03/15/2005 05:00 PM OIL & GAS
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ALASKA STATE LEGISLATURE HOUSE SPECIAL COMMITTEE ON OIL AND GAS March 15, 2005 5:03 p.m. MEMBERS PRESENT Representative Vic Kohring, Chair Representative Nancy Dahlstrom Representative Norman Rokeberg Representative Ralph Samuels Representative Berta Gardner Representative Beth Kerttula MEMBERS ABSENT Representative Lesil McGuire COMMITTEE CALENDAR HOUSE BILL NO. 197 "An Act exempting certain natural gas exploration and production facilities from oil discharge prevention and contingency plans and proof of financial responsibility, and amending the powers and duties of the Alaska Oil and Gas Conservation Commission with respect to those plans; and providing for an effective date." - MOVED HB 197 OUT OF COMMITTEE HOUSE BILL NO. 142 "An Act relating to regulation of underground injection under the federal Safe Drinking Water Act; and providing for an effective date." - MOVED HB 142 OUT OF COMMITTEE HOUSE BILL NO. 71 "An Act relating to a credit for certain exploration expenses against oil and gas properties production taxes on oil and gas produced from a lease or property in the state; relating to the deadline for certain exploration expenditures used as credits against production tax on oil and gas produced from a lease or property in the Alaska Peninsula competitive oil and gas areawide lease sale area after July 1, 2004; and providing for an effective date." - MOVED CSHB 71(O&G) OUT OF COMMITTEE PREVIOUS COMMITTEE ACTION BILL: HB 71 SHORT TITLE: AK PENINSULA OIL & GAS LEASE SALE; TAXES SPONSOR(s): RULES BY REQUEST OF THE GOVERNOR 01/12/05 (H) READ THE FIRST TIME - REFERRALS
01/12/05 (H) W&M, O&G, RES, FIN 02/11/05 (H) W&M AT 8:30 AM CAPITOL 106 02/11/05 (H) Moved CSHB 71(O&G) Out of Committee 02/11/05 (H) MINUTE(W&M) 02/14/05 (H) W&M RPT CS(W&M) NT 3DP 1AM 02/14/05 (H) DP: MOSES, GRUENBERG, WEYHRAUCH; 02/14/05 (H) AM: WILSON 02/17/05 (H) O&G AT 5:00 PM CAPITOL 124 02/17/05 (H) Heard & Held 02/17/05 (H) MINUTE(O&G) 03/15/05 (H) O&G AT 5:00 PM CAPITOL 124 BILL: HB 142 SHORT TITLE: OIL & GAS: REG. OF UNDERGROUND INJECTION SPONSOR(s): RULES BY REQUEST OF THE GOVERNOR 02/14/05 (H) READ THE FIRST TIME - REFERRALS 02/14/05 (H) O&G, RES, FIN 03/15/05 (H) O&G AT 5:00 PM CAPITOL 124 BILL: HB 197 SHORT TITLE: OIL SPILL EXEMPTIONS FOR GAS WELLS SPONSOR(s): OIL & GAS 03/03/05 (H) READ THE FIRST TIME - REFERRALS 03/03/05 (H) O&G, RES 03/15/05 (H) O&G AT 5:00 PM CAPITOL 124 WITNESS REGISTER DANIEL SEAMOUNT, Commissioner Alaska Oil and Gas Conservation Commission Alaska Department of Administration Anchorage, Alaska POSITION STATEMENT: Testified in support of HB 197 and presented HB 142 to the committee. LARRY DIETRICK, Director Division of Spill Prevention and Response Alaska Department of Environmental Conservation (ADEC) Juneau, Alaska POSITION STATEMENT: Testified in support of HB 197. MARILYN CROCKETT, Deputy Director Alaska Oil and Gas Association (AOGA) Anchorage, Alaska POSITION STATEMENT: Testified in support of HB 197. BENJAMIN BROWN, Legislative Liaison Office of the Commissioner Alaska Department of Environmental Conservation (ADEC) Juneau, Alaska POSITION STATEMENT: Testified in support of HB 197. MARK MYERS, Director Central Office Division of Oil and Gas Alaska Department of Natural Resources Anchorage, Alaska POSITION STATEMENT: Presented HB 71 and answered questions. DAN DICKINSON, Director Central Office Tax Division Department of Revenue Anchorage, Alaska POSITION STATEMENT: Answered questions regarding HB 71. ACTION NARRATIVE CHAIR VIC KOHRING called the House Special Committee on Oil and Gas meeting to order at 5:03:18 PM. Representatives Kohring, Samuels, and Dahlstrom were present at the call to order. Representatives Rokeberg, Gardner, and Kerttula arrived as the meeting was in progress. HB 197-OIL SPILL EXEMPTIONS FOR GAS WELLS 5:04:20 PM CHAIR KOHRING announced that the first order of business would be HOUSE BILL NO. 197, "An Act exempting certain natural gas exploration and production facilities from oil discharge prevention and contingency plans and proof of financial responsibility, and amending the powers and duties of the Alaska Oil and Gas Conservation Commission with respect to those plans; and providing for an effective date." 5:04:34 PM CHAIR KOHRING, as chair of the House Special Committee on Oil and Gas, sponsor of HB 197, explained that the bill addressed an unintended consequence that resulted from last year's House Bill 531: [That was the bill regarding] the coal bed methane issue where we put into place some pretty restrictive requirements. ... The bill went a little bit too far in terms of requiring C-Plans, which is the term referring to oil spill contingency plans, and it also requires proving financial responsibility for all kinds of gas wells, whether there are any threats of oil spills or not. And what we'd like to do is to put in place an exemption to the existing state law for gas wells where there is no threat of any ... oil seepage through the formations when the gas wells are drilled.... [Alaska Oil and Gas Conservation Commission (AOGCC)] will determine if the formations will potentially have oil where the gas is being drilled, and if they determine that there is oil that could potentially work its way through the formations and come out and spill on the ground and cause environmental problems, then they would not allow the exemptions. So it's entirely dependant on what their analysis and evaluation of the formations in the ground are. So what's we're essentially doing with this legislation; [HB] 197 is clarifying the authority that the state has by amending the existing law dealing with oil discharge prevention. 