Legislature(2011 - 2012)BUTROVICH 205
02/28/2011 03:30 PM RESOURCES
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SB 85-TAX CREDIT FOR NEW OIL & GAS DEVELOPMENT CO-CHAIR WAGONER announced SB 85 to be up for consideration mainly for questions of the administration. From the AOGCC Cathy Foerster and John Norman, from Department of Natural Resources (DNR) Kevin Banks, and from the Department of Revenue (DOR) Jerry Burnett were present. 3:40:14 PM He said he had distributed nine issues that he and his chief of staff came up with while talking to various members of the administration staff - AOGCC, DNR and DOR. But, before they go there, he asked if there were any other questions. SENATOR FRENCH asked what it costs to get a field ready for production. CO-CHAIR WAGONER remarked that was question number 7. 3:41:20 PM KEVIN BANKS, Director, Division of Oil and Gas, Department of Natural Resources (DNR), said he didn't have those kinds of figures before him at the moment. Some information may have been published along with the development of the Nakiachuk project and the Oooguruk project, which are two fairly recent developments and he remembered those numbers to be in excess of $1 billion. He said his information will be based on what has been published in the trade papers and the Anchorage press. SENATOR FRENCH said that would be very helpful. CO-CHAIR WAGONER said he asked a couple of people today about prices of just drilling a well on the North Slope and found a range from $12 million to $300 million depending on the well and its location. CO-CHAIR PASKVAN asked what the administration might think is the correct parameters for a sunset and then what the interplay of this credit would be with the other credits. He also asked about the ring fence issue. MR. BANKS responded to his first question, how long it takes some projects to get off the ground and said some start up within four years, but the average since Alpine started in the early 90's is around seven years. 3:44:15 PM] SENATOR WIELECHOWSKI joined the committee. CO-CHAIR WAGONER said the problem with Cook Inlet is that it has no production tax now, so SB 85 wouldn't be applicable there, although it would apply in the rest of the state. SENATOR WIELECHOWSKI asked if someone did develop in Cook Inlet could they write that off of their production taxes on the North Slope. SENATOR FRENCH said he thought that any company operating in Alaska would be able to do that. MR. BANKS agreed that it was also his impression that if a company was doing some work in the NPRA and accruing these credits over the time it took to go from exploration to production, credits could apply to taxes paid anywhere else. However, at least the bill does limit how long that may be done. CO-CHAIR WAGONER said AOGCC was on line earlier and they talked about them being the agency to certify the production instead of DNR. 3:47:43 PM KATHY FORESTER, Commissioner, Alaska Oil and Gas Conservation Commission (AOGCC), answered that would be consistent with what the agency already does and that wouldn't require a fiscal note. CO-CHAIR WAGONER stated that AOGCC certifies statewide, while DNR does it only on state lands. MS. FORESTER said that is a good point. CO-CHAIR WAGONER asked her to speak a little bit about their earlier discussion on the "pool" as it applies to shale production. MS. FORESTER explained that these shales tend to be just regional trends that cover large areas. While the drainage area for one well may not impact other wells, they have the expertise to be able it say if there is continuity and contiguity, then it really is one reservoir. Then the onus would be on the operator to scientifically prove it is a new discovery. 3:49:49 PM SENATOR WIELECHOWSKI said the committee just had a presentation by Great Bear on Saturday where they talked about the Shugalik Formation that appeared to run the whole length of the North Slope west to east. Would that be considered one pool? MS. FORESTER replied that the operator would have to provide clear proof of an area being a separate pool like a big fault and seismic data showing a break in contiguity. In the absence of that proof the agency would say it is one pool. SENATOR WIELECHOWSKI said they also hear that the Shugalik Formation flows into Prudhoe. He asked if the Kuparuk and Alpine are flowing from the same reservoir. MS. FORESTER replied that Kuparuk, Alpine and Prudhoe are all separate pools, but they are all fed by the deeper shales. So, as the shale goes east to west it would be the source that feeds all of those pools. SENATOR PASKVAN said he understands that three layers of shale in Alaska are considered the shale source rocks. Would each one of those layers in the east/west "Fairway" be considered one pool? MS. FORESTER answered no. If they are not continuous and contiguous with one another, if they are at different vertical depths they wouldn't be considered one pool. CO-CHAIR PASKVAN said he understands that those three source rocks are on top of one another and asked if an individual pool can run for 300-500 miles. MS. FORESTER answered yes. SENATOR WIELECHOWSKI said they heard testimony that Great Bear could drill down and hit the HRZ, the Shublik and the Kingak pools. So, the way this bill is written would they get separate tax credits or would they possibly get additional tax credits for one drill that went through three different pools? MS. FORESTER replied that she didn't know the answer. They are three separate pools. If one well drilled through all three of them that would be the discovery well for all three. Whether Great Bear chose to develop the three simultaneous or separately would be their call. They could develop them separately but they would have one discovery well and each pool would have its trigger start when that pool produces. 