Pricing ANS: Part 1 – Physical Market Dynamics

After all the craziness of negative prices last month, a reader asked if I would write an article explaining how pricing Alaska’s crude oil works. That seems like a good idea, although I can’t do it in one digestible piece. So, the plan is to write a three-part series that can act as an educational tool for anyone interested.

We need to start with the fundamentals of supply and demand in the physical market. Then, we can talk about futures contracts and options. Finally, we can talk about how the futures and physical markets meet – and how they intersect with our state laws. Only then can we fully understand pricing ANS.

It all starts with production

Like any free market, ANS prices are ultimately determined by supply and demand. With oil, supply comes from extracting the crude from the ground, then processing out the water, gas, and impurities. It’s a capital intensive process. However, Alaska’s oil fields are conventional reservoirs. That just means that it costs a whole lot to get started, but then the oil flows for a long time. Of course, keeping a mature elephant field flowing has its own costs and challenges.

Here is the history of oil production from the North Slope:

Production Distribution

The anchor field for Alaska’s North Slope is Prudhoe Bay. It was one of the largest fields ever found in the world, and it has been flowing for more than 40 years. Over 13 billion barrels have come out of the field (including the satellite pools surrounding the main pool). BP has been operating Prudhoe for decades now, but they only own 26% of the leases – which will transfer to Hilcorp in a few months. ExxonMobil and ConocoPhillips each own 36% of the lease interests, with the remaining ownership belonging to Chevron.

The Kuparuk River Field is also substantial. It came online in 1982 and has produced nearly 3 billion barrels. It still contributes over 100,000 barrels per day to the system. ConocoPhillips is the operator of the field. After an asset swap with BP a few years ago, it now holds 92% of the working interest. Exxon has about 5% and Chevron holds the rest.

And then there’s the Colville River field on the western edge of the Central North Slope. It started production in 2001 and has pumped about 500 million barrels of oil. That’s basically all Conoco now (after buying out Anadarko several years ago), with less that 1% spread across some minority interest. Another 8 fields produce oil from state lands, and there is one producing unit in the National Petroleum Reserve – Alaska (NPRA). Several other exciting discoveries have been announced, but aren’t producing quite yet.

All told, here is how the production breaks down by company (after BP/Hilcorp deal closes):

On to the Midstream

The production companies need to move their oil from the North Slope to the market. That transportation system is called the midstream.

Pipelines

A system of gathering lines bring produced fluid to processing facilities on the North Slope. For the most part, each field has its own facility. Then, market-ready crude comes out of the processing facilities and moves through a network of feeder pipelines. Each pipeline charges a tariff to cover the cost of moving the oil over to Prudhoe Bay. On average, these feeder pipelines cost $0.60 per barrel to operate, although tariffs range from $0.25 to nearly $20 per barrel.

From there, the oil enters the 800-mile Trans-Alaska Pipeline System (TAPS). Contrary to popular belief, the pipeline is always full of roughly 9.1 million barrels of oil all the time. Putting a barrel in at one end effectively forces one out the other. It’s more accurate to say the pipeline flows at a quarter speed rather than saying it’s a quarter full. At peak production, it took about four and a half days for a barrel of oil to flow from end to end. Today, that journey takes about two and a half weeks.

TAPS is an expensive operation to run. It costs hundreds of millions of dollars to pay the employees and contractors that keep the system running and secure. Another $160 million per year goes to state and local governments for property tax. All of these costs get spread over the barrels flowing through the system (called a tariff), for an average cost of about $5.50 per barrel.

TAPS is owned and operated by the Alyeska Pipeline Service Company. In turn, Alyeska is owned by:

Note: The ownership of each company is through a subsidiary. For Hilcorp, when it takes over, the name of the sub is Harvest Alaska.

While the North Slope production companies own TAPS, there are two things to keep in mind. First, the ownership in the pipeline is not aligned with the volume the companies produce. Second, the asset is regulated by FERC and the RCA. So, it’s not like the companies are shipping their oil for free or shifting a bunch of profit to the midstream. The tariffs are regulated cost recovery with a little bit of an allowable return on capital.

Tankers

Once the oil gets to the end of the 800-mile journey, it gets put into storage at Valdez. There are 14 storage tanks (the other 4 are not in service), each capable of holding about a half-million barrels of oil – for a total storage capacity just over 7 million barrels.

Oil gets pumped from these storage tanks onto very large crude carriers (VLCC). On average, it takes 22 hours from the time a tanker docks to the time it’s ready to leave. The terminal in Valdez can accommodate two large tankers at a time (the other two berths are out of service).

ConocoPhillips and BP own subsidiary tanker companies to move the oil from Valdez to the US West Coast (and occasionally Hawaii or Asia). Exxon recently sold its two tankers, but maintains a long-term contract for them.

There are 11 tankers that frequent Valdez, each capable of making two round trips per month. Companies could contract with other tanker companies, but this fleet is dedicated to Alaska shipments on long-term contracts of Affreightment (COA). Finding tankers to move oil out of Valdez should not be a problem.

