally, in most jurisdictions, either the Utility or a government regulator limits the size of the pv system, so that it will not generate more than a maximum percentage (for example, 80 percent) of a property’s electricity usage. However, notwithstanding these circumstances, there are times when the pv system will generate more electricity than the property is using, causing the Utility meter to run backwards, referred to as “net metering.” In many jurisdictions, usually by means of the interconnection agreement, the Utility will pay the host or credit the host’s future electric bills for the amount of this excess electricity.

For this reason, most PPAs provide that the host will purchase all of the electricity the pv system generates and own all the net-metering credits. However, before entering into a PPA, a host should review its third-party electricity supply contracts to make sure that they do not contain prohibitions against pv or other on-site systems or do not contain minimum usage requirements. The PPA and LOI should

also address the situation where the property becomes vacant, because most net-metering programs have limitations on how much excess electricity the Utility has to buy.

Electricity Production Guaranty

Many hosts assume, in their financial planning for a property’s operation, that the pv system will generate a minimum amount of electricity in each calendar year. Accordingly, they request a production guaranty. If the host wants a production guaranty, this should be set forth in the LOI. Additionally, the adjustments to the guaranty for weather, system shutdowns and force majeure events should be spelled out.

Taxes

Many jurisdictions provide limited sales and use tax exemptions on the sale of electricity from on-site pv systems and exclusions from increases in real property taxes by reason of their location on a property. However, other jurisdictions do not provide such exemptions or the exemptions are very narrow and do not apply to every situation. Accordingly, the host and provider should determine whether or not a tax exemption exists or applies before they enter into a LOI. If the exemption is available, the LOI should set forth which party is responsible for obtaining it. If no exemption applies, the LOI should set forth which party is responsible for the particular tax.

SNDAs

Most properties are subject to mortgage secured debt. Under the Uniform Commercial Code, as adopted in most jurisdictions, the PPA can provide that the pv system is the personal property of the provider, not a fixture, and thus not subject to the lien of the mortgage on the property. However, most loan and security agreements for most mortgages also provide for security interests in the personal property located at the property. The language in these documents is often extremely broad. Additionally, the provider needs access rights over the property to install and repair the pv system and rights to place the pv system on the property. PPAs generally provide these rights as leasehold or license rights. Finally, many mortgages require mort- gagee consent for the installation of pv systems on the property.

Accordingly, the LOI should set forth whether or not, and at whose cost, the host will obtain subordination, non-disturbance, attornment and lien waiver agreements (“SNDAs”) from all current and future holders of mortgages on the property. Such a provision can provide for the sharing of the cost to obtain the SNDA between provider and host, with a waiver or cancellation option if the cost exceeds a certain amount.

Non-interference With PV System And Property Access

Many retail tenants, in particular, have consent rights over the roofs of their stores, rights to install HVAC systems and antennas on their roofs and exclusive rights over certain parking lots and common areas. The provider cannot allow its pv system to be moved, damaged or shaded. Additionally, the provider needs laydown, storage and parking areas for its installation, repair and maintenance of the pv system. Accordingly, the LOI should address tenant consents and lease and OEA amendments, if required, in order to insure non-interference with the pv system and necessary provider access. The LOI should also address which party is responsible for obtaining the consents and access and non-interference rights and at whose cost. Additionally, the LOI can provide for a non-penalty termination of the PPA if these consents and rights cannot be obtained.

Temporary PV System Relocation, Removal Or Shutdown Most PPAs have a term of 15 to 20 years. During such a time period, roofs often have to be repaired and parking lots resurfaced. The cost to relocate or temporarily remove and reinstall a pv system is significant. Additionally, the cost to the provider in lost electricity revenue and more importantly lost incentive revenue can be substantial. Accordingly, the LOI should set forth which party will bear these costs or how they will be shared. Cost sharing may shift later in the term of the PPA because the provider’s loss of incentive revenues will likely be less and the need for repairs will be more likely to occur.

PV System Purchase Options

If the PPA is going to provide for a purchase option, the LOI should address at what times in the term the host can exercise its option and set forth the method for determining the fair market value of the pv system at the time of the exercise of the option, including what factors will be used in determining the value of the pv system.

