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Despite ERCOT’s Price Spikes, Texas Public Power Utilities Remain Resilient

In mid-August, S&P Global Ratings observed price spikes in the Electric Reliability Council of Texas Inc. (ERCOT) market, which exposes utilities short on energy to increased power costs. Because the ERCOT market does not compensate generation owners with capacity prices that might provide incentives to encourage new market entrants, regulators use scarcity-pricing signals and energy conservation measures to ensure system reliability of the electric grid. Despite the recent price spikes and ERCOT's recent energy emergency alerts (EEA1) on Aug. 13 and 15, 2019, ERCOT has not had to implement systemwide rotating outages this summer. Although ERCOT's market dynamics present cost-recovery challenges to utilities for a period when reserve margins are thin and energy demand peaks, we observe public power and electric cooperatives in Texas sufficiently managing power supply needs and using power cost recovery mechanisms to recover increased power costs. We also observe that these spikes tend to be short-lived. Utilities with surplus capacity to sell might benefit during these spikes, but at other times, they face cost-recovery challenges because prices are generally low in the ERCOT market due to an abundance of renewable generation and natural gas relative to pipeline capacity. We're following the ERCOT market price spikes to better understand utilities' power supply strategies and the extent to which they are exposed to cost recovery challenges.

ERCOT's Price Spikes And Low Reserve Margins

Although the summer of 2019 has not been as hot as 2018 or prior years, hot temperatures on Aug. 12, 2019, contributed to ERCOT reaching a new all-time peak demand of 74,531 megawatts (MW). The following day on Tuesday, Aug. 13, ERCOT issued its energy emergency alert (EEA1) to consumers in the afternoon when its operating reserves declined below 2,300 MW. While temperatures reached 102 degrees and operating reserves fell, ERCOT requested that consumers conserve energy by raising thermostat temperatures by two-to-three degrees during the peak demand hours of 3 p.m. to 7 p.m. It cancelled its EEA1 by 5 p.m. on Aug. 13, when operating reserves rose above 3,000 MW, a level that ERCOT considers providing a cushion sufficient to respond to the risk of outages. It issued another EEA1 on Thursday, Aug. 15 and urged consumers to reduce electric use during the afternoon peak demand hours. ERCOT last issued an EEA1 in January 2014, which highlights this summer's low reserve margins and the rarity of these types of heat events.

In the chart below, ERCOT's projected reserve margin of 10.5% in 2020 remains below its "safe" reserve margin of 13.75% as summer peak demand is projected to increase. If it were to maintain its safe reserve margin at 13.75%, it estimates a rotating outage event would occur once every 10 years. ERCOT is now projecting a 76,845 MW summer peak demand in 2020, which is a 3.1% increase over the all-time peak demand in mid-August. In terms of capacity, ERCOT's total generation resource capacity increased to 78,929 MW as of May 2019.

Chart 1


High temperatures in mid-August throughout Texas caused an increased demand for electricity, but this summer has not been as hot as 2018 and not nearly as hot as 2011. Dallas-Ft. Worth had a total of 23 100-degree days in 2018 compared with a record 71 days in 2011. ERCOT projected the number of 100-degree days in Dallas-Ft. Worth could range between five and 12 in 2019, and there had been only seven such days as of Aug. 13, 2019.

Chart 2


As seen in the chart below, ERCOT real-time settlement point prices in the North load zone (along with other load zones) reached the $9,000 per MWh offer-cap (or near it) for multiple 15-minute intervals, particularly during the hours of 4 p.m. and 6 p.m. on Aug. 13 and Aug. 15. The $9,000 per MWh offer-cap is equivalent to a whopping $9 per kWh, compared with the cost of electricity, which is measured in cents and is typically about two-to-five cents per kWh for wholesale power in ERCOT. However, it is important to note the duration of the price spikes are relatively short-term, which is a mitigating factor. In addition, there is the potential that brief surges in procurement costs might be mitigated by market purchases at more moderate or even low prices during the balance of the day and the month. The rapid increase in peak pricing can be even more pronounced when intermittent resources like wind and solar are not available. Intermittent resources (including wind and solar) now account for 25.5% of ERCOT's total generation capacity in 2019, making the grid more susceptible to price volatility.

Chart 3


Exposure To Increased Power Costs

Texas public power and electric cooperatives in ERCOT face the challenges of managing a power supply that mitigates exposure to real-time market price spikes and rapid increases in power costs. The price spikes present challenges for utilities who are short energy, or who depend on intermittent renewable resources for a large portion of supply and are not sufficiently entering into forward capacity and energy contracts to cover peak loads. The intermittency of renewables poses challenges to utilities that must firm up these resources with quick-start natural gas peakers or rely on market purchases, exposing the utilities to price risk, which is especially acute because they would likely need to purchase power during periods of high demand when prices rise sharply. Power producers who are typically long on power may also experience unplanned outages during these periods of peak pricing and find themselves short on energy.

