Cook Inlet Gas: The Cold Day Problem
The cold snap at the end of January brought on a flurry of articles and Legislative presentations related to shortfalls of Cook Inlet Natural Gas. The level of alarm caused me to dig deeper into the problem. There are really two distinct issues related to Cook Inlet Gas Supply:
Cold Day Deliverability: This is the ability of the natural gas infrastructure to deliver enough gas during a cold day in the winter when demand for gas is highest due to high heating needs.
Sufficient Annual Production: The total production of natural gas across the year needs to be sufficient to meet the total need for gas. While we do have a substantial amount of stored natural gas, a deficit in annual production will quickly draw down those natural gas stores.
As I discuss below, the Cold Day Deliverability problem can be solved with substantial certainty and only moderate amounts of money. The much more serious problem is maintaining sufficient annual natural gas production or importation to meet the annual gas demand; I plan to discuss this topic in a future post.
Cold Day Natural Gas Deliverability
On an average day during the year, Cook Inlet natural gas users need about 190 million cubic feet (MMcfd) of gas. However, on the coldest day designed for (a bit colder than January 31 of this year), users would normally demand about 390 million cubic feet of gas, slightly more than double the average day (see Table 4 of the Berkeley Research Group report on Cook Inlet Gas). For about 10 years, gas wells in Cook Inlet have not had the ability to ramp up to this high level of demand, so natural gas storage has been utilized to supplement the production from the gas wells. When the wells are producing more than the need for gas in the summer, gas is stored into underground storage facilities (old natural gas reservoirs). In the winter when demand is higher than production, gas is withdrawn from storage to supplement production from the gas wells.
During the recent cold weather event on January 31, it is important to know that there was plenty of natural gas volume in storage facilities to meet the gas demand. The CINGSA storage facility alone had 6,730 million cubic feet of gas actually in storage, which is sufficient to supply the natural gas production deficit under design day conditions for 33 days. In addition, Hilcorp has substantially more natural gas storage than CINGSA. Although I could not find data on the current volume of gas stored in Hilcorp storage, during mid-February of 2022, Hilcorp had a total of 15,300 million cubic feet in storage (Luke Saugier presentation to House Energy Committee on 2/21/2023). So, we likely had enough gas in storage on January 31 of this year to supply the production deficit for multiple months of design-day cold weather. The problem on January 31 was not a problem of having enough gas in storage.
The ostensible problem on January 31 was the ability to supply natural gas from storage at a fast enough rate. Removing gas from underground storage involves using wells to extract the gas, compressors to provide sufficient flow and dehydrators to remove moisture from the gas. CINGSA, the regulated gas storage facility owned primarily by ENSTAR-related companies, had been experiencing problems with two of its wells. CINGSA was designed to supply 150 MMcfd of deliverability, but because of sand intrusion in two of its wells, CINGSA showed its available deliverability to be only 97 MMcfd on January 31. ENSTAR is the largest user of CINGSA and this loss of deliverability from CINGSA put ENSTAR in a pinch. ENSTAR has firm commitments for substantial deliverability directly from the gas producers, primarily Hilcorp, but not enough to make up for the lost CINGSA production. Railbelt electric utilities helped out by reducing their gas demand through stopping sales of gas electricity to Golden Valley Electric (who replaced the electricity with oil generation) and by ramping up hydroelectric production. Hilcorp came up with additional gas beyond their contractual commitments to ENSTAR. So, heat and power in Southcentral Alaska continued to be delivered.
How close were we to a customer-impacting shortage? This analysis I did looks at the total amount of deliverability in Cook Inlet (including CINGSA at its crippled 97 MMcfd level) and compares it to an estimate of January 31 demand. That analysis shows that supply of deliverability exceeded demand by 24% assuming that all of the non-CINGSA sources of deliverability were fully available and not experiencing problems. My attempts to contact Hilcorp about their actual deliverability on January 31 were not successful. This is an important analysis, similar to comparing available electrical generation capacity against peak electrical demand. We should have better publicly available data on the natural gas peak-day situation.
The analysis I did also estimated the temporary help that Railbelt electric utilities could provide by reducing their demand for gas. A portion of these actions were implemented on January 31, but a number were still available if the situation got worse. Specifically, the Matanuska Electric Association Eklutna Generating station can be switched from natural gas to oil fuel. If that plant were run at full capacity using oil, it would have relieved about 9% of January 31 gas demand. There was the ability to further ramp up hydroelectric production, saving about 4% of gas demand. Importing 30 MW of power from Golden Valley Electric across the Northern Intertie would have relieved another 1.6% of demand. So, those potential contributions are significant and were not needed on January 31.
While the data available to me is not conclusive, let’s assume that we cut it too close on January 31. How can we fix this problem? Again, there is plenty of gas in storage; the problem is getting it out of storage at a higher rate. ENSTAR is undertaking an expansion project at their CINGSA facility that will increase deliverability by 65 MMcfd, which represents 17% of peak design-day needs of Cook Inlet and represents 22% of ENSTAR’s peak needs. So, this is a substantial increase in deliverability. The project also adds 2 BCF of storage volume to the existing 11 BCF storage capacity of CINGSA. This very noticeable improvement in peak day withdrawal capacity comes with a price tag of $72 million. To put $72 million in context, remember that ENSTAR was recently purchased for $800 million. Hilcorp has stated in their presentations to the Legislature that they invest hundreds of million of dollars per year into Cook Inlet gas facilities. The solutions to our annual gas production needs identified in the Berkeley Research Group report vary in capital cost from $570 million to $9 billion. So, I would characterize $72 million as a very moderate investment.
My conclusion is that the cold-day deliverability problem can be solved with near certainty and with a moderate amount of investment. I do wonder why the solution hasn’t come earlier. I had much more concern about this problem when I first read the interview with John Sims, the ENSTAR president, in the Northern Journal and heard Mr. Sims’ presentation to the Legislature. In my opinion, those presentations were more alarming than justified after a deeper dive into the cold-day issue.
In a future post I plan to address the more serious problem of adjusting to dwindling annual production of Cook Inlet natural gas. In my opinion, the solution to that problem will be more wind/solar electrical production, increased energy efficiency, and, unfortunately, importation of Liquid Natural Gas.