Assignment

The LOI should state when, under what terms and to whom the parties can assign their rights under the PPA and whether a party and, if applicable, its guarantor, remains obligated under the PPA after an assignment.

Limitations On Liability

The LOI should specify whether the parties will be responsible for consequential damages, whether there will be absolute limitations on all damages, including indemnification obligations, and the dollar amount of these limitations.

Parental Guaranties

Most pv systems are owned through a single-purpose entity whose only asset is the pv system, and most shopping centers are owned by single-asset, single-purpose entities. Accordingly, the provider and the host should determine in the LOI if they are going to provide parental guaranties to each other and under what terms.

Conclusion

While the list of issues this article covers is by no means exhaustive, the author hopes that it will be helpful in streamlining the negotiation of PPAs.

This article appeared in the March 2014 issue of The Metropolitan Corporate Counsel. The views and opinions expressed in this article are those of the author and do not necessarily reflect those of Sills Cummis & Gross P.C. Copyright © 2014 Sills Cummis & Gross P.C. All rights reserved.

Article by:

Kevin J. Moore

Of:

Sills Cummis & Gross P.C.

The post Letters Of Intent For On-Site Solar Energy Transactions appeared first on The National Law Forum.

The ongoing discussion between solar energy stakeholders and utilities concerning the merits of net metering and the best approach to ensure that ratepayers with installed solar power systems contribute appropriately to overall electric transmission and distribution costs spans the nation,  with state utility commissions from Georgia to California considering this issue.  However, nowhere is that discussion presently more heated and more closely watched than in Arizona and Colorado.

After a day of public comments and a full day of discussions with interveners, the Arizona Corporation Commission (A.C.C.) voted 3 – 2 on November 14, 2013 to modify APS’s Net Energy Metering (NEM) program. (A.C.C. Docket No. E-01345A-13-0248)  In brief, the A.C.C. voted to adopt a 70 cent/kW installed monthly charge for ratepayers with rooftop solar.  For the average-sized rooftop installation of 7 kW, this means a monthly charge of $4.90.  The two commissioners who voted against the decision felt that this did not go far enough in addressing the cost shift from NEM.

While the decision is likely to be perceived as a win for the rooftop solar companies, APS and other utilities can take solace in the fact that the Commission recognized that NEM does produce a cost shift and that the grid has value for all customers.  The details of the cost shift, including consideration of the value of the grid, will be the subject of A.C.C. workshops that will take place prior to the next APS rate case.

Prior to the open meeting, it appeared as though the A.C.C. would adopt a solution that would reduce the NEM subsidy based on a formula that took into consideration the lower cost of utility scale solar.  The monthly charge calculated through this formula ranged from $7.00 to $56.00 per month for a 7 kW installation, depending on the individual Commissioner’s proposal.

However, on the morning of the second day of the open meeting, the rooftop solar interveners and the Arizona Residential Utility Consumers Office (RUCO) negotiated a settlement that was the subject of most of the discussion.  This “settlement” proposed a monthly charge of 70 cents per kw installed or $4.90 for a 7 kW system.  While Commissioner Pierce and others mentioned the lower cost of utility scale solar, the final outcome had less to do with addressing the rate-shift and more to do with the amount that the DV industry said that the average customers, who they contend only save $5-10/month, could absorb and still be willing to install a system.  APS opposed the eventual outcome, as did Commissioners Pierce and Brenda Burns.

The following solution was adopted:

Monthly charge.  New rooftop PV customers beginning after December 31, 2014 will be billed a monthly charge of 70 cents per kW installed to help address the rate-shift from solar to non-solar customers.  For the average-sized system of 7 kW, that would mean a charge of $4.90/month.  The charge can be adjusted by the Commission in the future – either up or down – based on the volume of installations.  Reports of rooftop installation volumes will be provided quarterly.  There is no automatic escalation of the charge based on installation volume.  This charge will be added to the rooftop solar customer’s Lost Fixed Cost Recovery (LFCR) fund assessment currently paid by APS customers.  An offsetting reduction will be made to the monthly LFCR assessment currently paid by customers without rooftop solar.

