ALASKA STATE LEGISLATURE  HOUSE RESOURCES STANDING COMMITTEE  April 25, 2012 1:07 p.m. MEMBERS PRESENT Representative Eric Feige, Co-Chair Representative Paul Seaton, Co-Chair Representative Peggy Wilson, Vice Chair Representative Alan Dick Representative Neal Foster Representative Bob Herron Representative Cathy Engstrom Munoz Representative Berta Gardner Representative Scott Kawasaki MEMBERS ABSENT  All members present OTHER LEGISLATORS PRESENT Representative Mike Doogan Representative Neal Foster Representative Lance Pruitt Representative Kurt Olson Representative Dan Saddler Representative Pete Petersen Representative Chris Tuck Senator Albert Kookesh Senator Cathy Giessel COMMITTEE CALENDAR  HOUSE BILL NO. 3001 "An Act relating to adjustments to oil and gas production tax values based on a percentage of gross value at the point of production for oil and gas produced from leases or properties north of 68 degrees North latitude; relating to monthly installment payments of the oil and gas production tax; relating to the determinations of oil and gas production tax values; relating to oil and gas production tax credits including qualified capital credits for exploration, development, or production; making conforming amendments; and providing for an effective date." - HEARD & HELD PREVIOUS COMMITTEE ACTION  BILL: HB3001 SHORT TITLE: OIL AND GAS PRODUCTION TAX SPONSOR(s): RULES BY REQUEST OF THE GOVERNOR 04/18/12 (H) READ THE FIRST TIME - REFERRALS 04/18/12 (H) RES, FIN 04/20/12 (H) RES AT 1:00 PM HOUSE FINANCE 519 04/20/12 (H) Heard & Held 04/20/12 (H) MINUTE(RES) 04/21/12 (H) RES AT 10:00 AM HOUSE FINANCE 519 04/21/12 (H) Heard & Held 04/21/12 (H) MINUTE(RES) 04/21/12 (H) RES AT 2:00 PM HOUSE FINANCE 519 04/21/12 (H) Heard & Held 04/21/12 (H) MINUTE(RES) 04/23/12 (H) RES AT 9:00 AM HOUSE FINANCE 519 04/23/12 (H) Heard & Held 04/23/12 (H) MINUTE(RES) 04/23/12 (H) RES AT 1:00 PM HOUSE FINANCE 519 04/23/12 (H) Heard & Held 04/23/12 (H) MINUTE(RES) 04/24/12 (H) RES AT 9:00 AM HOUSE FINANCE 519 04/24/12 (H) Heard & Held 04/24/12 (H) MINUTE(RES) 04/24/12 (H) RES AT 1:00 PM HOUSE FINANCE 519 04/24/12 (H) Heard & Held 04/24/12 (H) MINUTE(RES) 04/25/12 (H) RES AT 9:00 AM HOUSE FINANCE 519 04/25/12 (H) Heard & Held 04/25/12 (H) RES AT 1:00 PM HOUSE FINANCE 519 WITNESS REGISTER SCOTT JEPSEN, Vice President External Affairs ConocoPhillips Alaska, Inc. Anchorage, Alaska POSITION STATEMENT: Provided ConocoPhillips Alaska, Inc.'s comments on HB 3001. DAN CLARK, Manager Strategy and Portfolio Management ConocoPhillips Alaska, Inc. Anchorage, Alaska POSITION STATEMENT: Provided ConocoPhillips Alaska, Inc.'s comments on HB 3001. DAMIAN BILBAO, Head of Finance Developments and Resources BP Anchorage, Alaska POSITION STATEMENT: Provided BP's comments on HB 3001. TODD ABBOTT, President Pioneer Natural Resources, Alaska Anchorage, Alaska POSITION STATEMENT: Provided Pioneer Natural Resources' comments on HB 3001. KARA MORIARTY, Executive Director Alaska Oil and Gas Association (AOGA) Anchorage, Alaska POSITION STATEMENT: Provided AOGA's comments on HB 3001. ACTION NARRATIVE 1:07:13 PM CO-CHAIR PAUL SEATON called the House Resources Standing Committee meeting to order at 1:07 p.m. Representatives P. Wilson, Dick, Foster, Herron, Feige, and Seaton were present at the call to order. Representatives Munoz, Gardner, and Kawasaki arrived as the meeting was in progress. In attendance from the House Special Committee on Energy were Representatives Foster, Olson, Pruitt, Saddler, Petersen, and Tuck. Also in attendance were Representative Doogan and Senators Giessel and Kookesh. HB3001-OIL AND GAS PRODUCTION TAX  1:08:08 PM CO-CHAIR SEATON announced that the only order of business would be invited testimony from the oil and gas industry regarding HOUSE BILL NO. 3001, "An Act relating to adjustments to oil and gas production tax values based on a percentage of gross value at the point of production for oil and gas produced from leases or properties north of 68 degrees North latitude; relating to monthly installment payments of the oil and gas production tax; relating to the determinations of oil and gas production tax values; relating to oil and gas production tax credits including qualified capital credits for exploration, development, or production; making conforming amendments; and providing for an effective date." ConocoPhillips Alaska, Inc.  1:09:15 PM CO-CHAIR SEATON invited ConocoPhillips Alaska, Inc. to provide its testimony. 1:10:17 PM SCOTT JEPSEN, Vice President, External Affairs, ConocoPhillips Alaska, Inc., reviewed an outline of the discussion that he and Mr. Clark intended to cover today, which included the latest financial performance of ConocoPhillips; the potential in Alaska, particularly in terms of the legacy fields; the existing fiscal framework; and ConocoPhillips' commitment to spend additional funds in Alaska if there are substantial changes to the fiscal framework in Alaska. 