Legislature(2003 - 2004)
03/16/2004 03:15 PM House O&G
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* first hearing in first committee of referral
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HB 531-CONVENTIONAL & NONCONVENTIONAL GAS LEASES [Contains discussion relating to SB 312, the companion bill, and to SSHB 364] Number 0850 CHAIR KOHRING announced that the final order of business would be HOUSE BILL NO. 531, "An Act relating to natural gas exploration and development and to nonconventional gas, and amending the section under which shallow natural gas leases may be issued; and providing for an effective date." CHAIR KOHRING invited Representative Seaton to join members at the table. Number 0888 REPRESENTATIVE BEVERLY MASEK, Alaska State Legislature, presented HB 531 on behalf of the House Resources Standing Committee, which she co-chairs. She brought attention to the new proposed committee substitute (CS), Version D. Number 0923 REPRESENTATIVE HEINZE moved [to adopt the proposed CS, Version 23-LS1818\D, Chenoweth, 3/12/04, as a work draft]. There being no objection, Version D was before the committee. REPRESENTATIVE MASEK explained that the shallow natural gas program was adopted by the legislature in 1996 to provide a clean-burning, inexpensive source of fuel for rural communities and remote locations. This over-the-counter application program has required the Department of Natural Resources (DNR) to issue a shallow natural gas lease if the director determines the discovery of a local source of natural gas would benefit the residents of an area. Under the program, no best interest finding has been required, however. REPRESENTATIVE MASEK said although the program has been used in a few areas for its original intended purposes, in other areas it has been used for large-scale commercial operations in nonrural settings. This has led to a series of unintended consequences; for example, in 2003 approximately 98 percent of shallow natural gas leases and applications were in higher- population locations such as the Big Delta, Matanuska-Susitna ("Mat-Su"), and Homer areas. Representative Masek said the lack of discretion given to the director on issuing leases, along with the occurrence of applications in higher-density areas, has led to heightened public concern about the program. Number 1055 REPRESENTATIVE MASEK conveyed her belief that [Version D] resolves four fundamental problems with the program: lack of public notice and participation prior to issuance of a lease; "over-the-counter discretion" in issuing a lease once the application is received; use of over-the-counter applications, rather than competitive bidding; and problems such as pooling once a lease reaches production. It replaces over-the-counter shallow gas leases with a gas-only option, exploration licensing, and areawide leasing; she indicated the latter two are existing programs that require a best interest finding, which involves the public at the beginning of the process. She said these programs give the director discretion about whether to issue a lease and whether to exclude certain lands from a lease such as those where the surface contains a school. REPRESENTATIVE MASEK reported that the bill provides that nonconventional gas developers enjoy the same lower rent and royalty rates currently in the shallow gas leasing program. Replacing over-the-counter leases with exploration licensing and areawide leasing provides DNR with much greater public input, as well as agency control and discretion to determine whether exploration and development are appropriate in certain areas. Both leasing and licensing processes are competitive, she noted, ensuring maximum value to the state. REPRESENTATIVE MASEK said the bill creates a gas-only selection of areawide leasing and exploration licensing "identified in a best interest finding by DNR." It also differentiates between conventional and nonconventional gas resources for the purpose of lease and rent royalties. Furthermore, it encourages exploration licenses with a [best interest finding] as a method for nonconventional gas exploration outside of the areawide leasing, which she said is mainly in rural Alaska. It recognizes that lease rights shouldn't be determined by depth only. Representative Masek concluded by saying [Version D] incorporates the foregoing and that experts from DNR on teleconference could answer technical questions. Number 1316 MARK MYERS, Director, Division of Oil & Gas, Department of Natural Resources, specified that DNR and the administration support this legislation. Referring to public workshops in the Mat-Su area and concerns heard from Homer and other areas, he reported that one chief public concern about the shallow gas leasing program has been an unintended consequence of the program, that very little actual notice occurs up front prior to issuance of the lease. One main concern expressed in the workshops has been the desire to have a process that includes a best interest finding. MR. MYERS explained that a best interest finding is a document like an environmental impact statement (EIS) in which the state weighs the values and looks at the environmental issues as a "major, full public process" with a lot of public input; the draft decision document then is available for public comment by not only citizens, but also local governments and so forth. In response to that, the final decision must incorporate all those comments and answer any questions that have been brought up or else modify the proposed lease sale for that area. MR. MYERS said that process has worked very well; is established, court-tested, and well accepted; and has "the balancing test of the state's best interests" as its true measure. He opined that this has allowed a very successful program for areawide leasing, and said a modified but very similar process is used in exploration licenses. He remarked: Through those two processes, we believe we can accomplish pretty much everything that is accomplished with the shallow gas program in terms of encouraging exploration for and development of coal bed methane to provide that additional public input that's been sought for the public process elsewhere. Number 1460 MR. MYERS explained that one big thing this legislation does is allow that upfront planning process. Acknowledging it's more work for the department, he nonetheless remarked that when [DNR] is done with it, it will have really taken the public concerns and done a balancing test, and will be able to say the leasing is appropriate; it also gives [DNR] a longer, better-defined process to put in stipulations and mitigation measures for environmental protection. He reiterated that he believes it's a solid, time-tested process. MR. MYERS highlighted advantageous provisions for the lessee. For example, by replacing shallow gas leasing with either conventional leasing or exploration licensing, the program allows applicants to have a much longer period of time; the three-year period for shallow gas leases has been problematic in that it's hard to actually do development work in a three-year period, which has led to less value for the