As previewed in an October 2019 article in Tax Notes Federal, 1 in November 2019 the IRS published a private letter ruling2 in response to a regulated utility's request for rulings on (1) whether a wind-powered electrical generation facility with a wholesale power purchase agreement (PPA) would be treated as public utility property and (2) whether the PPA, if between the utility and a tax equity partnership, would be subject to loss disallowance rules applicable to related-party transactions. The IRS (1) held that the facility would not be treated as public utility property because it has a revenue contract that is set at market-based rates rather than a revenue stream set on a regulated rate-of-return basis and (2) declined (on the ground that further legislation or regulation was necessary) to rule on the second request.

This article will further the conversation begun by the authors of the October 2019 article by drawing from our experience representing the tax equity providers in the structuring and negotiation of what we believe is the only wind production tax credit (PTC) transaction to have achieved a binding commitment between a regulated utility and a tax equity provider. We will also discuss the effect of the ruling on transactions involving facilities that claim the investment tax credit. The ruling does not address the application of normalization rules to a utility-sponsored tax equity partnership that claims the ITC, but the analysis used in the ruling sheds light on how the IRS may view a similarly situated ITC transaction.

I. Ruling's Effect on PTC Tax Equity Financing

Our experience is consistent with the suggestion by the authors of the October 2019 article that a tax equity transaction between a regulated utility and a tax equity provider can be challenging, particularly regarding the regulatory overlay that is applicable to regulated utilities (that is not applicable to the independent power producers that regularly raise tax equity financing). The transaction on which we worked took more than 18 months of persistence and ingenuity on the part of equity providers and the utility to achieve a binding commitment. We believe, and our experience demonstrates, that in many cases the challenges faced by these transactions can be overcome.

The letter ruling is an important step in reducing the barriers to utility-sponsored tax equity transactions because it provides some certainty that the IRS will not treat a facility as public utility property if that facility sells its output for rates that are determined on a wholesale market basis. Thus, it also provides some certainty that depreciation of the facility assets would not be subject to normalization rules. However, this issue is only one of several challenges faced by utility-sponsored tax equity financings.

A. Utilities Need Permission From Regulators

Before we discuss the process and hurdles involved in a utility obtaining the necessary approvals to enter into the tax equity financing of a facility, we want to emphasize how important it is that a utility must plan carefully, in detail, and well in advance of making any regulatory filings. The utility should engage in planning with potential tax equity investors and advisers with extensive tax equity experience. Once a filing has been made with a state public utility commission, we have found that a utility faces enormous pressure to not change the form or content of the transaction that it described in its regulatory filings. Tax equity transactions are highly specialized, rule-intensive, nuanced, and difficult to properly structure and execute. We have seen unfortunate (and avoidable) outcomes when the needs of tax equity investors clash with the need to follow the form and content of the transaction described to state regulators. Investing resources upfront to carefully plan will pay dividends in the long run.

When a retail utility adds an electric generating asset to its fleet and uses that asset to produce power for its retail customers, it can, with approval from its state public utility commission, include in the rates it charges its retail customers the cost of acquiring that asset (spread over the life of the asset; that is, normalized). To include the costs of those facilities in base retail rates, the utility must justify to the state public utility commission the prudence of the investment(s), as well as the appropriateness of including those costs in retail electric rates. Retail ratepayer advocacy groups, state agencies responsible for protecting the public interest, and utility customers regularly challenge utilities' investment decisions (and proposals to include investment costs in base retail rates) to minimize the electricity rates to which captive retail ratepayers are subject.

Instead of acquiring the sole ownership interest in a generating facility, the utility that obtains tax equity financing for a project owns a partnership interest in a tax partnership (in most utility-scale tax equity transactions, the entity is a limited liability company that is treated for tax purposes as a partnership) and the tax partnership owns the facility. It is the cost of acquiring that partnership interest that the utility intends to recover from its ratepayers. Explaining to a state public utility commission and ratepayer advocates why this ownership structure makes sense for ratepayers is no small feat. This undertaking is likely the highest hurdle in structuring a utility-sponsored tax equity transaction, given that the public utility commission and ratepayer advocates may not be familiar with the tax equity financing structure and terms, as well as the economic reasons why this structure could be at least as good for ratepayers as would be the purchase of power from an independent power producer in accordance with a PPA. Thus, a utility that is considering arranging a tax equity financing for one of its generating facilities should plan carefully and well in advance so that it can begin conversations with all its stakeholders (like public utility commission staff, ratepayer advocates, and major customers) far ahead of any formal filing with a state public utility commission.