1:11:13 PM DAN CLARK, Manager, Strategy and Portfolio Management, ConocoPhillips Alaska, Inc., referring to slide 3 entitled "Latest Financial Performance", began by stating that although ConocoPhillips Alaska, Inc. ("ConocoPhillips") does make money in Alaska, there are significant benefits to the State of Alaska. For the first quarter of 2012 ConocoPhillips earned $616 million and paid $1.5 billion in taxes and royalties, of which about $1.2 billion went to the State of Alaska. On a daily basis, $13.1 million of taxes and estimated royalties and $16.5 million of total government take go to the state. He acknowledged that ConocoPhillips' first quarter earnings were $173 million higher than they were for the fourth quarter of 2011 and attributed it to the four tankers in the water between Valdez and the West Coast as of the end of December, which resulted in additional deliveries to the West Coast that were beyond ConocoPhillips' production. Although there have been several comparisons in regard to the earnings in Alaska as opposed to the Lower 48, he opined that such comparisons are difficult because the makeup of the production is very different. In fact, over half of ConocoPhillips' production in the Lower 48 is natural gas production. When one reviews the equivalent per barrel oil price for gas in the first quarter, it's around $15-$16 per barrel versus $100-plus for oil. Furthermore, when one considers ConocoPhillips' liquid production in the Lower 48, a good proportion of that is natural gas liquids. Those natural gas liquids are recovered from the natural gas production and are a lower value. 1:13:52 PM REPRESENTATIVE TUCK inquired as to how many tankers ConocoPhillips run per year. MR. CLARK said he didn't know, but offered to provide it to the committee. He then informed the committee that a tanker equates to about 900,000 barrels and with annual production of about 225,000-230,000 barrels a day one can sort of do the math. 1:14:24 PM MR. JEPSEN referred to slide 4 entitled "Production is Declining in Alaska", which is a chart that shows Lower 48 production and Alaska production. In terms of oil, the Lower 48 is going through a Renaissance and has been on a substantial incline since 2008 with production increasing by about 25 percent. Production has declined by about 15 percent during the same timeframe in Alaska. He attributed the increased production in the Lower 48 to use of fracking/horizontal drilling for shale gas, resource potential, and higher oil prices. In Alaska, the resource potential, price, and technology exist. However, the problem with Alaska is that under Alaska's Clear and Equitable Share (ACES) as oil prices change an investment in Alaska doesn't result in the same upside as in other places. Mr. Jepsen opined that the aforementioned is the deciding factor with regard to what's holding Alaska back because the ingredients for a substantial increase in investment in Alaska are present and would have a substantial positive impact on the production from the North Slope. Moving on to slide 5 entitled "Legacy Fields are Key to Future Production", he highlighted that the legacy fields accounted for about 90 percent of North Slope production in 2011. Furthermore, future production on the North Slope is by far the largest resource [in the state]. Mr. Jepsen informed the committee that the data on slide 5 is from the 2009 Department of Revenue (DOR) report that reviewed production for the years 2010-2050. This report is used because it was the last year in which the data is parsed in such detail. The data represents future cumulative production during 2010- 2050. The combined production of Point Thomson, Nikaitchuq, Liberty, and Oooguruk don't compare to the opportunities in the legacy fields. He highlighted that the cumulative production isn't riding the base decline into the ground, it's going to require tens of billions of dollars to achieve it. Whether that production is achieved over the next 30 years is a function of whether Alaska can attract the capital investment necessary to make the investments. MR. JEPSEN continued on to slide 6 entitled "Opportunities within Legacy Fields" and noted that ConocoPhillips drills designer wells. Coil tubing drilling units are used to drill a sidetrack from an existing well. The sidetrack can be from 500- 3,500 feet long horizontal into targeted sands as thin as 10 feet. Therefore, ConocoPhillips is developing a field within a field. For instance, in the Kuparuk River Unit there are isolated fault blocks that are targeted with these designer wells. This new horizontal drilling and targeting technology allows production in these isolated fault lines. This technology, he opined, has been extremely leveraging for the development of Prudhoe Bay and Kuparuk River Units and will continue to be a development opportunity in the future. This technology is also being used to drill into thin sands. When considering the entire opportunity suite, ConocoPhillips believes there could be more rigs drilling in Alaska if there was the appropriate fiscal framework to make the case that Alaska is as attractive for investment as other locations. ConocoPhillips is spending more capital in the Lower 48 because it doesn't see the upside for investments in Alaska. However, he emphasized that he didn't want to leave the committee with the impression that ConocoPhillips isn't drilling or pursuing opportunities in Alaska as it spends about $900 million a year in Alaska, which is ConocoPhillips' net shares for Alpine, Prudhoe Bay, and Kuparuk units. Furthermore, ConocoPhillips is drilling wells, shooting seismic, and pursuing facility expansions where they make