HB 325 - ROYALTY SUSPENSION: N. SLOPE HEAVY OIL Number 023 REPRESENTATIVE JOE GREEN, sponsor of HB 325, read his sponsor statement into the record: "HB 325 allows the producers of heavy oil to forgo the payment of royalty to the state on the first 500 barrels of heavy oil produced each day, for a period of five years. The heavy oils considered in this bill is a thick, tar-like, very viscous hydrocarbon that is more difficult to produce than the lighter, more conventional oil and gas that we had in Prudhoe and in the Cook Inlet. The purpose of suspending the royalty is to encourage the lessees of heavy oil deposits to do field research and hopefully develop the maximum amount of recoverable oil in a timely manner. HB 325 requires no application, the suspension that we are talking about is automatic. In order to receive the suspension the producer must simply submit documentation to the Department of Natural Resources (DNR) certifying that the oil produced meets the definition of "heavy oil" and that is clearly the reference in the bill, it is a federal determination, 20 gravities or less, 20 degrees API or less, and the operator would monitor the production rate to satisfy the requirements that are contained in the bill. HB 325 sends a message, we believe, to potential investors world- wide that the Nineteenth Alaska Legislature supports the development of heavy oil. Number 070 BRUCE POLICKY, Manager, Milne Point, BP Exploration (Alaska) Incorporated, (BP), was the next to testify. He gave a brief overview of his responsibilities, parts of which were indiscernible due to coughing and the recorded voice level. He said it was his intention to discuss heavy oil development, primarily, within the Milne Point Unit. He would include a brief history, what was done last year, this year, and what the Milne Point owners are looking at as potential development. MR. POLICKY passed around a handout and pointed out a map of the North Slope showing the location of various operating units. He said the ownership is 91 percent BP and 9 percent OXY USA, Incorporated (OXY). He mentioned that OXY is the only original owner in Milne Point left. Currently, production for the Milne Point Unit runs around 25,000 barrels of oil per day. Three thousand five hundred barrels of this oil comes from the Schrader Bluff Reservoir which has heavy oil accumulation. Schrader Bluff extends over a large area. Mr. Policky stated that the Schrader Bluff Reservoir had 20 billion barrels of oil in place with gravities of 10 to 20 degrees API. For a point of reference, API gravity refers to the density of oil, 10 degrees would be the same weight as water, although the viscosities are very different. He added that the Schrader Bluff Reservoir, within the Milne Point Unit, occurs at a depth of about 4,000 feet. The reservoir temperature is 80 to 90 degrees Fahrenheit on sediment that was laid down 75 million years ago. MR. POLICKY again pointed to the handout and asked everyone to look at a close-up map of the Milne Point Unit. He said it showed the Schrader Bluff accumulation system from an aerial view. The map showed three different regions of Schrader Bluff. The first region was a small development representing 10 percent of the total area and is known as Tract 14. He then pointed out another area of the map, and said that these were various developments in progress. Milne Point owners had taken over these projects beginning in January of 1994, with most of the development occurring in 1995. The last area of the map Mr. Policky covered represented potential future development of a large area with a reservoir of two billion barrels of oil roughly 10 percent of the heavy oil potential, spread out between Milne Point and the Kuparuk River Unit. That potential development would occur within the next two years and, if it proves to be commercially successful, would continue for ten years. MR. POLICKY said that the first development was attempted at Milne Point by Congress in 1991 in the Tract 14 area. In that development, six producers and five injectors were drilled. The project had a low average, initial well rate and high costs both in capital and operating expenses. Development stopped in 1991, but the process resulted in several technical hurdles. He cited the use of artificial lip methods, electrical submergible pumps, methods to control the fan production from the consolidated sand were identified, ways to keep the wells from freezing up during production were developed, and a water flood was started. MR. POLICKY again referred to the handout, which showed the production plot of Tract 14, with the top curve showing oil rate in barrels of oil per day from the entire field and the bottom curve showing the number of wells that are