5:06:16 PM CHAIR KOHRING continued: With the current law that we have in place, it actually is going to make it harder for smaller companies to operate because, with the C-Plan requirements, it's going to add to the extra cost ... associated with gas exploration. So we could actually see less gas drilling and exploration if they're subject to these C-Plans and ... proving financial responsibility. 5:07:31 PM DANIEL SEAMOUNT, Commissioner, Alaska Oil and Gas Conservation Commission (AOGCC), Alaska Department of Administration, noted that the AOGCC had submitted a letter of support for HB 197. Regarding the bill, he commented: It mends the laws regarding oil discharge prevention and contingency plans, and also proof of financial responsibility, otherwise known as C-Plans. It allows better use of the geologic information and expertise that the AOGCC has in understanding the need for such plans. Under current law, the C-Plan is required for wells drilled to explore for or produce oil.... The C-Plan ... was not in the past required for wells drilled to produce only gas, however ... [House Bill 531] passed in 2004 kind of had an anti-loophole. The only wells that could be technically exempted were basically only coal bed methane wells, and other gas wells that were not nonconventional ... did not technically have the ability to be exempted from a C- Plan. So we don't believe that that was the ... legislators' intent ... last year, and it resulted in a mismatch between the current scope of the C-Plan exemption and the facts of Alaska's geology. ... And those facts are: drilling for gas in many areas, whether it's nonconventional or not, carries virtually no risk of an oil spill. There are thick geologic sections containing both conventional and nonconventional gas reservoirs, but they have very little potential for the existence of zones capable of flowing liquid hydrocarbons. A C-Plan requirement only adds costs and delay to gas exploration with no increased protection to the environment. We believe HB 197 corrects the inadequacies in current law by providing for a case-by-case geologic evaluation of wells drilled to explore for gas. ... Wells drilled to explore for gas would qualify for a C-Plan exemption only if the AOGCC determines the evidence demonstrates with reasonable certainty that the well will not penetrate a formation capable of flowing any kinds of liquid hydrocarbons to the ground surface. So the approach of HB 197 is to base C-Plan exemption decisions on applications of the AOGCC's geologic expertise.... 5:12:54 PM REPRESENTATIVE GARDNER commented that the Alaska Department of Environmental Conservation (ADEC) "already has authority to do this on a case-by-case basis, and this bill simply clarifies the circumstances under which they can do this." 5:13:19 PM REPRESENTATIVE KERTTULA asked if the bill would apply to conventional as well as nonconventional gas. MR. SEAMOUNT responded that it would,.but noted, "Only in the case where we have determined that geologically there is ... virtually no risk of hitting zones that are capable of flowing oil to the surface." REPRESENTATIVE KERTTULA asked if currently all conventional wells are required to have C-Plans. MR. SEAMOUNT replied that wells drilled before 2004 were exempted, and then he deferred to ADEC. 5:14:35 PM LARRY DIETRICK, Director, Division of Spill Prevention and Response, Alaska Department of Environmental Conservation (ADEC), stated that the department supports the bill. He commented that ADEC has historically relied on the AOGCC's expertise regarding the North Slope. REPRESENTATIVE KERTTULA asked if ADEC had intended to raise the financial responsibility level from $25,000 to $1 million. MR. DIETRICK replied that the intent was that if the determination was made that there was no oil that would float to the surface in a particular reservoir, then both the financial responsibility and the C-Plan requirements would be voided. 