Legislature(2001 - 2002)
02/01/2002 01:15 PM 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 307-OIL/GAS EXPLORATION INCENTIVE CREDIT Number 0010 CO-CHAIR MASEK announced that the first order of business before the committee would be 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." Number 0212 REPRESENTATIVE FATE, speaking as the sponsor, explained that HB 307 is an extension of a bill already in existence that sunsets in 2004; this bill extends the life of that bill to 2007. He explained that this bill provides an exploration incentive credit (EIC) to the industry. He said the [EIC] already exists and this bill extends the incentive for [an additional] three years. He said the [EIC] allows a company to explore in the Nenana basin, which he suggested has an extremely high potential. Currently, there is only one company to bid on the area and therefore only one explorer in the Nenana basin. He indicated that this legislation would allocate money to be used as an incentive credit toward future royalties. He noted that Mark Myers was on teleconference and could provide the details. REPRESENTATIVE FATE referred to a previous debate in the House Special Committee on Oil and Gas; he suggested that the committee was neutral on this bill and that is why it was moved out. Number 0389 REPRESENTATIVE GREEN asked if Mark Myers could explain what the legislation is granting with the EIC. Number 0401 CO-CHAIR MASEK announced that Representative Kapsner had arrived. Number 0434 MARK MYERS, Director, Division of Oil & Gas, Department of Natural Resources, testified via teleconference. He informed the committee that HB 307 does extend the economic incentive credit program that was passed by the legislature in 1994. He said the [EIC] had a ten-year period, which is slated to sunset in 2004. He explained that the EIC grants a credit against either royalties, taxes, lease-bonuses, or rentals; the credit can be up to 50 percent of the cost of certain activities. Those activities include: drilling wells, exploration, stratigraphic test wells, or geophysical information such as seismic data. MR. MYERS said the [EIC] can be up to 50 percent of the cost of the exploration well, the stratigraphic test well, or the seismic data on "unleased" state land; the [EIC] can be up to 25 percent on federal or Native-owned land. He explained that the program was designed to limit the total exposure to $30 million; an individual project, which was never defined, can get up to $5 million total in credit. Number 0576 MR. MYERS suggested that the legislative intent behind the program was fundamental for the state to acquire information that it would not otherwise be able to acquire regarding oil and gas. He said the state takes that data and shows it to third parties to bolster competition in the industry. He offered some history about this bill. He said this [legislation is based on a] stratigraphic test well program, which is a program that companies participate in before the exploration season or exploration in an area. MR. MYERS explained that the [exploration company] would go into an "unleased" basin or area, drill a well as a consortium among 10 or 12 companies, for example, and drill deliberately in a nonprospective area where the company can understand the representative geology. Since [the area] would be "unleased," the [exploration company] would not want to find commercial hydrocarbons, but would want to test and see what the geology looked like. He said the [exploration company] would take that information and use it in its evaluation prior to a competitive lease sale to determine where and how much it wants to bid. Number 0670 MR. MYERS explained that the concept of the [program] was that prior to a lease sale, an [exploration company] might drill in some of the Interior basins [using this type of] test. He said there wasn't the same interest that there was in the past, especially in the offshore basins where a dozen different companies are participating. He said in those cases the state could accelerate an [exploration company's] drilling one of the wells or subsidize the drilling of the well up to 50 percent on unleased state lands, or to a lesser extent on federal or Native lands. Having the criteria for evaluating this program is what is valuable about this information to the state. MR. MYERS said Andex Resources, the company interested in [drilling] in Nenana basin, has proposed [obtaining] an exploration license from the state. He said the [legislature] enacted this program in 1994; it allows exclusive exploration rights to an individual company for up to 5,000 acres. He explained that Andex Resources has applied for such a license and it is anticipated that if all goes well the [license] will be granted over [a period of time]. MR. MYERS said in doing this, the state has to issue a best- interest finding, which means it is in the state's best interest to issue the license. He explained that a license is different from a conventional lease because the state receives a one-time application fee of $1 per acre, and then receives no bonuses or rentals from the land. MR. MYERS said the state receives a work commitment from the company, which is the competitive part. He explained that when a company applies for a license the state publishes information that announces that the license is available and [accepts bids on which company] will spend the most money on legitimate exploration