Legislature(2007 - 2008)BUTROVICH 205
10/30/2007 09:00 AM JUDICIARY
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SB2001-OIL & GAS TAX AMENDMENTS 9:17:36 AM CHAIR FRENCH announced the consideration of SB 2001. Before the committee was CSSB 2001(RES), labeled 25-GS0014\M. He said a BP representative had testified yesterday that repealing AS 43.55.165 (c) and (d) would send a signal that the commissioner would no longer have the discretion to allow or require the use of billed or billable costs. He asked Mr. Bullock to discuss joint interest billings and the repealer of two subsections in AS 43.55.165. 9:18:33 AM DONALD BULLOCK, Counsel, Legislative Affairs Agency, said any time you repeal something it raises the question of what it means. In isolation, if you repeal it, then there would be the implication that you can't look at that any more. However, you can't look at the repealed subsections of AS 43.55.165 (c) and (d) in isolation; they're part of a larger bill. Included in this larger bill is the amendment to AS 43.55.165(a), which is in Section 19 of CSSB 2001(RES) and in Section 56 of the governors bill (SB 2001). MR. BULLOCK said his reading of AS 43.55.165(a) gives the department the discretion to determine whether costs are allowable under the standards that are presented there (page 16, line 2, of CSSB 2001(RES)). Costs must be incurred upstream of the point of production for oil and gas; the costs must be ordinary and necessary costs of exploring, developing, and producing; and the exploring costs must be direct costs. This language doesn't preclude the department from looking at those costs. Perhaps the repeal puts less emphasis on the use of those costs, "but the department's given the discretion in the amendment to .165(a) to put whatever is out there -- to see if the costs meet the criteria that are established in .165(a)." 9:20:23 AM CHAIR FRENCH said that the PPT was enacted just one year ago and in it the commissioner was granted authority to look at those costs in the two subsections that are now being repealed. It isn't as if the PPT has 20 years of fights in court about what costs are allowed and what aren't. So repealing it wouldn't be undoing a long standing practice. MR. BULLOCK agreed and said he didn't believe an audit of the returns that were filed on April 1 had been completed. Under current law, the department has three years to complete that audit. The legislature can put on the record the interpretation that the department can continue to consider these things in determining the ordinary and necessary costs. Alternatively, a clearer message in .165(a) could say that the information the department may look at may include the type of things that were in (c) and (d), but he didn't think that was necessary. 9:22:32 AM SENATOR THERRIAULT asked if putting something in statute would be harmful. MR. BULLOCK replied that putting it in statute would create a lot of appeals. If it says "may consider" the department would be challenged to say why it didn't consider it or give it more weight. To give the department the broadest discretion to use whatever information it feels is relevant to support its assessment, it is best to leave it as the legislative record. 9:23:56 AM JONATHAN IVERSEN, Director, Tax Division, Department of Revenue (DOR) agreed with Mr. Bullock. He said the department still has authority under its general powers to require any information it needs in order to reach a calculation of the tax. However, he pointed out that the reporting requirements in section 16(f)(5) of the CS expressly reference joint interest billings. So, the department can look at those. In regard to the repealer, AS 43.55.165(c) and (d), he pointed out that the department has several concerns. One is from Gary Rogers, supervisor, of the Oil and Gas Revenue Audit Section, on an administrative standpoint that starts with .165(c) posing the question of whether the taxpayer has substantial consistency between the joint interest billings and the standards that are set forth in the statute and the department's regulations. If the department makes a finding referring to costs that are billable as lease expenditures under the joint operating agreement, AS 43.55.165(d) takes that a step further by also posing the question to the department of whether there is substantial incentive and ability to effectively audit by the other working interest owners. This poses an administrative problem because the audit is looking in the past to determine whether there has been substantial consistency and the incentive and ability to audit to determine the future. Also, these agreements are moving targets. The accounting procedures in these joint interest agreements are not set in stone. The department would essentially be auditing the agreement and then auditing the joint interest audit. This creates a multi-track administrative problem. 9:28:19 AM SENATOR WIELECHOWSKI joined the hearing. 9:28:50 AM GARY A. ROGERS, CPA, Supervisor, Production Tax Audit Group, Department of Revenue, added that in writing regulations to implement 165(c) and (d), he is being asked to write regulations that make subjective judgments about whether or not Alaska has industry standards. He hired consultants who came up with a variety of agreements on what "substantially consistent" means, and he decided that rather than create administrative fights in the future, he wanted to publish the department's own standard of what lease expenditures are. He said that (d) also asks the auditors or the regulation drafters to make the subjective judgment of what is effective auditing if the joint interest parties are auditing each other. "How do we define effective? How do we know that what was effective in the past has continued in the future?" His division is put in the position of auditing their auditors rather than the tax returns. CHAIR FRENCH noted that Senators Stevens and Thomas had joined the meeting a while ago. SENATOR HUGGINS asked if current language allows, but doesn't require, the flexibility to look at the joint interest billings. MR. ROGERS replied that is correct. Any auditor, whether state, federal or independent, auditing oil and gas lease expenditures that are subject to unit operating agreements would look at the joint interest billings and unit agreements. MR. IVERSEN noted the policy concern of these provisions. His staff are put in a tenuous position because they haven't done any activity under this section. The concern is shifting the determination of what costs are allowable to the taxpayer. The department would be moving from its normal "trust-but-verify perspective" to a scenario of the taxpayers saying "trust us, but let us verify it ourselves," and particularly in .165(d). He said these sections also reference the final resolutions of these claims that are contested between the parties to the unit operating and joint interest agreements, and they won't necessarily be aligned with the state's interest. Another concern, he said, is a potential gap between statutory standards and whatever "substantial compliance" means. Because of this gap, there can be another gap as to how this provision is administered between taxpayers, because one can't be treated differently than another. 9:33:27 AM MR. IVERSEN said ultimately this concept sets another layer of ambiguity and shifts responsibility to where it shouldn't be. He stated that the responsibility should lie with the department and that the additional language should give him the affirmative responsibility to set forth in regulations what allowable costs are. CHAIR FRENCH said it occurs to him that since there is no body of law and precedent with respect to what his practices are going to be, that at this stage of the game, to repeal these two permissive practices doesn't take away his authority to use them if he decides to. But it doesn't bind him to use them either. SENATOR THERRIAULT asked if that is how the CS is written. MR. BULLOCK replied yes. 9:34:44 AM CHAIR FRENCH turned to the issue of corrosion starting at section 21, AS 43.55.165(e) on page 19. MR. IVERSEN said this provision intends to hit the same policy objectives expressed in SB 80 but with a different take. It has a different trigger point and takes the auditor away from making a determination of improper maintenance or negligence, which really isn't their purview. Those are legal or engineering issues. The provision refers to unscheduled interruptions or reductions in production or spills/releases of a hazardous substance. The costs incurred for repair or replacement or deferred maintenance of facilities, equipment, and structures (with a carve-out for wells) would be excluded from lease expenditures, which means they would be excluded from both the deductions credits. The reason for the well carve-out is because there is a greater degree of geologic uncertainty associated with wells. The end of the section inserts a quasi force majeure provision that is the same as language in CERCLA (Comprehensive Environmental Response, Compensation and Liability Act of 1980) - that basically excludes liability for the repair or replacement if it was necessary due to an act of war, an unanticipated grave natural disaster, or some other sort of inevitable phenomenon - as long as the effects of that could not have been reasonably prevented or was not from intentional or negligent acts of a third party - as long as the operator acted with due care. 9:38:45 AM MR. IVERSEN said that (a), (b) and (c) of this section delineate what costs include and the meaning of hazardous substance (oil is included). Replacement includes renovation and improvement. He said Pat Martindale from Martindale Consulting helped draft this provision. 9:40:43 AM CHAIR FRENCH asked him about the corrosion provision in SB 2001. PAT MARTINDALE, Martindale Consultants, Oklahoma City, OK, testifying via teleconference, gave his background in oil and gas auditing. CHAIR FRENCH asked if he has had experience working with these types of provisions that try to exclude the deduction of costs that are due to unscheduled interruptions or reductions in rates of production due to problems with improper maintenance. MR. MARTINDALE replied that his experience is working with industry in writing language to identify [indecipherable] … productions cost statutes in the mid 1990s. CHAIR FRENCH asked him to walk through a couple of scenarios this provision would apply to. 9:45:36 AM MR. MARTINDALE described a circumstance where an oil company had to repair or replace its infrastructure where preventative maintenance might have kept it from happening. 