5:16:16 PM REPRESENTATIVE KERTTULA said, "If they're required to do a C- Plan, then they're under the $1 million level, even if it's nonconventional. Am I right?" MR. DIETRICK replied affirmatively. REPRESENTATIVE KERTTULA continued, "So under the current situation, current law, which created this glitch, for nonconventional, they were under the ... $25,000 per incident. Is that how it was working with financial responsibility?" MR. DIETRICK answered that this was correct. REPRESENTATIVE KERTTULA noted, "The only gap now ... is that, for the wells that are exempted, what happens if ... we turn out to be wrong, and there actually is an oil spill. Is there any way to go back, or any financial responsibility required at all? MR. DIETRICK responded, "We rely on the AOGCC determination then of whether or not the potential exists. ... And so therefore a contingency plan and financial responsibility would not be required up front." He said that he could not think of any case in the past where AOGCC was wrong in a case like this. He noted, "I think the likelihood of that occurring [is] very remote, so there are no specific provisions for that right now." 5:19:04 PM CHAIR KOHRING asked if there was anyone in Juneau or on teleconference who wished to testify. There was no one. REPRESENTATIVE KERTTULA asked if other facilities or pipelines have to have financial responsibility. MR. DIETRICK responded that the exemption would not apply to any other category of facilities that are regulated and required to have financial responsibility or C-Plan, including nontank vessels, tank vessels, railroad, pipelines, and oil terminal facilities. He said, "It's only for the wells." 5:21:14 PM REPRESENTATIVE DAHLSTROM moved to report HB 197 out of committee with individual recommendations and the accompanying fiscal notes. There being no objection, HB 197 was reported from the House Special Committee on Oil and Gas. HB 142-OIL & GAS: REG. OF UNDERGROUND INJECTION 5:21:44 PM CHAIR KOHRING announced that the next order of business would be HOUSE BILL NO. 142, "An Act relating to regulation of underground injection under the federal Safe Drinking Water Act; and providing for an effective date." 5:22:57 PM DANIEL SEAMOUNT, Commissioner, Alaska Oil and Gas Conservation Commission (AOGCC), Alaska Department of Administration, introduced HB 142 on behalf of the Alaska Department of Administration. He directed attention to "slides" printed in a handout available in the committee packet. He began by giving a brief outline of his presentation. 5:26:18 PM MR. SEAMOUNT turned to slide 3, containing the AOGCC mandate: AOGCC regulates operations affecting subsurface oil and gas resources, ensures the reliability of oil and gas flow measurements, and ensures that underground sources of drinking water are protected. MR. SEAMOUNT explained that the AOGCC mainly oversees subsurface oil and gas activities, but also makes sure that the meters are accurate. 5:27:03 PM MR. SEAMOUNT turned to slide 4, which defines the AOGCC underground injection program. He explained that the AOGCC regulates Class II wells and has primacy for implementing the federal Underground Injection Control (UIC) Program for purposes of enhanced oil recovery and for the most environmentally sound disposal of oil field waste. He said: The proper underground injection of material to enhance oil recovery has resulted in billions of dollars in revenue to the State of Alaska and industry. That's the enhanced oil recovery Class II wells, or Class II-R. Also, there are some Class II- D, which are disposal wells that dispose of ... oil- filled waste. ... The best place to put oil-filled waste is deep underground where it's not going to have the potential to spill on the surface. 5:28:12 PM MR. SEAMOUNT continued: Slide 5 is just a statement of the ... statute as it is right now that gives us the power to oversee ... Class II disposal wells, and also the protection of underground sources of drinking water. The next slide shows what change [HB 142 would make] to that part of the statute. And that would be in Section 1, AS 31.05.030(h).... It gives us oversight for the control of underground injection related to the recovery and production of oil and gas wells, and ... it is adding, "and the control of underground injection in Class I wells as defined in [40 C.F.R. 144.6, as amended]." 5:29:15 PM MR. SEAMOUNT turned to slide 7 and explained: What we have now are two agencies performing the same job; one is protecting a nonexistent resource on the North Slope, and that is an underground source of fresh water. It's been determined that there are no underground sources of fresh water. And that's one of the things that Class I wells [are] supposed to do. ... [There are] Class I wells up there that are protecting something that doesn't exist. And this results in onerous and costly requirements on industry and the State of Alaska. ... [Through this bill, AOGCC] would obtain control through primacy or ... having [the U.S. Environmental Protection Agency (EPA)] agree that we really don't need Class I wells, so we would just continue the Class II oversight, and say that ... everything on the North Slope was oil and gas waste, so we could do it through putting it down a Class II well. 5:30:29 PM MR. SEAMOUNT opined that the five classes of wells under the Safe Drinking Water Act are very confusing; there are different interpretations about what waste can go down what kind of well, and sometimes a Class I well is situated next to a Class II well. He gave a brief overview of what each of the well types were for. In Alaska, there are 1,155 Class II wells which are overseen by the AOGCC, he said. There are only 7 Class I wells, all on the North Slope, and there are more than 3,000 Class V wells. 