Learning the right lessons from the Texas crisis
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Why did 4.5 million Texans lose power in freezing temperatures caused by Winter Storm Uri in February? It is a question that is of urgent importance to Texas, so it can learn how to prevent another catastrophe. At least 210 people died during the blackouts, of causes including hypothermia and carbon monoxide poisoning. But it is also highly relevant for the rest of the world. Questions over how far wind and solar power contributed to the disaster are increasingly pressing as the share of variable renewables on the grid rises around the world.
To be clear, there is no real doubt about what caused the Texas power crisis. The single largest factor was a massive failure of gas-fired generation, caused by a combination of freezing problems in critical components and a shortfall in gas supply. That was the conclusion of the recent report on the crisis from the staff of the Federal Energy Regulatory Commission, echoing similar analysis from Wood Mackenzie analysts in April. On Ferc’s calculations, gas-fired plants accounted for 55% of the capacity that experienced unplanned outages and reductions in output. Another 22% was wind power, mostly because of turbine blades icing up, and 18% coal, again because of frozen equipment.
But although those facts are straightforward, their implications are more complex. Although the central issue in the crisis was gas-fired power, not wind power, the blackouts do raise important questions about investment, innovation and electricity market design, as the share of variable renewable generation on the grid increases.
In Texas, the argument over the causes of the disaster rages on. In an editorial over the weekend, the Houston Chronicle called for the resignations of Wayne Christian, chairman of the Texas Railroad Commission, the oil and gas regulator, and his fellow commissioner Christi Craddick, arguing that they had “misled Texans about the causes of the deadly blackouts” by trying to pin the blame on renewable energy.
At a meeting of the RRC this week, Christian spoke up in defence of the gas industry. “While no form of energy performed perfectly during Winter Storm Uri, the insistence that natural gas producers are the primary culprit of the February blackouts is pure hyperbole,” he said. His argument against renewables was not so much that wind and solar had failed in the freezing temperatures, but that subsidies for wind and solar had stifled investment in gas-fired generation. “If you add unreliable wind and solar generation and subtract reliable natural gas generation, that equals a less reliable electric grid. Until we fix this fuzzy math, we’re simply putting a band-aid on the problem,” he said.
Ferc’s assessment was that the most important issue was ensuring that power plants of all types could function in cold weather. The staff report made 28 recommendations, including requiring generators to identify cold-weather-critical components, and implementing freeze protection measures. The staff noted that “protecting just four types of power plant components from icing and freezing could have reduced outages by 67% in the ERCOT region.”
The Texas Public Utility Commission, the state’s electricity regulator, in October adopted a new rule to compel companies to comply with winter weather readiness recommendations. However, Texas suffered a similar power crisis in cold weather in 2011, which also led to a series of Ferc recommendations for generators to improve weatherproofing. The effectiveness of those previous recommendations can be judged from the fact that 81% of freeze-related outages at power plants occurred at temperatures above their stated ambient design temperature. Texans must hope that the latest round of weatherproofing improvements is more effective.
Some of the Ferc recommendations do not come into effect until the winter of 2023-24, and there has already been a warning that the Texas grid is vulnerable to another bout of extreme cold. The North American Electric Reliability Corporation warned in its Winter Reliability Assessment for 2021-22 that Texas was one of the power markets where “peak demand or generator outages that exceed forecasts — at levels that have been experienced in previous winter events — can be expected to cause energy emergencies.” It also highlighted the risk that “disruptions to pipeline natural gas supplies and natural gas production sites… can have the potential to affect power system reliability in winter.”
Meanwhile, the longer-term significance of the Texas crisis is more directly connected to renewable energy. The worst of the problems hit during an extended “wind drought”, with low wind speeds and power output across a vast area of the US, covering the ERCOT, MISO, PJM and SPP regions for 12 days. That is a period much longer than can be managed by most standard demand response programmes, or lithium ion battery storage systems that have durations typically lasting up to four hours. As the share of wind power on the grid rises, and the shares of coal and gas decline, managing the grid to maintain electricity supplies through these wind droughts is going to become increasingly important. In a net-zero emissions power system, some mix of technologies including long-duration storage, nuclear, fossil fuel plants with carbon capture, and hydrogen will have to be available to provide firm power to back up variable renewable output.
