Legislature(2001 - 2002)
01/31/2002 10:07 AM House O&G
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* first hearing in first committee of referral
+ teleconferenced
= bill was previously heard/scheduled
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= bill was previously heard/scheduled
HB 307 - OIL/GAS EXPLORATION INCENTIVE CREDIT [Contains discussion of HB 308] Number 0191 CHAIR OGAN announced the first order of business, HOUSE BILL NO. 307, "An Act delaying to June 30, 2007, the last date by which hydrocarbon exploration geophysical work must be performed or drilling of a stratigraphic test well or exploratory well must be completed in order for a person to qualify for an exploration incentive credit." REPRESENTATIVE FATE, sponsor of HB 307 and HB 308, informed members that although the two are separate bills, both relate to exploration and development in the same basin. Number 0254 JAY HARDENBROOK, Staff to Representative Hugh Fate, Alaska State Legislature, read the sponsor statement for HB 307 as follows: House Bill 307 will extend the exploration incentive credit [EIC] for petroleum for an additional three years. This will allow for further exploration into the possibility of natural gas and oil in the Tanana River drainage basin. There is presently renewed interest in exploring for natural gas in the above- described basin near Nenana. This simply extends its sunset provision from 2004 to 2007. MR. HARDENBROOK noted that Mark Myers of the Division of Oil & Gas was online to explain the EIC. Number 0312 CHAIR OGAN asked why HB 307 is a good idea. MR. HARDENBROOK indicated the subject [of both bills] came to the attention of Representative Fate's office via Andex Resources, a company out of [Houston, Texas, with offices in Denver and Oklahoma City]. He noted that committee packets contain an article from Petroleum News [Alaska] that talks about a renewed interest [by Andex Resources] in the Nenana basin, which is close to both Nenana and the Parks Highway; it reports an interest in providing natural gas to Fairbanks and the surrounding area. Mr. Hardenbrook said this is a "great boon for Fairbanks, since the majority of us are still on heating oil, which makes our heating costs considerably larger than those of other areas in the state." Number 0398 REPRESENTATIVE FATE offered some history. He recalled that 15 or 20 years ago ARCO and Texaco drilled exploratory wells and found "good structure"; one of those wells was capped. To his understanding, they hit the "basement or igneous rock" at about 6,000 feet, which isn't the optimum level for a large gas deposit. Since then, with new technology and seismic exploration, the Nenana basin has been found to go as deep as about 20,000 feet, with much at 14[,000] feet. He stated his understanding that [Andex Resources] will extend its exploratory drilling down to about 14,000 feet. He pointed out that gas is found both above and below this level, but is optimum at about 12,000 feet; he indicated Andex Resources believes the potential is quite high. REPRESENTATIVE FATE told members the entire Tanana River drainage [basin] takes in far more than the Nenana basin, but includes coal-bearing strata in the northern and eastern parts. Currently, another company there is looking for shallow gas; that doesn't even touch on the Jarvis Creek area, where exploration has been done on coal. That whole basin has the potential for both deep and shallow gas. REPRESENTATIVE FATE noted that [HB 307] just extends a [deadline], whereas [HB 308] duplicates what has already been done in Cook Inlet. Therefore, they extend these [incentives] and provide the same new advantages for new exploration and development - in an area of high potential - that have existed already in Cook Inlet. Number 0576 REPRESENTATIVE DYSON asked why this only applies for that basin, and whether a similar incentive is being made available for other areas. REPRESENTATIVE FATE answered: Because basically this was the area in question. There are other basins, and I would have no objection ... if those basins were identified. This basin is specifically identified in this particular bill, and I can't speak to other basins as to their stratigraphy and anything else. Number 0628 CHAIR OGAN pointed out that the foregoing discussion pertained to both bills. REPRESENTATIVE DYSON stated his understanding that HB 307 extends the date for everyone. CHAIR OGAN affirmed that. He asked Mr. Myers to explain the EIC and whether it has ever been applied for or used. Number 0723 MARK MYERS, Director, Division of Oil & Gas, Department of Natural Resources, testified via teleconference. He first offered some geology, saying: We concur with Representative Fate's assessment of the Nenana basin. It's a very attractive-looking basin, ... particularly for gas. One of the exciting things about it is, it does have two well penetrations, the last one by ARCO. On the peripheral edges of the basin, ... neither well hit into the ... "gut" or the deeper parts of the basin. There's a regional seismic grid that exists in the basin, and it's gravity and magnetic data. So, the basin is very well defined on regional data. ... Also, with the well data and with the outcrops that are exposed around the peripheral parts of the basin, we know a fair amount about it. We know that it's a very young - geologically young - basin. It contains numerous coals, and obviously some of those coals are the edge of the Usibelli mine; ... you can see some of the same geology that would reflect into the basin. It has very prospective-looking, positive indications of reservoir rock. We know gas was generated in the basin; there's enough ... direct indications of gas being generated in the basin. So, we have many of the key components for ... significant discoveries of gas in the basin. I would concur, again, with the depth assessments that are being relayed. There's significant parts of the basin that are at 10,000 feet or deeper depths, which ... generates the large "kitchen" to create the gas. ... Additionally, no one's ruled out the potential for oil or for ... heavier liquids, although there's not a good indication that the type of source rocks you would need to generate oil are in the basin. The basin was earlier explored, as we said: twice from the [19]60s on. The state actually held a competitive sale there in 1982 and got ... 14 bids from ARCO, Shell, and ... private parties. And that resulted, then, in the drilling of the ... ARCO well. Number 0878 MR. MYERS highlighted another attractive feature: the proximity to Fairbanks and to infrastructure on the highway. Currently, he told the committee, liquefied natural gas (LNG) is being shipped to Fairbanks, where it is converted back to methane. Mr. Myers said it is "receiving about $8 a ... thousand cubic feet." He called this "very high, positive price" a great incentive for exploration in the basin. Number 0917 MR. MYERS addressed the exploration licensing program. He noted that currently [DNR] has an application from Andex Resources for a 500,000-acre license; it covers, basically, the entire basin itself. Mr. Myers told members: We're encouraged by this license. I think ... the exploration license is a dynamic tool for exploration. It does a bunch of things to the basin. One is, it gives exclusive rights of exploration for a one-time, $1 fee per acre; then the license period is negotiated, based on the dollar or work commitment and time. So ... the only money the state receives out of the initial license period - and, typically, anywhere between five and ten years for a license period - is $1 per acre; in the case of a $500,000 application, it gets $500,000. There are no rentals to pay. At the end of the exploration license period, that company - which ... now has exclusive rights to explore, basically, in this case, an entire basin - those can be converted into leases noncompetitively. So they can choose the heart - the best part of the basin - and then convert to a 12.5-percent lease, with no bonus upfront. Number 0990 That gives a company a huge competitive advantage and a huge incentive. To realize what that's worth, approximately, is if we went for a minimum $5 bid for the same amount of acreage and ... it was bid at that level, and we then follow it up ... with just the normal rentals, it'd be worth about $10.5 million. So I think one real, positive [incentive] is the exploration licensing program that then allows conversion, gives exclusive rights of [exploration] at extremely minimal costs, and then a significant subsidy over what we'd do with a competitive sale. And I think it's a very good program, and I think it's a very encouraging program for production of gas in ... this basin. Again, we have good geology; the basin looks very positive; we have an exclusive right ... to explore, by a company that seems willing to explore. ... So, again, some very positive indications. The other thing is, we're not far from market, and the market