5:33:47 PM MR. SEAMOUNT turned to slide 11 and remarked: We believe that it's a waste of taxpayer and industry time and money to have ... two agencies overseeing two very similar well programs. There's confusion by operators over what waste is allowed to be disposed in each class of well.... [But] all wastes on the North Slope are directly associated with hydrocarbon production, and there are some regions in the EPA that say that if it's [a waste] associated with oil and gas production, ... then it ought to go down a Class II well, not a Class I. ... Much time and energy is expended by the two agencies and industry ... in tracking what waste goes where. There's a huge amount of time and energy that could be allocated in other places. ... Often the same fluids are injected into the same disposal zones in different wells that are sitting next to each other. The two wells are constructed virtually the same. And AOGCC works on these Class I wells anyway by performing a lot of work advising EPA on their program, and our five inspectors ... inspect the Class I wells.... 5:36:03 PM MR. SEAMOUNT turned to slide 12 and continued: The Class I program ... protects a nonexisting resource: fresh water. It's an inefficient ... permit process. EPA approvals are generally much slower than AOGCC, though ... in the recent past, they're getting better at that. ... They tend to have onerous and costly stipulations considering well integrity. EPA has no onsite field inspectors. They regulation only seven out of 1,162 UIC wells and ... it would appear that it would be costly and remote for EPA to be running a program out of Seattle for only seven wells. There is a temptation for industry, from all this confusion about what to do with these different types of wastes, ... to transport waste long distance for surface displacement or disposal in a redundant disposal well, and that leads to a ... further risk of surface spills. 5:37:23 PM MR. SEAMOUNT noted that slide 13 was a cross section that shows the similarity between Class I wells and Class II wells. Then he moved to slide 14, which he said highlighted the confusion about fluids eligible for a Class II well. He said that the Region 10 EPA position was that only fluids that have been down hole can go into a Class II well, or the waste has to be generated by contact with an oil and gas production stream during the removal of produced water or other contaminants. He described a few issues that tend to cause confusion regarding which type of well is appropriate for which type of waste. 5:39:31 PM REPRESENTATIVE GARDNER asked what "USDW" and "SDWA" stand for. MR. SEAMOUNT replied that USDW stands for underground source of drinking water, such as an aquifer. He noted, "Where oil is produced on the North Slope, there are [no USDWs]. The ground is frozen and none of that water is moveable." SDWA stands for Safe Drinking Water Act. MR. SEAMOUNT turned to slide 15 and said: One of engineers did an analysis of the differences in cost between a Class I and a Class II well, and historically a Class I well cost $2.50 barrel of fluid disposed as opposed to a Class II well, which is $1.50. 5:41:10 PM MR. SEAMOUNT explained that slide 16 is a list of options and solutions. He said: We've got three options. The first option, business as usual, would be if HB 142 is not passed, and the ... silver lining to that is that I wouldn't have to do very much work ... on this task force; no effort would be expended to change the status quo. But if we don't do anything, we're going to continue to have confusion among industry, cost to the taxpayer and industry. There's going to be redundancies between the two agencies. There'll be inefficient approval processes. And it is not industry's preference because ... of the costs associated with it. MR. SEAMOUNT continued: [Slide 17] shows the two [other] options. The first option would be probably the easiest and that would be ... somehow for AOGCC to obtain primacy over the EPAs Class I program. This would lead ... to less industry confusion; they'd be dealing with one agency, and it would save everybody money. The second option would be to just go to having one class of well for all disposal, and that would be a Class II well, overseen by the AOGCC. ... That would need HB 142 to be passed also, and it also [would] need a ruling by the EPA. It would take a little bit more work, but ... that's the best option possible. That would result in less energy used for waste determination and tracking, less cost, less ... industry confusion ..., and it saves everybody money. 