“There is increasingly going to be an incredibly high value in having firm dispatchable generation with low emissions,” says Ryan Sweezey, Wood Mackenzie’s research manager for power and renewables. Ensuring that those technologies are available is going to require progress on several fronts. Most are not yet in large-scale commercial deployment. New small modular reactors, for example, look promising, but the first such plants in the US are scheduled to come online in 2028-30. The energy provisions in the recently passed US infrastructure bill, targeted on helping new nuclear, carbon capture and hydrogen, reflected the fact that those technologies still need substantial government support to scale up.
Electricity markets may also have to be redesigned to encourage large-scale deployment of those technologies. Texas has a particular issue in that it has an "energy-only market", in which generators are paid only for the power they produce. Unlike in some other markets in the US, they are not rewarded directly for holding spare capacity available to be called on when needed. Instead, wholesale power prices, which were capped at $9,000 per megawatt hour, were supposed to provide an incentive for generators to sell into the market when needed.
The February crisis, when prices were close to or at the cap for several days, but supplies remained short, exposed the limitations of this model. The Texas Public Utility Commission this week voted to lower that price cap to $5,000 per megawatt hour, which seemed like an acknowledgement that that even higher prices had not been doing the job they were supposed to do.
“You don’t necessarily get additional supply when the price is at the cap,” Sweezey says. “And it doesn’t provide an adequate incentive for investment. Nobody is going to invest, and banks aren’t going to finance projects, just on the chance that there might be very high prices in a crisis. To encourage investment in firm capacity, you need a market structure that creates incentives for it, whether through capacity payments or some other mechanism."
The story of the Texas power crisis encapsulates the central challenge of the transition to lower-carbon energy. Companies and regulators need to manage the transition to new energy sources in the medium to long term, while ensuring that the old sources can still provide reliable supplies in the short term. There can be a conflict between the two goals: the Texas PUC has been looking at ideas for improving the resilience of the grid, some of which could hurt the state’s renewables industry. These issues are never easy to manage. But the right decisions are going to be even harder to reach without a clear understanding of the facts.
OPEC+ sticks to its plan to increase supply
The oil market had been on a wild ride in the days leading up to the online meeting of the OPEC+ countries this week. The US last week moved to release oil from strategic reserves, with some support from other countries including China, because of concerns that gasoline prices were a burden on American consumers. Then three days later the World Health Organization announced that a recently identified variant of the Covid-19 virus, named Omicron, was a “variant of concern” that appeared to present an increased risk of reinfection.
The Omicron news sent crude prices tumbling, with Brent dropping from about $82 a barrel at the start of last week to below $70 at one point on the Friday. Since July, the OPEC+ countries have been sticking to a strategy of raising their agreed production limit by 400,000 barrels a day each month. But before ministers logged in for their regular monthly meetings this week, there was speculation that they might abandon that plan. Some reports suggested that the ministers might want to offset the extra barrels that would come on to the market as a result of the US-led reserves release.
As it turned out, those fears were misplaced. After the OPEC+ ministers’ video conference, it was announced that they had agreed to reconfirm the strategy adopted in July, and would raise production by 400,000 b/d in January as planned. Ann-Louise Hittle, vice-president of Macro Oils at Wood Mackenzie said: “In a highly uncertain situation, the best option is to stick with the plan. That is exactly what OPEC+ has done today.”
The Biden administration, which since the summer had been haranguing the OPEC+ countries to raise production more quickly, welcomed the news. Jen Psaki, White House spokesperson, said: "We appreciate the close coordination over the recent weeks with our partner Saudi Arabia, the UAE and other OPEC+ producers to help address price pressures.”
However, there was a significant detail in the announcement: the ministerial meeting did not formally end, but remains in session “pending further developments of the pandemic”. The idea, the OPEC statement said, is to allow ministers to “continue to monitor the market closely and make immediate adjustments if required.” The next meeting is scheduled for January 4, but this move means that new decisions on production limits could be made at any time before then, if necessary. “They can react swiftly when we start to get a better sense of the scale of the impact that the Omicron variant of Covid-19 could have on the global economy and demand,” Hittle said.
The net result was to leave oil slightly lower for the week at about $71 a barrel for Brent crude and $68 for WTI. US average retail gasoline prices dropped this week and are likely to continue to fall, to the great relief of the Biden administration. Meanwhile, in another sign that inflationary pressures on energy prices are easing, US benchmark Henry Hub gas front month futures have dropped back from over $6 per million British Thermal Units in late October to about $4.15/mmBTU on Friday.
