The U.S. electric power industry is in transition, seeking to decarbonize its fuel sources for environmental stewardship, regulatory requirements, or financial and economic reasons. While many utilities are developing plans to add renewables, others are taking a cautious approach.

Why this matters:  S&P Global Ratings evaluates a utility's fuel mix against the backdrop of a variety of risks that could affect financial metrics that underscore a utility's credit quality. Although we have not lowered ratings on carbon-intensive utilities in the U.S. to date due to energy transition risks, their emission profile has generally limited positive rating actions. However, we believe that pressures to decarbonize are mounting, and this could lead to downward credit pressure as regulatory measures are adopted and deadlines approach.

What we think and why:  In our view, utilities that proactively develop decarbonization strategies are better positioned to preserve credit quality and absorb transition costs. Utilities with reactionary management could face operational disruptions and spikes in electric rates rather than a glide path to higher costs. However, adding renewables could present potential operational and technological impediments depending upon the pace and scale of adoption by the U.S. power sector, which could jeopardize reliability, raise power and capital costs, and potentially pressure rates, financial metrics, and credit quality.

The Renewables Landscape In Four Shapshots

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Wind and solar generation are often the primary method to achieve carbon reduction in the U.S. due to the relative cost competitiveness of these power sources and as alternatives (including nuclear, hydropower, and geothermal) are generally not available to most utilities. Furthermore, newer technologies (such as small modular reactors, carbon capture, and hydrogen) are still in development.

While many utilities have developed, or are developing, plans to add renewables, others are taking a cautious approach reflecting:

• A lack of widespread renewable standards and/or clean energy goals among U.S. states, or statutory provisions requiring minimal and easily achievable reductions;
• Long-dated compliance deadlines, giving utilities time to optimize the remaining useful life of existing assets while alternative technologies develop and become more cost competitive; or
• Concerns regarding the integration and intermittency of renewables on reliability.

Meanwhile, despite passage of the U.S. Inflation Reduction Act (IRA), which directs $369 billion in federal aid toward incentivizing the adoption of renewable energy and low-carbon technologies, some U.S. utilities are waiting to see what emission regimes are promulgated, and potentially what legal challenges may arise. Regardless of the motivation to add renewables or wait, we believe that utilities should plan for operational and technological impediments--each of which could jeopardize reliability and raise power and capital costs--potentially pressuring rates, financial metrics, and credit quality.

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Regulatory Pressures Could Drive The Pace Of Decarbonization

Regulatory measures, particularly among U.S. states to require renewable portfolio standards (in addition to the costs of renewables), are supporting the pace of the energy sector's decarbonization. As of 2022, 37 states have renewable portfolio criteria with differing stipulations: 30 have adopted standards that renewable resources provide a specified percentage of energy by a certain date. Of them, 14 states mandate a 100% renewable and/or carbon-free portfolio standard. In addition, six states have adopted renewable goals and one state has adopted clean energy goals (see chart 5).

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In our view, several of the near-term renewable standards and goals are achievable for many utilities given current technology and pricing, with limited impact to financial metrics and credit quality. However, goals for a few states including Hawaii, Maine, and New York (100% renewable by 2045, 100% renewable by 2050, and 70% renewable by 2030, respectively) might be optimistic given current technologies, costs, and labor and supply constraints as well as limited ability to alleviate intermittency risk. We generally view goals as being somewhat aspirational and therefore flexible, depending on the perceived impact on power economics and the future development of technologies to support their achievement. As a result, should U.S. power utilities in these states not meet the aggressive goals, it may not have a credit rating impact, particularly should we view utilities in these states undertaking best efforts to meet the deadlines. In the event these states modify the goals by adopting them as standards, which we view more as matters of law, it could be more challenging for utilities to adapt without significant operational and capital costs.