5:43:22 PM REPRESENTATIVE SAMUELS asked for clarification about the mentioned task force. MR. SEAMOUNT replied, "We have been talking to ... EPA about building this task force. We're ready to put it in place, and that would be one of the actions we would take." REPRESENTATIVE SAMUELS asked if AOGCC would take any other actions. MR. SEAMOUNT answered, "We are looking at ... writing some regulations in the event that we do reach an agreement with EPA." 5:44:16 PM REPRESENTATIVE KERTTULA asked if permafrost would be considered an underground fresh water source, and if so, if this was the reason that EPA does not consider all North Slope wells to be Class II. MR. SEAMOUNT responded that the EPA definition of fresh water is water that is flowable and in quantities that is usable, therefore permafrost is not considered fresh water. He said: The people at EPA that we talked to are in agreement; they would like us to take the program. Their problem is they don't see in the Safe Drinking Water Act where it's allowed. ... Class II primacy is allowed, [but] they don't see where Class I primacy is allowed. They have a legally, technical problem with it. ... We have been talking to other states about whether they have partial primacy, and we found three states: California ... has partial primacy over a certain set of Class V disposal wells, which involve geothermal wells. And then New Mexico and Illinois have stated that they have some sort of partial primacy. 5:46:47 PM REPRESENTATIVE GARDNER pointed out that if the bill passed through the legislature exactly as written, "we're only partway to where you want to be, and we still then need to get something worked out with the EPA, and that's not in our hands, is that correct?" MR. SEAMOUNT answered affirmatively. 5:47:13 PM REPRESENTATIVE ROKEBERG asked for further distinction between Class I and Class II wells. MR. SEAMOUNT replied: The whole issue ... is sort of a fight between whether confinement of the fluid is most important, or legally the type of fluids, where it's come from, is most important. And that's a dynamic situation. It's been changing gradually through the years. ... We tend to take the position that if we can confine the fluids underground, the type of fluid doesn't really matter that much. Whereas EPA tends to think that they have to go by the letter of the law, and if they interpret that this fluid came from this location ... then it's got to go down this kind of well, and another one, it goes down another type of well. ... They tend to want to see more of Class I wells. 5:49:09 PM REPRESENTATIVE ROKEBERG noted that in producing some types of petroleum, some deadly toxins are produced. He asked, "Seemingly from this definition, everything that comes out of a producing well would be a Class II well, even if it was poisonous, is that correct?" MR. SEAMOUNT replied that this was probably correct and commented, "We haven't had to deal with that in Alaska yet, because we generally have pretty clean oil; very low SO2 concentrations." REPRESENTATIVE ROKEBERG asked, "But what if you did have an SO2 concentration; would that be a one or a two?" MR. SEAMOUNT replied, "I believe that would be a Class II because it came from down hole." REPRESENTATIVE ROKEBERG asked why it was more expensive for Class I well. MR. SEAMOUNT explained that some of the extra cost is due to reporting, and a lot of it is testing. He added that in the past there has been a requirement to cement Class I wells all the way to the surface through its deep casing, which many times requires extra holes shot in the casing and more attempts to get the cement to the surface. He said that the AOGCC believes that there are operational problems and environmental risks associated with cementing casing all the way to the surface. He noted that if the cement is too high it will become too heavy "and you could lose it to the formation." He explained that a Class I well could be between 2,000-9,000 feet deep on the North Slope, and the casing depths range to over 20,000 feet. He said, "A typical Prudhoe Bay well is about 9,800 feet true vertical depth, but with extended reach well bores, they can go to 13,000 feet or more. ... They generally case all the way." 5:54:36 PM MARILYN CROCKETT, Deputy Director, Alaska Oil and Gas Association (AOGA) explained that AOGA is a private, nonprofit trade association whose members comprise the majority of the oil and gas operations that occur in the state. She testified in support of HB 197. She remarked that the AOGCC is very highly regarded for its management of the Class II well program. She continued, "The [AOGCC] is the one state agency that has the specific technical expertise needed when evaluating issues related to the subsurface and the structural integrity of wells." 5:56:51 PM CHAIR KOHRING asked if the EPA is willing to cede control to allow the state to have primacy. MS. CROCKETT replied that the Region 10 EPA administrator had told the AOGCC that if it is legal for the EPA to transfer this program to the state, he would support doing so. She noted, "The rub seems to be in the attorneys reaching the conclusion that in fact it is possible to carve off this program as they have done in three other states for three other programs." 