So Far, More Than Two Dozen Rating Actions

The February winter storm unofficially known as "Uri" and its power market disruptions were the catalysts for recent negative rating actions affecting many electric and gas market participants in Texas and the Southwest. The credit effects of Uri proved most acute among Texas' electric cooperative and public power utilities (see table at end). Within those sectors, we have to date lowered our ratings on seven entities, including three multi-notch downgrades: one to 'D' from 'A', one to 'CCC' from 'A', and one to 'CC' from 'A-'. We lowered the other four by one notch. We also placed 21 public power and electric cooperative utilities' ratings on CreditWatch with negative rating implications to reflect the potential for further rating actions.

Merchant generators, independent power producers, investor-owned gas distribution companies less exposed to credit pressures.  We have identified fewer credit exposures among merchant generators, independent power producers (IPPs), and investor-owned gas distribution companies, where there have been three rating downgrades: two downgrades were by two notches and one was by one notch. Four of the companies in these sectors have either a negative outlook or a negative CreditWatch listing. We view Texas-based investor-owned electric utilities as structurally less exposed to the storm's financial and operational fallout because they neither produce nor purchase electricity for their retail customers; rather, they are compensated for merely conveying the electricity that separate retail electric provider companies (REPs) procure.

What's Next For Creditworthiness?

We believe unpaid bills for wholesale purchase of electricity and gas represent the most significant financial exposures that are likely to negatively pressure ratings. Secondarily, looming over many Texas electricity market participants are latent negative credit pressures that could materialize as the Electric Reliability Council of Texas (ERCOT) socializes defaulted power payments to non-defaulting market participants. ERCOT estimates $3.1 billion of participant payment defaults. About 75% of the defaulted payments are attributable to two rated electric cooperative utilities, Brazos Electric Power Cooperative, Inc. (D/NM) and Rayburn Country Electric Cooperative, Inc. (CC/WatchNeg). The balance derives from several unrated companies, most of which are REPs.

As more complete data on the magnitude of these liabilities becomes available, we will be able to better assess the magnitude of the financial exposures facing energy companies, their counterparties, and their lenders as they quantify the costs. Some market participants might also face the potential for governmental directives and adverse judgments in pending and anticipated litigations whose outcomes might require generators to disgorge portions of power sales revenues, which in turn may affect creditworthiness. If successful, litigations challenging ERCOT's right to socialize defaulted payments might erode the viability of the ERCOT market.

We are monitoring several credit drivers that could lead to additional negative rating actions. They include:

• We estimate ERCOT market participant defaults of $3.1 billion. We believe this number could grow if unrated REPs or other rated or unrated market participants continue to default on their ERCOT obligations. We expect ERCOT will seek to allocate defaulted payments pro rata among the market's non-defaulting participants, which could create financial pressures among market participants and lead to additional rating downgrades. ERCOT may need to revise its monthly cap on shortfall collections; otherwise, it might take years to recover defaulted payments. Lifting current limits could accelerate negative rating pressures facing market participants.
• Public power utilities, electric cooperative utilities, and some natural gas distribution utilities may need to pursue steep rate increases to amortize the debt they plan to issue to fund payments to ERCOT and to gas suppliers. We believe that sizable rate increases, should they occur, can impair customer affordability and exhaust ratemaking capacity, which could lead to negative rating effects.
• Uncertainty remains about the propriety of some of the estimated $55 billion cost of electricity sales made through ERCOT during Uri. Among the costs of the week's electricity sales, the Texas Public Utility Commission's (PUC) independent market monitor originally identified $16 billion of over-pricing that it attributed to the commission's perpetuation of market prices at the $9,000/MWh maximum level for 33 hours longer than warranted. Subsequently, the market monitor revised its estimate to $3 billion-$4 billion to reflect netting vis-à-vis generators that both bought and sold power. Two of the state's three PUC commissioners have resigned in the wake of the independent monitor's report, which will likely delay any corrective measures.
• Over time, we anticipate that market participants will seek to reconsider hedging policies, and explore the availability of hedging structures and supply commitments that could better able them to shield financial performance from extreme prices of the kind and duration experienced during the storm. However, we anticipate that in Uri's aftermath, counterparties may be less willing to provide hedges and/or price them more expensively.

