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Industry leaders: Alaska could cripple the goose Because of the high cost of doing business in Alaska, the state could jeopardize its supply of golden eggs if it turns to the oil industry to solve its fiscal gap, reducing competitiveness of Alaska projects that would benefit state Kristen Nelson Petroleum News Editor-in-Chief
How do you cheerlead the potential for continued — and even expanded — oil and gas development in Alaska while at the same time trying to persuade the state not to increase taxes, crippling the goose that has been laying golden eggs for all these years?
That was the task tackled by executives of Alaska’s oil and gas companies at the 10th annual Alaska Oil and Gas Association-Anchorage Chamber of Commerce luncheon June 14 in Anchorage.
The approach they took was to temper predictions of what the oil industry in the state could look like in 2014 — they had been asked to make predictions, and to include what might seem farfetched — with admonitions about the high cost of oil and gas exploration and development in Alaska, and the competition their investment proposals face from projects around the world. The Alaska Oil and Gas Association provided summaries of a study ranking total government take, cost per barrel and profitability of oil and gas in Alaska compared with other oil provinces — a 2002 study by consulting firm Wood Mackenzie which found Alaska has higher than average total taxes and royalties and the highest total oil and gas costs, putting it almost at the bottom in terms of profitability.
There were a number of references to the state’s fiscal gap, the spread between income and expenditures, and concern that the state might increase taxation on the oil and gas sector, reducing the competitiveness of Alaska projects.
Oil and gas executives were joined by a top official of the U.S. Department of the Interior and by Alaska Gov. Frank Murkowski, who has called a special session of the Alaska Legislature beginning June 22 to tackle the fiscal gap. The federal perspective Assistant Secretary of the Interior Rebecca Watson offered a federal perspective, noting the importance of energy in the United States economy: with only about 5 percent of the worlds’ population, “we use that energy we consume to create 25 percent of the world’s GDP,” she said.
Watson, responsible for both the Bureau of Land Management and the Minerals Management Service, said: “As I look into my crystal ball for 2014, I see us building on the successful sale we had in the National Petroleum Reserve-Alaska,” and predicted continued lease sales and production from NPR-A Alpine satellites. On the Minerals Management Side, in the outer continental shelf, Watson predicted: “Northstar entering its second decade of production, Liberty oil flowing down the pipeline,” as well as continued exploration and other discoveries moving toward production.
As for gas, Watson said she sees “Interior looking far into the future for methane hydrates, so that these gas resources can be added to the gas flowing” through a gas pipeline, “a pipeline that Interior helped to permit.”
She said that, like President Bush, the Department of the Interior believes “that energy production and environmental protection are not competing priorities. We think they’re dual aspects of a single purpose — and that is to live well and wisely upon the earth.”
So along with increasing oil and gas development in Alaska, she said the future she sees includes “birds continuing to nest, caribou herds migrating freely and the North Slope residents continuing to hunt successfully.” Governor wants state to look at equity position in gas pipeline Alaska Gov. Frank Murkowski said he expects to see a gas pipeline in operation by 2014, expects it will follow the Alaska Highway and connect with the North American gas pipeline grid in Alberta. He said he thinks the potential is “very strong” for spur lines to Valdez and Southcentral, supporting consumers and industrial users.
As for financing, the governor said he thinks “that you will see the state participating in the gas pipeline as an equity owner” of up to 12.5 percent, equal to the state royalty on gas. “It could dramatically increase revenues for the state and I think it’s worth taking a serious look — and my administration’s in the process of doing just that.”
On the oil side, the governor said, companies producing in the state “need to reinvest more of their profits in the state.”
Once the gas pipeline is in operation, the governor said he expects “a significant southward and westward migration on the North Slope over the next decade as explorers reach further inland in search of additional gas.”
He predicted “a major discovery on the Alaska Peninsula,” which he noted is ice-free, and also predicted “a major discovery offshore of ANWR, which will require the Department of Interior to drill ANWR to prove from whose reserves” the oil is being pumped.
“I also predict major discoveries in NPR-A, and then we’ll be looking at boosting the oil flow through Taps, instead of merely holding it steady.” “Farfetched” possibility for much more exploration drilling Ken Sheffield, president of Pioneer Natural Resources Alaska, a large independent which has been working in Alaska for less than two years, said possibilities for the future include “continued step-out exploration” on the central North Slope, which “offers attractive reserve target sizes for independent companies.”