leases. MR. MYERS reported that another problem with leases has been the shallows depths; he acknowledged that the legislature has struggled with whether it should be 3,000 or 4,000 feet, or should be part of the field above 3,000 feet and continue to deeper depths. He remarked, "We think the best way to lease land is to provide ... the gas potential at all depths; in that sense, then, the correlative rights of all parties are protected, at least the maximum production from the lease." He mentioned that there'd potentially be fewer facilities built and thus less of an impact. Number 1566 MR. MYERS noted that one concern about those who produce or explore for shallow gas or other nonconventional types of gas has been the economic structure of the leasing program. Conventional lease rentals start at $1 an acre and go up to $3. He pointed out that exploration costs and the economics for coal bed methane or other nonconventional gas such as gas hydrates or gas-producing fractured shales are different from those for with conventional reservoirs. To encourage that activity, he said, this bill provides a mechanism whereby if the lessee makes a showing that the gas potential on the lease is nonconventional, [the lessee] can retain a $1-an-acre rental; if the gas doesn't compete with other gas, the 6.25 percent royalty share can also be retained that is part of the shallow gas leasing program. MR. MYERS concluded by saying this bill should stimulate the shallow gas and coal bed methane industry; provides a balancing; has a mechanism for the state to recognize the difference in economics and to give a better lease term; is for all depths and for a longer period of time; will lead to more rational development; should bring in more money to the state; provides a best interest finding and public input; creates a situation in which, to his belief, the leases are a better value for applicants; and deals with some problems relating to the limited depths of the shallow gas leasing program. He stated support [from DNR and the administration] for those reasons. Number 1686 REPRESENTATIVE KERTTULA asked what kind of notice is given. She expressed concern that there still isn't direct notice to landowners, although it could happen. MR. MYERS answered that there is no notification at the time of leasing to all residents in the area, but there is full notification to any resident who provides his/her name for the mailing list; to all municipal governments and community councils; and [to the general public through] the local newspaper, [notification posted] at the post office, and so forth. Mr. Myers said he doesn't know of any state program that notifies all residents in an area that the state is doing a disposal. He explained: We have difficulty because we have no qualified lists of residents. We have tax records in some places, but that goes to the owner, not to the resident. And in other unorganized boroughs, we really don't have those lists. ... We can attempt it, but we haven't traditionally, in our programs. MR. MYERS said other than for the shallow gas program, [DNR] hasn't had this as a major complaint. He pointed out, though, that there is a requirement before any operations occur that all residents be notified; at that stage, they "go on the ground and physically require that notification." Number 1794 REPRESENTATIVE KERTTULA asked how onerous it would be to notify the owners instead of the residents prior to leasing, and whether a list could be obtained from the courts, for example. MR. MYERS answered [that DNR] has looked at using available lists including court lists, tax records, and so forth, but records in most areas aren't all that good and it would add costs to the programs. With the shallow gas program, for example, the estimate is about $70,000 a year if [notification] is via certified mail; he offered to provide a breakdown. He noted that commercial mailing lists could be tried, said contracting it out has been looked at, and highlighted the substantial cost. Although it's possible, he said, he didn't have confidence about [the ability to notify] all residents of an area, based on the historical quality of the data sets. He added that probably the best records [DNR] has seen are some commercial mail-outs for coupons, but it costs money and takes time. It also could be done under contract. Number 1870 REPRESENTATIVE KERTTULA asked, "What if the list were simply to owners and we figured out some fairly simple way to do that and it was not certified?" She surmised this would lower the cost. MR. MYERS answered affirmatively, estimating that for the shallow gas program it would cost about $10,000 using regular mail. He mentioned concern about being sued if someone doesn't get a letter. Indicating DNR tries its best to notify people, he said the preferred method is to put out the notice and have [concerned citizens contact the department]; if there is any activity at all in their area, DNR will then notify them, thus ensuring that "the folks that really care about it" receive notification. He said notifying people prior to a disposal isn't current state policy on conventional leasing, (indisc.), or any other disposals of the state; however, it's something [DNR] could look into if the legislature so desires. REPRESENTATIVE KERTTULA suggested it's certainly worth the legislature's thinking about it very hard because of events of last year relating to shallow natural gas. Number 1970 REPRESENTATIVE ROKEBERG recalled seeing a schematic of a distribution plan for Fort Yukon to take advantage of nearby potential shallow gas to distribute to that village, one intention of the original [shallow gas] legislation. He asked whether HB 531 provides a choice between exploration licensing or an areawide leasing plan. If there were a small, discrete area around that village, for example, he asked how Mr. Myers would recommend that work under this proposed legislation. MR. MYERS said that's a good question. He recalled that the shallow gas legislation passed the same year as exploration licensing; thus there wasn't a vehicle outside of the areawide sale areas to allow for leasing and development. REPRESENTATIVE ROKEBERG remarked, "That was before areawide leasing too." MR. MYERS agreed, saying there were conventional sales where [DNR] did a finding. Remarking that areawide leasing certainly would apply in areas where he thinks the department's intent would be to extend the current areawide sales, he mentioned north and south Cook Inlet and at least looking at those possibilities. MR. MYERS pointed out that the other mechanism, the most appropriate in rural Alaska, is where the intent is for (indisc.) energy: either the applicant would apply or the state would open an area for exploration licensing - it has been done both ways. Although it can be applicant-driven, the applicant has to compete for that license in terms of dollars of work commitment spent for the area. He noted that a license can be for as few as 10,000 acres, essentially two shallow gas leases. Also, an applicant can request the area and [DNR] can grant the license without a competitive process, since