The February winter storm (unofficially known as "Uri") and its power and gas market disruptions led to negative rating actions affecting many Texas-based public power and electric cooperative utilities wholly or partly within the jurisdiction of the Electric Reliability Council of Texas (ERCOT).

In response to the event, the Public Utilities Commission (PUC) established a rule on Oct. 21, 2021, that requires power generators, utilities, and transmission service providers to comply with winter weather preparedness recommendations by Dec. 1, 2021, and to attest to the repair of any known failures that occurred because of winter weather conditions from Nov. 30, 2020, to March 1, 2021. However, many ERCOT utilities are awaiting announcement of further reforms before taking additional action.

S&P Global Ratings believes that the amalgam of the ERCOT market's operational attributes and its geographic exposure to extreme summer and winter weather events translate into meaningful operational and environmental risks that could continue to negatively affect ratings. In our view, returning the negative outlooks to stable and resolving the negative CreditWatch listings depend on what additional actions utilities and regulators take to mitigate ERCOT-related risks and recent significant storm costs.

About Half Of Public Power And Electric Cooperative Utility Ratings Within ERCOT Were Lowered

Of the 27 rated electric cooperative, municipal electric, wholesale, and combined utilities in ERCOT, we lowered the ratings on 14 given the financial effects of the storm, our view of ongoing physical risks, and governance risk associated with ERCOT that could negatively affect financial performance. Two other ratings were lowered for non-storm-related reasons: For Seguin's combined utility, we lowered the rating as a result of our view of the utility's projected lower fixed-charge coverage and greater leverage given plans to issue considerable debt over the next several years. The Seguin rating change led to a similar rating change for Schertz/Seguin Local Government Corp. (LGC), given that Seguin's combined utility is responsible for 50% of LGC project costs and our rating on LGC's bonds reflects Seguin's status as the weak link participant among the bonds' two obligors. In addition, we revised the rating outlook to negative from stable on eight other ERCOT utilities, or about one-third of the total, leaving associated ratings unchanged but reflecting the potential negative financial exposures that we associate with operating within the ERCOT market.

The three utilities below exhibited the most pronounced rating changes among the utilities adversely affected by the winter storm:

• Brazos Electric Power Cooperative Inc. (Brazos; 'D') is in default, so the outlook is not meaningful.
• The Brazos Sandy Creek Electric Cooperative (BSC) 'CCC' rating remains on CreditWatch with negative implications. While BSC is not a party to the Brazos bankruptcy proceeding, BSC's capacity to service debt depends entirely on its receiving payments from Brazos under a power purchase agreement (PPA).
• The Rayburn Country Electric Cooperative (Rayburn) 'CCC' rating has a positive outlook, which reflects our view that we could raise the rating over the next one to two years, potentially by several notches, if securitization of extraordinary costs is successful and Rayburn is able to discharge its large obligation due to ERCOT.

Eleven other ratings have negative outlooks, generally given our view of the continued uncertainty associated with many factors facing utilities throughout the state, including an uncertain regulatory environment, the ERCOT market's relative price volatility, gas price volatility and supply reliability risks, extreme temperature and demand fluctuations, and weaker grid interconnectivity as compared with grids in other states.

In two cases--for San Miguel Electric Cooperative (SMEC) and South Texas Electric Cooperative (STEC)--'A' ratings were placed on CreditWatch with negative implications on March 3 and then removed from CreditWatch and affirmed with stable outlooks on July 22, 2021, based on our view of STEC's favorable power supply portfolio and virtually cost-neutral impact from the recent February winter storm. The STEC rating heavily influences the SMEC rating given that STEC is the sole offtaker for SMEC's coal-fired generating station. These two ratings represent the only two cases where the rating and outlook are unchanged from prior to the winter storm.

See table below for a full list of rating actions taken since the February winter storm.

ERCOT Risks We Are Monitoring

Irrespective of whether utilities were long or short generation or gas, the specter of ERCOT's socialization of defaulted payments among nondefaulting participants (pending securitization for cooperatives with the highest unpaid invoices, such as Brazos and Rayburn) based on utilities' pro rata share of sales (in megawatt-hours, or MWh) in the ERCOT market presents a negative credit risk for generation companies and utilities. Based on our understanding of its framework, ERCOT could allocate among nondefaulting market participants, on a pro rata basis, close to $3 billion of defaulted payments, but securitization financings might mitigate this exposure.