activities. The company will typically bid so many millions of dollars; Andex Resources bid approximately $2.5 million, which doesn't go to the state but instead goes into its exploration program. He said in the areas that the state had deemed that exploration wasn't rapidly occurring or where it wasn't going to have an area wide sale, it had a mechanism to offer a large amount of acreage as an incentive to development. Number 0808 MR. MYERS said in a typical case the exploration license is a very positive incentive; in this case, it is estimated to be worth about $10.5 million in terms of what the state would normally have gotten if it had received its minimum $5 bid per acre and had received the normal rentals during the period of a typical seven-year license. He reiterated that he thinks it is a good inducement. He expressed enthusiasm because there is a current applicant that is in the process of attempting to obtain a license. MR. MYERS explained that the way the exploration credit would apply in this particular case. Prior to drilling a well, the applicant would come to the state and announce that it was requesting an EIC. He said the state would then have to [review it] and the Department of Natural Resources (DNR) commissioner would determine whether the information was of sufficient value to the state that it wanted to contribute to the cost of the well. The commissioner would have the discretion to give up to 50 percent [EIC] on leased state land or 25 percent of the cost of the well if it was drilled on privately owned or federally owned land; the cost will be determined on a footage basis by the well or by line-mile or square mile on the seismic data. Number 0914 MR. MYERS reiterated that if the state values the information, it could contribute to the cost of the well. He suggested that the state has other advantages such as being allowed to show the data to third parties, which in some cases could be a significant value to the state. If the well was drilled on "unleased" land and the state was going to have a conventional sale in the area and wanted to promote the well, it couldn't give the data to a third party but it could show the third party the prospective seismic data, well data, etcetera. He said the challenge in regard to an exploration license is that another company could not be promoted into the basin because of the exclusive exploration rights given to the third party. Number 0988 MR. MYERS explained that the EIC would also be valuable if the state valued the information on a well drilled on privately owned land or federal land for which the state would not typically receive the data for 24 months. He said on state land the state gets the data within 30 days after the completion of the well, and it gets the seismic data after it is shot via the permit to shoot on state land. He said on privately owned land the state does not get the seismic data, but that data may be of value to the state, and it may want to pay for it. He said on private lands, the [EIC] would either accelerate the state's getting the data, if needed, or would allow the state to acquire seismic data that it wouldn't otherwise receive. Number 1016 MR. MYERS explained that this program has never actually been used; in the last seven years [DNR] has received two applications for an EIC under this program, one was for seismic data regarding National Petroleum Reserve-Alaska (NPR-A) by Anadarko [Petroleum Corporation]; the state looked at the request and said, "Yes, we're not going to get this data [otherwise]. It's important to our state lands immediately adjoining NPR-A." Therefore, the state offered an EIC of 18 percent to Anadarko. He said Anadarko decided it did not want to accept the EIC because of the state's ability to show the [seismic] data to third parties however. He explained that in the other case, some geochemical data was being shot in an area where the state had some great seismic coverage and didn't think the data was important enough to grant an EIC, so it was denied. He said the $30 million in the EIC fund is still fully there and intact; to date, the state has had no applications for an EIC for wells. He stated that DNR is neutral on this bill and believes it is the [committee's] policy call on how this bill is used. Number 1190 CO-CHAIR MASEK asked if this bill is applicable statewide to [those wanting to explore] beyond the Nenana basin. MR. MYERS said yes, it would certainly apply statewide as well as to federally and privately owned land. He said one of the challenges with this bill, in applying it to a licensed area, is that [DNR] would have to [determine] whether the value of that information is significant to the state. He reiterated that that was the intent of the program. He commented that the intent was not to decrease the risk in the drilling of commercial wells; rather, it was all focused toward the value of the information. He suggested that if the state wants the program to be applied differently in order to stimulate commercial development, then it should set the intent to limit the risk to the party drilling. He commented that the intent is the value of the data and the legislative history really strongly supports that. Number 1204 REPRESENTATIVE GREEN explained that he'd asked for that review because several members of the committee were not present in 1994 or [may not] have understood what this bill did. He asked if it was true that