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    Fitch Downgrades Austin, TX Electric Utility System Rev Bonds to 'AA-'; Outlook Stable

    June 29, 2022 - ENP Newswire


      Fitch Ratings has downgraded the following electric utility system revenue bonds issued by the City of Austin, TX to 'AA-' from 'AA'.

      $1.9 billion electric utility system revenue and revenue refunding bonds;

      $50.3 million combined utility systems (prior subordinate lien) revenue bonds.

      The standalone credit profile (scp) is assessed at 'aa-'.

      The Rating Outlook is Stable.


      The downgrade to 'AA-' reflects Austin Electric's (AE) elevated leverage, which has steadily increased during the past three years. Weaker operating cash flows primarily driven by lower base rate revenues contribute to the utility's rising leverage, which was already somewhat high after AE's $460 million debt-financed purchase of Nacogdoches Power, LLC (NAC) biomass facility in fiscal 2019. Gains from excess market sales during the 2021 winter storm event - estimated at $100 million - are being returned to customers through a lower Power Supply Adjustment (PSA).

      The Stable Outlook reflects AE's projected improvement in operating cash flows, which assumes the implementation of AE's proposed base rate increase in January 2023. The rate adjustment remains subject to city council approval, which AE anticipates will occur in October to November 2022. The planned rate increase is projected to contribute an additional $48 million in base rate revenues. AE expects additional base rate increases will be necessary to improve the utility's operating cash flows and leverage profile on a sustained basis.

      The rating also reflects Fitch's view of the elevated operating risk for public power systems located within Electric Reliability Council of Texas (ERCOT) regional market. Operating risk for all Fitch-rated ERCOT-based electric utilities remain constrained to an 'a' operating risk assessment due to the ongoing ERCOT risks, including natural gas delivery concerns, counterparty risk and price volatility, all of which were exposed during the Texas winter storm event in February 2021. Costs related to AE's Resource Generation and Climate Protection Plan to 2030 (2030 Plan), which outlines the city's goal to have 100% carbon-free electric generation by 2035, are not expected to materially increase in the near term, but could increase over the longer term.

      The rating also considers Austin's robust service area characteristics, including the utility's consistently strong customer growth rates, and the city of Austin's (general government IDR AA+/Stable) very strong economy.


      AE provides exclusive electric service to over 500,000 electric customers in and around the City of Austin. The city of Austin makes up roughly half of the utility's defined geographical service territory, while sizeable portions of Travis and Williamson Counties make up the balance. AE is the sole supplier of electric service in its service area with the exception of an 11 square mile area accounting for less than 5% of the utility's service territory. The single-certified territory is not subject to retail competition introduced in parts of Texas in 2000. Municipal utilities in the state have the option to offer retail competition in their service areas. AE has indicated no intent to do so.

      Fitch considers the system to be a related entity to the city for rating purposes given the city's oversight of the system, including the authority to establish rates. The credit quality of the city does not currently constrain the bond rating. However, as a result of being a related entity, AE's ratings could become constrained by a material decline in the general credit quality of the city.

      February 2021 Winter Storm Event

      AE is the only Fitch-rated ERCOT public power issuer that experienced a net positive financial impact from the winter storm event, with net revenues approximating $100 million. Like many Texas utilities, AE experienced a surge in natural gas prices, prompted by unprecedented and prolonged below freezing temperatures across the state; however, AE benefited financially from energy sales from its generation fleet which more than offset the higher fuel costs and power purchased through ERCOT to serve system load. AE's generation fleet generally performed well, with limited outage times at its facilities during the winter storm event.

      The positive financial impact from the storm are being returned directly to customers through rates. AE began returning a portion of the net proceeds from the winter storm to customers in fiscal 2022, partially offsetting AE's need to adjust the utility's PSA in light of the recent rise in the utility's power supply costs. AE has returned approximately $68 million (unaudited) through May 31, 2022 and expects to return any remaining storm-related revenues through FYE 2022, excluding any net receivables due from ERCOT (approximately $27 million) The timing and ultimate payment amount on the ERCOT receivable is expected to be determined following resolution of the Brazos Electric Power Cooperative (BEPC) bankruptcy. Management does not intend to return any additional funds related to the receivable until AE receives payment from ERCOT.

