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Impact of royalties
House Resources hears Gaffney Cline analysis of Cook Inlet gas development
Kristen Nelson Petroleum News
Would royalty reduction spur more natural gas development in Cook Inlet?
The Legislature has been considering changes to natural gas royalties and Nov. 19 the House Resources Committee heard an analysis Gaffney Cline prepared at the request of the Legislative Budget and Office Committee addressing the issue.
Nicholas Fulford, senior director of Gaffney Cline, told the committee that there are an array of risks facing any investor in Cook Inlet oil and gas, including cost, aging infrastructure, limited services, the challenges of weather and operating in the inlet, environmental considerations and liabilities of decommissioning.
Then there is the lack of access to a broader market, with any new gas likely going to one of a handful of buyers, buyers who are looking to diversify their energy sources.
Add to that the possibility of a gas line from the North Slope, making it more difficult to ensure that there would be long-term secure sales for any new project producing Cook Inlet gas.
Fulford said he sees the biggest risks as cost pressures and having a long-term reliable buyer who would support the investment with an adequate price.
And were a gas line to be built from the North Slope, that would substantially change the market dynamic in Southcentral, something which would be of concern to investors, he said. Fulford suggested a measure of state support could help protect against price changes should a North Slope gas line be constructed.
Types of developments Fulford said Gaffney Cline's modeling showed that while royalty changes can help create a case for investment in a project, gas purchase price and production levels are more influential, with royalty reductions broadly comparable to savings in operating and capital requirements.
The modeling looked at two hypothetical Cook Inlet projects -- a standalone shallow water gas field and incremental drilling at an onshore gas field. Fulford said that generally incremental drilling from existing onshore or offshore locations had fairly positive economics without royalty relief.
For the new development, the modeling looked at a platform with all necessary infrastructure; at a development in which a platform tied back to another offshore structure; and a third option tied back to an onshore facility.
An offshore development to produce 250 billion cubic feet of gas has marginal economics if it is standalone. For it to be economic, a tie-back to either an offshore or onshore facility is needed.
An offshore platform with 500 bcf of recoverable volume is significantly more attractive than the 250 bcf, Fulford said.
While changes in royalty may be helpful, Fulford said, it's a larger resource base that really improves economics, with higher average production "significantly" improving the investment case. Modeling assumed a gas price similar to existing Cook Inlet gas contracts, some $8.50 per million British thermal units.
Cook Inlet reserves In the same hearing, the Alaska Department of Natural Resources' Division of Oil and Gas addressed the issue of remaining natural gas reserves in Cook Inlet.
Director Derek Nottingham of the Division of Oil and gas said some 500,000 people in Alaska, 70% of the state's population, depend on gas for heat and electricity. Of some 70 billion cubic feet a year used, Enstar has 35 bcf under contract, Chugach Electric has 19 bcf, Matanuska Electric has 6 bcf, the Interior Gas Utility has 5 bcf and Homer Electric has 1 bcf.
Gas production in Cook Inlet has been declining since 1990, when it peaked at more than 850,000 thousand cubic feet per day, averaging just over 200,000 mcf pr day currently.
Nottingham reviewed estimates of Cook Inlet gas reserves, including that one by the U.S. Geological Survey in 2011 that estimated the mean of undiscovered, technically recoverable gas is some 13.7 trillion cubic feet, with the mean of unconventional gas 5.3 tcf. The Bureau of Ocean Energy Management in 2011 estimated 1.2 tcf of additional mean resources in the federal southern Cook Inlet outer continental shelf.
But, he said, of that potential of some 14 tcf of conventional gas in the Cook Inlet basin, that covers an area in excess of 5 million acres, while the area the state leases out some 2.8 million acres.
Significant amounts of those volumes, Nottingham said, may never be economically recoverable.
A lot of the gas resource in the federal estimates is from the wildlife refuge on federal lands, so of that huge 14 tcf resource, a lot is in inaccessible lands or lands that it may not be possible to be developed, or in pools so small they can't be developed economically.
2022 forecast Weston Nash, commercial analyst with the division, said the last gas forecast for Cook Inlet was done in 2022, an independent analysis to provide information on gas supply issues. It used public production data, he said, and standardized economic limits for each unit, with an assumption of 15 new development wells per year until 2030, but no new wells beyond that. The analysis assumed a flat gas price at 70 bcf, escalated with inflation but does not forecast market changes and does not include contributions from non-producing known prospects.
Nash's slides included the cost of a hypothetical new gas project targeting 250 bcf of recoverable resource -- something he said would be a very significant field for Cook Inlet, most likely offshore, which increases capital expenses.
The investment is estimated at $350 million, with a 3-year development time and operating expenses of 50 cents per thousand cubic feet. Assuming that investors would require a 4-year payback period and a minimum annual real return of 15%, the cost of that gas supply would be $12.26 per mcf, compared to current $8-$9 per mcf prices.
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