The two largest US oil and gas groups, ExxonMobil and Chevron, announced corporate plans this week. ExxonMobil said it planned to keep capital investment steady in a range of $20 billion - $25 billion a year until 2027 at least, “with flexibility to adjust to adverse market conditions or changes in policy and technology for low-emissions projects”. Darren Woods, chief executive, said that improvements in the business, including enhanced efficiency, portfolio improvements and the use of technology, meant that the company expects “to double earnings and cash flow potential by 2027 versus 2019 on a flat price basis.” ExxonMobil has also developed more aggressive plans for further cuts in its Scope 1 and 2 greenhouse gas emissions, from its own operations and its purchased energy, by 2030.
Chevron, meanwhile, announced a planned capital and exploratory spending programme of $15 billion next year, at the low end of its $15 billion - $17 billion guidance range. Mike Wirth, chief executive, said: “The 2022 capital budget reflects Chevron’s enduring commitment to capital discipline… We’re sizing our capital program at a level consistent with plans to sustain and grow the company as the global economy continues to recover.”
Royal Dutch Shell has decided not to take part in developing the Cambo oilfield west of Shetland, in which it has a 30% stake. Wood Mackenzie estimates the field holds 156 million barrels of oil and 53 billion cubic feet of gas. Shell said in a statement that it had "concluded the economic case for investment in this project is not strong enough at this time, as well as having the potential for delays". The project had been a focus for protests from climate campaigners, who argued that developing new resources in the North Sea was incompatible with the UK’s goal of achieving net zero greenhouse gas emissions by 2050.
Norway’s government will not grant any new oil exploration licences in new or little-explored areas in 2022. However, it has continued to leave open the option of granting leases for already-developed regions, including the North Sea. The decision was seen as a compromise, attempting to balance the county’s climate goals against the economic importance of oil and gas.
BP has unveiled a plan for a large-scale green hydrogen plant on Teesside in northeast England. It aims to take FID in 2023 and start production by 2025. The initial phase would use 60 megawatts of power, potentially scaling up to 500MW by 2030. The project, called HyGreen Teesside, is intended to develop the area as the UK’s first major hydrogen transport hub, “leading the way for large-scale decarbonisation of heavy transport, airports, ports and rail,” BP said.
Offshore wind power is becoming a contentious issue in France’s elections.
And finally: another sale of strategic commodity reserves. The Quebec Maple Syrup Producers organisation, which controls the world’s only strategic maple syrup reserve, announced that it planned to release about half of its 100 million pound stockpile, to keep the market well supplied and stabilise prices. Demand for maple syrup has been rising, hitting a new record high last year, but production collapsed in 2021. Quebec’s harvest dropped 24% to 133 million pounds, hit by unusually warm temperatures in April that brought the sap season to an abrupt halt. Serge Beaulieu, president of the QMSP, said there was no cause for concern about future supplies. “Our organisation has the tools in place to meet demand,” he said. “The Strategic Reserve has the capacity to respond to the industry's needs for conventional maple syrup in the short and medium terms.” The industry is stepping up production capacity, adding a further 7 million sap taps in Quebec over the next three years, a 14% increase, to reach a total of 57 million.
I have to admit the story surprised me with just how dominant Quebec is in the maple syrup industry: it accounts for about 72% of total worldwide production. Calling Quebec “the Saudi Arabia of maple syrup” doesn’t really do it justice.
Quote of the week
“Given mutations that may confer immune escape potential and possibly transmissibility advantage, the likelihood of potential further spread of Omicron at the global level is high. Depending on these characteristics, there could be future surges of COVID-19, which could have severe consequences, depending on a number of factors including where surges may take place.” — A World Health Organisation technical paper on the Omicron variant of the Covid-19 virus explained the reasons why the overall global risk it presented was assessed as “very high”. The WHO underlined, however, that many key features of the new variant were not well understood. The main uncertainties include how transmissible the variant is; how well vaccines protect against infection, transmission, and disease; and whether Omicron presents differently from other variants that are currently more widespread.
Chart of the week
This comes from Wood Mackenzie’s European solar PV market outlook 2021, showing the expected strong growth of solar power over the next three decades. We expect sustained additions of new capacity, so that by 2050 solar PV is providing about 20% of Europe’s electricity. In the leading markets, Spain and Italy, solar’s share is likely to rise to about 35%, while in Germany it will be about 25%. The ambitious decarbonisation goals set by the EU and European governments will drive strong solar deployment, while costs are expected to continue to decline. Average levelised costs of electricity for tracking PV systems are expected to fall as low as €24.6/MWh in 2030. Daniel Tipping, Wood Mackenzie’s European solar analyst, writes: “Bifacial panels and larger wafer sizes are expected to push down costs and make solar more competitive versus other technologies.”