no one else has competed for it. He remarked, "We're not seeing a lot of competition in the exploration licensing." MR. MYERS elaborated, saying an applicant can come forward any April and propose a license in an area, and [DNR] will start the process. Or the state, at any point, can decide to "go out for a license" in a specific area, often in response to a request. In Bristol Bay, for example, there was a lot of local interest and the state "self-proposed" it. The mechanism in rural Alaska would be an exploration license application. Suggesting the applicant's cost would be far cheaper than for a shallow gas lease, with a longer-term license, he added, "What they're bidding on is really a work commitment to evaluate leases, which is what we want anyway." MR. MYERS explained that at the end of the license period is a right to noncompetitively convert to a conventional lease at 12.5 percent. Under this program, for an area like Fort Yukon where [DNR] sees no oil potential, a gas-only lease could be applied for and negotiated. For coal bed methane, a showing could be made to [DNR] and then the royalty and rental terms would "stay at the dollar, and it would be the 6.25 [percent]." Thus economic terms at Fort Yukon would be obtained that are similar to those under shallow gas leases, except there'd be better terms because of the 7 to 10 years to explore and the exclusive right to explore before going to a lease. MR. MYERS added that overall, review of all the cases of shallow gas leases [has shown that] under this, the applicants would have been better off with actual exploration licenses; he mentioned the Red Dog area and some other areas. Having worked through the process, he said, he believes this is a more effective way to get unique areas like Fort Yukon under lease, because there is a best interest finding up front that includes the public process and will protect [lessees] from litigation. Number 2280 REPRESENTATIVE ROKEBERG noted that the best interest finding has to be completed for both the exploration licensing and any conventional or areawide leasing. He asked Mr. Myers whether DNR's costs would be lower to prepare a best interest finding in a rural area with a relatively small amount of acreage, or whether there is a usually a fixed cost because of the breadth of any best interest finding that must be prepared. MR. MYERS said he believes the answer has two parts. If the area is geographically small or constrained, the finding is more constrained; it is easier to do a finding for 10,000 acres than for 0.5 million acres because of the research needed. It has been found, however, through the process of shallow gas leasing and developing stipulations and mitigation measures, that it still requires a substantial amount of research. Prior to issuing a lease, he said, [DNR] goes through the full public process. MR. MYERS reported that, in retrospect, for the shallow gas leasing program more effort has been spent than if the findings had been done up front. He mentioned the Holitna basin, the Healy-Cantwell area, and a desire of people there to have public input and a public process. In reality, he said, there has been little discretion to change things, even though there hasn't been a public process. He offered his belief that it's not a whole lot more work to actually do the [best interest] finding and have public input up front. MR. MYERS explained that also different under the licensing proposal is an ability to negotiate with applicants to remove acreage that is environmentally sensitive or that has a low probability of finding gas. Perhaps 90 percent of problems are eliminated by eliminating 5-10 percent of the acreage, but the applicant doesn't necessarily know that. Thus having a process that includes discussion with the agency and a shaping of the license area has been a huge success; he cited a Susitna license as an example, saying there was little public concern because it was shaped with the applicant to avoid "hot-spot" areas. Returning to balancing, he mentioned the cost of licensing, leasing, and the best interest finding. He pointed out that while it takes about a minimum of a year to issue a finding, it takes [DNR] longer than that to issue shallow gas leases now. Number 2443 REPRESENTATIVE ROKEBERG asked what it typically costs to do a best interest finding. MR. MYERS replied that including staff time and depending on the amount of travel, $250,000 is an estimate for a typical exploration license. For a smaller one, it would probably be considerably less. If [DNR] does multiple ones in the same area, however, a lot of basic data is there and so it can cost much less. He reiterated that for shallow gas leasing, [the department] isn't spending a whole lot less, or perhaps is spending no less, if staff time is included. Number 2498 REPRESENTATIVE ROKEBERG asked what switching to areawide leasing and avoiding 5-year renewals on best interest findings saves the department over the years. MR. MYERS replied that the 10-year "shelf life" has saved millions of dollars and cut the staff for best interest findings to perhaps 20 percent of what was required before. REPRESENTATIVE ROKEBERG said he'd been looking for that answer since introducing an areawide leasing bill a few years ago. Number 2531 REPRESENTATIVE ROKEBERG expressed concern, stating his understanding that Mr. Myers had said one method for handling this type of nonconventional gas would be to extend the geographic boundaries of the current areawide leasing offerings. He asked, "If you were to do that, would that not either extend them or create new ones - like in Bristol Bay you basically created a new areawide lease area, as I understand it?" MR. MYERS answered in the affirmative. He said that would occur in the Cook Inlet areawide findings, due in 2007; the 10-year period would be up, so [DNR] would review it anyway in that timeframe, would look at areas it is aware of in the valley that would have coal bed methane potential, and would extend those further to the north. He added: In the meantime, if someone were to apply for a license in the area that's currently not, we could go through the process. ... Someone could lease that [at] this point in time, prior to that finding being completed ... or the announcement that we were going to extend it in the 2007 period. So I don't think under this program, in the interim time, any land ... is off-limits that isn't planned to be off-limits for areawide leasing, like in the Bristol Bay region. So we wouldn't anticipate a mineral closing or anything else in the valley. That ... would be open for licensing; again, it would provide that public process along with it. And then our ultimate goal would be, then, to extend the areawide further ... to the north there, certainly, and that would provide that best interest finding process, but still have ... a chance to develop the coal bed methane resources up there. Number 2625 REPRESENTATIVE ROKEBERG conveyed his understanding that when the Cook Inlet areawide leasing was established, the boundaries were adjusted during regulatory rule making; the "Kachemak Bay uplands" were excluded