Renewable generation resources have become the rallying cry for policymakers and developers alike as the movement grows to generate electricity in a more climate-friendly manner. Pending federal legislation creating a carbon cap-and-trade market and a national renewable portfolio standard (RPS), together with existing state requirements, is spurring utilities that lack renewable generation to acquire some—no matter the federal legislative outcome—and causing utilities with sizeable renewable generation to expand their existing portfolios. The economic downturn also has lowered the cost of certain renewable projects, making them more affordable: Cambridge Energy Research Associates reports that project costs for wind projects have declined by 11 percent in the first six months of 2009.
As utilities seek more renewables, they are identifying cost-effective projects through the time-honored method of requests for proposals (RFP). Although many utilities have deep experience with RFPs, in the current economic and regulatory environment an RFP for renewable resources merits special consideration. Some utilities that lack experience with particular renewable technologies have entered joint ventures with experienced developers to spread risk, optimize capital, and benefit from the developers’ superior expertise. Joint ventures, however, raise a host of issues that utilities would not encounter in traditional build-transfer or offtaker arrangements. Also, recent financing trends and new governmental incentives in the form of loan guarantees and tax benefits affect the most cost-effective ownership and contractual structure that utilities should adopt for their renewable projects. Further, in the movement for more renewable resources, many exciting and innovative technologies are under development, but utilities need to understand the technologies’ chances of successful implementation. Utilities should take these factors into account when structuring RFPs for renewable resources in order to attract more potential developers and stronger proposals.
When issuing RFPs, utilities can request that developers propose a joint-venture structure that will be the most cost-effective, allowing developers to be creative with their structures in the hope of identifying superior proposals. But a utility should consider setting parameters around certain variables—ownership of project assets and performance security—to ensure that the joint venture appropriately balances costs, regulatory requirements, and the relative risk profiles and goals of the utility and developers.
Developers and utilities typically own their assets through different structures. Developers usually form a project company (also referred to as a special-purpose entity) that owns only the project assets. Such ownership prevents any liabilities or costs associated with the project assets from adversely affecting the developers’ other projects and also facilitates project financing, in which lenders have limited or no recourse beyond the assets held by the project company. Utilities, in contrast, generally are impelled to own project assets directly without any intermediary legal entities if they are to be permitted to recover the project costs from ratepayers. Utilities could acquire equity interests in project companies through their unregulated generation subsidiaries, but federal and state regulations often make it much more difficult for such subsidiaries to operate effectively in the utilities’ home markets, particularly in franchised service territories.
Developers and utilities can achieve their respective goals of limited liability and rate recovery through a joint-ownership structure known as a “tenancy in common.” As tenants in common, a developer and utility each would own an undivided percentage interest in the project assets, with the interest allocation determined by the parties. They would hold their ownership interests through vehicles that achieve their respective goals: The developer would own its portion of the project assets through a special-purpose entity that limits its liability and allows for non-recourse project financing, while the utility would own its portion directly and thus preserve its ability to recover project costs from its ratepayers. Thus if a utility wishes to receive bids for joint ventures, it should ask developers to draft their proposals under a tenancy-in-common structure.
When a large, creditworthy utility partners with a developer, the utility risks exposing itself to a larger share of liability than its proportionate ownership unless the utility obtains security from the developer or limits its liability by contract. Many developers are small companies with shallow pockets. Even if a developer is a large, established company, it won’t be entitled to rate recovery, a right that contributes significantly to a utility’s creditworthiness. Further, if the developer holds its ownership interest through a special-purpose entity, the developer’s upstream liability will be limited. A regulated utility investing directly in a project lacks similar means of limiting its liability: If the utility is required to own its interest in the assets directly for regulatory purposes, the utility risks becoming a deep pocket in its joint venture.
A utility can mitigate this risk by requiring its developer partner to post security that narrows the disparity between utility and developer. Among other alternatives, such security can take the form of insurance, a guaranty from a creditworthy parent, a security interest in assets owned by the developer’s project company, or a letter of credit. When calibrating the appropriate level of security, the utility should consider what levels of security are appropriate at different stages of the project’s development and how much a security requirement will discourage bids or increase a project’s costs. Asking bidders to include the cost of different types of security as separate line items in their proposals will facilitate the utility’s evaluation of the market cost of credit support.