on production at any given time. The graph showed the project peaking around 3,500 barrels of oil per day in late 1991, and going into decline until production ended in 1993. Mr. Policky said this decline was due to lack of follow-up development by the Milne Point owners at that time. He added that the peak rate in 1991 came from 12 to 15 wells, whereas a typical Prudhoe Bay well may produce 3,500 barrels of oil from one well. Currently, the range of gravities that are being produced range from 14 degrees to 19 degrees API. Number 140 MR. POLICKY showed some oil examples, a 14 degree API from Milne Point, a 23 degree API from Kuparuk, and a 35 degree API from the Sak River Reservoir which is located within Milne Point. He said the higher the temperature of the oil, the lower the viscosity. He said Kuparuk oil was about 106 degrees, the Schrader Bluff heavy oil was around 80 to 90 degrees, and Sak River oil around 200 degrees. Number 153 MR. POLICKY began discussing the future plans of BP, saying that the 1995 objective was to determine the liability of a larger scope development depending on the ability to successfully compete for investment capital. He stated that failure in this area would delay the proposed 1998 development. This program would incorporate 300 or more wells with production rates approaching 60,000 barrels of oil per day beginning in the next ten years. He referred to the handout listing the 1995 BP objectives, including improving the cost performance ratio of the Schrader Bluff development, reducing operating capital expenses while increasing production rate, and reducing the amount of uncertainty. BP has spent between $13 million and $15 million on the Schrader Bluff development. The costs for drilling have been from $1 million to $12 million. To keep wells on line, $2 million has been spent in operating expenses and about $1 million on facility and reservoir technical studies. Number 180 MR. POLICKY said that no new wells have been drilled and BP is uncertain of how they will preform in the future, but it appears that drilling and completion costs have been reduced. He added that the costs were at such a level that production levels, and development incentives would determine the feasibility of further development. MR. POLICKY referred to the next page of the handout, which showed the technological side of development, and pointed out the improvement of the completion site at Milne Point. Completion was defined as the things done to the well after its drilled, to get it to preform to the desired production and keep your operating expenses low. He went into detail regarding these completion technologies such as the artificial lip, and the use of a heat trace. Mr. Policky pointed to the next page of the handout and reiterated what events need to occur for large scale field development to come on line including cost reduction in operating or capital expense, coupled with development incentives, and increased production. Number 221 MR. POLICKY said that HB 325 would not only be a development incentive, but would also increase production. He estimated that the total potential was between 200 million to 800 million barrels. BP has $4 million in their 1996 operating budget for technical studies, but doesn't have any drilling capital. He stated that he could not definitively state that, if incentives were or not available, development would occur. He cautioned that a delay in development, within the North Slope, puts ultimate recovery at risk. He added that lower production amounts would make the project less economically viable and cited examples where this had happened within the North Slope. Number 266 REPRESENTATIVE BETTYE DAVIS asked for clarification of the word "short" in the context of "short time to produce." Number 276 MR. POLICKY said this time was measured in months and stated that because the infrastructure was already in place it would reduce the amount of time needed. He felt that at Schrader Bluff it would take approximately 6 to 12 months to begin production. Number 289 CHAIRMAN ROKEBERG asked for information regarding the technology transfer items from a historical perspective to the technology that is currently being developed. Number 296 MR. POLICKY stated that the use of technology is based around completion efficiencies. One of these methods was first developed in the Gulf of Mexico and is called fracturing technology. Propane is injected into the wells to stimulate a high rate of production. Gravel packs are also installed and sand is placed behind the screen to control solids production from occurring later. Mr. Policky added that this technology could be used in the Sak River and the Kuparuk Unit. He also mentioned that the submersible pumps run lives