- Recent rolling blackouts across California highlight the potential for operational and financial challenges for electric utilities in that state and elsewhere as they embrace intermittent renewable resources.
- Although many states have introduced carbon-free mandates, the targets could be overly ambitious because achieving some elements of the decarbonization frameworks might not be feasible.
- Although pass-through mechanisms and other measures might insulate a not-for-profit utility's financial performance during price spikes, the corresponding rise in retail rates could alienate customers, interfere with their ability to pay their bills during periods of extreme costs, and create barriers to rate adjustments.
August's rolling blackouts across portions of California were attributable to electricity scarcity during a heat wave. Utility customers faced the specter of similar outages over the Labor Day weekend because of record temperatures. S&P Global Ratings believes that these blackouts are unlikely to meaningfully disrupt the revenue streams of the state's public power utilities. However, in our opinion, the blackouts portend operational, financial, and ratemaking challenges for not-for-profit electric utilities in California and elsewhere that face mandates to decarbonize.
The Race To Decarbonize Is On
Ever-changing environmental regulations have whipsawed public power and electric cooperative utilities' generation resource strategies in recent years. Following the federal government's supplanting the Environmental Protection Agency's Clean Power Plan with the more liberal Affordable Clean Energy Rule, many state and local jurisdictions have pressed ahead with their own climate change regulations and legislation to fill the void they perceive at the federal level (charts 1 and 2). We believe states and municipalities are acting in response to pressures from constituents to reduce power plants' greenhouse gas and particulate emissions.
We view the states' carbon-free mandates as laudable goals. At the same time, we see their targets as ambitious because elements of the decarbonization frameworks might not be technologically feasible. This is particularly true because of the paucity of carbon-free resources that can firm up the intermittent characteristics of renewable resources and facilitate their integration into generation fleets. It is technologically difficult and costly to counter intermittency, and adding storage capacity can saddle utilities with financial and operational burdens. In the absence of meaningful storage solutions, we believe there is the potential for compromised electric service reliability, which can fuel customer ire and create barriers that impede the flexibility we typically associate with the autonomous ratemaking authority that public power and electric cooperative utilities possess.
Decarbonization frequently entails idling or retiring carbon-based resources that might otherwise have firmed up the significant gaps in renewable resources production (chart 3). Some types of conventional resources that are surviving decarbonization initiatives are unable to ramp up and down as the wind and sunlight--the lifeblood of renewable resources--wax and wane throughout the day. The National Association of Regulatory Utility Commissioners (NARUC) recently observed: "Increased cycling operations of coal plants, including more frequent startups and shutdowns, as well as faster changes in unit output, have a considerable impact on the reliability and cost of the plant. More frequent cycling increases wear and tear of plant equipment and can lead to shorter equipment lifespan… and increased cost of start-up fuel." ("Recent Changes to U.S. Coal Plant Operations and Current Compensation Practices," Jan. 24, 2020.) Frequent starts and stops can similarly affect gas-fired power plants.
Wear and tear and operational inefficiencies lead to meaningful cost pressures for utilities. The challenges facing utilities as they integrate intermittent resources into their generation portfolio are analogous to the differences in maintenance and fuel expenses drivers experience when driving on highways versus stop-and-go city traffic. The power generation cost pressures can contribute to a tension among retail rate affordability, the ability to preserve a utility's operational integrity and the integrity of financial metrics, and ratemaking flexibility that are integral to credit quality.
The Dichotomy Between Mandates And Technology Remains A Challenge For Not-For-Profit Utilities And Customers
On Sept. 10, 2018, California's then-Governor, Jerry Brown, signed Senate Bill 100 (SB 100) into law. The legislation established a target renewable portfolio standard (RPS) of 50% by 2026 and 60% by 2030. SB 100 also requires 100% of all retail electricity sales to come from RPS-eligible or zero-carbon resources by 2045.