9:47:16 AM MR. IVERSEN clarified that Mr. Martindale was involved with this statute as an advisor; he didn't draft the provision itself. He asked Mr. Martindale, because he is a contract auditor, how this would be audited. MR. MARTINDALE explained that most companies would capture costs (repair and replacement) with work order project numbers. The current PPT audits would target each of the projects and determine whether costs apply appropriately for either operating or capital expenditures. The project would have to be described and reviewed with documentation. Having this provision might cause a taxpayer to be reluctant to describe a project, so some work would be required to look at the underlying vouchers and other documents to see if the project is legitimate. 9:51:41 AM CHAIR FRENCH thanked Mr. Martindale and went on to the issue of gas turbine maintenance. The turbines are frequently taken down for maintenance, and such a problem would be difficult to pick up on. He asked how narrow an application the language is for specific pieces of equipment, like the turbines. 9:52:56 AM MR. IVERSEN responded that part of this question goes to the underlying policy of scheduled proactive maintenance that is linked to a scheduled shutdown. If a turbine is replaced on a regularly scheduled basis, this provision wouldn't pick up on that - "it wouldn't even be on the radar screen." It would exclude the cost of repairing or replacing turbines from an unscheduled shutdown that is attributable to a turbine that just blows out. This is a brighter line and broader than in SB 80 in terms of the potential number of events, but it gets the state out of a deeper hole in the sense of actually making the determinations and the fights that are going to ensue regarding what is or isn't negligent. CHAIR FRENCH asked how the public would be able to tell if such costs have been deducted. MR. IVERSEN directed the committee to the monthly reporting requirements in Section 16 of the CS. Section (f)(3) requires reporting of any unscheduled interruption or reduction in the rate of oil or gas production. That would be the first tip off. A dip in production would also be apparent to him in looking at regular production reports. That would be questioned on an audit and depending on the response it might be looked into deeper. 9:55:49 AM MR. ROGERS concurred with Mr. Martindale who said that a company is normally going to establish some sort of cost center, project number, AFE, or work order number to track costs related to some sort of incident or unscheduled breakdown, and the auditors would look at the backup documents for those. CHAIR FRENCH pointed out that those work orders wouldn't come with flags on them. MR. ROGERS said experienced auditors know what to look for. 9:57:25 AM SENATOR WIELECHOWSKI said the thing that offends most Alaskans about the North Slope situation is that companies have acted negligently and are able to deduct those costs. This is very different than SB 80. MR. IVERSEN replied this is actually more of a strict liability type of statute and, in his mind, it is broader. SENATOR WIELECHOWSKI said the difference is if a company on the North Slope has been negligent for years and then schedules a shut down to fix that negligence, it can deduct those costs and essentially the people of Alaska end up paying for the repairs. MR. IVERSEN replied if it's part of their scheduled regime, then that is correct. Last year the incident was triggered by a leak and wasn't part of a scheduled maintenance program. At some point the state will have to draw the line as to what is not related to an incident. CHAIR FRENCH said he didn't know if a body of historical records existed that would allow the department to challenge whether a piece of maintenance has been scheduled or unscheduled. MR. IVERSEN answered that the trigger would be the shut down with a dip in the production report. 10:01:36 AM CHAIR FRENCH used the recent BP spill as an example and asked about spotting a leak and calling for a "scheduled" shut down. MR. IVERSEN replied that the department needs to keep the legislative intent in mind in writing the regulation for scheduled maintenance. The scheduling has to be reasonable. 10:03:14 AM SENATOR HUGGINS posed a scenario of installing a valve that fails the following day that causes an interruption and asked if that would qualify. MR. IVERSEN replied yes, but he said he was trying to reduce ambiguity and get out of those gray areas. CHAIR FRENCH wondered how removing "unscheduled" would put parameters on the meaning of what scheduled means. MR. IVERSEN replied that the issue with scheduling versus unscheduling goes to the underlying policy of setting some sort of standard for pro-active maintenance to keep production going. 10:06:13 AM SENATOR THERRIAULT said that taking a turbine down for scheduled maintenance would cause an interruption so he didn't think that word could be deleted. CHAIR FRENCH agreed. SENATOR THERRIAULT asked what "irresistible" is in the force majeure definition of exceptional, inevitable, and irresistible character. MR. IVERSEN replied that those terms are almost redundant and it means something that reasonably could not have been prevented - such as an earthquake. CHAIR FRENCH said he thought some eager lawyer had just started adding adjectives in there. On natural disasters, though, clearly a pipeline or a facility ought to be able to withstand a tremor, and he asked where one would draw the line between a tremor and an earthquake. MR. IVERSEN said that gets to the secondary area, which becomes an evidentiary matter. He didn't know enough about earthquakes to draw a line at the point where a tremor would inevitably rip apart any pipeline no matter how well constructed. This language triggers times when the event is unforeseen. 10:09:34 AM CHAIR FRENCH said it's his intention that the facilities should be built to withstand the terrible weather on the North Slope, like 70 mph winds and ice storms. MR. IVERSEN agreed. SENATOR THERRIAULT asked what "in privity of contract with" on lines 29-30 means. MR. IVERSEN said it means an oilfield contractor, for example. SENATOR THERRIAULT said last year in the Special Committee on Natural Gas that he offered Amendment 9 and part of the discussion on it was not only about the capital costs, but what happens to operating costs in a shut down. At the time it was estimated that 375,000 barrels/day of production would be lost. If there is a shutdown in Prudhoe Bay and half the production goes away, the fixed costs of $1 million/day don't go away. Part of it gets attached to every barrel that gets produced. Those may double on the remaining production. He asked if disallowing those costs was discussed. His amendment suggested that there should be a way of disallowing them - maybe through regulations. 10:13:19 AM MR. IVERSEN said the express topic of cost-per-barrel of capital expenses wasn't discussed. SENATOR THERRIAULT said they wouldn't be capital costs. MR. IVERSON said this provision would exclude both capital and operating expenses. So he thought perhaps additional language was needed. He said this language is fairly broad in that the costs are going to be those that are "in response to or otherwise associated with." SENATOR THERRIAULT said his interpretation is that this language does not address those fixed costs. MR. IVERSEN said the legislature might want to clarify that. 10:15:30 AM CHAIR FRENCH asked how this proposal treats well costs. MR. IVERSEN explained that the carve-out for a well is that it would be the costs incurred for repair, replacement or deferred maintenance of the facility or pipeline structure other than a well. It is still allowing the costs that would be associated with wells, recognizing the uncertainty in drilling. MR. ROGERS said he would echo that comment. Lots of things that can't be anticipated can go wrong "down-hole" in a well that you really can't control or observe as with above surface equipment. 10:16:56 AM CHAIR FRENCH noted that AS 43.55.165(e) has a general prohibition that lease expenditures do not include "costs arising from fraud, willful misconduct, gross negligence, violation of the law, failure to comply with an obligation or a lease permit or license." If drilling operations get too far outside the bounds of normal behavior, there is a cutoff point, but in general well-drilling costs can be deducted whether something goes wrong on the rig floor or down-hole that causes a problem in "the normal course of drilling operations." MR. IVERSEN responded that is correct to the extent other exclusion provisions would affect wells and the normal course of business stuff isn't going to be picked up here. 10:18:18 AM CHAIR FRENCH said that administration could offer a rebuttal. The committee took an at-ease from 10:18:35 AM to 10:39:14 AM. CHAIR FRENCH said the committee will hear from the industry. 10:39:37 AM MARILYN CROCKETT, Executive Director, Alaska Oil and Gas Association (AOGA) introduced Mr. Williams who would present AOGA's testimony. TOM WILLIAMS, Chair, AOGA Tax Committee, said the comments he made yesterday about the repeal of Section AS 43.55.165(c) and (d) were made for AOGA and not as a BP representative. 10:40:48 AM He read the following testimony pertaining to corrosion: The administration's proposed paragraph (19) to be added to AS 43.55.165(e) would, unless a situation is caused by a "super" force majeure, disallow any cost incurred for the repair, replacement or deferred maintenance undertaken in response to failure, problem or event the results in an unscheduled interruption of or reduction in the oil or gas production or is undertaken in response to or is otherwise associated with an unpermiteed release of hazardous substance of gas. Not only is the language of this proposed revision ambitious and likely to lead to additional audit exceptions and disputes, the entire provision is unnecessary. The proposed provision states that otherwise ordinary and necessary, and thus deductible, costs would be disallowed if the Department of Revenue determines such costs were in response to a 'failure, problem or event' that results in an unscheduled interruption or reduction in production. What constitutes a 'failure, problem or event' and under what standards would any of those be determined? Cost associated with any temporary, unforeseen shutdown or minor interruptions, regardless how minor, could now be disallowed by an auditor even when such an event arises despite otherwise prudent and necessary business operations. Yet the issue of determining what portion of any maintenance costs should be disallowed, if related to improper maintenance or production interruption, was thoroughly debated when the legislature was considering the PPT and again in recent legislative sessions. Each time amendments such as the one the administration is now advocating failed because the difficulties with such subjective standards were immediately apparent. The state turned to Dr. Pedro van Meurs, an international gas consultant retained by the state, who recommended a flat 30 cent/barrel exclusion from what would otherwise be a producer's capital portion of its