and thus became available for leasing under the shallow gas [program], which has created somewhat of a problem by the fact of their exclusion. He asked whether [DNR] has plans relating to extension of the areawide leasing boundaries there or in the [Mat-Su area]. He also asked about impacts relating to the costs and the regulatory rule making, and whether [DNR] will go through the whole public hearing [process] again when there is a renewal of the best interest findings at the 10-year [renewal point in 2007]. MR. MYERS addressed the last question first, saying the 10-year period starts with a brand-new best interest finding along with a decision by the commissioner on what area will be included in the finding. In the 1997 finding, he noted, then-Commissioner Shively made a determination that limits the area to the south; however, there is no real documentation of the policy call at the time. Mr. Myers said those limits could be subject to the commissioner's discretion at the time the finding is done. If the finding didn't include that area to the north and south, it would still be open for exploration licensing under this program. MR. MYERS reiterated that the major concern heard from folks in the [Mat-Su area] and Homer is the lack of public process. Even with a license, he said, there'd still be a best interest finding process and the ability to "size and shape" the area to eliminate areas of major public concern "if the findings reported it." The public process would be there in either case. Mr. Myers went on to say that, at this point, he believes DNR's intent is to incorporate a "larger areawide leasing" because it's supported now by the geology and the technology. The discussion of what should or shouldn't be in the sale, the sale area, mitigation measures, surface occupancy standards, and so forth would be worked out through the public process, the findings, and the weighing of the state's best interests. Number 2771 REPRESENTATIVE ROKEBERG asked whether an applicant could request a gas-only lease under this bill if the areawide leasing boundaries were expanded in Cook Inlet to the south and north, for example. MR. MYERS answered that for those particular areas, DNR's commissioner would have to make a determination, if it was within an areawide sale, as to whether to issue a gas-only lease. There are qualifications as to how it would be done, but he said the logical implications are that the potential and the environmental sensitivities are what would be looked at. For an area by Homer where there is a lot of concern about oil-spill issues, for instance, it might be appropriate to issue a gas- only lease because of environmental sensitivity. The commissioner would have to work that out; it would be explained and argued in the findings, and would be determined by the findings process. MR. MYERS explained that the other case where a commissioner would do this is if an area really had no oil potential. If the area underneath had a lot of oil potential as well as gas potential, or had even moderate oil potential, Mr. Myers said he doubted that the commissioner would make a determination to issue a gas-only lease unless it was determined, environmentally, to be the only way to properly lease it, to balance the state's best interests. Number 2858 REPRESENTATIVE ROKEBERG inquired what the economics would be if there was drilling for shallow gas or coal bed methane within areawide leasing geography. He asked what the economic impact would be if there was a lower-production shallow gas operation versus more conventional gas. MR. MYERS responded that conventional gas - the kind of gas typically explored for on the Kenai Peninsula or most of the known North Slope reserves - has superior economics and requires fewer wells. The gas resources are typically at higher pressure, for instance, and the rate from an individual well is much higher. The cost of drilling a well is also higher, but overall the economics are generally a little better. Pointing out that the economics for coal bed methane are very good in some areas, Mr. Myers said he thinks that determination will be based on the cost of drilling; the approximation to infrastructure and the cost of getting the gas to market; and the productivity of the coals, which can vary. MR. MYERS provided examples, saying the [Mat-Su area] has existing infrastructure including roads, and is much cheaper to explore than the Fort Yukon area; most of the economics are pretty good in the [Mat-Su area], and pilot programs in the Pioneer Unit there are in conventional, competitively bid, standard oil and gas leases held by the Pioneer Unit itself. Areas to the north of that have shallow gas leases. Mr. Myers surmised that Evergreen Resources was comfortable drilling with conventional lease terms. In the [Mat-Su area], he said, he believed it would be a tossup whether conventional lease terms would affect the economics, and didn't think they'd affect it very negatively. He added that the differential in the royalty rate, the 6.25 [percent], makes no difference because that gas is fully competing in the market with other gas. In rural Alaska, however, there is a high cost to develop infrastructure, there are limited markets, and so forth. TAPE 04-9, SIDE B Number 2948 MR. MYERS mentioned potential for the lower rate [in rural areas]. Turning to Homer, he noted that there are multiple wells drilled in the Homer bench itself, many with good gas shows, on a trend with normal gas fields; the shallow gas potential there is actually conventional. Mr. Myers explained that in such an area, [DNR] would probably argue that there's more conventional gas potential; that it shouldn't be at the lower royalty rate; and that someone could bid competitively for those leases, successfully, and could afford the exploration and development program. Number 2948 REPRESENTATIVE HEINZE noted that some legislators had just returned from the Energy Council [conference in Washington, D.C.], where they looked at projected gas shortages in the U.S. She asked, as companies look towards Alaska and its gas, and as competition increases for these applications, whether Alaska will "have enough area for these shallow gas leases." MR. MYERS suggested looking at Alaska's long-term gas supplies and basins with large potential; many of these areas are under exploration licenses. He said the North Slope is under traditional leasing, however, and significant potential exists within North Slope foothills basins, in particular, for undiscovered, large, conventional gas fields. Indicating a lot of large gas producers are buying those leases, he cited examples of companies with a long history of gas exploration and mentioned the potential for a natural gas pipeline from the North Slope. MR. MYERS reported that further south, one of the more outstanding candidates is the Nenana basin outside of Fairbanks, where Andex [Resources LLC] has a license; that deep basin has potential [in the trillions of cubic feet] but is under exploration licensing. The Susitna basin has two different exploration licenses with Forest Energy; characterizing it as "sort of an