Emily Pickrell, UH Energy Scholar
HOUSTON, TEXAS – FEBRUARY 21: Texas flags fly near an electrical substation on February 21, 2021 in … [+]
Failures in Texas’ ability to provide electricity for its 26 million customers who rely on the ERCOT grid one freezing week in February have captured media attention around the world. Debates have sprung up over politics, environmental issues and grid reliability.
Yet another system’s failure contributed greatly to the problem – getting the Texan natural gas to the generation facilities, including that from its Permian Basin shale play. And it failed when residential use of natural gas worked swimmingly, unfettered across the state. At the moment that the Texas grid came close to failing, Texas had at least 300 billion cubic feet (BCF) of natural gas stored.
The failure of the system to make this natural gas accessible to the generation facilities was a key factor in the collapse of the system on Feb. 15.
“We don’t need more natural gas storage,” said Ramanan Krishnamoorti, a petroleum engineering professor at the University of Houston, in response to public discussions of whether Texas needs to expand its natural gas storage as a safeguard. “We need to have natural gas storage that is actually pumpable.”
It has been well reported how natural gas production dropped dramatically the week of Feb. 15. Conditions in the storm – including the freezing of some wellheads and natural gas processing outages – resulted in a 30% production decrease from 24 BCF per day to less than 17 BCF in the Texas region, according to Argus Media. It averaged at 13.8 BCF per day that week, falling as long as 11 BCF at one point, according to the U.S. Energy Information Administration.
A big reason for this is the growing role of the Permian Basin is providing the type of natural gas Texas is using. Permian natural gas is known as “associated gas”, because it is a by-product of the much more lucrative shale oil being produced.
And while this gas is interchangeable with deliverable gas as a fuel stock, its production process is different, according to Christine Ehlig-Economides, a petroleum engineering professor at the University of Houston.
Deliverable natural gas comes from a pressurized gas reservoir, meaning that it can flow on its own, and does not have to be compressed, which requires electricity.
Associated gas, on the other hand, “comes to the surface at a low pressure, and now you need to compress it to gas plants, where you take out more valuable components, like propane and butane and ethane,” Ehlig-Economides said. “It comes because we are pumping oil out and that requires electricity. So with no power or winterization of the pumping process, you are not getting this gas out.”
The failure of these shale producers to move the associated gas made the gas storage facilities a natural backstop.
Under normal conditions, the Texas electricity grid relies less on storage capacity as an available backup than other states that are heavy users of natural gas, such as California, because it is normally much easier to extract the gas directly.
Nevertheless, gas suppliers had an advance warning from the Texas Railroad Commission, or TRRC, which issued an emergency order on Feb. 12, giving priority to natural gas generators in Texas for residential power.
However, the pipeline companies that largely control the storage sites began withdrawing a relatively much smaller amount of gas from storage than the combined drop in production and spike in demand, according to data from the U.S. Energy Information Administration, or EIA. Based on data available from the EIA and TRRC, Texas storage was pumping out about 5 billion cubic feet per day on average in the weeks prior to the snow. The week of the storm they were pumping out an average of 9 billion cubic feet per day.
That is far short of the maximum 17.5 BCF per day that is available from storage facilities according to the data from TRRC on their public website.
Natural Gas Supply & Demand before and during Winter Storm Uri
During this period, the low temperatures, and continued operations of export of natural gas to Mexico and LNG at least during the initial periods of the freeze, kept demand for natural gas at high levels.
Natural gas experts say that the shortfall in the amount of natural gas that came out of storage was a result of limitations in the system.
Texas had sufficient natural gas in storage to cover the shortfall at the beginning of the week of Feb. 15, according to data from the TRRC. Yet there are further limitations in what the system can extract beyond what is reported to the TRRC, said Ben Chu, a natural gas analyst at Wood MacKenzie.
“The three facilities were drawing the maximum they could as early as the 10th of February,” Chu said, referring to storage sites that Wood MacKenzie tracks as indicators of sector behavior.
The maximum extraction rate is estimated to be 17.5 BCF per day by the TRRC, but the real rate depends on the level of pressure in the reservoirs, which tends to fall off as it depletes.
For example, one of the largest natural gas storage facilities, Tres Palacios Storage in Matagorda, is reported by the TRRC as having 2.5 BCF per day of withdrawable gas.
Wood Mackenzie says the real amount that can be withdrawn is much lower.
“That data is questionable or debatable,” said Eric Fell, director of North America natural gas at Wood Mackenzie. “Tres Palacios is a big facility – it is hypothetical that it could be that big. What we see in the daily (statistics) is that it has never done more than 800 or 900 million.”
Tres Palacios also went into “force majeure” on Feb. 15, meaning that it had serious performance issues that reduced the amount of natural gas that could be delivered.
The failure of Texas’ biggest salt cavern storage facility at the worst possible time has wrongly been written off as inevitable, Krishnamoorti said.
“The conditions should have been relatively good for Tres Palacios,” Krishnamoorti said. “It’s in one of the warmer parts of the state. And there is a much higher level of being able to pump that gas out in these salt caverns – the heavier hydrocarbons are likely to have settled in the reservoirs, it is naturally pressurized. We ought to have been pumping out more.”
Who got priority for the natural gas that was extracted also made a difference.
Delivery of stored natural gas is also prioritized to those with firm supply contracts, which peaker natural gas generators are not required to hold. This means in effect that peaker plants – the ones the Texas grid was relying on on Feb. 15 – could be last in line behind other natural gas clients. Yet even who got priority is difficult to know, as Texas pipeline companies are not required to publicly disclose this contractual information, unlike pipeline operators under federal jurisdiction.
Many public utilities in other states have natural gas storage facilities specifically dedicated to providing fuel, even in adverse conditions, said John Hilfiker, a senior energy analyst at S&P Global Platts. It is not something that the market system in Texas would necessarily encourage, which instead depends on a thin percentage of excess capacity (known as a reserve margin) to protect its system against a power collapse.
And, as it turns out, this excess capacity relies on the natural gas being readily available as it is produced.
“There is a problem when you rely on production for a majority of your supply and then have one of these freeze off events,” Hilfiker said. “You are at the whim of a producer being able to maintain output.”
The shortages resulted in soaring prices for natural gas: $206 per million British thermal units at the Waha Hub, which is located in the West Texas basin and best represents the price for Permian gas. The previous week, natural gas at the Waha Hub had had an average spot price of $4.54. Prices for natural gas at the Houston Ship Channel were higher than Waha, reaching as much as $400 per million BTU, in spite of being closer to the storage facilities.
This situation certainly has generated no shortage of unhappy customers, as well as an estimated more than $85 billion cost for the state.
The awkward question remains – how much of this was foreseeable for natural gas producers, who own the mineral rights at storage facilities? Could they have more aggressively pumped gas the entire week prior to Feb. 15? Was any behavior influenced by the skyrocketing natural gas prices over that time? How does the market guide behavior under such conditions, when regulations do not govern it?
In 2016, the U.S. Department of Energy issued a report on how to decrease the potential impact of future prolonged disruptions of natural gas infrastructure.
In its report, it discussed the importance of ensuring that a failure to access the needed natural gas does not lead a collapse of the electricity grid.
It’s advice Texas legislators should take to heart, to make sure we are not having the same conversation again a few storms down the road.
Emily Pickrell is a veteran energy reporter, with more than 12 years of experience covering everything from oil fields to industrial water policy to the latest on Mexican climate change laws. Emily has reported on energy issues from around the U.S., Mexico and the United Kingdom. Prior to journalism, Emily worked as a policy analyst for the U.S. Government Accountability Office and as an auditor for the international aid organization, CARE.
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