CS FOR SENATE BILL NO. 305(RES) "An Act providing for a production tax on oil and gas; repealing the oil and gas production (severance) tax; relating to the calculation of the gross value at the point of production of oil or gas and to the determination of the value of oil and gas for purposes of the production tax on oil and gas; providing for tax credits against the tax for certain expenditures and losses; relating to the relationship of the production tax on oil and gas to other taxes, to the dates those tax payments and surcharges are due, to interest on overpayments of the tax, and to the treatment of the tax in a producer's settlement with the royalty owners; relating to flared gas, and to oil and gas used in the operation of a lease or property under the production tax; relating to the prevailing value of oil or gas under the production tax; relating to surcharges on oil; relating to statements or other information required to be filed with or furnished to the Department of Revenue, to the penalty for failure to file certain reports for the tax, to the powers of the Department of Revenue, and to the disclosure of certain information required to be furnished to the Department of Revenue as applicable to the administration of the tax; relating to criminal penalties for violating conditions governing access to and use of confidential information relating to the tax, and to the deposit of tax money collected by the Department of Revenue; amending the definitions of 'gas,' 'oil,' and certain other terms for purposes of the production tax, and as the definition of the term 'gas' applies in the Alaska Stranded Gas Development Act, and adding further definitions; making conforming amendments; and providing for an effective date." This was the seventh hearing for this bill in the Senate Finance Committee. Co-Chair Green announced that three independent oil and gas companies would provide their perspectives on the Petroleum Profits Tax (PPT) during this hearing. 9:04:57 AM PPT Discussion Anadarko Petroleum Corporation April 7, 2006 MARK HANLEY, Public Affairs Manager, Anadarko Petroleum Corporation/Alaska, stated that his presentation would review Anadarko's Alaska operations; the company's perspective on the PPT as presented in SB 305 which was the original PPT bill proposed by Governor Frank Murkowski; the key issues of the PPT identified by Anadarko and how they might impact the company's activity in the State; and elements of concern to the company in CSSB 305(RES) which is the bill being advanced by the Senate. [Note: CSSB 305(RES) is referenced as CSSB 305 in these minutes.] Mr. Hanley's remarks were accompanied by a PowerPoint presentation (copy on file). [Note: The pages in the PowerPoint presentation were not numbered; therefore, for reference purposes, the Senate Finance Committee Secretary made a notation on each page of the corresponding timestamp in which that page was addressed in this hearing. General descriptive information of each page is provided in the body of these minutes when feasible. A copy of the handout can be obtained by contacting the Legislative Research Library at (907)465-3808.] Mr. Hanley informed the Committee that Anadarko, which was headquartered in Houston Texas, is a large independent company whose primary activity is to explore and produce oil and gas. Even though Anadarko had global operations, it did not have much public name recognition as it did not have refineries or gas stations. Anadarko had approximately 3,500 employees and market capitalization holdings of approximately $23 billion. Mr. Hanley communicated that Anadarko had operated in Alaska for approximately ten years. The map in the presentation titled "Anadarko's Alaska Acreage Position" depicted the company's "extensive" Alaska acreage holdings: the areas highlighted in pink or yellow indicated areas in which Anadarko had an ownership interest. Other companies' acreage was depicted in gray. Anadarko's acreage exceeded five million acres gross or 2.2 million acres net and consisted of leases on State, federal, and Native Regional Corporation land. The company competed with ConocoPhillips for having the largest net acreage in the State. ConocoPhillips leases consisted primarily of State and federal land. Mr. Hanley noted that Anadarko addressed its land holdings as a regional model whereas other companies typically concentrated on one or two areas of operations at a time. Anadarko currently had in excess of "100 leads and prospects across the State". The company enjoyed working in the State because there were "opportunities in multiple plays". 9:07:37 AM Alaska Opportunities · World class petroleum basin · Significant remaining resource potential · Legacy type prospectivity (i.e. Anchor Fields) · Favorable political environment · Abundant new entrants/partnering opportunities Mr. Hanley reviewed the information. He pointed out that even a 50 million barrel field would be uneconomical were it more than five or ten miles from existing infrastructure. Nonetheless, the company determined that significant oil potential particularly large fields did exist. Large oil fields, such as Alpine, which are referred to as legacy or anchor fields because they could "support their own facilities", were important to Anadarko. The company preferred to develop satellite fields after the infrastructure of the larger field was in place. Anadarko, partnering with ConocoPhillips, held a 22-percent ownership in Alpine. The two companies were also conducting exploration activities in the National Petroleum Reserve-Alaska (NPR-A). Mr. Hanley noted that the stability of the political environment in the State was important to the industry. They also appreciated the State's efforts to address industry issues. For example, the State endeavored to find ways to lengthen the short drilling season experienced in the State. It also continually addressed regulatory issues of concern to the industry. Mr. Hanley was pleased that new companies were entering the Alaska resource market. This momentum was considered positive, as, in addition to furthering the development of North Slope resources, these companies could be potential partners. 9:09:29 AM Senator Dyson asked Mr. Hanley to comment on some companies' position that the PPT would negatively affect exploration and development activity in the State. Mr. Hanley disclosed that the PPT had been the focus of two recent meetings he attended at company headquarters. Anadarko's efforts to advance Alaskan projects with some partners was being hampered because of the proposed tax change. People wanted to know how such things as the 40 percent exploration credit allowed under the State's current tax regime, the Economic Limit Factor (ELF), would be affected. Thus, Anadarko was considering how the proposed PPT would affect its projects. "Depending on how it comes out, it can have an impact." He would expand on this later in his presentation. To that point however, he noted that Anadarko had determined that "the Governor's bill, as introduced", would "improve our exploration economics" over that of ELF. 9:11:14 AM Senator Dyson asked whether that view was primarily due to the exploration and development work credits included in SB 305. Mr. Hanley replied "absolutely". Additional remarks on this would be forthcoming. Alaska Challenges · Maturing basin/materiality · High costs · Lack of infrastructure and competition · Extremely long lead-time exploration · Seasonal drilling & regulatory timing requirements · Lack of gas market Mr. Hanley stated that while Alaska had resource potential, it also had resource challenges. He reviewed the challenges as listed. The lead time from discovery to production in Alaska was one of the longest in the world. While it might be possible to drill one well a year in Alaska, three wells could be drilled in one year in places such as the Gulf of Mexico (GoM). A project which might take four or five years somewhere else might take seven to ten years here. Tying up money for that length of time had an impact. The time required for projects in the State also resulted in conservative oil price valuations. People have asked him why more drilling had not accompanied the high price of oil. His response was to ask those people if they could predict what the price was going to be from 2013 to 2035. That was the length of time that might be required to produce some of Alaska's oil. Conservative decisions must be made. Mr. Hanley noted that the lack of gas market was also an issue. Anadarko was very supportive of a gas pipeline because they believed there was "significant gas potential" in the State. Right now, gas discoveries were considered "throwaways" as, without a transportation link, they "are not worth anything". The belief was that a gas pipeline would incur both significant gas exploration and oil exploration. How about PPT? · We support original bill · Administration did a good job balancing issues & priorities o We pay more in taxes, but our exploration economics improve and there is some downside price protection - should increase exploration investment o State receives substantially more revenue than under current system Mr. Hanley voiced support for the original bill as introduced by the Governor. He categorized Anadarko as having been "more supportive" of that bill than other producers who have painted themselves as being "tentatively" supportive. The Administration "did a good job of balancing the issues and priorities that were out there. Frankly, as a producer at Alpine and an explorer" we would probably pay more in taxes under the new bill"; however that would be offset by "an improvement in our exploration economics". The "downside price protections" provided in the PPT are an improvement over ELF. Nonetheless, the State would be collecting more revenue at higher prices under the 20 percent tax and 20 percent credit (20/20) structure proposed in SB 305. 