have increased from a few minutes to four years. Changes in run materials, how to keep the wells from freezing up, and how to control Amp production have lead to the increased run lives. On a reservoir recovery basis there is some potential enhancement of oil recoveries through a variety of methods. One of the methods is a gas injection system which was developed in Prudhoe Bay. The heat trace system is another method. It places a band of heat tape across the layers of permafrost to prevent freezing, maintaining working temperatures of 60 degrees Fahrenheit at a cost of $80,000. Number 327 CHAIRMAN ROKEBERG asked Mr. Policky to compare temperatures and difficulties that you face in Milne Point to those in Prudhoe Bay. Number 329 MR. POLICKY said the temperatures can range from 60 degrees to as high as 195 degrees Fahrenheit when it came out of the ground. He added that, without heating the oil, the temperature is about 25 to 30 degrees Fahrenheit. Number 337 CHAIRMAN ROKEBERG asked if there was both water flooding and gas injection going on in Milne Point and how much gas is in the gas gap in the whole west side formation. Number 340 MR. POLICKY said that there isn't a gas gun in the Schrader Bluff area and he didn't believe that there is one within the west side. BP re-injects or produces gas in the Kuparuk Reservoir. He added that BP is water flooding about half of the Schrader Bluff accumulation. One of the areas that BP is studying is when and if you need a water flood. So far it appears that a water flood is beneficial and it is believed that injecting gas would also be beneficial. Number 355 CHAIRMAN ROKEBERG mentioned that this is the only area in the state where pumps are being used because oil flows naturally. Number 360 MR. POLICKY stated that he was not aware of any other commercial pump applications on the North Slope, but said he did not know about Cook Inlet. CHAIRMAN ROKEBERG questioned if the expense of lifting this heavy oil, added to the cost investment which makes it a more difficult investment decision. MR. POLICKY said he believes that BP has selected the most cost effective lifting mechanism for these types of production characteristics. Number 368 REPRESENTATIVE BRICE questioned the average life of a well. MR. POLICKY said a well, with a production rate of 300 to 400 barrels a day dropping down to approximately 200 barrels per day after the first year, it would have an average life of 20 years. Number 385 CHAIRMAN ROKEBERG said that the royalty relief grant in HB 325 would be 12.5 percent, more or less, depending on which lease would be affected. He cited a calculation of an oil well producing 300 barrels per day, sustained on a 30 day basis, would be about $12,000 in revenue relief granted per month. Chairman Rokeberg asked, in economic terms, what kind of impact would this royalty relief have and would the state receive any other money such as severance taxes as a result of foregoing these revenues. Number 395 MR. POLICKY answered that the significance of the royalty holiday depends on how close an oil company is to making a commercially viable project. He cited factors such as average drilling costs, facility costs, coupled with what type of production rate you would need on a loan, and how much improvement you would need to make in order to make a project commercially viable. He added that royalty reduction had the same effect as increasing production out of the well. In numbers, it is felt that to make this project commercially viable, 400 to 500 barrels of oil per day would be needed, coupled with half the drilling costs experienced in the past. In the past, 350 barrels of oil per day were averaged. If BP can achieve 450 barrels of oil per day, in addition to the royalty reduction, then it would meet the 500 barrels per day rate and be commercially viable. Number 425 CHAIRMAN ROKEBERG reiterated that these are marginal oil wells and pools of oil, and suggested that the state should work in partnership with companies to cover their amount of investment. He added that it was a test bed technology chance for the amount of money the state would forgo in this area. Number 440 MR. POLICKY added that the resource is highly variable and the challenges change as you go to different parts of the field. He said that incentives would lead to development that wouldn't occur otherwise. He added that there would be secondary benefits such as money being spent on construction of housing modules. He said he didn't believe that Schrader Bluff, in regards to the ELF factor, would fall out of the severance tax area. He added, that any time you increase your use of the pipeline system, there is directional reduction in tariffs that are paid and in corporate taxes if you are making