Alaska North Slope 10-Year Oil Production Forecast

I gave you my projections of how oil production on the North Slope will look next fiscal year.

But, the question most people really have is “what happens after that?” We’ve all heard about some major projects that are coming. So, what will that mean for the amount of oil flowing down the pipeline? (a follow-up question of what this all means for the treasury is also important and is coming in a week or two).

The answer is a little challenging. The reason is that there are a lot of unknowns about these future projects.

But, I can certainly take a crack at it. The proponents have all talked about their projects in public. And I can use those comments to put together a comprehensive picture.

All those pieces fit together somehow, and I’m a decent puzzler. So, let the game begin.

Base Production from Legacy Fields

Before we start layering on the new projects, it’s good to understand the status quo. So, here is how I see the next 10-years from the existing fields.

You’ll notice that Prudhoe Bay continues its long, slow decline, but remains the major source of production throughout the period. This can only happen by continuing to find new pockets of oil in the field. I believe the major seismic shoot over the entire Prudhoe field next year will give them what they need to accomplish this.

Kuparuk declines a little faster than Prudhoe Bay, but it’s likely that Conoco will beat this forecast. With expanded efforts in West Sak, and a few prospects that aren’t included here (Cairn is one), I can imagine a lot of scenarios with a much lower decline rate. I haven’t included those scenarios here because there is not enough information available yet.

Alpine gets a bump in 2021-2022, which helps offset some of the decline in the other fields. That bump is coming from the CD5 second expansion, and from the activation of the extended reach drilling rig that will be delivered in early 2020. I have that rig drilling targets in Fiord West then Putu after delivery.

Milne Point gets a near term bump from Moose Pad, but then the field goes back into its decline pattern. However, once we get more information about the polymer flooding  pilot project going on at J pad right now, this might get adjusted.

The other fields just continue their current trends until we hear otherwise*.

*Note: PTU could show an increase in production of up to 50,000 barrels per day if they elect to move the natural gas out of the unit. There is a lot of uncertainty about when and if that may happen. While the dust settles, I am not making a guess on how this plays out. 

Greater Moose’s Tooth

So far, we’ve only heard about the GMT1 and GMT2 projects in the Greater Moose’s Tooth Unit.

GMT1 started production on October 5th, 2018.  GMT2 received a Record of Decision from the Bureau of Land Management in October. The project was promptly sanctioned by ConocoPhillips.

Each of these projects is expected to produce around 30,000 barrels per day, at peak production (GMT1 a little less, GMT2 a little more).


In order to estimate how that actually plays out, I used a project management approach. Each stage gate of the project has an end-to-beginning dependency. So, drilling at GMT2 requires the pad construction to be complete, and the rig to be available. If one of those things get delayed, the drilling gets delayed too.

I also created a rig schedule for Doyon 19 (the rig I assume will drill GMT2). The rig will finish drilling GMT1, then will move to CD5 while GMT2 is constructed, then will move to GMT2 (and then on to Willow). I assume it will drill the number of wells Conoco has stated in their EIS for each project.

To estimate production, I used Alpine wells as analogs for GMT1. Given the statements of well counts, peak rate, and total recovery at GMT2, the wells must be less productive to make the numbers work. So, I used Schrader Bluff wells as analogs for GMT2.

Production Profile

When I put all this together, the GMT Unit production profile looks like this. Notice that you can’t just add the 30,000 barrels from each pool together. You have to account for the timing of the production and the impacts of natural decline on GMT1 by the time GMT2 comes online.

Of course, things don’t always go as planned. And sometimes the wells turn out better than expected. So, when I account for schedule slippage and rate uncertainly, I get this range of possible futures.

I should note that there are a few more prospects in the GMT Unit. However, there isn’t enough information about them quite yet to draw up a profile. That’s why we need to keep updating our forecast as new information becomes available.


Just a few miles west of the GMT projects is the Willow prospect. That oil pool is located inside the Bear’s Tooth Unit.

The BLM is currently assessing alternatives to the proposed project as part of the EIS process. Within the next few months, they should release a final EIS. That document then must go through a public comment period and get feedback from cooperating agencies.

After something like a year of bureaucratic process, they will very likely release a Record of Decision that gives the project a green light (possibly with some conditions that must be met).

Once that ROD is in hand, Conoco can review the conditions and run some final numbers on the economics of the project. At that point they will do some actual engineering and design work for the facilities, roads, pipelines, and port. That process will probably take another year.

Then, if everything looks good and the project appears that it will be sufficiently profitable, they will make a final investment decision.


That’s when development finally starts. They will contract someone to fabricate the facilities, put in orders for pipe, and hire contractors to start building the gravel pads, roads, bridges, and a landing zone for the facilities to be delivered. This is a two to three year process.

