Legislature(2007 - 2008)BUTROVICH 205
10/22/2007 11:30 AM RESOURCES
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SB2001-OIL & GAS TAX AMENDMENTS 11:34:51 AM CHAIR HUGGINS announced SB 2001 to be up for consideration. ROBERT MINTZ, Kirkpatrick Lockhart Preston Gates LLP, began his presentation on SB 2001 tax issues. He said he has been working with the Department of Revenue on drafting this production tax legislation. He mentioned that Marsha Davis, Deputy Commissioner of the Department of Revenue (DOR), would arrive soon. He said he called this presentation a topical analysis simply because he doesn't intend to go through in numerical order. He said that quite a number of sections of the bill are basically conforming or technical types of amendments. He said that sections 3 - 9, 11, 12, 23, 30, 33 - 35, and 41 are conforming amendments often with only a paragraph number reference changing. Sections 24, 25, 29, 32, 42, 53 and 60 are non-substantive improvements, clarifications or corrections in the existing language and sometimes also conforming amendments. MR. MINTZ turned to the substantive part of the presentation on oil and gas production tax. 11:35:28 AM CHAIR HUGGINS interrupted to ask when he and his organization became involved in this process. MR. MINTZ replied that he worked with the Oil, Gas and Mining Section of Department of Law (DOL), until May 1, 2006 when he retired. He had worked on drafting production tax legislation law. He joined the law firm of Preston Gates & Ellis, but at the beginning of 2007 it joined with another law firm. He had worked with the Department of Revenue on implementing regulations after the PPT was enacted. More recently he has been working with the department on drafting this new legislation. CHAIR HUGGINS asked when he completed the PPT regulations. MR. MINTZ replied that phase 1 of the regulations was done and adopted in March. It encompassed the more urgent regulations so that taxpayers could calculate their taxes and fill out their returns by the deadlines. Phase 2, which is still under development, addresses giving more specific content to deductible lease expenditures. The initial PPT bill was retroactive to April 1, 2006. The legislature authorized the department to make the implementing regulations retroactive also, which is essential if one is going to implement a retroactive piece of legislation. He said there is some detail that may or may not require retroactive adjustments after the regulations are adopted. There is nothing unusual in that because it is typical for producers to file amended returns as they get additional information that relates back to the time when the initial return was filed. 11:39:33 AM CHAIR HUGGINS said his interest in the case on behalf of the committee is how coherent the return factors based on the timeliness of phase 1 are and how quickly they could be digested and reported. He asked what the reporting date was for phase 1. MR. MINTZ replied March 31. He said there is generally a 30-day lag between when regulations are filed by the lieutenant governor and when they become effective, but the producers at least had notice of what the regulations were going to be. He said, "I think that it's fair to say that they were able to implement or follow the regs in time to file their March 31 returns." 11:40:19 AM CHAIR HUGGINS said he portrayed phase 2 as the deduction criterion and that is ongoing. MR. MINTZ replied yes. SENATOR STEDMAN asked if he is representing the administration as Preston Gates. MR. MINTZ responded affirmatively. SENATOR STEDMAN asked why the administration doesn't do its own sectional review. CHAIR HUGGINS said that was a good point and he called an at ease. 11:41:30 AM at ease 12:05:36 PM CHAIR HUGGINS called the meeting back to order saying that the committee thought it important to have an administrative official present at the hearing. MARCIA DAVIS, Deputy Commissioner, Department of Revenue (DOR), joined the committee. MR. MINTZ continued by explaining that Title 43 of the Alaska Statutes has a number of different taxes and the production tax is in Chapter 55. He said the production tax is in addition to other substantial revenue producing mechanisms based on oil and gas including royalties on state oil and gas leases, oil and gas property tax and the corporate income tax. He explained that the state has had an oil and gas production tax since before statehood (starting maybe in 1955). A production tax generally imposes a percentage tax rate on some measure of the value of oil and gas produced - an idea that has evolved over time. It's important to remember that this is regarding the taxing authority that applies to oil and gas produced from land any where in the state - whether that is state oil and gas leases or private land or onshore federal leases; it does not include authority to tax on outer continental shelf (OCS) federal leases that are outside state water. 12:07:35 PM MR. MINTZ said the core provisions of the current PPT law have not been changed by the ACES bill. AS 43.55.011(e) - (i) is the fundamental provision that imposes the tax that is the production tax value of oil and gas produced in the state. Under the current system it is a net value. That value is determined by deducting upstream costs (exploration, development and production costs) from a value, which has been an existing feature of the production tax law - gross value at the point of production. Gross value has been in the law for a long time and has a lot of settled interpretation and regulations and everything else. "We don't fool with that. We start with that and then deduct the upstream costs." 12:08:51 PM The PPT law introduced several categories of new tax credits in AS 43.55.023 - .024 and changed the production tax from monthly to an annual tax, but with monthly estimated tax payments. Because it's an annual tax, there is one annual return. The current PPT has a 22.5 percent rate on the production tax value of oil and gas. In order to figure out the production tax value (net value), one must go to AS 43.55.160. Important exceptions to note are that the tax doesn't apply to the state or federal royalty share - as has always been the case. It also does not apply to the land owners' royalty share. In other words, the PPT does not apply to a private lease, which has a separate tax provision under AS 43.55.011(i). The reason for the difference is because a royalty share by definition is a kind of gross value and it just doesn't make sense to apply a net value tax to the royalty share. 12:10:23 PM MR. MINTZ said two other important exceptions are the tax ceilings on Cook Inlet oil and gas production and the minimum tax floor on Alaska North Slope (ANS) production, which under current law is a sliding percentage based on the west coast price of the ANS. 12:10:41 PM He recapped that AS 43.55.011(e) establishes a base tax rate of 22.5 percent. Section (g) has the progressivity factor that is currently calculated on a monthly basis. When the net value of oil and gas on a Btu equivalent barrel basis exceeds $40/barrel the tax rate increases by quarter percentage point for each dollar the value goes over $40. He mentioned that gas and oil are added together and are referred to on a Btu equivalent basis. 12:11:33 PM CHAIR HUGGINS asked if SB 2001 addresses gas versus oil. MR. MINTZ replied that SB 2001 doesn't change the treatment of gas versus oil. In general the percentage tax, whatever it is under the current law or the bill, applies to the total net value of oil and gas. However, Cook Inlet is treated differently because it has separate tax ceilings for oil and for gas - but that is not changed either. CHAIR HUGGINS said he intended to ask the administration when it intends to address that - because based on the rationale of corruption he has heard, if one is tainted, he assumed the other is tainted too. He said no matter how that is described, the question remains because the strategic objective is to get a gas pipeline. The legislature needs to have an expectation of what time period that will be addressed. MS. DAVIS responded that he raised a good point. She said, "Gas is sort of not right in our face. We're not really talking about gas; we're talking about oil. So what does it mean for gas?" Because the earlier PPT law dealt with both of them at the same time, she said her assumption would be that as this administration and legislature looks at the proposals, it is still happening for gas at the same time. However, they are not being given proposals for gas; that's a separate question. She elaborated: As we've mentioned earlier, we recognize it's an important thing we have to do and it is something that needs to be done because there is some concern that the way PPT was passed before by treating oil and gas the same and the way it's being approached now which is to not carve gas out and treat it any differently than before, we still have that issue coming down the pike at us. And certainly the administration wants to address it, but our recommendation is to wait and get a little closer - once we've seen what the gas proposals are. Because what those proposals are is going to tell us something about what types of gas projects we would be looking at, needing to insure our economic, and needing to insure that our tax system doesn't serve as a deterrent to. So, there is no question that important dialogue needs to come and needs to be brought before the legislature. Our preference is to bring it after we have had a look-see at the proposals that come in at the end of November and have a sense of whether there are economic proposals and what they are - because that will inform your understanding and your debate about how you need to adjust the tax system - to insure that we as a state have done everything we can to insure the economic viability of whatever those projects or that project might be. But I think you raise a very good point that this assurance to the public that we've looked at it is half way there in the sense that before PPT dealt with oil and gas the same way. We're doing the same thing here, but we recognize there's one more job to do. And we are putting it off to a little later date. 12:16:01 PM CHAIR HUGGINS said he understood this to be event-driven and he agreed with her. But he said they know what the next event is and it will ask the question of what the state will do about gas. He said he started asking this question last January and they need an answer. "I think it's important for Alaskans to understand that - and for the legislature." SENATOR STEVENS asked if Ms. Davis was comfortable with waiting until after the proposals are in to address the gas tax. MS. DAVIS replied yes: We are comfortable because the application process is going to be about building a pipeline or building a line that includes an LNG plant or it may include a variety of things. And the economic viability of that is going to depend in part on what's the price of gas at the North Slope and part of what is going to be sold often times, a majority of times, owners essentially either - they pass through that tax. And so in looking at what the tax is currently, the only statements from Commissioner Galvin on this topic have been that we're not looking to increase tax on gas. What we recognize is there actually is a sort-of built-in disadvantage to gas under this system by treating it the same as oil and gas. At least our understanding of the economics now are that treating it on an economic equivalent basis - this Btu/barrel basis - is not tracking market pricing - that we're going to have to give some more benefits. We're going to have to be more favorable - in other words cutting back on how we approach tax for gas. So right now as they look at the analysis, it would probably be a worse-case scenario as far as what they are looking at for the tax on gas and our intention would be to look at how we make it more favorable to insure a project goes. So, they have right now in terms of their economic modeling what a worse-case would be, but we're looking to improve that down the road. With that said, because it's going to be pipeline companies, at least companies wearing a pipeline hat, the lion's share of what's going to happen is going to be how economic is a project to build a pipeline and they will take some assumptions and some givens with respect to the commodity price. Wearing your oil company hat and whether you do or don't want to sell gas isn't going to necessarily be the hat you're wearing when you're putting in your application for the pipeline part. 12:18:53 PM MR. MINTZ moved on to explain how the bill proposes to change the current law. He said section 15 of SB 2001 would repeal and reenact AS 43.55.011(e). Since progressivity is proposed to be handled on an annual basis, all the department needs is one single percentage rate that applies to the production tax value of oil and gas, so section 15 actually makes it quite a bit simpler. It says you start with the tax value under AS 43.55.160 (under current law) and multiply that by a tax rate that is determined under AS 43.55.011(g). Subsection (g) says the tax rate is 25 percent plus the progressivity tax rate, which is determined under AS 43.55.011(h). The progressivity tax rate is similar [in SB 2001], but slightly different numerically from the current formula and starts with a trigger of when the net value exceeds $30/barrel instead of the current $40/barrel, but it goes up at a slower rate - 1/5 of a percentage point rather than ¼ percentage point for each dollar - over the trigger value. And this is calculated on an annual rather than a monthly basis. CHAIR HUGGINS asked why they should like this. MR. MINTZ replied everything else being equal, it is simpler; but what should drive the legislature's decision is the policy behind it. CHAIR HUGGINS asked if the difference in calculating the two has nothing to do with the fact that one is so complex they may not understand it. It's just that one calculation is a bit simpler. MR. MINTZ replied: "Let's put it this way. It's happenstance that the policy call that the administration is proposing in this case also has the benefit of being a little bit simpler in terms of drafting and applying and understanding it." 12:21:30 PM He said as with current law, there are two big exceptions to the general tax mechanism of a percentage of value. One is the North Slope tax floor. Bill section 16 replaces the current tax floor with a different one that applies to legacy fields. These are units for, just to cover all bases, in the case of a non- unitized reservoir that meets two criteria: total production to date of at least 1 billion barrels and recent daily production of at least 100,000 barrels/day. For these units, the minimum tax is 10 percent of the gross value at the point of production. The other big exception is the Cook Inlet tax ceilings, which are dealt with in Sections 19 and 20. CHAIR HUGGINS asked him to give them an example. MR. MINTZ imagined legacy field A, which meets the criteria for the 10 percent floor. In any given year, he supposed that the progressivity was not triggered that year; so the tax rate is 25 percent of net value. CHAIR HUGGINS interrupted to ask what circumstance would cause progressivity to not be triggered. MR. MINTZ replied if the net value of the oil and gas produced from this legacy field didn't exceed $30 per barrel. CHAIR HUGGINS said that is important for the public to understand. MR. MINTZ went back to his example and supposed that this legacy field generated a total production tax value of over $2 billion in that calendar year. A 25 percent tax rate times $2 billion is $500 million. That would be the tax that would be paid using the percentage of value. If you compare that to 10 percent of gross value and the point of production - hypothetically suppose you do that calculation - and get $400 million, in this case the tax paid under the percentage of value formula ($500 million) is greater than the tax floor so the company would pay $500 million. Now one of the rules to implement the tax floor which comes later in the bill is that if you're producing from a legacy field, you cannot apply tax credits to reduce your actual tax paid below the floor. So in this case, the tax levied is $500 million. If the producer had $200 million of tax credits available, he could only apply $100 million that year to bring the actual tax paid down to $400 million. He took another example that supposed either prices were lower or that costs were higher and the total net value of oil and gas produced during the calendar year from legacy field A was only $1.2 billion. With the 25 percent tax rate, the tax is $300 million. If that is compared to the $400 million which is 10 percent of the gross value, they have fallen below the floor, so they have to pay what the floor says - $400 million. 