has high value. The market will have additional value, of course, if a gas pipeline goes through Fairbanks. So, ... again, great potential for a local market - we've kind of assessed that - and a long-term potential with a pipeline. ... It's a basin we were excited about years ago, with the state; under land selection, we selected as much of the prospective part as we could. ... So the potential's been recognized for years, and it's nice to see someone actively going into exploration - and, again, we're excited about that. Number 1092 MR. MYERS, in response to a question by Chair Ogan, noted that the license [Andex Resources] has applied for is in the review process now. In further response, he said: They would not be allowed, within that license area, to explore for shallow-gas leases. ... It's an exclusive right for explorations from grassroots all the way down to the center of the earth. So it precludes anyone within that license area from doing coal beds. MR. MYERS, when asked by Chair Ogan to confirm that this legislation doesn't affect the shallow-gas leasing program, said it doesn't directly. He added: Now, there's some nuances with ... the exploration licensing part of that, in the sense that ... an exploration license cannot be given on leased state land. So EICs only work on the regulations on unleased state land or private land. So with respect to [HB] 307, if someone has a shallow-gas lease, the state cannot give them an EIC, or a conventional lease, they could not give them an EIC. MR. MYERS concluded by saying [shallow-gas leasing and exploration licensing] are totally separate, distinct programs. Number 1232 MR. MYERS offered some history of the exploration incentive program. It was designed so the state could acquire geologic information, generally prior to competitive sales. In the past, a consortium of perhaps a dozen companies would drill wells into a frontier basin to acquire data prior to a lease sale; they would deliberately drill "off-structure" in a location where they believed they wouldn't encounter hydrocarbons, to avoid giving a competitive advantage to anyone. This was in order to understand the basic geology of the basin. Mr. Myers cited examples, including Norton Sound, indicating these are called "cost wells" or "combined offshore stratigraphic test wells." MR. MYERS said the concept was that if everyone chipped in some money, "we could go out and get the scientific information and be better prepared for the leasing program." Under this concept, it could be extended to Interior basins, although he said there wouldn't be a dozen companies interested. He suggested that if a company were interested, then the commissioner of [DNR] would have discretion to pay for part of that exploration well or geologic test well; that could occur if the value of the information to [DNR's] leasing program and resource management issues - and to promote exploration - was [deemed] significant enough. Mr. Myers told members: It also had another element: it was recognized that the state doesn't ... get seismic data over lands that are Native-owned or privately owned. We get it now by right of permit on state lands. But it would apply to wells or seismic data drilled on private lands the state wants to get. In general, if a well is drilled on private land, the state is not entitled to see that data until the primary, two-year period of confidentiality is over for that well. On state lands, ... the program also gave some other rights to the state. It would be able to show that data - not give, but show that data - to third parties, to promote exploration. So, again, from a well and seismic information [standpoint], it was to encourage the gathering of baseline geologic data, to then be better prepared to go forth and promote exploration ... into the basins. Number 1373 So, that was clearly the intent; that's the way the program has been proposed for administration. It put a cap on $30 million for the entire program over its life, to 2004, for the ten-year program. It also said that no single project - and it didn't really define "project" - could be more than $5 million. The money would be given based on a cost per line-mile for seismic, or by foot for well drilling. So, it was designed that the state would pay so many dollars for each foot drilled, and then ... would get that information. Number 1395 MR. MYERS pointed out that under some circumstances, wells can be granted "extended confidentiality" beyond their primary term, beyond the 24 months. He indicated [HB 307] says [a company] that gets information under this program couldn't apply for extended confidentiality. He noted that there are approximately a dozen wells on the North Slope under confidentiality now. MR. MYERS told members [HB 307] is well-intentioned legislation that DNR certainly doesn't oppose. However, the question that comes to mind is whether it is appropriate to give EICs in a license area - which is a precursor to leasing - where there is no competition at that point in time and where the geologic data, because of that, doesn't have significant value to the state. He expanded on his answer: The state's going to get that data anyway on state lands, so ... is it appropriate to do in a license area? Laws researching whether or not the state can do it - is a license a lease? - because we're restricted from doing leases. And I think our tentative belief is that it's probably not, that there's probably discretion to be able to give it. But, again, the value of the information: if someone has locked up the basin to exclusive rights of exploration for the first seven years, followed by a lease for another seven years, say, there's fourteen years where that data isn't of value in ... promotion, to the state. It may be of value in the state's ability to manage the land. It may promote the exploration. But ... was that the intent of the program? Number 1493 MR. MYERS proposed that one of clearest values of discussing the bill's extension is to get clear legislative intent as to whether the legislative intent of the program is changing to be more of an incentive to people in license areas, for the state to subsidize or pay part of the cost of drilling. He added, "Again, the original intent was clear, for the state to gather information; so it's very discretionary on the DNR commissioner's part. So that's the fundamental question." He continued: I think there are other areas of the state that aren't under license where the original intent would clearly be met. And there are Native lands or privately owned lands within this basin that the state might want to apply it to, if it considers the information very valuable, to get within the two-year period. ... Again, the original intent was to acquire information, not to subsidize drilling on state land. Number 1552 CHAIR OGAN noted the $30-million cap on the program in total, with a $5-million incentive-credit cap per project. He asked whether that $5 million would come from royalties or bonus bids, for example. MR. MYERS answered that it comes directly from the revenue stream coming out of oil and gas. It could be royalties, rentals, taxes, and/or bonus bids. It also is transferable to other companies that may have production. MR. MYERS reported that in the past, the state had another EIC program under which, when people competitively bid, they knew the state might pay up to 30 percent or so of the cost of the well. To date, those EICs have cost the state about $55 million. Furthermore, under that program the state had transferable EICs; companies without production on the North Slope sold their incentive credits and transferred them to third parties such as ARCO or BP. Number 1648 MR. MYERS, returning attention to the current program, remarked, "We have not had anyone apply for this program, so at this point in time, literally, we have not expended any money." In response to a question from Chair Ogan, he clarified that no one has wanted to drill a stratigraphic test on unleased acreage to this point. He added: The other wrinkle in this is ... that when this bill was passed, it was the same year that exploration licensing was passed. So my opinion is that didn't really address the licensing issue. So that's one thing, again, that probably would need to be clarified, as to the legislative intent: Is it different now? How does the license fit in with ... the issue of "it's for unleased acreage?" Number 1691 CHAIR OGAN offered his reading of the statute: an oil company can apply, but the commissioner [of DNR] has discretion, based on eligible costs - approved by the commissioner - of performing [geophysical] work, drilling a stratigraphic [test well], and drilling an exploratory well. MR. MYERS affirmed that the commissioner has discretion. He again emphasized that legislative intent is of great importance in the commissioner's granting, or not granting, of an EIC. The amount also is discretionary. He reiterated, "Right now, it's pretty