9:14:12 AM More production needed · Declining production is primary driver of lower state revenue · Increased investment (compared with today's levels) needed to increase production & stem decline · Original bill offset tax increase with credits & allowances o Our exploration economics generally improved · Tax rate increases and allowance decreases (with no credit offsets) reduce our economics o Minimum economic field size increases o Amount of economically recoverable oil & gas decreases Mr. Hanley referenced an Anchorage Daily News editorial [copy not provided] which spoke to the decline in oil production in the State. Declining production was an issue of concern to the industry. As production decreased, costs associated with that production increased. Some of this issue "is masked" by high prices. From an exploration position, Anadarko hoped that the provisions in the PPT would encourage additional investment in the State beyond that occurring under ELF. 9:15:20 AM Mr. Hanley stated that SB 305, as opposed to the House and Senate PPT committee substitutes, would balance the higher tax with credits and deductions. Even thought the severance tax levied on the industry would increase under all three of the PPT proposals, the State would "pick up" 40 percent of drilling and other development costs under the 20/20 terms of SB 305. Mr. Hanley pointed out that the tax increase and the decreased allowances contained in CSSB 305 would affect Anadarko's exploration economics. To further this point, he displayed a copy of "Chart 11.7" [copy not provided] developed by Dr. Pedro van Meurs, an international oil economist hired by the Administration, which provided "a net present value" (NPV) analysis of a 50 million barrel field. The bottom graph line depicted the economics of that field under ELF. Dr. van Meurs also calculated the economics of the field under two other scenarios: a 20 percent tax and 15 percent credit (20/15) PPT tax structure and a 25 percent tax and 20 percent credit (25/20) PPT structure similar to that proposed in CSSB 305. Like CSSB 305, the 25/20 example also excluded the $73 million allowance contained in SB 305. While the 20/20 tax regime proposed in SB 305 was not depicted on the chart, the value of the $73 million allowance included in that bill to a new entrant in the oil and gas industry in Alaska was reflected on the chart. Mr. Hanley noted that the $73 million allowance provision in SB 305 would be of some benefit to major companies; however, its impact on smaller companies and new entrants in the State's resource market would be much more significant. Mr. Hanley pointed out that the graph lines crossed over each other when the West Texas Intermediate (WTI) oil price exceeded $40 a barrel. At that point, the 25/20 PPT example, without the $73 million allowance, would be, in the industry's perspective, "worse than the current system": it would tax more at that level, even without a Progressivity element. The inclusion of a Progressivity element would further affect the percent of government take. Such things were considered by the industry in their economic modeling. The industry was also concerned about which price level would trigger the Progressivity escalator. In summary, the Progressivity component included in CSSB 305 would negatively affect the prospectivity of fields in Alaska. 9:19:11 AM Senator Bunde asked Mr. Hanley to further explain how the 25/20 example modeled on the chart compared to CSSB 305; specifically whether it contained "the two for one clawback" provisions included in CSSB 305. Mr. Hanley considered the 25/20 line graph on the chart to be similar to the 25/20 PPT before the Committee with the exception being that the "two for one" clawback transitional language was not factored into the modeling. The inclusion of that transitional language in the modeling would not result in a noticeable shift in the line as those provisions would provide "just a slight amount of benefit" to the industry. Senator Bunde understood therefore that the transition language in the bill was of less importance to companies such as Anadarko than it might be to others. Mr. Hanley clarified that, while the transition language would be "important" to Anadarko, it would affect companies differently. Companies such as Anadarko which had expended money in the past and expected to spend money in the future would be assisted by that provision. However, the transition provisions would not benefit a company new to the State. Mr. Hanley expressed that the economics of production from existing fields would differ from those of new fields. "Different fields have different threshold prices" upon which they would make money. Some profess that the 25/20 PPT proposal would be more beneficial to exploration when prices were low, as it would provide some downside protection. The discussion, however, does not address the fact that at low prices, few new prospects would be economical. Thus, while the 25/20 PPT proposal would cover the cost of drilling a dry hole, no wells would be drilled when barrel prices were low. It would be uneconomical to do so. The whole story must be considered. Mr. Hanley affirmed that, as attested by the State's consultants, the industry would include a range of prices in a project's economic modeling analyses. 9:22:28 AM Mr. Hanley next reviewed a "Small Oil Development - Net Present Value" chart [copy on file] developed by Anadarko which was based on the wellhead oil price rather than the WTI price utilized in Mr. Van Meurs NPV chart. Therefore, for comparison purposes, eight dollars should be added to the wellhead price. The charts were similar in their modeling conclusions. Anadarko included the $73 million dollar allowance in both the 20/20 and 25/20 modelings depicted on its chart and compared those charts to ELF. While this chart would indicate that a "higher tax rate" would negatively impact a project's economics, the decision as to whether those economics would be "worse than the current system depended on the price forecast "and what's in there" in regards to the tax rate, the credits, and the allowances. 9:24:38 AM Mr. Hanley communicated that another issue of concern to the industry was the PPT tax escalator which the Legislature has titled Progressivity. The industry characterized this as a windfall profits tax; however, it would be more appropriate to refer to it as a windfall gross revenue tax. A windfall profits tax would be applicable where it to apply "to a profit margin after expenses, not applying something to a gross number regardless of cost". Mr. Hanley further noted that the primary focus of the discussion about the Progressivity element was the barrel price point at which the Progressivity element would be triggered. 9:25:54 AM Mr. Hanley referred to a chart [copy not provided] developed by Econ One Research, an economic research firm hired by the Administration. The chart depicted "USGS [United States Geological Survey] estimates at different oil prices of the economically recoverable reserves". Exploration efforts occurring on reserves on the central North Slope was the focus of this chart. The Arctic National Wildlife Reserve (ANWR) was not included in the information. USGS estimated there were approximately four billion barrels of economic recoverable oil remaining in the central North Slope area. However, it was uneconomic to recover these reserves at oil prices of $30 a barrel. Approximately one billion barrels of oil would be considered economically recoverable at oil prices of $40 a barrel. That number would increase at prices of $50 per barrel. Mr. Hanley communicated however that the effect of declining production rates were "missing from some of the analyses" which depicted higher tax rate take information. They were not included because they are difficult to model. The modelings instead utilized "a standard forecast" provided by the Department of Revenue. This was an important factor in regards to the price point at which Progressivity would be activated. While small fields or fields away from existing infrastructure might be thought to be economic at barrel prices ranging from $40 to $60, the higher tax rate imposed under the Progressivity component would negatively impact them. The industry in general does not support escalators; "we do play for the high side". However, were the inclusion of an escalator inevitable, the trigger point should be elevated beyond the point at which smaller fields would be considered economic. 9:28:07 AM Senator Bunde asked whether Anadarko had modeled production costs verses the barrel price for such fields, as affected by elevating barrel prices. 9:28:33 AM Mr. Hanley understood the question to be whether costs would be subject to inflationary influences as prices increased. 9:28:48 AM Senator Bunde clarified his question: how much more would it cost to access a field which, while not considered economic to develop at $40 a barrel, would be at $60. In other words would the profit margin for a field developable at $40 be the same as a field deemed accessible at $60. Mr. Hanley stated that were a field deemed uneconomic at $40, but economic at prices or $50 or $60, it must have "crossed certain thresholds" such as a minimal rate of return. As the price of oil increased, "the minimal economic field size on the North Slope decreases; the distance you can be from infrastructure and still have a project increases…." Senator Bunde asked how the profit margin of a project deemed economic at a $40 barrel price would compare to a field deemed economic at $60 per barrel. Mr. Hanley replied that the profit margin would "be higher at $60 than it was at $40". Senator Bunde asked whether that would be true in the case where that field had been deemed uneconomic to access at $40. Mr. Hanley understood the gist of the question to be whether development costs would also increase as prices increased. Senator Bunde affirmed. Mr. Hanley stated that some increase would be experienced. However, as prices increased "there tends to be more exploration around the world". For example, recent high oil prices resulted in increased competition for exploration rigs. This served to increase costs. Mr. Hanley hoped that a gas pipeline would be constructed on the North Slope. Regardless of whether or not oil prices continued upward, industry costs would increase because of a steel shortage resulting from the McKenzie gasline and Alaska pipeline demands. In addition to such things as increased drilling pipe costs, these two projects would also increase labor and material costs due to increased competition within the industry. Mr. Hanley suggested including a cost inflator of some type on whatever price was determined as the Progressivity trigger. To that point, "it would be easier to apply the tax escalator to the net" rather than to the $40 barrel price proposed in CSSB 305 because utilizing the standard Consumer Price Index (CPI) "would not necessarily reflect the cost in the oil industry". He reminded that, in the 1980s, while inflation increased, oil industry costs actually decreased due to such things as improved technology and a surplus in rigs resulting from lowered oil prices. In recent years, drilling expenses had increased approximately 50 percent even though the CPI had not. Mr. Hanley stated that basing "the escalator" on net profits would "have the proper impact". It would allow the industry to deduct its actual costs. Were costs to decrease, the money to the State would increase, and were costs to increase the tax payment to the State would diminish. 