Sunday, April 5, 2015

State estimates $150B to treasury if ANWR ever opened

Alaska Contract Staffing
Tim Bradner
Alaska Journal of Commerce

Alaskans have long believed oil discovered in the coastal plain of the Arctic National Wildlife Refuge could help keep the Trans-Alaska Pipeline System operating and also replenish the state treasury.

It may be a pipe dream because the federal government shows no sign of opening the coastal plain to further exploration and Congressional approval is required for any exploratory drilling or leasing.

Interior Secretary Sally Jewell, who denied the State of Alaska’s proposal for new seismic exploration of the ANWR coastal plain and is awaiting the outcome of a court case challenging that decision, wants to make it wilderness, a permanent lockup.

But what if? What if there were exploration, and discoveries? How much oil could there be? State officials told legislators in February the revenue to the state treasury could total more than $150 billion over 50 years.

ANWR’s coastal plain, in the eastern North Slope, is thought by geologists to have the best potential for major discoveries of any unexplored onshore area of the U.S.

Major oil fields have been discovered in the central North Slope, including the very large Prudhoe Bay and Kuparuk River fields. There is potential for further discoveries in this area but they are expected to be smaller.

The southern North Slope, and the huge 23-million-acre National Petroleum Reserve–Alaska on the western Slope, are generally thought by geologists to be prone to natural gas discoveries although some oil will almost certainly also be found.

The most informed estimate on ANWR’s coastal plain area came from the U.S. Geological Survey in 1998, which made a “mean” estimate of 7.7 billion barrels of recoverable oil that could be discovered. “Mean” is basically mid-way between high and low estimates.

Whether oil is really there isn’t known for sure. The USGS worked with data from 1,180 miles of two-dimensional seismic program conducted between 1983 and 1985, plus what is known about the regional geology.

The only exploration well drilled in ANWR, in a 91,000-acre in-holding of private lands owned by Kakovik Inupiat Corp. and Arctic Slope Regional Corp., was drilled in the early 1980s by BP and Chevron Corp., and the results are still secret.

No matter what the drilling showed, development of even these private lands are blocked unless Congress decides to open the rest of the costal refuge.

Still, state legislators in Juneau want to know what Alaskans may be missing out on.

In mid-February, the House Resources Committee asked the state departments of Natural Resources and Revenue to develop the most plausible oil discovery and production scenarios based on that is known, and to derive state revenue estimates from those.

The two agencies presented their results to the committee on Feb. 12.

Paul Decker, acting director of DNR’s Division of Oil and Gas, described ANWR’s regional geology in the so-called “1002” area, a coastal plain area named for the section of the law in which Congress designated for additional study of petroleum resources in the Alaska National Interest Lands and Conservation Act of 1980, the federal law that created the refuge.

Decker said the best prospects for discovery are in the western third of the coastal plain, which state geologists believe to hold the most oil potential. Of the 7.7 billion barrels of resources estimated to be in the 1002 area, 6.4 billion barrels are expected to be in the western third.

That is about five times the oil potential of the eastern two-thirds of the coastal plain.

“The northwestern one-third of the coastal plain is geologically simpler and more favorable to hosting oil accumulations,” Decker told the committee.

The area is also adjacent to state lands across the Canning River where companies have made discoveries at Point Thomson (gas, liquid condensate, and oil), and Sourdough (oil). Oil has also been discovered offshore the 1002 area, with the Kuvlum well in 1993 and “Hammerhead” (where Shell is exploring) in 1985.

Geologists in the division did further analysis, predicting that most of the accumulations that might be discovered would be in the 32 million-barrel range to 256-million-barrel range, but accumulations of 1 billion barrels were also possible.

Based on that analysis, the Department of Revenue developed possible production and oil royalty and tax estimates. Ken Alper, director of the Tax Division, presented the conclusions, assisted by Dan Stickel, assistant chief economist.

The scenario presented by Alper and Stickel would have permission granted by Congress to explore in 2016 and leases issues between 2017 and 2019. Exploration would begin in 2019, with the first field located in 2022, and with its development beginning that same year.

First production would be in 2026. From that point on, the scenario foresees one new field discovered and brought into production every two years so that there would be 25 fields in total developed by 2074. The assumed size of discoveries vary along the lines of the estimates by the Division of Oil and Gas but most of the new fields would be between 64 million barrels and 512 million barrels of recoverable resources.

All prices and costs in the modeling assumed 2015 constant dollars and an oil price of $110 per barrel along the lines of the Revenue Department’s very long-range price forecast (a $90 per barrel case was also considered, however).

The modeling assumes no gas being developed, although surely there would be gas discovered also.

Given these assumptions in the modeling, a “base case” of 7.1 billion barrels of oil developed and produced until 2075 would bring $150.9 billion to the state treasury, although the number could be higher, or lower, depending on the amount of oil found.

The production profile in the base case was about 560,000 barrels per day, with a high case, with more oil discovered, of 760,000 barrels per day and a low case, with less oil discovered, or 350,000 barrels per day.

The required investment by industry would reach $5.75 billion per year in the development, pre-production phase, with continuing investment all through the operating lives of the fields.

Because of tax credits in the current state production tax the state treasury would not begin to experience income net of the tax credits until 2030 or 2031, but revenues would then increase rapidly to a peak of about $4.9 billion per year in 2045.

Revenues would the taper off gradually, but even by 2075, the end of the period modeled, there would still be $3.3 billion per year net to the state treasury.

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