The Alaska Department of Natural Resources should be done with its production forecast.
Over the next few weeks, The Department of Revenue will insert that forecast into their revenue model and discuss things with treasury, the APFC, and OMB. Ultimately, they will publish the Revenue Sources Book along with the budget in early December.
There is usually a lot of anticipation about what that report will say. It sets the tone for the entire budget debate.
With all the talk of new oil projects and confusion about what they will mean, I thought I would tee up the conversation with a discussion about how I see things going on the North Slope.
Today, I’m only looking at the FY20 production number (the budget year being discussed). Stay tuned for a closer look at where things will go from there (coming next week).
Unit Level Forecasts
One of the unfortunate consequences of having the Department of Revenue put out a forecast, is that they get hamstrung by taxpayer confidentiality rules.
Since the taxpayers send production information with their tax returns, the Department cannot supply much information without being accused of disclosing confidential data.
That is the advantage of having an independent third-party put the numbers together. Since I don’t have access to confidential data, I can’t be accused of disclosing it.
So, here is how I see things going, at a unit level.
Of course, there are risks. Facilities might go offline for part of the year. The new wells being drilled as we speak may turn out to produce higher than expected. Or, they might be total duds. And, there is an outside chance that everything goes perfectly.
All of these factors mean there is uncertainty around the forecast. So don’t misinterpret these numbers as exactly what will happen. These are just the best guess I can make based on the information I have right now. The real numbers are certain to be different, we just won’t know why until the future unfolds.
Prudhoe Bay Unit
The data for FY19 so far show a slight increase in production over the same time period in FY18 at PBU. This really just means that the summer maintenance cycle was not as deep as the year before.
Given the information we have in hand, it looks like FY19 (the current year) production will be about flat from FY18.
But, I expect the FY20 numbers to show a slight decline at Prudhoe Bay. That will be partly due to a more normal maintenance cycle next summer.
Right now, my FY20 projection is for about 266,000 barrels per day.
Prudhoe Bay NGLs
Prior to 2014, there was a “Large Scale Enhanced Oil Recovery” project going on in Kuparuk. Basically, they took Natural Gas Liquids (NGLs) from Prudhoe and pumped them down a well bore into Kuparuk.
Because these NGLs mix with oil (unlike water, which repels it), pumping them into the reservoir “catches” oil that sticks to the rocks. When these NGLs come back to the surface, they bring extra oil with them.
In the summer of 2014, ConocoPhillips decided that they had pumped enough NGLs into Kuparuk. From then on, they expected to produce the needed NGLs for the project as part of their normal production. So, they turned that transportation line into a natural gas pipeline.
This year, ConocoPhillips decided they wanted to resume NGL delivery. The RCA approved that decision and delivery resumed in October 2018.
If we taxed those NGLs at Prudhoe Bay, they would be taxed again when they got re-produced at Kuparuk. So, the Department of Revenue will not count them until they head to Valdez.
To the naked eye, this will look like a production decline of around 12,000 barrels per day. But the AOGCC reports will still show this production.
Kuparuk River Unit
The increased production last year from adding 1H-NEWS wells is clear on the graph. The fourth new well on the 1H pad was completed on September 18th. It is a trilateral well which should add a few thousand barrels of production per day.
Additionally, an expansion of drill site 3R is underway. That expansion will lead to new production wells in the West Sak oil pool at some point in the near future.
These new wells, and the injection of NGLs, will result in increased production. However, it won’t be very noticeable.
Although these projects are adding rate, the field will probably show a small decline. But not as large as it would have without these projects.
On net, I’m expecting to see FY19 finish around 108,000 barrels per day and FY20 to fall slightly to 104,000 BOPD.
It is possible that successful exploration activity this winter (especially at Cairn) will also lead to increased production next year. I just don’t know enough to include it yet.
Colville River Unit
CD-5 breathed new life into the Alpine production facilities back in 2015. The production from that new drill pad kept the CRU above 60,000 barrels per day in FY18.
With the drill rig now over at GMT1, the CRU will see declines in FY19. Right now, it’s looking like the unit will come in around 55,000 barrels per day this year.
And that natural decline will continue in FY20. Although there should not be as large of a summer disruption next summer, I expect to see production come down a bit the rest of the year.
However, I expect Doyon 19 to finish drilling out GMT1 next Fall. With GMT2 still under development at the time, I expect the rig to move back to CRU and drill some targets in the second expansion of CD-5.
Accounting for time to transport and rig-up, we should see a small bump in production from CRU before the end of FY20.
My projection for FY20 at CRU is right around 50,000 barrels per day.
Milne Point Unit
You can see the FY18 actual production numbers came in right around 20,000 barrels per day at Milne Point.
FY19 has already started coming in a little higher than that. And, at some point in the next few months, production from the new drill pad (called “Moose Pad”) will start.
So, FY19 will finish the year a little higher than FY18. And with the drilling of that new pad taking at least a year, FY20 will finish even higher than FY19.
Right now, I have the number set at about 32,000 barrels per day in FY20.
ENI put drilling on hold when oil prices crashed. According to AOGCC records, the last production well completion occurred in October 2015.
Therefore, the existing wells are experiencing natural decline without any new wells replacing that rate.
FY18 saw production of 17,934 barrels per day. The numbers that have come in for FY19 so far have been 14% lower than last year. The field looks to be on pace to produce about 15,000 barrels per day in FY19.
FY20 doesn’t look any better. My current projection is for less than 14,000 barrels per day.
You may have heard of the Nikaitchuq North project. It’s an exploration program in the federal waters north of the Nikaitchuq Unit in the Harrison Bay.
The first exploration well was drilled last winter. It looks like they ran into some problems and weren’t able to flow test it this year.
The second exploration well was scheduled to be drilled in December of this year, which is now likely delayed.