clear that the intent was [that] the commissioner's discretion was based on how much he valued that information." He added that the determination would be based upon how that information could be used, to whom it could be shown, and what value it had in promoting exploration and more competition in lease sales. Number 1760 REPRESENTATIVE FATE asked whether [a company] has to actually be producing before the credit is given. MR. MYERS said that is basically correct, but it can also be used on rentals, royalties, and bonus bids. REPRESENTATIVE FATE suggested it wouldn't be against the bonus bids because there is no production there. MR. MYERS replied: In this particular case, more than likely the EIC would be sold. ... A hypothetical ... company that didn't have production or ... wasn't bidding on exploration acreage elsewhere in the state ... would sell that credit to a third party; that's what's happened normally. So it's real dollars. And they may get 90 cents on the dollar. ... It's whatever they negotiate with that party. But ... it's just like cash, in essence. ... They always can sell that credit ... to another producer or another explorer that has those costs. Number 1830 MR. MYERS, in response to Chair Ogan, specified that he was talking about the EIC and its worth. He added: A licensee, of course, doesn't have any rentals or didn't pay any bonuses, nor do they have any taxes or royalties; so they have nothing to take that EIC off against. ... That party would have to sell it to someone, ... as a transfer to someone that does have those elements. And, of course, we have a lot of that on the North Slope [and] on Cook Inlet. CHAIR OGAN requested clarification about Mr. Myers' statements that the [current] program has never had anyone apply under it and that traditionally these are sold like cash. MR. MYERS replied that there are two EIC programs. The first is a term [during which] the commissioner has the option of putting on a competitive sale. He explained: The thought was that an EIC upfront would be worth an increase in the bonus bid [at] the time of sale. So it was a competitive term that would not only encourage people to drill wells, but also the costs would be recovered by people bidding more on the sales. And I don't believe there was a symmetrical relationship there, but that was the theory. The state has not used that program for years, but we have used it in the past, and have given out $54 million. So there's a significant track record of how those EICs were transferred. The methodology in how it mechanically works, other than discretion [on the] part of the commissioner, ... is identical to the ... other EIC program that I referred to. Number 1925 REPRESENTATIVE GUESS asked: If we were discussing a basin where you didn't see that there was the value that there might be in another situation, where would you sit on this? ... This bill in front of us is just extending the date; it doesn't really particularly talk about any specific basins. Do you think we should just let 2004 come and go, and that this part of the statute isn't necessary anymore? Or where do you sit on extending the date, versus Nenana basin? MR. MYERS replied: I know DNR's position is that we're neutral. We think it's really a policy call of ... the legislature. I think it's a very good point. Outside of license areas, the intent is still there. And it may even be there within license areas [if] the intent ... is clarified by the committee. There are certainly other areas of the state, other ... potential basins, where we have not had lease sales - there are no licenses - where the information might have great value. And ... if the state would subsidize it or pay for a part of the cost of the well, it may be money well spent. So, again, that was the original intent ... of the program; ... again, I'd certainly think that that intent's fine. ... But I think whether or not you want to continue that program is ... really a call you have to make, depending on intent, and then I think language - since license areas didn't exist before - clarifying what the intent would be in license areas, where someone has an exclusive right to explore and you're not really going to promote competition by granting the EIC. Number 2050 JAMES B. DODSON, Executive Vice-President, Andex Resources, L.L.C., testified via teleconference. He informed members that Andex Resources was formed in late 1998 by a foundation and a family that has been in the oil and gas business in the Lower 48 for about 50 years. Its original capitalization was $80 million in cash and $20 million in oil and gas leaseholds, particularly in the Rocky Mountain States. Headquartered in Houston, it has a Denver office where he himself works. MR. DODSON said the Nenana basin is of interest to Andex Resources because the project is the right size for a company its size. He surmised that one reason ARCO "walked away from this basin in 1983-84" was that it didn't see a significant enough gas market. However, Andex Resources sees the Fairbanks market - which it estimates to be 40 million to 60 million cubic feet a day - as being of interest, even though a "major" might not see it the same way. MR. DODSON indicated Andex Resources did approximately a one- year study of the Nenana basin; he concurred that the basin is probably 20,000 to 21,000 feet deep at its deepest. From an exploration standpoint, he said, the biggest problem stems from the fact that the deepest penetration was on the basin's flanks and that ARCO's well only got down to about 4,000 feet. He added: So we don't know what the basin looks like deep. ... No one ever has drilled a well down to, say, 12,000 or 14,000 feet, which we think needs to happen. So what we don't know about the basin is, ... particularly, what kind of "seal rocks" we may have in the basin. ... That's one of our critical components to the play that we, frankly, have to say is an open question at this point, because the shallow penetrations have not found a shale or a sealing rock that would give us a lot more confidence in the basin. But we do agree that it is very rich in hydrocarbon- generating source rock, particularly coals and some (indisc.) shales. We don't know if gas is trapped and, if so, where. Our interest in being able to draw upon exploration incentive credits is basically to help us in carrying out our exploratory effort while, frankly, reducing our capital risk in doing so. ... By granting the exploration incentive credits, the state would be promoting the work that we want to do and be promoting an effort to get gas into Fairbanks. ... Number 2224 The first thing that needs to happen in the basin is probably about a 275-mile to maybe 300-mile 2-D seismic grid tying in the old grid and shooting over the deepest part of the basin, which ... hasn't been done yet. And we think that that's going to cost somewhere in the neighborhood of $6 million, after which, hopefully, we have some prospects fall out of that seismic work. And a well to about 12,000 feet out here, unfortunately, would cost about, again, $6 million. And part of the problem with working in an Interior basin is that there isn't a lot of oil and gas infrastructure to leverage off of. In the Cook Inlet, there is an oil and gas industry. There are service industries, et cetera, that could support you in the Cook Inlet. For us to work up here in the Nenana basin, we've basically got to position everything out of the Cook Inlet, move it 300 miles to the north, and ... build ... ice roads out into the basin. Everything is done on a retail basis; it's just part of the problem. MR. DODSON emphasized the importance to Andex Resources, when it comes time to make an economic decision, in having help in defraying those costs. For example, once the seismic [data] is shot, the company would need to make an economic decision regarding whether to risk drilling the well. Assuming its license issues this year - which the company is hopeful will happen - its desire is to shoot seismic information in winter 2002-2003 and drill a well the following winter. Number 2334 MR. DODSON pointed out, however, that this EIC is set to expire July 1, 2004. He said the statute itself defines an exploratory well as being three or more miles from another well. [Andex Resources] envisions having perhaps two to four "prospects" "fall out of this seismic program." There wouldn't be time to drill the exploratory wells in the basin by 2004. Rather, the company would drill in the winters of 2003-2004 and 2004-2005; if successful, it would be with the idea of maybe trying to "hook up Fairbanks" with some gas sometime in 2005. MR. DODSON suggested to the committee that anything the state can do to make [Andex Resources'] economic decision on whether to drill a well easier and less risky is advantageous not only to the company, but also to the state. The state would get the seismic data over the deepest part of the basin, as well as stratigraphic, structural information