The rapid transformation of the power grid poses challenges for all market participants. 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. The flow of energy could also change, with consumers producing power at the edge of the grid.

Even setting aside the effects of renewable penetration, grid reliability is already being challenged by more intense weather events, pressure on conventional generation, and increased load due to electrification. The North American Reliability Corp. (NERC) highlighted in its May 2023 report that, although most grids should be able to handle normal weather conditions, almost two-thirds of North America could be at risk of electricity shortfalls during periods of extreme heat (table). This is meaningful considering the more extreme climate events expected in the future.

Changing the systems to better fit the production mix and shifting demand will be costly, lengthy, and complex. Many market participants will need to contribute to this effort, including regulators, utilities, consumers, and merchant power producers. Independent power producers (IPPs) will have to adapt to a changing grid that will evolve due to multiple forces outside of their control.

In this report, S&P Global Ratings explores some of the key aspects linked to greater intermittency and lower reliability of the grid, including why it could worsen, what are some of the potential solutions being explored, and the implications for merchant power generators.

Why Is Grid Reliability Projected To Become A Greater Risk?

The fuel mix is changing, with rapidly increasing renewable representation

Rapid renewable penetration is the most meaningful development that has occurred since electrical systems were created (chart 1). This has been a challenging transition on many fronts, mainly due to the generation profile of renewables. Renewable resources are inherently more unpredictable because generation is influenced by external factors, such as cloud cover or weather. In addition to having variable production, renewable power generation is intermittent and not generally dispatchable, unless paired with storage technology. This does not even factor in inherent technological challenges, such as inverter-based disturbances, which affected the Texas and California markets, or curtailment of power during congestion events.

Chart 1

California is a key example, as the state has heavily supported the adoption of solar generation to reach its greenhouse gas reduction targets (chart 2). This has resulted in significant solar production without an ideal method of integrating or storing it, which poses several challenges. These include costly requirements for utilities to reserve generation sources for peak times, such as curtailment of solar during hours of overproduction and an extremely sharp evening ramp up that relies heavily on fossil-fuel generation.

Chart 2

The change in fuel mix has meaningful implications for the dispatch curve and merchant power producers' profitability. A greater contribution from renewables will result in lower power prices, on average, with some power prices already turning negative in some instances. Greater efficiency will also flatten the curve, which will hamper the profitability of multiple assets, including incremental renewables.

At the same time, the marginal unit, which is the last unit that must be used to serve customer load, will continue setting the clearing price and is currently likely to be serviced by carbon-fueled facilities (chart 3).

Chart 3

Market incentives don't favor carbon-fueled generation, which magnifies the impact of renewable penetration

Even in an environment of lower and more volatile power prices, efficient baseload generation still has a role to play until reliable alternative mechanisms are in place. However, current market incentives, including continuously depressed capacity prices, don't favor the construction of more efficient carbon-fueled assets. For example, the Pennsylvania Jersey Maryland (PJM) interconnection is only projecting the addition of two combined cycle power (CCGT) plants in its pipeline.

Peaker plants are also important because they can dispatch quickly, filling the gap of intermittent supply. We could see a faster-than-expected pace of retirement as older and less efficient assets face strained profitability or are forced to retire due to regulatory measures. The Environmental Protection Agency is proposing to tighten standards for coal-fired plants. PJM anticipates as much as 40 gigawatts of retirement by 2030, which represents up to 21% of its installed capacity (chart 4). The New York State Department of Environmental Conservation's peaker rule is already affecting generators in New York Independent System Operator (NYISO), with about 550 megawatts (MW) of proposed retirements in 2023. The NYISO now forecasts a 446 MW deficit in 2025, due to electrification and retirements.

Chart 4

Unpredictable weather events result in erratic load

Increasingly unpredictable and severe weather events could stress power markets, even without factoring in the contribution of renewables to the power stack. Although not nearly as severe as the February 2021 winter storm event, the winter storm in December 2022 had significant consequences for merchant power producers. The large drop in temperature resulted in a spike in load, with PJM and ISO New England (ISO-NE) experiencing large unplanned outages. This resulted in penalties for many generators, totaling $1.8 billion in PJM. Some project finance issuers that we rate, such as Elwood Energy LLC or Parkway Generation LLC, were downgraded by multiple notches as a result because the penalties reduced the projects' ability to sweep cash against their term loan Bs. At the other end of the spectrum, other IPPs, such as Constellation Energy Inc., generated net bonuses, which highlights the benefits of having diverse assets.

We anticipate there will be more extreme weather events year-round, including summers. Numerous independent system operators have resorted to instructing consumers to restrict energy consumption over the past few summers, including more recently Electric Reliability Council of Texas (ERCOT) due to the heat wave in Texas this past summer, with a record load of 85,593 MW.

Changing technology is expected to result in greater electrical demand, with a new pattern of energy consumption

In addition to the macroeconomic factors that result in load growth, the pace of electric vehicle penetration could drastically change consumer demand due to charging behavior. We currently have limited visibility on this factor, but view it as a major driving force going forward. Furthermore, data centers, where proximity to end users is a key factor, will add to the increased load. Heating electrification, such as heat pumps, could also contribute to increased demand, particularly in regions that have colder winters, such as NYISO and ISO-NE. The resultant increase in load could shift those markets from a summer peaking to winter peaking. At the same time, generation from renewables could be limited during peak demand in the winter, due to storms or lower solar radiation.

What Are Some Of The Solutions Being Explored?