a profit. Number 471 REPRESENTATIVE B. DAVIS asked why five years was given as a time line. REPRESENTATIVE GREEN said, as opposed to an investment by the state, an investor time-rates his money, and this creates an in- house economic barrier. This barrier means that if you don't recover your money within five years, you have lost the opportunity for other investments. He said most companies won't think of investing in anything that wouldn't recover their investment until after the five year mark. Number 501 REPRESENTATIVE B. DAVIS asked Mr. Policky if that five year time line was seen as reasonable to oil companies. Number 504 MR. POLICKY stated that five years would be the upper time frame BP would normally build. He added that BP has projects all over years because of the problem of capital allocation. He said the shorter the royalty suspension time period the less the significance of the incentive. REPRESENTATIVE GREEN interjected that the time frame might be different if the incentive was directed at the Prudhoe Bay, because the rates of oil production are so much higher. REPRESENTATIVE B. DAVIS asked how much money would be lost due to this incentive. Number 541 REPRESENTATIVE GREEN said that the state could be losing whatever production rate the oil companies are losing below 500 barrels per day. If they produce 499 barrels of oil per day for five years, the state would be giving up one-eighth of the royalty. He mentioned that without this incentive it would be unlikely that there would be any royalty because of the heavy costs associated with the production of heavy oil. REPRESENTATIVE B. DAVIS asked if more money would potentially be available if oil companies were to stay there and produce. Number 566 MR. POLICKY said he didn't have numbers on the overall economic outlook. He said he felt it was an opportunity to test the potentials of the region and establish commercial techniques and approaches which can be expanded into other regions. Number 584 REPRESENTATIVE G. DAVIS said that HB 325 provides an incentive for five years creating production possibilities, after which you have the royalty on whatever is produced. REPRESENTATIVE GREEN said that the amount of oil recovered after five years, at full royalty, would be worth more to the state than the discounted royalty. Number 600 REPRESENTATIVE G. DAVIS pointed out that HB 325 concerns the entire Arctic Slope not just Milne Point or Schrader Bluff, and asked what the possibilities were for producing heavy oil elsewhere. Number 612 MR. POLICKY said that possibilities have already been studied in the Kuparuk River Unit and stated that same difficulties exist there as they do at Milne Point. REPRESENTATIVE GREEN said that to his knowledge, Kuparuk River and Milne Point were the only two regions in the state that were capable of producing heavy oil. CHAIRMAN ROKEBERG said that the production and technical problems would revolve around those pools of oil that may be discovered because they are heavy gravity oil. It was explained that the definition in the bill was based on a federal statutory code that is readily understandable and definable. TAPE 95-19, SIDE B Number 000 JON TILLINGHAST, Attorney, Milne Point Unit, OXY USA, Incorporated, and BP Exploration (Alaska), Incorporated, was next to testify. He referred to a hand out, presented to the Oil and Gas Policy Council on June 29, 1995, which indicated that Alaska's fiscal system does not encourage the development of marginal fields. Mr. Tillinghast said, in Alaska, no differentiation is given between oil fields, which inevitably favors the bigger oil wells. He added that both the Executive and the Legislative Branches are beginning to recognize that three things need to happen. Those things include relying on the smaller, marginal reserves that are located on the North Slope, the second thing is the need for OXY and BP to work together to solve the economic problems associated with those marginal oil wells, and the last thing is that Alaska needs to reevaluate their oil and gas policy. Number 024 MR. TILLINGHAST said that Alaska needs to increase the number of oil companies. He said that the heavy oil reserves in the North Slope are the largest, proven reserves in the country. He added that the state has not previously included the Schrader Bluff resources in the Department of Natural Resources (DNR) production forecast or in the Department of Revenue (DOR) forecast. He said that the state of Alaska has begun the process to attract new oil companies. Number 047 ED BEHM, Heavy Oil Team Leader, Milne Point Unit, OXY USA, Incorporated, who is responsible for making investment decisions regarding heavy oil development, was next to testify. He gave some background of OXY stating that