9:32:45 AM Mr. Hanley addressed the assumption that as prices increased, the industry would have more money and "could afford to pay a higher share". This would only be correct were costs to remain constant. The simplest way to address the cost element would be to apply the escalator to net profits. He was puzzled to the resistance this suggestion had encountered. Mr. Hanley identified another PPT issue as being whether to use WTI or Alaska North Slope (ANS) West Coast "as the marker". He opted against using WTI. Econ One had previously presented a history of the two. The value of WTI was historically two dollars more than ANS West Coast. However, that difference would increase as more heavy oil was processed: it would "be less reflective of the actual value of Alaska crude in the future potentially than it is today". Mr. Hanley suggested that the Committee consider utilizing "a wellhead approach" for the tax base. He was again puzzled as to the reason there was also concern in this regard. This approach would use the process determining "the gross value at point of production for the purposes of overall revenue". The first step would be to determine the production level in terms of oil in barrels per day. That figure would be used to determine the price. The point of production calculation was currently required from each developer. Costs would be deducted from this. That would provide the tax base for the PPT. Mr. Hanley could not understand why this calculation, which was "our actual revenues received, times our barrels produced" would not be preferred to "some hypothetical number that may or may not mimic what the actual costs are or inflation". Mr. Hanley stressed the point that calculating the wellhead value would be a required component of the PPT in any case. He suggested that the wellhead value be determined at each point of production, as differences would occur. Producers in Alpine were subject to extra costs since additional pipe was required to transport oil to TAPS. That was an actual cost to the producers. Utilizing WTI or ANS West Coast prices would not reflect such costs. Additional expenses would also be incurred by companies operating in NPR-A. "Using a standard methodology that says as the price goes up, you have the same impact discourages some of the exploration that might go on in the developments that are further out." Higher costs should be reflected. Mr. Hanley supported the suggestion offered by Chevron during their April 6, 2006 presentation to the Committee. That suggestion spoke "to how to evaluate a net profits approach with the escalators on the net, and how you use a criteria for where you start your escalator based on a per barrel basis." While it might be more difficult to "describe", it would not be difficult to implement. It would be based on the gross value at each point of production and the net on that. Mr. Hanley repeated his suggestion that Progressivity be triggered at a $55 wellhead North Slope price or $60 ANS West Coast price rather than the $40 price proposed in CSSB 305. This would allow the industry to access "some of the increased economics that are out there". 9:37:30 AM Co-Chair Wilken countered Mr. Hanley's position that Progressivity was incorporated into the bill based on the premise that as industry's profits increased, they could pay more. The State like Anadarko had shareholders. Thus, as increasing oil prices generated more revenue to the industry "through no effort of your own", the industry would benefit because its costs were not increasing "at a corresponding rate". In other words, its gross profits would be increasing more than its expenses. Therefore, the industry's shareholders should share that profit with the State's shareholders who had shared their oil resources with them. Co-Chair Wilken stated that SB 305 would maintain a constant State take rather than increasing State take as oil prices escalated. It was "entirely appropriate" for the Senate to incorporate a Progressivity element which would allow the State "to share with the producers that what amounts to an increase in revenue without a corresponding increase in costs." He doubted that this legislation would be adopted "without some sort of Progressivity factor". Co-Chair Wilken appreciated that Anadarko was in alignment with Chevron's position on the PPT, as he considered their suggestions on the bill to be worthy of consideration. 9:39:30 AM Mr. Hanley communicated that the intent of the industry was to provide constructive suggestions regarding the structure of the PPT and the Progressivity feature. A structure should be developed which would address the "legitimate concerns" of the industry. The discussion should consider the possibility that industry costs might increase faster than the price of oil. Having Progressivity based on net profits would address such concerns. Mr. Hanley acknowledged that industry costs would not immediately track with a rapid increase in oil prices. However, industry costs over time would increase. Since a $40 barrel price was included in the industry's economic modeling, basing the Progressivity trigger at that price would affect "how we view the economics of some of our future prospects". He urged the Committee to specify a Progressivity trigger at a higher price. 9:41:25 AM Mr. Hanley addressed Senator Bunde's question about the transition allowance which was also referred to as the "clawback" or "look back" provision. He noted that in December 2004 when oil prices were "fairly high", Anadarko make a "sanctioned decision" to begin work on two satellite areas in the Alpine field. The fact that Anadarko would pay "little or no severance tax on those two fields" under ELF was a factor in the decision to develop those two fields. However, when Governor Murkowski issued "his aggregation decision" in January 2005, those fields "were put on hold". Discussions ensued with the Administration, as Anadarko, which is currently paying a severance tax rate of approximately 13 percent at Alpine, was concerned about the effect that decision might have on those fields. The company decided to proceed with its plans as the Administration excluded those fields from being aggregated for their first six years of production. Anadarko invested millions in the development of those fields in 2005 and 2006. Now, the State was considering changing the tax structure. Mr. Hanley continued that under the conditions of the PPT, the severance tax on those two fields could increase from approximately zero percent for six years to 20 percent. Some expense deductions would be allowed. Nonetheless, the timing of the company's decision to invest in those fields "was terrible" in consideration of this bill. Had Anadarko known the bill was forthcoming, it would have delayed those projects "a year and a half because then the State would have picked up 40 percent of the costs of our development program and that would have offset, just like the other things, that increased tax". Mr. Hanley expressed that Anadarko's timing on these projects was considered the worst recent timing decision in the industry in respect to this bill. Exploration investments made on those projects would not qualify for any PPT credits or deductions and would be subjected to a high tax rate. In addition, no revenue from those projects would be received until production started in late in 2006. An "equity issue" could be argued in regards to investment decisions that were based on ELF. Even though changes are always inevitable, some allowance for these things could be provided going forward. Even though Anadarko preferred the provisions included in SB 305, the two-for-one look back provisions included in CSSB 305 would be acceptable. Mr. Hanley suggested however that the provisions be extended a year or more longer than the seven years specified in the bill, in order to provide a sufficient amount of time in which a company could feasibly recoup the clawback funds accumulated. 