several basins have not [been drilled] and as a result there is a lot of speculation about what those basins might have. He suggested that the remoteness from [transportation] to market may be a deterrent to using the [EIC]. He reiterated that the [committee] would like to keep this bill if there is a [company] that would like to use it, especially a [company] within proximity to an existing pipeline to be able to get it to market if it does discover something. Number 1265 MR. MYERS concurred with Representative Green's comment. He explained that there have been positive indications. Currently, DNR has three applications for exploration licenses: two in the Susitna basin and one in the Nenana basin; DNR has also granted a license in the Copper River basin. He said approximately 2 million acres is involved in these licenses; the pattern indicates these are all primarily gas-prone basins. Number 1389 MR. MYERS suggested that they are pretty much along the route of a prospective pipeline, near the Anchorage Bowl or the Fairbanks area, where there are local markets that should have a demand for gas, either now or in the future. He suggested that this is a positive indication that the market is driving this and that the expectation of a commercial gas line is driving a new round of exploration. MR. MYERS commented that one of the encouraging things about the Nenana basin, in particular, is that the market in Fairbanks is right for the gas; the geology of the basin is very "prospective," and right now gas commands a very high price. He said liquefied natural gas (LNG) shipped to [Fairbanks] gets about $8 per mmBtu [million British thermal units] or million cubic feet (mcf) at the burner tip, which is a very lucrative price. He reiterated that the economics are there for gas exploration in the basin. He said the basin is not that far from the Fairbanks infrastructure, and he thinks that there is a very commercially viable opportunity in the Nenana basin. He commented that the license will help that process a lot. MR. MYERS said the question [involves] how much "incentivizing" needs to be done versus how much will be done naturally by market forces. He said in regard to economics, at current prices there is a netback of about $4 a mcf to the wellhead, which is itself a great incentive if the basin has commercial gas. He explained that the basin is about 20,000 feet deep with lots of coal; DNR has good geochemical data to support that it has generated the gas and there are good reservoir rocks. He reiterated that it is a very prospective basin. He said DNR was encouraged by it back when it did the final state land selection and therefore picked up as much of the acreage as possible in the basin. He said the positive news is that exploration will occur in this basin; a license is a great tool to get it there. He indicated that licensing is in progress for the Susitna basin, as well as potentially to the north in the Yukon Flats where both oil and gas may exist. MR. MYERS suggested that earlier rounds of exploration in these basins stopped mainly because there wasn't really a market for gas. He said [companies] were looking for commercial oil, and in these cases the test wells did not suggest good oil source rocks in many of these basins. Number 1459 REPRESENTATIVE KERTTULA asked if the original policy behind using exploration credits was so the state could get more information, which it could then show to third parties, and have a better understanding of what was happening in those areas. Number 1476 MR. MYERS answered yes; it was the value of the information to the state. He explained that at that point in time the exploration-licensing program [did not exist]. He said if this information is made available before a competitive sale, it might increase the level of activity and interest. He suggested that the data is valuable when the state needs that data to assess land selection or other purposes. The value of getting data that it would not otherwise receive on private lands or federal lands was also important. Number 1500 REPRESENTATIVE KERTTULA asked if the exploration licensing statute that Mr. Myers had explained was in place. MR. MYERS answered yes. Number 1514 REPRESENTATIVE KERTTULA asked if that allows $1 an acre and if the license can be converted to a lease if a discovery is made. MR. MYERS explained that it is $1 a acre for the state, so that on a 500,000-acre application an [exploration company] would pay a $500,000 application fee. He said the [exploration company] commits to a certain-million-dollar [amount] of exploration expenditures; DNR doesn't dictate what the expenditure amounts are, which just have to be reasonable exploration costs. He said those costs could be for wells; seismic, gravity, or magnetic data; or geologic fieldwork. He explained that that is the competitive part: the party that bids the highest level of work commitment, which is based on dollars, is the party that wins the competitive part of the bid. Once the party has the license, it has a negotiated period with DNR for that license, typically, five up to a maximum of ten years; at the end of ten years, it has the right to convert the entire amount of acreage into a lease. He explained that the lease term is at 12.5 percent. At that point, it pays rentals, but no bonus; it's a noncompetitive program which allows the company to explore. He mentioned exploring to "high-grade" the acreage