In addition, Uri exposed risks related to buying and selling power in the ERCOT market, which present unique challenges for remediation under the market's current structure. These risks include:

• 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. 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. In addition to the insufficiency of reserve margins in February, we estimate thin summer reserve margins of 10%, suggesting the potential for winter and summer operational and financial disruptions.
• Although regulators intended scarcity pricing of $9,000/MWh to encourage generation owners to operate during periods of extreme electricity demand, during Uri the financial incentives to run power plants could not overcome physical barriers that precluded generation owners from producing sufficient electricity during the weather event. By comparison, market caps in California and other markets are far lower at $2000/MWh or less.
• During Uri, the market's price signals not only failed to produce their intended supply response, but were the catalysts for economic impairment when operational hurdles frustrated generation from dispatching.
• Investments in more robust winterization might add to the financial pressures already facing market participants. February showed that historical winterization practices at power plants, gas wells and along gap pipelines could not support uninterrupted electricity and gas supplies during this 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 February's outages.
• The growing interdependency of electricity and natural gas production exposes generation to natural gas supply disruptions and the equipment that drives natural gas wells and pipeline pumps to electrical outages.

Why Did The Storm Have An Extreme Market Impact?

Cold weather events are not unique, but the severity of Uri and the market and operational dislocations it caused were. During Uri's market disruption, 46,000 MW of generation capacity was offline, out of total capacity of 82,000 MW. This compares to 33,000 MW in outages in the last severe cold weather event to hit Texas, in February 2011. During Uri, Power prices spiked to $9,000/MWh, whereas in 2011 they did not exceed $3,000/MWh. Moreover, the duration of the 2021 winter event was far longer than 2011's, with prices averaging $6,600/MWh over the six-day period.

Sustained high prices over several days saddled the sector with an estimated $55 billion of extraordinary electricity prices, in addition to margin calls on contractual positions. February's gas and electricity costs have created formidable liquidity needs that many, but not all, market participants are struggling to satisfy. Beyond extreme liquidity calls, entities that were short power or natural gas have suffered substantial losses. At this point, we are unable to determine the allocation of any clawback of the overcharges cited by the market monitor. If there is a clawback, those that had short positions in February might benefit, and those that were long could need to disgorge what might be deemed to be excessive profits.

Ratings and outlooks of market participants short on power or natural gas were the most negatively affected

Our negative credit rating actions were most prevalent among those market participants that were short power or natural gas during the weather event. Many of the affected utilities faced significant liquidity demands to cover unprecedented commodity procurement expenses and collateral calls. The severity and duration of freezing temperatures, along with the unparalleled disablement of power plants, eclipsed the stability commonly afforded by hedging arrangements, leaving utilities vulnerable to the extraordinarily high costs incurred during the storm. This resulted in weaker financial metrics for these utilities. At the same time the intense price pressures penalized utilities that exhibited short positions and exposed the limits of their hedging practices, other utilities with long generation positions profited from energy sales made at stratospheric prices. Short generation positions occurred on a case by case basis and were attributable to individual utilities' generation arrangements and outages.

Irrespective of whether they were long or short generation or gas, the specter of ERCOT's socialization of the defaulted payments ratably among non-defaulting participants presents an ongoing negative credit risk for generation companies and utilities. Based on our understanding of the ERCOT framework, we expect ERCOT will allocate among non-defaulting market participants on a pro rata basis, an estimated $3.1 billion of defaulted payments. This figure is fluid and has been increasing as market participants, principally REPs, have failed to pay ERCOT.

The Brazos bankruptcy

The largest default on ERCOT obligations is attributable to a single utility, Brazos Electric Power Cooperative, which owes ERCOT about $1.8 billion for Uri-related obligations.

The size of this obligation is extremely large relative to the utility's $2.2 billion of existing debt and precludes contemporaneously passing along these costs in rates.

The liability to ERCOT triggered the cooperative's bankruptcy filing and our assignment of a 'D' rating from 'A' to the utility and a 'CCC' rating from 'A'to its subsidiary, Brazos Sandy Creek Electric Cooperative, Inc., which owns an interest in a coal plant, and relies on a power purchase agreement with Brazos to pay debt service on its bonds.