Other risks that utilities within ERCOT face include the following:

• ERCOT's limited interconnectivity with generation beyond its borders contributes to greater price and supply volatility when weather or other factors impede the state's native electric system operations.
• February's numerous generation plant outages bear out the criticality of ERCOT's tightly aligned generation resources and consumer demand, resulting in an overall slim reserve margin. Beyond the compensation that unpredictable scarcity pricing provides to generation owners, the market does not provide generation developers with capacity payments that might otherwise incentivize generation additions that could contribute to a more robust and stable market.
• Although regulators intended scarcity pricing of $9,000 per MWh to encourage generation owners to operate during periods of extreme electricity demand, during the winter storm the financial incentives to run power plants could not overcome physical barriers such as gas well or line freeze-ups and weather-related mechanical failures that precluded generation owners from producing sufficient electricity. By comparison, market caps in California and other markets are far lower at $2,000 or less per MWh. We expect the $2,000 price cap, which has been in place for the past six months, to be ephemeral, and we see a higher cap as reasonably likely by the beginning of 2022.
• During the winter storm, the market's price signals not only failed to produce their intended supply response, but spurred economic impairment when operational hurdles frustrated generation from dispatching.
• Investments in more robust winterization add to the financial pressures that market participants face. February highlighted a vulnerability that historical winterization practices at power plants and gas wells and along gas pipelines could not support uninterrupted electricity and gas supplies during an extreme weather event. Moreover, debt added to fund February's electricity and natural gas procurement bills might create barriers to financing and implementing winterization projects, leaving utilities exposed to potential recurrences of those outages.
• Potential delays in weatherization investment requirements for the natural gas industry in Texas will leave utilities and their generating assets vulnerable to extreme weather and resulting outages.

Weatherization efforts are subject to ERCOT inspections, and the PUC is permitted to impose administrative penalties on generation entities that have not cured their noncompliance within a reasonable timeframe. The rule mentioned earlier represents phase one of the overall winterization process; phase two will focus on broader, year-round weather emergency readiness reliability standards that will be informed by ERCOT's ongoing weather analysis. The phase one rule does not require weatherization compliance by gas suppliers, because neither the PUC nor a generation entity can require weatherization. Section 5 of Senate Bill 3 directs the Railroad Commission to develop weatherization standards for gas fuel suppliers.

The risks and cost of doing business as an electric utility in ERCOT have shifted materially higher, in our view. Winterization projects could be costly for some utilities and could lead to slimmer financial metrics and/or sizable rate increases. We believe that recent regulatory initiatives might be insufficient to mitigate the ERCOT market's generation constraints and scarcity pricing model, thus continuing to expose utilities to financial pressures. Therefore, we are assessing utilities' operational and financial strategic responses to these exposures, including assessing the sufficiency of access to liquidity to temper extreme unbudgeted expenses.

Why Did The Storm Have An Extreme Market Impact?

Cold weather events are not rare, but the severity of the winter storm and the resultant market and operational dislocations were. During the storm's market disruption, 46,000 MW of generation capacity was off line, out of a total capacity of 82,000 MW. This compares to 33,000 MW in outages in the previous severe cold weather event to hit Texas, in February 2011. During the more recent winter storm power prices spiked to ERCOT's price cap of $9,000 per MWh, whereas in 2011 they did not exceed $3,000 per MWh. Moreover, the duration of the 2021 winter event was far longer than that of the 2011 storm, with prices averaging $6,600 per MWh over the six-day period of this past February. Gas prices also rose considerably as a result of supply shortage (partly the result of frozen natural gas wells and pipelines) and surging demand. At the Henry Hub, natural gas prices reached $23.86 per million British thermal units (mmBtu) on Feb. 17, the highest real (inflation-adjusted) price since an Arctic blast in February 2003. Prices at the Houston Ship Channel spiked even higher to $400 per mmBtu. Pre-storm gas prices were around $3 per mmBtu.