Once the road and first pad are installed, they will move a drill rig on-site, start installing the facilities, and put in the delivery pipeline. This is another year-long process.

As you can see, we are still a long way from first oil at Willow. Using the same project management approach as before, I drew up a timeline for Willow. To me, it looks like oil should start flowing in FY25 (barring any delays).

Production Profile

Given the project description, and the public statements I’ve heard about production rates and total recovery, this is the profile that seems to fit all those conditions.

Again, delays can happen and the actual productivity of the wells is uncertain. So, here is the range of expected production.

Note that a very fast schedule gets to first oil in FY24. But, the more likely timeline doesn’t have production flowing until FY26. Oh, and It will take a few years of drilling before they reach that 100,000 barrel number you’ve heard about.

West Willow

There is another discovery to the west of Willow. I’ve seen it on the maps that ConocoPhillips puts in presentations. However, I don’t know much more than that. I have heard they will be testing the reservoir again this winter. Maybe we will know more soon. But for now, it’s not in the forecast.


The Liberty Unit holds over a hundred million barrels of oil that have been known since 1982. The problem is getting to it.

The reservoir is 5 miles offshore, making it a challenge to develop. A few attempts have been made, but were scratched before the project was sanctioned. The first time was in the early 2000’s, when an oil price crash drained the capital budgets of all major oil companies. The second attempt faltered in 2012, when BP wasn’t ready to take chances in the offshore right after Macondo.

Now, Hilcorp is in the driver’s seat and the project has been approved by the Bureau of Ocean Energy Management. With the last two years of rising oil prices, both Hilcorp and BP should have the financial strength to move forward.

Right now, the working interest owners (Hilcorp and BP) are running the economics. We should know by June if they are going to move forward. At that point, they would start ordering components and preparing to construct a gravel island.

The island would be constructed during the winter, starting in late 2019 or early 2020. Once the island is built, it will take another year to install the facilities and subsea pipeline. Oil could start flowing as early as three years from now.

In order to make all the comments made in public fit together, this is what a production profile at Liberty would look like.

And, again, there is uncertainty. The biggest question (once the project is sanctioned) will be if production starts toward the beginning or the end of FY22, which largely relies on if they can finish the island construction in two winters.

Here is how the range of potential production plays out.


Probably the most exciting discovery in Alaska since Alpine, is the Nanushuk formation. And, the most interesting portion of that formation occurs in what is called the Pikka Unit, nestled between Alpine and Kuparuk.

This project recently received it’s final EIS and is currently under review by the Corps of Engineers. A Record of Decision is expected within the next 6 months. Once approved, Oil Search expects to get moving right away. They are planning 3 drill sites, with a total of over 140 wells.

After reading their project description, and reviewing the statements they’ve made in public, I generated a project management schedule that fits all those pieces.

Here’s what I came up with.

And in terms of the uncertainty, here is the range that makes sense.

Other Nanushuk

Oil Search and ConocoPhillips have some additional interesting discoveries within the Nanushuk trend. They go by names like Horseshoe, Stoney Hill, and Narwhal.

Those prospects are currently being evaluated, but have not quite reached the point where I have enough pieces of information to build a project.

So, keep an eye out for when the results from this winter’s exploration season hit the press. If we hear enough to understand the project, I’ll add them to the forecast.


The Mustang field has been a problem child for the last 5 years. The project was right on the verge of getting done in 2014 when the oil price crashed and investment money dried up.

AIDEA stepped in and helped out, but they just kept running into problems getting all the investors lined up.

Right now, the project is again moving forward. So, I think it will start producing next year. It’s not a huge field (maybe 15,000 barrels a day), but every barrel counts.

I have included this project in the forecast with a lot of timing uncertainty.


Caelus also has project that is shovel ready, but having a hard time getting financed. It’s onshore in the southern edge of the Oooguruk Unit.

Until this project gets sanctioned, it doesn’t belong in the forecast. But, it is a source of potential future increases. Hopefully one that gets funding soon.

Beyond 10-Years

There is a little bit of a paradox when you peer beyond 10 years into the future.

On one hand, TAPS could be nearing the end of its life. On the other hand, TAPS may be too small to handle all the new production that is seeking investment.

Without the addition of Willow and Pikka, TAPS would be very close to being technically and economically challenged to continue production from the North Slope in the 2030’s.

But, with these projects extending the life of the line long enough to bring ANWR and other major projects to market, there is a chance we will have to deal with too much oil.

Smith Bay

Caelus made headlines a few years ago, when they announced a multi-billion barrel discovery in the State waters north of the NPR-A. This is a very exciting potential project.

To get oil flowing, they need to submit a project description to the Bureau of Ocean Energy Management (or maybe BLM, depending on who has jurisdiction). That will initiate the Environmental Impact Statement (EIS) process.