We Trace The Storm's Financial Pressures To An Amalgam Of Factors

A rare weather event

After Feb. 12, subfreezing temperatures persisted throughout much of Texas for about a week. Austin reported 162 consecutive hours of freezing temperatures, and Dallas, 140 hours, during that window. By comparison, the most significant cold weather event that affected the state's power markets prior to Uri was a decade earlier in February 2011 and the duration of freezing temperatures and their impact on electricity operations and prices was substantially less. During the 2011 event, Dallas experienced 101 consecutive hours of freezing temperatures and Austin, 69.

Demand surges

As homes and businesses struggled to stave off the cold, the harsh temperatures drove electricity demand to 77,000 MW, or 33% above the 58,000 MW winter peak projected by ERCOT. The peak demand ERCOT projected for winter 2020-2021 was 2% above the 10-year average historical peak. The largest upward deviation from the average peak during those 10 years was 16%.

Generation capacity declines

The storm's freezing temperatures disabled a lot of the generation capacity needed to meet customer demand. On top of 8,500 MW of generation that was already offline due to scheduled or forced outages, the low temperatures disabled another 38,000 MW of ERCOT's 82,000 MW of generation capacity because insufficiently winterized equipment froze at several power plants and other power plants were unable to source natural gas because the temperatures impeded natural gas production and transmission. By comparison, 2011's winter event idled 30,000 MW.

ERCOT responded to February's power plant failures by directing utilities to shed nearly 30,000 MW of load by disconnecting customers from the electric grid to protect the grid from a cascading collapse. By comparison, in 2011, ERCOT's load shed directive affected only 5,000 MW. While ERCOT's Uri-related load shedding directive lasted 71 hours, 2011's winter event required only eight hours of load shedding, underscoring Uri's extreme effects and uniqueness.

Supply and demand imbalances triggered a pricing surge

Power plant outages created acute supply and demand imbalances that triggered exorbitant commodity price spikes. Hourly wholesale power prices reached $9,000/MWh, a price that persisted. However, from Feb. 14 to Feb. 19, average hourly wholesale power prices were a lower, but still onerously high, $6,600/MWh. By comparison, in 2011's winter event, prices did not exceed $3,000/MWh. And, although prices reached $9,000/MWh during an August 2019 heat wave, the market prices persisted at that level only 4 p.m.-6 p.m. on Aug. 13 and 14. Aside from those hours, power prices approximated more normal levels throughout most of the balance of those days.

The independent monitor is revisiting regulators' pricing decisions

The PUC's independent market monitor asserts that economic supply and demand theory is principally, but not totally, responsible for high prices. The independent monitor opined that the PUC inappropriately imposed scarcity prices for a day and a half longer than necessary. The monitor also said that the commission's erroneous perpetuation of scarcity pricing accounted for some of the estimated $55 billion of extraordinary electricity prices, which added to financial difficulties that utilities, generation companies, and their customers experienced.

Natural gas prices also spiked

In addition to shouldering exorbitant electricity prices, utilities encountered a meteoric rise in Henry Hub's natural gas price, which reached $24 per million British thermal units (mmBtu) on Feb. 17, the highest level reached since February 2003's $19/mmBtu. The $24 price on Feb. 17, 2021, was six times higher than the $4 price for Henry Hub gas seven days earlier. Some other regional natural gas pricing hubs reported prices exceeding $1,000/mmBtu. The amalgam of electricity and gas price increase left power market participants facing monumental unbudgeted expenses ranging from tens of millions of dollars to more than $2 billion.

Transparency considerations also drove our CreditWatch actions

Our CreditWatch negative actions reflected, in part, the market's lack of contemporaneous transparency concerning the winter event's financial burdens. Days after temperatures moderated, market participants continued to quantify and disclose their financial exposures, which frustrated efforts to identify the amounts of internal and supplemental external liquidity needed to satisfy obligations.