When the governor signed the legislation, he acknowledged that the law's renewable goals were inconsistent with existing storage resources and that reliable electric service was vulnerable to the limitations of storage technologies needed to compensate for intermittency. For "goals to be credible, we have to have the ingredients that will actually get us there," he said. ("California Lawmakers Vote to Mandate Carbon-Free Electricity Generation," Wall St. Journal, Aug. 29, 2018.) In a similar vein, the chairman of Wyoming's Public Service Commission observed this year: "State energy regulators need to ensure that reliable power can be delivered to customers, regardless of whether or not the sun is shining or wind is blowing" ("New NARUC White Paper Explores Impacts of Changing Generation Mix on Coal Plants," Jan. 24, 2020).
Two types of rolling blackouts have plagued California electricity consumers in 2019-2020: those resulting from utilities prophylactically deenergizing power lines to reduce the risk of igniting wildfires during high wind events, and rolling blackouts attributable to insufficient energy supply during periods of high customer usage. August's rolling blackouts fell into the latter group and highlight the operational challenges utilities in California and elsewhere could face as they become increasingly dependent on renewable resources.
Over a few days in August, customers of the state's investor-owned electric utilities, along with customers of municipally owned electric utilities subject to the California Independent System Operator's balancing authority experienced rolling blackouts. The blackouts were the product of the combination of a regional heat wave, the effects of multiyear efforts to supplant dispatchable conventional resources with intermittent renewable resources, and the inability of renewable resources to provide around-the-clock continuous power supply.
In recent years, California's utilities transformed their resource mix by increasingly introducing renewable resources (chart 4). Although solar resources, as part of the renewable mix are not an overwhelming component of energy production, the higher levels of solar generation reached in recent years present meaningful operational consequences because of their intermittency. Solar represents about 14% of California's energy production, and renewables of all stripes support about one-third of energy sales. Further complicating matters is California's reliance on neighboring states for about another one-third of its residents' electricity requirements. The state also faces transmission constraints that restrict its import capabilities. Consequently, we believe this summer's rolling blackouts indicate that the evolution of California's generation portfolio creates a reliability threshold during heat events and that California's experience is instructive for utilities in other states that are pursuing decarbonization.
In California, the output of utility-scale solar and rooftop solar peaks about midday. Solar production trails off sharply during the afternoon. By comparison, consumers' demand for electricity peaks in the late afternoon and early evening when solar generation is near or at zero levels. Therefore, California's rolling blackouts largely coincide with the late afternoon and early evening tapering of native solar production and the limited availability of importable electricity.
When heat waves cover a broad swath of the Western region, as they did in August and over the Labor Day weekend, California's ability to import sufficient power from neighboring states' dispatchable conventional resources to offset the intermittency of its own renewable resources is compromised. High electricity demand within neighboring states that coincides with California residents' elevated electricity usage substantially exhausts the output from conventional resources in those states, depleting the amount of electricity available for California to purchase to backstop its systems' capabilities and increasing the likelihood of rolling blackouts. The interplay among supply and demand in these scenarios leads to very high prices for the market electricity that is available to serve load.
On Sept. 1, on the heels of August's rolling blackout events, investor-owned Pacific Gas and Electric Co. filed its 2020 integrated resource plan (IRP) with the state's Public Utilities Commission. The IRP flagged the reliability problems flowing from the state's carbon-reduction goals and growing reliance on intermittent renewable resources. In its filing, the utility wrote: "The recent rolling blackout events of August 14–15, 2020, clearly demonstrate a need for an operational reliability assessment… before the Commission considers a lower GHG emission target for 2030."
All Charged Up: Are Batteries The Answer?
Are there technologies that can counter intermittency? Can utility-scale batteries provide a solution for countering the intermittency of carbon-free renewable resources? The answer is a qualified "yes." Batteries can help, but only up to a point. Batteries, in addition to representing only a small piece of the electric resource pie, provide only limited energy potential (chart 5).
The U.S. Department of Energy reports that the average duration of utility-scale lithium ion battery storage systems is 1.7 hours, but can reach 4 hours, depending on the draw on the batteries. In other words, it is unlikely that batteries will get a utility through the night if the utility has an outsize dependence on solar resources and insufficient firming resources. In addition, during retail customers' peak consumption hours, batteries could be depleted rapidly.
