OFAC revokes so-called U-turn authorization for Cuba-related financial transactions
OFAC published a final rule that modifies the Cuban Assets Control Regulations to revoke the so-called "U-turn" authorization.
A report by the California Public Utilities Commission in May predicts that more than 85 percent of California’s retail electric load will be served by sources other than investor-owned utilities by the middle of the 2020s.
IOUs are being replaced in large part by community choice aggregators. By the end of 2017, the number of customers in California who get power from community choice aggregators is expected to reach almost one million.
Amidst this backdrop, wind and solar developers and potential lenders are assessing the financeability of projects that have long-term power purchase agreements with CCA offtakers.
This article identifies some unique features with which they will have to grapple.
A CCA is a legal entity, usually a joint powers authority, formed by one or more counties, cities or towns for the purpose of purchasing power on behalf of the residents and businesses within local boundaries. The incumbent utility, which no longer provides the electricity, still remains responsible for transmitting and distributing the power, as well as for billing, collections and other customer services. Laws enabling this structure have been passed in California, Illinois, Massachusetts, New Jersey, New York, Ohio and Rhode Island.
California has seen a proliferation of CCAs since the first one launched in 2010. There are now eight operational CCAs, and at least 15 more are in various stages of planning, altogether covering 23 counties.
The Los Angeles County CCA, scheduled to launch in January 2018, will be the largest in the state. The total average annual energy use of all cities and unincorporated areas within LA County is around 3,440 megawatts, with a 7,900 megawatt peak. This amounts to more than 30 percent of Southern California Edison’s total load. (SCE itself accounts for about 27 percent of aggregate state load.) LA County plans to procure power with at least 50 percent renewable energy content to meet this load, almost twice SCE’s current 28 percent. The aggregator could end up procuring even more renewable power, depending on how many customers sign up for 100 percent renewable content.
Community choice aggregators present a huge new opportunity for developers of wind and solar projects because they are focused on purchasing renewable energy to serve customer load. CCAs have three unique features.
CCAs do not yet have credit ratings, although some of the older CCAs are actively working on establishing a credit rating.
One way to fill this gap is to set shadow metrics that signal possible trouble for a project whose power contract is with a CCA. They would act like tripwires, triggering cash traps, operating reserves and cash sweeps to backstop and pay down project-level debt more quickly.
These tripwires are the same credit metrics that rating agencies use to assess credit default risk. They typically include measures of cash flow, earnings, leverage and coverage. Using these building blocks, the parties can negotiate bespoke metrics for the transaction designed to give a picture of the CCA’s financial health and signal vulnerability to default on financial obligations. An example of a CCA-specific metric would be opt-out rates, or the decrease in number of customers measured against a baseline.
If any of the credit metrics is not maintained, then protections are triggered under the loan agreement to reduce the exposure of the lenders. Possible protections include cash traps, cash sweeps and reserve accounts. In project finance, cash sweeps or distribution blocks are used to motivate the borrower to remedy violations of financial covenants. The difference here is that the trigger event relates to the financial health of the offtaker.
If tax equity is involved, back-levered lenders should take into account any protections the tax equity investor has built into the tax equity deal that may be triggered ahead of any protective measures on which the back-levered lender is counting. For example, in some partnership flip transactions, the tax equity investor is entitled to cumulative preferred cash distributions ahead of any distributions to the sponsor partner. This means that the sponsor member bears the risk that the CCA is not creditworthy and, by extension, so does any lender who lends at the sponsor level rather than the project level. In other deals, there may be a cash sweep starting on the projected flip date if the tax equity investor has failed to reach its target yield by that date.
Where tax equity will sit behind the lender in the capital stack, the tax equity investor will require the lender to enter into a forbearance agreement promising not to foreclose on the project after some kinds of defaults to give the tax equity investor time to reach its target yield. The lender can take over the sponsor position as managing member of the tax equity partnership in the meantime. Cash sweeps, reserve accounts and distribution blocks in favor of a project-level lender have not typically been addressed in forbearance agreements involving projects with utility PPAs. They may become a focus in projects contracting with CCAs. (The same issues should be present in projects with corporate PPAs.)
Leveraged partnership flip transactions — where there is debt at the project level ahead of the tax equity — are rare in the current market.
A CCA may have a hard time offering credit support. Any such support would have to come from the municipalities inside the CCA service area and, thus, would require approval by the county board of supervisors or one or more city councils.
This requirement is rooted in the legal structure of a CCA. The California legislation that enables CCAs, AB 117, provides that a group of cities and counties can elect to combine their loads through the formation of a joint powers agency. A JPA is established pursuant to the Joint Exercise of Powers Act (Government Code, section 6500 et seq.). That act provides that a JPA is a public entity separate from the parties to the underlying joint powers agreement. To this point, the joint powers agreement for a CCA typically includes a provision stating that the debts, liabilities or obligations of the JPA shall not be debts, liabilities or obligations of the individual municipalities, unless the governing board of a municipality agrees in writing to assume such debts, liabilities or other obligations.
Opt-out risk refers to the risk that individual customers will decide to switch back to utility service.