9:45:31 AM Mr. Hanley identified the point of production definition as another issue of concern in the PPT. The point of production provision in CSSB 305 mirrored that of SB 305: "the point of production for oil is at the place that pipeline quality crude enters" into the pipeline system. Production and development facilities upstream of that point would qualify for the credits and deductions in the bills. That was considered "appropriate" as the State would be assisting in the costs associated with developing and getting the resource to the pipeline. Once the oil entered the pipeline, a tariff deduction would be applied to determine a wellhead price. Mr. Hanley noted that PPT provisions pertaining to gas specified its point of production as being upstream of the treatment facility in which the gas was made pipeline quality. This was interesting to the industry. "Gas is generally less economic than oil." The level of the pipeline tariff currently being considered for the proposed gas pipeline was an amount equating to approximately 35 percent of the current $7.00 per million cubic feet (MCF) value of gas. The current TAPS tariff on oil was approximately $4.00 and the tariff on tankers was approximately $2.00 for west coast destinations. This would total approximately $6.00 or $7.00 or a tax of approximately ten percent tariff on oil selling at $65 per barrel. Gas would incur more transportation expenses than oil. This was opposite than he expected. Mr. Hanley noted that under the ELF tax regime, the tax on gas was ten percent as compared to a 12.5 or 15 percent tax on oil depending on the field. "It's strange that the facilities you need to develop your gas into pipeline quality, some of them are not qualifying for the credits and deductions." He concluded that there must be something relating to "the big gas treatment facility that is sitting out there as part of the big development" in the proposed gas contract that he was not privy to. One reason might be that the State did not desire to "pick up 40 percent of the cost of the big gas treatment facility". While that might be apropos for the North Slope, it does not consider other gas regions such as the gas foothills, the Nenana Basin, and Cook Inlet. "Frankly, if you're going to pay a higher tax rate, the whole concept is the State picks up part of the cost and you pay a higher tax rate. To leave out a big chunk of what it takes you to get that developed and not apply those credits, we think is problematic." Thus, he argued "that the point of production for gas should be the same as for oil. Whatever it takes to put pipeline quality gas into the pipeline should be the same as what it takes to put pipeline quality crude in the pipeline." He reiterated being unaware "of what's driving some of the other stuff, but I think as a policy call, we would argue that you're significantly going to hurt the economics by increasing that tax but not giving us all the benefits of some of the credits and deductions". Mr. Hanley identified the credit component of the PPT as the counterbalance of the taxes proposed in the PPT, particularly if the goal of the PPT was to encourage more investment and thereby reduce the slope of declining production in the State. SB 305 included provisions that created "better exploration economics" than ELF. 9:49:47 AM Mr. Hanley stated that the answer to the question of how paying a billion dollars more in taxes, as might occur under the PPT, could allow a company to improve their exploration economics was dependent on whether it was an existing field or new field. "Existing production is what's paying" the larger portion of the proposed tax increase. "The tax increase is hitting those, but they're not getting the benefit of the credits and deductions off the previous investments they've made". Conversely "new prospects" going forward would get those benefits. Thus, "to the extent that you increase the tax rate, if you want to keep the exploration economics the same, you need to do something with credits". 9:50:27 AM Mr. Hanley applauded the $73 million allowance provision included in SB 305. The Governor and Dr. van Meurs "correctly identified … the value of the $73 million to smaller and to new players" in the industry. The allowance would be particularly helpful to companies with existing production in Cook Inlet who under ELF, currently pay a minimal level of severance tax on oil. It would offset some of the tax increase they would experience under the proposed PPT. Companies such as Chevron and Anadarko attested to the benefit that allowance would provide. Anadarko considered the $73 million allowance more valuable to them than it would be to larger players in the industry. Omitting the $73 million allowance provision included in SB 305 would equate to increasing Anadarko's tax rate five percent. The impact on a larger company such as ConocoPhillips would be 0.5 percent. Mr. Hanley characterized the industry's positions regarding SB 305 as being "a tenuous truce" between the companies because, due to the economics of it, larger companies would "trade off the $73 million in a heartbeat for a one percent change in the tax rate". However that allowance would have a huge impact on new players and existing players with small levels of production, "particularly with fields that don't pay much". 9:52:34 AM Mr. Hanley stated that the 5,000 barrels per day exemption provision in CSSB 305 which replaced the $73 million allowance proposed in SB 305 would not benefit Anadarko, nor did he think it would benefit Chevron or Marathon Oil. The 5,000 barrels per day exemption "has very limited value." It would provide no benefit unless production was occurring. It would not benefit new players; particularly since it would terminate in seven years as it would take longer than that to bring a field to production. The inclusion of that exemption in CSSB 305 "has hurt the economics of a number" of players. The House committee substitute addressed this concern by providing companies the option of utilizing "some exploration credits that exist today". 9:53:55 AM Mr. Hanley advised that including a termination date on exploration credits would be acceptable provided the timeframe was sufficient. A five or seven year timeframe would be too short in which to use a development credit, particularly for a new player. Consideration should be given to the different "impacts of a development type incentive". The $73 million allowance included in SB 305 did not have a termination date. That is the reason it had "significant value". Mr. Hanley stated that the industry wide desire would be for a lower tax rate. "Increasing the tax rate decreases economics, and at some point, it actually makes exploration economics at higher prices worse than the current system." However, "at higher prices, some things become economic and there's a tradeoff there". Mr. Hanley communicated that Anadarko supported SB 305. CSSB 305 would apply "a higher tax rate, no $73 million allowance, an additional escalator starting at a pretty low price taking away even a higher tax in the range in which we're making decisions…" Anadarko was agreeable to the transition provisions in the bill, was concerned about the point of production for gas as that element would not be treated "as fairly" as oil. 9:55:33 AM Senator Dyson opined that the industry's remarks that the State would be "participating in exploration and development costs" were misleading. "What they're really saying is the State elects to defer income … through tax credits", rather than inferring that "the State is putting the people's money out on the table" for the industry "to explore with". By providing tax credits, the State would be "foregoing revenues" that it could have received. Mr. Hanley affirmed. Senator Dyson encouraged the industry not to "infer that the State is putting State money into exploration". 9:56:39 AM Senator Dyson understood that the capacity of the present Prudhoe Bay "gathering centers are somewhat limited on their capacity" to address the volume of water and gas being experienced. Consequently, the companies operating those facilities were disincentivized to provide smaller producers such as Anadarko access to those facilities. If this were the case, he asked what the State might do to encourage the major companies "to increase the through-put capacity at those bottlenecks so that smaller companies would not be disadvantaged". 9:57:27 AM Mr. Hanley specified that Anadarko had not experienced this issue as it typically did not explore satellites around existing infrastructure; Alpine being the exception. This was not an issue at Alpine because when oil entered the pipeline there it was pipeline quality crude. Anadarko sought out "larger fields that will have their own facility". 9:58:08 AM Co-Chair Wilken assumed chair of the hearing. 9:58:16 AM Co-Chair Wilken, referring to a production process flow chart [copy on file] which had been distributed in an earlier meeting by Dan Dickinson, Consultant to the Administration, asked Mr. Hanley to further his remarks requesting that the point of production for oil and gas be at the same point. Co-Chair Wilken understood that the point of production for both oil and gas would be after the treatment facility. Mr. Hanley, who did not have a copy of the flowchart, advised there was "a difference between treatment and processing according to the [unspecified] department". Co-Chair Wilken reviewed the production process for oil and gas as depicted on the chart. He understood they would be treated the same. 10:00:10 AM Mr. Hanley voiced the desire to review the flowchart, as he thought the point of production for gas would be "after the processing facility for gas but before the treatment facility". Co-Chair Wilken provided a copy of the flowchart to Mr. Hanley. Mr. Hanley expressed that Anadarko would analyze the chart and provide further clarification. 10:00:39 AM Co-Chair Wilken concluded that Anadarko would prefer that the point of production for oil and gas be uniform in regards to their relationship with the treatment facility. Mr. Hanley affirmed. Anadarko would be satisfied were the point of production for gas specified as the point at which it became pipeline quality. However, his understanding was that the point of production for gas would be "upstream of the treatment facility and downstream of the processing facility". "The definition of treatment is getting it to pipeline quality." This would be further clarified. He interpreted the flowchart provided by Co-Chair Wilken, to indicate that "after the central gas facility, this would be the processing, there would be another treatment facility before it gets to pipeline quality, and the point of production is in between the two". Co-Chair Wilken stated that the flowchart had been developed to assist the Committee in understanding this complicated issue. He would appreciate additional input from Mr. Hanley in this regard. Co-Chair Wilken addressed the contention that the State was "running out of oil". While several references had been made to 50 million barrel fields, the prospectivity of reserves in ANWR and NPR-A had been ignored. He understood the oil reserves in NPR-A could be the equivalent of Prudhoe Bay with ten billion barrels. Revenue projections at current prices could range from $400 to $800 billion. Consideration of this field should be included in the prospectivity conversation. Co-Chair Wilken stated that while little exploration had occurred in ANWR, it too might contain significant reserves. The Legislature should not be "led to believe" that we have "plucked all the low-hanging fruit" and must now seek out smaller fields. 