The Coronavirus (COVID-19) pandemic has severely disrupted the wind market’s supply chain and labor resources, resulting in significant project delay risk. This legal and commercial checklist is a comprehensive practitioner’s guide to help sponsors and borrowers review their tax equity, financing, offtake and material project documents to ensure compliance with obligations, prevent unnecessary default triggers, and manage relationships with banks, tax equity and other stakeholders.
Community choice aggregators (CCAs) are growing in popularity as an alternative electricity provider for communities that want more local control over their energy mix. And so, financiers, CCAs and other business leaders must assess what this growth means for the electric grid, utility business models and project finance. While there’s a primary focus on California, increasing energy loads being served by CCAs and other non-utility suppliers have been trending across the country.
The recent American Council on Renewable Energy (ACORE) Forum united dealmakers, policymakers and systems experts to confront the business opportunities, policy and regulatory issues, and technology challenges associated with integrating high-penetration renewable electricity on the grid. The goal of ACORE’s 2019 forum was to advance efforts for a modernized grid that values flexibility, reliability and resilience. One important session was Community Choice Aggregation: Impacts on Project Finance and Grid Management, which was moderated by Ed Zaelke of McDermott Will & Emery and included panelists Nick Chaset of East Bay Community Energy, Daniela Shapiro of ENGIE, N.A. and Britta von Oesen of CohnReznick Capital.
A Brief History
The first CCA formed in 2010 in Marin County, CA, and since then, the CCA movement has grown very quickly to 19 agencies (19 of California’s 58 counties). Notably, CCAs serve over 10 million Californians today. Helping local governments accelerate climate action is foundational to CCAs, with many seeing CCAs as a positive catalyst in promoting climate action, cleaner energy and finding ways to make the necessary energy investments to actuate transportation electrification and building electrification.
In a nutshell? They want to offer lower-cost energy that is cleaner and find ways to invest in local communities. (more…)
FERC announced actions in response to the 2017 tax reform legislation and a revised income tax policy, which eliminates the income tax allowance for Master Limited Partnerships. Regulated entities should ensure that they comply with FERC’s orders regarding the treatment of income taxes and consider whether to file comments on the proposed rulemaking and notice of inquiry.
Changes to the energy credits proposed in the Tax Cuts and Jobs Act could impact the eligibility of renewable energy projects that had been relying on the guidance previously issued by the Internal Revenue Service.
On September 28, 2017, the US Department of Energy (DOE) submitted a proposed rule to the Federal Energy Regulatory Commission (FERC) that, if implemented, could reshape organized wholesale electricity markets. Citing electric grid reliability and resiliency issues like the 2014 Polar Vortex and recent hurricanes, DOE asked FERC to enact a new compensation system for coal and nuclear power plants—dubbed “fuel-secure resources” by DOE. Coal and nuclear plants have been retiring prematurely and, according to DOE, the retirements are “threatening the resilience of the Nation’s electricity system.”
In order to stem the tide of retirements, DOE submitted to FERC a proposed rule requiring organized wholesale electricity markets run by independent system operators (ISOs) or regional transmission organizations (RTOs) to develop and implement market rules that “accurately price generation resources necessary to maintain the reliability and resiliency” of the bulk power system. The proposed rule would require ISOs and RTOs to provide “a just and reasonable rate” for the purchase of electricity from a fuel-secure resource and “recovery of costs and a return on equity for such resource.” Eligible resources must (i) be located within an ISO or RTO, (ii) be able to provide energy and ancillary services, (iii) have a 90-day fuel supply on site, (iv) be compliant with all environmental laws, and (v) not be subject to cost-of-service rate regulation at the state or local level. Practically, these requirements limit participation to coal and nuclear plants. (more…)
On December 15, 2016, the Internal Revenue Service released Notice 2017-04, which provides welcome guidance on how to meet the “beginning of construction” requirements for wind and other qualified facilities. There has been much uncertainty about when construction of these types of facilities begins for renewable energy tax credit purposes. The Notice (1) extends the “Continuity Safe Harbor” placed in service date for projects that started construction before 2014; (2) provides that the “combination of methods” rule set forth in prior guidance only applies to facilities on which construction begins after June 6, 2016; and (3) clarifies that for purposes of the 80/20 Rule, the cost of new property includes all costs properly included in the depreciable basis of the new property.