5:58:22 PM REPRESENTATIVE KERTTULA asked Mr. Seamount, "Once you have primacy, what kind of latitude do you have to go outside the EPA regulations?" MR. SEAMOUNT replied that the AOGCC would have to reach a compromise with the EPA on that issue; the EPA would still be the overseer. 5:59:04 PM BENJAMIN BROWN, Legislative Liaison, Office of the Commissioner, Alaska Department of Environmental Conservation (ADEC) stated that no concerns about the bill were raised by the commissioner and the directors of the Division of Spill Prevention and Response, the Division of Water, and the Division of Environmental Health. He commented, "We feel at [ADEC] that [AOGCC is] in a very good position to obtain primacy from the EPA over this." REPRESENTATIVE KERTTULA asked if this bill would affect ADEC operations. MR. BROWN replied that it would not. 6:00:59 PM REPRESENTATIVE DAHLSTROM moved to report HB 142 out of committee with individual recommendations and the accompanying fiscal notes. There being no objection, HB 142 was reported from the House Special Committee on Oil and Gas. HB 71-AK PENINSULA OIL & GAS LEASE SALE; TAXES 6:01:33 PM CHAIR KOHRING announced that the final order of business would be HOUSE BILL NO. 71, "An Act relating to a credit for certain exploration expenses against oil and gas properties production taxes on oil and gas produced from a lease or property in the state; relating to the deadline for certain exploration expenditures used as credits against production tax on oil and gas produced from a lease or property in the Alaska Peninsula competitive oil and gas areawide lease sale area after July 1, 2004; and providing for an effective date." [Before the committee was CSHB 71(W&M).] 6:02:06 PM MARK MYERS, Director, Central Office, Division of Oil and Gas, Alaska Department of Natural Resources (DNR), presented HB 71 to the committee. He explained: [The bill would] extend a tax credit for exploration wells that was approved under AS 43.55.025 for a period of time, specifically to the Alaska Peninsula area, and it would be the onshore and state waters portion of the Alaska Peninsula only. So it extends it from the 2007 sunset of this current tax credit to 2010. And essentially what the bill does is it allows a 20-40 percent tax credit for exploration wells. If they're less than 25 miles away from an oil and gas unit that existed at the time of the bill passage ... and three miles away from another well or more, they would get a 20 percent credit against severance taxes. ... If it's three miles away from other wells and more than 25 miles away from another oil and gas unit, [it would] get up to a 40 percent credit. Exploration seismic, shot outside of an existing unit area, would be eligible for a 40 percent tax credit. So those are the conditions currently under AS 43.55.025, and the thought is to extend those specifically for a limited period of time for the Alaska Peninsula only ... up through 2010. MR. MYERS continued: We believe these credits are important to the Alaska Peninsula because we're starting out with a basin with no infrastructure, and basically no modern well data or seismic data. So this credit would be a significant encouragement, and [by] having it in place before the Alaska Peninsula lease sale, we believe, oil companies would bid increased amount of dollars at the sale. ... There really is no modern data.... So it's really important for exploration success out here to get modern seismic and modern well data shot. So this credit would greatly encourage that by limiting it to a five year period after the sale; they would have to ... do the exploration work early in the primary terms of the leases, and we believe that would accelerate the exploration process. 6:05:01 PM MR. MYERS noted that if the bill were not passed, the credit would be of very little use; by the time a company acquired a lease and set a program up, it would basically have one season before the credit ran out in 2007. REPRESENTATIVE KERTTULA asked if a company could actually end up with an 80 percent credit. MR. MYERS responded that the credits are not additive and would be limited to a maximum of 40 percent credit. 