12:25:58 PM MR. MINTZ went on to the second major exception to the general tax mechanism - the Cook Inlet tax ceilings, which have not been changed; there are just conforming amendments. Section 21 has technical language that is probably almost inexplicable by itself, he said. It is essentially a conforming amendment to a later provision of the bill which has to do with the rules on deducting lease expenditures. He explained that the existing law has an "anti-double dipping" provision for use of tax credits in Cook Inlet. It is intended to prevent, in some cases, exporting tax credits that a company would otherwise use, but not because of the tax floor. It prevents exporting those credits elsewhere in the state, because that would be getting a double benefit from the tax floor or double-dipping. Later on in the bill, section 55 has rules how lease expenditures are deducted, which also implements an anti-double dipping concept. This technical language in section 21 of the bill basically is meant to make sure that the anti-double dipping under section 55 isn't applied twice against a producer. He clarified: In other words, if you've used up your excess lease expenditures on your section 55, then you don't have to do it again under section 21. It's kind of an anti- double dipping from the state standpoint and qualification to the anti-double dipping from the producers' standpoint. It's just basically a fairness - a little twist to insure that it works fairly and doesn't overly penalize producers. And we can go into more detail if you want later when we get to section 55, but I should mention this basically is already in the current implementing regulations. But because there are a lot of unanswered questions in the existing law about how all these different provisions fit together, we thought it best to make it explicit in the statute. 12:28:25 PM MS. DAVIS said because it was very complicated she wanted to test this with the Cook Inlet piece and she explained: What essentially happens at Cook Inlet is if you calculate their tax under PPT, you would apply lease hold expenditure deductions of your Capex and your Opex and draw down your number; and then you would apply capital credits and then be able to draw down the number yet again. But we have this other rule on the side that says 'Oh, by the way, you never ever - you pay the ELF ceiling.' I mean essentially that will be the lowest you can drag your tax. So the assumption is to the extent that you had your PPT up here and it drew down with expenses and it drew down with capital credits and somewhere you crossed the line and said 'Whoop, there's my ELF ceiling. I can stop now.' What it's saying is that you as a producer can't say 'Well, this was my tax I paid; so now I'm going to go back and grab these capital costs and these expenditures and they technically didn't get used because I paid this rate and now I'm going to take them and throw 'em up to North Slope or throw them somewhere else.' And they're saying no; those are considered used even though you may have ended up paying this rate. So, that's the theory. But if you had capital credits that didn't get used to get you down to there, you still had some more left, then you can still use those and go throw them up to the North Slope if that makes sense. 12:30:07 PM MR. MINTZ moved on to AS 43.55.160 (bill sections 52 - 55) which tells how to calculate actual taxable value that one applies the percentage tax rate to. He said the basic principal remains the same n the bill and explained: You start with the gross value at the point of production and subtract your lease expenditures. And there have been some changes in the wording. First of all we can throw out half of it because we no longer need to calculate monthly values because progressivity is now an annual concept. And second, the bill expresses a number of rules about when and how lease expenditures can or must be deducted. These are rules which are implicit in the current law, but they're not spelled out. And I think the reason for that is you go back to the history of the current law. The initial proposal that the previous administration submitted to the legislature was very uniform in how it treated oil and gas statewide to the extent that if you're a producer in Alaska, in order to calculate your tax, you could add up the gross value of all your oil and gas produced anywhere in the state, get a single number, add up your lease expenditures incurred anywhere in the state, get a single number, and subtract one from the other. That's your production tax value - you multiply it by a percentage and that's your tax. Over time, various exceptions and different treatments were introduced - specifically the Cook Inlet tax ceilings, the North Slope tax floor and a special credit for production taxes outside of either the Cook Inlet or the North Slope. And that required some degree of what we call ring-fencing - that is separately calculating the taxable value in these different areas. And to reconcile those ring-fencing concepts with the general concept that you want to basically deduct all your available expenditures in that year rather than carrying them forward is a little bit complicated and the rules had to be worked out and they've been worked out in regulation. But since we have an opportunity to revisit the statute, we feel it's much more desirable to state these basic rules in the bill. And in addition, now that we realize more what the challenges are of reconciling these two principles, I think the language has been made clearer and simpler and that's the other reason for the change in the language in section 160. 12:33:34 PM SENATOR ELLIS joined the committee. 12:34:39 PM MR. MINTZ said as an example of why these rules are needed going back to the case of the legacy field, you calculate the taxable value and multiply that by the tax rate and compare the result to the floor. If you're down to the floor, then you're not getting any benefit from deducting further lease expenditures. So if you had your druthers, you would export those lease expenditures and deduct them somewhere else; that would undercut the whole point of the floor. So basically you can't export lease expenditures from a legacy field to somewhere else. He said another example of one of these rules based on what Ms. Davis just explained is if you have lease expenditures in Cook Inlet that you don't need (because you're already down to zero or perhaps you're still exploring and not producing yet), and you would rather export those somewhere else and reduce your taxes, for instance, on the North Slope, but that would basically constitute double dipping if you're not required first to deduct them in Cook Inlet. 12:35:12 PM SENATOR THERRIAULT joined the committee. CHAIR HUGGINS mentioned that there are some exceptions between Kuparuk and Prudhoe, for instance. MS. DAVIS replied that the different treatment for legacy fields, which are now by definition Prudhoe and Kuparuk (and are in AS 43.55.160(f), is they have the same PPT rate and the same productivity rate, but they have a floor. Before there was a 4 percent floor applying to everything and now that has been contracted to just those two fields and it's a higher floor at 10 percent. The other piece that has changed is that the ring- fence runs around both Prudhoe and Kuparuk. So now capital credits can move across those two units. So, the prohibition on exporting is really a prohibition from exporting outside of either of those two units. CHAIR HUGGINS asked if that was the only difference. MS. DAVIS replied yes. CHAIR HUGGINS asked the rationale for that change and who developed it. MS. DAVIS replied the rationale of that change was when the bill was first drafted, they analyzed when a field would kick in for each unit as a standalone unit. So as they ran their modeling on what the margin tax rate is, and therefore, what the government take at each unit is, it was found to be too high for their comfort level. It was too aggressive in terms of applying a 10 percent floor to just Prudhoe or just Kuparuk and companies needed to be able to move the funds across the units to bring down the financial impact of having that floor. "That 10 percent floor wouldn't kick in unless on a blended basis the oil price on the west coast was $40 or less." CHAIR HUGGINS asked if industry was consulted on the effects of this provision. MS. DAVIS replied that she had one conversation with ConocoPhillips letting them know that is how she saw it. Her sense was they were listening to what she was saying and doing their analysis. She didn't ask them what they thought the cross- over was. They shared some information on heavy oil in Kuparuk. 12:38:29 PM MR. MINTZ clarified that the final bill still has ring fencing separately for legacy field deductions, but what was changed is that capital credits can be transferred from legacy field to another. That's in AS 43.55.023(a) and they would get to that in a minute. 12:38:58 PM He summarized they had just dealt with AS 43.55.160 that says that basically to get your taxable value, you subtract lease expenditures from gross value. AS 43.55.165 tells you what lease expenditures are and what qualifies and what doesn't. AS 43.55.165 (a) and (b) (bill sections 56 - 59) have been rewritten and reorganized for more clarity. An example is that the current law defines lease expenditures as being direct costs and it defines direct costs as including certain overhead. The problem with that is just terminologically everywhere else in accounting and taxing where overhead by definition is an indirect cost. So it is confusing. They just no longer call the overhead allowance a direct cost; it's just a separate item. Substantively there is no change. MR. MINTZ said the more substantive change is that current law allows, but does not require, that the concept of lease expenditure be implemented by regulation. It was the department's judgment that to insure basically greater control by the department and greater transparency and predictability that lease expenditures are expressly provided "that in order to be deductible lease expenditures, the department must affirmatively allow them by regulation." 12:40:53 PM MR. MINTZ said the other substantive change to AS 43.55.165 is the repeal of current subsections (c) and (d). These provisions basically provided kind of a second track for determining what allowable lease expenditures are. He said: The first track is the general concept as implemented by the department either by regulation or by case by case interpretation. But the second track was that - let's say you have a unit operating agreement under which an operator sends monthly bills to its partners for the costs of running the unit. And if the department under subsection (c) or (d) determined that the rules in that operating agreement were substantially consistent with the rules defining lease expenditures in general, then the department could allow or require the producers in that unit to basically substitute the billings or what is allowed to be billed under the operating agreement for the general concept of lease expenditures. There are some advantages and there's some disadvantages to doing that, but it was the department's judgment after reviewing this and also after grappling with the implementation problems in the course of trying to develop implementing regs that the disadvantages outweighed the advantages and it is better to have a single uniform definition - a specification of allowable lease expenditures in regulation. So this bill does propose to repeal subsections (c) and (d). CHAIR HUGGINS asked for an example of that provision. 12:42:41 PM MR. MINTZ said sure: Let's take - let's just call it unit A where you have several producers that have interest in a unit. Well, let's go back a step. A unit is basically a group of oil and gas leases or tracts that have different ownership. And when you have different ownership over an oil or gas reservoir, it can basically impede the efficient development of the reservoir. The easiest way to see this is to think about sometimes the most efficient way to produce oil from a reservoir is to inject water into some parts of it and drive the oil into other parts of it where it's produced. Well, if you own leases in the area where water is being injected, you're not getting any production, so that's not going to appeal to you. So in order to overcome that problem, you treat all of the leases as if they're a single lease and if you own a lease on the outside instead of getting the oil that's produced from your lease, you get a share of the oil that's produced from everywhere in the unit. So, basically, that's why we have units. Typically, the lessees, the producers, have one of their group actually operate the unit and that operator incurs the expenses and bills the other producers, its partners, for their share. And the thought was - and the operating agreement typically defines the costs that are allowed to be billed. The thought was that the partners are not interested in paying more than they need to any more than the state is interested in their deducting more than they want them to. And so if the department looked at this operating agreement - looked at the rules for what costs could be billed and determined that those rules pretty much conform to what would be allowed to be deducted, then the thought was instead of having kind of a two-step process, where the producers get billed and then they look - when it comes to determining what they can deduct for the taxes - they look somewhere else and see what the department allowed, that the department said you can deduct what can be billed under the operating agreement. So that's how it would work. I say there are implementation problems with that. In addition, even though once you get to that point of approving the agreement, you could say there's some administrative savings, the fact is that you have to have these two separate tracts in order to administer the two subsections along with the general definition. It didn't seem that it was going to be in the state's interest to implement these separate tracts. 