from a well drilled to, say, 12,000 to 14,000 feet. Furthermore, Fairbanks would be more likely to get natural gas. MR. DODSON referred to Mr. Myers' testimony that this is a policy issue regarding what these credits are to be granted for. Mr. Dodson reiterated that Andex Resources sees a significant gas market in Fairbanks for a company its size. In addition, people in Fairbanks are paying a lot for energy, and the company believes it could "attack that cost structure." Mr. Dodson concluded by saying Andex Resources would certainly favor an extension of this EIC through 2007 in order to ease the burden of getting this exploratory work done. Number 2449 REPRESENTATIVE FATE asked Mr. Dodson whether he perceives this as a possible model for drilling in other rural areas where there is at least the potential for a small market. MR. DODSON answered in the affirmative. He reiterated that the problem with exploration in the Interior is lack of nearby infrastructure support. To the extent the state can step in under the EIC program and change the economics for an operator to figure out whether to drill a well, it certainly creates a model that might be applicable, for example, near the Red Dog zinc mine, which to his understanding is looking for a local source of gas - a risky and expensive undertaking. If the state could use the EIC program to help decrease risk to companies doing exploration, Mr. Dodson said he does see it as a model for the balance of Interior Alaska. Number 2530 REPRESENTATIVE GUESS referred to the exploration license discussed by Mr. Myers. She asked how those incentives fit into Andex Resources' business plan and how they interact with the EIC. MR. DODSON answered that he believes there is a good reason why no stratigraphic test well has been drilled in this basin in the absence of a lease or license. This project is of a size that won't interest a major [producer], which would be more likely to drill a stratigraphic well just to get geologic data. He said the license is important to Andex Resources; the company doesn't want to spend money on a block of land unless it believes data generated from the well will be to its economic benefit. As for the EIC program, it just makes the decision whether to drill that much more favorable toward drilling because of the reduced risk of capital. Mr. Dodson further said: At the end of the day, if the state were to give us a credit for half of what we spent on state lands or a quarter of what we spent on Doyon land, that helps us make the decision to go forward. But in the absence of a license and the exclusive right ... it grants, we wouldn't spend our 50 percent or 75 percent of that well cost. ... So we do see the two being very integral to one another. Number 2624 CHAIR OGAN asked about the company's timetable for drilling. MR. DODSON replied that the critical item right now is getting a license from the state, which will determine quite a bit. The company believes it is dealing with a winter-only area, for both environmental and access reasons. The key is how far advance of a winter - and which winter - it would be in position to have a license and could therefore shoot seismic data. He expressed hope that a license would issue this year in time to shoot seismic data in December, January, and February, and that summer 2003 would be used to complete the seismic model for the basin, generate prospects off of that, and then drill a prospect to 12,000 feet or deeper. Because of the need to get a good set of sonic logs to tie into the seismic database, Mr. Dodson said he doesn't envision more than one well in winter 2003-2004. He also mentioned the need for direct readings on the porosity and density "of the stratigraphy we do drill through," which can significantly improve the accuracy of the seismic model; that would happen in summer 2004. In winter 2004-05, the company could drill one, two, or possibly three wells, and then be in a position to make a decision [whether] to build a pipeline into Fairbanks. Number 2730 CHAIR OGAN asked whether the company plans to shoot two- dimensional (2-D) or three-dimensional (3-D) seismic data. MR. DODSON offered Andex Resources' current belief that it likely would be a patchwork of both: predominantly 2-D, with perhaps a nine-square-mile area of 3-D. Number 2752 CHAIR OGAN asked what the company estimates the aggregated costs of the bonus bid and so forth would be, should the company decide to go forward; he indicated those are the costs for which a credit by the state could be given. He also asked whether the company plans to spend more than $5 million. MR. DODSON answered: Absolutely. ... Initially, there'd be a half-million- dollar payment due the state for issuance of the license. Then we're looking at a $6-million seismic program. And each exploratory well we're anticipating would cost about $6 million also. And so we're thinking it's going to take at least three wells out in this basin to get to an aggregate amount of production that would allow you to build into Fairbanks. So we're talking $24 million-plus to develop this basin. Number 2808 CHAIR OGAN clarified that he wanted to know whether the state would have to absorb 100 percent of the company's costs for this project; he also asked whether that would continue for five or ten years or for the life of the project. He further inquired whether the state ever would [receive] revenues if [Andex Resources] applied for this and got the full $5-million credit. MR. DODSON answered: We'd certainly work our way through the credits. ... If you assume that we were able to get to a $50- million-cubic-foot-per-day gas market, and ... the state royalty share - even if we were given the same treatment as in the Cook Inlet, with a 5-percent royalty - ... the state's royalty ... on 2.5 million cubic feet of gas per day at, say, a $2 netback, would be $5,000 a day, $150,000 a month, $1.8 million a year. MR. DODSON concluded that the project definitely "goes positive" for the state in terms of revenue, if successful. In the alternative, if the company drills a series of dry holes, "we go away." Number 2896 CHAIR OGAN asked whether, in applying for an exploration license, the company had to submit the same geological data to the state that is required for an EIC. MR. DODSON deferred to Mr. Myers. MR. MYERS answered that the information [regarding] wells drilled on state land has to be given to the state within 30 days of completion of the well, under any circumstances; it is part of the permitting requirement and is a lease requirement as well. But even if the drilling is on nonleased land, the same requirements apply, as part of the permit. Similarly, seismic data shot over state lands must be submitted to the state. A significant difference regarding the program on state lands, however, is that it allows [DNR] to show that data to other parties; that was designed in anticipation that the data would have value in promoting exploration in a competitive sale. Number 2957 MR. MYERS returned to the basin's history, noting that he'd been part of ARCO's exploration team when it drilled that well. He explained that [ARCO] was actually looking for oil, but the basin isn't oil-prone; he suggested the same was probably true for Unocal. He then said he likes the "characterization" of the basin, and believes there is a positive market there, as well as a very large long-term market if there is a gas pipeline. Mr. Myers said he is encouraged by Andex Resource's exploration plans. He added, "It's one of the basins we've had our eye on a long time in the state; it's trying to promote activity. ... So we're moving ahead with the exploration license." [Comments about timing were cut off by the tape change.] TAPE 02-4, SIDE B Number 2924 REPRESENTATIVE JOULE asked Mr. Dodson whether his company is looking at any part of the state other than the Nenana basin. MR. DODSON answered in the affirmative. He said the two areas of greatest interest after this would be Yukon Flats and the Susitna basin, in a possible joint venture with Forest [Oil Corporation]. REPRESENTATIVE JOULE inquired whether this would allow other small independents to perhaps look at other areas. For example, has a company done anything in the Bethel area, a highly populated rural area where energy costs are extremely high? MR. DODSON replied that he understood the [federal] Minerals Management Service (MMS) was looking at trying to license federal lands in the Norton basin, to his recollection; beyond that, however, he didn't know of any company efforts to "work" that part of Alaska. Number 2865 CHAIR OGAN informed Mr. Dodson that the committee plans to hear from the independent companies that are moving to Alaska and operating in the state. It would include discussion of what those companies' plans are, as well as what the state can do to provide a modicum of ease for them. To that end, he invited Andex Resources to participate in an overview and to think about