lease expenditures. As Dr. van Muers explained: It should be noted that in most oil and gas fields, assets will have to be replaced after the technical life of such assets has expired. Therefore, such replacements are reasonable lease expenditures and required to protect the health and safety of the workers and to protect then environment. The US $0.30 per BTU equivalent barrel is based on reasonable capital maintenance costs of fields for which I have (confidential) information. Dr. van Meurs further testified that: Maintenance is a reasonable deduction for PPT; but it is sometimes hard to decide which expenditures fall into that classification. The simplest solution is to take some base expenditure that really will be replacement and over the next 20 - 30 disallow a modest floor of the capital expenditures. MR. WILLIAMS said if you assume that production is 250 million barrels/year, which is a little less than 700,000 barrels/day, the 30 cents exclusion comes to $75 million (capital expenditures that collectively the industry would incur on the Slope) that will be disallowed from either being deducted or giving rise to credits. He continued: At a 25 percent tax rate, that disallowance is $75 million and equates to $18.75 million. The 20 percent credit on that $75 million equates to another $15 million. That's over $33 million a year of tax reduction that occurs because of the 30 cents disallowance. Thirty cents doesn't sound like much, but $33 million a year is quite a lot. That's the point. We believe that over time that's, as Dr. van Meurs believed, that that's going to more than be adequate for the situations you will be concerned about. So, Dr. van Meurs' recommendation was adopted and became section 43.55.165(e)(18) of the PPT. The flat 30 cents per barrel exclusion sets a floor for maintenance costs and avoids the problems of case by case decisions as to whether maintenance (repair or replacement) is required because equipment or facilities have been improperly maintained or result in an unscheduled interruption. To adopt the administration's proposed amendment while leaving the flat 30 cents per barrel exclusion in the law would result in a double disallowance of the same costs. The flat 30 cents exclusion also avoids all questions and disputes about which categories of costs were incurred due to a triggering event and are nondeductible as a result - and also disputes about how much was incurred in each cost category. Finally the 30 cents per barrel exclusion applies every year, whether there is a triggering event or not. Over time the 30 cents figure may well prove to be a reasonably accurate approximation of the average amount of costs that would be disallowed by auditing and verifying exactly which cost categories are disallowed under the proposal and how much costs is in each such category. A flat rate disallowance greatly furthers the goals of clarity, certainty and efficiency in tax administration, enforcement and compliance. Paragraph (19) in contrast would undercut each one. 10:46:32 AM SENATOR WIELECHOWSKI asked what it cost BP to repair the corrosion on the North Slope. MS. CROCKETT cautioned the committee that Mr. Williams was here on AOGA's behalf, not on BP's. So, it's not appropriate for him to answer questions relating to his company's activities. SENATOR WIELECHOWSKI said they were trying to figure out if this is a reasonable amount. 10:47:37 AM MR. WILLIAMS responded that AOGA doesn't have information about what oil transit line costs are for Prudhoe Bay. He said the committee could get an estimate by remembering how many instances of the type they are concerned with and they already know that disallowed costs amounted to $33 million/year. He said AOGA doesn't have the information to answer the question. CHAIR FRENCH said they would not go forward without the answer to the question, because it is relevant to know if the 30 cents really captures extraordinary events that will take place with respect to production. Those are the things that subsection 19 is trying to address and he said, "Frankly the oil spill on the North Slope a year ago was one of them." 10:50:25 AM MR. WILLIAMS recalled that Mr. Suttle's letter mentioned that BP had a $13 million tax effect. Here they're looking at a 30 cent exclusion that totals a third of a billion over a 10-year period. He suggested that they get someone else to speak for BP. CHAIR FRENCH said it's important to take into account the unavoidable event that is driving this provision. 10:52:51 AM SENATOR THERRIAULT asked if Mr. Suttle's number was an estimate of the tax consequences at that time or the ultimate tax consequence. MR. WILLIAMS said that it talked about the effects during 2006. CHAIR FRENCH asked if he had to choose between the language in SB 80 and in SB 2001, which he would choose. 10:54:08 AM MS. CROCKETT replied that AOGA's belief is the 30 cents per barrel provides the protection they are looking for and the language in both bills is not necessary. MR. WILLIAMS said he would have to ask the tax committee what its preference was. SENATOR THERRIAULT remarked that all members would have to agree because AOGA is a consensus organization. 10:55:26 AM MR. IVERSEN agreed that this adds another item to their audit and that acts of negligence are included in this sort of strict liability provision. He pointed out that there is some dispute regarding what this 30 cent provision covers. Senator Wagoner said it was originally intended to bring the tax closer to a gross system and statements have been made that it's supposed to cover regular maintenance. CHAIR FRENCH asked his view of the 30 cents. MR. IVERSEN replied that it seems the discussions originally began with Senator Wagoner asking Dr. van Meurs about bringing the system closer to a gross and hitting costs that would be regular maintenance. This would be picking up a different sort of item than what either SB 80 or HB 2001 is addressing. He discussed the 30-cent per barrel exclusion. It is a per barrel amount; it isn't an exclusion that's going towards negligence or unscheduled interruptions. As production declines, the 30-cent amount the state gets declines. The real tension is if it's declining because of poor maintenance practices, the state actually gets more money taken away because it's based on a per barrel amount. The way the calculation actually works is counter to the concept of covering these items. MR. IVERSEN also pointed out that the 30-cent exclusion applies to everyone regardless of their behavior. And it's based on their production; it's not going toward negligence; it's not going toward improper maintenance; it's not going towards unscheduled shut downs in production. "It's a blanket that hits everyone in the entire state." CHAIR FRENCH said it's almost a gross tax floor. 10:59:43 AM MR. IVERSEN agreed. With that in mind, the 30-cent provision compared to SB 80 or HB 2001 is not a double disallowance because they are hitting different things. The 30-cent provision does not further the policy of promoting planned maintenance and planned shutdowns. Costs associated with deferred maintenance will rise in the future. Under the current regime it's $150 million, but if they want to stick with the exclusion (from capital costs), it could be increased to include operation expenditures as well or maybe a more realistic assessment of what costs are - and put that 30 cents up to 50 cents. He clarified that BP is just one of several working owners in that unit, and its reported $13 million tax effect is just a fraction of the effect on the state. 11:04:11 AM SENATOR WIELECHOWSKI asked if the state knows the cost of the corrosion repairs. MR. ROGERS replied it does not. SENATOR WIELECHOWSKI asked if he has authority to get that information. MR. IVERSEN replied if the department has a provision that makes that a tax effect by statute, he could, at audit. Otherwise he can't. Without language from SB 80 or SB 2001, the state is on thin ground. SENATOR WIELECHOWSKI asked what the loss to the state was from the other groups. MR. ROGERS answered that he could look up the working interest owners' shares in the unit operating agreements, and he recalled that BP owns about 26 percent of Prudhoe Bay. SENATOR WIELECHOWSKI asked if the state lost about $50 million. MR. IVERSEN replied yes - for one year. The expenses are supposed to span the course of two years. So those repairs would amount to about a $130 - $150 million tax impact to the state. SENATOR WIELECHOWSKI asked if those costs would be covered if the governor's section on this issue was passed. MR. IVERSEN replied: To the extent that any of those costs are associated with a spill...or an unscheduled interruption in production and there were those as well, then those would be excluded. At some point we will have to draw a line as to both in time and scheduling as to how far that goes.... SENATOR WIELECHOWSKI asked if the state would be able to capture more of the $150 million loss if SB 80, which includes a negligence standard, were to be passed. MR. IVERSEN replied: "Since there has been a plea of criminal negligence, if there is a negligence standard that we're looking at, then I would have to look at the actual plea agreement to determine exactly what that covers." One of the things he wrestled with is that gross negligence is currently excluded under statute. But the challenge with a negligence decision, he said, is if BP decides to replace the entire pipeline, deciding what percentage of that replacement would have been done anyway and what percentage is actually attributable to negligence. He opined that the language in Version M is tighter in terms of precluding an argument. SENATOR WIELECHOWSKI said the administration supported SB 80 last year. 11:11:42 AM CHAIR FRENCH asked Mr. Iversen to bring the committee something more definitive on the tax consequences of the spill on the North Slope: what they are under current law and what they would be if SB 2001 passed. MR. IVERSEN said that request brings up a couple of complications. The first is that this is under investigation by the Department of Law (DOL), so he can't speculate about the actual damages. In addition, he doesn't know what the costs are; he only has heard what they might be. CHAIR FRENCH asked where the $250 million to $300 million number comes from. MR. IVERSEN said they were in articles that came out when the incident happened. SENATOR HUGGINS recalled that $250 million came out in Resources along with an inflationary figure of 5 to 10 percent. He thought BP was the source. CHAIR FRENCH went back to AS 43.55.165(e) on page 17 of the CS that says "costs arriving from fraud, wilful misconduct, gross negligence, violation of the law or failure to comply with an obligation under a lease." He said BP's guilty plea is drop-dead proof that any costs that arose from that violation would not be deductible. He asked if he was interpreting that too broadly. MR. IVERSEN replied on its face that would seem to be the case, but he anticipated an argument that criminal negligence isn't the sort of violation of the law that they would be looking for. CHAIR FRENCH responded that his lawyerly sense says that he could argue that the only cost that arose from that violation was the fine paid, not the pipeline replacement and perhaps that's why the language is needed. SENATOR WIELECHOWSKI pointed out that there's still 74 percent from the other operators who didn't plead negligence. SENATOR HUGGINS asked Mr. Iversen if this provision is tighter than SB 80. MR. IVERSEN replied yes. SENATOR HUGGINS asked him what happens to the money that comes from the 30 cents/barrel provision. MR. IVERSEN said that provision is an express exclusion from lease expenditures under AS 43.55.165(e). That's the same provision that sets exclusions for things like gross negligence, fraud, the provision the Senator French mentioned a few minutes ago, violations of law or lease expenditures, and others. It is 30 cents/barrel of capital costs, "so you take your taxable production … which would be rate of production less royalty barrels, multiply that amount times 30 cents a barrel, and then you exclude that cost from allowable lease expenditures." It isn't money sitting in a fund. SENATOR HUGGINS said it is not to be used for maintenance work, and it is important to recognize it as a flat tax or revenue. 