Legislature(2003 - 2004)
05/18/2003 11:15 AM O&G
* first hearing in first committee of referral
= bill was previously heard/scheduled
= bill was previously heard/scheduled
SB 185-ROYALTY REDUCTION ON CERTAIN OIL/TAX CRED [Contains discussion of HB 198, which was included in the new House committee substitute] Number 0079 CHAIR KOHRING brought before the committee CS FOR SENATE BILL NO. 185(FIN), "An Act providing for a reduction of royalty on certain oil produced from Cook Inlet submerged land, and for 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." CHAIR KOHRING requested a motion to adopt the proposed House committee substitute (HCS). [There was a motion to adopt Version U, the version passed by the Senate previously.] The committee took an at-ease from 11:28 a.m. to 11:29 a.m. in order to distribute copies of Version X. Number 0132 REPRESENTATIVE FATE moved to adopt the proposed HCS, Version 23- LS0926\X, Chenoweth, 5/17/03, as a work draft. There being no objection, Version X was before the committee. CHAIR KOHRING explained that Version X includes the original HB 198, which relates to platform royalty-reduction provisions; the governor's tax-severance credit provisions that were put in on the Senate side; and new amendments requested by the industry. Number 0224 The committee took an at-ease at 11:30 a.m. that lasted less than a minute. CHAIR KOHRING explained that rather than dealing with amendments, he'd rolled the changes into one package. He asked that the sponsor provide details. Number 0263 SENATOR THOMAS WAGONER, Alaska State Legislature, sponsor of SB 185, thanked Chair Kohring for his work on the bill. He then told members SB 185 provides for reduction of royalty [on] oil produced in certain Cook Inlet fields and platforms as they near the end of their production capability. The intent is to provide a monetary incentive in the form of royalty relief to maximize production from oil fields and extend the longevity of Cook Inlet oil platforms; in return, there will be continued employment in the area, rather than loss of jobs because of the abandonment of those fields. Senator Wagoner said that, to him, this is about saving onshore and offshore jobs, including maintenance and operations, if only for a few years. He stressed the importance of this to the community in Kenai. SENATOR WAGONER explained that the bill also offers exploration severance-tax credits to explorers for work performed on or after July 1, 2003, and before July 1, 2007. Presently, maximum tax credits for exploration in Alaska result in a cost of about 65 cents per dollar, which compares poorly with the credits of Northwest Territories, Alaska's nearest competitor in Canada, where the cost is 10 cents [per dollar]. He told members: Alaska is at the bottom of the list in terms of exploration credits; basically, the world's passed us by. And to catch up with that, the governor has offered this amendment to the bill to give the ... exploration credits. This bill will result in some cases in a 20 percent tax credit ... for any hole that's drilled in a radius from an existing well, 3 miles from that well out to 25 miles. Any well drilled in a radius 25 miles from an existing well and further out will get a 40 percent tax credit; that's very substantial. And that credit will be applied against severance taxes and would reduce the cost in Alaska to some 39 cents. That'd put us in about the mid-range again, and being in the mid-range and being in the United States, being a stable entity, having stable taxes, should ... put us back in good stead for the oil companies for exploration and drilling. Number 0576 REPRESENTATIVE HOLM surmised that Section 3 is the governor's proposed language. SENATOR WAGONER affirmed that. REPRESENTATIVE HOLM asked, when moving out farther from established fields, what happens when there are adjacent fields. REPRESENTATIVE ROKEBERG suggested those are units, not "fields." SENATOR WAGONER agreed and said, "The specific thing is the well - out from an existing well." AN UNIDENTIFIED SPEAKER said, "Or unit - a lease unit." Number 0651 REPRESENTATIVE ROKEBERG asked Senator Wagoner to explain the differences between [CSSB 185(FIN), labeled Version U] and Version X. The committee took an at-ease from 11:34 a.m. to 11:36 a.m. Number 0673 CHAIR KOHRING brought attention to two additional lines that had been inserted in Version X, page 7, lines 21 and 27. He asked whether anyone wanted an explanation. REPRESENTATIVE ROKEBERG asked whether it narrows the timeframe and sets the timeframe for applying for the credit. CHAIR KOHRING affirmed that. He then opened the public hearing. Number 0745 MARK MYERS, Director, Division of Oil & Gas, Department of Natural Resources (DNR), said he believed the legislation had been accurately summarized, but emphasized that there are two significantly different portions to the bill with very different purposes. The first looks at the aging Cook Inlet infrastructure and platforms, providing royalty relief modeled on when operating costs exceed the profitability of the platform; he mentioned a $20 netback oil price. He explained that this was modeled in clusters or groups for Cook Inlet platforms. It triggers automatic royalty relief: rather than having to go to an application, it drops the royalty to 5 percent, with the goal of extending the platform life up to perhaps 14 months' additional time. MR. MYERS noted that in addition to the purpose of "incremental oil production," this will maintain intact the inlet's infrastructure. He explained that as platforms are yanked out, the use of the infrastructure by the remaining platforms goes up; this increases operating costs, and it may accelerate abandonment of the offshore production, perhaps prematurely. He told