incentives for such companies to do business in Alaska. Number 2813 REPRESENTATIVE JOULE asked about communities that would be impacted by this. MR. DODSON answered that Nenana and Minto would be most affected by the license area Andex Resources has asked for. He reported that he'd gone to a meeting at the offices of Doyon, Limited, that included people from village corporations and from the communities of Nenana and Minto. The general viewpoint in Nenana is "very, very positive," with a desire to see this go forward and to have this gas supply available, he said. However, people in Minto are "not opposed, but they are nervous," primarily about disturbance of traditional lands, whether Native lands or state lands, on which the people have depended for food for a very long time. MR. DODSON reported that in response to those concerns, Jim Mery of Doyon, Limited, had asked him to coordinate with Marathon [Oil Corporation] for a tour of its "Deep Lake gas find" on the Kenai Peninsula; Mr. Mery went on that tour and will follow up in late March with a tour of that same gas facility with people from Nenana and Minto. Mr. Dodson suggested that once people have a chance to see the rather minimal impact of the wellhead and buried pipeline coming out of it - with not an enormous amount of surface disturbance - they will be favorable toward the project. REPRESENTATIVE JOULE agreed and remarked that education is always a good thing. Number 2670 MR. DODSON returned attention to the EIC program. He specified that Andex Resources believes the logic for the creation of the exploration incentive credits in the first place still exists; the company is just asking that the program be extended three years. He indicated there should be an opportunity to take advantage of it, since no one has even applied for one of the credits under the program. In response to a question by Chair Ogan, Mr. Dodson affirmed that his company absolutely would want to apply for an EIC. "We do plan on going forward with exploratory work out there," he added. Number 2633 CHAIR OGAN mentioned the policy call that the committee needed to make, and he referred to the director's testimony. Acknowledging that the discussion had pertained to both HB 307 and HB 308, he reminded members that HB 307 just extends the date of the program. CHAIR OGAN asked whether there was further testimony; none was offered. Number 2573 REPRESENTATIVE DYSON surmised that because the committee hadn't heard from others in the industry, it meant they had no reservations about the bill; he expressed hope that it was so. CHAIR OGAN pointed out that the oil industry generally pays attention and that there was proper notification. Number 2514 REPRESENTATIVE GUESS moved to report HB 307 out of committee with individual recommendations and the accompanying fiscal notes. There being no objection, HB 307 was moved out of the House Special Committee on Oil and Gas. HB 308-OIL/GAS LEASES; DISCOVERY ROYALTY CREDIT [Contains discussion of HB 307] CHAIR OGAN announced the final order of business, HOUSE BILL NO. 308, "An Act extending to discoveries of oil or gas in the Tanana River drainage basin the discovery royalty credits that are authorized for lessees of state land drilling exploratory wells and making the first discovery of oil or gas in an oil or gas pool and for licensees under oil and gas exploration licenses making the first discovery of oil or gas in an oil or gas pool that convert those licenses to oil and gas leases." REPRESENTATIVE FATE, sponsor of both HB 308 and HB 307, asked Jay Hardenbrook to present HB 308 to the committee. Number 2449 JAY HARDENBROOK, Staff to Representative Hugh Fate, Alaska State Legislature, read from the sponsor statement, with a few changes, as follows: House Bill 308 will provide that a royalty discovery credit such as allowed for Cook Inlet oil and gas will be made available for the Tanana River drainage basin. This allows companies drilling for oil and gas in the area near Nenana, as well as throughout the Tanana River drainage basin, to be on the same royalty footing with those companies producing in Cook Inlet. Once again, interest in this basin is being dusted off, and new information and technology raises the potential for oil and gas discovery in the Tanana River drainage basin. This will also be a huge boost to rural Alaskan economies, and the economy of the state as a whole, if oil and gas are actually found in commercial quantities. Number 2380 REPRESENTATIVE FATE reminded members that much of the discussion of HB 307 earlier in the meeting pertained to HB 308 as well. Noting the [state] budget crisis, he mentioned "development in a very proper and environmentally sound way" for resources found in Alaska; he said this is simply another method of trying to create incentives "to do just exactly that." Number 2330 MR. HARDENBROOK, in response to Chair Ogan's request for a "walk-through" of the bill sections and the justification, noted that he hadn't brought his sectional analysis. He explained, however, that the whole bill basically just adds "the Tanana River drainage basin" wherever [the statute] says "Cook Inlet" for the royalty credit. Mentioning that the Twentieth Alaska State Legislature had placed a royalty amount of 5 percent on oil and gas, he added, "For this, all we have done is extended that to the Tanana River drainage basin so that they can also have that same credit, given that petroleum is found in paying quantities." Number 2286 CHAIR OGAN offered his understanding: "They want an exploration incentive credit [EIC], which they could get up to $5 million; and now, on top of that, if they find something, they get 5- percent royalty." MR. HARDENBROOK replied in the affirmative. CHAIR OGAN surmised that it is for a pool or unit of gas, basically. MR. HARDENBROOK said that also extends to the entire Tanana River drainage basin and the Nenana basin, which is where Andex [Resources] has applied for an exploration license. He added, "While it is a very large area, it's a very small part of the entire basin that we're talking about in this bill." CHAIR OGAN said he wanted to do what he could to help Fairbanks "get energy and keep energy," but was a little worried this whole project could result in negative cash flow to the state. There is already a $5-million credit, assuming [the company] applies and is approved; he questioned the wisdom of knocking the royalty down to 5 percent in addition. He pointed out that it costs money to manage these leases, for example. He asked Mr. Myers whether the Division of Oil and Gas expects to get any revenues out of this project, under the best-case scenario, if both these [incentives] are applied for. Number 2175 MARK MYERS, Director, Division of Oil & Gas, Department of Natural Resources, responded via teleconference. He noted that the license is an exclusive right to explore that doesn't involve bonus bids and that foregoes the rentals; it's worth about $10.5 million "under conservative consideration." An EIC is defined at $5 million per project; however, a project isn't defined yet. When the two are combined, "conceivably, you could see one basin, multiple projects, that might consume the entire $30 million." He continued: But let's say that it's half of that - $15 million there - combined with a discovery royalty; that means, as Mr. Dodson said [during that day's hearing on HB 307], that the cash flow to the state might be ... a few million dollars ... per year. So it takes the state a long time to get to [a] revenue-neutral position. Additionally, we would not anticipate that these leases - I'm talking with the Department of Revenue - would pay any severance taxes, based on current ELF [economic limit factor]. So if they paid any, it would be only a few percent. ... If it's gas, if it's oil, ... the rate would vary. But primarily the only direct revenue stream from the state would be local taxes, income taxes, and then the 5-percent royalty share. So ... the chicken doesn't have much meat on it left, if you combine all the programs together.... I think that's a fundamental issue the state has to grapple with: ... I don't believe a discovery royalty credit can be more justified in this basin than, say, Copper River, Susitna, or, potentially, even the North Slope foothills, where the same arguments about economic incentives, need to explore, could be used. ... And you're looking at it, potentially, involving multiple discoveries. It's per pool. So if each one of those, the different wells, [is] in a different pool, the discovery royalty would be given on those. So when you add it up cumulatively, discovery royalty can be very expensive - in the tens to hundreds of millions of dollars over time. Number 2067 MR. MYERS emphasized that this is a big-ticket item. He suggested the question is whether it is what the legislature wants to do, given the current fiscal situation. Conversely, is it a good incentive? Noting that discovery royalty has existed, in