12:45:45 PM CHAIR HUGGINS asked in his estimation as a professional, if what is being used as a concept of operation is functional and if he supported the repeal. MR. MINTZ replied that is a policy call that he doesn't make. "But in terms of implementation and what makes sense in tax administration, that there's no problem in repealing it. I mean, it's kind of a novel approach, but it's certainly worthy of consideration." MS. DAVIS said this is a slightly different view of this issue - from more of an administrative side - than this body discussed before. She said she approached the issue from a background of nine years of working in big oil and when she came to work for the state, she recognized how dysfunctional the audit proceedings can sometimes be on the owner's side. The time frame for resolving these issues can take from one to seven years and they can be on a item-specific basis. She said that often operating owners don't agree and their agreements change as they are resolved. It's such a dynamic process for the working interest owners that the amount of time it would take for the state's auditing staff to revisit challenged issues and rethink whether it is appropriate or not would be lot. So, she decided to put weight on the industry's resolution of what expenditures should be in or out of lease hold expenditures and backed it into a different provision, section 57, which mandates for the department to consider what the operating agreement provides is an appropriate expense. That can be used on a item by item basis. So, the department gets the benefit of the operating agreement, but isn't "tied whole hog to the whole process - either in or out." Where it seems fair, they can lock that in and move on. When new things come up the state can take its time, let the owners sort it out, and then look at it and see if it's sorted out and matches reasonable accounting practices - boom - that's locked in. "It recognizes frankly, the reality of how much time and how much dynamic changes there are in the way operating owners work out their costs with each other." 12:50:39 PM CHAIR HUGGINS remarked that this is a novel approach and there are two litmus tests that run through his mind. One is if it is operationally sound and if it is durable. MS. DAVIS replied that her approach is more operationally sound and it's more durable. MR. MINTZ went on to the list of fraud and wilful misconduct over gross negligence exclusions in current law and how this bill adds a couple of categories - costs arising from violations of law or from noncompliance with lease or permit obligations. MS. DAVIS noted that this change came from an interested citizen's note of concern and she hoped this encouraged people to send in their good comments. 12:53:14 PM MR. MINTZ continued to the second category of expanded exclusions in paragraph 15 and said at the end of a field life, there can be quite extensive costs involved in dismantlement, removal and restoration and these are typically called DR&R. The current law allows those costs to be deducted to the extent they are attributable to future production, but not past production. Upon revisiting this, the department decided it was not good policy for the state to, in effect, subsidize shutting down and what it is really talking about sharing in is the cost of exploring and producing. This provision would basically say any DR&R costs are not deductible. MS. DAVIS added that under the lease, the owners are obligated to do this from the very beginning. Generally, she said the state wants to incentivize that which someone isn't obligated to do. So, in this case the state's dollars are being used to support something they are already legally required to do. 12:54:16 PM MR. MINTZ said paragraph 19 deals with issues in SB 80 from last session. It has to do with whether or not the state should share in the cost (including in the case of capital costs) giving credits for repairing or replacing facilities or equipment such as pipelines that may not have been maintained the way the department hoped. It addresses that issue in a slightly different way. Rather than look at the conduct of the producer, it looks more objectively with the event that is associated with the need for the repair or replacement. If the repair or replacement was necessitated by some event which causes an unscheduled interruption of oil or gas production or if the repair or replacement causes a unscheduled drop in oil or gas production, then those repair or replacement costs would not be deductible. Similarly if the repair or replacement were necessitated by an oil spill or some other kind of release of a hazardous substance, then the state would not share in those costs either. 12:55:38 PM SENATOR WAGONER asked Ms. Davis if she knows yet how much Opex BP billed against the state's credits for its work on the pipeline. MS. DAVIS replied no. She didn't know yet. SENATOR WAGONER remarked that BP had sent a letter saying it would deduct those expenses. SENATOR WIELECHOWSKI said the difference between this and SB 80 is that a company could have been negligent for decades on the North Slope and this kind of gives them a pass if they schedule to fix their negligence. MS. DAVIS responded: Unless that negligence rise to the level of gross negligence whereby it would be excluded under one of the other provisions. If someone were not grossly negligent, but simply negligent, then what we're doing is we're saying - we will not participate in the repair costs and the replacement costs where that negligence has caused unscheduled production impacts or releases - contamination. So, to the extent that negligence is something that doesn't impact production or doesn't impact the contamination, then we're still allowing the credits and the deductions to occur. SENATOR WIELECHOWSKI asked if she has other examples of how other regimes treat this issue - as far as placing a strict liability based on scheduled or unscheduled drops in production. MS. DAVIS relied that she hadn't asked because it's only relevant in regimes that have tax and royalty credits. She said: Production sharing countries generally sort of lock down all of their provisions in contract, and we can look at that, but it's not as informative as if we'd looked at statute in tax and royalty countries. In thinking off the top of my head, it's really going to be relevant only in those tax and royalty regimes that have credits.... She said she would ask her experts about that. 12:58:44 PM SENATOR WAGONER asked when the department would know how much expense BP is writing off. MS. DAVIS replied that the state has a couple of initiatives going on different tracks - one is a legal enquiry in the AG's office, which allows the discovery process which would provide the opportunity to develop that number. BP's 2007 filing is due with the state on October 15; October 31 is when their federal returns are due. This allows the state to begin an audit process. Her goal would be to do one of these pretty quickly - within a year after that. She said the legal efforts might produce an answer sooner than that. 1:01:10 PM MR. MINTZ said the final addition to the list of exclusions is paragraph 20 that relates to the cost of acquiring, constructing or operating a crude oil topping plant or refinery. He explained: This has to do with the fact that sometimes right in the field producers want to producer their own diesel - it would be the best example - for use as fuel or otherwise and sometimes they choose to obtain that by building their own little topping plant rather than just buying the fuel. And it's the department's judgment as expressed in paragraph 20 that that is really not is meant by direct costs. That's getting pretty indirect when you make your own plant to produce a product that you then use in operations. Paragraph 20 would exclude deductions for constructing or operating the plant, itself. However it does allow for essentially deducting the value of the product whether or not you build the plant or buy it - because that does look like a direct cost of producing oil and gas. Now there's a little twist on here which I just wanted to explain for the record. What's allowed to be deducted is the difference between the market value of the product and the value of the oil that's going into it. The reason is because the oil is being produced from that field and its tax exempt. So, if you allow the deduction of that value, the tax then - you'd be double dipping - double counting. So, it's the value added between the value of the oil that goes into the plant and the product that comes out of the plant that you can deduct. If you think about, if you were buying the fuel on the market then the oil that you'd otherwise use to refine into it, you'd be selling and getting the value of that. So, that's why just that detail is - you deduct the value-added rather than the gross value of the product. 1:03:06 PM SENATOR STEVENS asked what the value added is. MS. DAVIS explained that this complicated language allows an operator: to deduct the value of the diesel that they use - either because the bought it and shipped it up - or if they go ahead and say even though we don't have a credit, we're still going to be making our diesel on the Slope with out crude oil topping plant. When they reach in and grab the barrel of the oil out of the ground and throw it into the plant, they're allowed to take that barrel out and not have to pay tax, because it's being used on the lease. So what we're doing is saying since you didn't have to pay tax on it, when you go to deduct it from your tax because of the fair market value of what a diesel thing is, we're going to make you take out the piece you didn't pay tax on. That's all. So, it's essentially not letting them get a free barrel and then deducting it from us. 1:04:38 PM CHAIR HUGGINS asked if you build a facility or truck it north. MS. DAVIS replied: It's whether you build the facility and incur the cost, build the facility and have the state incur - what is it - 25 and 20 - 42.5 percent of the cost or do you truck it - is the frame of reference. And what we're trying to do is make one of those options, which is build the facility and have the state pay 42.5 percent of the costs not one of the options. CHAIR HUGGINS said his concern from a practical standpoint is that causing more trucking activity might not be the right thing to do because it requires more road maintenance and carries more liabilities. MS. DAVIS agreed that they need to understand the economic trade off. She said that modifying the Kuparuk plant is estimated to cost $300 million - let alone what it would cost to build a new one. She is hearing that they have two plants up there neither of which conforms for sulphur. Both of those would potentially create a $300 million bill, plus potentially a third plant as they step out and do remote work. "These are not small ticket items." SENATOR WAGONER said he remembered that Tesoro's plant modification and expansion for its low sulphur unit was around $50 million and he thought it was producing enough low sulphur fuel for the state at this time. He didn't think the North Slope was taken into consideration and he also didn't understand why it would cost $300 million to modify the plant up there to give them the low sulphur diesel. MS. DAVIS responded that she didn't know, but she did know that the Slope has environmental challenges relative to air emissions and other standards. 1:08:53 PM MR. MINTZ recapped that they had gone through the calculation of the percentage of value, the question of credits and determining how much actually tax has to be paid. And so a number of provisions of SB 2001 amend the current tax credit provisions of the production tax law. He explained that AS 43.55.023 (a) is the existing provision that provides for a 20 percent tax credit for qualified capital expenditures. A few changes are proposed to it in the current bill. First, a limitation that no more than 50 percent of a credit may be taken the first year. CHAIR HUGGINS asked what the value of this provision is. MS. DAVIS replied it won't save the state total dollars, but it smoothes out the lumpiness of the swings from year to year from a budgeting standpoint. She explained that capital spend may have peaks every two or three years and under the current system those peaks can hit in a single year and so the state's budgeting has to absorb it. She said that Norway is considered to have a highly accelerated depreciation schedule at six years and the federal government is at eight years. Alaska is at one year; so she thought that spreading it out over two wouldn't make a huge difference in the state's competitive advantage. 1:11:33 PM CHAIR HUGGINS asked what "our business partners'" perspective on this is. MS. DAVIS replied that she hadn't heard any comments from them on that one. Probably the smaller companies, like Pioneer, would potentially care about having the full credit to be able to sell in one year versus selling half in one year and half the other. However, the total economic benefit is still substantial for them. CHAIR HUGGINS asked if she had looked at the implication to Pioneer of having a provision that accounted for the size of the organization. MS. DAVIS replied that a legislator raised that issue once the special session started and she would be open to that notion. CHAIR HUGGINS said he felt that Alaska's future would include "the Pioneers of the world" and if the state is looking at incentives, he wanted something that would encourage those companies. SENATOR WIELECHOWSKI said the Gaffney Cline testimony from yesterday was very compelling especially regarding the discount rate and how industry has 10 percent and the state has 5 percent. It seemed to him that this is one of those knobs that could be turned to help maximize investment and the internal rates of return. He thought upfront credit to the industry is good because it increases investment pretty significantly. He asked how much the spikes are. Is it hundreds of millions? MS. DAVIS replied they would have to look at the spikes on a taxpayer basis, but she would show him a one-year cycle to the extent she has the Capex for those years. She said her concerns went into the future with aging fields and infrastructure where there may be wholesale replacement of systems every three or four years which could create bigger spikes than the state has ever seen. She agreed with Senator Wielechowski that getting capital returned early makes a huge difference when a company assesses is deciding whether it wants to invest or not. 1:15:32 PM CHAIR HUGGINS wanted to know if their quest for information from the companies included predicting those spikes. MS. DAVIS replied to some extent it's the unknowable because unexpected things sometimes create the spikes. If any of the heavy oil pilot projects take off, they would require construction of large power plants and some unique systems to handle sand, for instance. Those will trigger big spikes. The state will try to anticipate these projects as much as it can, but the challenge is knowing the timeframe and knowing what they are. MR. MINTZ turned to the second change in the capital credit provision, AS 43.55.023. He said as Kevin Banks explained last night, there had been a number of changes to AS 43.55.025, the exploration incentive credits section - one group of which has to do with additional or clarification of expanded information submission requirements. He said the current law under AS 43.55.023(a) also provides that if you want a capital credit rather than an exploration incentive credit under .025 for an exploration expenditure, you also have to agree to the same information submission requirements that you would have to comply with .025. Since those submission requirements under .025 have been changed, there is just a conforming change under .023(a) to make sure that you have to provide the same information to the state - whether you do it under .025 or .023(a). CHAIR HUGGINS asked him to walk through a scenario. MR. MINTZ responded that AS 43.55.025, the exploration incentive credit program, predates the PPT legislation. That was a separate targeted set of credits with its own sunset provision and was targeted towards certain types of exploration activities. And depending on the type of category, there could be either a 20 percent or a 40 percent credit. When the PPT legislation was enacted, one of the basic philosophies was not to try and change parts of the existing law that didn't need to be changed. So, the exploration incentive credit provisions in .025 were left alone with the exception of conforming changes. MR. MINTZ there is a new very broad credit provision under .023 which said: Any capital expenditure that also is a lease expenditure - in other words - if you own a current expenditure for, develop or produce oil or gas and if it's a capitalized type of expenditure, they can get a 20 percent credit for that. Well, there's a big overlap between that and the exploration expenditure. The exploration incentive expenditures under .025 are much narrower, but they're a subset of the broad category under .023. So, in a sense, if you qualify for a 20 percent credit under .025, the existing exploration incentive credit program, it's not that different whether you do it under that program or under the new program, .023(a). But what we want to make sure if an explorer does it under .023(a) it's not in order to escape the obligations to provide exploration data to DNR. So, when .023(a) was enacted it said basically if you're an explorer, you're doing exploration, you have to comply with the same information submission requirements that you would have to under the existing exploration incentive program. And since those have been changed in the bill, they are also changed under .023(a). 