There is no chance Nikaitchuq North will add production before the end of FY20.
The Oooguruk Unit has produced since 2008. The operator was still drilling new wells and fracture stimulating production until 2016.
But since then, no new activity was reported from the unit. So, the field is now in decline. Reported data so far this fiscal year suggests that the field will produce at little less than 11,000 barrels per day in FY19.
Looking forward to FY20, the trend indicates an expected loss of another 1,500 barrels next year.
There is a known hydrocarbon accumulation called “Nuna” in the Torok formation within the Oooguruk Unit. However, Caelus has not been able to sanction that project so far.
If that project does get funded this year, it will still take a few years to get into production. So, for now, I expect to see the unit’s production continue to decline.
Greater Moose’s Tooth Unit
The first field within the Greater Moose’s Tooth Unit (GMT1) started production on October 5th, 2018.
It will take some time for the field to reach peak production, which I have at somewhere around 27,500 barrels per day.
The FY19 production will average about of 11,000 barrels per day (partly because it has three months of zeros).
FY20 will see the rest of the wells come on-line, averaging about 26,000 barrels per day for the year.
North Star Unit
North Star is a field near the end of its economic life. However, Hilcorp has done an admirable job keeping it alive.
Although no new wells were drilled since 2009, they did revive two wells from the dead (NS-13 and NS-15). And stimulation activities have been fruitful in other wells as well.
From the available data, it looks like North Star should produce around 8,000 barrels per day for FY19 and FY20. I don’t know of any efforts to bring new targets online within the next 2 years.
Duck Island Unit
The Duck Island Unit (better known by the name of its major field – Endicott), is another mature field near the end of its life. Hilcorp also picked this asset up from BP to try to squeeze the remaining blood from it.
They’ve done a good job so far, able to keep production fairly flat. The data suggest production will be around 7,000 barrels per day in FY19 and slightly lower in FY20.
There are no plans to drill new wells in this unit.
The Badami field is sort of a boondoggle on the North Slope. It never really lived up to the hype. There’s a lot of oil there, but it’s hard to get.
Production from Badami has been off and on for years, but there hasn’t been a real attempt to develop the technically challenged reservoir in a long time.
Glacier Oil drilled a new well in May of this year; the first since 2012. So, there is some interest around what will happen next. There’s also some new interest in the leases around the unit.
But, for now, I don’t expect more than 2,000 barrels per day out of the field for the next few years. I’ll update this forecast when I hear more details about a plan going forward.
The Point Thomson Unit is producing retrograde condensate (think oil suspended in natural gas due to really high pressure) by cycling high-pressure natural gas through a decompression system.
The project is not economic and the producers are losing money while they do this. The only reason they are producing at all, is because of a settlement agreement that allowed them to keep the leases while they work on building a gas pipeline.
To make matters worse, the compressors are constantly breaking down. The data from July to September of 2018 show an average daily production rate of just 87 barrels per day.
I believe the rates are so low because they are attempting to repair the compressors before winter hits.
The facilities can process 10,000 barrels of oil per day when they are fully functional. Hopefully, they will get everything working correctly and we will see that number.
But, until we see some proof, we shouldn’t hold our breath.
I’m projecting an average of 6,000 barrels per day in FY20 (which assumes some improvement over the current situation).
The Mustang field has been about 6 months from production for the last 5 years. With prices where they are today, and with a little help from the State, it is looking like it might really happen this time.
When production does start, it will add around 10,000 to 15,000 barrels of oil per day to the pipeline.
There was also a plan at one point for temporary production facilities to begin trucking produced oil to a processing facility. That plan called for a start date of October 20th, 2018, and would deliver 6,000 barrels per day.
I reached out to the operator to see if that plan was still on track, but got no response.
For now, I have a risk-weighted production estimate of about 5,000 barrels per day included in my forecast. That production comes online beginning in February 2019 in my model.
Total North Slope
Data so far in FY19 has come in slightly lower than FY18. However, production increases from GMT1 and Moose Pad are expected to lift the winter rate slightly higher than last year, as those projects are drilled out.
The net result is a production number of around 519,000 barrels in FY19 (about even with FY18).
As these projects are completed, and new production wells from CD5X2 are drilled, it is looking like the total production from the North Slope should increase to almost 530,000 barrels in FY20.
Breakdown of Production
Here is how the production breaks down by unit.
However, because some of that production will be used for enhance oil recovery, it is likely that the Department of Revenue will report a decline in FY19.
Additionally, production from the NPR-A is not owned by the State. Therefore, the producers will pay the royalties to ASRC and taxes to the State.
As more oil is produced from non-State lands, this distinction will become increasingly important.
|Total AOGCC Reported||520,161||519,259||529,026|
|NGLs to KRU||–||8,767||11,585|
|DOR Reported Production||520,161||510,491||517,441|
|Federal offshore (nontaxable)||390||423||377|
|Total Taxable Production||519,771||510,068||517,064|
|Non-State Owned Taxable Production||33,836||40,351||52,639|
|Total from State Leases||485,935||469,717||464,425|
As you can see from the above graphic and table, the status of the oil production will influence how we talk about what is happening on the North Slope.
This is a first look at where I see things as of November 2018. Of course, as new information becomes available, this outlook will change.
But, right now I see production increasing next year (FY20). A lot of that increase will come from GMT1, which is not from State leases. So, while total production will rise, production from State leases will fall.
The delivery of NGLs to Kuparuk will also generate confusion. I am sure we will see some people point to DOR reported production to show a decline, while others will point to AOGCC reports to show flat production.
I talked last week about how those GMT1 barrels translate into State dollars. But this issue of different classification of oil is sure to bring confusion to any debate about how the future is shaping up.
I sure hope someone is there to help clear it up.