one form or another, since pre-statehood days, Mr. Myers said, "It was initially repealed. Again, the new program came in, in Cook Inlet. So there's a lot of history on what the program has and hasn't done that I'd be happy to share with the committee, if and when you're ready." CHAIR OGAN asked whether anyone in Cook Inlet has applied for this. MR. MYERS answered that Redoubt Shoals had qualified. He added, "There was a reduction royalty for six identified nonproducing pools. We estimate the Redoubt Shoals discovery royalty will cost the state about $29 million in lost royalty." Number 2019 CHAIR OGAN said he'd carried, on the House floor, the previous legislation that passed; the idea was that because of declining productivity in Cook Inlet, the time was right for giving such a break to encourage new development there. He asked whether this has ever been done for a basin where there is only speculative development and no history of production. MR. MYERS answered that the program existed in Cook Inlet and on the North Slope before they had production. The original program for discovery royalty [incentives], very similar to this program, was repealed in 1969. However, many existing leases on the North Slope within units are pre-1969 and have retained that right. For example, the state gave a discovery royalty [incentive] at Alpine and now is in litigation with Phillips and BP over a discovery royalty on a 37-year-old lease within the Prudhoe Bay structure. He cautioned about creating a program like this, because it has a huge legacy. He emphasized that the [legal] case in Prudhoe Bay, if the state doesn't prevail, will cost about $20 million in lost royalty, although it is within the confines of the largest oil field in North America, on a lease that is "where the discovery was not made until it was - quote, unquote - 30 years old." Number 1912 MR. MYERS told members he doesn't believe this has been an effective incentive. History illustrates how the state has given away millions of dollars. Nor does he believe it has accelerated exploration or production, he said. The program has involved intense litigation over the years. It also is a very hard program to define in terms of whether something is entitled to a discovery royalty. Furthermore, it simply isn't a high enough incentive to really change behavior, which he said has been learned from long experience. Mr. Myers elaborated: The problem is, if you look at commodity price variation, you look [at] exploration, ... that explorer has to risk lots of factors ... on a "nonsuccess" leg, and then put that calculation into its model. ... And then, if they're successful, one of the big issues is, what's going to be the price of oil or gas? You're [skimming] about 7.5 percent off the total royalty stream of the total production; that's equivalent to about a change in about one dollar per barrel for oil, for example. So if you look at commodity price variation, that explorer has to take in account that that price of oil's going to vary multiple dollars in a year; that uncertainty greatly overcomes any value they would get in discovery royalty. That said, it's still millions of dollars. But if you look at a development project, development projects cost tens or hundreds of millions of dollars to do. So, again, that few million dollars a year has not, at least historically, driven exploration. ... And, again, the evidence is there in terms of the activities; the evidence is there that we're granting these on ... almost 40-year-old leases, in cases. So, again, I guess I have to stress that we are opposed to this program not because we don't like to see enhanced oil-and-gas exploration and development, but we just think this is not an effective tool, and it's historically been proven not to be an effective tool. Number 1790 MR. MYERS pointed out that the state has other incentives and programs, primarily in the royalty-reduction statutes, that he believes are much more effective in dealing with the risk element. He emphasized that discovery royalty is given whether the discovery needs it or not, based on evidence of the first discovery. On the other hand, royalty reduction is tailored: if the project is uneconomic, the state can lower its royalty. He concluded, "So we have the ability, I think, to stimulate that development and to deal with issues of ... a project becoming uneconomic. And ... we can do it with much more precision, with much more proof, and with much more positive impact to the state treasury." Number 1753 CHAIR OGAN asked, "What part of the bill do you like?" MR. MYERS answered that because of the long, troubled history, the "dollars given," and the inability, to his belief, to show that it has actually accelerated exploration and development, he personally doesn't like discovery royalty at all. CHAIR OGAN again indicated that his own previous involvement in legislation affecting Cook Inlet was to try to help primarily with oil development, since [production] was declining there; the policy call was that those fields required some incentive. He said there is a fair amount of competition in [Cook Inlet] now, and suggested some people might disagree with Mr. Myers about whether the incentives had anything to do with that. Regarding the Tanana River drainage basin, he asked whether there is competition or if [Andex Resources] has "applied for all the good stuff." MR. MYERS replied that the application basically covers the entire sedimentary basin, but not the shallow-gas leasing potential for coal in the "shallow horizon." Referring to the intent, he said: I think exploration licensing is a powerful tool because it lets one company tie up an entire sedimentary basin, and that's ... a huge thing, if they can leverage it. The uniqueness of this basin, the positive thing, is it's not very far from Fairbanks; there's already a local market. Should a gas line be created from the [North] Slope, there is a very, very large ability - there's a potential, assuming we have the right access language - that that gas could be put into that longer transportation system. So it has both the elements of being able to serve a small, very lucrative market and the upside potential to serve a much larger ... market. Number 1630 MR. MYERS mentioned the "really positive, good geology" as well as exploration risk. He pointed out, however, that if an exclusive right is given, companies historically minimize risk by farming out [to other companies] or bringing other companies in at a higher rate. He remarked: In an exploration license, it's the perfect situation, where a company can say, "Look at the good [prospect] here; why don't you come in and share my costs or take a higher percentage of the cost, and I'll give you some of the capital in return." Licenses are designed so that it would be very easy to do that. Also, it allows ... that person exclusive rights to explore, so when they convert to leases, they can bull's-eye exactly what they want, ... with a full data set. MR. MYERS warned that the state would get very little money upfront, only the dollar-per-acre initial application fee. He told members, "The competitive nature of the license is strictly the work commitment, which the [company] needs to do anyway to assess the basin. So the money goes into the ground under this program, not in the state coffers. The anticipation is, in the future, the state's going to recover that ... in royalty." He explained: Now, if you take that away by ... spending the money on incentives upfront, whether that [would] be EICs or discovery royalty, ... you're taking away almost all the value of those discoveries to the state treasury, or very ... near. So you end up ... creating an oil- and-gas situation where your prime value is getting that commodity to the market, and it's serving ... that market, not serving the state treasury. MR. MYERS cautioned members that this is a very serious policy call that the legislature has to make. Number 1527 CHAIR OGAN asked about "other modalities" if someone had a marginally economic field, for example; he referred to an unspecified bill several years ago that Representatives Rokeberg and Green had "pushed through." He said: So they could apply to the state for a royalty reduction if ... they laid out the numbers and said, "Look, we've got a project; here's what we think our find is; here's what our economic models are; this doesn't pencil out for us if we don't get this reduction." They have the ability to apply to the state for that; is that correct? MR. MYERS answered: Absolutely, Mr. Chairman. Under AS 38.105.180(j) we have what's called royalty reduction, where the state looks at ... the economics of the project and determines whether it needs to reduce the royalties. Now, it puts a fairly high burden of proof ... on the lessee to demonstrate that. But, again, we think that it's ... very appropriate; we think it's good legislation; it's very appropriate that the state have that flexibility. But