1:20:46 PM MR. MINTZ said the final change in .023 (a) is something which basically helps to implement the tax floor for legacy fields and it provides that if there's a capital expenditure incurred in the legacy field that the credit for that expenditure can only be applied against a tax on a legacy field. Other wise they could get around the floor by exporting the credit to another field. He continued: A second major credit provision of the PPT law, which is only slightly changed is the carry-forward annual loss credit. This means if you're a producer, maybe you're not producing yet, but you're still developing, so you're incurring a lot of costs or you're an explorer that incurs costs or you're a producer that's operating at a loss - there are costs which you would otherwise be able to deduct, but you can't get your taxable value below zero. So, if you can't deduct in that year, instead you can carry them forward. When you carry them forward instead of being a deduction, we turn them into a credit. It has the same economic effect. And again because of the floor on the legacy fields, in order to basically make that floor more effective, if you run a loss in a legacy field, you can't carry those forward - under this proposed bill. There actually is a kind of conforming change that I think I neglected to include in my presentation, but I should mention it because the tax rate under the bill is under 25 percent - that when you deduct a cost, in calculating your taxes, your after-tax cost is 75 percent. You get 25 percent deductible. So when you turn the cost into a credit for carrying forward, to get the same economic impact, the credit also is 25 percent of the cost. The current law has kind of an anomaly in that respect because if the tax rate is 22.5 percent it only provides for 20 percent loss carry forward. Our proposal is to conform the tax rate for the loss-carry forward to the tax rate that's imposed in calculating the tax. So that's changed from 20 percent to 25 percent in the bill. MS. DAVIS said that provision came from the smaller players. 1:24:43 PM MR. MINTZ said that AS 43.55.023(d) provides for transferable tax credit certificates. This is the mechanism by which an explorer producer that doesn't have tax liability to apply the credit against can turn it into value by getting a certificate and then selling it - or in the case of the new provision that proposes having the state purchase it. He said the only significant change here is to conform the certificates to the 50 percent rule that applies to the capital credits. There is a provision that says basically half of a credit can be used immediately and the other half cannot be used until the next year. MS. DAVIS added that Chair Huggins had requested her to look at a cap on the size of the credit for small producers and if they would allow that small a class to do all of theirs in one year, they would have to modify this slightly so their certificate doesn't get split in two. 1:25:57 PM SENATOR WAGONER said he concurred with that because it would be simpler and because otherwise the smaller operators would be penalized by the value of the money at issue over one year. He remarked, "I just can't see doing that. I really can't see doing that to a big operator either." MS. DAVIS said she has an evaluation of what the time value cost is to the state apart from any revenue planning aspects. 1:26:27 PM CHAIR HUGGINS asked what the value of this is. MS. DAVIS replied that it's relatively small in terms of the time value difference. 1:27:11 PM MR. MINTZ said the next change clarifies that if you're a tax exempt municipality, you may not obtain a transferable tax credit certificate and then get money back from the state. CHAIR HUGGINS asked if they had arm-wrestled over this provision before. MS. DAVIS replied no; it's just a clarification. 1:27:50 PM SENATOR STEVENS asked if this applies only to a municipality or to other tax entities. MS. DAVIS replied she checked with the DNR and this is the only one. "The reason is there's this constitutional issue about the state taxing municipalities which is what creates this anomaly. So that's what takes them outside the tax which then we are finishing by taking them outside the credits." SENATOR STEVENS asked, "So a Native corporation would not be tax exempt?" MS. DAVIS replied they would not be tax exempt under this language. 1:28:34 PM MR. MINTZ added that the final change to the AS 43.55.023 credits is very significant. It's short, but it repeals the transitional investment expenditure credits. It had a number of nicknames but it basically provided credits for certain capital types of expenditures that were made during the five years before the PPT started on April 1, 2006. CHAIR HUGGINS asked if this is the infamous claw back provision. SENATOR WAGONER quipped that he called it two for one, but he has since called it a kickback, but whatever it's called, he didn't support it. MS. DAVIS said that Dr. Pedro van Meurs didn't like this provision either. CHAIR HUGGINS said it is worth exploring its impact on smaller organizations. 1:30:49 PM SENATOR WAGONER remembered how some companies told him last year that they wouldn't have purchased the equipment at that time to do that job if they would have known this provision was going to be adopted; they would have waited five years. And he thought that was most disingenuous of them. MS. DAVIS said they won't know about small producers because they haven't incurred credits yet. 1:32:24 PM MR. MINTZ said the next slides deal with bill sections 36-44, which are changes to the exploration incentive credit program in AS 43.55.025. He noted that almost all of these changes that are described on the slides were described by Kevin Banks last night and so he would skip to the ones Kevin didn't mentioned. MR. MINTZ said the exploration incentive program in .025 has a relatively limited universe of costs that are deductible. This bill proposes to add one more, which is costs that are incurred as a result of gross negligence or a violation of health/safety environmental laws or regulations. CHAIR HUGGINS asked what the impetus was for that change. MR. MINTZ replied that there is some recent experience with exploration activities that seem to be more expensive than they should have been - a potential loophole. CHAIR HUGGINS said he thought that "this business of health" has a tremendously broad connotation. MS. DAVIS agreed and explained that it's a little more constrained than the broad topic in the sense that it is confined to statutes or regulations that deal with health, safety or environment. CHAIR HUGGINS asked for an example. MS. DAVIS replied probably it will concern the DEC environmental statutes and regulations and OSHA laws that operators already know about and allegedly already comply with. The intent here is that if there is a cost or an expense that arises because an operator cut a corner violating a DEC or OSHA law and now is dealing with it, the state wants the legal authority to delete it. She said it is a mirror provision to what already exists in the capital expenditure section which disallows these types of violations. CHAIR HUGGINS said he didn't want to get into a "lawyerly playground here." MR. MINTZ went to section 39 that makes the 50 percent rule to certificates under the exploration incentive program consistent with how it's being treated elsewhere. He said this is just the third place where it comes up. 1:36:47 PM MR. MINTZ said he was leaving the credit provisions and turning to the question of how to monetize credits if you can't apply them against your taxes if you are an explorer or new producer. He explained that current law has a provision in AS 43.55.023(f) that establishes some criteria for getting cash refunds for the state and provides for no more than $25 million in cash refunds for a particular applicant for a particular year. He said that limitation is not in the new proposal. The new proposal repeals that section and replaces it with a new system, an oil and gas credit tax fund, in AS 43.55.028. It provides for funding that tax fund with a percentage of production tax revenues - either 10 percent or 15 percent depending on the DOR price forecast. Other than the $25 million limitation, the existing criteria for whether you qualify to get what's now called a purchase rather than a refund remain in effect. For example, you can't produce more than 50,000 barrels a day in order to qualify. You can't be delinquent on any of your tax obligation and also you have to have used up credits against your tax liability before you can get a refund. There are a variety of administrative reasons why this new approach is believed to be preferable and more effective at accomplishing the goal of basically giving 100 percent value for the credits that a producer or explorer earns that the state is going to bear 100 percent of anyway. 1:39:26 PM CHAIR HUGGINS asked how big this fund would be. MS. DAVIS replied that they have looked at the state's track record so far on the tax credits and they are higher than predicted. In terms of identifying how much money would need to be available to have enough funds on hand to fully refund the credits the department is expecting, said that Cherie Nienhuis did the analysis and forecast. She saw consistently if the price of oil is $60 or higher, 10 percent covers it; if it's less than $60, 15 percent covers it. The administration is comfortable with that range. It was also comfortable enough to eliminate the $25 million per taxpayer in part because they are not having the large companies come in and have credits, because clearly they have tax liability that is sufficient to absorb whatever capital credits they have in the current year. They are seeing that it's the smaller producers who either do not yet have production and those were the companies that said the $25 million cap was too low for the majority of the types of expenses they were incurring. She said she could bring the committee a number for the size of the fund. CHAIR HUGGINS asked for her to bring the mechanism to deal with the annual cycle as well. 1:41:30 PM MR. MINTZ said the current system has monthly installment payments of estimated tax with a final payment on March 31. This is unchanged. But since the tax calculation is changed in the proposal, the rules for calculating it - the installment payment - needs to be changed. One set of changes is basically to conform to the changes in the tax. The other set of changes basically corrects what may have been an oversight in the original law - one of which was that Cook Inlet tax ceilings were not accounted for in the estimated payments - which means Cook Inlet producers will be required to overpay. This didn't make sense, so they fixed that by allowing Cook Inlet oil and gas to take account of those ceilings in calculating their estimated tax. Also if you're a legacy field subject to a floor, you take account of the floor in calculating your estimated taxes. The last point is that installment payments do not take account of the progressivity rate. He said, "There is a practical problem in requiring that which is simply that we would require predicting the movement of oil prices in the future, which I think we all know is not something which you can do with any confidence." 1:43:30 PM CHAIR HUGGINS asked him to explain the old mechanism on installment payments and progressivity rate. MR. MINTZ replied that the old mechanism did take account of progressivity because that was calculated on a monthly basis. In the new progressivity provision, you don't know even if progressivity is triggered or if it is how much it is until you know the price of oil over the course of the year. He explained: Here are the things that go into calculating your estimated installment payment: one is your monthly production. Well, you know that every month. The second is your gross value at the point of production. You pretty well know that every month because you know what the price of oil is for that month. And the third th is 1/12 of your annual costs. Now that's to some extent a forecast, but the producers typically have a pretty good handle on their costs, because they have to budget in advance. So that's not too much of a stretch. But those are the things that go into the installment payment. A producer, in fact, cannot know exactly what the right amount is until March 31, but he can get pretty close. The fourth element, as I say, involves predicting the future of oil prices and I think in the department's judgment that's too much to expect a producer to do and that's why the progressivity element is not included in the estimated taxes, but of course, on March 31 when taxes for the year are calculated, that's going to be part of the tax due. 1:45:14 PM CHAIR HUGGINS said, as an example, the producers wouldn't be held accountable if the progressivity rate caused them to be out of tolerance. MS. DAVIS replied yes. She said the policy call behind doing the progressivity on an annual basis is because of the volatility of oil price up and down, the administrative time and efficiency for everyone to try to track it month to month and follow the spikes and make sure it's all right and challenge if it's wrong is a lot of effort for not a lot of money. She wanted to simplify and focus efforts on things that mattered. CHAIR HUGGINS said that could possibly cause an automatic big underpayment. MS. DAVIS said their analysis doesn't show that could be a sizeable number. 