      While the storm resulted in a positive financial impact for AE, AE remains exposed to meaningful operational risk in the ERCOT market. Approximately 40% of the utility's customer base remained without power for multiple days due to ERCOT-mandated load shedding events. Reduced customer load, in addition to AE's strong power supply performance through most of the winter event, allowed the utility's power generation to exceed customer usage and therefore, benefit from the excess market sales.

      AE is required to transact energy purchases through ERCOT, which is regulated by the Public Utilities Commission of Texas (PUCT) and governed by deregulated market principles established by the Texas Legislature. Participation in ERCOT exposes parties to price volatility and counterparty risk, with the potential to share in counterparty default costs. These risks were realized during the February 2021 winter storm event and Fitch believes the operating risk of ERCOT-based public power systems remains elevated.


      Revenue Defensibility: 'aa'

      Strong Customer Growth and Rate Affordability

      AE's revenue defensibility is well supported by revenues from electric sales within and around the City of Austin and electric rates that are established locally by the city council. AE's revenue defensibility reflects rapid and sustained annual customer growth, which averaged 2.5% over the last five years. Service area characteristics, rate flexibility, and affordability are all very favorable.

      Operating Risk: 'a'

      Low Operating Costs; Weaker Operating Cost Flexibility

      AE's operating risk profile remains strong reflecting the utility's low operating costs at 11.1 cent/KWh in fiscal 2021, but also considers Fitch's view of the elevated risks associated with operating in the ERCOT market. These risks became evident during the February 2021 winter storm event in the form of extreme price volatility and counterparty risks, both of which weaken Fitch's view of AE's operating cost flexibility.

      AE continues to transition its power supply to more renewable resources, which accounted for 61% of AE's 2021 total energy load, up from 23% in fiscal 2015. Fitch expects the utility's operating costs to remain relatively stable in the near term even as owned resources continue to be replaced with renewable contracts over the next five years; however, increased reliance on ERCOT market purchases to supplement AE's power supply further exposes AE to market price volatility.

      Financial Profile: 'aa'

      Elevated Leverage, Proposed Rate Increases to Improve Cash Flow

      AE's financial profile showed continued weakening in fiscal 2021 as the utility's operating revenues narrowed to a five-year historical low. Declines were primarily driven by the utility's lower base rate revenues, which are expected to remain at lower levels in fiscal 2022, offset by the recognition of a portion of the net revenues AE gained during the February 2021 winter storm event. Fitch expects the implementation of AE's planned base rate increase in January 2023 would significantly improve the utility's operating cash flows and return AE's leverage profile to levels commensurate with an 'aa' financial profile assessment. Long-term debt is expected to trend slightly higher over the next five years as the utility partially debt finances its capex plan, but should not materially impact the utility's leverage profile.


      Factors that could, individually or collectively, lead to positive rating action/upgrade:

      Improved operating cash flows resulting in projected leverage declines consistently below 7.0x in Fitch's base and stress case scenarios;

      Factors that could, individually or collectively, lead to negative rating action/downgrade:

      An inability to maintain leverage below 8.0x in Fitch's base and stress case scenarios;

      Unanticipated increases in AE's operating costs and/or capital expenditures as the utility transitions its power supply following the closure of the Decker Creek gas-fired Units 1 & 2 (Decker units);

      Inflationary cost pressures that weaken AE's financial profile on a sustained basis;

      Legislative or regulatory changes that impose material new operating or capital costs for utilities.

      Best/Worst Case Rating Scenario

      International scale credit ratings of Sovereigns, Public Finance and Infrastructure issuers have a best-case rating upgrade scenario (defined as the 99th percentile of rating transitions, measured in a positive direction) of three notches over a three-year rating horizon; and a worst-case rating downgrade scenario (defined as the 99th percentile of rating transitions, measured in a negative direction) of three notches over three years. The complete span of best- and worst-case scenario credit ratings for all rating categories ranges from 'AAA' to 'D'. Best- and worst-case scenario credit ratings are based on historical performance. For more information about the methodology used to determine sector-specific best- and worst-case scenario credit ratings, visit


      Electric-system revenue bonds are secured by net revenues of AE. The bonds are on parity with the prior subordinate-lien obligations of the combined utility systems. The prior subordinate-lien obligations are secured by a joint and several pledge of net revenues of the combined utility systems, consisting of AE and Austin Water Utility (revenue bonds rated AA-/Stable). The prior subordinate-lien obligations are rated (AA-) on par with the electric system revenue bonds, given the small amount of debt outstanding in relation to AE's overall outstanding debt. The issuance of additional bonds secured by the combined utility pledge is no longer permitted by the master bond ordinance, making the lien effectively closed. The remaining prior subordinate lien bonds mature in 2025.