In addition to educating and achieving buy-in from stakeholders regarding the fundamental economic structure and consequences of a proposed utility-sponsored tax equity transaction, utilities face several other procedural hurdles. For example, in the normal course of utility ownership of generating facilities, the entity that is itself the regulated utility owns all the assets that it includes in its rate base. In fact, we are aware of only a few situations in which a regulated utility has owned rate-based assets via a special purpose entity, much less a situation in which that special purpose entity is co-owned by another entity that is not a regulated utility. Even something as basic as having a special purpose holding company own the generating facility (which is almost a universal practice in the non-regulated-utility market for generation and transmission infrastructure) is likely a novel issue for many state public utility commissions.

A utility-sponsored tax equity transaction is only viable (but also only useful) in states that have not unbundled the procurement of electricity from transmission and delivery service (only 13 states plus Washington have active unbundled retail electric choice programs). Also, some states do not allow utilities to file limited rate cases for specific investments. In states that do not allow limited rate cases, the utility would have to incorporate a proposed tax equity financing in a general base retail rate case — an exercise that is already complex, time- and resource-intensive, and of great importance to the utility's business as a whole. Because each state has authority to regulate franchised retail utility monopolies that operate within that state and because the rules and procedures applied by each state have been developed over time in a manner that is unique to that state, the experience of each utility will vary depending on the state(s) in which the utility operates. Moreover, states will have differing priorities, which may result in a single utility receiving approval for a proposed rate-based investment from some, but not all, states in which it operates.

Tax equity providers will expect a sponsoring utility to have secured — before the funding of any tax equity financing — state public utility commission approval to recover from its ratepayers the cost of the utility's investment in the tax equity partnership. While commission approval is not necessary for the tax equity provider to receive its bargained-for return, it does bear on the credit quality of the utility. The utility's credit stands behind the indemnity obligations it has to the tax equity provider. Also, tax equity may seek protections against any adverse tax consequences resulting from the utility's inclusion of its equity investment in its rate base.

B. Most Utilities Lack Experience With Tax Equity

In the past, utilities preferred not to own renewable energy power plants for reasons unrelated to the tax normalization rules. Renewable energy technologies were unproven and expensive. There was skepticism that they could be deployed at a large scale because they relied on intermittent resources. Few states had aggressive mandates for utilities to source generation from renewables.

In recent years, that trend has reversed. Wind and solar facilities now have long and stable operating histories. Utility-scale plants are being appraised based on useful lives in excess of 30 years. Large-scale electricity storage and demand-response facilities are rapidly being developed and deployed to more closely align intermittent solar and wind resources with intermittent consumer demand. States are now regularly setting aggressive renewable portfolio standard targets. Utilities are actively developing and acquiring renewable energy facilities. We are regularly working on transactions involving the acquisition by utilities of wind and solar facilities at all stages of the project life cycle.

While utilities are accustomed to developing and acquiring power plants, most are not accustomed to tax equity financing. Utilities generally have access to more conventional public and institutional debt capital markets and can obtain low-cost and long-term financing by leveraging their aggregated property, plant, and equipment, or issuing notes secured by project assets. The supply in conventional debt capital markets outweighs demand and borrowers are driving historically low pricing and borrower-favorable terms.

The tax equity market is different. While pricing for utility-scale projects has come down over the last few years, terms remain investor-favorable, and the supply of tax equity providers for utility-scale projects remains limited. Tax equity providers require significant reporting obligations and consultation/veto rights for major decisions that affect project operations. Utilities are not accustomed to involving outside parties, particularly investors, in these kinds of decisions. Long-established internal utility processes may need alteration to comply with tax equity's needs.

Further, tax equity transactions are considerably more complex to structure and negotiate than most conventional debt capital market transactions. Transactions, and the facilities to which they relate, should comply with tax rules and, just as importantly, market norms for key structural and factual determinations like start of construction, continuous efforts, and appropriate developer fees. These additional compliance needs — and the fact that in the market for utility-scale tax equity, investors do not permit project-level debt financing as long as they own an interest in the facility — also complicate other aspects of the overall development, acquisition, construction, and financing of a renewable energy facility.

Also, the utility arranging tax equity financing is likely at the same time negotiating a commitment to purchase the facility from the initial developer and arranging (or supporting the arrangement of) construction financing. Each of those component transactions is intertwined and even the most experienced sponsors find it challenging to juggle all three at one time and keep them moving in concert.