10:04:15 AM Mr. Hanley suggested inviting USGS staff to testify in this regard. Their research would support the fact that while there was a significant amount of oil potential remaining in the State, "it is not in one field". Even though Anadarko was "more optimistic" than other companies about the resource potential in the State, it did not believe NPR-A held fields with quantities similar to Prudhoe Bay or Kuparuk; their view was that there might be the potential for a lot of oil in the State, but it would be in smaller fields such as Alpine. More exploration activity would be occurring were people to believe that a Kuparuk sized field existed in the State. 10:05:33 AM Co-Chair Green resumed chair. Mr. Hanley also communicated that even were a 1.5 billion barrel field discovered in a remote area of NPR-A, "it would probably not be economic. That is the challenge that we face…" Even 30 to 50 million barrel oil fields not within ten miles of existing infrastructure would be very expensive to develop in the State. In conclusion, Co-Chair Wilken was correct in that there was vast oil potential remaining in the State, however, there would not be another huge reserve like Prudhoe Bay. 10:07:08 AM Mr. Hanley addressed the issue of the proposed gasline. He contended "there's a lot of gas out there". Anadarko's research indicated there being numerous "Alpine size equivalent gas" fields. Thus, a boom in gas exploration would be expected with the onset of a gas pipeline. The field size potential was much larger for gas than it was for oil. This would be required since gas was "challenged". 10:07:55 AM Senator Stedman furthered Co-Chair Wilken's remarks. The State was "setting our tax structure" and selling its resources "under the expectation" of smaller fields. Large field discoveries "would change the dynamics" in terms of the global oil basins the State was being compared to. The discovery of another Prudhoe Bay would place "upward pressure on the government take" level since evidence would indicate that "the bigger the oil basin, the larger [government] percentage share". The current argument is that Alaska could not be compared to areas with large fields because "it has smaller pools of oil". Thus, while there was "a lower probability" the State might have larger basins, "it would have definitely been in the best interest of the State to know it before we set the selling price than after." Co-Chair Wilken agreed with Senator Stedman. The prospectivity issue might not be as negative as people had been "led to believe". Even the Legislative consultant, Econ One, limited their analyses to resource potential on the Central North Slope and did not consider fields east and west of it. "East or west is our future." 10:10:48 AM Mr. Hanley recognized this "good point". Additional viewpoints would be beneficial. After a few years of high production, most gas fields' production decline and level off with the exception being the gas fields in Qatar which continue to produce at high levels. Prospectivity factors should "absolutely" be considered and a higher government take on huge reserves would be expected. However, the proposed PPT tax structure was not "so far off" that the State would miss out on a significant amount of revenue from possible reserves; particularly in consideration of such things as the high cost of exploration in the State. Mr. Hanley disclosed that while the cost of drilling some wells in the GoM could mirror the cost of a well in NPR-A, a 50 million barrel field there could be developed and on line faster as wells in GoM were closer to infrastructure. The demands of developing a field in Alaska differed from those of a well in GoM. Mr. Hanley reiterated Anadarko's belief that prospectivity existed in Alaska. The economic assumptions prepared by Dr. van Meurs indicated that at a $30 barrel price, a company would garner a 25 percent rate of return on a 150 million barrel field. Were such a field in Anadarko's portfolio, it would "be developing it today". However, it should be noted that Dr. van Meurs' cost assumptions were to fields close to infrastructure. While Anadarko believed that such fields exist in Alaska, those fields were in remote locations and Anadarko would not develop them until infrastructure was closer to the field or prices significantly increased. Mr. Hanley expressed a "very positive attitude towards Alaska". People "are not trying to hide the ball by saying we think there's another Kuparuk out there, we're just waiting for the Legislature to pass a better tax structure to drill it". Under high price, large field scenarios, "the current [tax] system's better". Were such reserves known, people would be drilling them today. 10:14:07 AM Senator Dyson found it "striking" that neither Anadarko nor any other presenter had discussed any disincentives to investing in Alaska. No one mentioned the pending reserves tax on gas which would charge a tax on gas reserves under lease but not producing. Thus, he questioned why this issue had not been discussed; if it was considered to be a disincentive to the industry, what might the Legislature do to address it. 10:14:54 AM Mr. Hanley replied that Anadarko would prefer a "sweet approach" as opposed to a "the stick approach". However, the reserves gas tax issue was drafted in a manner that would not impact Anadarko. It would not impact new gas discoveries or certain existing gas discoveries. It would specifically impact three or four other companies. 10:15:52 AM Mr. Hanley concluded his remarks and thanked the Committee for the opportunity to discuss the legislation. He would be pleased to answer Committee questions at any time. AT EASE 10:16:19 AM / 10:20:10 AM PAT FOLEY, Manager, Alaska Exploration Group, Pioneer Natural Resources Alaska thanked the Committee for allowing him to speak to the PPT. He acknowledged Mr. Hanley as being "a wonderful articulate spokesman for Anadarko, for the independents in general, and for our industry". "Pioneer is closely aligned with Anadarko, specifically because of our niche that we find ourselves in. We're an explorer; we're a developer of some smaller resources…" Mr. Foley's reviewed a handout titled "Pioneer Natural Resources Alaska SB 305 PPT" dated April 7, 2006 (copy on file). Page 1 Pioneer's Alaska Acreage [This map displayed the company's holding in Alaska. Other than the Cosmopolitan Field in Cook Inlet, their fields were located in the vicinities of Alpine, Kuparuk, Prudhoe Bay or the NPR-A.] Oooguruk Discovery ƒPXD 70% WI (Op) ƒ58,000 acres Total Pioneer ƒ1.7 million acres NPRA Exploration ƒPXD 20% - 30% WI ƒ1.4 million acres Cosmopolitan Discovery ƒPXD 10 % WI - Option to a50 % ƒ25,000 acres in Cook Inlet Storms Area Exploration ƒPXD 50% WI (Op) ƒ153,000 acres ƒ1st well in 2006 Central North Slope Satellites ƒCronus - PXD 90% WI (Op) ƒAntigua - PXD 33% WI ƒ51,000 acres ƒ1 well on each in 2006 Mr. Foley noted that by financial standards, Pioneer, with a worth of approximately five billion dollars, would be viewed as a "smaller company". It was approximately one quarter the size of Anadarko. While it conducted business on a global scale, its operations were currently centralized in the United States. Mr. Foley noted that Pioneer began operating in Alaska in 2003. Areas of activity included Oooguruk, an offshore North Slope development project in which Pioneer held a 70 percent ownership with ENI Petroleum, an Italian oil company. ConocoPhillips was its equal exploration partner in the Storms area. Pioneer also had a 30 percent exploration interest in the Antigua field, a Central North Slope satellite field, which was operated by ConocoPhillips. Pioneer was also partnering with ConocoPhillips and Anadarko on exploration activities in NPR-A. Mr. Foley noted that Pioneer's total acreage in Alaska would equate to approximately 1.7 million gross acres netting to approximately 500,000 acres. Mr. Foley noted that the Cosmopolitan Discovery project near Anchor Point was Pioneer's only operation in Cook Inlet. The company had a ten percent interest, with an option to increase that interest to 50 percent and replace ConocoPhillips as the operator of that project. Page 2 Oooguruk Development Project Development Cost: $450 - 525 million Reserve Potential: 50 - 90 million bbls Peak Flow Rates: 15 - 20,000 bbls per day in 2010 Tie-in to ConocoPhillips Kuparuk River Facilities. Mr. Foley stated that production from this offshore project would be processed at facilities in the Kuparuk field and then transit via Kuparuk pipelines to TAPS. The company was proud of this project as only a five year time span would pass between the drilling of the first exploration well and the first barrel of oil being produced. "It is as accelerated a project as any on the North Slope." The resources in this field had been discovered but laid dormant for 20 years before Pioneer began drilling there; therefore, this marginal field lay undeveloped for approximately 25 years between discovery and production. Page 3 Oooguruk Major Project Construction Components · Winter 2006 o Gravel Mining o Gravel Placement - Drillsite & Onshore Pad · Winter 2007 o Flowline Installation o Facility & Equipment Installation · 2008-2011 o 38 Well Drilling Program Mr. Foley reviewed components of the three construction phases associated with the Oooguruk field. Page 4 Alaska's Challenges · Some of the Highest Costs in the World o Large Minimum Economic Field Size · Future Exploration & Development Potential: o Smaller Reservoirs o Remote Resources o Viscous Oil Resources o Gas · Long Cycle Times (5 to 10 years) · Investment Uncertainty o Exploration & Reservoir Risk o Price Risk o Fiscal Certainty Mr. Foley explained that when Pioneer began considering whether to operate in the State, it undertook what is referred to as a "new country entry". It examined the State's exploration potential, political environment, and fiscal environment as outlined on page 4. 