Austin (d/b/a Austin Energy) (AA/Stable), which has diverse power supplies and operational assets, experienced unplanned outages and derated capacity during the week of Aug. 12, which exposed it to higher power costs for a few hours. Officials indicated 572 MW, or roughly 23% of its owned generation capacity was unavailable, and a very small percentage of load was exposed to peak market purchases. However, we believe Austin Energy's recent exposure to increased power costs is mitigated by the short duration of the utility's exposure to extreme prices and its robust power supply rate stabilization fund with a balance representing more than 90 days of power supply costs.

Denton (AA-/Stable), which has a growing renewable portfolio, is at times exposed to market price spikes, particularly during low wind periods. However, the utility purchases any short positions in the day-ahead market, and any short positions and related cost increases from market purchases are balanced by its quick-start gas-fired peaking generation or passed through using its energy cost-adjustment mechanism. Officials also indicated at no time were more than two of its 12 reciprocating engines in outage.

Georgetown (AA-/Stable), which maintains a significant renewable portfolio and is long on power, did not experience any significant cost increases during the price spikes. However, it has saddled its customers with base-rate and power cost-adjustment (PCA) rate increases in 2019 because it contracted for the output of others' renewable resources in an amount exceeding its customers' around-the-clock energy needs. Because the renewable resources produce power in spurts that are not synchronized with energy consumption, the utility has to sell its surpluses into the market and frequently incurs losses when making these sales because market prices have tended to be significantly below the prices at which Georgetown committed to purchase renewable output under long-term contracts. For example, in fiscal 2018, electric system operating expenses exceeded revenue by $6.6 million, which weakened coverage metrics and liquidity. However, the combined system's fixed-charge coverage metrics remained extremely strong at above 1.6x in fiscal 2018 due to pledged water and wastewater revenues, which softened the financial effects on the combined system.

Common Strategies To Mitigate Market Price Spike Exposure

We believe public power utilities and electric cooperatives have certain credit attributes to help deal with these challenges. First, public power utilities and electric cooperatives serve a captive customer base not subject to competition (unless they opt into competition, which is rare). This captive customer base allows these utilities to recover fixed costs and any increases in operating costs (like changes in power costs). Because of the price volatility in ERCOT's energy-only market, the presence of a dynamic purchased power cost-recovery mechanism is an important credit factor. Public power and cooperative utilities help protect their financial performance from this volatility either through hedging arrangements or pass-through mechanisms. A PCA mechanism allows a utility to dynamically adjust rates (either automatically or at management's discretion) to recover costs from ratepayers for changes in fuel or commodity pricing, transmission, environmental regulatory, and purchase power costs. Rate-setting practices typically include a requirement to set rates that cover all costs (including debt service) plus a margin, which enables this pass-through of purchased power to ratepayers if scarcity pricing occurs.

We have also observed several common strategies utilities use to manage these risks. Following the recent price spikes over the past couple of weeks, we believe Texas public power and electric cooperatives are sucessfully managing their power supply to limit their exposure to peak prices. Power producers who are long on energy have benefited financially from market price spikes, which help offset any short positions and cost increases from unplanned outages. However, power producers whose assets experience unplanned outages and find themselves short on energy are not immune to higher power costs. Some utilities enter into market purchases of block energy during the summer months to meet peak loads and hedge against price spikes with call options, or purchase in the day-ahead market to limit any short positions. It is also important to assess whether certain hedging strategies create contingent liquidity risks through collateral postings that can challenge liquidity. In our view, the recent price spikes in mid-August did not create burdensome collateral posting requirements for Texas public power and electric cooperatives.

San Antonio (d/b/a CPS Energy) (AA/Stable), which maintains a diverse generation fleet, entered into additional energy contracts this summer to supplement its operating reserves and was not exposed to the price spikes. In addition, its forward energy sales to its wholesale customers were not exposed to procuring power on a real-time basis as the cost basis for those sales are equal to the utility's unit production costs.

The Lower Colorado River Authority (A/Stable) and its wholesale customers did not experience any exposure to the price spikes and officials indicated the authority accelerated planned plant maintenance in anticipation of the summer's low reserve margins.

Brazos Electric Cooperative (A/Stable), who serves 16 distribution member cooperatives and one municipality through 68 counties in Texas, has seen very limited effects from the price spikes this summer and no wholesale power cost impact above its budget. Management entered into energy block contracts and call options well in advance of the summer season, and its purchases in the day-ahead market secured sufficient reserves above its members' peak.

This report does not constitute a rating action.

Primary Credit Analyst:Scott W Sagen, New York (1) 212-438-0272;
Secondary Contacts:David N Bodek, New York (1) 212-438-7969;
Jenny Poree, San Francisco (1) 415-371-5044;

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