Slope production forecast coming up short
Alaska is facing a projected $1.6 billion budget deficit next year, but the financial picture for the current fiscal year could get a little worse if North Slope oil production figures don’t increase soon.
North Slope crude oil and natural gas liquids production for fiscal year 2019 averaged 496,197 barrels per day through February, according to the state Department of Revenue. That is 5.8 percent below the average daily production forecast produced by the Department of Natural Resources of 526,800 barrels for all of fiscal 2019, which began last July 1.
The delta between actual and forecasted production is notable because overall 2019 North Slope production was supposed to increase from the final fiscal 2018 average of 521,398 barrels per day. Instead, the 496,197 barrels per day of production since the start of July is also well below the year-to-date average for 2018, which was 516,870 barrels per day at the end of February 2018.
Overall, the state was expected to draw roughly $700 million from savings when the fiscal 2019 budget was passed last June.
Actual North Slope production in February averaged 517,227 barrels per day, while state officials calculated that production for the month would have to be about 582,000 barrels per day to stay on pace for the 526,800 barrels per day forecast for the year.
It’s worth noting that the monthly calculation is largely based on historical production averages prorated by month — production peaks in winter months —as opposed to strictly being based on year-to-year situations, according to state officials.
Oil taxes and royalties were expected to generate more than $2.2 billion in unrestricted revenue for the State of Alaska in the current fiscal year, according to the annual Revenue Sources Book the Department of Revenue publishes each December. The revenue projection is based on the combination of the department’s oil price forecast for the year as well as DNR’s production estimate.
The price side of the equation is currently a slight but dwindling positive for Alaska’s finances, as higher than expected prices through late summer and fall have the average price for a barrel of Alaska North Slope crude at $69.85 per barrel, or about 2.8 percent more than the $67.96 per barrel forecast. However, the average realized price has gradually been falling since Alaska oil prices fell back to sub-$70 per barrel range in November.
Another roughly 11,000 barrels per day of oil is produced from Cook Inlet oil fields, but Cook Inlet oil provides minimal production tax revenue and the volume doesn’t compare with North Slope production.
Division of Oil and Gas Commercial Analyst Pascal Umekwe said the Revenue Department’s annual spring update to the fall forecast will likely show “a slight downward revision” for the production forecast based on the numbers from the first seven months of the fiscal year. The spring forecast is usually published in mid-March.
State officials last year attributed actual production not meeting the fall forecast to unusually warm North Slope temperatures, which degrades the efficiency of production facilities designed to run most efficiently at very cold temperatures.
The natural gas compressors that help reinject gas at many wells to enhance oil production are not as effective at warmer ambient temperatures — which is the primary reason for less summer production each year — and can lead producing companies to focus on extracting oil from wells that have a lower gas-to-oil ratio when things warm up.
Last winter North Slope temperatures were about 14 degrees above the long-term average.
This year, February temperatures at Utqiagvik averaged 4.5 degrees Fahrenheit, or 18.7 degrees above normal. The high in Utqiagvik hit 34 degrees on Feb. 28. January temperatures were still high but more in line with historical norms at 4.6 degrees above normal, according to the National Weather Service.
Umekwe emphasized that production from the large, mature North Slope fields typically declines each year unless companies put significant work into turning it around. That work can come in the form of improving production facilities, “workovers” to existing wells or drilling new wells. The timing of that work can also impact oil production.
He also noted that state analysts who prepare the production forecast are typically able to have just one or two meetings with company representatives to gather information prior to releasing the forecast each fall. Subsequent information for the spring update comes from publicly available data.
Changes to companies’ maintenance and drilling schedules after their meetings with state officials could then play into the variance between forecasted and actual production volumes, according to Umekwe.
“It is the scheduling of work, in terms of turnaround activities that were done in the summer and how production responds after that work is done. That would be a key factor as well as how temperatures in a given February compare with temperatures in a previous February,” he said.
“Work being done at a production facility that dips down production for a longer period of time would be very different than work done in a similar period the previous year that wasn’t that extensive — so both the intensity of the work and the schedule of the work. When I talk about intensity, it’s intensity of the impact of that work on production.”
Industry representatives noted that Eni, which operates the small Nikaitchuq field, had problems with its production facilities in late fall, which slowed production from the field. An Eni spokesman did not respond to questions in time for this story.