that it wants or taking it all in a noncompetitive [way]. He reiterated that this is a good tool to see for exploration in the Interior basins. Number 1603 REPRESENTATIVE KERTTULA asked if this would add onto the legislation already in place. Number 1610 MR. MYERS answered that she was correct. He said it is also an existing program; up to [the year] 2004 both programs could be used. He pointed out that the issue that had not been addressed is that it's clearly on state land, unleased acreage. He said a license is not really a lease; it still [gives] exclusive exploration rights to the party. He said DNR is checking with the Department of Law to make sure that a license is not a lease; the preliminary view of it is that they are distinct. He suggested that it would allow DNR to give extra credit on a license. He reiterated that it's still preliminary. Number 1651 REPRESENTATIVE KERTTULA asked how much is known about certain areas of the state such as the Tanana River basin. She commented that she had heard testimony that there was a high potential there. She asked if her understanding was accurate. Number 1668 MR. MYERS said there are two wells drilled into the basin. One was drilled by Union Oil Company of California (Unocal), and the other was drilled by ARCO Alaska, Inc. (ARCO). Following a competitive sale in 1982, ARCO drilled the last well into the basin. He said state sold a fair amount of acreage in that sale; there have been competitive sales. He explained that at that point in time the companies were looking for oil; two wells were drilled, one by Unocal and one by ARCO, and a regional grid of seismic data was shot. MR. MYERS explained that the state has that [information] available, which very clearly outlines the basin; there is also gravity and magnetic data that support the belief that this is a very deep basin, about 20,000 feet in depth; it's a very young basin and has good reservoir rocks as well as lots of coals. MR. MYERS said the basin has generated enough geochemical data to suggest that those coals have generated plenty of gas; there is a fairly low likelihood of oil in the basin, based on some potential oil source rocks that are primarily gas-prone source rocks. He said basin [indisc.] very abruptly and has exposures of some of the reservoir and source rocks on the planks of the basin. Number 1749 MR. MYERS said the Usibelli Coal area is an example of those similar rocks exposed at the surface. He suggested that the coals and the sandstones found at Usibelli would make good reservoirs into the basin. He said that basin has generated gas and has lots of good reservoir rocks; the challenge is whether it has a good seal or good tracking mechanism. He mentioned that the regional seismic data has very nice geologic structures on it, large structures; the key elements appear to be there, but it still has an element of risk to it. He said DNR has a lot more data on this basin than on most of the Interior basins because of the wells and the seismic [data]. He said the data was very positive for gas, but not so positive for oil. He commented that he thinks this is why earlier explorers left. Number 1785 REPRESENTATIVE KERTTULA said it looks as though there is not a whole lot of risk there and now there is a market for it. She said the policy debate is about how far the [legislature] should go in terms of giving a break to a company that comes in when it is already known that it is a good area and a ready market. She mentioned that it appears it is going to happen whether the bill is [passed] or not. She asked Mr. Myers for a response. Number 1825 MR. MYERS said if the original intent is the value of the information, then that would be the determinate that the commissioner would have to weigh in deciding what size of EIC is [given]; that judgment can't be made until the locations of the well are known, etcetera. He said the second question is much more difficult, which is when an incentive is effective and when is it "icing on top of the cake." He suggested that the problem with the EIC is that it isn't automatic. The commissioner has discretion to look at those factors and could give 10 percent if he/she thought it was appropriate, for example. It is also difficult to know if the company would explore [because of] or without the incentive. He said in his personal experience, the license itself is a very powerful incentive. He said in his opinion, because a license requires a work commitment, the company will have sufficient data to decide whether it wants to drill; that drilling will largely be based on "prospectivity," based on what is seen in the seismic data and how the geology is tied into that, as well as the company's assessment of the costs of development, building the pipeline, and getting into the market. Number 1921 MR. MYERS said he thinks it is the market forces that drive it, and generally the incentives are a fairly ineffective tool. He said is a somewhat subjective judgment based on his own industry experience and background, rather than someone else's. He suggested that companies would argue that the [EIC] does reduce risks for them. He wondered if it was enough risk-reduction to change behavior; he noted that is always the challenge and the question. He said in this case, the way that he reads the current EIC statutes and regulations, the commissioner would really have to look at the value of the data. He said a license diminishes