Now that we’ve discussed the physical market and the futures market, we can finally turn to understanding how Alaska’s oil get’s priced. It boils down to a combination of factors that deal with each of these markets and their dynamics.
Alaska North Slope (ANS) crude doesn’t have a spot market (there just aren’t enough barrels) and it doesn’t trade on a commodity exchange (for the same reason). Every barrel of ANS oil either gets sold on forward contracts between a producer and a refinery, or it gets shipped on a vertically integrated supply chain (where the producer, shipper, and refiner are the same company).
That means that there is no “market price’ for ANS. There are only contracted prices, which aren’t usually public information. Understanding how those contracts work ties this whole story together.
Buyer and Seller Opportunity Costs
To begin, consider the situation from each side of the physical market.
The primary buyers for a North Slope producer’s oil are the refineries on the West Coast. If you’re trying to sell your oil, you might want to make some calls and see which refinery will give you the best price. There aren’t a whole lot of buyers, so it wouldn’t take long to develop a relationship between the marketing teams.
You’d also want to look around the world for other buyers. Maybe you can find a refinery in China, Korea, or elsewhere that is willing to pay enough extra money to cover the higher transportation costs. The opportunity to sell to different buyers around the world prevents West Coast prices from getting too far disconnected from other areas. Of course, locating a buyer, negotiating a contract, and shipping the oil takes time. So, there can be short-term anomalies, but they shouldn’t last very long.
Thinking about the situation from the buyer’s perspective is a little more complicated for two reasons: composition and transportation.
All crude oil is not alike. Barrels produced from each reservoir have a different mix of hydrocarbon chains. Some have longer chains, making it “heavy.” Others have mostly short chains making it “light.” Lighter crude oil produces more jet fuel and gasoline, while heavy crudes generate more of the heavier petroleum products.
Under normal conditions, refineries are willing to pay more for a lighter crude. But, if the demand for motor gasoline or jet fuel production goes down, while the demand for heavier products doesn’t, the refinery might pay more for a heavier crude blend (and less for a lighter blend) than normal.
Each barrel of crude oil also comes with some sulfur mixed in. Higher sulfur content crude are called “sour” and lower sulfur crudes are “sweet.” Sulfur is bad, as it emits sulfur dioxide when it burns. You may remember hearing about “acid rain” once upon a time. That was from burning fuels with sulfur in them.
Since then, the EPA and other international organizations have required more and more sulfur to be removed from fuels. The latest change to this requirement took effect in January 2020, which now requires an almost complete removal of sulfur. Removing sulfur is an expensive process, meaning that sour crudes come with higher refining costs – which in turn makes them less valuable.
In case you’re wondering, ANS crude blend is a medium-sour crude.
|ANS||32 degrees API||0.96%|
|WTI||42 degrees API||<0.45%|
|Brent||38 degrees API||0.45%|
Crude oil gets produced all over the world. Getting those various crudes to a specific refinery on the West Coast comes with different costs.
From the North Slope, the oil must travel down an 800-mile pipeline, and then make a week long journey over the open ocean. Oil from Saudi Arabia is just a longer trip on a tanker, without the pipeline costs. Oil from Canada, Mexico, and California only needs a pipeline. From North Dakota, oil gets loaded on a train car to cross the Rocky Mountains. And oil from Texas might be sent on a tanker through the Panama Canal.
Now we can get to the heart of the issue. Who decides how much a barrel of Alaska North Slope (ANS) oil is worth? The answer is…assessment companies.
The forward contracts on the West Coast don’t usually have a firm dollar value attached. Instead, they avoid that negotiation point by allowing a third-party to decide how much the oil is worth. That’s especially true for longer-term contracts.
Two companies offer this service — Platts and Argus. One reporting company (Reuters) includes an ANS price in their platform.
Assessment companies publish an assessed value for ANS at the end of each trading day. To determine what they think is a fair price for Alaska’s oil, they look at what refineries are paying for different blends from different location. Then they make an adjustment for Alaska’s oil composition and transportation costs. The most weight is given to actual contract prices, but they also look at refinery offer prices to track how the relative value of ANS is changing.
Basically, the assessors are looking for any new contracts to update their understanding of the current market. They rely on buyers and sellers to tell them about the contract terms. Each time the assessors hear about a new contract, they update their model.
For example, if a refinery in Long Beach enters a contract on May 18th for June delivery, the assessment companies reflect that price in their updated assessment. If the contract price for a crude very similar to ANS is NYMEX WTI plus $2, then the assessors assume the going rate for ANS on the open market would be something close to that amount.
If another contract is for a heavier sour crude gets pegged at ICE Brent minus $3, the assessors plug that contract price and specifications into the computer model too. The model makes an adjustment for quality and location, and spits out an adjusted value. Then, it takes some form of weighted average between the different contracts. The actual models are proprietary, so it’s hard to say exactly how they do this.