1:47:10 PM SENATOR WIELECHOWSKI said Dr. van Meurs recommended a penalty for underpayments to encourage payment of correct taxes. He asked if she would consider that. MS. DAVIS replied that they want to have something that someone views uniformly as having sufficient teeth to encourage people to not use the state as an ATM. She would be open to what they thought were adequate penalties. 1:48:14 PM SENATOR WAGONER asked if they didn't come up with a certain percentage that was required for each payment with a true up once a year. CHAIR HUGGINS said that was true. MR. MINTZ responded that was in various versions of the bill, but it wasn't in the final PPT, which has no "safe harbor" clause. In fact, he said, interest is required on any underpayment or refunded on any overpayment - a slightly different approach. He didn't hear what Dr. van Meurs was referring to on the subject of penalties, but existing law in AS 43.05 which are the general administrative provisions for all the tax laws have penalty provisions that are modeled after the IRS penalty provisions where underpayments of tax are subject to civil penalties. There are at least two types: a 5 percent per month up to 25 percent, which applies unless the taxpayer can show reasonable cause and not willful neglect for the underpayment. The other is a 5 percent of the total deficiency penalty if any part of a deficiency is caused by intentional disregard of law or regulation. There are more substantial penalties in the case of intentional fraud. These potentially apply to any underpayments, whether it's annual or the monthly installment. You have to be more careful with the monthly installment payments, because everyone knows they're going to be off - because it involves estimates of what one will ultimately owe. You wouldn't expect the department to be particularly harsh in using the penalty authority for installment payments, but if it was clear that a producer was intentionally underpaying because the interest isn't that much, the department has the authority to impose substantial civil penalties. SENATOR WAGONER said honest mistakes are made accounting-wise and asked if companies are allowed a true up without penalty every month for the last month's underpayments. MR. MINTZ replied yes if it was not due to wilful neglect. You always pay interest because that is the time value of money. 1:51:16 PM SENATOR WIELECHOWSKI asked if the penalty for underpayment is around 3 or 4 percent. MR. MINTZ replied that the interest rate for underpayments or overpayments on the estimated monthly payment imports the IRS interest rate, which is intended to be a market rate. If there is an underpayment after the March 31 final date, that is subject to the regular state interest rate, which is usually substantially higher, 11 percent compounded. 1:51:50 PM MR. MINTZ said a number of provisions that deal with reporting are in the nature of clarifying the department's authority to avoid potential disputes. It has broad reporting authority, but there are specific types of reports that are very necessary for the administration of this law. And the department wants to be sure there is no possibility for producers to argue about them. Section 51 gives express authority to the DOR to require tax payments to be made electronically in a form that will be most helpful for tax administration. MS. DAVIS added that they get all types of payments, but electronically is much faster and easier. CHAIR HUGGINS asked why that hasn't been done by regulation. MR. MINTZ replied there is a regulation for modest amounts. There are two reasons for this proposal - to remove any doubt that the department has the authority and they want to make sure that the electronic payments are made in a specific form that will help the department administer the program more easily. At ease from 1:55:43 PM to 2:21:27 PM. MS. DAVIS deferred to Mr. Burnett to explain the mechanics of the funding. JERRY BURNETT, Director, Administrative Services, Department of Revenue(DOR) ,Juneau, Alaska , recapped the question, which was related to the tax credit fund and how much money would go in each year. He said he believes the FY08 fiscal note was $1.9 billion. With 10 percent net of expected credit payments, the money going into the fund in FY08 would be about $200 million. Whatever credits were paid from the fund in FY08, which are estimated to be between $125 and $150 million, would come out of the fund in FY08 and the rest of the money would roll forward. In FY09 ten percent of the production tax revenue would go into the fund and the credits for 09 would be paid out of the fund. In high revenue years it would build a sort of balance to carry forward for low revenue years. Since it's not a dedicated fund, the legislature could appropriate some of the money for some another purpose if the balance got too big, he said. MR. BURNETT continued: One thing it does that would be helpful, at this point, when you look at our fiscal note with revenue projections, it shows an amount going into the general fund that's actually lower than the amount that is expected to go into the general fund in that year because with refundable credits, we're required to make then a general fund appropriation under the current system to pay for the refundable credits. Revenue estimates are net of those credits so right now it looks like we're projecting less revenue than we're actually expecting to get. The general fund actually carries a larger balance than we estimate and then we take some out for an appropriation to pay credits. It creates a little confusion and at this point we have open-ended appropriations out of the general fund in 07. In 08 we had an appropriation, which is limited at $25 million, which will require a supplemental, which will be made before we know how many credits are required to be paid. So again, it will have to be an open-ended appropriation from the general fund in order to properly pay the credits. I don't know how much exactly that will be, what we're estimating, but I think it's between $125 million and $150 million total credits in 08. CHAIR HUGGINS asked if those are all interest-bearing accounts. MR. BURNETT said yes, and if it's not specified in the statute the interest would go to the general fund. 2:25:31 PM SENATOR WIELECHOWSKI asked how much the state earns on the CBR (Constitutional Budget Reserve). MR. BURNETT said he believes that the annual return is in the 4 percent range. General fund and CBR funds earn short-term market rates for secure investments. The original $400 million CBR funds are an exception. Those were invested long and last year probably earned in the 15 percent range. CHAIR HUGGINS recognized that Senator Hoffman was present. MR. MINTZ informed the committee that he would discuss the key tools for administrating the tax. Bill section 46 deals with the annual return and clarifies that all oil and gas producers must fill a return annually regardless of whether any tax is due. He explained that the substantial tax credits that are available create a situation where in a particular year a particular producer may not have to pay tax. Nonetheless, it's important for DOR to receive the information for verification purposes and to track potential credits. Thus, actual production is the trigger. This section also expands the list of specific information that's required for the returns. He noted that DOR always retains the authority to require additional information. CHAIR HUGGINS questioned expanding the list when there's unilateral authority to require additional information. MR. MINTZ responded DOR decided that adding relevant things to the existing list makes sense and potentially avoids the possibility of a challenge. 2:29:41 PM MR. MINTZ explained that the bill proposes an additional penalty that relates solely to late filing whether there's an associated tax deficiency or not. It's calculated as a percentage of the tax deficiency. DOR would adopt by regulation standards for determining the size of the penalty, but it couldn't be more than $1,000 per day. MR. MINTZ said bill section 48 requires explorers or producers to file an annual statement of expenditures even if no oil or gas is produced during the year. DOR needs to track those expenditures because they could be deductible or potentially be turned into credits. SENATOR STEVENS asked if the form would be complicated and time consuming. MS. DAVIS replied the requirements are set out separately under the statute so the scope of information is narrower in the instance that no oil and gas has been produced. It's not onerous, she added. CHAIR HUGGINS asked if electronic filing is required. MS. DAVIS said yes, that's included in the bill. MR. MINTZ added that DOR has ongoing information needs that aren't adequately satisfied by annual returns and bill section 48 makes it clear that the department has the authority to require regular monthly reports with appropriate information. 2:33:15 PM MR. MINTZ explained that bill section 49 adds explicit new authority for DOR to require reporting of forward-looking information for revenue forecasting purposes. This is important because the current tax is dependent on upstream cost deductions, which is a category where very little information is available except for producers and operators. He added that now there's a provision giving express authority for the department to require electronic filing. There is some question whether the department could impose the requirement by regulation so this fills that gap. Also, this new authority allows the department to specify the format for the electronic report so the information is readily available. 2:35:42 PM MR. MINTZ said AS 38.05.035, bill section 2, gives DNR broad authority to share oil and gas lease information with DOR for purposes of administering the production tax and AS 38.05.230, bill section 13, provides DOR broad authority to share production tax information with DNR. SENATOR STEVENS referred to Commissioner Galvin's statement about confidential information that's transferred from DOR to DNR and asked how that works and who is involved. 2:36:53 PM MS. DAVIS explained that royalty and tax information is carefully protected. Specific auditors sign an agreement to review records and files while they're in the DOR office. "We rarely allow copying of any record to even leave the floor so it's very constrained, very limited. It's more of a check and verify," she said. SENATOR STEVENS asked if there are penalties for violating that confidentiality. MS. DAVIS replied there are very severe penalties including criminal sanctions and monetary fines. DOR and DNR employees take this very seriously, she said. She understands that the same constraints exist with regard to confidential information that DNR possesses. MR. MINTZ added that both agencies have a long history of having access to and maintaining highly sensitive information. He's sure both have exemplary records for protecting confidentiality. CHAIR HUGGINS questioned why royalties aren't under the purview of DOR since they are revenue. MS. DAVIS replied it's because royalties are a benefit that flows from a contract that is entered into and administered by DNR. CHAIR HUGGINS commented it still appears that it would be an objective for consolidating effort in managing resources. 2:40:16 PM MS. DAVIS said one thing we've learned is that different countries arrange things in different ways. Ideally we want to make efficient use of people and computer resources and improve the flow of information for the customers. As we move forward working with DNR, opportunities to create efficiencies will occur and this is a first step, she said. MR. MINTZ added that confidentiality is required under both aforementioned provisions. He then directed attention to bill section 61, which deals with public disclosure. He noted that there's existing authority for DOR to publish statistical information so long as it doesn't include the particulars of a taxpayer's business. This clarifies that if the information is aggregated among at least three producers or explorers then it's okay for the department to publish certain categories of production tax information. The idea is to increase public transparency and the confidence that tax laws are being effectively administered. 2:43:20 PM SENATOR STEVENS asked for the rationale for selecting three rather than two. MS. DAVIS explained that this bridge was crossed when the department looked at how to make the fisheries licensing tax information public. With help from DOL it was determined that an aggregation of three supplied sufficient anonymity. The driving goal is to maintain an adequate standard of protection for individuals and this seems to work, she said. MR. MINTZ relayed that AS 39.25.110, bill section 10 places oil and gas auditors in the exempt service. There's a transition provision in bill section 67 that provides current employees with the option to remain in classified service if they exercise the option within a specified period of time. AS 43.05.260 and AS 43.55.075, bill sections 14 and 50 extend the statute of limitations for production tax from three years to six years. DOR believes this is an important change to insure that it can do an adequate job of auditing and enforcing tax laws, he said. SENATOR WAGONER commented that seems to be a long time for a statute of limitations to run. MR. MINTZ replied it's not uncommon for a considerable amount of time to elapse when resolving tax matters. Even with a statute of limitations there are often extensions by agreement. Often it's in the interest of the taxpayer to do that rather than have the department issue a blue sky assessment. Also, one reason for statutes of limitation is the disappearance of memory and witnesses, but that really isn't much a factor with tax cases. Everything is documentary so the fairness issues aren't as acute in this area. 2:45:44 PM SENATOR WIELECHOWSKI advised that breach of contract is typically six years. MS. DAVIS said in Alaska it was amended to 3 years. MR. MINTZ recalled that if there is no specific statute of limitations provided, the default is six years. 2:48:10 PM CHAIR HUGGINS asked Mr. Bullock to give an overview of the effective dates and any other things that might be worthwhile. DONALD BULLOCK, Counsel, Legislative Legal and Research Services Division, Juneau, AK said he's listened to testimony from the administration and Mr. Mintz as he discussed what the administration plans to do in terms of policy calls. His opinion is that the bill as it's been presented would adequately carry out the proposed policies. MR. BULLOCK drew attention to the provisions at the end of the bill related to retroactivity and reported that U.S. Supreme Court cases have said that after a first return is filed, it's within the scope of due process to allow changes by the next legislature. Under that interpretation the first return was filed last April 1, so the next legislature could go up to this session. This is a special session so it's a gray area as to whether this session would count. He believes an argument could be made that it would not count because the legislature is limited by the call of the special session and by the time period. If faced with that kind of challenge he would say it's unreasonable to have expected the legislature to have considered the issue during this special session or in the one day session in June. Under that interpretation, there would not be a problem applying the retroactive provisions in the bill back to April 1, 2006, he stated. MR. BULLOCK addressed the question about putting things in regulation as compared to statute and explained that regulations are tested for consistency with statutes. Also, there are many things the department could do by regulation, but if it's a gray area or involves information somebody doesn't want to part with, then it'll be litigated. As legislators you're in a position to identify the information that's critically important to the state, he said. Put that in statute so it's not necessary to go through litigation if the regulation is challenged. It's more efficient. That doesn't take away general challenges of information that may be subject to the privacy provision in the constitution, he added. 