they are an independent company, one of the top ten in oil revenues, produce 60,000 barrels of oil per day domestically, and have heavy oil operations in California. He then reiterated information that Mr. Policky had mentioned regarding the expected oil output, and the economic disadvantages of heavy oil. Number 068 MR. BEHM said the best heavy oil deposits are in the Milne Point Unit. Those deposits have a 20 to 22 gravity and get progressively heavier towards the Kuparuk River Unit. Mr. Behm referred to a page in the handout labeled, "Unlocking the Heavy Oil Potential on Alaska's North Slope," pointing out maps of the area with various oil developments. He discussed a previous pilot project where several methods of obtaining the oil resources were tested, with the exception of gas injection. When water flooding was tested, OXY had water breakthroughs adding sand to the oil which added to the operating expenses. The determination of the pilot was that flat, long-lived production was the best served by a time frame royalty incentive. Number 137 MR. BEHM pointed to a graph on the handout and said that low cost fracturing technology appeared to be promising. He then referred to a completion diagram from the handout, and said that the shallow wells cost about as much as a deep well. The cost averages about $2.4 million per well to drill with a tariff of $5.60 per barrel. Number 152 REPRESENTATIVE BRICE asked if Milne Point relies on pipeline income versus (indiscernible). MR. BEHM said that "if it is an expense to unit or field or pipeline it is the same, then it is pipeline income" and pointed out that this is the only infrastructure within the state of Alaska. MR. BEHM gave a Tract 14 summary. OXY spent $126 million on 22 wells between 1991 and 1994. The wells averaged 275 barrels of oil per day at a cost of $9.30 per barrel which is not cost effective by North Slope standards. Some cost savings were achieved through new technology, and OXY is looking towards BP's fracturing technology. He added that exotic technologies used in warmer climates would not be economically advantageous on the North Slope. Mr. Behm mentioned that the hurdle rate, that OXY and the A. D. Little Report calculated in independent research, was 15 percent for heavy oil investment in Alaska. He stated that OXY had used the 1995 Spring DOR Sources Book in the determining the figures. Number 209 MR. BEHM said that if you build oil wells on a subsidized basis then the investment is 13 percent with a payback in 6 1/2 years. He said that an estimated $300,000 are lost per well. He referred to a chart in the handout listing the key factors for incentives including some quotes from the AD Little Study. These factors included specificity, relevancy, certainty, immediacy within the current window of opportunity, credibility, sufficiency and necessity. Turning the next page of the handout he referred to it and mentioned aspects of HB 325 including the suspension of royalty payments for each new well for the first five years and first 500 barrels of oil per day. He stated that HB 325 was a simple, automatic process and applicable only to those companies drilling the heavy oil. Number 237 MR. BEHM referred to the next page of the handout listing seven states that have suspension incentives that have worked. He specified Texas stating that they have a ten year suspension incentive which had resulted in a 400 percent increase in the number of wells, receiving a $4 billion increase in gas amounts and $240 million in sales revenue and created 104,000 employment years which generated $12 million revenue in sales tax. Number 262 MR. BEHM said that the five year suspension of royalties under HB 325, means that the oil company investment will take 5.4 years instead of 6.5 years to recoup. He mentioned another scenario that if you were to create a 5 percent royalty suspension for the lifetime of the well, it would reduce state revenue because of the potential of increased royalties due to higher prices of oil. Number 295 MR. BEHM referred to the curve Mr. Policky had presented and said that OXY had a similar set of numbers. He pointed to the handout listed as "Full Development of Heavy Oil at Milne Point Above and Beyond Existing Schrader Bluff" and said the numbers listed were 350 oil wells over a ten year period, spending $1.2 billion in capital with 300 million barrels of oil produced and a peak production rate of 60,000 barrels of oil per day. The potential royalties for the state of Alaska would be $60 million in the future, not including the possible investment loan income. If HB 325 were enacted and heavy oil development occurred, the state would get $329 million based on the economics of the OXY unit plus the long range forecast