Big news came from the Point Thomson Unit (PTU) today. Exxon has entered a Heads of Agreement with Qilak Energy to sell the long-stranded natural gas from the technically challenging reservoir via direct exports.
While it is still far too early to say for sure what all this means, I’m sure the question on everyone’s mind is “what’s in it for me?” To answer that question, I was able to get enough details from project representatives to piece together a skeleton of a model.
Here’s what I can share so far.
The idea is to build a floating LNG facility a few miles north of the Point Thomson Unit. Natural gas would be transported via a subsea pipeline to the facility, which would then liquify the natural gas and store it until it is loaded on to tankers.
The tankers (which would be contracted) are double-acting ships that can break the ice in one direction and navigate open water in the other. Several of these ships are already being built for Russia. This first of this new class of ship began operation just last year. The LNG would most likely be delivered to a power generation plant in Asia.
In order to sell PTU natural gas, Exxon would need to expand its facilities at Point Thomson to process out the condensate, water, carbon dioxide, and other impurities before delivering the market quality methane to Qilak (the buyer). The sales price for the gas hasn’t been made public, but around $2-3 per MCF is my best guess.
If all goes according to plan, natural gas delivery would begin in the 2025-2026 timeframe (which aligns with the existing pool rules). To hit that target, a final investment decision (FID) would need to be made by 2022. That’s where the announcement today comes in.
With a gas-sales-agreement in hand (although only a preliminary one), Qilak can now secure financing for the engineering and design work. Over the next two years, the company will firm up all the assumptions that went into the last three years’ efforts.
If it all pencils out, a commitment to spend something like $5 billion will follow. A lump-sum, turn-key contract would then be issued to a ship-building company. A few years later, that floating facility would make its way up to the Federal waters just north of Alaska.
Should the company secure additional gas supplies, additional facilities can be added later. This allows the project to start small and grow as needed. As such, the financial risk is far lower than building a $40-$60 billion project, trying to secure buyers for over 3 BCF/day, and rolling the dice on “yet-to-find” gas to make the numbers work.
ot a Pipeline?
This isn’t the first time a direct export idea has been floated for Alaska’s North Slope resources. The concept was thrown around nearly 40 years ago when the first study of moving natural gas from the North Slope was commissioned.
Iterations of the approach tend to reappear every time the newest pipeline plan fails. In the most recent chapter, Mead Treadwell has been pushing for a study of this option. But, backers of the gas pipeline reject the idea of North Slope shipping out-of-hand.
While the current iteration of the Alaska LNG project is moving through the regulatory process, the sheer amount of financing required does not bode well for it ever getting built. Without some very deep pockets supporting the project, it is very difficult to imagine it moving forward.
And now that the China deal is dead, BP is leaving Alaska, the State coffers are running empty, and with Exxon inking this deal, there are not many viable options to securing up to $60 billion for the pipeline project.
That is why this new project is so interesting. Lloyd’s Energy, the parent company of Qilak, would reportedly use the natural gas purchased from Exxon to generate energy at one of its own power plants. The vertical integration of the company would greatly simplify the supply chain and could be executed at a much smaller scale than the pipeline concept.
As a result, far less financing is required, fewer parties need to agree on difficult terms, and the challenge of trying to align Point Thomson and Prudhoe Bay owners is abated.
Further, moving Prudhoe Bay natural gas via a smaller scale pipeline for Alaskans is still viable. And, with Hilcorp soon owning resources on both ends of such a pipe, logistics get more manageable.
The combination of direct exports for Point Thomson and an in-state pipeline for Prudhoe Bay requires far less funding, reduces liquid loss in the reservoir, gets natural gas to Alaskans, and preserves North Slope natural gas access for large scale heavy oil production.
What Would This Mean for Alaska?
Objections to this announcement from Exxon and Qilak are predictable. Opponents will point to the lack of access, reduced job creation, and higher risk than a pipeline. However, it doesn’t make a lot of sense to sit at the car dealer refusing to buy a used car because you really want the fancy new one you can’t afford.
Comparing this direct export project to a large scale pipeline is probably a false choice. While a pipeline would be better in many respects, history has proven that waiting for it to be built is like playing the lottery. The odds are long.
And, we should not miss out on the good in pursuit of the perfect. The correct comparison is more likely between building this floating facility and chasing a pipedream. And from that perspective, there’s a lot of good that may result.
In reality, this announcement doesn’t kill the Alaska LNG pipeline. But, it may pull the plug on its life-support. So let’s grieve that loss and move on.
First, construction of the Point Thomson gas expansion would create a few hundred jobs during construction and up to 200 permanent jobs during operations. If Qilak opens a headquarters in Alaska, it’s likely to add a few dozen more.
Of course, the big prize from a gas pipeline has always been the delivery of natural gas to Alaskans. The cheaper energy alternative to diesel fuel would cut the cost of home heating in half within the interior. Power generation from natural gas could reduce the carbon dioxide output from coal and naphtha plants, maybe even at a lower cost. And the energy source flowing past resource deposits could unlock them for development.
Alas, those are all desirable outcomes that a direct export facility cannot provide on its own. Additionally, the LNG tankers cannot stop in Alaska to offload at coastal communities due to the restrictions of the Jones Act (there are no US dual-use LNG tankers). So, we will have to look for new ways to solve those problems.