2:52:16 PM SENATOR WIELECHOWSKI said he didn't see a severance clause in the bill. MR. BULLOCK replied it's redundant; Title 1 has a provision that every bill impliedly has the severance clause. If a provision is found unconstitutional, it would fail and if the rest of the bill can be enforced without that provision, then it would continue. CHAIR HUGGINS asked him to describe the schools of thought on the bill. MR. BULLOCK opined that several things are going on and some deal directly with the tax under the PPT. For example there's the nominal tax rate increase from 22.5 percent to 25 percent and there's the progressivity. Also there are issues that have to do with expenditures. Part of the PPT is just like the old tax because you start with the gross value at the point of production and then the allowable lease expenditures are deducted to arrive at the tax value of the oil and gas. The credits follow a similar line. Once the gross tax is determined, you figure how much further the net revenue to the state would be reduced by the allowance of credits. Those are all tax things, he said. MR. BULLOCK explained that within the expenditures there are additional information requirements so this is an appropriate place for tax policy. If you give a credit for exploration, it's reasonable to set the condition of getting some of that information back. The tax rates, the expenditures, and the credits are all directly related, he said. MR. BULLOCK said that with regard to issues relating to the administration of the tax, the bill has several provisions to address how you know the information that's submitted is correct. One thing is that if the auditors are exempt, the increased pay will attract auditors that have the skills to look in the nooks and crannies to find out what the numbers ought to be. Also, the information sharing between DNR and DOR will create a better bank of information so that the auditors on the royalty side and the tax side can communicate and review their thinking. Another administrative part is the extension of the statute of limitations. He said he believes that there is a statute of limitations for claims by the state. AS 09.51.010 comes to mind, he said. There's already a six year statute of limitations in place for the state to bring actions, but not in tax. Over the course of six years things happen, he said. Things that affect the production may come up in other bodies. For example these taxpayers are subject to the IRS code and normally if the IRS makes a change that affects Alaska taxes they're required to file. This is emphasized for this bill, he said. As Mr. Mintz said, the state can get agreements to extend the statute of limitations and often it's in both the state's and taxpayer's best interest to do that. But by having the longer time, they won't have to take all those extra steps involving additional negotiations. This approach is more efficient, he said. MR. BULLOCK summarized that most of the issues in the bill including the tax rates, the conditions for credits, and allowable expenditures are all policy calls and the administration has characterized what the calls will be. 2:56:55 PM SENATOR McGUIRE clarified the statute of limitations statute is AS 09.10.110 [AS 09.10.120].-Actions in name of state, political subdivisions, or public corporations-and it is six years. MR. MINTZ thanked Mr. Bullock for providing many helpful editing suggestions based on the initial bill version. The administration tried to incorporate those in the final version. MR. MINTZ turned to bill section 1, dealing with transportation and explained that those costs are deductible in arriving at the gross value of oil and gas for tax purposes. Imagine that in 2000 a taxpayer reported and paid production taxes based on pipeline tariff, which is a transportation rate that was deductible. After three years the statute of limitations expires and in 2004 there's a rate case and the FERC or the RCA orders a refund of transportation charges from year 2000. That actually increases the taxable value of the oil that was transported in 2000 and it increases the amount of tax that should be paid. He asked if the department is precluded from getting that additional tax because more than three years has passed since the return was filed or does the statute of limitations begin to run again because it's a new event when the refunds are made. The department has had a longstanding interpretation expressed in regulation that the statute starts to run again. Logically, how the statute of limitations could have run on something like that hasn't occurred, he said. But the taxpayer could argue that if they owed taxes in 2000 and now it's four years later the statute has run and nothing can be done about that. There hasn't been a test of this for two reasons: first, most of the time these retroactive adjustments have been dealt with by agreement with the taxpayers. The other reason is that in the tax arena the issue is generally income tax and when there's an adjustment like that for income tax it's simply treated as income tax in the year that it occurs so there's no question of going back in time. Things don't work that way in the production tax arena because it's not income that's taxed. The value of oil produced in a certain time period is what's taxed so it's really a retroactive change. Because this hasn't been settled and because there should be no room for argument or disagreement, this interpretation that's been in regulation is being placed in the statute. Because they believe it's a correct interpretation of existing law, they don't want it viewed as a change in the law. They're asking the legislature to recognize that the intention of enacting this is to confirm the existing interpretation. 3:02:02 PM MR. MINTZ directed attention to AS 43.55.110(g) bill section 51, which gives express authority to the DOR to issue advisory bulletins interpreting production tax statute and regulations for guidance to taxpayers and others. He noted that Chair Huggins questioned why this isn't already being done. The reason has to do with the very broad definition of the term "regulation" in the Administrative Procedure Act and the broad interpretation the courts have given that term. Basically, he said, whenever the department issues an interpretation of general applicability, the court says it sounds like a regulation, but unless it's adopted through the formal regulation process the court will say it's invalid. That's why the department is asking for the express statutory authority, he said. CHAIR HUGGINS described it as an inoculation. MR. MINTZ directed attention to the changes in the uncodified law dealing with the details of applicability, effective dates, and transition. He noted that most of the substantive changes that have been discussed, such as changes in tax rate and credits are prospective under the bill and would begin taking effect on January 1, 2008. That means they would apply to oil and gas that is produced and expenditures that are incurred after December 31, 2007. However, there are some categories of changes that the department views as mid-course corrections or changes that should have been made in April 1, 2006. Those include additions to the categories of exclusions from costs such as repair replacement to DR&R and costs relating to violation of law. The second category is repealing the sections relating to the use of unit operating agreements to define lease expenditures. Those are going back to April 1, 2006, he said. CHAIR HUGGINS commented that some people are questioning why this couldn't be done in the regular session with a retroactive effective date. A response isn't necessary, he said. 3:05:55 PM MR. MINTZ explained that another applicability provision is to apply the extension to any tax liability that's still open even if it came up in an earlier year. For example for a tax on oil and gas produced in 2005, the statute of limitations will be extended up to six years. But if the statute had already run-the three years had passed-that wouldn't be reopened. It's also limited back to April 1, 2006. It's viewed as a retroactive application so it's necessary to specify the retroactivity date, he said. MR. MINTZ reminded members that two provisions in the bill clarify that a tax exempt entity isn't allowed to get a transferable tax credit certificate. We view that as a clarification rather than a change, he said, so the applicability date is the date that each of the respective credit provisions began. In the case of the section 023 credits, the date was April 1, 2006. In the case of the section 025 exploration incentive credits, the date was July 1, 2003. Most of the other provisions take effect immediately. He noted that MR. MINTZ noted that earlier he referred to authority to make regulations retroactive to the same extent that they are implemented. That was provided for in the original PPT bill and it's provided for in this bill, he said. When the department implements by regulation the provisions that are retroactive to April 1, 2006 they likewise can be retroactive to April 1, 2006. Otherwise, there's authority to make regulations retroactive to January 1, 2008. That is in the future but by the time the regulations are adopted and the process is completed it'll be after that date. MR. MENTZ explained that a technicality is that although many of the provisions don't take effect until January 1, 2008,there is authority to immediately begin developing the regulations even though they wouldn't be adopted and effective until after January 1, 2008. 3:09:11 PM SENATOR WAGONER noted that he had asked about the corrosion issue and the billings and he would like Ms. Davis' thoughts on the increase in the capital and operation costs and how that would relate to the amount that BP initially said it would cost to replace that line. He recalled it was in the neighborhood of 300 some million dollars. MS. DAVIS said that's the kind of prospective information DOR would get under the bill, but it doesn't have access to that information as yet. She suggested the most immediate way to get that information would be to ask the parties that will be testifying. SENATOR WAGONER said he plans to ask that question. At ease from 3:12:26 PM to 3:23:42 PM. CHAIR HUGGINS reconvened the meeting. 3:24:26 PM DAN DICKINSON, LB&A Consultant, said he had a short presentation to provide context and a longer one that will go through the legislation looking at issues that need to be raised. He stated that he was formerly with the Alaska Department of Revenue and did considerable work on the PPT. STEVE PORTER, LB&A Consultant, relayed that he would make a short presentation on a higher level analysis of the bill and the associated issues. MR. DICKINSON delivered a PowerPoint presentation beginning with slide 4, which was a graph of Alaska's actual oil production from 1965 to the present and the projected production from the present to 2020. The largest area is Prudhoe Bay, which produced 1.6 million barrels/day at its peak and now produces around 400 million barrels/day. At the high point in 1988, the aggregated fields brought the total up to 2 million barrels/day. Production has been declining since that time and now it's around 700,000 barrels/day or 1/3 of what it was 15 years ago. The focus during this period was on reinvestment and the issue of decline, he said. When people talked about taxes, the economic limit factor (ELF) was discussed and the question was whether changing ELF would change the investment climate. The consensus was that it would. MR. DICKINSIN said that in 2003 some exploration incentives were brought in, but the decline dominated all thinking. In those days the production tax was the largest source of revenue for the state. It outpaced royalties but because of the economic limit factor, production taxes began a steady march down to the point that it would become an insignificant tax. SENATOR WIELECHOWSKI observed that since the taxes were so low you would have thought there would have been a tremendous rush of investment. He said he's never understood why that didn't happen. MR. DICKINSON replied there was investment. If you look at all the production except Prudhoe Bay you will see that production was increasing, he said. The point is, they weren't "elephants." 3:30:00 PM SENATOR WIELECHOWSKI commented that supports the argument. The investments were occurring in the areas that had higher taxes than the taxes on Prudhoe Bay and Kuparuk. MR. DICKINSON acknowledged that is partially true. The smallest fields had no tax, but places like Alpine and Northstar came on with rates that were as high as or higher than Prudhoe Bay. The atmosphere changed with the change in the price for oil. CHAIR HUGGINS remarked he's deducted that a challenge in getting new exploration is that there are no new elephants and the cost of a discovery for an "ant" is high risk. He asked if it's in the ballpark to say we're trying to balance that risk with finding the "ant" a small amount of oil. Steve PORTER agreed that he's on the right path. SENATOR WIELECHOWSKI brought up another concept that he's never fully understood, which is that decreasing taxability will result in more exploration than we had under ELF. MR. DICKINSON displayed the slide, ANS West Coast Price from July 77-Sept 07 that shows the absolute rise in the price of oil. If people invested expecting returns from selling their product in the $30 to $50 range there's a good deal on top of that that's being generated, he said. An observation he'd make is that the production tax is no longer talked about as a tax. We're now talking as though we're entering a bidding round and we're talking about leaving money on the table and promoting ourselves to partners and wanting to share. That may or may not be appropriate, but there's definitely a very different sense of what we're doing here than there was when we were focusing on the declining issues. SENATOR WIELECHOWSKI responded the legislature and the experts including Mr. Van Meurs, Mr. Johnston, Dr. Finizza, and Gaffney, Cline have all said we could have increased our taxes and we'd still have incurred investment. MR. DICKINSON replied he's not disagreeing; his point is that there's been a real shift in the last seven years. MR. DICKINSON summarized the next two slides and noted that in 1988 2 million barrels/day were produced at a market value of $15 for basically $30 million/day. Now production is just 700,000 barrels/day, but at $80 that's $56 million/day. The point that people designing a system need to consider is what 700,000 barrels/day at $15 would yield. He clarified that he's not making predictions about price dips, he's just saying that any system needs to be robust enough to deal with those variations. 