      Revenue Defensibility

      Revenue Source Characteristics

      Fitch considers AE's revenue source characteristics as very strong reflecting the electric utility's monopolistic characteristics. Core electric revenues constitute nearly all of AE's pledged revenues to electric bondholders, but also include the utility's chilled water business which contributed approximately 2.2% ($28 million) of revenues during fiscal 2021.

      The chilled water business is a fundamental component of the electric utility's strategy to reduce electric usage during peak hours in order to reduce overall costs. Chilled water plants use energy during off-hours to chill water that is used for air conditioning in commercial buildings in Austin's urban core. Companies participating in Austin's chilled water program have constructed their buildings to be cooled by AE's chilled water facilities and signed long-term contracts with the city for the service. AE's residential and commercial demand response programs are also integral to AE's plan to reduce peak demand.

      Service Area Characteristics

      The strength and diversity in both AE's customer base and Austin's economy continue to underpin electric demand, thereby contributing to the utility's revenue collections. Customer growth remains strong as evidenced by the utility's five-year CAGR of 2.5%. Energy sales growth, with a five-year CAGR of 0.3%, is tempered relative to the utility's customer growth rates reflecting energy efficiency gains, in addition to the utility's broader strategic investments to reduce peak demand. AE management conservatively estimates customer and annual load growth rates of 1.7% and 0.6%, respectively, over the next five years. Residential customers have accounted for approximately 40% of electric revenues in recent years.

      The City of Austin continues to be one of the fastest growing U.S. metro-area economies. The city is the state capital and home to the University of Texas system's (AAA/Stable) flagship Austin campus, as well as six other colleges and universities. The state government and higher education sectors historically have provided stability and an economic cushion during downturns and the technology sector continues to stimulate economic growth within the service territory.

      The city's population outpaces both the state and the nation, and is estimated at nearly 1 million residents. Wealth indicators for the area are above average with median household income at 114% of the national average. Much like the rest of the nation, Austin's unemployment rate peaked in the spring of 2020 (12.4% in April 2020), but rates have since dropped to 2.6% in March 2022, below the state and national March 2022 figures of 3.9% and 3.8%, respectively.

      Rate Flexibility

      AE's average residential retail revenue per kilowatt hour (10.6 cents/kWh) as reported by the U.S. Energy Information Administration in 2020 compares favorably to other large Texas utilities and the state average. Both AE rates and statewide revenue per kWh have benefited from lower natural gas and renewable energy costs. The low electric rates continue to contribute to AE' very affordable rates. AE's rate affordability also benefits from the City of Austin's high median income levels, as well as AE's lower average power consumption levels among its customer base, relative to other Texas utilities. Fitch measures rate affordability as the total cost of residential electric service divided by median household income within the service territory. AE's rate affordability was 1.4% in 2020.

      Electric rates are approved by the city council and are not subject to any additional oversight, although the city hires an independent consumer advocate as part of the rate review process. AE conducts a cost-of-service study at least once every five years to determine its base rates which account for approximately half of AE's average residential retail bill. The majority of the remaining bill relate to energy (i.e., PSA), regulatory (transmission costs), and community benefit charges, each of which is reviewed at least annually and can be adjusted more frequently if needed.

      Base Rate Review - Rate Increase Planned

      Based on AE's cost of service study completed in April 2022, management is proposing to increase AE's customer charge to better recover the utility's fixed operating costs and improve revenue stability. Management anticipates the rate adjustment, in addition to the rate structure change, will increase base rate revenues by approximately 7.6%, contributing an additional $48 million in revenues.

