SB 85-TAX CREDIT FOR NEW OIL & GAS DEVELOPMENT  3:40:48 PM CO-CHAIR WAGONER announced the consideration of SB 85, and stated that he was maintaining his objection to version E. 3:41:25 PM CATHY FORESTER, Commissioner, Alaska Oil and Gas Conservation Commission (AOGCC), said she would respond to questions that were submitted earlier. As to whether the AOGCC could accept the current definition of "sustained production," she said the answer was yes. As to how they feel about using the term "pool" as the defining mechanism for a new discovery, she said they don't feel at all good about that. She related that the AOGCC asked the Interstate Oil and Gas Compact Commission to query other states and the two that responded warned against using "pool" because a development has to be well underway before it's possible to ascertain whether there is more than one pool or just one blanket pool. To incentivize more than just one operator to explore and develop, the suggestion was to use some other than means to define a new discovery, but nobody offered a good alternative. CO-CHAIR WAGONER asked if the AOGCC talked to anybody in North Dakota. MS. FORESTER replied the states that responded were South Dakota and Indiana. CO-CHAIR WAGONER reported that someone from North Dakota told him their defining mechanism for a new discovery was two sections of land. MS. FORESTER responded that AOGCC supports using a reasonable unit of land, and couldn't give a better answer than that until there was some production and a fair number of wells. SENATOR WIELECHOWSKI noted that Great Bear testified there were multiple strata, and asked if she foresaw difficulties arising if a lease had three different strata of oil formations. MS. FORESTER explained that each stratum should be viewed as an individual pool, because they wouldn't have connectivity or communication. CO-CHAIR WAGONER added that North Dakota addresses that situation the same way. The only difference he found was that if the oil is on two different levels within the two-section boundary, there would be six wells instead of three. MS. FORESTER reiterated that each stratum would be a pool. SENATOR WIELECHOWSKI asked if one well could theoretically deal with three pools. MS. FORESTER answered yes, but an AOGCC permit to co-mingle the pools would be necessary. Co-mingling would require proof that the recovery wouldn't create waste; the production would have to be as good as or better than if each pool was produced separately. SENATOR WIELECHOWSKI referenced page 3, lines 16-18, that talks about qualified development expenditures, and asked if operating expense (opex) might be included in that type of exploration well. MS. FORESTER answered it was the committee's prerogative to define things in the bill, but in general operating costs are the costs of producing. Operating costs typically begin once the well starts to operate, and includes things like performing a workover to fix broken wells, paying an operator to turn valves and feeding people who work in the camp. The costs up to the point that production begins would be allocated to exploration and development. CO-CHAIR PASKVAN asked hypothetically how many wells could be drilled in 365 days at the Bakken Shale Oil Field. MS. FORESTER replied she didn't have enough familiarity with that operation to give an answer. CO-CHAIR PASKVAN asked where he could get an answer. MS. FORESTER offered to ask the question of Lynn Helms, her counterpart at IOGCC. 3:49:23 PM CO-CHAIR PASKVAN clarified that he wanted to know how many wells each of 20 drill rigs could drill in one year's time. He explained that that was where they would define the qualified development expenditure as to whether or not production was going on. SENATOR WIELECHOWSKI asked if it presented a challenge to define heavy oil in a pool. MS. FORESTER replied there are two groups of heavy and viscous oil. One is the West Sak/Schrader Bluff, which varies in oil viscosity from very viscous and hard to produce to less viscous and easier to produce. The less viscous oil is already being developed. The other very viscous heavy oil is found in the Ugnu and a very small area is currently under pilot to see if it can be produced. A lot of both the West Sak/Schrader Bluff and the Ugnu are not developable with current technology, and the defining mechanism for those separate blanket reservoirs would be on viscosity, not new pool. The low viscosity oil is already under production, and the high viscosity hard-to-get oil should be incentivized. 