11:18:58 AM CHAIR FRENCH said he read that BP's costs to replace 16 miles of pipe in Prudhoe Bay have increased slightly to as much as $260 million. So they are in the ball park with respect to cost estimates or pipeline replacement on the North Slope. MR. IVERSEN said the state is losing the time value of money for seven years - a substantially larger loss to the state. The committee took an at-ease at 11:21:09 AM. 11:22:01 AM CHAIR FRENCH said they would discuss the issue of actual versus reasonable, costs and he asked Mr. Burnett to discuss the pool the ACES bill envisions. JERRY BURNETT, Director, Administrative Services, Department of Revenue (DOR), said the original ACES proposal has a provision for setting up a tax credit payment fund and that was taken out in Version M. He referred to the chart of tax credit payments under the current PPT and under ACES. He said there are three ways to pay tax credits - one is that a producer who has a tax liability gets a reduction in his tax bill. Another is if he has a transferable credit (someone who does not have a tax liability) that can be sold to the producer that reduces the producer's tax bill. "So it comes right out of the production tax pool before that production tax goes to the general fund." MR. BURNETT said a refundable tax credit (whereby a company with no tax liability to the State of Alaska under the production tax but with earned credits under the PPT) could be paid out of the general fund through an appropriation. 11:24:11 AM MR. BURNETT said rather than having an appropriation to the operating budget and then paying the refundable tax credits, the ACES proposal (Section 45 in the original SB 2001) sets up a tax credit fund where an appropriation is made from the production tax prior to it going to the general fund in a percentage. 11:25:31 AM MR. BURNETT said producer transferable tax credits are handled exactly the same as they are under the current PPT. Refundable tax credits are paid from a tax credit fund that is funded from the appropriation of a percentage of production tax liability. It requires an appropriation into the general fund from the legislature each year, and then the payments are made out of the tax credit fund without further appropriation. This means that the balance in the fund can be carried forward; the earnings from the fund stay in the fund and the fund would not be swept into the CBR (Constitutional Budget Reserve). It's not available for appropriation because amounts in that fund do not require further appropriation to be spent. CHAIR FRENCH said it seemed to be an unusual arrangement. MR. BURNETT said it isn't a unique example and the education fund is similar example. SENATOR THERRIAULT directed attention to page 30. MR. BURNETT said that was the intent of the fund. He explained that a concern with ACES is that tax credits aren't equitable, and using the tax credit fund ensures that the funds are there and doesn't compete with general fund expenditures. The funding mechanism allows the legislature to know what is going on. 11:31:44 AM CHAIR FRENCH recognized Senate President Lyda Green. SENATOR WIELECHOWSKI asked if he thought this section would cost $100 million. MR. BURNETT said it will not cost the taxpayer anything, but the credits that are in current legislation will cost about $125 million and he already has a FY'08 authorization. This section would put about $200 million into the fund if the appropriation bill also has a language section conforming to it (incorporating the money into the fund). Other provisions in ACES would likely increase the amount of credits that needed to be paid from the fund beyond the $125 million. SENATOR WIELECHOWSKI asked how he negotiates the price for the credits. MR. BURNETT replied that when the state is paying refundable tax credits it is a 100 percent value, but a transferable credit to a producer is a negotiated value between the holder of the tax credit certificate and the producer. Testimony has indicated that to be in the 90 percent range. The department believes that since producers get 100 percent of the value of their credits, there is no advantage to the state to not give 100 percent of the value of a credit to a non-producer who could transfer it to a producer and the producer would get 100 percent. 11:34:27 AM CHAIR FRENCH asked him how much would have to be appropriated to the fund to get it up and running and to explain how it doesn't get swept into the CBR. MR. BURNETT started with Section (c), which assigns 10 percent of the production tax revenue when the price for ANS West Coast is above $60 into the credit fund. That fund would hold the money; it will be invested by the treasury in short term investments. Tax credits will be paid from the fund to the taxpayer when the division finishes auditing a tax application. CHAIR FRENCH asked how they arrived at the 10 percent figure. MR. BURNETT replied that 10 percent was based on an estimate by the department's economist based on what the likely value of tax credits will be relative to production tax over time. This is just for those who have no current tax liability and small amounts of production for that year. MR. BURNETT estimated that this year the fund paid out $125 million and left $75 million. He said next year they were hoping for $250 million in credits because that means more investment is being done. He said it's not expected to grow in a linear way over time; it's expected to be lumpy. This smoothes the flow of money out of the production tax by taking a percentage out each year and then the fund is able to pay differing amounts each year and the rest is carried forward. The legislature could decide each year to stay with 10 percent or to change it depending on how much is left in the fund. 11:38:50 AM CHAIR FRENCH asked if this was a guideline rather than a prescriptive value that will automatically pop up in an appropriation bill. MR. BURNETT replied that he expected the administration would always put that into the appropriation bill and then the legislature would discuss it. SENATOR THERRIAULT said he expected the Finance Committee to watch the balance. He also pointed out that this language gives the department the authorization to pay for these credits only, and it wouldn't have access to any other balance in that fund. The legislature does, however. Everyone agreed. SENATOR WIELECHOWSKI asked if there would be a market for these tax credit certificates if the state declined to purchase them. MR. BURNETT replied that the state doesn't have an option as to whether or not to pay the different types of credits unless there is insufficient money in the fund. Remaining amounts of the credits that weren't purchased by the state because of insufficient funds would be either carried forward or could be transferred to another taxpayer who had sufficient tax liability. There are limitations on how much one could reduce tax liability through transferable credits, so there could be circumstances where it could only be carried forward. SENATOR THERRIAULT noted that the agency could ask for a general fund appropriation the next year or ask for them in a supplemental budget to pay credits that were turned in with insufficient funds. MR. BURNETT replied yes, but a long period of low oil prices could lead to insufficient money in the fund after lots of credits have been paid out, and the legislature might choose to not spend the money on credits. SENATOR THERRIAULT followed up on Senator Wielechowski's question and said even though there is a private sector market mechanism, payment of these credits ultimately always comes back to the state treasury. MR. BURNETT said yes. SENATOR WIELECHOWSKI asked if the state pays interest to the credit holder if it doesn't turn in its credits for a few years. MR. BURNETT replied no; it is unlike a tax refund. Tax credits are not ones that earn interest. They are paid when there is a sufficient balance. 