it also targets it ... where it's really needed. The problem with other incentives that are upfront is you don't really know if that incentive is needed. ... But, again, the companies would be very foolish not to take advantage of incentives that exist out there; they're in the business to make money. So ... ideally you structure a reduction so you have a win-win situation: the state gets production it wouldn't otherwise get, even though it's willing to forego some of its royalty share, but ... under royalty reduction, you can effectively manage that process, look at the economic data, and make the conclusion very accurately and with precision, to that particular development, rather than on a very broad basis, as the other incentives are. Number 1413 REPRESENTATIVE FATE asked: How do you compare the new discovery incentive in other areas of the state, including Cook Inlet, where ... they're aggressively looking for new gas, including the North Slope and everywhere else, really, because of the popularity of gas? Does that discovery incentive cost the state "x" number of dollars, and then can you compare that loss to the state to what's perceived as a small potential in the Nenana basin? ... How are those losses comparable if, in fact, ... at this time in exploration that incentive is still utilized on the North Slope and in the Cook Inlet? MR. MYERS replied that each discovery royalty [incentive] is customized in the sense that it refers to an individual pool or "additional accumulation." It depends on the economics of that additional accumulation, if it is found. Basically, it lowers the state's royalty share from 12.5 percent to 5 percent; it is a reduction of 7.5 percent of the oil and gas produced that would normally go to the state. The effect is a direct decrease in the royalty cash flow to the general fund of the state treasury. The amount [of decrease] depends on how it is calculated. He offered an example: If you look at the Fairbanks market, and similar to Mr. Dodson's statement [during that day's hearing on HB 307], he said the state would receive about $2 million a year; it would then not receive about $3 million a year out of that. So that would be ... sort of the relative effect of that, ... and it would be for a ten-year period from the date of discovery. If it took you three years to bring it online, say, that discovery royalty would only run for seven years; so in that example, it'd be about $21 million. It's not quite ... 3-to-2, but it's 7.5 percent, and the state gets 5 percent. So basically, under the analysis by Mr. Dodson, it would be about $2 million. MR. MYERS told members it depends on the wellhead value and the final delivered-commodity price. He also indicated agreement regarding the size of market Mr. Dodson had mentioned initially. He offered that the upside is that it wouldn't be just a local market, but would be a long-term market with a gas line, assuming proper access language is written into the pipeline [agreements]. He said the number could go up significantly if there were multiple discoveries in the basin and a higher demand for gas than just the local market. Number 1192 REPRESENTATIVE FATE indicated part of his previous question had related to comparing what Mr. Myers had just explained to the loss that could be incurred both in Cook Inlet and on the North Slope, provided that new discoveries take place there, because of the current intense exploration. He said it isn't just a loss in one small basin, but is a potential loss in the rest of the state. He asked whether that is correct. MR. MYERS answered affirmatively, adding: We can quantify, sort of, what we know right now. Redoubt [Shoals], we estimate about $29 million of loss in revenue. ... If Phillips is successful, one of the other main fields is Zariski (ph) Point, which is where they're drilling now; so if they were to be successful, that would be ... similar dollars. Some of these are gas fields, and they would have a lesser impact, probably around ... the $5-million-effect range. So, cumulatively, add that up. Number 1121 MR. MYERS specified that on the North Slope, new leases aren't issued with the discovery royalty provision. It would only apply to leases within existing units that are pre-1969; those are still "popping up," like the one he'd mentioned at Alpine that is in litigation. He mentioned other examples, noting that the cumulative [monetary] effect on these large fields isn't much different, because it just applies to production from that one lease. However, what might vary is the netback value of oil. For example, if oil were discovered in the Nenana basin, there would be a netback of perhaps $12 to $17, depending on the price of oil. He emphasized that there would be larger numbers for oil than for gas. He added, "In a new basin, you just can't predict how many discoveries, and you hope for the most." MR. MYERS answered Representative Fate's question by reiterating that discovery royalty is a very expensive program for the state, and that "we just don't think it's delivered ... its promise of accelerating exploration and development." Regarding the argument that it has spurred exploration, he countered that the level of the incentive [relative to] the cost of developing a field is almost miniscule compared to the variation [of the] commodity price, and that the $2 or $3 million dollars a year a company gets from a discovery royalty isn't enough to change its development behavior "on most fields that we've seen." He added, "We can go back historically, from '59 on, and make that case very strongly." Number 0981 REPRESENTATIVE FATE asked whether Mr. Myers nonetheless believes the discovery incentive would encourage going into basins in Interior Alaska that are even more isolated than the Nenana basin. MR. MYERS answered that he believes the exploration licensing program is the tool doing that. For example, currently there is a license in Copper River; there are two applications in the Susitna basin and one in the Nenana area; and Mr. Dodson and others have expressed interest in the Yukon Flats area, another basin that is both oil- and gas-prospective. All those are along the route of a proposed gas line, he noted. MR. MYERS told members that economic opportunity overall - and not incentives - is what drives exploration for large commercial developments; that includes the ability to commercialize those exploration opportunities, whether to a local market the size of Fairbanks or to put into a larger pipeline for distribution. By contrast, he noted that the problems with dealing with a small village and its energy needs, and drilling dedicated wells, is much more problematic because the economics simply are not as good; he suggested perhaps targeting some of the shallow-gas legislation or incentives there. He continued: With that said, I think [the] exploration license is a very, very powerful incentive, because ... I don't know very many places in the world where you can lock up a very prospective basin near a market for $500,000 and then have the ability to selectively convert to a lease at 12.5 percent and pay virtually no severance tax. ... Those are all very, very positive things for development. Again, I'm not saying ... that they aren't appropriate in this case; I believe they're appropriate and, again, I think the exploration license program is doing what it wants to. Number 0815 MR. MYERS said these are some of the "better looking" sedimentary basins. Mentioning two licenses in Susitna "covering most of that basin," a 500,000-acre license already issued in the Copper River basin, and "a license expected to be issued here in October," he said, "If Yukon Flats is covered, a lot of the prospective sedimentary basins will be already under license." He reiterated that the program is doing what it is supposed to do. He mentioned rising gas commodity prices and renewed interest. MR. MYERS offered his belief that it is his division's job to heavily promote exploration and competition, where possible. He said, "I believe we can sell these licenses, we can see actuation activity and development. Part of it's just getting the word out, and part of it is just the change in economics and the potential for long-term ... gas sales from Alaska to the Lower 48." Mentioning earlier, unsuccessful rounds of exploration in these basins, he said that [lack of success] was largely due to looking for oil. With gas, however, there is a whole new emphasis for exploration. He added that it is positive and that he certainly doesn't want to take away from the efforts of Andex Resources to explore in the basin. He concluded, "But we have to recognize that, I believe, we have better economics than we did in the past and that exploration licensing already provides that tool to accelerate that exploration in the basin." Number 0697 MR. MYERS, in response to a question from Chair Ogan regarding acreage for gas versus oil, reported that currently under license or