Utilities Managed The Resulting Higher Costs, But In Many Cases Not Without Credit Deterioration

Sustained high prices over several days saddled the sector with extraordinary electricity and gas costs. February's gas and electricity costs created formidable liquidity needs that most market participants were able to satisfy. Beyond extreme liquidity calls, entities that were short power or natural gas, or that relied more heavily on intermittent resources such as wind and solar, suffered substantial losses as a result of the spike in costs. Utilities used a variety of tools to manage the surge in power and gas costs, including:

• Use of internal liquidity, including unrestricted cash and investments, and/or rate stabilization funds;
• Raising base rates or imposing temporary "storm surcharges;"
• Short-term borrowing through commercial paper or advances on lines of credit;
• Long-term borrowing to refinance commercial paper or advances on lines of credit;
• Operating cost reductions; and
• Reduced or deferred capital spending.

Some Utilities Were Significantly Affected; Others, Not As Much

Net storm costs (unbudgeted expenses related to the storm less margins from energy sales into the market) for ERCOT utilities we rate varied significantly (see table), with some utilities saddled with invoices in the billions (e.g., Brazos Electric Power Cooperative with $2.1 billion), while one utility, Austin Energy, saw a net surplus of $101 million. Austin Energy reported that its generation output exceeded demand for energy, enabling it to fully recoup high natural gas fuel costs by selling energy into the market. For all utilities, many variables influenced storm costs.

Generally, those utilities that were most affected had one or more of the following fact sets:

• Relied more heavily on ERCOT market purchases to meet load--either because of a short position heading into the storm or an inability to dispatch owned or existing assets, whether as a result of insufficient winterization, an inability to source fuel, or generation intermittency;
• Were insufficiently hedged on fuel going into the storm or winter;
• Serve customers in the more northern portions of the state, where temperatures were especially cold, leading to record peaks in energy demand and natural gas supply interruptions;
• Have generation not diversified by resource or by geographic location;
• Were unable to meaningfully shed load during the storm;
• Maintained weaker financial metrics going into the storm, including thin fixed-charge coverage and liquidity, or high debt, such that even relatively smaller storm effects were meaningful; or
• Charged high retail rates going into the storm, reducing future financial flexibility, especially in cases where income levels are below average.

What Set Brazos And Rayburn Apart To Such A Degree?

Brazos experienced significant natural gas supply interruptions from the extreme weather event. One reason, we understand, is that natural gas supplies were more constrained in North Texas than in South Texas during the winter storm: Atmos Energy cut natural gas transportation to two of Brazos' plants, which then had to run on fuel oil. While slightly fewer than half of Brazos' gas-fired plants have the ability to burn oil as backup fuel, truck deliveries during the extreme winter weather also suffered disruptions. Brazos' plants experienced outages as a result of equipment and mechanical problems, and an inability to source fuel. Without power plants, the utility was forced into the spot market to purchase electricity at peak prices that led to its bankruptcy filing. In addition, the winter storm caused an 8% increase in demand above Brazos' forecast peak.

Rayburn had secured 95% of its forecast load prior to the storm and its generating assets experienced only minor outages, but the cooperative experienced significant operating losses as heightened demand (40% above forecast) necessitated the purchase of significant amounts of energy at scarcity pricing levels. Rayburn's market power purchases reached the market cap of $9,000 per MWh during many hours of several days beginning Feb. 14, contributing to the utility's substantial unbudgeted costs. Because of the unexpected demand, Rayburn's need for market purchases to complement its owned generation and PPAs ultimately left it exposed to unexpected and unhedged costs.

Why Were Some Utilities Relatively Unaffected By The Storm?

While storm costs were significantly higher for some utilities than for others, size (in terms of the number of customer accounts ultimately served) explained much of this differential. But in some cases, other factors such as the level of actual peak demand versus forecast demand accentuated the costs. Among the 23 rated load-serving utilities that experienced both negative and positive financial storm effects, storm costs per customer ranged from a surplus of $199 to a cost of $3,711 (see table), with the average storm cost per customer about $1,100. Rating changes as indicated in the table tended to correlate with a higher storm cost per customer, but this does not entirely explain all rating actions or lack thereof. We found that ratings were more resilient among utilities that:

• Were long on power and used that position as a significant hedge by selling power into the market to offset higher costs;
• Established strong governance factors, including sophisticated hedging practices and financial policies;
• Maintained very strong financial metrics heading into the storm, especially with regard to liquidity;
• Demonstrated good power supply diversification both from a fuel mix and geographic standpoint, without undue exposure to nonfirm resources that may not have produced during the storm; and
• Had entered into fixed-price PPAs, which shielded some utilities from surging costs during the storm.