3:51:52 PM SENATOR STEVENS joined the committee. SENATOR WIELECHOWSKI asked if she foresaw any problems in defining a pool of heavy oil. MS. FORESTER replied the West Sak/Schrader Bluff and the Ugnu are each individual big pools by the AOGCC's definition. And for the sake of what the committee is trying to do, the standard definition of "pool" doesn't work. She said it works in conventional reservoirs, but not in unconventional reservoirs. Viscous oil, shale oil and gas and probably coal bed methane are different. SENATOR WIELECHOWSKI asked her to describe "sustained production." MS. FORESTER replied the definition says production goes into a sale and doesn't include testing, evaluation and pilots. The Ugnu is called a pilot, but once it gets into a pipeline it's on production. SENATOR WIELECHOWSKI recapped that sustained production means when it goes in a pipeline. MS. FORESTER replied that's the definition in the statutes, and the AOGCC has no difficulty understanding and applying that definition. 3:55:25 PM CO-CHAIR PASKVAN asked, in a shale oil field, how long it takes, on average, from the start of drilling to first production. MS. FORESTER replied she would ask Lynn Helms that question, because neither she nor Mr. Seamount had experience with shale oil or gas development. CO-CHAIR WAGONER asked if on the first well it would be the well itself, a pipeline, a treatment plant and an agreement to enter the TAPS. MS. FORESTER agreed. SENATOR WIELECHOWSKI referenced an AOGCC chart and asked if she could explain the variations in time for bringing on North Slope oil fields. Kuparuk River Melt Water took a year and one-half to bring to regular production, whereas Coleville River/Nanook took six and one-half years and Nokia Chuck at Schrader Bluff took six and three-fourth years. MS. FORESTER replied one thing was proximity to the infrastructure and another was having all the commercial agreements in place. Any problems with either will slow progress. 3:58:19 PM SENATOR STEDMAN asked about the status of AOGCC's data gathering task regarding how may well feet were drilled. MS. FORESTER replied it was just about finished and Mr. Seamount would deliver it the next time he was in Juneau. SENATOR STEDMAN expressed a desire for the committee to hear the presentation. MS. FORESTER confirmed that AOGCC would deliver the presentation at the committee's convenience. CO-CHAIR WAGONER thanked Ms. Forester and asked if there were questions for Mr. Banks. 3:59:53 PM CO-CHAIR PASKVAN asked Mr. Banks how long it takes in a shale oil field from the start of drilling to sustained production. KEVIN BANKS, Director, Division of Oil and Gas, Department of Natural Resources (DNR), replied a company doing work in North Dakota said that the actual drilling can go fairly quickly, but that the fracking process can cause a slowdown, because only a certain number of frac crews are available. He opined that Commissioner Forester should be able to provide a good average estimate based on information from the folks in North Dakota. He said he wanted to confirm agreement with Commissioner Forester's comments on viscosity and heavy oil. It's difficult to know what type of oil will be produced until exploration is well underway, but how credit is awarded under SB 85 is certainly the single most important variable in identifying heavy oil in Alaska. Division staff has been challenged to think about things like depth of drilling and productivity of a well as the defining mechanism for heavy oil, but every one of those things falls short of simply identifying heavy oil by its viscosity. SENATOR FRENCH asked how much it costs to drill an exploration oil well on the North Slope. MR. BANKS replied the numbers go all over the map. Wells that were drilled in the southwestern part of the NPR-A cost in excess of $70-80 million, whereas wells drilled at Pt. Thomson were probably closer to $100 million. In Alaska, shale wells may cost $20-25 million depending on the distance from the Haul Road. He noted that information from an earlier presentation indicated that the average cost for a well in North Dakota was $6.1 million. SENATOR FRENCH asked if those were exploration wells. MR. BANKS answered no, those were shale wells. He estimated that a North Slope exploration well that was close to the Haul Road would cost about $25-30 million. SENATOR FRENCH asked what would be considered a healthy level of exploration wells drilled every year, and noted that since 2003 the number was about 10 wells per year. MR. BANKS answered "the more the merrier." SENATOR FRENCH questioned whether the focus should be on encouraging more exploration wells or on the development costs to bring a pool of oil to production. MR. BANKS responded that Alaska is challenged with high costs and remoteness, and the state has very few levers to pull that would have an effect on cost. SENATOR FRENCH asked what percent of the cost of an exploration well is state subsidized through credits under ACES. MR. BANKS replied it would depend on how far the well was from existing infrastructure, but it could be the 40 percent direct exploration credit plus the net operating losses. He offered to follow up with a more exact answer. SENATOR FRENCH expressed concern that the bill was unclear with regard to what it would cost the state. He suggested that an alternative would be for the state to annually appropriate a sizeable amount of money to stimulate 10 exploration wells. Once the money was gone that would be it until the next appropriation. 