the committee: So, by reducing royalty ... we believe we can have an effect on extending the life of the Cook Inlet platforms in general. And on specific platforms, by triggering royalty relief slightly ahead of ... that operating-costs-exceeding-profits point, we can hopefully stimulate additional exploration and development off the platforms. MR. MYERS concluded the "platform" part of the bill by explaining that the platforms are clustered into three groups, based on their operating costs and reservoir characteristics; this is fairly easy to quantify because there are about 30 years of production data for most of these platforms. He offered his belief that this has been modeled reasonably accurately. Furthermore, if production increases from these platforms beyond certain thresholds, the royalty rate goes back up gradually to the original 12.5 percent; this provides some "upside protection" for the state as well. Number 0906 MR. MYERS explained that the second part of the bill is a "stimulus for exploration" credit. Noting that the Department of Revenue worked extensively on these credits, he said this credit is for deposits that haven't yet been discovered. The exploration must occur outside of [existing] oil and gas units. He explained that this bill isn't intended to "incentivize" activity within the units, and said units generally are aggregations of leases that are in production. For "leases in production with a planned development," he said exploration inside that unit boundary does not receive the credit, but outside it does. If it's more than three miles from a well, it would receive a 20 percent credit; if less than three miles from a well, it would receive no credit. He told members: With the exception of certain timing restrictions on wells, ... the amendment to the bill that you see on page 7, ... [lines] 3 and 4, says that two cases where wells really aren't considered wells for purposes of [the] three-mile limit. The first is that if the well is less than 150 days old, it doesn't count as a well. And that, I think, allows for two purposes. One purpose is, someone goes out and explores [and] a ... second company is exploring nearby to them; both companies would be eligible for the credit because you'd have to base that well's existence, without this kind of language, on the first well to spud or to start drilling. The second part is, ... under this kind of credit, delineation wells of an exploration prospect would qualify as well. MR. MYERS said the second part is that 15-year-old wells aren't considered wells for this purpose. He remarked, "The logic there, I guess, is to allow the credit to be used in areas where earlier exploration occurred but there hasn't been recent exploration." He said that is the major change to the bill. Number 1057 MR. MYERS noted another major issue: when DNR gets the data, there is a six-month window during which the company can decide whether to take the credit. If it doesn't take the credit, there is no obligation to give the data to DNR to use; if the company uses the credit, it must give the data to DNR within six months of completion of the data. This broad-based credit for exploration drilling, particularly away from existing infrastructure, is for costs incurred in the early parts of exploration: the drilling of the well; the first, initial logging of the well; and certain costs incurred because of drilling. However, it doesn't allow for costs incurred from testing a well. "Again, basically, you're trying to get the company out there," he told members. Offering his experience that once there is success in exploration, a company will test the well, Mr. Myers said the state doesn't need to subsidize that activity. Number 1124 MR. MYERS specified that this bill applies equally to private, state, and federal lands. Finally, it allows a 40 percent credit for seismic data that is shot outside of units. He explained: One of the benefits of the data, in addition to spurring the explorer to shooting that data - or ... a seismic company to shoot it "on spec" - is that that data becomes public in ten years. ... And I think that's a very important concept in this bill. It's been one of our issues with new companies coming up, is it's very hard to get a hold of seismic data. Ten years, I think, allows a long period of protection for the initial investors in that seismic data, but at the ten-year time point, the data still has some value .... It also [corresponds] to the longest lease term we have. So you'd be fully protected ... at or near the time of leasing, for the entire time you held those leases. And another company with surrounding leases couldn't ... use that data ... that you had paid for. Number 1202 MR. MYERS summarized by saying there are two distinct programs under the bill. Referring to DNR's fiscal note, he pointed out that it is the same as for [HB] 185 and just addresses the platform parts of the bill, whereas the one from the Department of Revenue addresses fiscal impacts from the severance tax incentive. He urged members to get a more complete briefing from the Department of Revenue on that second part. Number 1237 REPRESENTATIVE ROKEBERG referred to Representative Holm's earlier questions and asked what happens when multiple units, such as at Prudhoe Bay, are "bounded together." He asked how that boundary is accounted for if there are multiple units that may or may not be contiguous. MR. MYERS answered: Basically, it uses the outside boundary of the unit ... under a plan of development as of a certain date. So ... the units have a geographically described outside boundary, normally referring to a lease boundary, sometimes a segregated part of a lease. So you'd be 25 miles from the aggregate of all those units that have a plan of