The assessors only include contracts for delivery during the next calendar month – that were signed between 10 and 60 days before the end of the assessment month. They don’t include any distressed sales or one-off contracts that are unusual. And they don’t include any sales between a parent company and a subsidiary refinery. Nor do they include long-term contracts, as the terms don’t reflect current market conditions.
Platts only looks at contracts at one delivery location – Long Beach, California. It’s unclear from their methodology if Argus does the same. Both companies only count contracts for tanker deliveries of at least 300,000 barrels.
Contracts only stay in the assessment model if they are for the front-month delivery. The included contracts roll out of the model on the 20th of each month. For example, assessments for today’s (May 18th) ANS price are using June delivery contracts. That will switch to July delivery later this week (after the 20th of May).
Keep in mind that the number of contracts on the West Coast (and especially Long Beach alone) is a small number. At most, it’s one or two contracts per week. Therefore, every new agreement has an outsized impact on the assessed value of ANS. That can cause large swings in the ANS differentials as contracts are added and removed from the model. And, those impacts can persist for several weeks.
The daily price changes that we see in ANS are mostly a reflection of the changing values between marker crudes sold on the exchanges. When a new contract is heard, it changes where ANS falls between those differentials.
Note on Reuters
Reuters isn’t an assessment company – it’s a news outlet. They have journalists, not assessors. Consequently, Reuters uses a different method than the assessment companies to determine the prices they publish in their platform.
I reached out to Reuters to try to figure out their methodology, since it isn’t published. They told me that their reported price is simply the most recently heard contract – reported as a differential to WTI. That’s a different method than the assessors use, but it’s unclear how much different the results are.
Pricing Alaska’s Royalty Oil
When oil first started flowing down TAPS, the physical market was a lot different that it is today. Most of the oil production moved along a vertically integrated supply chain. The producer, shipper, and refinery were all the same company. How can you determine the market value of something that is never sold?
This challenge in determining the value of Alaska’s royalty oil resulted in lengthy litigation. The discussion that resulted from it would fill a large book. But, for our purposes today, it’s sufficient to say that the State of Alaska and the producers each settled on terms outside of a court decision. Basically, for all leases entered into before about 1980, royalty values are determined by these assessment companies.
Leases signed after 1980 are called “new form” leases. The royalties from those contracts are determine by the actual contract terms. In reality, those contracts often use the assessed price of ANS, typically naming which company’s assessment to use. But, if there were some other price agreement in the contract, our royalty gets the better terms.
However, only about 5% of our royalty barrels get priced like that. For the other 95%, we tell the producers to give us barrels of oil rather than money. Then, we turn around and sell those barrel to Alaska refineries at a price we negotiated. In almost all cases, we end up getting more money for our royalties this way — because we don’t have to pay for the marine shipping costs.
Pricing Alaska’s Oil Taxes
For severance tax purpose, the “prevailing value” of oil is the average of the assessed value by Platts and the reported value by Reuters. The Department of Revenue publishes this value on their website each day. But, the prevailing value only applies to oil that isn’t sold via a contract. For instance, when BP ships oil to its Cherry Point refinery, it’s assigned the prevailing value. On the other hand, when BP ships a cargo to China, the value is defined by the contract terms.
After the BP-Hilcorp deal closes, there won’t be any non-arms-length sales left. Therefore, the published prevailing value that we eagerly watch for every day won’t truly matter anymore. It will be the actual contracts between producers and refineries that determine the taxable value.
Of course, those contracts often use the assessed value to determine the price. So, at least the prevailing value will give us a sense of what we might be getting in taxes – without subscribing to Platts, Argus, or Reuters.
While many of us like to watch the price of oil move around throughout the day, it’s important to know what that really means. What we call the “current” price is actually the current value of a 1-month futures contract.
ANS doesn’t get traded on futures contracts. Instead, the ANS price is an assessment, which is updated once a day to reflect how ANS would hypothetically have traded on the exchange. It’s determined by the changing prices of other crudes, and any new contracts for next-month delivery.
However, daily ANS prices are actually meaningless on their own. Oil never sells at a daily price, only futures contracts do. Royalty calculations use the monthly average price to determine how much leaseholders owe in royalty payments. Our tax law uses the annual average price to levy severance taxes.
It’s also important to remember that the oil price is only one part of the equation. The published price is an estimate of what the refinery pays for delivered crude oil. But, the producer must located, develop, produce, process, and ship that oil to the refinery. Those steps cost a tremendous amount of time and money to complete.
Multiplying the delivered price of oil by the number of produced barrels tells you about as much about profits as counting up the hours that kids are in school tells you about a teacher’s pay. It’s a completely misleading number that fails to grasp the reality of how much goes on behind the scenes.
Still, it’s worth understanding what the numbers mean. I hope I’ve provided some insight and education on the matter. Feel free to reach out if you have further questions or see anything that needs corrected.