Historically this risk has proved low, with actual opt-out levels averaging around 7 percent according to recent feasibility studies conducted on behalf of counties and cities exploring CCA formation. However, the data are not deep. The oldest CCA has been operating in California for only seven years.
The key thing to remember is that a CCA has the advantage of being the default electric service provider for all electricity consumers within its boundaries. Existing IOU customers are automatically switched to CCA service. This is provided for in AB 117. The act says that “if a public agency seeks to serve as a community choice aggregator, it shall offer the opportunity to purchase electricity to all residential customers within its jurisdiction . . . . [A]ll customers shall be informed of their right to opt out of the community choice aggregation program . . . . If no negative declaration is made by a customer, that customer shall be served through the community choice aggregation program.”
Opt-out risk can also refer to the risk that counties or cities that initially voted to form a CCA will decide to withdraw from the CCA.
If a county or city leaves the CCA, then the CCA will no longer serve the load of those customers. This risk may prove to be low for two reasons.
First, the ability of a county or city to withdraw from a CCA is typically constrained by the terms of the joint powers agreement. In addition to a requirement to give advance notice of a decision to withdraw from the JPA, the agreement typically provides that a withdrawing participant will remain responsible for any financial obligations arising from the party’s participation in the CCA program before the withdrawal date. Some joint powers agreements state explicitly that this continuing liability includes any losses from the resale of power contracted for by the JPA to serve the withdrawing party’s load. Some agreements also allow the JPA to charge the withdrawing party a fee set at an amount that would offset costs to the remaining CCA ratepayers.
The second factor mitigating the risk of a municipal opt-out is that the CCA movement is underpinned by state and local climate change goals and renewable energy targets. California set an ambitious new goal in SB 32 in December 2016 of reducing greenhouse-gas emissions to 40 percent below 1990 levels by 2030.
Evidence suggests CCAs are helping meet these goals. A recent study by the Luskin Center for Innovation at UCLA found that for the same amount of electricity delivered, four out of five CCAs studied beat IOU emissions by an average of 43 percent due to higher use of renewable energy. The one outlier had an emissions level that was 1 percent higher than the local IOU due to heavy use of renewable energy certificates by the IOU.
CCAs are also often cited as being a key tool for achieving local renewable procurement targets. When San Francisco launched its CCA in 2016, public officials praised the program as an important step toward achieving the city’s goal of 100 percent renewable energy use by 2020. Similarly, San Diego City’s climate action plan sets a renewable procurement goal of 100 percent by 2020 and points to CCAs as a way to get there. The city of San Diego is currently exploring the idea of setting up a CCA.
To remain competitive, a CCA must procure power at a rate that is lower than the retail rate charged by the local utility plus a surcharge called the power charge indifference amount or “PCIA.”
The formula for calculating the PCIA is currently under review as part of a broader review of the regulatory and policy framework affecting retail choice and the future role of utilities by the CPUC and the California Energy Commission. (For the latest on these proceedings, see “The Changing California Electricity Market” in this issue starting on page 5).
The risk is that the PCIA could increase to a level that would drive customers away from CCAs.
The PCIA, more informally known as an “exit fee,” is what utilities charge customers who leave utility service to take electric service from CCAs or other non-utility power marketers under the evolving California retail choice program. The objective of the PCIA is to ensure that the remaining utility ratepayers remain economically indifferent to whom California residents use as their electricity suppliers because the utilities would still cover the cost of power procurement investments made by utilities on behalf of customers who later switch to CCAs. These costs would have been recoverable by the utility through electricity rates, but they become stranded when the customers leave.
The amount of the exit charge is set annually by comparing the actual costs of the utility’s portfolio of assets to the market value of those assets. The fact that they can change annually is a risk. The exit charge does not allow the utility to recover the entire cost of procurement, only the uneconomic portion, meaning the extent to which the power was procured at a price that is above the current market price. The idea is that if the utility procured the power at a price that is below current prices, then the utility should be able to mitigate losses by selling excess energy and capacity into the market. Because the PCIA represents the above-market portion of generation costs, when market prices fall, the PCIA increases.
There is general agreement that the current methodology for calculating the PCIA is flawed. (For a discussion of the main issues with the PCIA, see “Huge Potential New Demand for Power” in the October 2016 Newswire).
The CPUC has said that its task is to adjust the PCIA methodology in a way to both allows customers to continue to make the choices they want and ensures that all other customers are not left with an unfair allocation of costs. Fees set too high undermine retail choice, while fees set too low unfairly shift costs to unbundled customers of the utility.
Interestingly, AB 117 also gives CCAs the right to charge their own exit fees under certain circumstances. The law provides that fees may be imposed on customers who choose to opt out of CCA service after a 60-day grace period. The fee must be approved by the CPUC. This issue will be reviewed in the same CPUC and CEC proceedings relating to the PCIA.
OFAC published a final rule that modifies the Cuban Assets Control Regulations to revoke the so-called "U-turn" authorization.
On 5 September 2019, Professor John McMillan AO’s Final Report (Report) on the operation of the Narcotic Drugs Act 1967 (ND Act) was tabled in Parliament. Section 26A of the ND Act required the Minster to cause a review of the operation of the ND Act to be undertaken.