the ability to use that data to raise competition, so the question is how large a grant [the commissioner] would make, which Mr. Myers said he cannot answer. He said the [commissioner] would have to weigh the individual situation. Number 1959 CO-CHAIR MASEK turned attention to page 1, lines 9-11, which refers to the commissioner and says the qualified applicant must be approved before drilling or geophysical work commences. She commented that that probably has a lot of "weight to carry." She refers to the last part of the bill, which says, "copies of all raw and processed data derived from drilling"; and goes on to say that it's "within 30 days after the completion, abandonment, or suspension of the well." She said there are good safeguards in [place]. Number 2019 REPRESENTATIVE GREEN addressed Representative Kerttula's concern. He said the biggest oil field in North America is Prudhoe Bay, located on the Barrow "arch", which was a highly prospective area. He explained that the North Prudhoe Bay fault has separated the Prudhoe Bay field, which is productive, and another sister field that BP drilled years ago and spent about $50 million on. He said it was the same "arch," the same "trap," and it was barren; there were 13 wells drilled before the discovery of Prudhoe Bay. He suggested that this bill does not give anything; it's just as an incentive that if all of those things that look good prove up, then maybe there is some incentive for an oil company. He said even if things look good, there is still an enormously high risk. He suggested that if the [oil companies] can be encouraged to [explore], then it certainly is in the state's best interest. Number 2103 REPRESENTATIVE FATE thanked Mr. Myers for the time spent on his testimony. He said he didn't want to suggest to anybody that "it's a slam-dunk." He said the belief is that there is a high potential in a basin. He commented that to his knowledge there had never been any three-dimensional (3-D) seismic work done in there, which he said really is the state of the art. He asked Mr. Myers how much 2-D [seismic work] had been done and how that basin was delineated [from] the two wells that had been done almost 20 years ago. Number 2150 MR. MYERS said he doesn't have the exact line-miles, but there were two regional seismic grids shot there, basically far-apart lines just to kind of outline the basin sufficiently to get the fringes of the basin. He said it was 2-D data, which is fairly good-quality data, but it's certainly not adequate to drill a prospect in the basin with any confidence. He said the normal procedure would be to go into the [basin]; depending on the style of trapping mechanism [needed], it would be either a series of closely spaced 2-D lines or a series of 3-D lines. MR. MYERS said the other part of the data is the gravity and magnetic data. Sedimentary rocks are distinguished from igneous rocks in their lower density, and they have a different gravity profile because of that lower density; gravity data outlines the basin very clearly because the reservoir rocks are low-density even when compared to some of the North Slope rocks. He explained that the basin stands out very clearly in gravity and magnetic data; this helps to provide a good model of the basin. He said this is based on some work done in a [capital improvement project (CIP)], in terms of getting the gravity and magnetic data interpreted, which the state did. He expressed confidence and commented that the regional seismic grid is good. Number 2224 MR. MYERS said the two wells did not hit the heart of the basin; the Totek Hills ARCO well was drilled on the fringe of the basin, and the Nenana 1 Unocal well was not drilled in the deepest part. He said it is encouraging that they have good sedimentary sections and good potential reservoir rocks, and that gas shows in the well. He commented that this doesn't mean they have encountered a commercial reservoir. He said the deepest part of the basin has not been tested; any exploration program would go in there and either shoot a closely spaced 2-D survey in the area where they are interested or a 3-D survey if they are looking for stratigraphic traps, which are much more subtle. The [exploration program] would also try to apply techniques that looked for direct indications of hydrocarbons, which can be done in these types of rocks, particularly if there's gas. He explained that the [exploration program] would look for flat spots and bright spots on closely spaced 2-D or 3- D data; direct hydrocarbon indicators are a possibility here for gas. Number 2286 MR. MYERS said all of those would be prudent before a [exploration program] spent between $6 million and $6.5 million per well; it would need to be fine-tuned with seismic [work]. He said the EIC gets the workmen a long ways toward that seismic grid; it probably wouldn't cover all that they want to shoot, but it would cover a lot of it. He explained that the company would have to decide whether it thought it had a commercially viable prospect that came from that data. He reiterated that it was not [guaranteed]. MR. MYERS remarked that the weakest geologic potential is proving a seal. He said the structures, reservoir, and gas are there, but he questioned whether there was a seal to hold the gas inside that reservoir. That is something that 3-D seismic and 2-D [work] would provide more certainty about before drilling [commenced]. He said the other