10:26:58 AM Mr. Foley perceived the State's future exploration and development potential to differ than that of the past, as the determination was that "the super giant fields that opened the Slope no longer exist". Future opportunities would involve smaller fields, remote resources, viscous oil, and gas. Mr. Foley disclosed that small independent companies and investors were "shocked" that it could take a minimum of seven years for a field to go from discovery to first production in Alaska. "That's just not the business environment they are used to." Mr. Foley also noted that investment uncertainties relating to price risk and fiscal stability were issues a company would consider when weighing operations anywhere, and, to that point, the fiscal certainty of the State had historically been stable. The PPT legislation was proposed "literally the next day" after Pioneer decided to begin operations at Oooguruk. That caused the company "some concern". Page 5 Alaska Climate that Encouraged Pioneer · Emerging Business Opportunities o Investment Opportunities Offered by Majors o Cooperation re: Facility Access · Attractive Fiscal Policy o Reasonable Lease Terms & Availability o ELF Formula: Low Taxes on all by Largest Fields o Exploration Incentive Credits Mr. Foley communicated that Pioneer talked with the Administration as well as other producers in the State when it was considering whether to invest in Alaska. "There was definitely an open for business environment, both on behalf of government and on behalf of industry." Such things as lease bonuses, lease terms, and royalty rates were "relatively attractive when balanced" with the economic opportunity potential. Pioneer felt that the major companies operating in the State considered "it to be good business" to provide other companies access to their existing facilities. "We believed that the world was going to change, those facilities would no longer be held exclusively for their use, but instead they would invite others to process through them." Mr. Foley noted that Pioneer also determined it would pay a zero severance tax under the State's ELF formula unless it found "a super giant field". It was also "encouraged by the exploration incentive credits". To that point he noted that "Pioneer has enjoyed 40 percent exploration credits on at least two of its wells out in NPR-A". A well currently being drilled was expected to "enjoy a 20 percent exploration incentive credit". The exploration incentive credits "do have material impacts on an investor when they make a decision". Page 6 Alaska's Competitiveness · To Attract Most Independents, Alaska must effectively compete with onshore North America Resource Plays o Resource Plays (tight sands, coalbed methane, shales) are attracting huge amounts of capital ƒLower Risk ƒLower Cost ƒShorter Project Cycle Time ƒLower State Tax 10:30:34 AM Mr. Foley acknowledged the breadth of separate testimony regarding the competitiveness of Alaska to "super producing basins" in the world. While the worldwide arena was an important consideration, small independent companies placed great emphasis on how Alaska's resource development opportunities compared to opportunities in the contiguous United States and Canada. Huge investments were being made in tight sands, coalbed methane, and shale resource projects in those areas. Furthermore, those projects were found to have lower risk, lower cost, shorter development times, and lower state taxes than Alaska. The Committee must be "cautious" in designing the PPT as the State must be "competitive with the market that the investors you're trying to attract are currently involved" in. Page 7 Benefits of Administration's PPT Proposal · Balanced Tax/Credit Rate of 20/20 · Fair Principles o Tax Based Upon Profits o Compensation for Transition Capital · $73 MM Exemption Mitigates New Entrant Challenges · Tradable Credits allow Quick Monetization · Modest Incentives for Exploration, New Investors · Reduces Minimum Economic Field Size We believe the proposal would encourage new investment in Alaska, grow the resource pie and increase revenues to the State. Mr. Foley stated that when Pioneer first reviewed SB 305, "on general we found it to be fair and balanced" since "it was a tax based on profits". He reviewed the benefits companies would receive by such things as the $73 million allowance and the transition provisions, particularly as investments were made in the State under the auspice of an ELF "zero severance tax expectation". "If the laws are to change, it just seems it would be fair and reasonable for there to be some kind of a slow transition to allow people to recoup or recover from some of those investments." The $73 million dollar allowance would "mitigate many of the new challenges that a new entrant would face". The credits provided in SB 305 would be "very helpful, but would represent a "modest incentive for new exploration". 10:33:50 AM Page 8 PPT Tax Rate · 20% Rate Reasonably Balanced w/20% credit · If Rate is Higher it must be Balanced w/Equal Credits o Credit must apply to both Exploration & Development o Rate/Credit Balance is Affected by Price & Production · Higher Tax Rate: o Reduces Incentive to Invest · Raises Investment Threshold ƒFewer Exploration Wells Drilled ƒMarginal Resources Left Undeveloped Mr. Foley reiterated that the 20 percent tax "balanced with a 20 percent credit" as proposed in SB 305 would be "fair and reasonable and appropriate". Nonetheless, the company was "respectful of the fact that there seems to be pressure" to increase the tax rate. However, the Committee should note that any increase in tax percent should be "balanced with an increase amount of credits". The answer to the question of what would be an "appropriate relationship between the tax rate and the credit rate" would depend on "where you sit in the investment life cycle": the tax rate would be "less important and the credit rate is huge" to a company making its initial investment in the State; conversely, "the credit rate would be meaningless" to a company in a "harvest" rather than investment mode. The tax rate would be important to that company. Mr. Foley stated that a company like Pioneer would be "somewhere in the middle". A higher tax rate would be a disincentive to investment because it would increase the economic minimum field size that would "be required for an exploration target". Thus, fewer exploration wells would be drilled. More importantly, the tax rate would impact the decision" of whether a marginal field would be developed. Page 9 Tax Rate Progressivity ƒIncreasing Oil Prices Lead to Increasing Costs o 2005 W. Texas Drilling Costs Increased ~ 50% o Steel prices more than doubled in 2 years o Costs for all Services Escalating Rapidly ƒProfits not Directly Proportional to Oil Price Increase ƒIf Enacted, Progressive Tax Rate o Should be Profits Based ƒFairness Issue ƒDifferent basis is un-necessarily complex o Trigger Price Should Be: ƒAt a level equal to today's price environment ($60) ƒBased on ANS Posting (vs WTI) ƒIndexed for Inflation Mr. Foley conveyed that Pioneer would opt against including Progressivity in the PPT, even though its inclusion would seem "inevitable at this point". Thus, "caution" should be taken when designing that element. "As oil prices increase, the costs to the industry also increase". The relationship was difficult to explain but "it is a real phenomenon". Pioneer's cost to drill a development well in 2005 in Texas increased approximately 50 percent "in a single year. As an industry, we have seen the cost of steel more than double in the last two years, and the cost of all services seemed to be escalating rapidly". It was believed that by the time the proposed gas pipeline became reality, costs of operating in the State would have increased "substantially". 10:37:29 AM Senator Stedman encouraged testifiers to provide specific language suggestions or concepts regarding the Progressivity element. The goal of Progressivity would be to maintain the level of government/industry take as oil prices increased. The State should not be disadvantaged under those circumstances. Co-Chair Green specified that this issue was included in the list of questions being developed by the Committee. 10:39:05 AM Mr. Foley suggested a Progressive element based on profits rather than on gross revenue. It would also prefer a $60 ANS price to the $40 WTI trigger price included in CSSB 305, as that would best reflect today's price environment. Mr. Foley understood one of the arguments for the $40 trigger price was that that price "was beyond the realm of prices that companies use for their investment decisions". While the mechanics of how a company made its investment decisions was privileged information, he disclosed that Pioneer considered "several different price scenarios" when making its investment decisions. A low price would be in the $30 range, a medium price would be in the $40 range, and a high price might be in the $70 range. He discussed a variety of high price scenarios, including the consideration of financial futures markets, a company might include when making its investment decisions. 10:42:04 AM Senator Dyson appreciated Mr. Foley's "insightful" remarks. The thought had been that "it was all together reasonable for the people of Alaska to share a bit in the return off the depletion of their resources" when oil prices increased beyond the price point at which a company had based its decision to advance a project. Mr. Foley's comments, particularly those about the futures market, served to expand the field of things that could be considered when establishing a trigger point. 10:43:20 AM Mr. Foley clarified that the decision to advance a project might not be made based on the futures market, "but it is a component of the decision". Economic investment decisions were "not as simple as feeding information into an economic model" and getting an answer. All companies utilized a variety of scenarios, including "distribution of costs, distribution of outcomes, and various price test scenarios" in making their investment decisions. Some decisions were easier to make than others because the project might be "wildly optimistic". Often "these decisions are right on that ragged edge of being marginal". 10:44:10 AM Senator Dyson stated that regardless of "whatever the cut line price" was, "if the prices make that project even more profitable" for the company, "the people of the State" should be able "to share a bit in that good news for you". 