      The rate increase appears necessary to improve AE's revenue stability and operating margins; however, customer rate flexibility could be impacted. While the proposed base rate increase will result in a 7.6% increase in base rate revenues, actual bill impacts will vary depending on the customer class and energy consumption. Average residential customers (estimated at 900kWh/month) will see a 17% monthly bill increase, primarily due to the proposed increase in the customer charge. The estimated bill impacts exclude adjustments to energy charges, which could see upward pressure given the recent rise in commodity prices. Customer education efforts about the rate proposal are ongoing and management anticipates city council will vote on the proposed increase in October to November 2022 with a planned implementation in January 2023.

      The current base rate review represents an interim review and follows AE's 2021 rate review, which resulted in base rates remaining unchanged. AE last adjusted its base rates following a 2016 rate review, in which base rates were reduced by 6.7% starting in January 2017. Future base rate reviews are expected to consider AE's potential exit from the Fayette coal facility, in addition to an expected decline in in certain PSA costs related to the NAC biomass facility.

      The City of Austin's council maintains a stated 2% annual rate cap target. However, the 2% cap is evaluated over time, on average, so the recent years of lower fuel and purchased power costs have created headroom in AE's rates as compared with the 2% annual cap target put in place in 2012. Fitch does not view the 2% annual cap target to be a practical constraint on AE's rates.

      Rate Structure Considerations

      Fitch believes AE's annual electric rate adjustment mechanisms are essential for the full recovery of ongoing power costs. An additional and important cost recovery component is the recovery of line extension costs. AE made the decision to move to 100% recovery of costs in 2015. Fiscal 2016 was the first full year the policy was in place and cash collections have averaged $42 million annually during the five years through fiscal 2021. Connection fees are expected to continue to recover costs associated with AE's robust customer growth.

      Operating Risk

      Low Operating Costs, Transitioning Power Supply

      AE's operating costs remained low at 11.1 cents per kWh in fiscal 2021. Total utility operating costs decreased in fiscal 2021 despite the increase in commodity costs related to the winter storm as total fiscal 2021 energy sales declined by approximately 1.7% from fiscal 2020. Rising fuel and market prices, in addition to other inflationary pressures, are likely to cause the operating costs to increase in fiscal 2022, but Fitch expects costs to moderate over the medium to long term as inflationary pressures ease. Additionally, AE's pursuit of its Resource Generation and Climate Protection Plan to 2030 (2030 Plan), which outlines the city's goal to have 100% carbon-free electric generation by 2035, is not expected to materially impact the utility's overall operating costs in the near-term, but could result in cost increases over the longer term.

      AE owns 1,860MW generation capacity, excluding the 405MW gas-fired Decker Unit 2, which ceased operations on March 31, 2022. AE also purchases approximately 2,588MW of energy through purchase power contracts, all of which are sourced through renewable projects located within ERCOT. While AE's total capacity including purchased power appears larger than needed relative to AE's 2021 peak of 2,644MW, renewable generation is intermittent and only available during certain times.

      Operating Cost Flexibility

      AE's operating cost flexibility is assessed at weaker reflecting AE's exposure to ongoing risks associated with the ERCOT market operating structure and volatile commodity prices, both of which were evident during the February 2021 weather event. While AE did not suffer any negative financial impacts from the winter event, the utility remains exposed to structural weaknesses in the ERCOT market.

      While the operating risk in ERCOT remains elevated, the Public Utility Commission of Texas and ERCOT market administrators have taken steps to limit future operational and financial risk to utilities. Additional winterization requirements and reduced market price caps - from $9,000/kWh to $5,000/kwh - are expected to have the most meaningful impact on overall market risk. Additionally, ERCOT administrators expects to maintain higher reserve margins the coming years as additional generation units come on line, which should provide additional resource adequacy. ERCOT's summer 2022 planning reserve margin increased to 23% from less than 10% during the 2019 summer.

      Environmental Considerations and Clean Energy Transition

      Approximately 87% of AE's annualized load was carbon-free during fiscal 2021, with renewable energy accounting for the largest portion of the fuel supply at nearly 61% of net load during fiscal 2021 and the remaining coming from the South Texas Project nuclear facility. However, coal generation, which had steadily declined as a percentage of AE's fuel supply from 30% in 2017 to 19% in fiscal 2020, increased to 25% in fiscal 2021. AE relied more heavily on its coal facility during the February 2021 winter event, which contributed to the overall increased coal power production in fiscal 2021. Excess load was sold through the ERCOT market through bilateral sales.