In contrast, utilities are often faced with taking a measured and incremental approach to regulations, and might wait to adopt requirements until deadlines approach. Among many other considerations, power supply planners evaluate their current power supply (including the remaining useful life of their fossil fuel units and whether their retirement will result in stranded investment) against the risks of waiting too long. For example, some utilities located in the Southeast are lagging in renewables investment, potentially reflecting a lack of state- or locally adopted standards and goals.

In our view, both approaches may have pitfalls. If utilities move forward more quickly, they could face initial technological investments needed to transition to renewable sources becoming cheaper or lose out on more advanced technologies emerging. On the other hand, utilities that wait to initiate transition could face increased capital costs, more limited supply for required technology as greater demand by U.S. utilities occurs, and potentially the need to offset these costs with higher user rates.

Renewables Are Trending Upward Despite The Challenges Of 2022

U.S. power utilities already focusing on energy transition have largely closed older, inefficient, and fully depreciated coal plants, replacing them with natural gas units and/or market purchases that helped lower carbon footprints and bridge further decarbonization efforts.

The U.S. Energy Information Administration expects solar and wind capacity to more than double by 2050 from 2021 levels, as utilities increase stakes in renewable resources as part of their power supply portfolios in furtherance of their net-zero and/or 100% clean energy goals.

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However, we believe that natural gas will remain a necessary component of the industry's fuel mix to ensure reliability of both individual utilities and the grid as a whole until the shortcomings of energy storage and/or other breakthrough technology are solved. Nevertheless, ongoing investment in gas-fired generation could frustrate the pace of decarbonization and increase the prospects of additional stranded investment, particularly as the Environmental Protection Agency's proposed May 2023 regulatory measures that target gas-fired generation through limitations on new gas-fired combustion turbines; existing coal-, oil-, and gas-fired steam generating units; and certain existing gas-fired combustion turbines. While this proposed rule may change prior to implementation, it signals the potential risks of natural gas serving as a bridge fuel to decarbonization.

From 2009 to 2021, the levelized cost of energy from utility-scale solar units dropped 90% while the levelized cost of wind energy declined 72%, as improving efficiency and lower capital investment drove down the cost of renewables, making them cheaper than base-load resources (coal, gas, and nuclear).

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However, the trend reversed in 2022. The pandemic and Russia's invasion of Ukraine disrupted manufacturing and created supply chain bottlenecks for critical technology components. Grid operators, overwhelmed with interconnection requests, faced a burgeoning backlog. Component cost inflation raised capital costs for renewables, and higher interest rates pushed up financing costs. According to the Wall Street Journal, the price that renewable developers were charging long-term buyers for their electricity has doubled since the pandemic, rising nearly 30% in the past year alone.

As a result, renewable projects have been delayed, and some cancelled, as developers and their energy off-takers sit on the sidelines, waiting for resolution to these impediments. We believe that some hurdles are short-to-medium term in nature and growth in renewables will pick up as pressures to decarbonize continue to build, inflationary pressures abate, technological advances help reduce capital costs and improve reliability, and incentives contained in the IRA are leveraged. (However, we do note that domestic content rules embedded in the IRA could limit a utility's ability to access program funding.) For more information, see S&P Global Commodity Insights, The cost of renewables will continue to fall, this is why, published March 31, 2023, and Renewable Energy Funding in 2023: A "Capital Transition" Unleashed, published Sept. 14, 2023.

The Renewable Generation Buildout Faces Impediments

Serving load with an intermittent resources present challenges, particularly for smaller utilities that lack sophisticated trading and energy management capability

While the absence of fuel costs makes renewables attractive in providing energy, they are an "intermittent" resource, making them suitable to meet peak demand, but poor substitutes for conventional baseload generation. Utilities are constantly balancing electricity supply and demand to avoid a blackout or other cascading problems.