10:44:55 AM Mr. Foley encouraged the Committee to base the trigger point "on something other than WTI". While he supported Mr. Hanley's suggestion of using a wellhead price as the Progressivity trigger point, there was concern that doing so would "introduce even another level of complexity simply because every field will have its own unique well head price". While it would be "a fair and reasonable" way to do it, "a barrel weighted wellhead price" would be required for each company. The next trigger point preference would be an ANS West Coast delivered price. Regardless of the price base used, it should be indexed for inflation. The issue of what index to use would be debatable, as oil prices and costs do not "track PPI" or CPI. 10:46:40 AM Page 10 5,000 BBL "Start-up" Exemption ƒNew Entrant Challenges o New Entrants do not hold Existing Infrastructure o Smaller Investors lack Operating Economics of Scale o Most New Investment Opportunities are Challenged ƒExemption Mitigates High Alaska Start-up Costs o Local, Highly Skilled Technical Employees Required o Requires Building an Expensive G&G Database o Companies w/AK Employees Pay Income Tax w/o Revenue ƒExemption Sunset is not Fair or Practical o Discovery to Production cycle time is 5-10 years ƒPhase out of Credit/Exemption is Discriminatory We believe "Start-up" Exemptions will bring in new investors and give them a better chance to succeed. Mr. Foley noted that the "start up exemption" proposed in SB 305 would have allowed a $73 million exemption. The House committee substitute changed that to specify a $12 million credit "which would be equivalent to a $60 million revenue exemption"; CSSB 305 changed it to a 5,000 barrel per day exemption or "barrel holiday". Mr. Foley reviewed the challenges new entrants to the Alaska resource development market would encounter under the provisions of the PPT. "Start up exemptions" would assist "in mitigating" challenges a new company would experience. As highlighted on page 10, a new company would be required to hire a "highly paid technical skilled" labor force and acquire expensive geological databases. A company should strive to hire people who live in the State. However, even though Pioneer had no producing fields at this point, and thus, no revenue, it was required to pay income taxes based on a portion of the company's worldwide income because it employed 26 people in the State. Rather than the company being rewarded for investing in the State, "there is a cost". A start up exemption would assist in mitigating some of the costs. Mr. Foley also noted that the 5,000 barrel per day exemption included in CSSB 305 would terminate at some point in the future. As mentioned by Mr. Hanley, this was of concern due to the long cycle time involved in bringing resources to production. "No new company would include this exemption in their economic analyses". The barrel exemption proposed in CSSB 305 would terminate at approximately the same time that Pioneer's Oooguruk field production was scheduled to begin. While the Legislature could revisit and extend the exemption provisions, the company was not confident that would occur. Senator Stedman stated that the issue of imposing State income taxes ion a company experiencing zero revenue in the State should be discussed with the Department of Revenue. 10:51:08 AM Mr. Foley stated that, being relatively new in the State, the company has only recently delved into this issue. In addition, it was challenging for a small company like Pioneer with only 26 employees in the State, to keep abreast of the multitude of changes occurring in the PPT bill. The "accounting" of the various provisions could be even more challenging when the company's production started. 10:51:48 AM Mr. Foley urged the Committee to eliminate the termination date relating to the transition exemption, regardless of whether it was a credit or barrel holiday. In addition, "it should be applied equally to each and every investor here in the State". Phasing the exemption out would be "somewhat discriminatory" as some companies would not be able to receive the transition benefits. Page 11 Fair value for Tradable Tax Credits · Tax Credit Value is Diminished to New Investor o Held Credits diminish through time value of $ o Sold Credits would likely sell at a discount o Discount Value captured by purchaser o Credit Cost to State remains 100% · "Refundable" Credits Increase Value to New Investor · Pioneer's Investments Will Generate Substantial Credits o Consider a State Cash Refund at Higher Oil Prices Mr. Foley pointed out that since it was a new investor in the State, Pioneer would be receiving "many tax credits" for the investments it made in the State. However, Pioneer's ability to utilize those credits would be delayed because it could not use them immediately like longer term companies could. Pioneer did not yet have "production, we're not paying a tax, we're not offsetting taxes". Mr. Foley stated that Pioneer could hold the credits "until a time" when they could use them "but their value would be diminished through the time value of money". Even though there would be a pool of buyers interested in buying the credits were Pioneer willing to sell them, it was anticipated that the purchase price would be discounted to a price less than the face value of the credits. Therefore, while the credit provision would cost Pioneer, the State would "realize the full loss of that credit", and the purchaser "would capitalize on the difference". Thus, Pioneer requested the State consider some kind of refundable credit program. For example, were Pioneer to generate $20 million in credits, it could request that the State pay them full face value for those credits. He noted that "Pioneer would be willing" to accept a modest discount. 10:53:38 AM Senator Bunde pointed out that the refundable program being suggested would be "highly unlikely" as there would be "political ramifications" were the State to "pay oil companies for coming here to make money". Mr. Foley was respectful of that. However, the Committee should be aware "that the value of those credits won't be fully enjoyed by the investor" were they intended to attract new investment. 10:54:25 AM Page 12 Transitional Capital Recovery · Fairness Issue o Investments were made under ELF System o Tax System is changing o Pioneer has recouped nothing from production · Pioneer's Alaskan Investment Began in 2003 · Pioneer's Cumulative Investment over $100MM · Transition Capital Look-Back is Appropriate · Look-Back w/2:1 Future Requirement is OK Mr. Foley stated that the transition capital provisions in the PPT would apply to both large and small resource companies. The $100 million investment Pioneer made over the last three years had been made under the "expectation of an ELF zero production tax for anything other than super giant fields". Changing that tax regime would impact Pioneer, which to date had not experienced "a single barrel of production". Therefore, it was "fair and appropriate for there to be an opportunity to recover transition capital". The inclusion of a two for one look-back would be acceptable to Pioneer. 10:55:10 AM Pioneer Key Messages · Pioneer Goal: Establish Alaska as Core Producing Area · Priorities for State of Alaska: o Provide Incentives to Convert Resources to Revenue o Attract New Investment ƒEffectively Complete w/North America Onshore · Administration's 20/20 Proposal is Balanced & Fair · Higher Tax Rates will Discourage Needed Investment · Progressivity, if Enacted, Should be Structured Fairly · "Start Up" Credits will Encourage New Entrants · Transition Capital Look-Back is Appropriate · New Concern: Impact of Facility Access Fees on PPT???? Mr. Foley summarized Pioneer's key concerns. Pioneer recognized a new concern: the PPT might impact facility access arrangements. To that point, he noted that Pioneer was currently involved in facility access negotiations with the Kuparuk River Unit. While he was "confident" that "fair and reasonable" terms would be reached, the concern remained. This issue could be revisited as further details became available. Mr. Foley concluded his remarks. 10:56:43 AM Co-Chair Wilken noted that approximately three months earlier, Pioneer had asked the Legislature Budget and Audit Committee (LB&A) to provide it some "royalty relief". That request was being considered. He asked that a copy of the presentation Pioneer gave to LB&A be provided to the Committee, as the work conducted by Pioneer in the State was "fascinating". The high cost associated with such things as project engineering was evident. Pioneer should be proud of its efforts. Mr. Foley stated that copies of that presentation would be provided to the Committee. Co-Chair Wilken referred back to the "PPT Tax Rate" information depicted on page 8 of Mr. Foley's presentation. That information helped him focus on the struggle he was having in regards to the 20/20 proposal in SB 305 and the 25/20 proposal with a two percent progressivity component triggered at a $40 price per barrel as proposed in CSSB 305. He understood that SB 305 would result in a government take equating to 58.2 percent. CSSB 305 would result in a government take equating to approximately 60.6 percent. That "240 basis point" difference might generate an additional $200 to $400 million in revenue to the State. While that would be a significant amount of money to the State, the question was how significant that amount would be to a producer receiving a six or seven billion dollar revenue stream. There was also the question of whether "the competition for capital is so great that a four percent increase in government take takes a project in Alaska and moves it down the list for investment". The testimony to date would attest that it would. His "struggle" was that he could not determine whether that additional $400 million in government take would cause investments to go elsewhere or not. Co-Chair Wilken stated that this "tipping point" dilemma was presented in the information on the "PPT Tax Rate" page. 11:00:27 AM Mr. Foley responded that it was difficult to pinpoint a response to Co-Chair Wilken's question. The industry would "like to be 100 percent aligned" in regards