issue is in building the commercial infrastructure; the findings have to be [good] enough to justify building a gas treatment plant, if necessary, and a pipeline from those facilities. He mentioned that these are the kinds of risks that oil companies take. MR. MYERS said one of the positive things that exploration licensing does to accelerate is not only lower capital costs, but allow a large area of exclusive rights; that allows companies to bring in other companies that will pay part of the exploration costs. He offered an example: Andex could share with two, three, or four other companies, giving them a smaller percentage of interest "in the play" for the capital to explore. Number 2360 MR. MYERS explained that that kind of "farming out" of interest is very common; it happens all of the time in the industry, including on the North Slope [presently] and Cook Inlet. He said this is particularly appropriate here, where the risk sharing could be done between companies; it also provides more capital and minimizes the individual companies risks. He suggested that would be a typical model followed in the basins if exploration gets to the drilling station. Number 2396 REPRESENTATIVE KERTTULA asked him if getting the exploration license itself was an enough of an incentive in regard to the Tanana basin. Number 2499 MR. MYERS said that is what he personally believes, although the exploration company may have a very different opinion of that in how it assesses the risk. He explained that at this time, the exploration program license is new. It has only issued one license and is in the process of "this" and two other licenses; the programs need to have a chance to work. He reiterated that the EIC program is discretionary. The DNR commissioner has the discretion not to grant an [EIC] if he/she doesn't think it is appropriate, and the commissioner has the discretion to limit the amount of dollars given in the program. MR. MYERS explained that the difficult part in that determination will be how the [commissioner] assesses the value of that data, because it's not going to promote a competitive lease sale. The [commissioner] is going to have to justify the value of that data under the current intent, which might make it problematic for a large grant of an EIC. He commented that he is not prejudging what the commissioner would or wouldn't do. He said if he looks at the straight intent of the EIC language, he is not sure what the commissioner would decide regarding the application, which would be looked at individually. He suggested that the "flip-side" is that there are other areas of the state where the [EIC] might be of use as well. Number 2487 REPRESENTATIVE KERTTULA asked Mr. Myers in what other areas of the state foresees this coming up. Number 2499 MR. MYERS said he suspected if anything was done on the Tanana basin, then the other basins that have licenses would want equal treatment; the two licenses in the Susitna basin and the one in Copper River would have similar expectations and could make similar arguments. He mentioned the Yukon Flats as an area of interest to the north of a prospective gas line; it is not a lot of state land, but federal land. MR. MYERS said the other Interior basins are more difficult; they're farther from infrastructure, pipelines, and large enough markets. In those cases, it would be smaller [companies] wanting to test things such as coal-bed methane on unleased acreage or maybe gas hydrates or some more exotic technology. He suggested it would largely be done as a science experiment, perhaps by the Department of Community and Economic Development or maybe by a Native corporation, for example; it wouldn't be large-scale development. He said places where this is most likely to be seen are along the route, such as a local market like Fairbanks that's large enough to be serviced and has high value for gas. Number 2586 REPRESENTATIVE GREEN moved to report HB 307 out of committee with individual recommendations and the accompanying fiscal notes. Number 2594 REPRESENTATIVE KERTTULA asked for more discussion on it. Number 2609 REPRESENTATIVE GREEN withdrew his motion to move HB 307 out of committee. Number 2614 REPRESENTATIVE KERTTULA said she thought that Mr. Myers raised two interesting points. The first point, she explained, is that it seems the [EIC] is [designed] to give an incentive to companies when there's really a risk, rather than just the state's wanting to get the information. She said she is not really sure how she feels about that, because in some ways maybe the only thing that should be measured is whether the information being gained by the company is valuable to the state. REPRESENTATIVE KERTTULA asked if it is the risk to the company, which she said seems to be a fairly low risk, that [the committee] is worried about. She asked if that is the measure the [committee] wants in regard to the areas around the gas line. She said the second point is the question of what the risk is back to the state: if it's a sure thing or very close to it, then how much money does the [state] stand to lose? She indicated she is not sure if this applies to this legislation or to future legislation. She suggested this may provide several ways for companies to get breaks. She asked if the other committee members had similar thoughts or concerns. Number 2680 REPRESENTATIVE GREEN reiterated that there is risk to the company, not to the state. He said the