of those wells and the new technologies that will be developed. Number 302 MR. BEHM pointed to the last page of the handout and said, according to these figures, the state of Alaska will be earning money on these early wells when the oil companies will still be recouping their capital investment. Number 318 MR. TILLINGHAST explained that the five year, 500 barrel numbers have independent justifications. He said that 500 barrels is a good definition of a marginal field in the North Slope and five years is the pay off period for investors. MR. TILLINGHAST said that OXY has restrictions on its ability to apply for discretionary relief to DNR as a result of a settlement agreement, therefore OXY would not be eligible for relief under HB 207. He added that HB 207 requires a five percent minimum royalty and doesn't fit some of the criteria. He mentioned such as immediacy and certainty. He said that the heavy oil problem has a specific and focused fix. Number 349 CHAIRMAN ROKEBERG asked for more information on the settlement agreement between OXY and DNR. Number 359 MR. TILLINGHAST said the agreement restricts OXY's ability to apply for a royalty reduction. He added that there would be an issue as to whether when the law changed significantly, as it did with HB 207, whether that would be covered in the application made to HB 207. He said his client assumes that HB 207 would restrict them from doing that and would not go through a discretionary royalty reduction again because of the time and expense that it cost OXY. Number 388 REPRESENTATIVE OGAN addressed criticism from the public that the oil companies would develop these fields anyway with or without a royalty suspension. Number 401 MR. TILLINGHAST responded that there is no risk free decision about whether or not heavy oil extraction would occur in the North Slope without a royalty suspension. He said the A. D. Little Report mentioned concerns about putting the development of heavy oil resources on hold. The report states that at some point in the twentieth century the TransAlaskan Pipeline capacity is going to decline, raising per barrel tariffs so that any new marginal production in the North Slope would not be economically sound. He added that the pipeline might also close for lack of capacity. Number 434 MR. TILLINGHAST questioned that if heavy oil production was profitable, why weren't oil companies already producing it. MR. BEHM added that the suspension of royalty payments is a good way of increasing production of heavy oils. Number 455 CHAIRMAN ROKEBERG asked if the 9 percent of Occidental would be applicable to OXY not with standing the settlement. MR. TILLINGHAST said that all the settlement does is prohibit the discretionary application process. Number 470 GEORGE R. FINDLING, Manager, Government and Public Relations, ARCO Alaska, Incorporated was next to testify. He read his statement into the record: "Mr. Chairman, for the record, my name is George Findling, I am the Manager of Government Relations for ARCO Alaska, Incorporated. I have resided in Alaska for 11 years. Thank you for the opportunity to testify on HB 325. To summarize, while the provisions of HB 325 would create significant value in a West Sak development effort by ARCO and while there is a real merit for Alaska to incentivize heavy oil development, we can not say at this time that the provisions of HB-325 will create enough value to move the West Sak accumulation from unattractive to attractive for development. Further, it is not clear to us at this time, that the provisions of HB-325 would be the most efficient in stimulating the West Sak, the heavy oil accumulation which lies above the Kuparuk horizon, I would like to elaborate briefly on these points. ARCO is working to bring West Sak oil into production. In the mid- 1980's, our field work demonstrated a technique that could be used to complete wells and produce oil at modest rates. Despite these advances, the West Sak accumulation is currently not competitive for investment dollars when compared to other world wide opportunities. Numerous, closely spaced wells and lack of facility capacity make capital costs relatively high. Low well rates, high operating costs and uncertain overall recovery rates raise the ongoing cost structure of the bulk of West Sak to unacceptably high levels. Since the West Sak reservoir quality, indicated mainly by seam thickness, varies over the field, we would expect to develop first in the best areas, then move to the lesser areas of reservoir quality. In this scenario, you can envisage that production slowly builds up over time as the field development expands to new areas and cost reduction techniques are refined. Now, remember, the `best' West Sak is not as good in terms of current