Not-For-Profit Utilities' Credit Exposure Is Elevated

A legacy of predictable revenues

Favorable financial metrics and captive wholesale and retail customers have been a source of a stable and predictable revenue stream for the recovery of fixed and variable costs and the underpinnings of the historically investment-grade ratings we assigned to Texas' public power and electric cooperative utilities. Traditionally, not-for-profit utilities' ability to levy rate adjustments on captive customers, which has facilitated sound alignments among revenues, expenses, and debt service, has been a credit strength. Before Uri, these utilities have consistently recouped generation investments and operating costs from their wholesale and retail customers, even if generation plants were not dispatching into the market, whether due to plants' relative economics or outages. On the other hand, due to the absence of capacity revenues in ERCOT, merchant generation owners operating within ERCOT lack a predictable pathway for recovering fixed costs.

Rapid acceleration of additional costs weakened financial flexibility and leverage measures

Uri upended the Texas not-for-profit utility sector's traditional resilience because the magnitude of the weather event's price spikes was so large and protracted that we see it as diminishing ratemaking options. The price spikes significantly diminished balance sheet liquidity at many utilities and will likelynecessitate debt additions that we believe could increase leverage and weaken debt service coverage metrics. We anticipate that debt additions will place substantial upward pressure on retail rates at some of the not-for-profit utilities, which could frustrate the ability to exercise the financial flexibility we traditionally associate with the sector's autonomous ratemaking authority and challenge the preservation of sound credit metrics.

Operational factors impaired financial performance

The catalysts for our rating downgrades and our negative CreditWatch placements include short generation positions that created dependence on costly energy purchases, what proved to be inadequate legacy power plant winterization initiatives that led to outages that compounded short positions, and hedging that could not mitigate the severity and duration of the market disruptions. These factors, together with extensive power plant outages, and insufficient liquidity balances relative to market exposures, exerted additional negative credit pressure. Going forward, adding to credit risks will be customers' wherewithal to shoulder sharply higher rates as their utilities recover electricity and natural gas procurement costs along with other rate increases needed to cover inflation and support capital projects. Weakened ratemaking flexibility could also make it difficult for utilities to rebuild liquidity to levels suited to respond to recurrences of similar price spikes. Uri's erosion of existing liquidity makes the task that much more challenging.

The ERCOT market's design exacerbated financial pressures

We also believe that the public power and electric cooperative utilities operating in the ERCOT market will continue to face credit exposure to the flaws market's structure as detailed below. The storm highlighted the financial risks ERCOT's framework presents. And, we believe extreme weather events increase the market's vulnerability to winter and summer recurrences of the outsize price and operational disruptions that played out in February.

ERCOT has limited ability to respond to in-state generation outages, whether attributable to weather events or other factors. Because of its limited interconnectivity with generation beyond its borders, ERCOT is constrained in its ability to import electricity from neighboring power markets to temper runaway prices like February's.

We also have questions about the prospects for generation additions that will bolster the market's resilience to outages. ERCOT compensates generators for energy sales by paying them market-clearing prices; it does not compensate generation owners with capacity payments that fund the recovery of capital investments in generation irrespective of dispatch levels. Because generation owners do not receive capacity payments, the principal financial incentive for adding to the state's generation portfolio is the prospect of receiving scarcity pricing for energy sales during hours when electricity demand is highest.

ERCOT's fleet of generation assets is tightly aligned with consumers' electricity demand. Summer 2020's peak demand was 74,000 MW compared with the market's 82,000 MW of generation capacity. The slim 10% reserve margin increases the likelihood that energy prices could rise to the market's exceptionally high $9,000/MWh scarcity price ceiling during summer or winter peaks. By comparison, in California, a state that is prone to occasional supply and demand imbalances, the California Independent System Operator's tariff contains a significantly lower $2,000/MWh price ceiling.

Diminished prospects for hedging opportunities

Hedging practices were unable to temper the financial pain Uri imposed on utilities and we think it will be increasingly difficult for utilities in the ERCOT market to preemptively strengthen their hedging to reduce future exposures. In Uri's aftermath, we believe that utilities seeking hedging arrangements could face significant obstacles. Counterparties that have traditionally provided hedges to Texas' utilities might be reluctant to provide them because the risk of committing to deliver price certainty to utilities could expose the provider to the potential of another runaway market. Even if counterparties are willing to provide hedges, we believe they might become significantly more expensive for Texas-based utilities.