Another consideration when assessing battery technology is the lifespan of an investment in lithium ion batteries. Not unlike cell phones' lithium ion batteries, utility-scale lithium ion batteries have a finite number of charging and discharge cycles, which means that in addition to initial investment and installation costs, utilities need to consider the costs and environmental impact of disposing of lithium ion battery banks, along with the costs of replacing batteries periodically.
Credit Quality Considerations For Public Power And Electric Cooperative Utilities Include Potential Infrastructure Investments And Effects On Financial Ratios
Because California's rolling blackouts suggest the presence of a disconnect between governmental decarbonization directives and prevailing storage capabilities, decarbonization mandates might compel utilities to invest in technologies that satisfy regulatory requirements but that do not support reliable service. Unless there are significant technological and economic advances in storage systems, the time may come when regulators and legislators need to revisit today's decarbonization milestones. Recurrences of episodes of rolling blackouts like this summer's in California might lead to the public's reassessment of priorities. A need to reconsider laudable but unfeasible goals could manifest in California and other jurisdictions. If utilities need to backpedal to reintroduce conventional resources to shore up reliability, that could necessitate infrastructure investment costs that pressure financial margins.
Utilities in decarbonizing jurisdictions that plan to maintain reliability by looking to wholesale power markets to purchase electricity from other jurisdictions could encounter volatile prices for power, including extreme costs during some hours, assuming the power is available. Exceptionally high prices during peak periods was the case in California this summer and in Texas during summer 2019. In high-price scenarios, unless public power and electric cooperative utilities have effective hedges or use pass-through mechanisms that provide for timely cost recovery from retail customers, credit metrics and ratings might be at risk. Although pass-through mechanisms might insulate a utility's financial performance during price spikes, the corresponding spikes in retail rates that they create might alienate customers and interfere with their ability to pay their bills during periods of extreme costs. Such disruptions could adversely affect cash flows and credit quality, depending on the duration of the price spikes and the magnitude of customer payment delinquencies. So far, due to their limited duration, the financial effects of the outages and prices spikes have been manageable for California's public power utilities.
Another credit consideration we associate with a migration to carbon-free resources relates to public power and electric cooperative utilities' almost universal use of power purchase agreements (PPAs) as the vehicle for adding renewable resources. It is rare for these utilities to directly finance and build their own renewable generation. The rationale for this choice is a function of the inability of these not-for-profit utilities to monetize the tax credits associated with renewable investments. By way of PPAs, public power and electric cooperative utilities partner with generation developers and power marketers that can monetize the tax credits.
We expect that, as utilities add more contracts for renewable generation, leverage ratios will improve because public power and electric cooperative utilities will simultaneously amortize portions of existing debt and add resources that are not financed on the utilities' balance sheets. However, we do not expect this improvement will strengthen credit quality. We will capture the migration to more off-balance-sheet supply in our fixed charge coverage (FCC) calculation. As utilities add more PPAs, FCC degradation is likely to temper or offset improvements in leverage ratios. Our FCC calculations capture public power and cooperative utilities' funding of renewable project developers' recovery of their capital investment in generation projects. We look at the PPAs as though the not-for-profit utilities are contracting with renewable project developers to issue debt on their behalf. Therefore, we treat a portion of the payments by the not-for-profit utilities to power projects as debt service, rather than an operating expense. Depending on the resulting FCC ratio, adding PPAs could negatively influence credit ratings for some utilities.
Nevertheless, at the same time that this summer's rolling blackouts in California illustrate the financial and operational difficulties utilities could face as they shed conventional generation resources and embrace intermittent, renewable resources to lower their carbon footprint, for the most part, we believe public power and electric cooperative utilities have the financial capacity and ratemaking flexibility to respond to these challenges and preserve credit quality.
This report does not constitute a rating action.
|Primary Credit Analyst:||David N Bodek, New York (1) 212-438-7969;|
|Secondary Contacts:||Jenny Poree, San Francisco (1) 415-371-5044;|
|Paul J Dyson, San Francisco (1) 415-371-5079;|
|Jeffrey M Panger, New York (1) 212-438-2076;|
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