Exploration in the gas-prone Foothills “awaits a pipeline to carry the gas to market,” he said. “The lightly explored NPR-A offers larger exploration targets than the mature east-central area,” but “significant discoveries” require facilities construction. The outer continental shelf and Bristol Bay offer exploration opportunity, but have “huge commercial challenges,” Sheffield said.
He predicted “modest step-out exploration with increasing participation from the independent companies” on the central North Slope, “paced westward expansion with infrastructure” in NPR-A, low activity for the OCS and frontier basins — while the future of the Arctic National Wildlife Refuge is “in the hands of politicians. … The resulting impact of this best-bet forecast is that exploration discoveries over the next 10 years will likely only moderate the overall North Slope production decline.”
Sheffield stressed the tough nature of the exploration business, with very long cycle times from land acquisition through discovery and appraisal to production, and said those long cycle times and huge investment and business risks mean that “most companies shy away from exploration altogether and focus on investments exclusively — on property acquisitions and development.”
On the far-fetched side of the agenda, Sheffield said that if “operators achieve a significant capital cost reduction,” if “we have a period of sustained higher oil prices” and Alaska “initiates additional tax and royalty incentives” to spur development, “you could see greatly increased exploration activity, and an influx of independent operators.”
Exploration wells in the state, currently some 10 to 15 a year, could increase “up to 40 or 50 wells a year.”
But, Sheffield said, “lowering the cost of doing business and providing appropriate exploration incentives are critical to this scenario,” because higher oil prices will positively affect investment opportunities worldwide, not just in Alaska.
“In this high-exploration scenario, over time, new discoveries not only arrest Alaska’s oil production decline, but result in an overall production growth.”
Is it farfetched? Sheffield said his exploration manager told him it’s a realistic goal, “if all the players commit to make it happen.” Cook Inlet needs step change John Barnes, Alaska asset team manager for Marathon Oil, said Marathon “signed its first lease agreement on the Kenai Peninsula” in 1954, “so now in 2004 we’re proudly celebrating 50 years in Alaska.”
The search in the 1950s was for oil, and it was found in the Cook Inlet basin, with production peaking at 227,000 barrels a day in 1970. But oil production in the inlet is now about a 10th of that peak, he said, and the focus is on the search for more natural gas, a resource discovered during the search for oil, and discovered in such quantities that it fueled both heating and electric use and created two new industries — the fertilizer plant and the liquefied natural gas plant. But there is now only some 10 years of supply left.
“The Cook Inlet needs a step change in natural gas exploration and development activity,” Barnes said. The state and industry have responded to the need for more natural gas, but a bump in the road occurred with pipelines, he said: Marathon and Unocal are still waiting for a tariff on the Kenai Kachemak Pipeline, although that line went into operation in September, and the regulatory portion of the pipeline cost may “approach 20 to 25 percent of the project cost” of $25 million.
Companies need some certainties to make investments, he said, and while companies understand subsurface risk, accept commodity price risk and work to control project risk, Barnes said he believes “regulatory and tax uncertainties” are now “the most notable risk companies face in Alaska.”
As for the future, Barnes said: “If sufficient exploration occurs, and sufficient success is achieved, enough gas may be found to meet local utility and industrial demands.” A higher price for natural gas will be required to attract capital for that drilling, he said.
But if there is “less exploration” or “insufficient success … this creates the distressing scenario” where only one of the industrial plants may stay in operation — or worst case, both may be forced to close. Viscous could triple Steve Marshall, president of BP Exploration (Alaska), talked about the success BP has had with viscous oil at Milne Point and Orion. Horizontal dual-lateral wells are now used to produce viscous oil, he said, and whereas early vertical wells did well to produce 200 barrels per day, the company now has 10 wells that have each been producing “in excess of 1,000 barrels a day for more than a year.”
And in addition to dual-laterals, the company now has tri-lateral wells and at Orion, a Prudhoe Bay satellite, “the latest well there was a quad-lateral, with four wells going off it” and “26,000 feet of reservoir contact — five miles in one well.” Compare that, Marshall said, to 400 feet of reservoir contact in a viscous well in the 1990s.