Market Framework Insulates Credit Ratings Of Electric, But Not Gas, IOUs

Texas disaggregates the businesses of supplying and delivering electricity. The state's investor-owned utilities (IOUs) convey the electricity customers separately purchase from REPs. The IOUs do not purchase electricity commodity for resale to retail customers. Consequently, the investor-owned electric utilities in Texas do not have exposure to ERCOT for power purchases, which helped shield their credit ratings. The REPs purchase electricity commodity for their customers in the ERCOT market and transmit that electricity to customers over the investor-owned utilities' wires. The REPs issue bills to retail customers for the commodity and its delivery.

Limited ratings effects beyond Texas's border

Although the most significant financial effects of the winter storm were contained within Texas's borders, price spikes for electricity and natural gas extended into neighboring states. However, for the most part, Uri's effects on credit ratings were less impactful outside of Texas. Yet, Oklahoma Gas & Electric Co. and its parent, OGE Energy Corp., suffered $800 million-$1 billion of unbudgeted fuel and purchased power costs. We believe the debt funding these obligations will weaken its financial measures, which we reflected by assigning a negative outlook to the company's 'BBB+' rating.

The effects of high volumes and prices on gas distribution utilities

In addition, Uri negatively affected the financial performance of some investor-owned natural gas distribution utilities that sourced unforeseen volumes of gas to meet their customers' heating needs. They purchased these volumes at greatly elevated prices. Gas utilities' sales do not clear through ERCOT.

Atmos Energy, a natural gas distribution company, projects incremental gas procurement costs in the $2.5 billion-$3.5 billion range due to the commodity's high prices during Uri and customers' elevated consumption of natural gas for heating. Atmos issued debt to fund February's costly natural gas purchases and will recover the debt's costs from customers over the long term to help shield customers from rate shock. We lowered Atmos's rating to 'A-/A-2' from 'A/A-1' and revised the outlook to negative to reflect expectations of weaker financial measures due to the additional debt. Similarly, we lowered the rating on gas distribution company ONE Gas, Inc., to 'BBB+' from 'A'. The outlook is negative.

Operational And Financial Disruptions Compromised Some Merchant Generator And Project Financing Ratings

Cashflow vulnerability stems from ERCOT's framework for compensating generators

Prior to the storm, ratings on nearly all the merchant generators and IPPs operating in the ERCOT market were in the 'BB,' 'B,' and 'CCC,' rating categories. The market structure that does not compensate generation developers with capacity payments contributed significantly to these companies' speculative grade ratings. In the absence of capacity payments, merchant generators and IPPs primarily relied on periodic scarcity pricing to recover fixed costs on top of their variable costs. Our ratings on these companies reflected scarcity pricing's unpredictability. By comparison, merchant generation operating in markets like the PJM Interconnection receive capacity payments as part of a market structure that compensates generation owners to induce them to make generation investments that contribute to the reliability of the PJM market. PJM's capacity payments contribute to cashflows that are more predictable than those ERCOT market participants can expect.

We placed the 'BB+' rating on Vistra Corp., on CreditWatch with negative implications. The company is an IPP that also operates an REP business and estimates that its cash flow faces a negative $900 million-$1.3 billion Uri impact because of several factors. The REP's load serving obligations aggravated Vistra's short generation position. About 3,000 MW-5,000 MW of its natural gas-fired generation fleet could not dispatch during Uri because the company could not procure fuel. The remainder of its plants that did dispatch burned fuel acquired at very high prices. We also placed the 'B' issuer credit rating of Talen Energy Supply LLC on CreditWatch with negative implications to reflect the generation outages and collateral posting requirements this IPP with an REP business faced. We believe Talen could face losses of $50 million-$100 million that could lead to lower ratings.

Exelon revisits its business strategy

We lowered to 'BBB-' from 'BBB' the rating on Exelon Generation Co. LLC's multi-state generation portfolio in response to its parent's decision to spin off its generation portfolio business, including its Texas powerplants. The outlook is stable. The lower rating reflects the generation company's stand-alone credit quality. The Exelon subsidiary's Texas generation assets were almost entirely unavailable during Uri, which forced the company into the market to purchase extremely costly power to discharge power supply commitments.