On November 17, 2016, the Federal Energy Regulatory Commission (FERC) issued a notice of proposed rulemaking (NOPR) that, if adopted, would require organized wholesale electricity markets (RTO/ISO markets) to modify their open access transmission tariffs and market rules to accommodate electric storage resources and allow participation of distributed energy resource aggregators. This NOPR is part of FERC’s ongoing efforts to remove barriers to participation in wholesale electric markets. FERC recognizes that electric storage resources and distributed energy resources are often constrained by antiquated wholesale market rules that were, as FERC puts it, “developed in an era when traditional generation resources were the only resources participating in the organized wholesale electricity markets.” This NOPR will promote far greater market participation by storage resources of all types, including batteries, flywheels, compressed air and pumped hydro, as well as distributed resources such as distributed generation, electric storage, thermal storage and electric vehicles.
For electric storage resources, which are defined as resources capable of receiving electric energy from the grid and storing it for later injection of electricity back to the grid, the NOPR would require each RTO/ISO to implement tariff provisions that will:
Property assessed clean energy (PACE) programs are an innovative mechanism for financing energy efficiency and renewable energy improvements on private property. They also present a number of challenges to investors—for one, the variance between different programs (even within a particular state) and an understanding as to how particular programs work remains an impediment to investors and to scalability. This post provides a brief overview of PACE programs generally and one particularly popular PACE program – CaliforniaFirst.
Overview of PACE
PACE programs vary by state, but most allow property owners to finance clean energy projects through a voluntary property assessment paid as a line item on their property tax bills. Thirty-two states and the District of Columbia have enacted PACE-enabling legislation and there are active PACE programs in 19 states and the District of Columbia. While most of these states provide financing for commercial PACE projects, only California, Missouri and Florida have active residential PACE programs.
CaliforniaFirst PACE Program for Commercial Property
The CaliforniaFirst PACE program is one of 12 PACE programs active in California and is available for both residential and commercial real property. CaliforniaFIRST is offered by the California Statewide Communities Development Authority (CSCDA) and is currently available in more than 40 California counties, with over 330 participating local governments.
Using the CaliforniaFirst PACE program (Program), commercial property owners can work directly with a clean energy developer and the CSCDA. The developer agrees to install the clean energy project and provide power to the property owner through a power purchase agreement or lease. The property owner pays for the project through a contractual assessment, which appears as a line-item on the property tax bill.
The CSCDA secures the payments through a notice of assessment recorded on the property title. The contractual assessments have priority over any existing mortgage lien. If the property owner sells the property, the repayment obligation remains an obligation of the property. The Program’s underwriting criteria focuses primarily on the relevant payment history and value of the property. The clean energy project must have an effective useful life of at least five years and only new systems can be financed through the Program. The Program is administered by a third-party administrator (Renewable Funding LLC).
As an “interim financing mechanism,” CSCDA and a clean energy developer would typically enter into an assignment and assumption agreement under which CSCDA assigns its rights to receive the contractual assessments to the clean energy developer in exchange for the clean energy developer assuming CSCDA’s financing obligations under the assessment contracts, plus certain specified costs. The assignment term is expected to last three years. On or prior to the end of the assignment term, CSCDA issues bonds to the clean energy developer in exchange for the property tax assessments that were assigned to the clean energy developer. The principal amount, maturity date, amortization and interest rates of the bonds are designed, in the aggregate, to produce cash flows that replicate the principal and interest components of the contractual assessment installments.
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On August 8, 2016, Massachusetts Governor Charlie Baker signed into law a major energy bill aimed at putting Massachusetts at the forefront of states developing offshore wind power. The law, An Act Relative to Energy Diversity (H. 4568), requires Massachusetts electricity distribution companies to procure 1,600 megawatts (MW) of offshore wind energy by June 30, 2027. The United States currently has no offshore wind generation, but Rhode Island wind developer Deepwater Wind is nearing completion of a 30 MW offshore wind farm, which will be the first of its kind in the country. In a statement, Governor Baker’s office said the bill “spurs the development of an emerging offshore wind industry…and represent[s] the largest commitment by any state in the nation to offshore wind.”
