Winter storm Elliott, a mass of frigid, arctic air and blizzard conditions enveloped much of the eastern two thirds of the US with the worst of it hitting the US on December 22- 25. In its wake over 200 million Americans were adversely affected and almost 100 died. We wrote about our concerns here on December 20th focusing on Texas. The biggest worry was whether natural gas producers and processors had adequately weatherized key systems, steps required by the Texas Railroad Commission after the previous storm in February 2021. Bottom line: the Texas (and Oklahoma) gas infrastructure system held up fairly well but with some noticeable loss of production during the freeze. Bloomberg reported that by Friday December 24th US gas production had declined by 10 bcf or about 10%. The exception here was a major retail gas provider, Atmos Energy, which serves about two million customers in Texas and another million in adjoining states. The company cited unexpected “low system pressure” as the reason that thousands of central Texas customers were without gas as the winter storm and severe temperatures rolled in. On the electric utility side in Texas overall, the system performed fairly well. That is with no meaningful or extraordinary level of outages. Call us sentimental but we think keeping the lights and the heat on at Christmas is a big “W” for the electric industry there. However, gas and coal plants totaling 11,000 MWs went offline in ERCOT and reserve margins were certainly skimpy, to be polite. And ERCOT officials stated that Texans electrical demand during the period exceeded their estimates by over 10,000 MWs. Probably the biggest overall surprise was wind power. The front edge of the storm was big and windy and in its early hours wind constituted up to 40% of ERCOT’s total power generation. We doubt anyone expected this but it did take some early pressure off and provide the grid additional time for completion of emergency preparations.
Several sources in Texas after the storm expressed surprise at the size of this new winter peak in electric power generation required to serve. We’re surprised they were surprised. This is a service area where older, more modest residences rely on resistance heat and often lack proper insulation. The incremental electrical demand in these frigid situations is huge. But perhaps more interesting is that in the aftermath of the last major winter storm (Uri) ERCOT never attempted to estimate their maximum demand had their system not collapsed into blackouts. Typically utilities want to know as accurately as possible what peak demand is or will be so that they can adequately cover demand plus having power plants in reserve just in case. (The “just in case” expressed as a percentage of total generation is called the reserve margin and in ERCOT it typically runs at a lean 8% vs 15% plus for neighboring systems.) The reason to be scrupulous about reserve margins is simple. Idle power generating plants sitting around merely as back-up are very expensive but absolutely necessary for system stability under extreme circumstances. Being accurate about demand forecasts is really important for both reliability and expense control. By not estimating the full demand implications of the previous storm Uri meant that ERCOT was flying blind to an extent with respect to ultimate system electrical demand. Lapses like this suggest a deeper degree of political influence and resulting regulatory dysfunction, a system intentionally hobbled by special interests involved in energy production.
In the utility business there are typically two kinds of electric companies. Many utilities in the northern half of the US are winter peaking, that is electrical demand or usage is greatest during the winter heating season. Summer peaking utilities on the other hand experience maximum electrical demand during the hottest summer afternoons when air conditioning load is greatest. Much of Texas geographically defines the southernmost boundary of the US but is now experiencing northern Wisconsin-like winter electrical demand peaks along with the expected (and probably worsening) peaks in summer. For owners of power generation plants, this poses difficult questions about the optimal time for extensive, months long but routine power plant maintenance. We think planning for major power plant overhauls just became a lot more complicated from a grid reliability perspective.
But the real difficulties in grid performance appeared further to the east. The TVA system and Duke Power in the Carolinas both experienced power plant failures resulting in extensive outages and rotating blackouts. The TVA system lost 6,000 MWs or 20% of its generating fleet including the 2470 MW Cumberland coal fired station. What was truly surprising is that TVA officials cited a maximum system demand was almost 34,000 MWs versus about 24,000 MWs for a typical late December day. The resulting rolling blackouts throughout the TVA system lasted for two days. The generating station outages in Duke Power’s system resulted in power blackouts for half a million customers in the Carolinas beginning on Christmas eve. At least unlike ERCOT, with its minimal transmission ties to neighboring grids, TVA and Duke were able to import considerable amounts of power short term from both the MISO and PJM system operators. Even in NYC we received a request for conservation efforts from Con Ed.
Increasing weather or climate instability is taking its toll on our electric infrastructure. At one level it is becoming more difficult to plan for necessary, extended power plant maintenance outages when electrical demand unexpectedly spikes “out of season”. And this is certainly not the utility’s fault but it is becoming their problem. The challenge as we see it for utilities going forward is even more basic. The consumer’s demand for and reliance on electricity is growing significantly due to an electrification trend. But this is occurring precisely at the moment when reliability is increasingly challenged by extreme weather events like polar vortices. The easy or at least lower cost response is to shed load by getting customers to quickly conserve energy at critical times. This is called demand side management. And we expect to see more of it.
The more difficult response involves rethinking the provision of electrical service in a way that maximizes reliability and not simply cost. Locating power production and storage facilities closer to the customer, or even inside the customer premises itself, may vastly improve reliability. However this also involves reversing a century-old utility mindset of lower costs through centralization and scale. There is also a potentially franchise-threatening problem of stranded assets. New distributed forms of power generation could potentially render a significant portion of the legacy utility asset structure as obsolete or economically irrelevant. Legacy utilities are experiencing spiking demand, a consumer desiring improved reliability, but retaining a commitment to existing modes of production that are increasingly problematic. We hate the overused term “disruption”. But if ever there was an industry ripe for disruption this is it.
By Leonard Hyman and William Tilles for Oilprice.com
More Top Reads From Oilprice.com:
- Oil Prices Plunge Below $80 As Near-Term Demand Worries Grow
- The Oil Market Crisis Sparked By Russia’s Invasion Is Nearing Its End
- Russian Crude Oil Exports Plummeted At The End Of 2022