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The North Slope: A geologist’s dream, an investor’s nightmare
Kristen Nelson Petroleum News Editor-in-Chief
Why are there so few companies exploring Alaska’s North Slope, a basin with recognized world-class hydrocarbon potential? The answer is cost: “The North Slope basin is the most expensive onshore basin in the world. … And it may even be one of the most expensive basins in the world, including offshore basins,” Mike Dunn told the Anchorage chapter of the International Association for Energy Economics Jan. 20.
Dunn, vice president of New Tech Engineering, an Anchorage, Alaska-based consulting firm, was talking about a problem he confronted as a consultant working with companies interested in coming to Alaska: “The minimum economic size on the North Slope: why is it so large and what can we do to reduce it?”
Minimum economic size is a question addressed by oil companies of all sizes: It’s not, can I find oil in this basin, it’s if I find oil can I make money producing it?
Over the last five or 10 years, Dunn said, most companies have adopted a methodology that lets them look at a combination of factors — geologic risk, reserve size, development costs and cash flow models — and then determine the minimum size field needed to make money. The result, minimum economic size, can be compared with opportunities in basins worldwide.
Dunn said when he did the analysis for independents interested in the North Slope “sticker shock” was the typical reaction. Sticker shock Dunn said prospects 50 miles from North Slope infrastructure would have to be about 360 million barrels to break even, and when he explains that to companies looking at Alaska, the reaction is not positive. Companies who can find 100 million barrels in the Gulf of Mexico in 8,000 feet of water and make money aren’t likely to be interested in a basin where they would have to find 360 million barrels just to break even.
Some companies do look harder, he said, and question whether you really have to spend a billion dollars for a facility and gravel and infield pipelines for 120,000 barrels a day. They start looking at what has been done in Canada or in Russia and thinking it can be done cheaper on the North Slope.
Rigs are another issue. Dunn said companies compare $110,000 a day “as the spread day-rate on a drilling rig in a land-rig operation” on the North Slope with $100,000 a day for a jackup rig in the Gulf of Mexico with boat and helicopter support: another unfavorable comparison.
There is another wrinkle to this.
If you have to find 360 million barrels to break even, that’s about a 1 in 20 chance of making a commercial discovery, Dunn said, based on how the U.S. Geological Survey estimates the numbers and sizes of fields in basins. There are just limited numbers of fields that large. Why the cost? There are legitimate reasons for high costs on the North Slope, he said. It’s a long way from markets, it’s a long way from major population centers and the climate is very harsh. But Dunn said he believes some of the reasons for high costs are based on the culture which grew up on the North Slope when oil was discovered — billions of barrels of oil in a single field.
Prudhoe Bay, he said was “the best thing and the worst thing to happen to the North Slope.”
It established infrastructure, and only a field of that size could have justified the facilities at Prudhoe and the trans-Alaska pipeline.
But it also created a culture where people said ‘money is no object, this is Prudhoe Bay.’
There are things you could afford to do at Prudhoe Bay, because of its size, that you can’t afford to do at the types of fields being looked at for development now, Dunn said.
Can any of that be changed? Is Alaska that different Dunn said another part of the “cultural” side of the cost equation is the notion that Alaska is different, i.e. just more expensive.
That was true 30 years ago. “Alaska was different,” he said. The North Slope was the first Arctic basin developed and a lot of technology had to be developed specifically for Prudhoe Bay.
But today there are Arctic developments in both Canada and Russia, and Alaska is not as different as it once was.
Dunn said he’s done a lot of benchmarking of Alaska costs to costs in Canada. “It is surprising how much less expensive those developments are” in Canada, he said. And part of the reason for the difference is that the Canadian Arctic industry started with small gas fields and “they’ve just had to figure out cheaper ways to develop these fields.” Opportunities to reduce costs? What opportunities exist to reduce costs?
Dunn said an Energy Information Administration study comparing drilling costs in Alaska with those in the Lower 48 found it would cost about $2.5-$3 million to drill a 10,000 foot well on the North Slope, compared with about $750,000 to drill a 10,000 foot well in south Texas. And, Dunn said, drilling on the North Slope is generally faster.