development. REPRESENTATIVE ROKEBERG surmised that this must be 25 miles away from any unit, then. MR. MYERS said that is for the 40 percent credit, for the additional 20 percent; it isn't the case for the first 20 percent. REPRESENTATIVE ROKEBERG asked, "It's not less than 25 miles from the outer boundary; is that because if it was more than 25 miles, we'd be getting in the area of the exploration credit that already exists? Or what's the reason there?" He specified that he was asking about the 40 percent credit. MR. MYERS responded that closer than 25 miles, the economics are clearly better; there's more incentive naturally to do it. Also, 25 miles is about the distance that untreated oil, gas, and water mixed together can be sent through a production facility currently on the North Slope. So [the 25 miles] is a rough number that approximately represents the change in economics - from using the shared-facility infrastructure to having to build at least partial facilities out on the exploration site. That changes the size and scope of the discovery and its economics quite dramatically. He noted that the unit is where the production facilities reside. Number 1389 REPRESENTATIVE ROKEBERG offered his understanding, then, that if it is less than 3 miles from the bottom hole, there is zero credit. From 3 to 25 miles, there is a 20 percent credit. And beyond 25 miles, there is a 40 percent credit. MR. MYERS affirmed that. He added that the wells are described as wells less than 15 years old but more than 150 days old. REPRESENTATIVE ROKEBERG asked whether an oil or gas well in the Copper River basin automatically would qualify for the 40 percent credit because there are no units there. MR. MYERS answered that there are no wells or units in the Copper River basin; therefore, he affirmed that well and seismic data in the Copper River basin would allow for a 40 percent credit. REPRESENTATIVE ROKEBERG asked about the proposed exploration in Minto Flats. MR. MYERS said that's an exploration license, which is different from a unit. Number 1503 STEVE PORTER, Deputy Commissioner, Department of Revenue, informed members that also available on teleconference to answer questions was Dan Dickinson, who'd worked on the fiscal note. REPRESENTATIVE ROKEBERG referred to page 8 [lines 15-16] and said the production tax credit certificate is for the amount of credit allowed against production taxes. He asked whether "production taxes" means severance taxes or something else. MR. PORTER said it means severance taxes and nothing else. REPRESENTATIVE ROKEBERG asked about impacts and noted that the bill mentions the National Petroleum Reserve-Alaska (NPR-A). He said, "We currently receive little or nothing in terms of the general fund in NPR-A monies because of federal impact legislation and so forth, and state statute." He asked, "Are we giving away nothing, or could you explain that to the committee? Are we going to receive anything from NPR-A, even in spite of this?" MR. PORTER said he would ask [Mr. Dickinson] to talk in detail about this, but answered that there are basically three tax types that [the state] still receives from NPR-A. He said, "You're basically looking at severance taxes and corporate income taxes - and depending on the size of the field that is discovered, those can be substantial - as well as property taxes." [Mr. Dickinson was not available on teleconference.] Number 1617 REPRESENTATIVE ROKEBERG referred to severance taxes and asked whether there is minimum production required in order to qualify. MR. PORTER answered that this becomes an economic limit factor (ELF) issue. He said that in a highly prolific field, there is an ELF of, say, 0.9, which would be multiplied against the 12.25 or 15 percent. In a field with many wells but little production, the ELF could be close to zero. REPRESENTATIVE ROKEBERG asked about Alpine or Northstar, for example. MR. PORTER answered that Alpine actually pays a very high ELF, about 8.4 to his recollection. It's very productive, with a small number of wells. Number 1683 REPRESENTATIVE ROKEBERG suggested that there would need to be a relatively high producing, commercialized well for the ELF and the credit to kick in. He proposed that if something was marginal, it perhaps could be produced and yet wouldn't necessarily qualify for the credit unless it was sufficient in production to generate a qualification under the ELF. MR. PORTER referred to the exploration tax credit and said Section 3 [of the bill] applies to the exploration well. It doesn't matter whether it is a dry hole or a producing well. It is truly to provide an incentive for exploration. REPRESENTATIVE ROKEBERG asked, "You could use the credit generated by the dry hole against other income that would be under an ELF generation?" MR. PORTER said that is for the total severance tax liability. REPRESENTATIVE ROKEBERG offered his understanding, then, that the quality of the new well is not in play here. MR. PORTER said that is correct. REPRESENTATIVE ROKEBERG added that this [assists if the company] is paying other corporate taxes on production. The committee took a very brief at-ease. Number 1796 REPRESENTATIVE ROKEBERG moved to report HCS CSSB 185 [Version 23-LS0926\X, Chenoweth, 5/17/03] out of committee with individual recommendations and the accompanying fiscal note(s). Number 1818 MR. PORTER informed members that the changes [in Version X] don't modify the fiscal notes. He clarified that DNR had produced the fiscal note for Sections 1 and 2, whereas the Department of Revenue had produced the fiscal note for Section 3. Number 1836 CHAIR KOHRING asked whether there was any objection to the motion. There being no objection, HCS CSSB 185(O&G) was reported from the House Special Committee on Oil and Gas.