11:44:09 AM CHAIR FRENCH asked how this would work and if the fund would fill up during FY'08 through an appropriation. MR. BURNETT replied that the state has outstanding credits, so it would make sense to request a supplemental appropriation to capitalize the fund in 2008 - especially since the revenues in 2008 should be sufficient. CHAIR FRENCH asked if it is the administration's plan to both capitalize the fund and spend it in the same year. MR. BURNETT replied yes, but the fund would have ongoing capitalization and would fluctuate from year to year. CHAIR FRENCH said it's not a slush fund. MR. BURNETT agreed and added that a slush fund would have no value to the department or the administration; it's just to cushion swings in income from year to year and to have sufficient funds to pay the credits each year. 11:47:01 AM CHAIR FRENCH asked how rapidly declining oil prices would affect the fund. MR. BURNETT replied that language in the bill requires the department to write regulations that determine how it pays credits in a time when there is an insufficient balance in the fund. It could be a case where explorers are spending a great deal of capital and so lots of money isn't going into the fund. He said the department is thinking of pro-rating the credits between the various tax certificate holders and allow them to carry them forward into the next year. It could be that the legislature will need to make a decision at some point. CHAIR FRENCH asked by how much FY'07 estimates were off. MR. BURNETT replied that the department asked for around $25 million in the supplemental budget and it ended up paying about $59 million in credits. Some credits have been paid out in FY'08, but not to the $25 million limit. He expected that most of the credits would come after the winter season and with the tax returns at the end of the year. Tax returns come in in April and they have 60 days to audit the credit application. MR. ROGERS clarified that under this proposal that is extended to 120 days. 11:52:34 AM CHAIR FRENCH referred to SB 80 corrosion elements inside the bill before them [CSSB 2001(RES), version M] and noted the memo from Mr. Bullock to Senator Wagoner, dated February 26, 2007, relating to retroactivity. Mr. Bullock opined that it would not violate ex post facto laws and it would be legal to look back that far. The committee recessed from 11:53:53 AM until 1:31:32 PM. CHAIR FRENCH called the meeting back to order. He said that Dr. Scott would address transportation deductions and that he had copies of the current law for the committee members. ANTONY SCOTT, Commercial Analyst, Division of Oil and Gas, Department of Natural Resources (DNR), said AS 43.55.150 is about transportation deductions which are used to determine gross value at the point of production. He said he would review the current law, some of its problems and some potential remedies for determining transportation deductions for tax purposes. He explained that gross value at the point of production is determined by subtracting reasonable costs of transportation from market prices. The statute says reasonable costs are determined to be different from actual costs by meeting three conditions. CHAIR FRENCH asked if this calculation applies to both royalty oil and PPT payments. MR. SCOTT said he is only talking about PPT payments, not how transportation tariffs are set for rate-making purposes, and he isn't suggesting the state can do anything about what a pipeline actually charges. He was speaking to what the legislature wants to determine is the appropriate transportation deduction for tax purposes. This is not about royalty deductions, which are determined by contract, either. MR. SCOTT said under the current PPT, reasonable costs are deemed to be the actual costs unless three simultaneous conditions hold. The last condition, the oil/gas transportation method, is not reasonable in view of existing alternative methods of transportation and will never be obtained. The only reasonable method of transportation of gas or oil off the North Slope, for example, is always going to be by pipeline - unless the sea ice melts. So the third condition, which would provide an exception to reasonable costs being actual costs, is never going to be obtained - they will always be actual costs. 1:36:50 PM CHAIR FRENCH asked why that matters. MR. SCOTT replied that the first condition (which would suggest that maybe reasonable costs shouldn't be actual costs) is when the parties to the transportation of oil and gas are affiliated. It's possible that the price paid doesn't indicate appropriate costs. Affiliate language exists elsewhere for determining appropriate lease expenditures. For instance, the production wing of an integrated oil company will pay a rate to the transportation subsidiary of the same integrated company. But because it's affiliated, it may not be reasonable. He surmised that when the statute was initially drafted, people probably thought the DOR should be able to take a closer look. The second condition is similar: If the contract for transportation of oil or gas is not an arms-length transaction or is not representative of market value of that transportation. 1:39:03 PM CHAIR FRENCH said the first two conditions cause a person's eyebrows to be raised that the correct rate is not being charged and that they need to look deeper. MR. SCOTT agreed. SENATOR HUGGINS said he believed that an arms-length transaction is a basic requirement for transportation for the affiliates. MR. SCOTT responded with an example supposing that BPXA owns 100 percent the North Star field, BPTA owns the North Star oil pipeline, and they transport 100 percent of BPXA's oil. Although they are separate companies, they are clearly affiliates. One could at least argue that it is not a fully arms-length transaction - although legally they are two separate entities and the parties nominating oil on the pipeline will be separate people from the parties receiving those nominations. He added that the pipeline has rules to insure that the pipeline personnel from BPTA do not provide privileged information to the shippers in BPXA. SENATOR HUGGINS said he operates under the assumption that an arms-length transaction is one of the requirements for the transportation. MR. SCOTT said that gets into the issue of what arms length is. 1:41:29 PM CHAIR FRENCH doubts it's possible to have arms-length transactions between affiliates. SENATOR WIELECHOWSKI asked where the potential for conflict between the state and producers is on this issue. Is there a concern that actual costs are not what reasonable costs should be? Is the concern that when they set their tariff they don't get taxed on that tariff? Is there a concern from anyone's perspective that when the tax is raised, the producers can raise their tariff? MR. SCOTT responded that the concern is if one affiliate is charging a rate to another affiliate of the same company. At the parent level, the company doesn't care about the rate, because it is moving the money from the left hand pocket to the right. But there is a substantial tax consequence, because the transportation deduction is a tax deduction. If the transportation tariff is $1 too high (above reasonable cost) under PPT, the state receives 22.5 cents less on each barrel of oil that is subject to tax. 1:44:34 PM MR. SCOTT said in practice, the first two parts of AS 43.55.150(a) go to circumstances that might raise some eyebrows about actual costs being reasonable. He advised: It might be worth taking a second look, but right now in the statute it's not just that you have to be an affiliate or have an arms-length transaction, it is also the case that reasonable costs and actual costs cannot be different unless there is an alternative mode of transportation - and practically speaking, that's never the case. MR. SCOTT said that right now this statute might remotely apply to some circumstances in Cook Inlet, but he couldn't imagine it. SENATOR THERRIAULT speculated that other basins where perhaps the oil could be trucked wouldn't trigger the state to impose a reasonable rate because one or two wouldn't be satisfied. 1:47:11 PM MR. SCOTT said that is correct. He supposed a case where a producer has chosen to truck the oil to market and there is more than one trucking company, but the producer does a sweetheart deal with one. If it is not an affiliate transaction and even though the one would charge less, the state would be required to pay the other rate. The state would have no recourse. 1:48:09 PM SENATOR HUGGINS reminded them that they would have to discuss the treatment of different geographical areas based on the different variables of developing. SENATOR THERRIAULT said now they are focused on the North Slope with its developed transportation system. But the state hopes to find resources in other areas, and the committee should make sure this statute, which applies statewide, works statewide. MR. SCOTT said transportation deductions on oil pipelines in the state have historically been determined by rates that have been sanctioned by regulatory bodies - the Regulatory Commission of Alaska (RCA) or the Federal Energy Regulatory Commission (FERC). Historically this has been the basis for saying that's the transportation deduction. 1:49:35 PM CHAIR FRENCH asked how far the transportation element is meant to carry. MR. SCOTT replied that transportation can begin downstream of the point of production. Upstream of the point of production, which is defined for tax deduction purposes in AS 43.55.920, is not considered transportation. Downstream is considered transportation. Moving oil on TAPS is transportation. Prudhoe Bay has oil transit lines that are not transportation; they are field lines that are considered to be upstream of the point of production because the oil is not metered yet for custody transfer. In Prudhoe Bay, transportation begins downstream of Pump Station 1. CHAIR FRENCH asked if that is really the inlet valve to pump 1. MR. SCOTT replied yes - it is metered where the producer transfers custody at a flange to TAPS. He said the Alpine unit has a similar story in that the custody transfer happens to the Alpine pipeline, which is owned by a separate transportation company. At that point, transportation begins. Upstream of that any of the flow lines within Alpine are not transportation for tax purposes. Those are lease expenditures (for tax purposes). "So that custody transfer meter marks the distinction between whether you're upstream of the point of production or downstream, and if you're downstream, it can be transportation." 1:52:36 PM CHAIR FRENCH said this came up yesterday, and he said that Kuparuk is more like the Alpine scenario. Prudhoe Bay has feeder lines that go into pump 1. MR. SCOTT agreed and said North Star is the same thing. CHAIR FRENCH asked how far downstream transportation goes. MR. SCOTT replied that it goes to market. He added that the Department of Natural Resources (DNR) and Department of Revenue (DOR), separately, have spent an enormous amount of time figuring out the reasonable cost of transportation for tankers. SENATOR HUGGINS asked how much maritime costs are. 1:54:08 PM MR. SCOTT replied that those change for different companies and he didn't want to venture a figure. There are differences between the tanker transportation deduction for royalty and for tax, but it's in the range of $1.50 to $2.00. DOR publishes what the marine transport deduction is to the West Coast for income tax purposes. SENATOR THERRIAULT said that was discussed last year. Exxon was the highest and the state is trying to come to an agreement with them on what fee should be paid - as a contractual dispute. MR. SCOTT said he would be happy to get those figures. He went on to explain that historically the transportation deduction for tax purposes has relied on rates that have been sanctioned by the regulatory bodies; however, it has not resulted from a regulatory determination. This is an important distinction. If you have a rate which is approved by a regulatory body, in general those agencies have a requirement to establish rates that are just and reasonable. Historically, and it's usually the case within the state, the producers through their affiliates own transportation. Typically you see a very close match between ownership percentages in the pipelines and ownership percentages of the production which comes out of the fields. He said because these integrated companies are paying themselves - moving money from one pocket to the other - they would prefer a high rate. Because the higher the rate, the lower their tax payments will end up being and the lower the royalty payments will be. So the only party usually complaining about transportation deductions has been the state. A dispute will occur and rate litigation will ensue. Without exception the state has ultimately come up with settlement agreements for those pipeline tariffs. The regulatory agencies have never said that the rates produced by the settlement agreements are just and reasonable rates. Just and reasonable is a term of art in the regulatory arena, which means historically cost-based rates - rates which reflect actual costs of developing and operating a pipeline including reasonable return on capital. 