extension of Cook Inlet to the north," he offered the belief that this area is gas-prone, with the same formations that produce gas in the Cook Inlet. Moving further south to the northern extension of Cook Inlet, he said there is coal bed methane activity in the Pioneer Unit and the shallow gas leases adjoining that area to the north, and then Cook Inlet proper. MR. MYERS provided details, concluding that there is a lot of potential in the offshore Cook Inlet area, but it's expensive to get to and the fields would have to be very large to support the cost of development. Onshore there is a fair amount of exploration activity - more than traditionally, on both sides of the inlet - with some success for gas; however, those discoveries cumulatively will only extend the life of Cook Inlet [production] about another year. Mentioning about nine years of reserves plus the possible one-year extension, he suggested the unknown exploration potential there needs to be banked on if the life is to be extended. He also indicated in Bristol Bay it's believed a basin may have multiple [trillions of cubic feet] of conventional gas "on state lands and state waters." CHAIR KOHRING noted that Mr. Myers has a Ph.D. and speaks from a lot of experience. Number 2760 REPRESENTATIVE PAUL SEATON, Alaska State Legislature, paraphrased from Version D, page 25 [amending AS 38.05.180(f)(3)], which read: (H) for nonconventional gas that will not be produced in direct competition with gas on which a royalty at a rate of at least 12.5 percent is payable, a royalty share reserved to the state of at least 6.25 14 percent in amount or value of the production removed or sold from the lease; REPRESENTATIVE SEATON requested clarification, offering his understanding that gas produced in most wells in Cook Inlet until January of this year had a 5 percent royalty rate. Number 2707 MR. MYERS replied that most gas in Cook Inlet is produced at a 12.5 percent royalty rate from state land. However, legislation passed in 1994, which he believed sunsetted in January 2004, gave a 5 percent royalty to certain "known but at that point uneconomic" gas fields to spur development; the legislation listed those fields and gave 10 years from the bill's effective date for production to start. Mr. Myers recalled that the 5 percent was on the first 35 billion cubic feet of gas produced from the field. Corresponding was that certain ones were oil fields; for example, one platform got a 5 percent royalty until it produced 25 million barrels. MR. MYERS said for this program [under HB 531], in most of Cook Inlet that has conventional oil and gas potential, the lower royalty rate for the "gas-only" wouldn't be eligible. He added: It's not eligible for it now, and it wouldn't get the 6.25 percent treatment. What was designed in this bill was a mechanism, though, recognizing Representative Rokeberg's Fort Yukon-type scenario where there was a mechanism, if the gas was unconventional, ... to get a 6.25 percent royalty for local energy use. Number 2595 REPRESENTATIVE SEATON noted that page 25 doesn't distinguish, but talks about [competition] with gas with a royalty of at least 12.5 percent. Saying there is a mixture in his own area [Homer], where at least two fields just came on line prior to January 1, he requested further clarification about how this will apply to his area. MR. MYERS responded that if gas was competing and came from the Falls Creek Unit or several other units [listed in statute], it would have a royalty of 12.5 percent, although in "the one case ... in the North Fork Unit" it would be 5 percent; that isn't changed by this [bill]. If production occurred on one of the current shallow gas leases in the Homer area and it was competing with other gas, the royalty on those shallow gas leases would be 12.5 percent; if it wasn't competing, it would be 6.25 percent. This determination would be made at the time of the discovery, he added. Number 2490 REPRESENTATIVE SEATON asked, "So if it's competing with North Fork gas, it's taxed at 5 percent?" MR. MYERS replied that it would be 12.5 percent because of "the standard on the lease." REPRESENTATIVE SEATON asked if that's even though page 25 talks about competition with gas with a royalty rate of at least 12.5 percent. MR. MYERS affirmed that and explained that in this bill, the royalty rate determined on those current shallow gas leases is enshrined in statute. The bill's language doesn't directly apply to the leases in the Homer area because, he said, "those leases are established under the contract right and it's enshrined in the lease under current statutes, under [AS 38.05.]177." Number 2442 REPRESENTATIVE SEATON sought clarification about a concern expressed the previous week about [SSHB 364, which he sponsored], relating to shallow gas leases in Homer, that there is a problem with [DNR's] discretion to extend those leases if they aren't being actively pursued. He asked Mr. Myers, "Would you have any problem putting that same discretionary language in this bill, as well, so that you would have the discretion and the guidelines for reissuing the current shallow natural gas leases in the Homer area?" MR. MYERS shared his personal view, saying he'd have no problem with the legislature's clarifying what that discretion is. "I think the language you presented does it well and stays within ... the intent of the law," he said, and thus wouldn't be considered the taking of a lease right. Unless activity was occurring, he suggested, it probably would assure that those shallow gas leases expired in three years; then, if the finding was extended, the area "currently under exploration, under shallow gas leases, ... if it was appropriate in the finding," could be included in an areawide sale for, potentially, a gas- only lease. He added his belief that shortening that term and limiting the discretion, or defining that discretion as that bill [SSHB 364] does, wouldn't negatively affect this bill. Number 2337 REPRESENTATIVE ROKEBERG brought up concerns raised by folks at [Teck Cominco Limited, at the Red Dog mine] about a shale discovery; he said they apparently have a current shallow gas lease and concerns about how this bill relates to their future operations. He asked whether there have been discussions with them, whether any accommodation can be made for that situation, and whether Mr. Myers believes this bill is adequate for their purposes. MR. MYERS answered that there are multiple issues involving their particular leases and elaborated: I did use the discretion of the director there to extend their leases. They're past their three-year primary term, so they ... have two years left ... on a term that's actually going to end up being six years. And the reason that that determination was made was that they were doing a lot of good exploration and work on adjoining, Native-owned leases. And that work was directly appropriate for the development of the fractured shale ... in their reservoir. So ... they did, in fact, get an extension ... of term. Realistically, for them to go into production, in my opinion, it's going to require unitization. And through