More meaningful market reforms are underway

Regulators are looking at multiple avenues to help counter the increasing stress on the grid and more meaningful market reforms are likely on the way. PJM is conducting an in-depth review of its market construct. In ERCOT, the Public Utility Commission of Texas is exploring the performance credit mechanism. The Texas government is also looking at funding more dispatchable generation through the newly established $10 billion Texas Energy Fund. NYISO is considering proposed changes to capacity payments, which will be based on both how the resources contribute to grid reliability and the performance of the asset. NE-ISO is studying a new methodology that seeks to address how resources contribute to resource adequacy in the forward capacity market. We will continue monitoring market reforms and their potential implications, while being cognizant that meaningful change always entails the risk of unintended consequences.

In addition to market reforms, we anticipate that regulators could reconsider the value of dispatchable generation, which might result in the delayed retirement of facilities. Greater support for battery use, as highlighted by the provisions embedded in the Inflation Reduction Act (IRA), should result in broader deployment. Developers can now add storage to existing sites, whereas it originally didn't make sense to do so.

The recent support for nuclear generation clearly illustrates that regulators are aiming to decarbonize the grid while maintaining reliability. The production tax credits imbedded in the IRA essentially provide a price floor for nuclear power generation over a long period. As a result, merchant nuclear generators are incentivized to keep running the plants for longer because they no longer rely on shifting wholesale power prices. Having better visibility on nuclear cash flows has meaningfully increased their value and market activity, with Vistra Corp. buying Energy Harbor Corp. and Constellation buying NRG Energy Inc.'s (NRG) 44% stake in the South Texas Electric Generating Station.

A suite of solutions is likely the answer

Changing the systems to better fit future needs will take an extensive effort from all market participants. The grid of the future will have to be more flexible and robust, with better storage, data analytics, and transmission capabilities. Batteries are frequently touted as a key part of the solution but might not be applicable for every market and for every situation given their limited hourly capacity and reliance on renewable production. Green hydrogen could complement batteries, as the element can be stored and used at will; however, its production needs to become economically viable. Enhanced geothermal systems, which differ from conventional geothermal by being less dependent on topography and dispatchable, could have significant potential.

What Does This Mean For Merchant Power Producers?

Larger power producers benefit from better scale, scope, and financial resources

We anticipate that larger power producers will withstand these changes better than their smaller counterparts. Larger companies are typically more diversified, which we view as credit positive. Having a diversified fleet in terms of assets and markets results in greater resiliency.

Larger companies usually have more financial capabilities, which allows them to pivot strategies by investing in different asset classes, technologies, or markets. Many large issuers have been investing heavily in their renewable pipelines. These assets can also play a role in the broader overall strategy of a company, such as servicing retail obligations in some cases.

Project finance issuers with greater thermal flexibility will likely be better able to withstand change

Implementing new strategies should be easier for corporate entities than for project finance issuers, which are typically either stand-alone assets or small portfolios that have limitations on selling or expanding their portfolios in their financial documentation. We anticipate that more flexible thermal plants, which can respond quickly to market conditions, will likely perform better because they can capture upside, even if their overall capacity factor declines. In other words, the profitability profile of assets might change. As the curve increasingly lowers and shifts to the right, even efficient facilities might be looking at producing less but at better prices. The baseload facilities of today could serve the marginal unit of tomorrow.

Project finance sponsors are also looking to adapt to shifting market dynamics, by repurposing lands or assets to develop renewables. However, these redeployments will likely be outside of the ring-fenced entities and will not directly affect the project finance issuers' credit profiles. Market developments could negatively affect the average life of project finance assets. Changing market dynamics will also affect single assets more meaningfully, with few mitigating factors. We will continue to monitor upcoming refinancings, and believe this uncertainty could result in more conservative leverage structures, such as the new issue of Generation Bridge Northeast Energy LLC, which had a debt ratio of about $167 per kilowatt.

Companies are looking at different models to mitigate the impact of the shifting power curve

Besides their intermittency, renewables will also meaningfully shift the dispatch curve. Having mitigating strategies to offset the impact of lower wholesale power prices will be key for maintaining credit quality. Different strategies are on the table. Some companies, such as NextEra Energy Partners L.P., TransAlta Corp., and Capital Power Corp., have reduced their exposure by being mostly or fully contracted, or having a very robust hedge book. Other producers, such as Constellation, Vistra, and NRG, have chosen the integrated model. We view having a retail segment with a high load-to-generation ratio as providing a countercyclical hedge. NRG has been heavily investing in strengthening its retail segment, which generates most of its EBITDA. With its recent acquisition of Vivint, the company is further lowering its exposure to wholesale markets.

IPPs will have to be innovative and adapt to changing market conditions

Innovative companies might also be more likely to withstand shifting market conditions. This could take many forms, from investing in emerging technologies to repurposing existing assets. For example, virtual power plants could help with the intermittency of renewables by pooling resources at the edge of the grid and dispatching when necessary. For companies with a retail arm, stronger data analytics on the retail front could also lead to better demand efficiency. This could eventually mean a lower churn rate for the companies with retail branches.

Larger Power Producers Are Better Positioned To Adapt To An Evolving Grid As Reliability Becomes A Key Factor

The broader decarbonization of the grid will entail major consequences for IPPs. The electrical systems of the future will likely have to rely on a series of solutions, ranging from better data analytics to a broader range of technologies. We think that the larger, more flexible power producers will likely adapt better to this new reality because of their ability to invest in new technologies, given their large balance sheet and constant readaptation to new market dynamics.

Related Research

• Industry Top Trends Update North America: Unregulated Power, July 18, 2023
• Inflation Reduction Act Update: Between Cheap, Firm, And Clean Power—Pick Any Two, Sept. 8, 2022