Exelon Generation announced a $750 million-$950 million impact from the storm. We expect Exelon will capitalize Exelon Generation's balance sheet at levels that result in adjusted FFO to debt at, or over, 30% on a sustained basis. Measures would include retentions of 2021 distributions at Exelon Generation, if required.

Impacts on renewable companies

A number of renewable companies have meaningful to smaller operations in ERCOT. The impact would depend on the nature of the contracting, or hedging. NextEra Energy Partners L.P.'s (NEP) agreements in ERCOT are structured "as produced." We expect its wind farms to have availability issues. However, we expect no material adverse impacts. The company's PPAs are structured such that projects are only required to deliver power if the sites are operating and there is no obligation to procure replacement power in the event the sites are offline. The company has reaffirmed previously issued guidance after the Texas freeze. We estimate the financial impact on Canada-based Innergex Renewable Energy at about C$70 million to C$80 million. The company was unable to generate electricity at three of its locations and has an adverse financial impact due to realized losses on the power hedges. We think other companies such as Pattern Energy Group Inc. would also be affected by the events as they have minimum commitments on their PPAs (or financially settled hedges). While these exposures could be manageable at rated levels, they will not be immaterial.

A pathway to cost recovery distinguishes the not-for-profit and merchant sectors

We differentiate the public power and electric cooperative utilities operating in ERCOT from the merchant generation companies. Although the not-for-profit utilities similarly do not receive capacity payments from the market, they have a record of recovering capital investments from their captive customers, irrespective of whether their power plants are dispatching. The ability of public power and electric cooperative utilities to set retail prices supports their higher ratings relative to the ratings of the merchant generators that are price takers that are beholden to wholesale markets that establish the price for the commodity they sell. For merchant generators, volatile market prices define their prospects for recovering fixed costs and their credit ratings. For the public power and electric cooperative utilities, ratemaking capacity defines the predictability of their cashflows.

Midstream Energy And Gas Producers Are Not Greatly Affected

We believe the credit exposure to midstream energy companies from Uri will be modest, with downside risk generally no more than 10% of annual EBITDA. This assumption is based on the somewhat limited exposure to the municipal power companies that were significantly harmed by the storm, and the ability of midstream companies to invoke force majeure clauses in their firm transportation contracts for delivered natural gas or crude oil. A definitive accounting of all the puts and takes that occurred to the bottom lines during the February storm will not likely be known until first quarter earnings calls, but, at this point, we think that the outcomes will not lead to any ratings pressure. Most gathering and processing companies had a number of days with volume outages from pre-emptive producer shut-ins or well freeze-offs but was not prolonged. We also expect that the larger, more diversified midstream companies that had natural gas in storage and had electricity to power compressors to move the natural gas to market could realize substantial profits. These proceeds could help strengthen balance sheets or lead to opportunistic share repurchases but will unlikely lead to any ratings momentum.

The Texas storm was another unwelcome and unexpected hit to the independent refining industry, which is still reeling from weak demand related to the pandemic, large declines in EBITDA, and heavy debt burdens used to shore up liquidity. We estimate that 5.7-5.8 million barrels per day of refining capacity went offline in the Texas Gulf Coast region due to the storm, and perhaps a little over 2 million barrels per day remains offline. This comes at a time when refined product inventory levels have declined to within the five-year average and refining margins have improved, but are still well below mid-cycle levels. The sector outlook is negative and most of the portfolio remains on negative outlook.

If the magnitude of the first quarter's weakness cannot be offset by refiners' financial performance in the year's remaining three quarters, we could lower ratings.

For Most Banks And Insurers, Texas Exposures Are Immaterial

S&P Global Ratings expects the credit impact from February's extraordinary power disruptions in Texas to be generally manageable for rated banks. Although some institutions we rate have exposure to power market participants in Texas, we believe the direct exposures make up a small portion of their loans and are manageable. We are still evaluating the full scope of the damage from the incident and we will continue to monitor for contingent exposures that could yet arise. That said, we believe that the broadly diversified loan footprint of these banks will help mitigate a rise in delinquencies or charge-offs from the power sector, should that occur. In 2020, most banks had already sharply amplified their reserves in anticipation of substantially greater losses from COVID-19 which has heretofore not materialized. The higher reserves, in turn, position the banks well to absorb potential losses that may emerge from the power disruptions. Furthermore, some large banks may have at least partially offset some default exposure in loans with the gains on certain power-related trading positions.