unitization, they'd have the right to extend those leases ... when they enter the unit. One of the reasons you need to do unitization of the area is because [of] the mixture of lease ownership, and you have to worry about the correlative rights ... between ... NANA [Regional Corporation] and the state; those are state lands. So it's the appropriate, normal way to go. Under unitization, those leases would be preserved as long as they are under production or under a (indisc.) of exploration. So, again, normally that's what we do with conventional leases; that would follow there. And, really, it takes care ... of their issue. Barring that, if they decided not to go ahead with future exploration, I think ... we'd be open to considering an exploration license application for the entire area that they're talking about. Again, I think ... they're sort of the "poster activity" that you want to see encouraged, that has local energy, ... fractured shales, a nonconventional gas source. ... Through the process of these bills, I believe, they would actually end up with a better-quality product. Some of their resource potential is, in fact, deeper than the 3,000 feet, which creates some correlative- rights problems in their area. That would be taken care of if they had a license; they would have [a] longer term for exploration, and then they would convert to a conventional lease with known terms. MR. MYERS said under this scenario he doesn't think there is any conventional gas potential in the area; thus they could end up applying for and being granted a nonconventional gas [designation], and could get a royalty rate and rental structure similar to the shallow gas program. He added: In either case, ... when I ran ... through their particular situation, I think they're fine if they want to go through the process of unitization ... and further development of shallow gas leases. They're probably in good shape if they decided not to and wanted to, again, go back and apply for an exploration license. So I think we've worked through that, particularly with their issues, but I don't really want to speak for them. But we have had those discussions. Number 2157 REPRESENTATIVE ROKEBERG asked whether they could in some way "top lease" it with an exploration license to protect themselves before their current leases expire. He also inquired how that transition would be handled so their investment is protected and so forth. MR. MYERS agreed they certainly could do that. The one risk would be if someone outbid them for the work commitment. He said he thinks it's possible but unlikely - if they own or manage the mine operations, have the equipment there, and are actively exploring on the surrounding lands - that someone else would come in and bid more for the work. He said [DNR] traditionally hasn't [offered] exploration licenses over shallow gas leases because of correlative-rights issues, for example, not wanting to deal with someone producing gas from 4,000 feet that is geologically connected to [gas at] 3,000 feet. MR. MYERS also suggested [the people at Teck Cominco Limited] could relinquish their shallow gas lease at the same time they applied for the exploration license, and then there wouldn't be a problem. Given the state of their exploration program, he said, it would be logical if they chose to apply for a unit; then the only cost besides the demonstration of their work commitment (indisc.) would be a $5,000 unit-application fee. Number 2069 REPRESENTATIVE ROKEBERG inquired about drilling test holes or having the position verified geologically. MR. MYERS answered that they've drilled numerous core-hole tests, but haven't had a long-term production test. He said one reason he'd extended the lease was because of their intent to do that; although the test probably would've been on adjoining, non-state lands, the information would've demonstrated the economics appropriate to the state lands. He added: Under unitization, ... we would go ahead and unitize both NANA and state lands out there, so there'd be ... a joint unit, in which case the work activities wouldn't have to exclusively occur on state land; it would have to occur on the unit for the purpose of the unitization. So I think, when you work through their situation, they are normally ... where you might expect someone to be in ... kind of a middle stage of exploration, and we often form exploration units at that point in time. Now, [if] the lease is conventional or nonconventional, it wouldn't matter - or shallow gas or conventional, areawide. CHAIR KOHRING opened public testimony. Number 1965 PATRICIA MACK informed members that she and her husband live in the Mat-Su area. Saying she wished [the legislature] would be as creative with that area's residential problems [relating to shallow gas leases] as with the Red Dog mine, she remarked, "I thought that was a very clean-sounding deal." She understands units, she said, but also understands that unitization pulls in people who are unwilling to participate in the plan, in what is called "forced pooling." Responding to remarks from Mr. Myers, she clarified that she was referring not to exploration, but to the decision to actually start producing. Noting that the Mat- Su situation involves small parcels of land, since perhaps 800 of the properties are one to five acres in size, she said more than 12,000 families are being affected. MR. MYERS answered that unitization occurs with respect to the subsurface owner, and the owner of the subsurface mineral rights generally won't be "force pooled" into that situation. He added, "If you did, you would not be forced ... into the unit if the state did not own the subsurface rights." MS. MACK expressed concern, however, that "under your oil and gas rules, you do have that clause." MR. MYERS affirmed that, saying it protects adjoining landowners. He explained: In other words, if they drill a well within close proximity to your land, it's just possible the gas they remove from the ground may be ... from your land, even if the well bore isn't on their land. You are not compensated for that unless you're part of the unit. ... It's also designed to protect your rights, so that you have ability to petition us for - in some cases, petition the Alaska Oil and Gas Conservation Commission [AOGCC] - so that ... your production of the gas ... from your subsurface rights are protected. So it's actually a process to protect you. ... If you don't care, no one's going to force ... your subsurface acreage into that unit. Number 1673 MS. MACK asked, "So, I wouldn't have to have a well on my property if I didn't want it." MR. MYERS replied no and said it's the opposite: "If they drill near your land, you can actually get credit and get royalties off your land." MS. MACK turned to another concern. She mentioned the DNR commissioner's fiscal year 2001 budget and said: You're using what's called the common law subsurface access ... to minerals. But under the Alaska constitution, we were provided rights for settlement, and so we have equal rights to the surface; you have rights to your subsurface. But the Supreme Court has done several rulings; one was