6:07:21 PM REPRESENTATIVE GARDNER asked what the mechanism is by which the state receives data from exploration companies. MR. MYERS replied: One of the purposes of the legislation was recognizing that this particular legislation applied on state, federal, and Native lands, and there's two components for getting the data. One is ..., under current law, the state, for management purposes, only gets the data on state lands. And, for instance, the data on [National Petroleum Reserve-Alaska (NPRA)] it doesn't get until those wells are publicly released, which is normally after 25 months.... So we would get the data for internal use. On seismic data, either state or ... federal land, basically it's never released in the onshore basins. In the federal onshore it can be 25- 50 years before seismic data is released. So two components: one is the Division of Oil and Gas ... would receive the data if the credit is accepted. And so we would have that for internal use. And again, generally, if it was on state land already, through our lease rights, we would receive it anyway. But the second component is then that data has to be publicly released. And right now seismic data would not be released under normal purposes. So basically the applicant would have to provide the data to the state, and after 10 [years] ... they would have to publicly be able to release it, similar to [how] well log data is released now. The seismic data is never released, but under this program, if you accepted the credit, you'd have to release it no matter whose land it was on, whether it be private, state, or federal land. MR. MYERS continued: [Regarding] well data: ... under state law almost all wells are released after 25 months, however there are exceptions where extended confidentiality is granted. So even if that extended confidentiality was granted, it would still require the well to be released after 10 years. So there's additional public benefit. And so the other benefit is: the state itself, if the well is on private land or federal land, generally does not have the right to see the data until that 25 months would be expended, and then we'd be able to see the data immediately. And for instance, some of the wells have been granted credit in the NPRA; ... DNR has already received that data, and then in 10 years the well data will be automatically released through AOGCC. 6:10:27 PM DAN DICKINSON, Director, Central Office, Tax Division, Department of Revenue, in response to Representative Kerttula, stated that the oil companies would be limited to a maximum of a 40 percent credit. He pointed out that the 40 percent credit still exists in paragraphs 1 and 2 of Section 1(a). He explained: If you have an exploration well, there's certain costs associated with that and you can get a 40 percent credit for those. If you do seismic work, you can also get a 40 percent credit for that seismic work. [But] you'll never have an expense that both qualifies as a seismic expense and qualifies as well work. 6:13:34 PM CHAIR KOHRING commented: One of the concerns we talked about last month ... was what we thought to be a loophole in legislation from two years ago: SB 281, [a] tax credit bill. We were concerned that perhaps that bill had unintended consequences in the sense that it was comprehensive extending to private lands and to the NPRA and other federal lands. 6:14:12 PM REPRESENTATIVE ROKEBERG moved to adopt Amendment 1, labeled 24- GH1040\G.2, Chenoweth, 3/16/05, which read: Page 1, line 10, following "gas only lease,": Insert "if the oil and gas lease or gas only lease was entered into by the state under AS 38.05.131 - 38.05.134, 38.05.177, or 38.05.180," REPRESENTATIVE SAMUELS objected for discussion purposes. REPRESENTATIVE ROKEBERG explained that the amendment would restrict the credits granted in current law and in the HB 71, and exclude private and federal lands to qualify for the credit. He commented that he was willing to work on the bill and the amendment with the administration and with the House Resources Standing Committee. He noted that AS 38.05.131-38.05.134 are the provisions for exploration licensing, AS 38.05.177 "is nonconventional gas leases," and AS 38.05.180 are the oil and gas leasing statutes. "The way this amendment has been drafted, it merely states that ... it's only on state lands that these credits are allowable, thereby excluding ... private and federal lands," he said. 6:19:41 PM REPRESENTATIVE ROKEBERG continued: [The amendment] would have an immediate effective date but it [would] only come into play for those applications for credits that occurred after the effective date. ... So this would not affect any activities currently underway that would qualify for the credits on private or federal lands ... so everything that's done and been committed qualifies. This would only apply to a two-year window remaining through July 1, , exclusive of Bristol Bay area or the Alaska Peninsula, and then apply only then to the Bristol Bay area. Frankly ... I think it might be up to the next committee of referral for the discussion on this; whether we want to even include that, whether that's appropriate. I'm not sure exactly how much, for example, privately held subsurface estate exists in the Alaska Peninsula right now. 6:20:58 PM REPRESENTATIVE GARDNER commented: I'm trying to understand, since we know now that the previous committee understood that the tax benefit was going to apply to federal and private lands as well, ... what the benefit would have been, why we would have done that. Obviously if we get the seismic data, that's one benefit to the state that they wouldn't otherwise have. If there's development that results in jobs, that's another benefit. ... Is there any other reason? REPRESENTATIVE SAMUELS answered that the state would still receive a royalty from development on private land. He removed his objection to the amendment. 