3:54:27 PM SENATOR PASKVAN asked if the first producer accesses a particular pool - the three layers of source rock as she defines it - could other potential developers be able to claim the credit if Great Bear were to penetrate all three pools. MS. FORESTER replied if the first operator penetrates and discovers all three, then they get the credit for the discovery. The next trigger is when they complete the first well, and if they complete a well in all three, then that starts the clock on all three. But what she said earlier still holds - those are three separate pools, but if another operator comes in 50 miles away and provides data that says their discovery and development is not in communication with theirs, then they could get it. It would have to be a geological barrier that wouldn't allow them to communicate. MR. BANKS added if the goal of this legislation is to provide credits for multiple penetrations in either one of those shale horizons, then obviously they will need some work. Everything Ms. Forester said is correct. If the idea is to provide for a set of development credits for the first discovery of a well that is capable of producing in paying quantities, if there were no faulting or discontinuities in the shale layer that had been penetrated by that discovery well, it would mean that no more credits would be offered to the other players that may be drilling into the shale prospect. CO-CHAIR WAGONER said that is what he was starting to think and he had gotten past where he wanted to go, because his idea was to generate activity to fill up the TAPS pipeline. He didn't want to be concerned over the pool issue because this is entirely different than a pool of oil caused by a trap. They must look more at the language he concluded. He asked him to talk about unitization. 3:58:13 PM MR. BANKS responded that typically they want to see a unit formed by DNR (the AOGCC can do it, too) to assure that the resources are developed and conserved in that development. They also want to make sure correlative rights are protected where there may be different ownership of adjoining leases. The idea behind unitization is conservation, correlative rights, and DNR's interest in the economic development of the resource without duplicative facilities on the surface. If you can imagine a conventional pool of oil or gas, the idea is to make sure that all of the lease tracts that may overlay parts of that pool that contribute to production get their fair share of the cost and the revenues from its development. Oil and gas shale may be more complicated because the wells produce from a fairly limited distance from the well bore and don't necessarily drain the oil or gas from another lease/well nearby. So, the issue surrounding unitization with shale would be a little bit more complicated and they are considering whether or not unitization is even necessary for a shale play since each lease can be developed from a set of wells without concern that they may drain the adjoining leases. CO-CHAIR WAGONER said it really depends more on the acres per well than unitization. In other words they are talking dropping down to a surface size of about 80 acres and if you're drilling into an 80-acre spot - the department showed a perspective of what would happen - it was kind of a checkerboard. Would that not be the case? MR. BANKS responded that was most of the story. In places like North Dakota the average well spacing was something under 160 acres. But it's also how close to the lease boundary the wells are drilled and that's under the purview of the AOGCC. CO-CHAIR PASKVAN asked if essentially the lease boundaries would be sufficient in and of themselves to define access it the money from that well for a shale play - because it's not draining from across the lease boundary. MR. BANKS responded that is where he is headed with this, and while his understanding of other jurisdictions like North Dakota and Texas is limited, he didn't think unitization is common with shale plays because there isn't a concern about drainage from one lease to another. 4:02:57 PM MS. FORESTER said the only time unitization might be warranted in this kind of development is if there are economies that could encourage greater ultimate recovery to be gained - in other words stopping competition between checkerboard small leases. CO-CHAIR WAGONER directed the discussion to commercial production. MR. BANKS said he was looking at "commercial production" on page 2, line 24, and thought about using an expression like "capable of production in paying quantities" in terms of "expenditures that are incurred after the completion of the first well drilled that discovers a pool capable of commercial production." The department has definitions in its regulations for purposes of defining what the expression means that they could use for production in paying quantities. He also wanted to see "sustained production" on line 25 as a requirement before commencement of production in "paying quantities". Again, he said the DNR uses regulatory language for "unitization" and "sustained production" that the committee might want to look at. SENATOR FRENCH asked him to walk the committee through the timeline or typical stages of development that will help him better understand what they are potentially putting the state on the hook for - before getting to paying quantities. The seismic and exploration work has been done, an area has been located where they think it's worth money to drill - all of those costs are excluded by this because they haven't drilled a well yet. 4:06:21 PM MR. BANKS replied they are basically talking about a period of time that could be as little as 4 years to as long as 11 or 12 years, which is what is seen in conventional plays in the last 15 years or so. Any seismic and other work that might have been done prior to the drilling of the exploration well would not be entitled to a credit in this bill. In fact, the exploration well itself would not be entitled to these credits. They actually begin when expenditures are being made to go through the next stages and he defined those as basically two: delineation where further wells are drilled to get a better understanding of the extent of the prospect that has been discovered. The exploration well tells you that oil is there; now you need to know just how well this area can be defined and how much eventual production can be produced from it. And, after delineation, a company would be making commitments to begin development. This stage includes the construction of many of the surface facilities and roads, pipelines/flow lines and processing facilities. Finally it gets to the point where production begins and the commencement of "sustained" or "production in paying quantities" would occur when all of the kit is in place and ready to go. The period between this delineation and development stage can be anywhere from 4-7 years. Folks at Great Bear think they can get their shale plays into production must faster, but that depends on their ability to access the wells 365/days a year in order to move the oil into a pipeline. 