Legislature(2003 - 2004)
05/14/2003 08:15 AM House RES
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* first hearing in first committee of referral
+ teleconferenced
= bill was previously heard/scheduled
+ teleconferenced
= bill was previously heard/scheduled
HB 246-OIL & GAS AUDITS & ACREAGE LIMITS Number 0075 CHAIR FATE announced that the first order of business would be HOUSE BILL NO. 246, "An Act relating to the limitation on upland acreage that a person may take or hold under oil and gas leases; and providing for an effective date." [The bill was sponsored by the House Rules Standing Committee by request of the governor.] Number 0275 REPRESENTATIVE MORGAN moved to adopt the proposed committee substitute (CS), Version 23-GH1135\D, Chenoweth, 5/13/03, as a work draft. [No objection was stated, and Version D was treated as adopted.] Number 0352 MARK MYERS, Director, Division of Oil & Gas, Department of Natural Resources (DNR), explained that HB 246 has two distinct parts. First, it expands allowable acreage that can be under lease by an individual company. Current statute limits this to 500,000 acres of non-unitized upland state lands. Highlighting a recent history of new exploration programs, he cited exploration licensing and shallow gas leasing in the North Slope foothills area, indicating such areas traditionally haven't seen a lot of interest. It is believed the original intent of the 500,000 acres was from looking at a more restricted statewide program, but now there are companies at or near their acreage limitations that are "good explorers," he told members. MR. MYERS related the belief that if the acreage limitation is extended, more acreage will be sold, there will be stimulation of exploration licenses in the Interior basins, and the shallow gas leasing program potentially will be helped by adding more "players." He explained that three companies are at or near their acreage limitations: Anadarko Petroleum Corporation ("Anadarko"); Petro-Canada; and ConocoPhillips Alaska, Inc. ("ConocoPhillips"), which is near 400,000 acres and has at times been at the limit, as has BP [Exploration (Alaska) Inc.], which is selling its acreage now. Passing around copies of a map showing current state leases, he said there remains a lot of acreage to lease and remarked, "We think this will help." MR. MYERS explained that the Umiat Meridian is important to the bill because the additional 250,000 incremental acres given to companies must be south of that line; there were concerns relating to the original 500,000 acres about having a monopolistic approach on the North Slope, and the limitation is to keep it from being owned by one or two companies. The additional acreage will be in primarily "frontier exploration areas" where a company needs a large amount of land to get a good commercial position in order to justify the "integrated economics" to develop the infrastructure to actually produce. He concluded: So we think it provides the proper balance between ... preventing potential conflict of ... monopolization of the central North Slope, the upper, more prospective oil areas, but allows for more folks to be involved in exploration licenses, shallow gas leases, and conventional leases south of that line. Number 0650 CHAIR FATE referred to the mention of shallow gas and surmised that this would include other areas of the state south of the Umiat Meridian, even in Cook Inlet, for example. MR. MYERS affirmed that. He said it also would allow companies that have used almost all their acreage on the North Slope to be able to buy onshore acreage in Cook Inlet. He added: Again, we don't see a great synergy between Cook Inlet and the North Slope. They're pretty different basins. They produce into different markets. And Cook Inlet oil, for example, is all refined locally, so it doesn't really compete with that oil going down TAPS [Trans-Alaska Pipeline System], which is predominantly exported. Number 0699 CHAIR FATE asked whether 250,000 acres is in addition to what the company would have if it's at or near capacity. He also asked whether there is enough land in the Cook Inlet area or enough hydrocarbon basins to facilitate that much acreage. MR. MYERS said that's a very good question. Referring again to the map, he pointed out green outlines of sedimentary basins that would be eligible for licenses or potentially for lease sales if the department chose to go through the "best interest" process for leases. Indicating the state has been selling a lot of exploration licenses, he said a company picks up, under licenses, up to 500,000 acres in an individual block. For a company that has bought a license and converted it all to leases, its entire statewide allotment would be used in that single license. This bill would allow such a company to pick up a reasonable portion if it had one license and a reasonably loose position elsewhere, for example. "So we think it's balanced, and we think it will help us sell leases," he said. MR. MYERS pointed out that for this part of the bill, there is an indeterminate positive fiscal note; he opined that it will only lead to additional revenue. Number 0778 REPRESENTATIVE HEINZE asked whether, under the exploration license, it's 500,000 [acres]. MR. MYERS affirmed that it's a maximum of 500,000. He added: That does not count against your leases until you convert to leases. There's a license. ... It's not leased land. They have no rights of production. They have exclusive right to convert to leases, though. ... If they convert, then, that would count against their statewide [limit]. Number 0813 REPRESENTATIVE CISSNA recalled other leases such as in the Katalla area and elsewhere. She noted that those aren't marked [on the map]. MR. MYERS replied that there's a small, privately owned concession around the Katalla oil field that was selected, to his belief, by a Native corporation; it's a tiny amount of acreage specific to that one small field, too small to show on a map of this scale, and there is no state lease or interest. In regard to other small, possibly prospective areas, he said: Basically, there's multiple different ... leasing programs that are active. One is the federal government, which looks at the offshore waters - the Minerals Management Service. So the OCS [outer continental shelf], they're contemplating ... working a five-year schedule for Alaska, particularly for the Beaufort Sea, lower Cook Inlet areas, and looking at Norton Sound and other areas, to revive interest in those areas. I think they'll have some interest in the lower Cook Inlet. They certainly will have some interest in the Beaufort Sea area - onshore, the Bureau of Land Management and particularly in NPR-A [National Petroleum Reserve-Alaska] - and then they have onshore acreage, federal acreage, in the Cook Inlet in particular. So ... they have active, producing [areas] on federal lands ... in the Cook Inlet [area]. I think other areas that have significant petroleum potential, particularly for gas, are in the Nenana basin, Copper River basin, Susitna basin. And those areas are highlighted by the exploration licenses already there. In addition, if you look in the Bristol Bay area, there's both oil and gas potential onshore as well as offshore. And then as you move to the north, you can see ... north and east of Fairbanks there's the Yukon-Kandik basin, which is the one that kind of hinges over to the Canadian basin; that has ... definitely some oil potential, as well as some gas potential. And then the Yukon Flats, near the wildlife refuge to the north of that, is also (indisc.