California moves forward
The amended plan of reorganization that PG&E Corporation and its subsidiary utility, the Pacific Gas and Electric Company, filed with the bankruptcy court in late September would leave in place all of the renewable energy power purchase agreements and community choice aggregation servicing agreements that the utility has currently.
Financiers are taking a wait-and-see approach before financing or refinancing any project with a PG&E contract.
The plan shows that PG&E expects to pay most creditors in full.
The main battle will be with wildfire victims. PG&E cannot emerge from bankruptcy until all wildfire-related lawsuits have been settled.
After submitting its original plan, PG&E settled with insurance companies and agreed to pay $11 billion in connection with fires in 2017 and with the Camp Fire in 2018. Ultimately, the amended plan is likely to be contingent on how the remaining unsettled wildfire claims are resolved. Additional plan amendments will be needed if PG&E settles the claims for more than what is currently budgeted.
The steps to obtain approval of the amended plan are as follows.
First, PG&E needs to obtain approval for the form of disclosure statement, which summarizes the plan, and for the proposed voting procedures. As of now, only the wildfire claimants would be entitled to vote because creditors that are paid in full are not entitled to vote.
Next, voting occurs. After voting, claimants can file objections to the plan. If PG&E obtains the votes needed to approve the plan, then there is a plan confirmation hearing. Finally, the plan becomes effective, once all of the conditions occur. The conditions include California Public Utility Commission (CPUC) approval and necessary financing being put into place. The CPUC must approve participation by PG&E in a new wildfire fund described below and find that the plan is consistent with the state’s climate goals and is neutral, on average, to the ratepayers.
PG&E must emerge from bankruptcy by June 30, 2020 in order to participate in the new wildfire fund.
PG&E must put in place new equity offerings and new debt at both the parent and utility level. If California enacts new legislation that provides for wildfire recovery bonds, then the utility expects to take advantage of those. However, the state legislature failed to act before the end of the legislative session in mid-September.
While the plan will change in some respects, PG&E is not currently seeking (and seems unlikely to seek) to terminate any power purchase agreements.
If ultimately approved and effective, the plan is likely to have two major effects.
First, by assuming all power purchase agreements, PG&E will avoid any drawn-out fight with existing power suppliers. The dispute earlier in the year with the Federal Energy Regulatory Commission over whether FERC must approve any cancellations of power purchase agreements becomes irrelevant if the current PG&E plan is confirmed.
Second, it strongly increases the likelihood that future projects in California can be financed, perhaps with a “PG&E risk premium” for projects with PG&E contracts. Had PG&E terminated some of its power purchase agreements, it almost certainly would have created a huge hurdle to financing any projects in California. Financiers would have paused, and possibly decided not to fund, future projects with other utilities that had any chance of being pushed into bankruptcy by their own wildfires. With two bankruptcies in 20 years, it is hard to imagine any future project with PG&E being financed.
While most utilities are currently ahead of their targets under the state renewable portfolio standard, the state will need increasing volumes of renewable energy as the RPS targets increase over time. (For the current California RPS targets, see “California Update” in the August 2018 NewsWire.) The assumption of all power purchase agreements ensures access to the significant capital that will be required for the state to pursue its goals.
PG&E’s proposed plan will also have an impact on existing financings.
Most financings of projects that supply power to PG&E are technically in default due to the PG&E bankruptcy. Most lenders have allowed their borrowers to remain in default without exercising remedies because it was unclear what would happen to power purchase agreements, and lenders did not want to exercise remedies prematurely. Once PG&E emerges from bankruptcy, the defaults are probably not automatically cured, but the lenders are likely to waive any defaults relating to the bankruptcy because the plan keeps all contracts in place.
PG&E probably owes money to many counterparties (such as for energy delivered under power purchase agreements shortly before the bankruptcy filing) that it was not allowed to pay due to the bankruptcy filing. Assuming that the counterparties filed a notice of claim, these outstanding amounts will get paid as part of the resolution of the bankruptcy.
Not all parties to the bankruptcy case support PG&E’s proposed plan. The official committee of tort claimants and an ad hoc group of senior noteholders have joined forces in opposition to the plan, and they are seeking permission from the court to file their own proposed plan of reorganization for PG&E. A court hearing is scheduled for October 8 to consider this request, but either way, renewable projects remain in good stead. The terms of the committee and ad hoc group’s plan, like PG&E’s plan, provides that no renewable energy power purchase agreement will be rejected by PG&E.
While the state legislature did not block PG&E from filing for bankruptcy, it has been busy trying to ensure that the other California utilities do not face the same fate and to put PG&E in a position to weather future wildfires. However, there was no serious consideration given to changing the doctrine of inverse condemnation that holds utilities strictly liable for the fire damage, even if they followed best practices to avoid fires.
In July, Governor Gavin Newsom signed a bill called AB 1054 that addresses wildfires in several different ways.
The most prominent provision is creation of a new wildfire fund to be funded by the utilities and ratepayers. Both Southern California Edison (SCE) and San Diego Gas & Electric (SDG&E) already funded their shares of an initial $2.7 billion contribution to the wildfire fund. PG&E is supposed to contribute $4.8 billion after it emerges from bankruptcy. PG&E must annually contribute an additional $193 million, while the three investor-owned utilities (IOUs) combined must contribute $300 million every year.