4:08:22 PM CO-CHAIR WAGONER asked how to define an exploratory shale well as opposed to a production well, and the number of wells that had been drilled through the shale structures. MR. BANKS offered to follow up with an exact number, but it was very few. To define a shale prospect for the purposes of SB 85, he suggested using area rather than the normal definition of a pool, because the credit may not be available to anyone else once the once development and production started on the first set of wells. 4:11:28 PM ]BRUCE TANGEMAN, Deputy Commissioner, Department of Revenue (DOR), introduced himself.{ CO-CHAIR WAGONER asked if the committee had any questions for Mr. Tangeman. SENATOR FRENCH asked what percent of the cost of an exploration well is state-subsidized through credits under ACES. MR. TANGEMAN replied that for the exploration stage companies would be eligible for up to a 40 percent exploration credit and a 25 percent net operating loss credit for a total of 65 percent. CO-CHAIR WAGONER observed that the Great Bear properties had the advantage of proximity to the pipeline, which would make the price relatively low for the first well to go into production. SENATOR STEDMAN referenced Senator French's question and clarified that the 65 percent would be contributed by the state and federal government and the remaining 35 percent would come from industry. He expressed a desire to hear from the administration or the consultants with regard to where else in the world that magnitude of credit was available. CO-CHAIR WAGONER said his understanding of SB 85 was that it addresses credit for production; it does not cover exploration. MR. TANGEMAN said DOR's reading of the bill was that it incentivizes development; the expenses that go into that stage would be credited against a tax liability once production starts. SENATOR FRENCH asked if cost ever precluded development because his sense was that once a pool of oil is found, there's money to develop it. The hard part is finding the oil in the first place and that's where the analysis has to take place. 4:16:27 PM MR. TANGEMAN suggested he ask DNR that question. SENATOR FRENCH said Armstrong or some other company that was actively exploring could say they'd found oil but couldn't get the money to build a production facility to get it to a pipeline. MR. TANGEMAN offered his understanding that FEX was in that position; they found oil and eventually gave their leases back to the state. SENATOR FRENCH said he'd look into that. SENATOR WIELECHOWSKI asked, under current law, if DOR or DNR audited qualified capital expenditures. MR. TANGEMAN replied DOR audits the qualified capital expenditures. SENATOR WIELECHOWSKI recalled that Gaffney Kline testified that there was a worry about gold plating if credits were more than 40 percent. He asked if the administration had concerns about giving 100 percent for capital expenditures and there being gold plating. MR. TANGEMAN replied DOR's concern with SB 85 was how it interacts with the current tax credit structure. Initially the bill said a company could take either the existing tax credit structure or the one proposed under SB 85. Now the bill says the current tax credit structure would stay in place so the company would have to carry the costs during the development stage, but they could be 100 percent reimbursed during the production stage. DOR's concern with the current language is making sure that qualified reimbursement is capped at 100 percent. CO-CHAIR PASKVAN asked if he agreed with Mr. Bank's interpretation of the current version of SB 85: that the first shale oil well may be the only one that would qualify for the credit. MR. TANGEMAN replied he would defer to Director Banks on the technical aspects, but that was one of the issues related to the definition of a pool, and when the clock starts and stops in the development stage. CO-CHAIR WAGONER recognized that Representative Bob Herron had joined the meeting. CO-CHAIR WAGONER thanked the participants and announced he would hold SB 85 in committee.