--papers over microphone) prospective, ... both oil and gas. Number 0995 CHAIR FATE noted that those are outlined in green on the map. He then said this is an extremely important bill to the oil industry and to the state because the leases not only enhance exploration, but also provide revenue from the leases. Number 1025 REPRESENTATIVE GUTTENBERG asked about the difference between unitized and non-unitized acreage. MR. MYERS explained: The entitlement was ... designed for exploration, so that once it's in a unit, it's typically either in a plan of exploration or a plan of development. Most of our units are in a plan of development, so it's actually in development and the acreage is held by that plan of development. So it's extended beyond the primary term of the lease. Leases that are put into units have a negotiated work plan with the state. And they have, typically, production going on in them. So ... that acreage does not count against the statewide entitlement. So you put [it] in a unit; it's another way that ... your credits on exploration acreage goes down. But there's ... a hook there, which is part of our responsibility to make sure that once it goes in a unit, we're extending those leases beyond their primary terms, that we haven't agreed to work planned toward development, which typically includes shooting seismic [data], then drilling wells. So it locks the land up, but there is a distinct work commitment ... and a work in progress. When you buy [an] exploration lease, typically in the preliminary stages of exploration ... you may have some seismic data; you typically don't have any well data. ... So, in that case, you need a lot more acreage. When you get to the unitization, you have to have distinct exploration prospects in their outline. We won't approve the unit acreage beyond what we believe ... is the potential reservoir, based on the seismic and well data. So you can get more acreage ... than the 500,000 if it's within units, but units have very specific work requirements and they're very defined hydrocarbon plays or known producing or commercial fields. Number 1160 MR. MYERS addressed the second part of the bill, which moves royalty audit authority back to DNR from the Department of Revenue (DOR). It's strictly for royalty matters, he said, and the purpose is efficiency. He explained: In 1980 the law was changed to put it all in the Department of Revenue, thinking the same auditors would do ... the audits and there was efficiency there. But then the state entered the settlements, the Amerada Hess case. So each oil and gas company has a separate settlement distinct for royalties, different than taxes. So, in fact, audits aren't held at the same time; they're not done in conjunction. Not only that, but the settlements are ... commonly different on the two sides. So the working knowledge of that, really, and the negotiating part of that was done within the DNR, with the Department of Law. So there isn't any, really, commonality in the audits. Currently, DNR has ... four positions for audits, but those audits are initiated and supervised by DOR, and they have two supervising folks to do it. ... What we found is that it's a fairly inefficient way to work. Both DOR and DNR are in concurrence that it's more efficient to move that function back to DNR; it takes a statutory change. With that, DOR would transfer about $237,000 to DNR. We'd pick up two additional audit positions. So it's just an efficiency bill. We know of no opposition to it, and it's supported by the administration from both departments. Number 1259 REPRESENTATIVE GUTTENBERG referred to page 4, Section [6], noting that it deletes language relating to payment for oil or gas royalty. He asked whether redundancy is being removed or whether it takes out audits for royalty. MR. MYERS said this basically just transfers authority to do the audits from the DOR statutes and into the DNR statutes. Number 1316 REPRESENTATIVE CISSNA sought clarification about the history of this portion and whether this audit change will affect the industry, for example. MR. MYERS answered that the majority of the audit work is accomplished by DNR now. Because the authority exists in DOR, however, the head auditor for the issue must be within DOR. Noting that the settlements are still evolving, he said that as they change or go through "reopeners" and so forth, [DNR] finds that having the commercial knowledge in the organization doing the renegotiation is much better. He said, "It makes us more effective in the negotiations, and I think it makes us fairer, more knowledgeable." He suggested this is a benefit for the industry because of wanting negotiations to be based on knowledge when reopening a settlement. He told members: The settlements do set the framework. ... You just renegotiate ... changes in the marketplace, changes in the way petroleum's evaluated, or changes in transportation charges, basically. And they go up and down. The companies can reopen this, equal [the] playing field. ... So those commercial negotiations are very much linked to the auditing, because it's through the auditing that you find out whether or not you're getting out of line with the valuation. So we ... definitely gain efficiency on the commercial side to get true market value for our oil, based on the settlement, if that authority ... is within DNR. Again, we've had a good, cooperative working relationship with DOR; they recognize that it's inefficient as well, and that, again, envisioned was that tax and royalty audits would be done simultaneously and you would gain efficiency. When we reevaluate, given the current budget standards, we're always reevaluating ways to make the department more efficient. ... We're swamped with the increase in operations; this ... clearly makes us more efficient. REPRESENTATIVE CISSNA asked whether there were testifiers from the industry. She pointed out that the proposed CS had just been provided to members the previous evening. CHAIR FATE called a recess at 8:35 a.m. Number 1500 CHAIR FATE called the meeting back to order at 9:23 a.m. and announced that he was ready to move the bill. He related his understanding that Representative Cissna had discussed the bill in the meantime and was satisfied with it. He pointed out that it has an indeterminate fiscal note. Number 1530 REPRESENTATIVE GATTO moved to report CSHB 246, Version 23- GH1135\D, Chenoweth, 5/13/03, out of committee with individual recommendations and the accompanying fiscal notes. There being no objection, CSHB 246(RES) was reported from the House Resources Standing Committee.
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