Once that application is submitted, it will take at least 2 years to get approval (usually more). But, before they can submit that, they need to be able to define what the project will look like. And that requires drilling more wells to understand the reservoir.

Caelus did not drill any more appraisal wells last winter and are not scheduled to drill any this year.

Assuming they did go drill next winter, they would spend a year preparing the application. Add another 2 years for approval, and another year for engineering. Then tack on 3 years to build the facilities and another year to install them.

Best case scenario, they might be able to get production online in 8 years. But, that would be an amazing accomplishment. It is far more likely that this project doesn’t start delivery until the 2030’s.

If it does get to development, this field could produce over 200,000 barrels of oil per day.


According to a presentation I recently saw from USGS, there are very likely to be even more Nanushuk discoveries in the future. Given the source rock, the trapping mechanisms, the timing, the depth, and the migration paths, the USGS thinks something like 8 billion barrels of additional oil is out there somewhere.

One prospect sits west of Stoney Hill in the NPR-A. Many others are possible anywhere between Kuparuk and Smith Bay. Of course, we can’t predict if or when they will be found. So, it doesn’t make sense to include these hypothetical prospects in the forecast.

But, we shouldn’t be surprised if more good news keeps coming.


When the US Senate included some language in the budget that opened the 1002 area of the Arctic National Wildlife Refuge to oil development, it made headlines.

This is something Alaska has been trying to accomplish for decades. But, before we get too excited, remember that there is a long road between now and oil flowing from ANWR.

First, they need to hold a lease sale (which is scheduled for 2021). Then, the winners of the leases have to find oil. Once they make a discovery, they will need to complete the rigorous permitting process that typically takes several years.

Finally, once they have approval, it will take at least 5 more years to get oil flowing. Oh, and every phase along the way requires a public process that is sure to be litigated.

In short, ANWR is exciting to think about for the future. But, it’s not going to add production to TAPS until at least a decade from now.

If everything does work out, the 1002 area is believed to be a tremendous source of oil. Early assessments suggest a million barrels per day is not unreasonable. While it’s too early to start counting those chickens, it is exciting.

Other Projects

There are also some other projects that might find there way into future forecasts. Many of them are still in the very early stages of exploration and appraisal. As those prospects become better defined, the forecast will be updated to include them.

This includes finding ways to produce known accumulations like Umiat, Badami, and Placer. As well as early stage exploration, like Nikaitchuq North. And new lease blocks like we have seen Conoco, Oil Search, Caelus, and others pick-up recently.

There are also some speculative and unconventional resources that may contribute to future production. This includes shale and heavy oil, which have the potential to add billions of barrels of oil to future production forecasts.

The producers have been experimenting with various ways to produce heavier oil for many years. The most successful to date is called Cold Heavy Oil Produced with Sand(CHOPS). But that process is very expensive.

Hilcorp’s newest attempt at using polymer flooding looks like it is getting good results at Milne Point. It will be interesting to see if the operators at Kuparuk and Prudhoe Bay start their own pilot projects with this method.

Shale production has its own challenges. But, we do have a few companies trying to figure it out. If they can crack the code, there is something like two billion barrels of potential production available.

Total North Slope Forecasts

When I add up all the production from all these sources, here is what I get.

And, when I run simulations of different futures (that allow for schedule slippage and rate uncertainty) this is the range the model generates.

It is also important to remember that production from different areas have different implications on the State treasury (I’ll put a number to these in the near future).

Production from Federal waters is not taxable, whereas production from Federal land is. And the owner of the oil gets the royalty, which means a lot.

So, here is how the baseline production forecast is separated into those land classifications.

Baseline Forecast (Mode)

If I had to give you a scenario of how much oil was flowing down TAPS for the next 10-years, this is the scenario I would pick.

Remember, there are a lot things that can increase or decrease this view. But for now, here is how it looks:

FY Total TAPS Throughput
2019                 510,297
2020                 517,962
2021                 505,853
2022                 539,134
2023                 562,555
2024                 596,379
2025                 604,970
2026                 640,585
2027                 643,845
2028                 645,613
2029                 632,392
2030                 604,776


In a few weeks, the Department of Revenue will release their own forecast. Those numbers will be based on confidential data, interviews with the producers, and the collaborative efforts of a team of engineers with expensive software programs.

On the other hand, I constructed all these forecasts myself, based on publicly available information, with fairly cheap software. 

I haven’t talked to any of my friends at Revenue or Natural Resources about this forecast, so I have no idea what they will publish.

It will be tempting to think their numbers are “better” than mine. But, I’m curious to see how much different our numbers are from each other. Then, I’ll be even more curious whose numbers turn out to be better once we get the chance to observe the future.



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