      AE retired its Decker Unit 2 facility natural gas-fired facility, on March 31, 2022, in accordance with the 2030 Plan. However, AE's plan to retire its share of the Fayette coal-fired facility by the end of 2022 was postponed indefinitely after negotiations between AE and the other joint owner, the Lower Colorado River Authority (LCRA; AA-/Stable), stalled in late 2021. AE intends to minimize the facility's scheduled output while it continues to run its portion of the facility, but neither AE nor LCRA has committed to a future Fayette retirement date. The impact on AE's carbon-free generation targets remains uncertain; however, the facility provides a physical hedge to rising natural gas prices and market price volatility over the near to medium term. AE's financial forecast assumes the plant remains in service through at least the next five years.

      AE anticipates layering in renewable resources following the planned retirement of the utility's thermal generation resources. Intermittency of renewable power poses some additional ERCOT price risks, however, as AE would likely need to purchase power during periods of weaker renewable generation.

      AE's robust energy risk program focused on entering into futures contracts, options and swaps, somewhat mitigates the financial exposure of short-term price volatility. AE does not anticipate having large open positions after the planned closure of its thermal resources.

      Fitch does not expect AE's 2030 plan will meaningfully affect operating costs over the medium term. The utility is generally well positioned to meet the goals included in the plan. The goals of the 2030 Plan are subject to certain overarching affordability goals including the 2% rate cap target, which places a protective limit on the overall cost and pace of AE's resource conversion.

      Capital Planning and Management

      Fitch calculates AE's age of plant at 15 years, which potentially reflects elevated capital needs. Fitch expects the average of age of plant could decline as AE expects to retire older generation plants in the near term. Capex to depreciation, which averaged just over 100% during fiscals 2015-2018, increased substantially in fiscal 2019 due to the purchase of the NAC biomass facility, but returned to historical levels at 106% in fiscal 2021. AE plans to accelerate the depreciation of the NAC facility through December 2022.

      AE's five-year capital improvement program (CIP; fiscals 2022-2026) includes an estimated $1.2 billion in planned investments. The CIP includes additional spending for distribution and transmission projects that will be needed to support the planned closure of the Decker unit 2, facilitate additional purchase power imports into the city, and support the Austin service territory growth. Transmission costs will be recovered through the ERCOT transmission rate that is charged proportionally across all electric customers within ERCOT.

      Financial Profile

      AE's financial profile weakened in fiscal 2021, with leverage rising to 11.1x and coverage of full obligations declining below 1.0x. Rising debt levels to fund capex, including approximately $88 million for the construction of a new headquarters complex, contributed to the utility's elevated leverage in fiscal 2021. AE's leverage was also impacted by the utility's weaker operating cash flows in fiscal 2021, which declined primarily due to lower base rate revenues.

      AE's leverage, which was 5.8x in fiscal 2018, has steadily increased during the past three years due to a combination of increased debt and weakened operating cash flows. AE's debt-financed purchase of the NAC biomass plant for approximately $460 million in June 2019 increased AE's long-term debt burden to $2.0 billion at FYE 2019 from $1.5 billion at FYE 2018. Weaker than projected operating cash flows in fiscals 2020 and 2021 have also contributed to the utility's rising leverage. Fiscal 2020 operating revenues declined following City Council's April 2020 approval to reduce rates in response to the economic impacts from the pandemic. Coverage levels, which were also impacted by increased debt service related to the NAC biomass facility, declined in fiscal 2020, with Fitch-calculated DSC dropping to 1.8x from 3.4x in fiscal 2019. The utility also provided electric bill relief customers during fiscals 2020 and 2021 of $35 million and $5 million, respectively.

      AE's very healthy cash and reserve balances have somewhat tempered the rise in the utility's leverage metrics. However, AE's liquidity metrics have declined over the past 18 months as the utility used its cash reserves to supplement the reduction in operating cash flows. Unrestricted cash balances, which were $690 million at FYE 2020, declined to $618 million at FYE 2021 and were approximately $558 million as of Jan. 31, 2022 (unaudited). AE's financial policies include a combined reserve target amount equal to no less than 150 days of operating and maintenance expenditures. Fitch calculated AE's days cash on hand at FYE 2021 at approximately 217 days. AE's proposed, but not yet approved, base rate increases are expected to steadily increase the utility's unrestricted cash balances.