company would have to weigh that, which is probably the biggest portion of determining whether to spend the money. He mentioned probability and said both are added up and assigned percentage factors. He reiterated his point about the drilling done in Prudhoe Bay. Drilling is very expensive. In drilling wells one through twelve, [the company] lost out, but it was the thirteenth well that hit [oil], by chance. REPRESENTATIVE GREEN reiterated that there are all sorts of risks. The [company] has to first find the "trapment" and then find that it is filled with something. He said the state is risking some amount of money that it might have received, had the [exploration company] gone in there on its own without the EIC. He pointed out that, as Mr. Myers had testified, there were two [instances] when there was a possibility of using the EIC, but they didn't work out: in one instance, the company didn't want to share the information; in the other, it wasn't worth it for the state to [give an EIC] for the information the state would receive, so it didn't go forward. Number 2769 REPRESENTATIVE GREEN reiterated that it is no guarantee that the EIC would be given; it is at the commissioner's discretion. He indicated that it could be the exploration company that does not want to pursue the EIC due to a provision requiring it to share that information. He said information is available on the two wells that were drilled and nobody has come forward in the Tanana [basin]. He suggested that there are many concerns that need to be addressed before a company will go in and spend money; if the [legislature] can ease some of those concerns, it might result in a huge payback to the state. He said if the [exploration company] goes in there and finds something, then there would still be land available in the basin for conventional leasing. Number 2809 REPRESENTATIVE FATE reiterated Representative Green's statement that the risk is huge. He said the [committee] failed to assess the deliberations of the boards of directors of these corporations, including small corporations, when they [pursue exploration]; they have to make the decision of whether or not to spend $6 million on one hole. He said the 3-D seismic [work] is extremely expensive; the board has to determine whether or not it has the money to do 3-D seismic [work]. Representative Fate asked how to weigh the risk of not developing an environmentally clean resource against the risk of the [exploration company's] not drilling. He suggested that this presents a big question for the state. He said the [state] runs the risk of no development if there are no incentives and still wants to have that incentive produce revenues to the state later on. He said these are the types of things he is concerned about. He suggested there are certain types of incentives that dig so deep into the credits given, eventually the state will not recapture a great deal of funds; then it may need to be seriously looked at. He said this was not one of those cases. He suggested that this bill is an extension of legislation that currently exists and is going to [result] in a win-win situation. Number 2917 CO-CHAIR SCALZI drew attention to the original intent of the bill and the question of why the [committee] was looking at reauthorization. He said the [discretion] that the commissioner has on the level of risk assessed to each individual area satisfied him somewhat. He said that although the argument could be that the commissioner is not going to be as stringent as he/she should be, that is something that the [legislature] is going to have to put in the hands of a representative of the state. TAPE 02-4, SIDE B Number 2975 REPRESENTATIVE MCGUIRE commented that she could see the value to the state in collecting the raw and processed data that is derived from the [stratigraphic] test wells. She indicated that there is risk and the EIC could be offered as an incentive. She suggested that the value of that data would be of good value to the state. She said the incentive is the development of new sources of energy for the state, particularly in rural Alaska. She suggested that this bill presents an opportunity [for development]. She commented that this is some of the cleanest and most environmentally friendly energy [available]. Number 2907 REPRESENTATIVE GREEN reiterated Mr. Myers' comment that the basin has a huge amount of sedimentary rock as opposed to igneous rock in which oil is not found. He said sedimentary rock is an encouragement because both oil and gas hydrocarbons can be found in it, [but there is no] guarantee. Number 2875 REPRESENTATIVE KERTTULA said this bill in and of itself really isn't such a concern. She explained that if the next bill comes along and it looks as though the three [bills] work together, however then she would start to have a much bigger concern. She said while development should be encouraged in areas that present a return back to the state, it is hard to know if [this is an incentive]. She commented that she is satisfied with the current language that the commissioner's decision has to be based on whether or not the [EIC] provides worthwhile information to the state. Number 2805 REPRESENTATIVE GREEN moved to report HB 307 out of committee with individual recommendations and a zero fiscal note. There being no objection, HB 307 was moved out of the House Resources Standing Committee.
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