Tanker Name	Owner	Capacity
Alaska Legend	OSG (BP > Hilcorp)	1.3 million
Alaska Explorer	OSG (BP > Hilcorp)	1.3 million
Alaska Frontier	BP – retained	1.3 million
Alaska Navigator	OSG (BP > Hilcorp)	1.3 million
Polar Endeavor	Polar Tankers (ConocoPhillips)	1 million
Polar Resolution	Polar Tankers (ConocoPhillips)	1 million
Polar Adventure	Polar Tankers (ConocoPhillips)	1 million
Polar Enterprise	Polar Tankers (ConocoPhillips)	1 million
Polar Discovery	Polar Tankers (ConocoPhillips)	1 million
Washington	Crowley Alaska Tankers (Exxon)	0.76 million
California	Crowley Alaska Tankers (Exxon)	0.76 million

At current production levels, ConocoPhillips fills a tanker a week, Hilcorp will fill one per 10 days, and Exxon fills one every 8 days. If Chevron contracted a tanker, it would require about 2 pickups per year. ENI would need 7, and all the rest of the oil from the North Slope would need 3 tankers per year. It’s more likely that this oil gets shipped on those 11 tankers mentioned above.

The average cost of shipping oil from Valdez to the West Coast is about $3.50 per barrel. That pays for the fuel, labor, and overhead required to operate, load, and unload a very large crude carrier.

Side note: Not all of Alaska’s oil leaves the state. We have 3 refineries here in the state (plus two topping plants on the North Slope) that take a portion of the ANS crude for domestic supply.

Down to the Downstream

On the other side of the market are the buyers that create demand for the oil. Ultimately, that’s you and me. We purchase motor gasoline for our cars, airplane tickets, plastic, rubber, and all sorts of petroleum-based products (that also need to be transported).

But, before we get to those finished products, the crude oil needs to be refined. Therefore, refineries create the demand for crude oil, but end-users determine that demand through their desire for refined products.

The market for Alaska’s oil lives on the West Coast of the United States. Alaska has 3 refineries (Kenai, Valdez, and North Pole) that meet the majority of in-state needs. Outside of Alaska, there are basically three refining centers (Anacortes, San Francisco, and Long Beach) that satisfy the needs of Washington, Oregon, California, Arizona, and Nevada. All together, there are 5 Washington State and 15 California refineries:

Refinery Name	Owner	State	Capacity
Ferndale	Phillips 66	WA	100,000
Tacoma	US Oil & Refining Co.	WA	40,700
Puget Sound	Royal Dutch Shell plc	WA	145,000
Anacortes	Marathon	WA	120,000
Cherry Point	BP	WA	225,000
Los Angeles	Phillips 66	CA	139,000
Los Angeles	Marathon	CA	103,800
Golden Eagle	Marathon	CA	166,000
El Segundo	Chevron Corporation	CA	276,000
Martinez	Marathon	CA	156,400
Torrance	PBF Energy	CA	149,500
Benicia	Valero Energy Corporation	CA	132,000
Richmond	Chevron Corporation	CA	245,271
Carson	Marathon	CA	240,000
San Francisco	Phillips 66	CA	120,200
Bakersfield	Kern Oil & Refining Co.	CA	26,000
Bakersfield	San Joaquin Refining	CA	15,000
Santa Maria	Greka Energy	CA	9,500
South Gate	Lunday-Thagard Co. (LTR)	CA	8,500
Wilmington	Valero Energy Corporation	CA	84,300

Other than the in-state use, Alaska’s oil primarily lands in BP, Marathon, and Phillips 66 owned refineries. Most of these deliveries stem from long-term contracts between the producers and the refining companies. There is no spot market for Alaska’s oil.

The West Coast refinery capacity is a maximum of almost 3 million barrels per day. Of which, they normally run at about 2.5 million BOPD. The next figure shows the amount of inputs, reported weekly. Notice the significant drop in April 2020, which is the result of the coronavirus lock-down. That 65% drop in refining is the reason the supply chain got backed up – leaving tankers lined up, forcing prorations, and pushing down on prices.

While Alaska’s oil was once the primary supplier to the market, declining production from Alaska and California has pushed these buyers to find new sources. Since there is no pipeline crossing the Rocky Mountains, most of this demand must be met by importing it from other countries. However, note that the total supply from Alaska and California doesn’t meet even the depressed demand we see today. Given the nature of the supply chain, it is more likely that refineries cut back on imported cargos (purchased as needed) than Alaska supply (purchased on long-term contract).

Here is approximately where refineries purchased their stock last year:

Wrap-Up

The physical market for Alaska’s crude is North Slope production as the supply and West Coast refineries as the demand. While Alaska once contributed a significant share of the supply to that market, it now meets only about a fifth of the refinery needs. The nature of this market make it unlikely that Alaska’s supply would shutdown for logistical reason. But, Alaska is far less important to the market than in the past. Those long-term contracts still compete with international cargos. That means that economics still play a role in production decisions.

In the 1980s and 1990s, Alaska’s oil supply chain was vertically integrated. Supermajor oil companies owned the lease rights, pipelines, tankers, and refineries. In 2020 and beyond, that dynamic has completely changed. While producers still control the midstream assets – which reduces transportation costs and ensures deliverability – the buyers of our oil are owned by separated refining companies purchasing oil from around the world.

The BP/Hilcorp deal will complete this transition. Once it closes, no major North Slope producer will also own a West Coast refinery to accept their production. This new dynamic is important in how we price our oil. But, we will get to that. First, we need to develop an understanding of how futures market work.