      Fitch Analytical Stress Test (FAST) - Base Case and Stress Case

      The FAST base case scenario represents Fitch's expectation of AE's financial performance through the five-year forecast period ending in fiscal 2026. The scenario analysis considers AE's planned base rate increases, rate adjustment mechanisms, including the power supply adjustment, and regulatory and community benefit charges, will continue to pass through costs to retail consumers.

      Fitch expects fiscal 2022 retail electric revenue will increase substantially as AE passes through rising power supply costs. However, excluding the benefit from the extraordinary winter storm revenues, operating cash flows are expected to remain weaker and contribute to AE's elevated leverage in fiscal 2022, which is expected to remain near 10x at FYE 2022.

      The FAST base and stress scenarios assume AE's proposed base rate increase is approved by City Council during the fall of 2022 and implemented in January 2023 (fiscal 2023). The improved operating cash flows in fiscal 2023 are expected to drive AE's leverage lower, remaining between 7.0x and 7.5x through fiscal 2024. However, lower than projected operating cash flows, which would likely occur if AE's proposed base rate increases are not approved, would pressure Fitch's assessment of AE's leverage profile. Unanticipated capex that result in a substantial decline in cash reserves, or an increase in debt, would also pressure AE's leverage profile. Unrestricted cash levels are expected to increase over the next five years, but days cash on hand should remain around 200 days as the utility's liquidity is somewhat offset by rising operating expenses.

      Fitch's stress case anticipates a decline in sales in the first two years with a recovery in the final three years of the forecast. The stress case assumes a 5.2% decrease in year one followed by another 2.6% decrease in year two, both of which would be sizable declines for AE given the utility's historical customer growth; however, Fitch believes the stress is reasonable given some volatility in AE's historical energy sales. The declines are layered on AE's conservative annual load growth assumption of 0.6%.

      AE's rate adjustment mechanisms could be implemented to mitigate a substantial decline in energy sales or operating cash flow. However, the approval of additional incremental rate increases could prove more challenging following the implementation of the proposed base rate increase in January 2023, a risk that is somewhat heightened given AE's pass through of the higher energy and fuel prices in fiscal 2022. Fitch believes AE would likely increase rates to offset the rising costs, but leverage would remain elevated over the near to medium term in a stressed scenario.

      AE maintains a $27 million net cash receivable from ERCOT resulting from the 2021 winter storm. The ultimate payment primarily depends on the resolution of the BEPC bankruptcy. Fitch did not include these revenues in the scenario analysis.

      Debt Profile

      Outstanding debt, including AE's portion of the very small amount of remaining combined subordinate lien obligations, totals approximately $2.1 billion, all of which was issued as fixed-rate obligations. The combined subordinate lien obligations mature in 2025. AE uses its tax-exempt and taxable commercial paper programs to fund construction, which is periodically refinanced with long-term debt. Fitch's leverage calculation included an additional $904 million of other obligations including pension liabilities and capitalized fixed charges for purchased power.

      In addition to the sources of information identified in Fitch's applicable criteria specified below, this action was informed by information from Lumesis.


      The principal sources of information used in the analysis are described in the Applicable Criteria.

      ESG Considerations

      AE has an ESG Relevance Score of '4' for Exposure to Environmental Impacts due to the effects of the February 2021 severe winter weather event, which weakens the operating flexibility assessment. The weather event exposed deficiencies in ERCOT's market design and ability to keep the grid functioning well in the face of an extreme weather event, which exposes AE to price volatility and counterparty risk outside of its control, which has a negative impact on the credit profile, and is relevant to the ratings in conjunction with other factors.

      Unless otherwise disclosed in this section, the highest level of ESG credit relevance is a score of '3'. This means ESG issues are credit-neutral or have only a minimal credit impact on the entity, either due to their nature or the way in which they are being managed by the entity. For more information on Fitch's ESG Relevance Scores, visit


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