Grandfathering.  Rooftop installations under the current NEM structure will be grandfathered.  There was a long discussion about grandfathering with a general consensus being reached that while any Commission can change any previous decision made, future Commissions were likely to honor grandfathering decisions made by previous Commissions.  Customers who sign up for systems under the new 70 cent charge will be grandfathered if the charge is increased to 80 cents or $1.00, but only until the next rate case in 2015.  Customers who then sign up under any increased charges (e.g., 80 cents or $1.00) will also be grandfathered until the next rate case.  However, all new rooftop customers (post December 2013) will be subject to any changes agreed to in the next rate case.

The NEM issue will be taken up again in the next APS rate case.

While the net metering discussion in Arizona has reached a conclusion – for now, the debate continues in Colorado.

On July 24, 2013, Public Service Company of Colorado (PSCo), Xcel Energy’s Colorado subsidiary, filed with the Colorado Public Utilities Commission (CPUC) its 2014 Renewable Energy Standard Compliance Plan detailing its updated proposal to meet Colorado’s requirement that 30% of PSCo’s retail electric sales come from eligible energy resources by 2020.  (CPUC Docket No. 13A-0836E)  Long recognized for its substantial commitment to wind energy, PSCo’s renewable energy portfolio also includes utility scale solar facilities and various programs designed to facilitate expansion of distributed solar energy installations, including the popular Solar*Rewards® program which has over 15,000 participants and represents more than 160 MW of installed solar capacity.

In its 2014 RES Compliance Plan PSCo proposed adding 42.5 MW of new distributed solar generation, including 36 MW of retail distributed solar generation through the Solar*Rewards® program and 6.5 MW of community solar gardens through the Solar*Rewards® Community program.  At the same time, the company proposed reducing the per kilowatt-hour incentives paid to customers with distributed solar installations.

The more controversial aspect of the utility’s filing related to PSCo’s call for more transparency in the NEM credit paid to customers with installed solar systems and the costs and benefits associated with distributed solar facilities.  PSCo explains that customers with installed solar arrays receive a 10.5 cent credit per kilowatt-hour of electricity they deliver to the grid, however, that electricity only provides 5 cents in benefits to PSCo systems and customers.  While PSCo acknowledges that distributed solar generation allows for some savings associated with fuel costs, energy losses, and the deferral of new generation resources, the utility argues that the NEM incentive paid to solar-owning customers does not adequately consider other costs related to generation, transmission, and distribution, costs that are presently being borne by non-solar customers.  As did APS in the NEM debate in Arizona, PSCo takes the position that the need for and nature of NEM incentives must be reevaluated as the solar industry moves toward becoming self-sustaining.  If the CPUC does not agree with PSCo’s NEM proposals, the utility indicated that it intends to acquire only enough distributed solar generation needed for minimum RES compliance – a total of 12.5 MW.

Solar businesses and trade groups, renewable energy advocates, and environmental groups have strongly opposed PSCo’s analyses and have characterized the utility’s proposal as declaring war on the solar industry.  These stakeholders argue that PSCo’s analyses fail to properly consider distributed solar’s grid, environmental, and job creation benefits.  To that end, the Vote Solar Initiative (VSI) filed a motion requesting that the CPUC sever the NEM issue from PSCo’s RES Compliance docket and conduct a separate, comprehensive NEM cost-benefit analysis.  While VSI’s motion was supported by various other stakeholders, it was opposed by PSCo and CPUC Staff, and was ultimately denied.

An evidentiary hearing on PSCo’s 2014 RES Compliance Plan, including consideration of PSCo’s proposed NEM changes, is scheduled for February 3-7, 2014.  Until then, it is likely that the NEM battle in Colorado will continue both in the CPUC docket and in the public debate concerning the costs and benefits associated with distributed solar generation, how those costs and benefits should be accounted for and allocated, and the continued need for incentives related to this distributed energy resource.

Article by:

Of:

Lewis Roca Rothgerber LLP

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