So, he asked, how much of the cost difference is due to the harsh climate and the distance from infrastructure? And how much is due to the way things are done. “I don’t know exactly,” Dunn said, “but I do think there’s some opportunity to reduce the costs on the North Slope.”
Typically independents follow majors into basins, he said, and independents “might take a more hands-on approach” to cost reduction and work the facilities costs a little harder and work the drilling costs a little harder.
“Independents have traditionally been better at cost reduction and cost control,” Dunn said, it’s one of their “core competencies” because they are developing smaller fields than those developed by the majors, and have to figure out ways to reduce costs — or they go out of business. What if costs could be reduced? Dunn said that if you plug cost reductions into the formulas used to calculate minimum economic size the changes can be dramatic.
The trans-Alaska oil pipeline tariff, for instance. If capital costs came out when that tariff has a re-opener in 2009, and the tariff dropped by $1.25 a barrel that takes about 60 million barrels out of the 360 million minimum economic field size. Dunn used a one-sixth royalty rate, and if you drop that to one-eighth, that takes the minimum barrel size down to about 270 million barrels.
And what if there were some way to reduce the marine transportation cost, now driven up by the requirement to use Jones Act tankers? What if moving ANS crude to the West Coast was comparable to moving oil from Venezuela to the Gulf of Mexico, a reduction of 50 cents a barrel?
The construction cost of facilities is a very large item.
Dunn said he looked at tax rolls and found that Alpine and Northstar were considerably more expensive than Badami when Badami costs were factored to handle more barrels, using a scaling factor used by chemical engineers. If facilities could be built on a Badami model, that would cut the cost substantially, and bring the minimum field size down to a little more than 150 million barrels.
And what if there was a better rig, or a better way to drill North Slope wells, and that cost could come down to $80,000 a day, and then, given that independents are known for cutting costs, on top of all of this the independent finds a way to cut another 20 percent? Stars in alignment Dunn acknowledged that in his example — which cuts the minimum economic size down to about 100 million barrels — that “all the stars are lined up.” This is, he said, the best you could expect.
“You’ve gotten some tariff reduction, marine costs are a little lower, you’ve got a one-eighth royalty, you’ve captured all of the lessons learned at Badami, you’ve worked the drilling rig and the drilling support real hard — and then you’ve got another 20 percent cost reduction on top of that.”
Is it just impossible?
Dunn cited an example from the Norwegian sector of the North Sea, where development also started with a large expensive field — Ekofisk — and where, in the early 1990s, the Norwegian government began hearing that it was too expensive to operate, and companies said they would look elsewhere to invest.
Government officials, operators, service companies and drilling contractors got together and looked at the costs, and they took 70 percent out of the capital cost between 1993 and 1998. Dunn said he didn’t know how differences in such things as water depth and field size were handled in this comparison, “but the point is that they thought there was some potential for cost reduction and they worked it and sure enough, they delivered on it.” What if the minimum was 100 million barrels? So what if 100 million barrels was the economic minimum, how does that change things?
Dunn said it changes the chance for success from 1 in 20 at the 360 million barrel size to 1 in 7 because there is a lot more potential for finding 100 million barrel fields than there is for finding 360 million barrel fields. And when more fields are developed, more infrastructure is built — making even smaller accumulations economic.
And what if there is no way to reduce costs?
Well, geologists love the North Slope basin — they know there is a lot of potential — but investors hate it, he said. “It’s not about the resource, it’s about reserves — and we need economic reserves. The minimum economic size has got to be reduced, or this basin will die,” Dunn said. “This basin is not competitive with other basins.”
And it is the costs that define minimum economic size: development cost, operating cost, transportation cost, royalty cost, tax cost, he said. If those costs can be reduced, if the minimum economic size were 100 million barrels, the value of the basin increases because there are more fields you can develop, and as infrastructure develops, smaller fields become economic.
“What’s the value of that in terms of billions of billions of dollars to the state’s economy, to the oil companies, if you can affect the minimum size?” Dunn asked.
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