4:09:30 PM SENATOR FRENCH asked where Alaska is in this process - where they know there is a pool capable of commercial production because a well has been drilled there, but they haven't begun the surface development. Is there a "perfect poster child" for this bill? MR. BANKS replied that he could think of situations where exploration wells have been drilled and the first question - is oil there - has been answered. Now the delineation process is beginning. He just recently unitized the Dewline Unit and the Beechey Point Unit north of Prudhoe Bay. A couple of units in NPRA have had exploration wells drilled, but the delineation still needs to occur. The bill as it is now looks for prospects that haven't been explored and exploration drilling hasn't occurred. He didn't know if they have a lot of candidates in line for that. MS. FORESTER added an example of something that is already discovered that operators are playing with but have never made commercial and that would be the Ugnu. That throws in another question: do you want to incentivize that sort of production as well? CO-CHAIR WAGONER said that is something to think about. CO-CHAIR PASKVAN asked where Sag River would fit in with the exploration delineation development timeline. MS. FORESTER said she wasn't familiar with the details of that project. MR. BANKS replied that Sag River is a tight sand formation that has been under production at Milne Point. He didn't know to what extent this type of play exists in a lot of other places. 4:12:39 PM CO-CHAIR WAGONER asked Ms. Forester about the possibility of overproducing a field to get the high credits to offset gold plating development costs. The result would be to deplete the fields. MS. FORESTER asked if he was talking about an operator discovering the pool and then completing the first well but not establishing production until he had put in all the wells. CO-CHAIR WAGONER replied no. He is talking about a company getting high credits for its tax liability with overproduction which would deplete the wells. Would a cap help them get away from the risk of gold plating? MS. FORESTER said if he meant they couldn't recover any more than their liability and that would prevent them from gaming the system, her answer is that she never underestimates an operator's ability to get "cagey." CO-CHAIR WAGONER said they are just trying to be careful. SENATOR WIELECHOWSKI said one concern he had was that production curves typically spike up and then slope downward, and since they have companies that will go out and spend maybe hundreds of millions of dollars developing the well, he asked if she foresees a situation where a company tries to take out more oil and having that potentially damage the field or cause waste down the line. MS. FORESTER answered that existing statutes and regulations require operators to come to the AOGCC for pool rules before they begin production and they have to demonstrate how they plan to drill the field, plumb up the wells and produce them. Prevention of waste is one of the primary things AOGCC does. So, if an operator came in with a plan that in some way looks like it would be causing waste, they would deny it. CO-CHAIR PASKVAN said he didn't understand how gold plating development costs fit in. CO-CHAIR WAGONER gave an example of when a company would spend money that they don't necessarily have to spend to achieve the goal - like using a bigger machine than necessary just to get more money back on the credit side. SENATOR FRENCH said he had a flip-side question to Senator Wielechowski's one about accelerated production: what incentives might be in the bill to delay commencement of production because a company would be getting a credit for every nickel of development costs they incur. 4:16:54 PM SENATOR STEVENS joined the committee. MS. FORESTER responded that is something an operator would do if the credit wasn't capped at their tax liability for any given year as well as capping the number of years in which the credit can be used, which a sunset would accomplish. MR. BANKS added that section (c) on page 3, line 2, creates a tension because it says a company is not entitled to cash in its credits until production begins. The other factor is that any delay in receiving the cash for credits will play against the net present value of that delay. 4:19:58 PM CO-CHAIR WAGONER emphasized that the credit is limited by how much a company's production is per year. CO-CHAIR PASKVAN asked again where these credits fit in with all the other credits the state offers. MR. BANKS responded that a company might be entitled to some of the AS 43.55.025 credits for the exploration well during this development state - post discovery - and is not entitled to any other kind of credit, the capital credits for example. And then post production the tax is calculated on the basis of just the normal deductions and then as the chairman has pointed out on page 3, line 23, of SB 85 this credit that is limited by the production attributable to this particular property. So, the taxpayer has to make some kind of judgment about whether or not this bill is more valuable because they are getting 100 percent of their development costs paid for but they have to wait for the cash and they also have a cap on how much they can get versus just the normal 20 percent capital credits allowed under AS 43.55.023. 