To some extent, a utility and developer can limit the need for backstop financial security by providing in their third-party contracts that their project liabilities will be several and not joint. Thus a contractual counterparty to the joint venture couldn’t sue just the utility for the entire amount of its claim, but instead would need to pursue each joint venturer for its proportionate share. Although this contractual division of liability has an attractive logic, it might be unrealistic in practice. Some contractual counterparties of the joint venture, such as an EPC (engineering, procurement and construction) contractor or turbine supplier, might refuse to accept several liability without receiving security from the developer or its parent company. And persons with a tortious claim against the project might possess legal rights that override a limitation on liability to which the utility and developer contractually agree.
If a utility doesn’t need an ownership interest in project assets until preliminary development work is complete, it can delay its investment in the project, mitigating the risks associated with ownership. The parties would enter into a joint-development agreement that specifies their relative responsibilities and rights and the expected milestones at which the utility would invest in the project. Such an arrangement might save the developer from posting security to cover the utility’s risk of joint liability until later in the project’s development. In an RFP for joint-venture proposals, a utility can encourage proposals that don’t require the utility’s ownership participation in a project until after the project has achieved some preliminary milestones.
The recent financial crisis has tightened the terms on which developers can borrow to finance their projects. Although a utility does not normally seek project financing, and instead issues corporate debt to be repaid through rate recovery for its share of project costs, the project-financing market does affect the costs faced by independent developers and, in turn, the pricing such developers can offer utilities. If a utility partners with a developer through a joint venture, build-transfer or build-operate-transfer arrangement, it can benefit from understanding how trends in the project-finance market affect the cost of development and, in turn, the attractiveness of developers’ bids. A utility also can include terms in its RFP that will facilitate financing and thereby increase bidder participation and the number of strong proposals.
Today, project-finance lenders are limiting the size of their commitments, are agreeing to lend only for relatively short tenors, and are conditioning their loans on equity investors’ contribution of a higher percentage of project costs, all in addition to their more straightforward demand for higher upfront fees and interest-rate margins. Prior to the financial crisis, developers frequently could negotiate tenors on term loans that ranged from 15 to 20 years, and even longer tenors were possible in public capital markets or from infrastructure funds. In the current market, lenders often are limiting their exposure to much shorter periods, on the order of five to 10 years. As another sign of tightening, prior to the financial crisis equity investment frequently covered as little as 10 percent of the costs of a project, with the remainder financed by debt. Today, lenders often are requiring 20 percent to 30 percent of a project’s costs to be funded by equity. Finally, many lenders are limiting the size of their commitments, a development that may restrict more ambitious renewable projects but spare those developed on a smaller scale, or that might require developers to assemble a larger club of lenders.
In considering how a utility might structure an RFP to lower a developer’s capital costs, a joint venture might help the developer satisfy the lower debt-equity ratios lenders are requiring and operate within the lower loan commitments lenders are giving. Since a joint venture most likely would limit the developer’s responsibility for project costs to the same proportion as its owner-ship share, the developer would need to raise less equity, and the required loan commitment would be smaller.
If a utility intends to enter a power purchase agreement (PPA) with a developer, then the utility can agree to terms in the PPA that cover the developer’s refinancing risk associated with short tenors. For instance, the utility and developer could agree to share the costs (or savings, if any) from a refinancing of the developer’s debt after the expiration of the term of its existing debt, or the utility could agree in advance that, if the developer is unable to refinance, the utility would purchase the developer’s ownership interest at a predetermined price. If in the solicitation a utility signals its flexibility to accommodate financing challenges faced by today’s developers, then it will improve the prospects for a successful RFP.