3:36:39 PM MR. DICKINSON referenced Article 1, Section 1, of the Alaska Constitution, which is quoted frequently in tax circles and noted that Chief Justice Marshall articulated that "the power to tax is the power to destroy" and that "taxation is an absolute power and like sovereign power of every other description, is trusted to the discretion of those who use it." Tax is part of the economic compact made in a society, which is very different from entering into commercial ventures, he said. Although the balance can change, the notion is that those are different ways of thinking about it and as a society our thinking might be changing. MR. DICKINSON reviewed slides showing the increasing costs and the projected $2 billion cost assumptions in the original fiscal note and then the $4 billion spring 2007 forecast. Those numbers are relevant because if you'd asked four years ago what the State of Alaska's costs would be, probably very few people would have said they would double. This is all part of the perspective of why we're changing the way we're thinking about these things, he stated. 3:38:53 PM CHAIR HUGGINS recognized that Senator Dyson had joined the hearing. MR. DICKINSON explained that in 2007 the legislature passed a budget and the DOR said there would be revenues from oil and gas of $3 billion and there would be another $400 million of non oil and gas for a budget of $3.4 billion. General fund appropriations were $3.2 billion so the surplus was expected to be $200 million. That was based on the ELF-driven production tax. Two months later PPT had passed and the fiscal note said in FY07 there will be an additional $420 million, which will be the retroactive portion from 2006 that won't arrive until March of 2007 so it'll be counted as fiscal 2007 money. In FY07 the payments will be $923 million for a total increase of $1.3 billion. Take the original estimate and add $1.3 billion to arrive at $2.3 billion. Now you're looking at oil revenues at $4.3 billion and the same non oil revenue for a revenue total of $4.8 billion so the expected surplus was $1.3 billion. MR. DICKINSON continued to say that a year later you see, according to the un-finalized Spring Forecast, that the projected $2.3 billion actually came in at $2.1 billion. That's about $200 million off. As a percentage, that was one of the best projections DOR made, he said. Looking at the figures, he explained that the property tax projection was $36 million and after a hearing on the value of the Trans Alaska Pipeline, it was increased by 42 percent to $52 million. For the income tax, prices were higher than anticipated so they went up 18 percent. For the oil and gas production tax, the price forecast, volume forecast, and cost forecast were all off, but the net effect was very close to the projection. SENATOR WIELECHOWSKI questioned if it's projected to be $800 million off next year. MR. DICKINSON replied he's heard that figure, but he isn't sure where it's coming from. He offered the belief that the $800 million is the difference between what the governor's proposal is projected to bring in if that proposal had been applied retroactively to the first day of the fiscal year. It's fine if you want to define that as a shortfall, but that's different from what you've been told in a fiscal note is going to be available for the fiscal year. He said his point is that what happened with the PPT is essentially as accurate as other taxes that were forecast. 3:43:08 PM CHAIR HUGGINS asked him to do the analysis because Alaskans have a misconception of what the $800 million really means and how it was derived. MR. DICKINSON asked if he should compare what the fiscal note said for 2008 and what the projection is now. SENATOR WIELECHOWSKI suggested an apples-to-apples comparison. MR. DICKINSON responded that would require waiting until the end of 2008 and then looking back to see what came in. I'm doing that now, he said. SENATOR WIELECHOWSKI said DOR has forecast an $800 million deficit. MR. PORTER responded they can't figure out how to come up with those numbers. MR. DICKINSON added there's no deficit being forecast. SENATOR WIELECHOWSKI said he understands that; it's an $800 million shortfall from the projection under PPT. MR. DICKINSON asked, "In the fiscal note?" SENATOR WIELECHOWSKI replied, "In the fiscal note." MR. DICKINSON responded he believes he can show that isn't the case. MR. DICKINSON continued to say that royalties came in at about what was projected because the price forecast was low and the production forecast was high so one offset the other. He noted that it's interesting that the non oil and gas was more volatile. It was off by about 50 percent. Overall, the difference was about $200 million. CHAIR HUGGINS noted that he gave a number of non oil investment categories to the commissioner of revenue because it shows a lot of disparities between the projections and what actually happened. That gets to the accuracy piece of the projections, he said. MR. DICKINSON observed that since 1990 when the Constitutional Budget Reserve (CBR) fund was established, the issue has been how much will come out of the CBR. A budget would be passed, the revenue identified and the difference would be made up from the CBR. The notion of getting a forecast to be dead on went by the wayside because it didn't matter relative to how the budget was being passed, he stated. MR. DICKINSON questioned how a better forecast or closer monitoring would have made a difference. He acknowledged that a big mistake in the PPT legislation was not requiring this earlier information and he applauds the measures in the current bill. SENATOR WAGONER referenced a prior presentation that used $43.43/barrel oil. The status quo at that price would have brought in $.9 billion. After credits the tax was going to bring in $1.7 billion for a difference of $800 million. That's what we came up with, he said, but that was with oil at $67 plus/barrel. Where did we go wrong on projecting the credits that were to come in, he asked. MR. DICKINSON replied that the state had no experience in estimating operating costs; and he understands that for 2007 they were off by 70 percent to 100 percent and the capital investment nearly doubled. His point is that a lot of things were underestimated. The $800 million likely came from adjusting the "knowns" and isolating the affect on one thing. That tends to overwhelm the things you've been adjusted for, he said. SENATOR WAGONER said maybe we didn't ask the right people the right questions when making the projections for CAPEX and OPEX. That's an awfully large amount to be off when the legislature is relying on the projections to set tax policy, he stated. 3:49:52 PM MR. DICKINSON pointed out that the legislature did ask a number of people and Mr. Van Meurs has said that if he'd been asked directly he would have said they would be higher. A number of folks looked at the numbers and nobody said they were out of whack. Using the Matanuska Maid bankruptcy as an example he said the point is that those sorts of things happen. You can have some forewarning and sometimes you can get it right and sometimes you don't. In this case, the cost estimates were significantly low, as were the price estimates. MR. DICKINSON directed attention to a one-page model he developed of the main revenue issues of the PPT versus the governor's proposal. It gives a sense of the general orders of magnitude of some of the issues. All formulas are there and it's not too complicated, he said. You can walk through making assumptions about barrels and costs. CHAIR HUGGINS asked him to go through the chart methodically. MR. DICKINSON continued the explanation as follows: The first column simply runs things over a range of prices. Back in September when I first did this, $80 was considered the high end-and that's life in the food-chain, I guess. We used 2008 estimate of volumes. Now that was the earlier one. DOR is about to knock 40,000barrels/day off that estimate, but a flat 244 million taxable barrels/year. You multiply what you sell it for times the number of barrels and so you come up with a sort value in market. At $30/barrel that's $7 billion at $80/barrel that's $19 billion. You then subtract the downstream costs, which the department estimated at $7.22 and that's tankering and TAPS-the ones that have always been deductible even under the so-called gross tax that we used to have. You then subtract the upstream costs, which are about $4 billion and I think as Senator Wagoner indicated, in our initial estimates those were closer to $2 billion. If you look at the document that you're looking at there [that Senator Wagoner indicated earlier] it's $1.7 so more like 100 percent off. They're closer to the downstream costs. Once you subtract that, you get what's called the production tax value or the net value. So again, at $30/barrel you've got just over $1 billion. At $80/barrel you've got $13.7 billion. And that's going to be the same under the governor's proposal or under the existing law. The first change occurs when you then multiply that times the tax rate. Under the current law it's 22.5 [percent], the governor's proposed 25 [percent] and so in column H you get the difference and as you might expect it's bigger at higher prices. The next set of calculations between I and N is progressivity. Again it's not really that complicated. You simply take the production tax value, you divide through by the barrels and so you come up with a dollar per barrel value. … The starting point for progressivity under the current law is $40, the governor's proposed dropping that to $30. … Starting at $60 and subtracting costs, under the current law there's no progressivity. Under the governor's bill, at $60 and $36 net, you have $6 worth of progressivity. So you calculate the number of dollars that you have and that's what's called the price index. Under current law you multiply each dollar is a quarter of a percentage point. Under the governor's proposal, each dollar would be a fifth of a percentage point so it'd rise less sharply. Then you simply multiply that through so if you had $6.15 and 25 percentage for each dollar, that means that progressivity is 1.54 percent. You mechanically can add it to the base rate, in this case we're trying to keep them separated, to show the results of progressivity so you multiply that 1.54 percent times your production tax value. And you can see at $70/barrel, you generate $173 million in progressivity. There was earlier discussions today-folks were saying how much was the progressivity piece. So this gives you a sense. At $70…it goes up rapidly so at $80 its $.5 billion. The third piece down here simply subtracts the governor's proposal from current law so it shows you the change. And you can see that there is a couple hundred million dollars of change in the progressivity with increases in price levels. SENATOR WAGONER asked how to calculate the difference when the governor has progressivity on an annual basis and the original bill had a monthly calculation. MR. DICKINSON replied you don't calculate that in this simple model. That is in his later presentation though because there are going to be differences, he added. 3:56:54 PM SENATOR WAGONER commented there will be quite a bit of difference. MR. DICKINSON agreed; potentially the differences can be huge. He then referenced the slide showing ANS West Coast Price to further demonstrate the point. SENATOR STEDMAN asked if his model uses the Texas or West Coast price. MR. DICKINSON replied that would be ANS West Coast, which is typically within $1.60 of ANS. MR. DICKINSON continued to review the model. The next thing sums up progressivity and the base line to come up with the total tax before credits. Then you analyze the credits beginning with the TIE (Transitional Investment Expenditures). The assumption is that most of the producers paying the tax would have had sufficient investment to generate TIE credits. They can be matched 2 to 1 so he decided to make the TIE credit exactly one half of what the investment credit is under bill section 023(a). Under the status quo they would subtract $190 million and under the governor's proposal they wouldn't. He continued: Because this is looked at as a one year snapshot for the first year, this is the only year in which you'd see a substantial financial affect from the notion of cutting credits in half and requiring to be applied over two years. I guess in theory the very last year you'd have the affect as well, but basically this year you see it. The fact that it's being proposed to be introduced on a calendar year basis means the fiscal year affect will be fairly minimal. Again, this is assuming that that change was in for the entire fiscal year. Not just half of it. So I've taken the full investment credit that would be allowed for $1.9 billion, and that's $380 million, and cut that in half. … It then shows you there's your total cost. You then say, what is my tax net of those credits? At $30, I'm wiped out and of course under the governor's proposal you wouldn't be wiped out. There would be a floor there. But I was mainly focused on the ranges where we see things today and at $40/barrel we're at $316 million [tax net of credits] and at $80/barrel we're at $3 billion. Under the governor's proposal … it's an incremental $200 million as you go up each $10 of price. MR. DICKINSON said his intention is to show how easy it is to sit down with an Excel spreadsheet and play with the concepts to get some sense of what's happening. Responding to a question, he agreed to provide an electronic copy. 4:01:11 PM SENATOR WIELECHOWSKI questioned how $30 versus $40 and .20 versus .25 impacts investment decisions by oil companies. MR. DICKINSON recalled that Dr. Tony Finizza addressed that question. Generally there's a company-wide price that all projects are evaluated against and then there's a stress price to evaluate against. Each company guards those numbers, he said. CHAIR HUGGINS asked him to restate the information from the slide titled FY 2007 comparisons because this bill is based on projections. MR. DICKINSON relayed it's easy to be critical of the projections but it's difficult to come up with better methods. What we do is take a set of knowledge and plug in a bunch of assumptions that we don't have any particular insights into, he said. He stated that the notion behind a revenue system is that it needs to be robust and cover a wide range. Also, it made sense to have a regressive system when Alaska was a young state because money was needed every month to do things like maintain roads and pay teachers. If there was a boom in the market the state was content not to participate because with a regressive system it was getting a baseline amount of money. The state's more mature now and it has a savings account that has billions of dollars in the unrestricted portion that is available for appropriation. For lots of reasons the state can look at its fiscal system and opt for a progressive system so that when everyone is making a large profit the state gets more. But it also means that when profits are smaller, the state gets less. Under ELF the state got a larger piece when people were making less. He said he believes that a lot of hard work goes into the estimates, but they can't be guaranteed. They're simply the best numbers that are available at the time. 4:06:51 PM SENATOR STEDMAN asked how many barrels/day the model used. MR. DICKINSON said he believes it was 760 barrels/day. All the numbers came from the