C. Illiquid Power Markets Less Likely to Benefit

ground that further legislation or regulation was necessary) to address whether a PPA between the tax equity partnership and the utility that owns the sponsor interest in the tax equity partnership would be subject to loss disallowance rules applicable to related-party transactions. The implication of the ruling is that the loss disallowance rules actually do apply to those arrangements. This ruling (or lack thereof) is likely to have somewhat of a chilling effect on the use of PPAs in utility-sponsored tax equity transactions. That effect is likely to be much more pronounced in power markets that are either bilateral or illiquid to the point that merchant volume and pricing is unstable. In markets in which the electricity and related attributes generated by a project could be sold under an arrangement, other than a PPA being the tax equity partnership and the sponsoring utility (like merchant sales or a short-term, third-party offtake agreement) for a portion of the facility's useful life, there are scenarios in which a sponsoring utility PPA could still be employed for the majority of a tax equity investor's expected investment horizon.

For a utility to recover its investment in a generation plant from its ratepayers, the plant must serve those ratepayers, but there is generally not a requirement that the generating facility be sited within the utility's geographic service area. Yet if utilities seeking to enter into tax equity arrangements are limited to selling the output of those tax-equity-financed facilities via open market sales or short-term third-party offtake agreements, then they are limited to employing facilities in geographical locations with liquid open power markets. This limitation would seem to greatly reduce the possibility of utility-sponsored tax equity transactions for facilities sited in bilateral and illiquid markets like most of Utah and Nevada (both seeing strong growth in commercial electricity demand, and both with robust solar resources).

As tax equity providers will generally not finance utility-scale projects that have significant exposure to merchant price volatility, a utility-sponsored project obtaining tax equity financing and selling electricity output on the open market also needs to obtain a hedge against price volatility. This hedge needs to be arm's length and on customary market terms because the IRS has the power to retroactively change the terms of non-arm's-length transactions between related parties so as to make those transactions arm's length. A revision of that type could be significantly detrimental to a tax equity investor's economic position. Tax equity providers will heavily scrutinize the hedge not only from a commercial perspective, but also to ensure that it is on customary market terms. Tax equity providers also customarily expect the project sponsor (that is, the utility) to bear hub/node basis differential risk and will require limitations on day-ahead merchant sales (and other forms of speculative or predictive trading) to limit the risk of facility nonperformance.

II. Ruling's Effect on ITC Tax Equity

In addition to the wind PTC transaction that we worked on, we know of a utility-sponsored solar ITC transaction that has also closed. While the letter ruling only directly addresses a wind PTC transaction, the analysis in the ruling should be equally applicable to an ITC transaction. The ruling states that "for purposes of application of the normalization rules, the definition of public utility property is the same for purposes of the investment tax credit and depreciation."

Nonetheless, the market would benefit from a utility obtaining a private letter ruling for a solar ITC project with a proposed tax equity financing.

The effect of the analysis in the letter ruling on ITC transactions is even more significant than its effect on PTC transactions. Because PTCs are based on actual project performance and because the PTCs are recognized as they are generated over the 10-year credit period, the normalization rules do not apply to PTCs and have much less influence on the value of the tax benefits (including depreciation) available in a PTC transaction than a comparably sized ITC transaction. If the normalization rules were applied to a utility-sponsored ITC tax equity transaction, the ITC would be disallowed, a result that would be much more economically negative than a comparably sized PTC tax equity transaction.

Tax equity providers are likely to expect utility sponsors to take the risk that normalization rules apply to the tax equity partnership. That risk allocation will generally take the form of an indemnity that is undertaken or guaranteed by a creditworthy utility parent company.

III. Conclusion

The letter ruling is a significant step in the right direction toward an established market for PTC and ITC tax equity financing for utility-sponsored renewable electricity generating facilities. Equally significant hurdles remain, but enterprising utilities and tax equity providers have shown that those hurdles can be overcome. Utilities and tax equity providers interested in transacting should begin conversations with potential tax equity providers, stakeholders, and advisers with extensive tax equity experience far in advance of any potential transaction and should be prepared for the process to stretch out over a much longer period than is the norm in non-utility-sponsored tax equity financings.

Footnotes

1. Brian R. Murphy and Michael J. Reno, "A Path for Utilities' Ownership of Wind and Solar," Tax Notes Federal, Oct. 21, 2019, p. 445.

2. LTR 201946007.

Originally published by Tax Notes Federal

The content of this article is intended to provide a general guide to the subject matter. Specialist advice should be sought about your specific circumstances.