Energy supplied by wind turbines and solar panels is variable; renewables are not "dispatchable" resources, capable of being sent into the grid at any time. Their production is based primarily on weather conditions: whether it's windy or sunny, which can change rapidly. Renewable power production can vary significantly by season or time of day (see chart 8 below), leaving a utility exposed to unhedged power costs when units fail to produce energy.

This variability can also lead to mismatches between generation and load. For example, wind generation peaks during the winter and spring, and wanes in the summer, making it more difficult to balance supply and demand in warmer climates that require high summer cooling loads. Although solar generation tends to match up better with demand, there are still times (early morning and evening) when solar production is ramping up and down.

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Utilities could address intermittency by pairing renewables with a "firming" resource; examples include quick-start gas-fired combustion turbines, market purchases, or energy storage. However, each of these firming strategies introduces power costs and presents drawbacks. Firming with combustion turbines and/or market purchases (generally dominated by gas units) can delay decarbonization efforts, unhedged market purchases can create power cost volatility, and there are technological shortcomings to energy storage (discussed below).

One of the hallmarks of renewable resources is the virtual lack of fuel cost, which can move them to the front of a utility's dispatch stack. However, in areas where there is a significant level of renewable penetration, an oversupply of renewable energy can crowd out generation from conventional resources. This can result in repeated on/off cycling, leading to elevated wear-and-tear on conventional baseload generating units, prompting respective grid operators to curtail renewables. Therefore, lower-cost renewable units could be underused so that conventional generating units can remain online (albeit producing power at a higher cost), potentially reducing the economic advantage of renewables and preventing emissions reduction. We anticipate these issues may underscore bigger risks for utilities as renewables are added to the generation mix over the next 10 years.

Batteries/storage could resolve challenges of intermittency, but are technologically constrained

While intermittency poses a significant challenge to renewables investment, battery storage offers one potential solution. By pairing batteries with solar or wind units, utilities can store energy to use during periods of high demand, but when the renewables are offline. However, utilities must manage the costs and supply chain challenges to effectively deploy this strategy without hindering financial metrics.

Batteries store electricity at their rated nameplate capacity covering four hours on average before depletion. While larger batteries that can store up to 10 hours of energy are available, they are expensive, and their use can make power prices uneconomic. Due to capacity and duration limitations, batteries are typically employed for subhourly, hourly, and daily balancing, and generally not paired with renewables to synthetically mimic baseload units.

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Technological gains have improved battery efficiency, driving down the price of lithium-ion batteries over the past decade. Recent studies also suggest the potential for an additional 30%-40% drop in battery costs from 2030-2050. However, further technological advancement is uncertain and unlikely to help utilities make long-term power supply decisions today.

While technology advancements may reduce battery production costs, supply chain disruptions and battery demand are pressuring battery prices. About 80% of the world's supply of lithium comes from three countries, and utilities are competing against phone and electric vehicle (EV) manufacturers for the raw material. Meanwhile, Russia's ongoing war with Ukraine has disrupted the market for other necessary metals--nickel, cobalt, and graphite.

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Beneficial electrification can aid decarbonization, but presents distribution challenges for utilities

Beneficial electrification lowers carbon emissions by using electricity from renewable resources to replace processes that traditionally used fossil fuels. Examples include EVs (replacing internal combustion [gas] engines) and heat pumps, which are three-to-five times as efficient as residential gas boilers, but costly to install on a retrofit basis. As new electric load is created, we will monitor the sector's ability to incorporate changing demand into their power supply and financial forecasts.

EV sales reached 8% of total U.S. car sales in 2022, and S&P Global Mobility estimates that EVs account for about 1% of all cars currently on the road. EVs are expected to account for 12% of all vehicles on the road by 2030 (see U.S. States Jump Start Electric Vehicle Charging Infrastructure, published Sept. 21, 2023). We anticipate that increasing penetration of EVs will aid overall decarbonization, particularly of the transportation sector. However, utilities will need to procure incremental power supplies (and incur additional distribution expense) to serve the additional load, and to avoid higher emissions, these additions will need to be carbon-free.