4:23:07 PM SENATOR WIELECHOWSKI said he had two concerns with the credit issue: potentially delaying well completion and gold plating. For instance, maybe Jeeps are the standard on the North Slope, but then they start using Humvees which are twice the price. He wasn't sure they had fully addressed either concern. MR. BANKS said he would have to think about the gold plating issue and commented that whenever the state is paying a part of the cost it represents some concern and the larger the credit the bigger the problem. Here, even though the state is willing to cover 100 percent of the costs during the development stage, whether or not a company could get enough production to generate a tax liability against which the credit will apply remains a question. So, taking a chance that you will somehow be able to artificially inflate your credits against potential production in the first five years of the field seems to be an offsetting incentive. If you don't think you are going to get all of your credits back you might not be willing to artificially pump up the cost. 4:25:24 PM MS. FORESTER added that the risk of gold plating is low on Senator Wielechowski's example because the operator still has to get a return on his investment. If he buys a Humvee he still has to get a return on that Humvee. If he could make more money buying a Jeep he's not going to try "to screw the state" with a little tax credit. But she thought the gold plating could become an issue if the operator says he only has the potential to have 20,000 barrels/day of production for 10 years on what he currently has leased, but he thought he could expand in the future and wants to put in a huge facility right now (to be ready to handle all of that extra production). And she wasn't sure they don't want to encourage an operator to hope he can get 80,000 barrels/day instead of 20,000. 4:27:14 PM SENATOR MCGUIRE said on the unitization issue she has heard that the downside of ACES has really fallen on the satellites in the unit, and that areas in Kuparuk and Prudhoe Bay would be developed but for the tax system. She wondered if they want to talk about that at some point because this new credit applies only to areas that haven't been within a unit. CO-CHAIR WAGONER said the bill currently excludes them and he wanted someone to "work that portion of it" and volunteered her to do it. Several plays in currently unitized areas are not commercially feasible to produce because of the tax structure or a couple of other items, and they hadn't come up with any recommendations yet. CO-CHAIR PASKVAN asked if one system would be preferable to another system for either an unconventional or a conventional oil play. MS. FORESTER stated that he should ask the operators for their advice on that because they are much more familiar with their economic situations that she is. MR. BANKS offered that it comes down to the two issues they have already talked about: how much of the 100 percent credit will be realized in the first five years of production given that sort of caps the size of the cash flow one would get from the state, and also the fact that you have to wait between the time of making those expenditures and the start of production. Having said that, if you have a prospect that will require significant challenges in terms of what the development might look like - it might be something like an offshore prospect or something on federal land that may be fraught with permitting issues - that means you're going to be waiting a long time before you are able to realize any kind of benefits from the credits. Shale oil has high initial rates of production, but then very quickly drops down to a more steady rate - Bakken 1,000 barrels/day initially but within two years or so it dropped down to a couple hundred barrels a day. Depending on how many wells fit under some kind of project like this it may be defined as a property that qualifies for this kind of tax, but an operator may find that the amount of tax liability he is accruing in the first five years of production might not be enough to make up for the initial investment, and the 100 percent credit is less valuable for that reason. CO-CHAIR WAGONER stated that this credit isn't meant to pay 100 percent of their costs, but it's supposed to incentivize and help a company get financing to do a project. SENATOR WIELECHOWSKI said they should be very careful in terms of expansion. He said he had pulled up an old presentation from the Department of Revenue that showed the state currently picks up 76 percent of the costs of an exploration well. If they are now going to pick up 100 percent of the development costs, at what point do they say let's just pick up the other 24 percent and end up socializing the entire risk and privatizing all the profits. He asked Mr. Banks how to define "sustained production" in the context of Point Thomson that is supposed to start producing 10,000 barrels of condensate per day; would that be considered sustained production? MR. BANKS answered that he had suggested earlier using language from the department's unitization regulations that say "sustained unit production" means, "continuing production of oil or gas from a reservoir in the unit area into a pipeline or other means of transportation to market, but does not include testing, evaluation or pilot production." So, depending on how they view the 10,000 barrel/day project in the Exxon Point Thomson case, that may almost be regarded as pilot production, but that determination hasn't been made yet. 4:36:41 PM SENATOR WIELECHOWSKI said they hear testimony on wells that are marginal and he wanted to get as much data as possible about why that is so. So he asked the DOR to provide as much data as they could on why are the fields marginal. What lever can the state pull to get them in production? Roads? Royalty relief? A tax break? He didn't feel they had the data that is needed to make a lot of these decisions. 4:37:34 PM Finding no further comments, Co-Chair Wagoner thanked everyone for coming and adjourned the meeting at 4:37 p.m.