Perhaps that means using some of the revenues from natural gas sales to support improved power (and heat?) cost equalization efforts. Maybe summer loading by US-flagged ships could bring the commodity to the ports around the state. And perhaps LNG trucking to the Interior could be expanded. Or, maybe that ASAP pipeline needs to be reassessed.
The bottom line is that the impacts on Alaska’s economy are not nearly as lucrative when comparing the direct exports to a large scale natural gas pipeline. But, there are positive aspects that are more likely to materialize.
Probably the biggest question on everyone’s mind is “how much money would we get?” The answer to that question comes in five forms.
- The State of Alaska would get royalties from natural gas sales.
- The working interest owners would pay production taxes on natural gas sales.
- Exporting natural gas from Point Thomson would result in increased oil production (generating additional tax and royalty revenue).
- In-state facilities to support the project would owe property taxes.
- Company profits would be subject to corporate income taxes.
Again, I don’t have sufficient detail (or resources) to put an exact number on any of this. But, I can get us in the right ballpark with some back-of-the-envelope calculations. If someone wants to provide some funding, I can put a finer point on this. But, for now, here’s a rough estimate:
According to my notes, project representatives pegged the direct export project at a rate equiv
Natural gas production tends to stay flat for a long time, so these royalties would likely be fairly stable for 20 years or more before beginning to decline. Of course, there’s a lot of assumptions built in there.
But, assuming that number is close to correct, the next question is what the sales price will be. It’s likely that Qilak will pay something greater than $1 per MCF for market-ready natural gas (otherwise it would not be worth the cost of gas expansion facilities). And, I would be surprised if that number is greater than $4 per MCF (otherwise other supplies would be cheaper). So, we have a reasonable band of value.
Let’s assume that the State gets the same price (I won’t get into the complications of this assumption here). This suggests that
Gas Production Tax
AS 43.55.011(e)(3)(B) is the tax law that would apply to natural gas production. The rate is a gross tax of 13%.
Given the assumptions made above, Point Thomson natural gas exports would generate roughly $25 to $100 million per year in
Increased Oil Royalties
Right now, Point Thomson Unit (PTU) natural gas is brought to the surface, is decompressed until the condensate (very light hydrocarbons found in certain high-pressure natural gas fields) falls out, and then the gas is compressed again to be re-injected into the reservoir.
That condensate is shipped over to Prudhoe Bay and mixed into the oil stream as it flows down TAPS. This is a very expensive and challenging process that has run into several complications since it began in 2016.
By shipping the methane off of the North Slope, rather than re-injecting it into the reservoir, the volume of natural gas that can be produced increases. With that additional gas comes more condensate.
At the target rate of natural gas production, the amount of condensate recovery would rise to about 33,000 barrels per day (12 million barrels per year). Compared to the 1,446,724 barrels of condensate produced last year, the result would be over 10 million barrels of additional oil production per year (declining gradually as the reservoir pressure drops, and then sharply when a threshold pressure is reached).
The combination of additional royalty barrels and lower transportation costs would result in roughly $80 million of increased oil royalty payments to the State each year ($20 million of which would go to the Permanent Fund).
Increased Oil Taxes
In addition, the increase in oil production would generate additional production tax revenue. However, the cost of development and operations would be tax-deductible (potentially from production at other fields). This makes the math a little too complicated to do in this high-level analysis.
However, we can get a ballpark estimate by assuming the minimum tax rate applies. That would generate about $20 million per year in additional oil taxes.
The new facilities at Point Thomson to support gas exports would create an
We do know that the Initial Production System cost was about $4 billion. If we assume the expansion project would cost half as much, the property tax liability would be in the $40 million per year ballpark.
Of that, the North Slope Borough would receive $36 million and the State would get the other $4 million.
Corporate Income Tax
This last component is tricky. There are three corporations potentially involved in the deal, but it’s only clear that Exxon would have a corporate tax liability. Hilcorp is currently structured as an LLC and therefore does not fall under the state tax law. Who knows if that will still be the case when natural gas exports would begin?
But, we do know that Exxon pays state corporate income tax. And its share of the sales would be taxable. However, we don’t really know what the operational costs would be. So, there is a big question mark on this number.
But, in the spirit of making an educated guess, I would put the corporate income tax increase between $5 and $30 million per year.
Is This For Real?
Look. We’ve been talking about natural gas exports from the North Slope for nearly 40 years. There have been numerous false starts, dashed hopes, and crushed dreams. So, I’m not going to get too excited about yet another project until I see purchase orders.
But, I will say this. I have very little faith in finding funding for a $60 billion project. I have some hope in a more manageable $5 billion one. And, with technological improvements over the years, a successful pilot project on the water, retreating sea ice, and a motivated seller, it makes me wonder.
Call me cautiously optimistic.
Adding it all together, here’s what I come up with as a total shot in the dark just to get us grounded in reality:
|Annual State Revenue (Millions)||Low||High|
|Increases Oil Royalties||$40||$100|
|Increased Oil Taxes||$0||$40|
|Corporate Income Taxes||$5||$30|
Of course, I don’t have nearly enough detail to tell you how confident I am in these numbers. As more information surfaces, we can adjust our expectations.
The bottom line is this project is not going to solve all our fiscal problems (if it happens at all) and it’s not “better” than a large scale LNG pipeline. But, it is more likely to happen and would certainly help our finances.
If we are starting to feel like the large-scale gas pipeline is just a mirage, maybe this di