The new law requires Massachusetts distribution companies and the Department of Energy Resources (DOER) to jointly develop a competitive bidding process for offshore wind energy generation resources by June 30, 2017. The bidding process will be subject to review by the Massachusetts Department of Public Utilities (DPU). The law permits one solicitation or multiple staggered rounds of solicitation that must result in at least 1,600 MW of aggregate nameplate capacity of offshore wind energy. If the solicitation is staggered, each round must seek proposals for at least 400 MW of capacity, and the costs in each subsequent round must decrease or the proposal will be rejected by the DPU. All proposals received during the solicitation process are subject to review by DOER.
Each distribution company will enter into a contract with the solicitation’s winning bidders for the distribution company’s apportioned market share, calculated based on the total energy demand for all distribution companies, compared to demand in an individual distribution company’s service territory. Distribution companies may use the long-term contracts to purchase renewable energy certificates, energy, or a combination. All proposed long-term contracts executed with distribution companies will be filed with the DPU and subject to DPU approval. Specifics on the solicitation, contracting, and approval processes will come when the DPU and DOER promulgate regulations carrying out the new legislative mandate for offshore wind.
The legislation represents a new chapter in offshore wind for Massachusetts. The infamous Cape Wind project—a proposed 468 MW wind farm—has been held up in the planning stages for years and its current status is uncertain. The new law is a definite step towards Massachusetts’ development of offshore wind energy generation resources. Several wind development companies already hold leases in Massachusetts waters.
The provision contained in incumbent electric utility tariffs—conferring on the holder the right of first refusal (ROFR) to construct additions to the high-voltage electrical grid, regardless of who conceived of and proposed the addition—is unduly discriminatory, the U.S. Circuit Court of Appeals for the D.C. Circuit held in a July 1 decision in Oklahoma Gas & Electric Co. v. FERC, No. 14-1281. The court’s decision upheld utility-specific applications of the FERC mandate—a central open-access innovation of the agency’s Order No. 1000 (Transmission Planning and Cost Allocation by Transmission Owning and Operating Public Utilities)—that directed independent system operators and regional transmission organizations (ISO/RTO) to remove from their existing tariffs and membership agreements the ROFR provision (Removal Mandate).
Earlier in South Carolina Public Service Authority v. FERC, 762 F.3d 41 (D.C. Cir. 2014), the same court generally had upheld the Removal Mandate as applied to ISO/RTOs but had reserved judgment on whether the 60-year-old Mobile-Sierra presumption that the rates in negotiated arm’s length natural gas and power sales agreements are just and reasonable applied to the ROFR provisions of the ISO/RTO tariffs and membership agreements. In Sierra, the Supreme Court of the United States held that the presumption applies against not only the parties to a negotiated agreement but against FERC itself; thus, if it were found to apply to the ROFR, FERC could overcome the presumption only by showing that the ROFR seriously harmed the public interest.
The court could have resolved ISO/RTO and incumbent utilities’ challenges to the Removal Mandate in either of two ways. First, it could have determined that the context in which the ROFR provision was included in the tariffs and membership agreements prevented the presumption from applying in the first instance because of infirmities or unfair dealings in contract formation, such as fraud or duress. Second, it could determine that the presumption did apply and then address the question of whether FERC had overcome the presumption with evidence that the ROFR in member agreements seriously harmed the public interest. The court took the former course. It ruled that the Mobile-Sierra presumption never applied in the first instance because (quoting Order No. 1000 and citing South Carolina), the ROFR “created ‘a pre-existing [i.e., not negotiated] barrier to entry’ for nonincumbent transmission owners.” Citing precedent from the Seventh Circuit, the court found that “such terms” as the ROFR are “self-protective and anti-competitive [and] cartel-like.”
By cabining its holding to the anticompetitive effects of the ROFR, the court was able to bypass two other and possibly more complicated issues. First, it bypassed the issue of whether the Mobile-Sierra presumption applies not only to the rates in regulated natural gas and power sales agreements, but also to agreement terms that affect rates. As the court noted, both the petitioners and FERC argued the case based “on the premise” that the presumption applies to both to rates and agreements terms that affect rates. Second and possibly more nettlesome is whether the Mobile-Sierra presumption would protect other provisions of ISO/RTO tariffs even [...]
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