proposed for licensing is over 2 million [acres] for exploration licenses. There is approximately an additional million acres for shallow-gas leasing. He agreed it is a huge quantity, and suggested Jim Hansen, who was there with him, could look up the number of acres under conventional leasing [for gas]. He added, "It's more than that, but they're getting to be pretty similar." CHAIR OGAN referred to a recent overview and recalled hearing that there was almost as much shallow-gas activity as there is total licensing for oil. MR. MYERS answered: Mr. Chairman, we leased last year 1.6 million acres on the conventional program, so we have about a million ... with the coal bed. ... So in the same timeframe - and you would (indisc.) shallow-gas leases, assuming we grant the licenses next year - we will issue more acreage, undoubtedly, in these programs than we ... do in our conventional programs. Number 0584 REPRESENTATIVE GUESS requested confirmation of her understanding that Mr. Myers was testifying that, in general, discovery royalty is not the best policy, that it doesn't matter where it is, and that other existing tools do a better job. MR. MYERS said Representative Guess had heard exactly right. He commended her for her summary. Number 0508 JAMES B. DODSON, Executive Vice-President, Andex Resources, L.L.C., came forward to testify on HB 308. He told members he thinks discovery royalties absolutely are an incentive to exploration. He mentioned discovery royalties applied in the early days of Cook Inlet and the North Slope. He continued: I agree with director Myers that one of the things that you can't wring out of your risk profile when you run your economic model for drilling a well is commodity pricing, which means that everything else that you can nail down the risk on - everything else that you can reduce your risk by - you should do. And reducing the royalty certainly would be an incentive for us to go from shooting seismic [data] to drilling a well. And I think it's axiomatic that ... if adding 7.5 percent to the royalty - say, taking it to 20 percent - would be a disincentive to drilling, I think it's similarly axiomatic that reducing the royalties by 7.5 percent is an incentive to drilling. I absolutely think that's true. MR. DODSON highlighted another important issue. Cook Inlet was granted a 5-percent royalty in order to try to increase supply to the Anchorage area, whose people pay much less for energy than the people of Fairbanks do. He asked, "Why wouldn't Fairbanks be given equal dignity with Anchorage, and why wouldn't the Nenana basin be given equal dignity with the Cook Inlet?" He suggested that policy decision for Anchorage should apply equally here with regard to Fairbanks. Number 0328 MR. DODSON, regarding the cumulative effect of exploration incentive credits (EICs) and a royalty reduction, told members the EICs remain discretionary with the commissioner [of DNR], depending upon how much the commissioner thinks the information gained is of value to the state. There could be no EIC, he indicated. He added, "What we asked for under House Bill 307 was simply a longer period in which to ask for those exploration incentive credits. They do not become legally mandated. They're simply an extension of the time ... during which we can ask for them." MR. DODSON noted that people in Fairbanks pay more than twice as much for home heating and energy than people in the Anchorage area. He emphasized that although there is a need to increase the energy supply and decrease the cost in Fairbanks, Anchorage is the one with this advantage. Number 0197 MR. DODSON offered a typical rule of thumb that 50 to 67 percent of the price at the "burner tip" doesn't show up at the wellhead; if gas sells to a homeowner for $3.60, then $1.20 to $1.80 shows up at the wellhead. Therefore, even if gas sells for $6 at the burner tip, he believes it still translates to about $2 for natural gas at the wellhead. He said he doesn't know that there is an enormous amount of additional value "that we might realize for gas sold into the Fairbanks market." At the end of the day, it must compete with heating oil, and must be cheaper. He told members: The royalty reduction we're asking for is just equivalent to that granted under the 1996 statutes in Cook Inlet. We're not trying to create something in the lease that ... created these problems from leases 30 or 40 years ago. This is just the same application as there would be in the Cook Inlet, trying to increase local supply, in this case, for the Interior as opposed to Anchorage. Additionally, Director Myers indicated we probably would not be paying severance tax on wells out here. And as I read the severance tax [regulations] and the economic limit factor under those, that would be true if our wells were each producing ... under 3 million cubic feet of natural gas per day; ... if that were the case and we were trying to serve 60 million a day to Fairbanks, we would need to drill some 20 wells plus probably 8 or so in reserve. ... Even if we drilled that many, we might get them down to $5 million apiece because of the volume. That's a $140- million investment to try to serve Fairbanks. The flip side of that is, if the wells are more productive - if they're moving, say, 8 million a day - they would be paying severance tax ... to the tune of about 5 percent ... of the gas produced. TAPE 02-5, SIDE A Number 0001 MR. DODSON said there a lot of wells out there with 3 million cubic feet a day or less of deliverability per well. He told members, "We think that the incentive is justified." He reiterated that it grants "equal dignity" to Fairbanks and Anchorage to try to increase energy supply and decrease the cost, and to the two basins that would supply the two biggest cities in Alaska. Number 0065 CHAIR OGAN again recalled that the policy call when the Cook Inlet legislation passed was that there was a "maturing field"; he acknowledged the major royalty differences for oil versus gas because of the value. Number 0139 REPRESENTATIVE GUESS asked Mr. Dobson what [his company's] reason is for taking this approach of "adding yourselves to this statute, which seems - at least from the state's perspective - fundamentally flawed, ... rather than working under the section that [Mr. Myers] had discussed, where ... the commissioner may provide for an increase or decrease or otherwise modify the royalty to allow production that would not otherwise be economically feasible." She added, "It seems, even under that case, you might get less than 5 percent, and maybe that's a better path than something in statute which is a set amount." She again asked why this approach is being asked for. MR. DODSON replied: I think ... it's certainty and avoiding an ad hoc decision on every well that we want to go and drill. If ... we knew with certainty that if we find a discovery and - under the '96 statute that applies in the Cook Inlet - could certify to the Division of Oil & Gas and the commissioner of [the Department of] Natural Resources that this is a new discovery, we're certain as to what our royalties are. And ... 7.5 percent of the production for the first ten years - ... that's another important point: ... this is not forever; this is for the first ten years of production - makes a difference in terms of whether or not you make the decision to drill a well. And if ..., for example, I'm ready to propose a well to my management, and I put together an economic model and I agree with the director that commodity prices move around and your drilling costs can escalate and you may be delayed in getting your pipeline on and a lot of variables are in there that can move around, the more that I can make certain, the better off I am in getting a decision to go forward with a well. And if I can say with certainty that if we make a discovery, the royalties will be 5 percent - they are not subject to an ad hoc decision post-drilling - then I'm in a much better position to get an affirmative answer on going ahead and risking the dollars necessary to drill a well. ... Even with the seismic shot, this is probably a "20- percent chance, 25-percent chance of success" kind of a venture. Most things that you try that are this risky, that are this exploratory, don't work. So the more you can do to improve your risk-to-economic [ratio], the better off you are making a decision to go on a well. Number 0385 CHAIR OGAN thanked Mr. Dodson and asked whether there were further questions; none were offered. He asked whether anyone else wished to testify; there was no response. He then announced his intention to hold HB 308 over. REPRESENTATIVE FATE thanked Mr. Myers and Mr. Dodson for their testimony, which he said had been most educational [even] outside the parameters of HB 307 and HB 308. CHAIR OGAN concurred and again invited Mr. Dodson to present an overview to the committee. He thanked all participants. [HB 308 was held over.]
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