1:58:59 PM CHAIR FRENCH asked why the state has not pursued this claim to the very end. Why has it relied on settlement agreements when it would have gotten a better result by forcing the regulatory agency to come to a decision on what actual costs are? MR. SCOTT replied that TAPS is the really big deal, and when those tariffs were being litigated from 1977 through 1985 (when the state finally settled), there was significant uncertainty around methodology issues for pipeline rate making. This applied to pipelines in the Lower 48 as well. It was against that context of regulatory uncertainty that the state made the determination that it had no comfort in getting to a final conclusion any time soon. Another ten years was the prediction at the time of the settlement. He said the determination was made that the state was better off settling, because it might have a potential refund obligation that was continually accruing. It measured in billions of dollars. There are a number of reasons why it seemed reasonable at the time for the state to settle the TAPS dispute when and how it did. 2:01:29 PM MR. SCOTT said his Master's thesis was on this question, and he never opined whether it was good for the state or not. Many people think that the state made a mistake and others think it was the right thing to do. Having settled TAPS, he said it could be argued that the state got used to not wanting to litigate any more and it now has a framework for subsequent settlements and has long-term settlement agreements. He assured them that those settlement agreements did not say that for tax purposes the state would use the tariff numbers that came out of those settlement agreements. Those settlement agreements said the following: Here is a methodology. It'll determine a rate. So long as the rate each year that the transportation company files is at or below that rate, the state will not protest the rate. That's what the agreements say. It doesn't say we're going to use them for tax purposes or royalty purposes or any other purpose for that matter.... Now, on the royalty side, we have a number of royalty settlement agreements, which make reference to various transportation rates, but again, for tax purposes - and so we're bound to the extent that our contracts bind us. But for tax purposes, when coming up with appropriate transportation deductions, you are not similarly bound - just like you're not bound on issues relating to corrosion.... You're the policy makers; you get to decide what's an appropriate course of action for deductions. 2:04:19 PM SENATOR WIELECHOWSKI asked if the state has lost money because of the way the rates are set. MR. SCOTT replied that the RCA was host to intrastate rate litigation concerning rates for 1977 through 2000 brought by Tesoro, an instate refiner. Tesoro thought the rates were too high. Eventually the RCA "disgorged" a 200-page decision that found that through 1996, TAPS tariffs had collected $9.9 billion too much from shippers. A very large percentage of that $9.9 billion was collected from Exxon Production Company to Exxon Transportation Company, but given the state's royalty and tax interests, the state footed roughly 25 percent of the bill - or $2.5 billion. SENATOR HUGGINS asked who paid the remaining $7.7 billion. MR. SCOTT replied that the remainder of the settlement would be mainly transfer payments from affiliates of the pipeline. In other words BPXA paid BPTA too much. "But since they were paying themselves, it's neither here nor there." CHAIR FRENCH commented, "We don't care except that it reduces our royalty and taxes." 2:07:17 PM MR. SCOTT repeated that the vast majority of the remainder of the $7.7 billion was paid by affiliates of the pipeline to itself. There were some independent shippers, but very few. CHAIR FRENCH recognized Senator Thomas and Representative Buch. SENATOR WIELECHOWSKI asked if the state can recoup that $2 billion based on that RCA decision. MR. SCOTT replied no. SENATOR THERRIAULT said that four years were being disputed and the FERC decision potentially goes back two or three years. The potential impact to the state treasury if the RCA rate is upheld is $800 million. 2:08:34 PM MR. SCOTT said he would talk about tax impacts shortly. He explained that in 2005, rate litigation at the FERC commenced with Anadarko and Tesoro as parties. The state was also a party, but its complaint had to do with discrimination because the intrastate rates were so much lower than the interstate rates. Last May, an administrative law judge for the FERC determined that indeed the interstate rates set pursuant to the TAPS settlement methodology with the state were much too high and suggested that the just and reasonable rate (for transportation on TAPS) should be about $2.00 rather than $5.00. That matter was appealed to the FERC as a whole, but he could guarantee that, no matter what the result, the FERC's decision will be appealed in the D.C. Circuit Court. SENATOR WIELECHOWSKI said losing this tax makes him angry. MR. SCOTT said the $2.2 billion figure from the RCA's decision is from the period of 1977 through 1996. SENATOR WIELECHOWSKI asked if the state could do a statute of limitations retroactively to recoup that loss. 2:10:53 PM MR. SCOTT said he couldn't answer that. SENATOR WIELECHOWSKI remarked that was like stealing. SENATOR THERRIAULT reminded them that it was only in 2005 that the state started protesting, and the opportunity to protest previous years is lost. MR. SCOTT said that is correct. In essentially all cases, until recently, regulatory bodies have blessed settlement agreements that the state has struck with industry rather than having a fully-litigated rate case that eventually came to conclusion. That raises some issues about whether actual costs are reasonable, and evidence exists that they are unreasonable - given recent regulatory determinations of actual costs. CHAIR FRENCH recognized the presence of Senator Hoffman. 2:12:19 PM MR. SCOTT said the first question he wanted to raise is why the state bases its tax policy for pipeline transportation deductions on pipeline rate litigation. For royalty, it is pretty much stuck doing so, but for taxation, it is not. Tax for transportation deductions is a sovereign matter. The right answer could be zero, he remarked, and added that this is not an unheard of measure. It's the legislature's call. MR. SCOTT further elaborated: On pipelines transporting federal royalty, if the pipeline is an affiliate of the producer, MMS (Minerals Management Service) doesn't take the tariff rate as the basis for determining the transportation deduction, in general. MMS is the federal equivalent of DNR for the state. So, under their leases, MMS, says, 'We will give you an actual and reasonable cost, but we're not going to look to the regulatory agency to determine actual and reasonable costs for transportation if you don't have a properly contested rate proceeding.' So, if this is not an arms-length transaction, what we do is we'll say, 'Here is a method, here's what you'll use. This is the formula, crank it through the formula. The rate that comes out [is] your transportation deduction.' It is not dissimilar, frankly, from what DOR - it's actually a little more formal. No, I shouldn't say that. It's not dissimilar from what DOR does for marine transportation deductions.... There are some reasons for the state to avoid relying on the regulatory process in setting tax value. First of all, as we've just been talking about, pipeline litigation can drag on for a considerable period of time and in the meantime you're accruing balances that may show up as refunds to the state treasury and may not, but you're creating uncertainty as to the ultimate tax value when you rely on litigation for determining tax value. 2:15:28 PM CHAIR FRENCH said his sense is that the regulatory process and the litigation that is used from that takes much longer than the litigation process that ensues when you have a tax dispute. MR. SCOTT said that can be the case. In a memo to DNR, Spencer Hosie said he could resolve tax disputes in two or three years. Mr. Scott said he hoped the first stage of the rate litigation at the FERC will be concluded within three years, but then it will go to the D.C. Circuit Court; more than likely a small portion of it will be remanded back to the FERC. It is a process that can take considerably longer than three years. He said the original Tesoro protest with the RCA was in 1997 and that was not concluded until 2005. That decision is still not final and is before the Alaska Supreme Court right now. SENATOR THERRIAULT said it took RCA five years, but it is evaluating a methodology and doing all the work. Then the challenge in the court system determines whether it was reasonable and not arbitrary. So there is some deference to the agency's expertise. One would expect the agency function to be the longest. MR. SCOTT agreed and said the second reason to question using the regulatory process to set tax value is that absent arms- length transactions with commercially sophisticated parties like Tesoro was at the RCA or like Anadarko and Tesoro were at the FERC. Absent that kind of a protest, it is at least questionable whether you're going to get settlement results that are a good match to actual costs or reasonable costs. 