DOR Spring Forecast, he added. SENATOR STEDMAN said he believes the Spring Forecast shows 995 barrels and the model shows 1.4 billion net of credits. The general concept is to be conservative on forecasting revenue. MR. PORTER advised that the administration has agreed to go over the assumptions to explain how the results were achieved. The idea is to create a public model that's within a percentage. MR. DICKINSON clarified that the 2008 Spring Forecast price is $54.72 and he believes they're at 983 barrels. SENATOR STEDMAN questioned whether there's opportunity for a surplus at the end of the year. MR. DICKINSON directed attention to page 81 of the revenue forecast and calculated that 700,000 barrels/day at $70 and a general fund budget of $4.1 billion would bring a surplus of $300 million. That gives a sense of movement with price, he said. 4:11:35 PM MR. PORTER began his presentation and advised that he would touch on stability, Alaska's prospectivity, ACES incentives and a general summary. Beginning with the issue of stability, he noted that Pedro Van Meurs warned that you begin to look like an unstable regime if you change the tax for what is arguably the third time. Daniel Johnston has disagreed with that while industry has repeatedly said you're moving in that direction of instability. He said he tends to agree with Mr. Johnston in terms of impact because stability is related to what happened at each particular time. MR. PORTER relayed that the oil industry continues to argue that there was a tax change several years ago, prior to PPT. Pointing out that to change taxes it's necessary to change the law, he emphasized that there was not a change in either statute or regulation. Basically, industry changed the way it managed wells and oil on the North Slope and captured an additional benefit under ELF. That's all that occurred; we simply applied the tax. Oftentimes that's been interpreted as a change in tax and we've politely not challenged that interpretation. But everyone knows that wasn't an issue of stability, he said. It was an application of law that happens all the time. Over time the industry and the state have lots of issues over the application of the regulations and the statute and this is just one more. It was just a bit more public, he said. MR. PORTER said the PPT came next. The situation was that over time ELF didn't pick up enough tax, particularly in a high- priced environment. That didn't make sense and everyone realized that ELF was broken. The recognition that the tax would need to change merged with industries need for stability, a stranded gas contract, and a reasonable tax. They lost on all three counts, he said, and that wasn't expected. That is the first change, he said. 4:16:32 PM MR. PORTER described the current situation as the second point in time. According to the governor, a cloud on the decision- making occurred during the PPT change of tax and so it's necessary to go back and see if the right decision was made. There are a number of ways of looking at the tax and the $800 million, but ultimately it doesn't matter. We're here so let's figure out what to do from here. Figure out the right answer, get it done and move forward, he said. But if you do work through this process and make a change you will be moving into a more unstable world if you immediately make another change, he cautioned. MR. PORTER turned to Alaska's Prospectivity and said he'd walk through oil and then gas. From the Colville through the Canning, the state land with oil underneath is a mature region. Referencing page 5 of Mr. Dickinson's presentation, he said we've found the elephant and all that's left is puddles. Move out into NPRA where the wells cost considerably, more and you see a changing economics factor for drilling wells. From the standpoint of attracting people, he said we're not the most prospective state in the world. Nobody is going to drill, regardless of the incentives unless you're willing to pay over 100 percent and at this point the state isn't willing to do that. With regard to competition he said we have three sets. First there's the Coleville and Canning competition, which is a mature field that only has puddles in remote regions so the costs are high. A second competition region is NPRA. That's what he calls the Alpine type region. Those are pretty good size fields but the oil is expensive. A rough estimate is between $30 million and $50 million, which is a lot of money if the hole is dry. He noted that when you shift from state lands you lose the royalty and that's not exactly prospective to the general fund budget. He elaborated that you get half the value that goes to the federal government, but it goes through a gauntlet to get anywhere. If anything is left after paying impact funds to the five communities in the North Slope Borough, then you go through a formula for funding PCE. Then you go through the next funding formula that pays for some type of credit fund for education. If anything is left, there's a possibility that some of the money will go to the general fund. He doesn't recall that ever happening. Most of it has stayed on the North Slope. You do get tax out there though so that is a benefit and that's why capital credits make sense there. Those puddles are much bigger than the ones between Colville and Canning, he said. MR. PORTER noted the difference between the industry models and state models. If you model a prospect from either standpoint there are lots of bells and whistles in terms of taxes, risk factors and other sensitivities, but take the reserves component alone and if you spread it to a bell curve, it really fattens up the economics. Geology is king, he said. If you have the geology, you will have the players because with big geology and big elephants, industry is willing to take big risks. MR. PORTER said the third region of competitiveness is the OCS. It truly does compete with elephants simply because there hasn't been enough drilling out there to know if there are still any elephants. Shell Oil is there and ready to spend billions on drilling in the OCS. The only problem is the state doesn't get any tax or royalty money from drilling on the OCS and that represents more than 50 percent of the potential oil and gas discoveries on the North Slope. That isn't the deal in the Gulf States. Those states have figured out that since they are carrying the risk, the federal government ought to pay a portion of the funds. He suggested that Governor Palin ought to be back in Congress working with the delegation to get a proportionate share off the OCS before Shell Oil drills the first well. 4:26:03 PM SENATOR WIELECHOWSKI asked if the state could capture some value by taxing the oil once it comes on shore. MR. DICKINSON recalled some cases and said he believes the main tax area will be the facilities that are on shore. It is something that needs to be negotiated with the federal government. The state can't assert a tax on something outside the realm and it can't assert a tax on the passage of offshore oil or gas through the realm. CHAIR HUGGINS commented everyone can't take a piece of the pie simply because it crosses the border. MR. PORTER said the next thing to look at is the huge resource of heavy and viscous oil. Because the oil industry will tap that resource, he cautioned members to ask if things in this bill will negatively impact that ability. He emphasized that the taxing structure should positively encourage the development of those resources because producing the reserves dwarfs everything else. Clearly it's more important than the tweaking we're doing here. Tweaking is within you purview but don't take some of these options off the table, he cautioned. He said later he would touch on how he thinks this may be impacted by the current proposed tax. SENATOR WAGONER questioned why it isn't possible to measure heavy oil that's going into the system to come up with a percentage and then a different tax system to encourage further development of heavy oil. He asked if that's unreasonable. 4:30:53 PM MR. PORTER suggested looking at the units Orion, West Sak, and Ugnu because you can almost identify the complexity and the cost of the well by what the unit is producing. He continued to say that the net basis and the 20 percent capital both work well if industry spends capital money on infrastructure and if they spend money on new development for places like West Sak to bring on additional reserves. Also you want industry to spend money on exploration. All three elements are important and right now the market is working and they're doing all three. It doesn't mean we've hit the sweet spot, but it's functioning. SENATOR WAGONER clarified that's at $80 or the higher rate of oil. 4:32:48 PM MR. PORTER responded that goes to his next statement, which is what happens when oil is at $40. He noted that Field A that was discussed yesterday had problems with the 10 percent gross tax and at $40/barrel oil it was right on the margins. He reminded members that when an oil company runs an economic analysis, each company uses a single price for consistency between divisions. Also they run economics on a stress price. Although it was said that the stress price is $40, he's more conservative because he's seen the world at lower levels. He emphasized that we don't know what the future holds, but we do know that you must cover the high, middle, and low to ensure that the state is positioned properly to encourage development at a particular time. Allow for uncertainty to occur and encourage development to occur over time, he said. MR. PORTER shifted to gas and said that in Alaska gas is not mature. The Foothills, NPRA, and OCS haven't been explored largely because you can't market the gas. Mr. Van Meurs said the gas pipeline is uneconomic, but he would describe it as indeterminate because of three elements that apply to a fourth. First, the cost of the pipeline is undetermined and that won't change much until you've spent closer to $1 billion and have certainty enough to know if you should go forward. Nobody will spend that amount by November, but they will have an estimate. Second, we don't know the future price of gas. We don't know how the gas play will come out in the future so that's risk. The third element is tax stability. Industry has always been afraid that the state will raise taxes and remove the profit after starting to build the pipe. All this rolls into an internal rate of return and basic project evaluation criteria to determine whether you think it'll be economic before building the pipe. You won't know if it is truly economic until well after the pipe is built. By 2030 you'll have a pretty good idea of whether or not you made a good decision, he said. 4:39:06 PM SENATOR WAGONER said he asked Chair Huggins to contact Mr. Van Meurs to define what he was talking about. In another presentation he said he was basing his statement on the line that was discussed in 2000 and 2001, which was the 52 inch producer-line using new steel and new technology and running to Chicago. We'll look at a lot of different scenarios before we reach that point, he said. MR. PORTER added that Mr. Van Meurs was also basing his statement on today's price with estimated increased costs, but that's based on assumptions that may or may not occur in the future. CHAIR HUGGINS recalled Mr. Van Meurs said liquids would work. The committee needs to hear from him to understand his rationale. We've also asked the administration to analyze his statement, he added. MR. PORTER said his second recommendation relates to what to do with a gas pipeline from here. He relayed that when he worked on the gas pipeline project, every day he asked himself how to best move the project forward. It wasn't how to move stranded gas forward or how to move the Canadian pipeline forward. To him, the project was monetizing the 36 tcf on the North Slope. With that in mind he suggested members ask if the activity today will enhance that potential. In his view it's the legislature's responsibility to review all the information and figure out the best path for moving forward. Don't lock down on a specific process; allow the facts to change your direction if it's appropriate. That's what you should do in November after the applications come in, he said. 4:43:43 PM MR. PORTER turned to the issue of timing the development and said the faster you can bring on development the better. It takes time to bring on oil after discovery. Six to eight years is probably a reasonable timeframe if you use the major facilities, but it there are environmental difficulties or local issues that timeframe gets extended. For this gasline it'll take ten years easily, he said. Any estimate that's less than that is probably skipping steps and creating additional risk. He clarified that's for the Canadian project. 4:45:42 PM MR. PORTER commented there's a lot of rhetoric about how ACES is an incentive to exploration and development and that it brings incentives because of capital investment. But, he said, ACES didn't create the capital investment, PPT did. If you look at the differences the only thing you can say is it hurts some parties less than others. When you take money out of someone's pocket, you make it less economic for them, but that doesn't mean that decision-making will necessarily change. He said he does know that the gross tax of 10 percent on the bottom, definitely is a big burden on West Sak and Orion and some heavy and viscous oils because their cost of doing business is in the $40s. Don't take money out of industry pocket in a low priced world, he cautioned. It won't encourage exploration and development in the future. MR. PORTER encouraged the committee to remove the minimum tax from the bill, but said the other elements of progressivity and changing the 22.5 percent to 25 percent are policy calls. 4:48:10 PM SENATOR WIELECHOWSKI referred to a presentation Mr. Van Meurs made, which was 25 percent with a gross at $50 and .25. He asked if that could be done without hurting investments. MR. PORTER said he hadn't modeled the impact of that because he hadn't seen that curve. You're trying to create a sharing curve and a lot of economists like a net sharing curve versus a gross sharing curve. Look at the curve and figure out how much more you want to pick up, he said. Only do it once though and then walk away for about 15 years. Take time, do it thoroughly, and make your decision. MR. DICKINSON noted that slide 8 illustrates that model. SENATOR WIELECHOWSKI asked if the state could increase the valuation of oil and not discourage investment. MR. PORTER said there is room. SENATOR WAGONER commented he didn't agree with the PPT but he voted for it because he wanted a bill. The problem here is there's a 2011 review date. He asked if having a clause like that in a tax bill isn't more dangerous than changing from one year to the next. 4:51:19 PM MR. PORTER opined that industry isn't worried so much about the tax review as the fiscal stability and long-term fiscal plan. If you want to make a stable environment, then figure out how to put a lot of the surplus money in the CBR and pay back the $5 billion you owe, he said. Then you'll begin to develop a fiscal plan that shows you're stable, conservative and responsible with the money you make in taxes. Do that and these companies will drop their risk factors, he said. That's what they're looking at. SENATOR WAGONER thanked him for the perspective. CHAIR HUGGINS thanked the participants, outlined the schedule for the following day, and adjourned the meeting at 4:53:04 PM.