Neither the initial contribution nor the annual contribution is recoverable from ratepayers. The legislature wanted the utility shareholders to bear this burden. However, if a utility must draw on the fund to pay claims and then replenish the fund, the contribution to replenish is potentially recoverable from ratepayers.
The new wildfire fund will act as a general fund on which any participating utility can draw to pay future eligible wildfire claims. A utility can only make a claim on the fund for claims that exceed $1 billion in the aggregate (or, if greater, the amount of insurance coverage required to be in place, based on a “reasonableness” standard).
If a utility receives payments from the wildfire fund, then it must file an application with the CPUC to recover costs. The CPUC is required to allow cost recovery if the costs are just and reasonable, which is determined by looking at the conduct of the utility related to the ignition of the wildfire and determining whether the utility’s actions were consistent with actions that a reasonable utility would have undertaken in good faith under similar circumstances. If the utility has a valid safety certification (the standards are in the new law), then there is a rebuttable presumption that its conduct in connection with a wildfire will be assumed to have been reasonable.
The law also requires significant new spending on wildfire prevention, including $5 billion in fire-risk mitigation spending that cannot be included in rate base.
The law also ties executive compensation directly to safety. In order to receive a safety certification, a utility must establish an executive compensation structure that is designed to “promote safety as a priority,” which may include tying all incentive compensation to safety performance and denying all incentive compensation if the utility causes a catastrophic wildfire that results in any deaths.
The wildfire law appears to have provided some relief to the utilities.
The rating agencies upgraded the outlook for both SCE and SDG&E and kept their ratings as investment grade. Lenders are considering funding projects with power purchase agreements with utilities other than PG&E. They are being cautious now, but the market seems to be assuming that California utilities will be safe counterparties going forward.
California’s wildfire season has already started this year. Whether AB 1054 actually helps the utilities in the long run will depend on, among other factors, the severity of future wildfire losses and whether they deplete the new wildfire fund.
Another bill, SB 520, has been sent to the governor for his signature. It allows the CPUC to decide what load-serving entity should serve as the electricity provider of last resort if a community choice aggregator (CCA) were to fail.
Current law assumes that the local investor-owned utility has an obligation to serve as the provider of last resort. Under SB 520, that remains true, unless otherwise provided in a service territory boundary agreement approved by the CPUC or the CPUC designates a load-serving entity other than the local utility pursuant to a joint application by the local utility and another electricity supplier.
The bill is supposed to provide a safety net for customers of CCAs and other electricity suppliers whose suppliers exit the market.
CCAs lobbied against the bill on grounds that it entrenches the utilities as the providers of last resort; if the utility does not sign a service territory boundary agreement or a joint application, then it will remain the provider of last resort.
The bill will not slow the creation of CCAs in California or the flight of customer load to the CCAs. However, it may be a source of leverage for utilities that could be used to the disadvantage of CCAs. For example, a utility may refuse to enter the agreement or application necessary for a CCA to be the provider of last resort, unless the CCA gives the utility something in return.
The CPUC has found that there is a significant possibility of a resource adequacy reliability shortfall in Southern California by the summer of 2021.
To address this, the CPUC issued a proposed decision recently that calls for 2,500 megawatts of incremental system resource adequacy and renewable integration resources to be acquired by all load-serving entities serving load within SCE’s transmission access area. The decision calls for 60% of this amount to be on line by August 1, 2021, 80% by August 1, 2022 and 100% by August 1, 2023.
SCE is required to procure 1,745 megawatts, a group of electric service providers are required to procure a total of 355 megawatts and six community choice aggregators are required to procure between five and 357 megawatts each.
The solicitation is for all resources, as long as they are incremental to the 2022 baseline set of resources. This may give pause to those who want to develop renewable energy projects or storage facilities. However, the CPUC has made it clear that SCE must “conduct its solicitation in a non-discriminatory manner, treating all resources on a level playing field as long as they deliver equivalent value.” The proposed decision also noted that “resources with different costs may be evaluated differently, so long as similar attributes are valued similarly.”
Developers should be sure to show the value of their projects clearly and how the projects compare to other resources and to highlight the advantages of their projects. A new project that on its face seems more expensive or uncompetitive may still be viable if the developer can show the project’s value and how it is better than other resources to address reliability. For example, a storage project could address an important issue that the CPUC identified in its proposed decision, which is that the system “peak is moving later in the day and later in the year, which does not coincide with the value provided by solar resources.”
The proposed decision does not set a megawatt requirement for hybrid generation and storage projects, but the CPUC expects such projects to be competitive in the solicitation. Another advantage for clean energy solutions is that the impacts of localized air pollutants and greenhouse gases on disadvantaged communities must be minimized.
Contracts entered by IOUs and CCAs for new resources to deliver system resource adequacy and renewable integration capacity must be at least 10 years in length. This is to avoid a cliff when resources drop off, but it could also encourage development of new projects. While traditional PPAs were for 20-plus years, many projects are now financed on the basis of a shorter revenue contract. However, developers should be mindful of the impact on financing that shorter contracts can have, such as an increased focus on refinancing risk and lower leverage.
Another issue that developers may contend with is utility ownership. The proposed decision allows SCE to propose to own a portion of the resources to be procured, but SCE “must propose its evaluation and comparison metrics for the CPUC consideration” and “must adhere to the existing rules about utility participation in utility-run solicitations.” Because the CPUC does not have authority over the ownership decisions of the non-IOUs, such entities “may conduct procurement in the interests of their own ratepayers.”