Although the balance sheets of most financial institutions and insurers who are lenders with exposure to Texas's energy markets have substantial capacity to absorb these borrowers' precipitous financial declines, we lowered our ratings on National Rural Utilities Cooperative Finance Corp. (CFC), a nonbank lender principally to electric cooperative utilities, to 'A-/A-2' from 'A/A-1'. The outlook is negative.

Our rating downgrade on CFC reflects the finance company's exposure to a number of Texas utilities that are experiencing and that could experience elevated credit stress as they settle their ERCOT transactions, pay for natural gas procured at high prices during February's extreme weather conditions, and contend with ERCOT's anticipated socialization of defaults. About 15% of CFC's loan portfolio is attributable to Texas utilities, including but not limited to Brazos and Rayburn Country Electric Cooperative. The former utility filed for bankruptcy due to its ERCOT bills, and the latter appears to lack the capacity to discharge hundreds of millions of dollars of pending ERCOT bills.

The ratings impact from Uri is neutral for the North American life, property/casualty insurance, and reinsurance sectors. When losses are aggregated, we expect the sector to able to absorb losses and this to be an earnings, not a capital, event. We anticipate property-related coverage such as homeowners and commercial property will be most affected, although we could see elevated claims on automobile and general liability policies. Ample reinsurance protection and robust capital among insurers should offer some respite to offset this unusual loss. However, insurers with high exposure to the affected region and less-robust capitalization could be subject to greater capital pressure if second- and third-quarter events reach higher levels than those in previous years. Losses could also eat into insurers and reinsurers' catastrophe budgets for the year. We also identified several life insurers that have direct asset risk to Brazos Electric Power Cooperative through investment in its debt obligations. The risk, in our view, is manageable for life insurers, as no one insurer group has more than $40 million in bonds, which is negligible when compared to the individual group's capital and surplus. In general, insurers and reinsurers strive to maintain well-diversified investment portfolios and limit their concentration risk to product and geography in order to protect balance sheets against significant event loss. We will continue to monitor the situation for contingent exposures that could arise.

Texas And Its Local Government Units

Impact on the state is minimal

While the immediate costs to the state are minimal, in our view, the cascading chain of events that were significantly disruptive across the state may result in policy changes that could have credit considerations, such as supporting funding efforts to weatherize the grid. Four days after declaring a statewide disaster (Feb. 12), the governor declared reform of the Electric Reliability Council of Texas (ERCOT) as an emergency item for the legislature to address in the current session scheduled to adjourn on May 31st. On March 9, the governor added an as emergency item for the legislature to address any potential billing errors assessed by ERCOT. Additionally, the governor has asked the legislature to mandate and ensure funding to winterize the state's power system, which could require a sizable investment. Major policy changes can often take time, and should it not be completed by the end of the regular session, a special legislative session can be called should the governor choose If legislation is passed, we will assess the outcome, if any, on the state's credit profile. The direct costs to the state and its agencies have so far been limited, with the chief of the Texas Department of Emergency Management reporting in late February expenditures of just roughly $41 million, with 75% of the cost likely reimbursable from the federal government.

Long-term impact to local government credit quality is expected to be limited

Following Uri, about 50% of counties were in the designated disaster area. Despite the widespread nature of this event we have not seen significant financial disruption for local governments. However, many cities in Texas have their own electric utility systems which will require additional credit focus related to the following risks:

• In some cases the utility supports general fund operations through transfers in or payment via franchise fees. The amount of support varies, but the potential for sudden and sharp reductions in payments due to fiscal pressure for the utility will be monitored.
• In the short term, Uri caused a liquidity event for utility providers, and we will continue to review any related reduction in a local government's cash position.
• On a longer-term basis, local governments who rely on revenues from the utility system for general fund operations or to support tax-backed debt may need to raise property taxes to compensate for less support, likely in concert with higher electric utility bills