Although higher financing costs might increase the cost of renewable projects, government incentives for such projects rarely have been more valuable. IRS regulations promulgated last year made the production tax credit (PTC) for renewable-energy projects available to utilities. More recently, the American Recovery and Reinvestment Act of 2009 (ARRA) boosted renewable-energy tax incentives by extending the PTC, permitting the election of an investment tax credit (ITC) in lieu of the PTC, and providing Treasury Department grants in lieu of the ITC for taxpayers lacking income to offset against the ITC. In addition to tax benefits for renewable projects, the ARRA increased the funding available for Department of Energy (DOE) loan guarantees (though Congress recently redirected a portion of this funding to the “cash for clunkers” program). The ARRA also widened the scope of renewable projects eligible for loan guarantees from just “innovative” renewable technologies to include other renewable technologies.
In its RFP, the utility should request that bidders specify how existing and future tax benefits will be shared between the utility and bidders. The utility in its RFP might wish to encourage developers to propose projects structured to take advantage of tax benefits and to share the savings through the developer’s proposed pricing. The RFP also could require developers intending to monetize tax benefits through a sale and leaseback, inverted lease, or partnership flip structure to describe their anticipated tax structuring, since it might affect the utility’s preferred ownership arrangement. If eligibility for tax benefits is conditioned on satisfying certain development deadlines, then the RFP should include appropriate schedule milestones to ensure such deadlines are met and could specify consequences for delay that compensate the utility for any loss of benefits.
Utilities’ RFPs also should ask bidders whether they intend to apply for DOE loan guarantees, which could decrease the financing costs associated with a project. By partnering with a creditworthy offtaker, a developer should more easily be able to demonstrate the creditworthiness of its proposed project, which according to recent guidance from DOE comprises 30 percent of the DOE’s “Phase II” evaluation criteria. Receipt of a DOE loan guarantee, however, subjects a project to certain requirements that might partially counterbalance the lower cost: DOE must receive a first lien on all pledged project assets, which could affect the developers’ financing and, under a joint-venture structure, the utility’s tenancy in common interest (though on Aug. 7, 2009 the DOE proposed eliminating this requirement, in which case DOE instead could share collateral on a pari passu basis with other lenders). Further, all but the smallest projects that apply for a loan guarantee must comply with the National Environmental Policy Act (NEPA), which likely will mandate an environmental assessment or environmental impact statement depending on the project’s characteristics. The time required to prepare either would lengthen a project’s development schedule. A developer’s plan to apply for a loan guarantee could reduce a project’s costs but at the risk of delay, and thus when a utility evaluates competing proposals, it should take into account whether a developer intends to apply for a loan guarantee and the degree to which such a guarantee is necessary for a project’s completion.
One tranche of DOE loan guarantees was authorized several years ago exclusively for innovative renewable technologies, and utilities eager to remain at, or advance toward, the technological forefront might wish to open their solicitations to such technologies. Because new technologies are by their nature un-proven, however, utilities must carefully assess their appetites for technology risks. If a utility enters into a PPA for power to be provided by such a technology, the utility could defer payments to the developer until the technology succeeds in generating electricity. In today’s tight credit markets, however, private financiers are likely to be tight-fisted unless they are confident of a technology’s success. Also, if a utility is relying on a developer’s project to serve the utility’s load by a particular date, then merely delaying payments until commercial operation wouldn’t address the new technology’s risk of delay. To mitigate the risk, the utility could conduct more extensive diligence of the developer’s proposed technology, or require additional financial security to increase the developer’s incentives to perform in a timely manner. The utility’s RFP could require bidders with innovative technologies to submit more background information about their projects than otherwise would be required, to offer additional security, and to demonstrate that their potential sources of financing historically have funded innovative technologies.
When procuring renewable generation resources, utilities today can utilize an RFP process not simply to procure megawatts and megawatt-hours, but to help structure innovative transactions that respond to market constraints, while taking full advantage of new incentives for renewables. Through well-crafted RFPs, utilities can seek expanded information from bidders, explore joint ventures, facilitate financing, and assess technology risk. Also, bidders should be required to describe their anticipated tax structure and any plans to apply for DOE loan guarantees or other renewable incentive programs to ensure the utility has the full scope of data it needs to evaluate proposals appropriately. With a carefully structured RFP, a utility will be well positioned to select a renewable project that achieves the lowest cost of capital and offers the most attractive pricing for the utility and its customers.