cost structure as the `worst' Kuparuk which is the underlying accumulation. So one key to West Sak is to make its cost structure effective enough to compete for facility usage against Kuparuk and other resources. ARCO is trying to find ways to reduce this cost structure and make a significant amount of West Sak cost competitive. We are currently doing a strategic and technical `rethink' which we hope will lead to new, and innovative development approaches. In essence, we hope that a limited field program in 1996 and 1997 will be the first step in a phased commercialization which will include incremental improvements in technology and operating costs. The details of this program are not yet developed, but I can say that we will be trying to find ways to reduce our cost structure substantially at each step so that development can proceed to the next step. Our current view is that we need to work through at least this 1996 program to specifically know when royalty modifications will be needed to make the then next phase of development attractive for investment. Our hypothetical analyses to date show that royalty reductions can provide major improvements in the economics of a marginal heavy oil field. A royalty holiday, one form of which is contained in HB 325, deserves consideration. Another approach which should be considered is a general reduction in royalty rate over field life. To summarize, whether some type of royalty reduction is sufficient to make the then next phase of the West Sak field attractive for investment is problematic at this time; but it will likely be better quantified after our 1996 program. Mr. Chairman, thank you for the opportunity to testify and I would be happy to take your questions." Number 542 CHAIRMAN ROKEBERG asked if ARCO had a formal position on HB 325. MR. FINDLING said that ARCO is interested in advancing incentives that would make a marginal project attractive to investors. He said that he could not say that HB 325 would have that effect. Number 571 CHAIRMAN ROKEBERG said then it appeared that HB 325 might not provide enough of an incentive. MR. FINDLING said that without addressing the state royalty part of it, the whole project cost structure is out of line and not attractive for investment. He said that the state needs to get that cost structure down in order to move ahead. He said that ARCO looked at the development of these heavy oil deposits with zero royalty paid and still found it unattractive to investment. He said that the key is to reduce costs in the operating area. TAPE 95-20, SIDE A Number 000 CHAIRMAN ROKEBERG said he wanted to adopt the committee substitute and hold it over for further testimony and additional hearings during the session. REPRESENTATIVE OGAN requested point of order as to whether or not committees could adopt a committee substitute during the interim. REPRESENTATIVE G. DAVIS moved to adopt the proposed committee substitute for HB 325 version 122/x/k, including the proposed amendment. Hearing no objections, the House Special Committee on Oil and Gas adopted the committee substitute pending a review of the rules on what a committee can do with a bill during the interim. Number 023 REPRESENTATIVE G. DAVIS asked Representative Green if the Administration had been provided a copy of HB 325. REPRESENTATIVE GREEN said he that the Governor is aware of the bill and is in favor of it to his knowledge. He said his understanding is that the Governor likes the bill, but doesn't want to get ahead of the Oil and Gas Policy Council. If HB 325 becomes a recommendation of that council, then the Governor would be in favor of it. Number 035 CHAIRMAN ROKEBERG said the Administration and the (indiscernible) were invited to be at this meeting, but were unable to attend. He added that there were a number of leases on Cook Inlet that went up for sale today. The state will earn $987,000 on this sale, if the bids are accepted. He that 25 tracts were bid on out of a number of 100. He said there was only one significant bid of $390,000 was offered. The balance of the bids ranged in the amount of eight dollars an acre. He said that six different companies won bids in the sale which included ARCO, Norcom, UNICAL, Union Texas, Stewart Petroleum. CHAIRMAN ROKEBERG said that the committee will be meeting on December 18, 1995, for a work session. In the morning, the committee will take up bonding requirements and removal of other impediments and obstacles to small, independent oil and gas producers in the state. In the afternoon, of December 18, 1995, there will be another work session focusing on areawide leasing and best interest finding legislation. CHAIRMAN ROKEBERG stated that the next public hearing of HB 325 will occur in the early portion of January.