about 20 years ago regarding coal and not coal bed methane, but they stated that the state did not need to take every drop out from under somebody's property. ... The other statement that they made recently on the East Coast, as far as ... Pennsylvania, ... they ruled that the access to the property, based on the fact that the state had watched the property being developed and had not set aside space for their development, ... was unreasonable and unnecessary. And so that was what my questions were. In densely populated areas like I live in, just the noise and the racket and the disturbance is just going to be a nightmare. Number 1582 MR. MYERS responded that one of [DNR's] purposes with the process in the valley is to work through these issues and work on specific noise-abatement standards, setbacks, and so forth. He indicated the department has heard loud and clear that people there want more certainty on "the regulatory framework." From public meetings there, he reported, a lot of information has been received that is being collated. He continued: I think ... some of your concerns will be taken care of in that regulatory process. In addition, the leases have stipulations and mitigation measures that give DNR discretion to do that ... on our state lands. We do not have that same discretion on non-state lands, however. So if the subsurface owner is other than the state, ... we don't have that same level of protection. But on state lands, we have that process, and ... we're aware of the issues. I think that's one of the things that's still recognized is, there are areas ... where if the state, rather than applicant, is driving the process, we can better customize what we lease and what we allow surface occupancy for facilities on than we can in an applicant-driven process. Number 1505 MS. MACK expressed disappointment in this whole process, having been to all those meetings; said she has never been more disappointed in a group of [legislators] in her life; and noted how horrible it has been to have a [shallow gas] well put in her backyard. She continued: I grew up in this state, and I was here when it became a state. And they gave us our land here because ... they wrote our constitution the way that they did based on settlement and resources, because we were being taken over by monopolies. ... And that's exactly what you've created here, ... a monster you can't control. CHAIR KOHRING offered assurance to Ms. Mack that the committee was trying to address her concerns. He said the constitution also created the situation that allows the state to develop on someone's land, although there are rigorous rules and hoops to jump through. He voiced confidence that DNR will take great care and use discretion to make sure that issues such as noise, setbacks, "visual issues," pollution, and so forth are addressed before permits are issued. MS. MACK suggested the need to look at the constitution more closely and said people will go to court when someone just shows up in their yards [as happened with the shallow gas leases]. Number 1377 ROBERTA HIGHLAND, Kachemak Bay Property Owners Association, Homer, said she appreciates and supports the intention of the bill, which seems to attempt to correct bad legislation, HB 394 and HB 69, that has turned many people's lives upside down. However, she said, HB 531 and SB 312 [the companion bill in the Senate] do nothing to correct the problem of already leased land in some very inappropriate areas including Homer's water reservoir, a public school, churches, heavily populated areas, and popular local ski trails. Noting how dearly people can pay for bad legislation, Ms. Highland expressed concern that this current legislation doesn't address the many thousands of acres leased against the will of a lot of people. Asking that this be passed, she also asked legislators to continue to strive to fix the ongoing problems with the leased properties. She mentioned a buy-back or land trade as two options. CHAIR KOHRING asked whether anyone else wished to testify. He then closed public testimony. Number 1228 REPRESENTATIVE ROKEBERG requested clarification from Mr. Myers about forced pooling. He cited an example of what he called de facto forced pooling in Oklahoma. MR. MYERS explained: We effectively have the right of forced pooling, but the cases it's used is ... the opposite of what ... the public was testifying on. Typically what happens is, it depends on the stage of a unit. Early in the life of the unit, 'cause we don't know the size, the shape, the accumulation, we have an exploration prospect under a lot of unitization cases. ... We look at the geology ... underneath it, and if it's reasonable that there's a party involved ... whose subsurface rights seem to be incorporated into that prospect, that's in our ... best guess, we will require the applicant for the unit to notify that party and invite them into the unit at reasonable terms. They do not have to accept that at that stage. ... Right there, ... the unit's operator or the applicant is required to notify them and give them opportunity. They're not required to accept, and that's it. The next stage is, if you actually have production, you form what's called a participating area. And here's where Alaska law kind of has ... two branches. ... Either DNR deals with it -- a participating area ... is the surface area underlying the area that's known to be underlain by the hydrocarbons, and it's reasonably estimated to be able to produce in paying quantities; so it's a commercial test that has to be estimated, and it has to be known to be part of the pool. But it's included in the smaller part of the unit; it's actually allocated production that you're talking about. Now, a parallel process goes on with AOGCC where, instead of looking at (indisc.), they use -- as in Oklahoma, they use what's called a pool, and they will define the outlines of that pool. ... If you picture the pool pretty simplistically as ... a big circle and you have a component of that circle whose landowner chooses not to join that unit, we will not force someone to join that unit. However, ... the operator will have to accord them the opportunity. Now, ... the owner has state subsurface rights that are being developed; they're primary rights. If they don't petition us, we won't do anything. If they're state's rights, we will probably make the argument for forced pooling ... so that they gets its royalty share. So the cases she was talking about, ... I believe, the state owns either the surface or the subsurface, and the applicant - the person on the land - didn't want to see ... any production or didn't care if they got any royalties allocated to their production. We're not going to force a person in that position to join the unit. Number 0953 MR. MYERS continued: There are other protections, though. If they drill within a certain distance of that person's lease line, with unleased acreage, AOGCC, if it's a certain distance, has no authority. But if it's closer than that distance -- and [typically], like an oil well, for example, it's 500 feet. If they drill within 500 feet of the lease line, they must