As for the future, the industry today is producing 50,000 bpd of viscous oil from the North Slope. “We see potential for that to triple by 2014, or maybe more.” But that production level will require an investment of some $10 billion, he warned.
As for technology, Marshall said BP is looking at ways to increase well productivity by reducing the viscosity. “We’re looking at miscible injectants, detergents if you will, to flush the oil out — even bacteria; looking at heat, perhaps from deeper water sources that we’d need to produce; maybe CO2, with major gas sales.”
It’s difficult to predict technology changes, such as those that have occurred over the past 10 years, but Marshall said, “one thing hasn’t changed and it’s not going to change: and that’s that capital flows to the investments with the greatest returns.”
And “Alaska has some of the highest costs in the industry,” he said.
Marshall offered two examples: BP Exploration (Alaska)’s drilling efficiency, the time it takes to drill, is almost at the top for BP, but so are the costs to drill those wells. Viscous has an additional problem, he said: you have to look at productivity in relation to cost. The lifetime production of a viscous well is some 5-6 million barrels, compared to 35-40 million barrels for a well in the deepwater Gulf of Mexico fields.
BP will continue to work the technology challenges, Marshall said, and future successes in that area will impact what North Slope activity is like in 10 years. But costs will continue to be an issue, as will public policy. And future activity, he said, doesn’t depend only on technology, it “depends just as much on decisions being made today in Juneau.”
Marshall, who has been president of the Alaska Oil and Gas Association for the past year, said in closing that the companies who spoke agree Alaska has a world-class resource, but “it takes well in excess of a billion dollars a year — maybe it’s closer to 2 billion” just to keep the existing operations running.
What the oil and gas companies operating in Alaska want to know, Marshall said, is: “Can we go back to our boards, wherever they are — in London, Houston, Calgary, Dallas — and say with confidence, that this is a good place to invest? The oil and gas is there, we just need to find a way to get it out.” Will Alaska go to the well again? Kevin Meyers, president and chief executive officer of ConocoPhillips Alaska, said the potential of a gas pipeline is what is most exciting to Alaskans. He compared it to oil: The 4.5 billion cubic feet a day of natural gas coming off the North Slope will be the equivalent of 700,000 barrels per day of oil.
In addition to being a big project, “it also will open up a whole new business for us here in Alaska,” the business of looking for natural gas in addition to looking for oil.
But the financial commitment remains huge, he said, with the tariff estimated to cost shippers about $10 million a day. And with an estimated cost of $20 billion to take gas to the Midwest, investors have to be comfortable that the price of natural gas will remain high enough to help pay back that investment, Meyers said. “And it’s not just 10 years: it’s 20-30-40 years from now that the prices have to be good enough to help pay back … that $20 billion investment.”
In addition to paying back investors, the natural gas price has to be high enough “to yield a wellhead price that is high enough to encourage new exploration, new development and the production of gas on the North Slope…”
The federal enabling legislation is also key, he said, because “investors need confidence that the regulatory and permitting process in the U.S. will not hinder or even kill a project once a decision has been made to move forward.”
Just the permitting for the gas line, Meyers said, is expected to cost between half a billion and a billion dollars.
The federal fiscal legislation that ConocoPhillips wants “can help increase investors’ confidence in the project,” he said, because gas prices have to be high enough for decades to pay back that investment.
And then there is state fiscal certainty: “The investors also need to know the rules by which the state will take its royalty and taxes. And more importantly, investors need to know the state won’t change those rules after they have invested billions of dollars.”
Hence the Alaska Stranded Gas Development Act, under which the producers are negotiating “a fiscal contract that will provide certainty and clarity for the gas pipeline project.”
The producers are also looking for ways to reduce the capital cost.
But there’s also Alaska’s fiscal gap. If “Alaska chooses to address the fiscal gap by going back, once again, to the well — excuse the pun — the oil and gas industry, the industry that already provides almost 90 percent of the state’s general revenues, then it puts future oil and gas investments here at risk,” Meyers said.
Will the industry leave the state? “No, that’s not going to happen,” he said. But if oil and gas taxes are raised, “it will mean less investment, fewer jobs, less production, a poorer economy — and in the long run, less revenues for the state.”
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