2:18:25 PM MR. SCOTT gave an example. Right now the TAPS transportation deduction is about $5.00. TAPS is one hose with separate straws within it and each one has a different tariff and those bounce around from year to year. The RCA determined that costs were actually around $1.97. The FERC law judge determined they were about $2.05. While the litigation continues, the state continues to allow $5.00 for a transportation deduction for tax purposes. If it is the case that TAPS deductions are $3.00 too high and assuming production is 760,000 barrels per day and production tax rate is 22.5 percent, it would cost the state about $160 million per year. 2:21:12 PM MR. SCOTT said he wanted to shift focus to talk about transportation deductions for gas pipelines. He said gas pipelines are typically built on the basis of negotiated rates between shippers and pipelines, and there is no scrutiny by FERC as to whether it is a fair bargain. In the case of a major North Slope gas pipeline, if the producers end up owning the gas pipeline, they can negotiate with themselves. That could result in a very high negotiated rate because they could use that rate for determining their deduction for determining gross value at the point of production for gas. Given the current statute, the state wouldn't even have a regulatory forum really to go to, practically speaking, to complain about this excessive, non- arms-length negotiated rate. The FERC doesn't care. So, why would the state want to set its tax policy for transportation deductions on the basis of a non-arms-length deal that the state can't even litigate before a regulatory body? The state's experience with TAPS suggests that would be unwise and there is no need to do so. He said this is an opportunity for the state to reconsider how transportation deductions are handled for determining gross value at the point of production. 2:23:56 PM MR. SCOTT said the state presently must live with it because it's never the case that there will be other reasonable modes of transportation - so the third condition in AS 43.55.150(a) will never be met. The DOR could follow MMS's lead and establish regulations given a statutory change to determine appropriate cost deductions for non-arms-length transactions. But the state will need to be careful to deal with the circumstance that Anadarko faces, for example. Anadarko really does pay TAPS tariffs; it doesn't own a part of the pipeline. A non-TAPS owner that is not an affiliate may want to use their actual costs. SENATOR WIELECHOWSKI asked the impact of exploration on the North Slope when tariffs are so much higher than they should be. MR. SCOTT said it is not helpful. There have been a number of presentations on how the tax rate affects the break-even point. Those movements based on tax may be well under that $3.00 swing. It is a substantial difference. 2:26:36 PM SENATOR WIELECHOWSKI asked if tariffs were down to $2.00 would that encourage exploration on the North Slope. MR. SCOTT said the short answer is no, and: the reason is because the state cannot, through its tax policy, determine what a pipeline actually charges; so a third party shipper right now faces TAPS tariffs which are arguably too high. They have to pay that tariff if they want to get their product off the North Slope. What you choose as an appropriate transportation deduction for tax purposes can't directly affect what the pipeline charges that third party. What you can do, and what you clearly have the power to do, is affect whether that transportation deduction affects the state's general fund. So, through tax policy you can't directly change the rate. Through tax policy you can directly affect the transportation deduction. SENATOR WIELECHOWSKI asked if the pipeline owners have to get FERC approval on rates or if they charge whatever they want. MR. SCOTT replied that owners of a pipeline will have to have a tariff on file with the FERC, for example. Absent someone complaining about that tariff, it will be allowed to go into effect. Protesting tariffs is an extremely lengthy and expensive process; it's not something that a company undertakes lightly. It would have to have enough production to be worth their while on a cost benefit basis. When Anadarko and Tesoro decided to challenge TAPS tariffs at the FERC, they needed approval for the legal expenditures that were going to be entailed because they measured in many millions of dollars. Small, new entrants will not be inclined to do that. 2:29:17 PM CHAIR FRENCH went back to the Anadarko case and asked why it wouldn't deduct the actual costs, since they are not affiliated. MR. SCOTT replied that changing "and" to "or" will get the state most of the way, if not all of the way, to where it needs to go. It won't capture Anadarko, but they want to make sure that when DOR promulgated regulations (after changing "and" to "or") for setting appropriate transportation deductions that it applies to everyone whether they are affiliated or not. It's probably not necessary to do it in statute. 2:31:06 PM SENATOR THERRIAULT said the actual cost will be a legitimate deduction for Anadarko or any other non-TAPS owner. MR. SCOTT said that is right. TAPS is the poster child, but this change could potentially apply to the other pipelines and it makes a difference. One needs to look on a case-by-case basis. It is really about transportation deduction policy. The committee took a recess from 2:33:05 PM to 2:52:53 PM. CHAIR FRENCH called the meeting back to order and said that they would hear a response to the previous testimony from Mr. Scott about actual versus reasonable costs from AOGA. MARILYN CROCKET, AOGA, said she is not planning to respond to the previous testimony. She has testimony on actual versus reasonable cost and the credit buy back. CHAIR FRENCH asked to start with the most recent topic. 2:54:07 PM TOM WILLIAMS, Chairman, AOGA Tax Committee, said the issue of actual versus reasonable costs is real and was faced by the DOR when he was director of the Petroleum Revenue Division of DOR (which is now the Tax Division) from 1975 to 1979 and also when he was DOR commissioner from 1979 to 1982. Back then the same issue arose in other contexts. In the context of the cost to transport ANS crude by marine tankers from Valdez to markets on the West Coast, Hawaii, St. Croix in the Virgin Islands and to the U.S. East and Gulf Coasts, the respective marine transportation costs had to be netted out or subtracted from the market value of the ANS delivered at each outside market destination in order to determine the corresponding netback value of that oil at Valdez. From the Valdez netback the pipeline transportation costs were further netted out to get the corresponding netback in the field (which was formally called the gross value at the point of production in production tax statutes starting in mid-1977). MR. WILLIAMS said, from a tax administrator's perspective, the advantage of using reasonable costs instead of actual costs is that you don't have to audit reasonable costs. You just find a publication or other recognized authority that tells you what the reasonable costs are and the current market conditions. For international marine transportation there was actually such a publication or authority. He said the average freight rate assessment (AFRA) was published by the London Tanker Brokers Panel. Those rates were helpful to DOR to find the delivered cost to acquire comparable foreign crude at a market destination where ANS was also going and competing against that foreign supply, but AFRA didn't give them the reasonable cost or market value of waterborne transportation in Jones Act ships. When he first heard about a new U.S. AFRA in 1978 he was inclined to consider using it to determine the reasonable costs for Jones Act tanker transportation from Valdez to the other U.S. ports where ANS was shipped - he was very inclined until he discovered that the tanker fleet for ANS would dominate the rates quoted for this U.S. AFRA. In other words, those quotes would basically be the same information he would be getting - it would be just another source. This illustrates one of the problems of using reasonable rates - which is finding an authoritative source you can trust. Often times there simply isn't one and sometimes they go out of business or become unreliable and inaccurate. The only other way to implement the reasonable cost approach is to audit the cost of everyone involved. 2:58:07 PM MR. WILLIAMS said this is the worst of all possible worlds from a tax administrator's perspective because you have to do all the auditing and other work in an actual cost system and once that is done there are the further challenges of proving to everyone that your reasonable cost figures are accurate and represent market conditions. Given the constraints of tax confidentiality, he asked how cost information could be used from one taxpayer to show any other taxpayer how reasonable cost was determined. The issue of how one taxpayer's information could be used to show another taxpayer was solved in the statute enacted last year. MR. WILLIAMS said reasonable cost figures will be badly out of date given that taxpayer information from which the department's figures are derived would have to be audited first to insure reliability. There would be a tax that no taxpayer could comply with correctly when due. It would require numerous filings and refilings of amended returns by tax payers as reasonable cost data was published or updated on the basis of new audit results, or it would be a tax whose correct amount cannot be determined at all until taxpayers are audited. The challenge for DOR to set up and maintain accurate records of each taxpayer's payment, corrections, and final cost figures would be enormous, but relying on audits is the only way to determine the correct amount of reasonable costs, and that would amount to taxation by audit instead of self reporting and self assessment. It would be difficult and inefficient to administer a tax that supposedly is self reported and self assessed. He continued: Rather than taking any of these unappealing alternatives, we (DOR) opted in 1979 and 1980 to use actual transportation costs as much as we could and save ourselves these troubles. From a taxpayer's point of view - and I am now putting my hat back on as chair of the AOGA Tax Committee - the reasonable cost approach suffers from three major problems. First, taxpayers only know their own business and their own actual costs. Anything different from a taxpayer's own actual costs cannot be right in its eyes, because the actual costs are what they are and the facts cannot be different from what they are. It is a rare tax, indeed, that does not look at the actual performance or results of a taxpayer's business or business related activities. 