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The carrot and the stick: Meyers, Condon look to lure investment Suggestions include incentives to make state more attractive to smaller companies and tax rate based on reinvestment in Alaska’s oil, gas fields Kristen Nelson PNA Editor-in-Chief
How should the state encourage oil and gas investment in Alaska? What incentive programs does the state have now and how do they work? The Department of Natural Resources and the Department of Revenue suggested carrot and stick alternatives to the House Special Committee on Oil and Gas April 5.
On the carrot side, Director of the Division of Oil and Gas Mark Myers said shallow gas leasing and exploration licensing have brought new players to the state, and told the committee the state should smooth out its leasing and permitting programs to make the state more attractive to mid-sized oil and gas companies.
On the stick side, Commissioner of Revenue Wilson Condon said existing tax incentives have worked to keep older fields producing and to encourage the development of smaller fields, but also suggested to the committee that the state should consider doing what is already done in other jurisdictions worldwide — offer tax encouragement for companies to reinvest money they earn in the jurisdiction. Leasing incentive programs DNR has a number of incentive programs, and Myers said two new leasing incentives are good programs for the state, drawing in new companies and getting work started in basins other than those currently producing.
The state’s shallow gas leasing program, an incentive because it foregoes competitive bids, offering over-the-counter first-come-first-served shallow leases in areas outside Cook Inlet and the North Slope, has already brought a new company to the state, he said:
“Evergreen Resources, pretty much a world-class coalbed methane company, has stated several times: they have come to Alaska because of this program.”
The shallow-gas leasing program is promoting coalbed methane development in the Fairbanks, Matanuska-Susitna and Homer areas and development of shallow gas from fractured shales near the Red Dog Mine, and Myers said the division strongly supports amendments to the program in Senate Bill 319 sponsored by Sen. John Torgerson: “We think it takes the program from what was designed to be a small local energy program into a full fledged commercial program.” The bill also provides “additional environmental protections for the state,” additional revenues to the state and “significant additional rights to the lessees,” he said.
The other new leasing incentive program that Myers said was working well is exploration licensing, an incentive because “it foregoes the normal competitive bonus received in a lease sale (and) allows a company to explore a large amount of acreage, up to 500,000 acres, for the cost of a work commitment.”
An exploration license in the Copper River basin has been issued, Myers said, and three more licenses are pending. The program allows a company to spend money on exploration, rather than on competitive bidding, in areas the division thinks “are economically more marginal than typical North Slope or Cook Inlet,” he said. Discovery royalty not appropriate Myers said that among the state’s existing exploration incentive and royalty reduction programs — reducing royalties or taxes to promote activity — royalty reduction is appropriate. That program, based on economic analysis by the state, allows the DNR commissioner to reduce the royalty to keep fields in production or to bring non-producing fields into production.
The exploration incentive program was appropriate because it is targeted directly at exploration and because exploration incentives are granted at the discretion of the commissioner.
But, Myers said, the discovery royalty credit has not proven to be a good incentive.
“Or at least it hasn’t stimulated or accelerated exploration, in my opinion.”
One discovery royalty program was repealed in 1969, but there are 274 leases on the North Slope still eligible for the program and another 33 in Cook Inlet.
Fourteen discovery royalties were granted while the program was active — but the state is still granting discovery royalties, Myers said, for leases under the old program: Some $12.5 million estimated in discovery royalties at Alpine and $50 million at Point McIntyre.
Myers said the continuing royalty credits show “that when you do create an incentive program for royalty purposes, you generally create a contract right that will exist as long as those leases exist.”
The program was established to accelerate exploration and development, and since it has most recently been granted on 30 and 40 year old leases, “it’s hard to make the argument that it has in fact accelerated exploration,” Myers said, probably because a reduction from 12.5 percent to 5 percent for a few years “has a very limited effect when you look at the cost of development of a field.” Incentives from the tax side Revenue Commissioner Wilson Condon said he was using incentive to mean “a provision in tax legislation that influences the behavior of the taxpayer.” Some incentives from tax legislation are intended, he said, and some are unintended.
In three cases, he said, the Legislature acted with conscious intention.
One tax oil and gas incentive was enacted then the basic tax rate was increased from 12.25 percent of the value of production in the field to 15 percent in 1981, Condon said. The Legislature left the rate for the first five years of field life at 12.25 percent “because they did not want to discourage investment in new fields…”
And the Legislature had two different incentives in mind when in enacted the economic limitation factor, or ELF, Condon said.
Legislators wanted to make sure that fields were not shut down prematurely because of the production tax, so as a property neared the end of its economic life, the tax rate fell to zero, “so that the cost of the tax would not be the straw that broke the camel’s back… in terms of ending the life of a producing property.”
When the ELF was enacted in 1977, it bas based on the per-well production rate.
When the Legislature changed the ELF in 1989, Condon said, one of its objective was to add overall field production into the ELF formula, “so that the ELF formula was a product of both per-well productivity and the overall production level from a producing field.”
The Legislature’s goal, Condon said, was to increase the rate for highly productive fields and reduce the rate for small fields, to encourage development of small oil accumulations.
“And certainly the taxpayers tell us,” Condon said, “that the development of what we call the satellite fields on the North Slope today is made more economic by the manner in which the ELF has been constructed.” New investment not recognized Condon said one thing Alaska’s tax system doesn’t do is to recognize new investment.
But among our competitors, he said, “many other areas in the world do take into account new investment in figuring the tax obligation of firms engaged in the oil and gas industry in their jurisdiction.
“And that is something we ought to think about today,” he said, because Alaska does compete with other areas for investment dollars and “if other jurisdictions have structured their fiscal system so that they take into account investment there and we do not, it does place us in a competitive disadvantage if all other things are equal in terms of cost, geologic prospectivity and so on.”
Committee Co-Chair Hugh Fate, R-Fairbanks, asked Condon if that kind of a tax change wouldn’t get the state “into a competitive shooting match” which would “seesaw downward.”
Condon said he didn’t think we could do anything about “a race to the bottom.”
But, he said, “I do think that when we look at our own tax system we have to ask ourselves whether we should be imposing the same tax obligation on a firm that makes money here and then reinvests that money here, as opposed to a firm that makes money here and takes that money and invests it in Kazakhstan.” New players an issue Myers told the committee at the end of the hearing that he thought promoting Alaska’s geologic potential to new companies, including mid-sized companies, was one of the important things the state could do.
Historically, he noted, as basins mature you see more independents coming in.
“Once the basic infrastructure is there they can move a little quicker, a little more inexpensively.” Smaller companies, he said, have better economics.
But, he said, they have to turn things around quickly.
“They have to make money — a rate of return — quicker. They can’t want 10 years for their production to come online. They need to get it in three or four years.”
The state can do some things that aren’t strictly monetary to encourage those companies, he said.
One thing is turning leases around quickly.
“We’re taking 14 months to issue a lease now — that’s problematic,” Myers said.
“We need to be able to accelerate our leasing program. We need to make sure that our title work is great and all our permitting processes work smoothly in terms of accelerating exploration and developing, and lowering their risk of project delay.”
And, he said, “the infrastructure on the North Slope needs to be open for all parties and that includes pipelines and facilities, facilities sharing agreements need to be efficient and work, so that new parties can come in and have excess capacities available in facilities…”
Myers said he thought there were a lot of areas “outside of strict fiscal incentives” where the state can improve — and bring in new players.
“They may not be large super majors,” Myers said, “but they will be the next tier of companies that you would expect as sedimentary basins mature and infrastructure develops.”
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