to the issue of the tax rate; however, "the reality is that the impact of the increased tax rate is far more punishing on those that are here, that have made their investments, that have a huge amount of production than they would be on a new investor". Mr. Foley clarified therefore that his response was limited to Pioneer's perspective of whether the 240 basis point increase would materially affect a company's investment decision. In addition, this issue was compounded by that fact that every project was unique. The increased tax might prevent some projects from going forward. The question for the State would be "how many of those projects do you want to have fall off". Mr. Foley stated that when studying Dr. van Meurs and other analysts' research on government take, he noted that they utilized "general industry wide matrix's where they say development costs on average are 30 to 35 percent", as no other option was available. However, this was immaterial to a small company like Pioneer. The projects it invested in were relatively small in size, costs were higher than larger players, and thus the profit percent for the company was less. The point was that the global industry take standard would be difficult to apply to any one company. Each project must "stand on its own". Dr. van Meurs often referred to a portfolio consisting of 500,000 barrel fields, a dozen 50 million barrel fields, and three 150 million barrel fields, all ranked at a 25 percent factor with certain costs applied; his conclusion was that "at higher prices, an investor would enjoy a 30 or 40 percent rate of return". Pioneer would be thrilled to have an opportunity to invest in a 500 million barrel opportunity with a 30 or 40 percent rate of return. Unfortunately Pioneer had nothing like that in its portfolio. 11:04:06 AM Mr. Foley referenced Co-Chair Wilken's question to Mr. Hanley about the prospectivity of NPR-A. Pioneer was Anadarko's exploration partner in NPR-A. Last winter ConocoPhillips, Anadarko, and Pioneer drilled two exploration wells there. While no drilling occurred there this year, drilling might occur in 2007. He could "assure" the Committee that were NPR-A to contain a field the size of Prudhoe Bay, rigorous drilling would have been occurring. Co-Chair Green thanked Pioneer and Anadarko for their presentations. The Committee would recess until approximately 12:30 PM in order to hear testimony from Jim Weeks with UltraStar Exploration LLC. RECESS 11:05:46 AM / 12:29:16 PM JAMES D WEEKS, Managing Member, UltraStar Exploration LLC, testified via teleconference from an offnet location. He shared that UltraStar, which was the smallest of the small independent explorers" in the State, was "in general support" of the remarks made by other industry members. He read his testimony [copy on file] as follows. …UltraStar Exploration LLC, a very small all Alaskan owned independent explorer, with strategically located leases on the North Slope. The Company was formed in 2002 by John Winther, Dale Lindsey and me, for the purpose of exploring and developing leases on the North Slope. UltraStar is 100% owned by Alaskans. I am Managing Member, and moved to Anchorage in 1984 with ARCO, and have had a presence here ever since. Dale, whom most of you know, was born and raised and still lives in Seward. John, whom most of you also know, was born in Fairbanks and raised in Juneau. He currently lives in Petersburg. Thanks for the invitation to testify on what I believe to be a very bad bill. During the last several weeks, I've listened to a lot of testimony on the Governor's original proposal, not only in this committee, but in the other committees in both houses of the legislature. I have witnessed an already complicated PPT proposal become so complicated that I sincerely doubt it can ever be fully and fairly administered, and the cost of such administration, for both the State and industry, will be huge. It will be even more overwhelming for small start-up guys like us, who don't have tax accountants and tax attorney on staff, and will need to acquire these services at market prices outside of our organizations. This bill is so bad that if it were the only alternative, we'd be better off with what's now on the books. But that's not the only alternative. The proposal by the Administration was complicated, but one we supported, and still could, but we can's support this one. Gross simplification is needed. Some taxes are to be applied to net profits, others to gross revenues. Sometimes ANS prices at the North Slope are to be used. Others times, ANS West Coast prices are to be used. This creates un-necessary complexity and opens the door to years of disputes and lawsuits. The Charter for Development may be a good example of how simple things can be made. I will now offer a few specific comments on the bill. You've heard lots of testimony supporting the 20-20 tax and exploration/development incentive split, and the arguments in favor of these provisions have been articulated very thoroughly and clearly, and I certainly cannot embellish on them, so I won't even try. I'll just add UltraStar's strong support for the positions of the existing producers and independents and explorers on these issues. Of more concern to me is the so called need for a progressive feature, where the State takes a higher percentage at higher oil prices. Wildcatters gamble for the upside. Upside reserves and upside prices. Taking away that upside will cause exploration investment to decrease. This smells to me like the federal windfall profits tax that so successfully drove industry from our shores in the early 1980s. There needs to be a mechanism for the State to buy back or otherwise allow use of any un-used exploration credits. The market for these credits is very limited, and I expect any that we may have would be sold at a considerable discount. It would help if the State provide an option to buy them, or allow holders of the credits to use them for other oil and gas related expenditures, such as bonus bids, lease payments, permitting and filing fees. The bill grants 5000 barrel per day exemption to companies with less than 55,000 barrels/day production. This is a provision with which we can agree, but I don't think it goes far enough. If the Committee wants every company, large and small, current producer, or wannabes like us, to be looking for new oil, then the 5000 barrels per day should apply to all new oil, regardless of the size of the company that drilled it. I suggest the following: When the PPT becomes effective, establish a "ring fence" around existing, producing units. If peripheral drilling outside that ring fence confirms commercial hydrocarbons and justifies unit expansions, the production from those expanded areas should be eligible for the tax exemptions and exploration and development credits in the bill, regardless of the size of the company that drilled them. Deeper and shallower accumulations, drilled within existing units after the effective date of the bill, should also be eligible. If the big, current producing unit owners were to receive the 5000 barrel per day allowance for exploration credits on new pools within an existing or expanded unit, it would provide a more meaningful incentive for all the industry. I question the need for a 7 year time limit after which the tax exemption will expire. UltraStar is a small, start-up company that is poking around the fringes of existing units and known reservoirs. Our leases are too small to stand alone, so access to existing facilities, owned mostly by the major producers, is the only way we can develop anything we might find. It took our sister company, Winstar, 6 years to negotiate access with the KRU to enable the drilling of the well they completed in 2003. UltraStar has been in negotiations wit the PBU for over 3 1/2 years now to get seismic data and facility access to enable the drilling of our Dewline Prospect. It takes a long time for these things to get done, and I question why our investments should be put at risk with this relative short sunset provision, whereas the major producers demand a 30 year period of assured fiscal certainty. Thanks for the opportunity to comment. 12:36:53 PM Co-Chair Green thanked Mr. Weeks for his testimony; particularly that he identified his particular areas of concern and offered suggestions to improve the bill. 12:37:22 PM Co-Chair Wilken asked Mr. Weeks to provide further information as to why it might take six years for a developer to get access to a facility through which his oil could be transported of an area like the Kuparuk River Unit (KRU) or the Prudhoe Bay Unit (PBU). 12:37:51 PM Mr. Weeks responded that in the case of KRU, the access issue was of less priority to facility owners who were concentrating on such things as company mergers. The fact that UltraStar was a small producer was another reason for the delay. "Facility owners will always make more money working on their stuff than working on our stuff." It was a matter of priorities rather than being an issue of "disingenuous effort or bad faith negotiations". Another issue in KRU was that "a precedent" was being set because UltraStar was "the first non-facility owner" to negotiate access there. Therefore, extra caution was exerted. While the "attitudes are good, it's just the nature of the beast". Mr. Weeks also noted that the concern about the capacity of a processing facility to handle production other than their own, as previously stated by Mark Hanley, was primarily related to a facility's ability to process gas and water. Another issue was how to "compensate a facility's owner" were they to defer their own production to allow a new player's production to be serviced. "It makes perfectly good sense to let us come in 'cause we have lower water cuts than they do, we have lower gas production, so you can get ten or 20 new …. oil barrels in for every barrel that gets deferred." He concluded, however, that this was an issue at every production facility on the North Slope. There being no further questions, Co-Chair Green thanked Mr. Weeks for his testimony. Co-Chair Green reminded Members about the list of questions and issues being collected for further discussion. Co-Chair Green ordered the bill HELD in Committee.