3:00:45 PM And as long as the tax is taking such later items into account, it is fundamentally unsound to ignore actual costs or similar actual results, and to base the tax instead on some different cost or result no matter how reasonable this derivation may be. Second, unless there is some reliable and authoritative source about reasonable costs under the current conditions that is available to taxpayers before their tax returns and payments become due, it will be impossible for them to compute, report, and pay the correct amount of tax on that due date. In the case of operating and capital costs to explore for, develop, or produce oil or gas on the North Slope, there is no reliable authoritative source available at all, much less one that can be available on a timely basis. Here you can see we misunderstood where the concerns seem to be of the committee on this subject. We were addressing the issue of the upstream costs in the field rather than downstream costs of the transportation. Third, if DOR would be determining the amount of reasonable costs to explore for, develop, or produce oil and gas on the North Slope on the basis of taxpayers' verified and audited actual costs for these activities, it would still be impossible for taxpayers to report and pay the correct amount of tax when it comes due. In addition, the problems of filing and refiling amended tax returns or of having the alternative taxation by audit will be about as difficult and onerous for taxpayers as they would be for tax administrators. It is also worth remembering that to the extent the actual lease expenditures can be based on joint interest billings by the operator to other participants in the operations, the total actual costs under those billings will be the same for each participant with the only difference being the size of each one's share of that total. Even if DOR were not to rely on the audits by non operating participants of the billings to ensure that those billings are appropriate and accurate, it would have to do only one audit of each set of billings by the operator. This is the same set for all the partners. And that would be, instead then of doing completely independent audits for each participant's actual costs. So, using actual costs could prove to be significantly less burdensome for DOR to administer, audit, and enforce than one might first expect. 3:03:14 PM SENATOR WIELECHOWSKI asked if his testimony represents a consensus view within AOGA including Anadarko. MR. WILLIAMS replied yes. "There was no dissent." SENATOR THERRIAULT said Mr. Williams indicated his testimony was not in response to the previous discussion, but rather in response to the upstream in-field reasonable cost discussion. MR. WILLIAMS said yes, but the anecdotal discussion about AOGA's experience with tanker rates fits into the discussion. CHAIR FRENCH asked if AOGA takes a position on the proposal with respect to AS 43.55.150, to change the final "and" to an "or", he would give him further opportunity to speak before the bill leaves committee. 3:05:13 PM SENATOR THERRIAULT asked if the gathering lines on the North Slope are regulated or just negotiated. MR. WILLIAMS replied that the pipelines in the fields, whether they are oil transit lines or not, upstream of the custody transfer meter are not regulated and have not been deducted in getting to the gross value at the point of production. That point of production is downstream. SENATOR THERRIAULT asked if the discussion for transportation costs for tax purposes is only for the downstream stuff. MR. WILLIAMS said yes. The transportation costs start at the custody transfer meter where it leaves the unit and goes into the custody of the common carrier pipeline serving that field. CHAIR FRENCH asked if AOGA had an opinion on a tax credit fund. 3:06:18 PM MR. WILLIAMS replied that AOGA supports the concept of the state buying back tax credit certificates and creating the fund to do so. Further he said. However, for this system to work it will be essential that future legislatures appropriate the necessary money into the fund each year. Otherwise the fund will turn into an empty promise for future investors. In as much as the topic currently under consideration includes appropriation authority for credit buy backs, AOGA would draw your attention to a few potential issues relating to this portion of the topic. First, might the automatic inclusion of earnings on the fund as part of the fund without specific appropriations of those earnings back into the fund each year violate Alaska's constitutional prohibition against dedicated revenues? If so, what might the legal effect be of AS 43.55.028(h) stating that 'Nothing in this section creates a dedicated fund?' With respect to that question, if I may depart from the testimony, I think that since this fund is an account in the general fund, this issue of dedication might be moot - as I understand it, because it is not an independent thing like the University of Alaska or something like that. But if that's the case and the earnings sort of automatically are there and there isn't an appropriation, then could they be taken out of the treasury without violating the clause in the constitution requiring an appropriation to take money out of the treasury? The fact that this statute says that they are automatically in the fund balance might not be self executing because it's not an appropriation; so you would have to take care in the future to make sure that in addition to appropriating the new tax receipts, the percentage of the tax each year, that you would also be appropriating the interest. There might be an issue otherwise about the use of that money that might not have been appropriated and that violates Article 9, Section 13 - or it might. I can't give you the legal opinion on that. Our concern is that it might. 3:09:07 PM The second question, which is now - might the anti- lapse provisions in AS 43.55.028(f), which states that money in the fund at the end of a fiscal year does not lapse and remains available for expenditure in successive fiscal years, which includes the monies appropriated to it, does that more properly belong in a bill making an appropriation to the fund or a bill specifically reappropriating the money back into the fund, rather than in this legislation establishing the fund in the first place. If so, would AS 43.55.028(f) violate the constitution's one-subject rule for legislation? There it says: 'Every bill should be confined to one subject unless it is an appropriation bill or one codifying, revising, or rearranging existing laws. Bills for appropriations shall be confined to appropriations.' Although representative of some members of the AOGA tax committee may be attorneys, the tax committee is not authorized nor qualified to offer you any legal advice or opinion about what the answers to these questions might or might not be. The most we feel we can properly do under the circumstances is to point out these potential issues so you can get whatever professional legal advice you may feel is necessary or appropriate to answer these questions and to revise, if necessary or prudent, these provisions of the bills accordingly. And I would add here that technically these are not in the bill in the sense that they are not in the committee substitute from Resources, but I discussed them because they are on the agenda and it's in the original bill. As I close, Mr. Chairman, I should mention that AOGA has prepared a white paper on aspects of tax credits since we're on the subject sort of tax credits, under the proposed bill that falls outside the specific scope of the present topic. In fact, the white paper covers the following topics: the 50 percent limitation on credits taken the first year for capital investments, the "TIE" credits, electric ratepayer benefits from selling tax credits, and conditioning exploration tax credits on new requirements to share information. We believe the committee members might find some or all of these points to be of interest and with your permission I would like to have that be submitted as part of the record. CHAIR FRENCH responded he would be happy to take that in. 3:11:27 PM SENATOR THERRIAULT suggested that the drafter had patterned the language after other sub-funds of the general fund that retain their interest and it may be worth having the legal division look at it. He didn't think it would create a problem. If the legislature in the future did not go through this separate fund mechanism to repay the credits, that doesn't mean the credits wouldn't be honored. Future legislatures could have different ways of honoring the state's commitment. 3:12:55 PM JERRY BURNETT, Director, Administrative Services Division, Department of Revenue, said he agreed with Mr. Williams that the legislature would have to appropriate the interest each year in order for the department to be able to spend it. The dedication of funds issue can be taken care of in the annual appropriation bill and it would be their intent to do it that way. CHAIR FRENCH asked about the anti-lapse provisions being in an appropriation bill as opposed to this one. MR. BURNETT replied that the intent of this legislation clearly can't deal with appropriations, so he intended to put the lapse language in the appropriation bill. SENATOR THERRIAULT asked if their main concern is having a fund that is not sweepable. Mr. Burnett replied yes. CHAIR FRENCH asked Mr. Scott if he wanted to respond to some of the comments made with on transportation costs. He replied no. 3:14:53 PM SENATOR THERRIAULT asked for producers who are owners of the means of transportation, if the state has to be careful in applying a reasonable rate to all shippers because some of them actually pay that rate. MR. SCOTT replied that is exactly right. So for TAPS, for example, there are a number of companies that have production on the North Slope who ship through TAPS or sell to other parties who ship through TAPS and don't own any interest in TAPS. For those parties, the reasonable costs really should be their actual costs because they really do pay it. The primary function of the tariff for an affiliate producer is to affect their tax and royalty distributions to the state. CHAIR FRENCH said he wanted to hear from a producer with no interest in TAPS before the committee takes final action on the proposed amendments. He said they would next take up the cost of the spill and how SB 2001 prohibits producers from deducting the costs of unusual events from their production taxes. 3:17:16 PM BERNARD HAJNY, Manager, Production Taxes and Royalties Alaska, BP Exploration Alaska, testified that their Prudhoe Bay manager testified that the cost to replace the oil transit lines is currently in the range of $250 million to $260 million. CHAIR FRENCH asked if those costs had been spent or will be spent or both. MR. HAJNY replied that some will be spent in calendar year 2007 and the remainder will be in 2008. That is the expected total. 3:19:20 PM SENATOR WIELECHOWSKI asked if that cost was all incurred by BP or if other parties are participating. MR. HAJNY replied that expenditure would be borne by the operating unit with BP as the operator. SENATOR WIELECHOWSKI surmised the cost would be spread around. MR. HAJNY replied yes. SENATOR WIELECHOWSKI asked if BP intends to write off the full amount as a deduction under the current PPT. MR. HAJNY referred him back to Doug Suttle's letter to the legislature on February 15, 2007 where he indicated BP intended to deduct the cost of inspection, business resumption, and replacement of the oil transit lines. There being no further business to come before the committee, the meeting was adjourned at 3:22:02 PM.