6:22:13 PM MR. DICKINSON clarified: I can't speak for the committee, but I can certainly speak for the reasons why we included state, federal, and private lands. ... It's incorrect to think that ... automatically we'll get more revenue from state land than we will from nonstate land. The severance tax will apply to all production, whether it is from state land, federal land, or private land. In fact, if it's on private land, the severance tax will apply to 100 percent of the production, whereas if it is on state or federal land, we do not tax either our own royalty share or the federal royalty share. So the real determinant on how much a severance tax is going to be ... is going to be the Economic Limit Factor [ELF]. ... [If, for example,] we were to be drilling in [Arctic National Wildlife Refuge (ANWR)] and you found a very large field there, you would get a lot of revenue because you might have a very high [ELF]. Compare that to a ... well drilled in the Cook Inlet where the [ELF] is zero, so you get zero severance tax, even though it was on state land. Again, on income tax, we get income tax from the increased production that flows to the companies that drill, and again, if it's on private land, we will be taxing both the landowner and the working interest owners. Whereas if it's on state land, we don't tax ourselves, [and] on federal land, we don't tax the federal government. MR. DICKSON continued: [On] private land obviously we don't get no royalty share. On federal land it can be highly variable.... Significant royalties could be flowing to the state even though the drilling was on federal land. And finally, property taxes: ... assets that are employed in the use of oil and gas, whether they are on state, federal, or private land, all the property tax will flow either to the state or to the borough in which those assets are located. So for the four ... [major taxes on oil and gas], none of them can you say with certainty [that the state would] get more if it's on state land and less if it's on federal or private land. 6:24:55 PM REPRESENTATIVE ROKEBERG asked what would happen if the subsurface estate was owned by a Native corporation or a private holder. MR. DICKINSON replied, "The severance tax is on any production in the state less that owned by the federal or state governments." He confirmed that a severance tax could be charged on a private subsurface estate, but there would be no royalties. REPRESENTATIVE ROKEBERG asked: What would be the impact of ... the current legislation that expires in  if ... the ANWR resolution were to pass to the Congress this year and be implemented in the federal  budget, which would put out the bonus lease sale ... before July 1, , thereby creating bonuses ... of $2.6 billion to the state? What would be the impact of ... this credit if those bonuses were to come before July 1, 2007? 6:26:41 PM MR. DICKINSON deferred to Mr. Meyers. He commented, "I don't know, in the current budget bill, whether it's still the 90:10 split and whether that would apply to the bonus bill." REPRESENTATIVE ROKEBERG replied that it is a 50:50 split. 6:27:23 PM MR. MYERS responded: Because the expectations [for ANWR] are high, I'm not sure that extending this credit one way or the other would make a lot of difference. [In] an area like the Alaska Peninsula, where it doesn't have infrastructure [and] it's gas-prone, certainly the economic incentives and the bidding levels are going to be significantly lower. ... So we're looking at basins with very different prospectivity, and again I don't think extending this credit into ANWR would significantly change companies' bidding, because they would bid a lot of money for it anyway. ... If you look historically on the North Slope, much of the revenue stream coming from the royalties is typically higher than that for the severance tax component. ... Generally the federal government has offered incentives where they've need to on their lands as well. 6:30:18 PM REPRESENTATIVE SAMUELS commented that to him the point of the amendment is to "make sure we don't give away the farm at ANWR." REPRESENTATIVE ROKEBERG noted the importance of making sure that the intent of the bill is completely clear. REPRESENTATIVE KERTTULA commented that she would like to go over the grammar of the bill. 6:33:14 PM There being no objection, Amendment 1 was adopted. 6:33:22 PM REPRESENTATIVE DAHLSTROM moved to report CSHB 71(W&M) as amended out of committee with individual recommendations and the accompanying fiscal notes. There being no objection, CSHB 71(O&G) was reported from the House Special Committee on Oil and Gas. ADJOURNMENT There being no further business before the committee, the House Special Committee on Oil and Gas meeting was adjourned at 6:34:11 PM.