We also note that the larger utilities in ERCOT were better able to offset costs given economies of scale: The utilities could recoup storm costs of several hundred million dollars by levying a relatively small base rate increase across several hundred thousand customers, preserving financial flexibility.

Lessons Learned, As Told By The Utilities Themselves

The utilities we rate within ERCOT are taking remedial actions to address the financial implications of the winter storm event, but many report that they are waiting to see what additional reforms the state, ERCOT, and PUC announce before implementing a course of action to mitigate exposure to similar events. This uncertainty contributes to our negative rating outlooks on the bulk of the state's municipal electric utilities and cooperatives. Several utilities with generating assets that failed to perform as a result of issues with fuel, freezing controls, or other impairments have added winterization projects to their capital plans, especially in light of the recent PUC winterization rule discussed above. While utilities are required to make best efforts to complete winterization projects by Dec. 1, 2021, we believe some utilities might request or require more time through the "good cause" exception process.

While some utilities' gas-fired plants were able to switch to fuel oil on a limited basis, this solution had mixed results depending on the availability and amount of fuel oil locally stored. Many utilities report a goal to explore the availability of hedging structures and supply commitments that will better allow them to shield financial performance from extreme prices of the kind and duration experienced during the storm. However, we anticipate that in the winter storm's aftermath, counterparties may be less willing to provide these hedges and/or will price them higher. Utilities also exhibit a heightened focus on strategy related to new power supply decisions, with more attention to the geographic location of the generation, the plant's reliance on fuel, ability to withstand extreme temperature changes, the price and length of the power supply contract, and whether the power is firm or intermittent. Several utilities are opting to enter into more bilateral power supply agreements for certain peak demand months. While such contracts are potentially beneficial, we note that they may not always be available or that prices could rise as the demand for such contracts increases, particularly because many utilities are opting to pursue securing additional supply only in the event of extreme weather reports. Other utilities have reported the need and goal to maintain higher liquidity, especially in terms of additional lines of credit, to promptly address needs during a stress event. In our view, those utilities that have the most comprehensive governance toolkits and that maintain liquidity commensurate with key risks will be the most nimble and able to manage financial exposure to extreme weather events during the summer and winter.

The Path Forward: What S&P Global Ratings Will Consider To Return Outlooks To Stable

In our view, returning the negative outlooks to stable and resolving the negative CreditWatch listings depends on a variety of factors, including:

• Risks related to operating within the ERCOT market;
• Utilities' additional actions taken in response to storm costs and their financial ramifications; and
• Potential market reforms that address connectivity, reliability, revenue volatility, and resilience.

Based on media reports and discussions with management teams, we do not expect significant improvement to connectivity with the broader energy grid, and this continues to leave ERCOT utilities exposed to extreme weather events without the ability to import meaningful amounts of power--and could affect ratings. Removing the negative outlooks also hinges on our assessment of whether utilities are becoming more financially resilient to both summer and winter extreme weather and whether the ERCOT market has put protections in place to temper the operational exposures of extreme weather events. We believe that exposure to scarcity pricing caps presents risk that needs to be resolved. Although the price cap was temporarily lowered to $2,000 per MWh from $9,000 per MWh after the storm, we understand that this remains in effect only for 2021 and, without additional action, could return to the higher level in 2022. In our view, ERCOT's status as an energy-only market and the high price caps that were put in place to incentivize capacity additions that are essential to maintaining grid reliability challenge the appetite to reduce the price cap in 2022 and beyond. We also expect that the legislature, regulators, and the Railroad Commission (whose oil and gas division regulates the exploration, production, and transportation of oil and natural gas in Texas) will take considerable time to deliberate and adopt additional market reforms, including phase two of the winterization process. In addition, it will take time for the utilities to implement corrective actions related to the storm. We expect that these issues could extend the lives of the negative outlooks. While the legislature approved the ability for utilities such as Rayburn and Brazos to securitize significant unpaid invoices from the storm, the timing and success of such financings remain uncertain.