get an exception. To get that exception, they generally have to hold a public hearing, in which case that person can complain about it or not. If that person doesn't complain about it, they will grant the exception and they will allow that person to be drained. ... Generally, it's in that person's - who owns the subsurface - interest to be accredited production from their acreage, and there's a vehicle to get that. And there's forced unitization or forced pooling allowed to get to that point. If that person owns the subsurface and chooses to be drained, essentially, I don't think the state ... would "force pool" or interfere. Does that make sense? Number 0875 REPRESENTATIVE ROKEBERG asked, then, whether someone can basically opt out of forced pooling under the state's statutes. MR. MYERS affirmed that and said the opportunity would be there if the person elected not to do it and the state didn't "have a fight." He added, "It's a correlative-rights issue, where the party chooses ... not to exercise their correlative rights." Number 0839 REPRESENTATIVE ROKEBERG asked whether it's the geological formation or the unit that will be the participant. He also inquired whether it's usually AOGCC that looks at the pool and determines the allocation of participatory rights, for example. MR. MYERS characterized it as a "black hole" that has never been cleaned up and said there are two parallel paths. He explained: Under DNR's authority, we use participating areas, which basically are the outline of the commercial part of the reservoir, if you think about that, the surface expression of that. ... We use "participating area" for that surface expression of the reservoir or pool; AOGCC uses the term "pool" for basically ... the same reason. One of the differences is, DNR typically is a royalty owner, but we still have a responsibility to ... prevent physical and economic waste. AOGCC has similar statutes under their pool standard, which is a slightly different but very similar standard. Of course, they're not representing the state ... as royalty owner. ... So the process is roughly parallel. ... Within a unit ... if you form a PA [participating area], there's often a parallel process of forming a pool. And generally the pools and the PAs are identical or nearly identical, and often we hold joint meetings with the applicant to do that. ... The process is driven by ... the formation of the unit, and the unit is typically represented by the unit operator, although through the process, anybody affected by the unit is publicly noticed and they have ... the right to petition us or a right to a hearing, typically. And they have a similar right under AOGCC. MR. MYERS acknowledged it's confusing, and reiterated that they're almost parallel but slightly different processes. Number 0675 REPRESENTATIVE ROKEBERG reported that at the recent Energy Council meetings a presentation addressed what different states have for damages to surface rights; he recalled that North Dakota and Oklahoma have some of the more stringent requirements. He asked whether Alaska has a statutory "damage- recovery claim" or how it is dealt with otherwise. MR. MYERS replied: It depends on who owns the subsurface. Under state subsurface, you are clearly entitled to damages statutorily, but those damages ... are determined by the courts. ... So the state has not quantified as to what those damages are, but there's a ... history of case law to sort of determine that. ... If the surface owner and the subsurface owner are different and they cannot reach a surface-access agreement, then DNR holds a bond hearing to protect the surface owner and that bond is held. And then if damages are claimed, it goes to court, and the damages are protected and paid for out of the bond. ... And that is statutorily based. There is no statutory base on non-state land. So if it's private subsurface, with a different private surface owner, there is nowhere in state statute; it's generally based on ... court cases and case law. But statutorily, they're not entitled to damages under current state law. REPRESENTATIVE ROKEBERG noted that in the Mat-Su area, for example, there could be different types of subsurface ownership; therefore, the surface estate may or may not be protected under the statutory scheme here and the surface owner could only rely on common law. He asked whether that's correct. MR. MYERS affirmed that. CHAIR KOHRING noted that time was running short for the meeting and announced that the bill would be held over. He pointed out that a possible amendment had been circulated. Number 0333 REPRESENTATIVE CRAWFORD asked how this would work in the rare instances when landowners have owned their land before statehood and thus hold subsurface as well as surface rights. MR. MYERS explained: When they come to form a unit in royalty state land, ... if their land was appropriate to be in the unit, as determined by DNR, we would require the applicant to ... notify them and offer them the chance to join the unit. If they refused to join the unit at that point in time and later exploration demonstrated the actual productive area, and they were defined as a participating area - included their land - again, they would ... have to be offered a chance to join the unit to get production. If they chose not to join the unit at that point in time, then if wells are drilled within a certain distance, ... they would have the opportunity before AOGCC to disallow that drilling, basically, within a full (indisc.) of their line, to prevent ... being drained. So there's some protection there they would have. But, generally, AOGCC would make a ruling. ... It's like, again, on oil: if ... someone proposed a well within 500 feet, AOGCC would look at it and say, "You have to get an exception." The exception will require ... that nearby landowner ... to say, "I don't want that oil because it's going to drain my property." And that would probably give AOGCC the reason not to approve the exception, and they'd have to set the well back further, at a distance generally designed in the statute and regulation to assure that they can't be drained. ... There's multiple levels of protection in there to protect ... that person. But, again, through our process of the participating area, it would require that they be offered the opportunity ... to be part of that ... unit and get allocated a percentage of production, whether or not the well is on their land, as long as they're affected or effectively being drained. So there's multiple levels, actually, of protection to get them into the unit. If they choose, again, as the (indisc.) not to participate, I don't think that we would force them -- if a company wants you to accept it for AOGCC and ... it wasn't a protest, AOGCC ... may well grant that. MR. MYERS concluded by saying there is a possibility that non- unitized acreage can be within a participating area, but he didn't recall any cases where that happened. He added that it's always in the applicants' interest to get their royalty share. CHAIR KOHRING thanked participants. [HB 531 was held over.]
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