Partly as a matter of convenience, EVs tend to be charged at night when electric demand is generally low, making them an attractive load for utilities that seek a more consistent base-demand profile. While nighttime charging matches up well with peak wind production, it does not match up well with solar, and this reintroduces the need for batteries. Utilities will also need to address increasing distribution system requirements. To help align the electric grid's supply and demand, utilities may need to adopt time-of-use rates to incentivize efficient charging patterns, which could result in broader investment in smart metering. As EVs become more ubiquitous, utilities may also find that they need to add additional substations and/or transformers to serve the growing load, particularly if current distribution resources are operating at or near capacity for existing loads. Each of these investments adds to capital costs and increases the price associated with energy transition.

Land requirements, physical risk, transmission needs, and permitting bottlenecks are impeding investment in renewables

Electrical grids are rapidly transforming due to greater renewable energy penetration. Reliability is a key consideration as generation is poised to become more intermittent and as load patterns change. Most power markets are looking to incorporate large quantities of renewables while maintaining grid reliability. At the same time, existing systems were not built to accommodate intermittent generation from many, more geographically dispersed sources. (See Step Up Transformers: How Will North American Power Producers Adapt To An Evolving Grid?, Sept. 14, 2023.)

Land requirements for renewables are many multiples higher when compared with conventional generation. Mitigating the land use and cost impact can result in renewables located far from load centers, sometimes on land that is not otherwise productive--such as mountainous terrains--or that can be used for other purposes--such as farming.

Moving renewable energy from remote production locations to end-use customers in load centers often means additional (and costly) high-voltage transmission lines, the siting of which could be problematic due to public opposition or environmental impacts. In addition, a decentralized and remote power supply increases the utility's exposure to physical risks such as wildfires. As transmission lines run farther, the likelihood of extreme weather events damaging infrastructure or of assets starting wildfires increases. This could result in high legal or maintenance costs to safely maintain these assets. Furthermore, with much of the transmission grid already operating at- or near-full capacity, utilities and developers may be required to cover the cost for downstream transmission upgrades to ease congestion. These added costs could make projects uneconomic.

The combination of renewables cost competitiveness and the adoption of state and local decarbonization/renewable mandates has resulted in a substantial surge in interconnection requests leading to an approval bottleneck, project delays, and cost increases. For example, project approval takes, on average, four years, or double the time compared with a decade ago. The Pennsylvania, New Jersey, Maryland (PJM) independent system operator accounts for about one-third of projects in the queue, and announced a freeze on new applications until 2026 to provide time to work through its backlog.

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The Renewable Landscape Is Mixed

Renewable resources account for a significant percentage of U.S. electric capacity expansion, but adoption is uneven. Intermittency, battery limitations, supply chain disruptions, land requirements, and interconnection bottlenecks present challenges for U.S. power utilities as they seek to decarbonize their generation supplies. These impediments could contribute to delays and/or increasing capital and operating costs for utilities adding renewables, which may affect their user rates, financial metrics, and credit quality in the long term.

These impediments also serve as harbingers for utilities that are waiting on the sidelines and that have thus far delayed making incremental progress in adding renewables. If and when regulatory measures are promulgated and deadlines approach, the utilities that failed to make incremental progress in adding renewables could face credit quality deterioration. We believe that proactive utilities that are developing strategies that contemplate anticipated emissions regulations are more likely to experience stable credit quality by balancing transition costs with other operational investments that could limit disruptions and spikes in electric rates.

Related Research

• U.S. States Jump Start Electric Vehicle Charging Infrastructure, Sept. 21, 2023
• Step Up Transformers: How Will North American Power Producers Adapt To An Evolving Grid?, Sept. 14, 2023
• The cost of renewables will continue to fall, this is why, March 31, 2023
• Renewable Energy Funding in 2023: A "Capital Transition" Unleashed, Sept. 14, 2023