sense. Again, with a different fiscal framework, he opined that there could be more investment in Alaska. He then addressed viscous oil and stated that the viscous and heavy oil reservoirs on the North Slope are an immense resource. ConocoPhillips, its predecessor ARCO, and BP have spent the last 30-plus years trying to find technologies to make viscous and heavy oil commercial. In fact, he recalled that his first job in Alaska in 1982 was to find a way to make West Sak and Ugnu commercial. However, after enough data was collected, it was determined that the heavy oil doesn't float and thus the focus turned to the viscous oil in West Sak. In the intervening years, technological advancements have been made. The best part of West Sak and Kuparuk is on stream and producing about 14,000 barrels a day. Mr. Jepsen related that although there have been problems, a lot has been learned. For example, there was massive water breakthrough for which technology was developed and is being tried on a well-by-well basis. Furthermore, progress is being made in regard to the problems with drilling the wells, pumps, and sand. ConocoPhillips' current plan is to expand its West Sak production from the core area to the Eastern North East West Sak. Although it's an area that doesn't have quite as good oil, ConocoPhillips believes it can be produced with the technology that's available today. However, it's a high risk and technologically challenging area. He noted that the extent and pace at which ConocoPhillips pursues that opportunity depends upon being able to make the case that capital investment in Alaska is as attractive as other opportunities as other places in the world and the Lower 48. In the price world of today with the technology that has been developed, ConocoPhillips is opportunity rich that is ConocoPhillips doesn't have enough capital to pursue every opportunity around the world. Therefore, the company has to consider those places where one would get the best return on the investment. Alaska could do a lot to improve its position, he reiterated. Mr. Jepsen told the committee that exploration and satellite opportunities are still available, particularly in the Alpine and Kuparuk River Units. As some may know, ConocoPhillips has been active in lease sales recently and the hope is that there will be sufficient change in Alaska's fiscal framework so that more investment will be attracted and ConocoPhillips can pursue some of those exploration opportunities. He noted that ConocoPhillips is advancing and pursuing engineering on some of the opportunities in the legacy fields. However, ConocoPhillips won't make the long lead time, highly capital intensive investment necessary to pursue those until the case can be made that these investments are the best place for ConocoPhillips to invest its money. ConocoPhillips will continue to seek additional opportunities [in Alaska], he said. MR. JEPSEN then turned to heavy oil technologies. The heavy oil is more viscous, and thus thicker and heavier than what is in West Sak. Much of this heavy oil is located in very cold parts of the reservoir and some of the heavy oil just doesn't flow. Therefore, heavy oil is challenging, particularly in addition to the environmental constraints in Alaska that require development from central locations. Although ConocoPhillips has been reviewing ways to produce this heavy oil resource for over 30 years, the commercial technology that would allow production of this heavy oil doesn't exist yet. Therefore, he cautioned tax changes that target heavy oil because the technology to address heavy oil doesn't exist yet and placing an emphasis on it won't bring that oil to market. Furthermore, he opined that long term this isn't the prolific reservoir similar to Prudhoe Bay and Kuparuk River Units. The rate of the heavy oil will be a small percentage of what has been experienced with the light oil reservoirs. Still, heavy oil is a large resource that ConocoPhillips will pursue, but the focus will be on the locations where results with significant impact to Alaska and North Slope production can be achieved. 1:28:04 PM MR. CLARK then directed attention to slide 7 entitled "ACES - High Average Government Take" which presents a chart from PFC Energy that compares worldwide fiscal regimes at $100 per barrel. He noted that for those areas with private royalties, the private royalties are included in the government take numbers. He highlighted that the red bars on the chart represent ACES, while the gold bars represent other countries included in the Organization for Economic Cooperation and Development (OECD). Relative to the other OECD countries, ACES at $100 per barrel is a high government take, he pointed out. He further pointed out that at $140 per barrel, the red bars representing existing and new development in Alaska under ACES would move up and there would be higher government takes. Basically, the bar representing the existing producer in Alaska would move above Norway and the bar representing the new development in Alaska would move up above Trinidad. The aforementioned highlights the effect of the progressivity mechanism within ACES. 1:29:48 PM REPRESENTATIVE PETERSEN asked if the chart on slide 7 takes into account the tax credits offered in Alaska. MR. CLARK replied yes. 1:30:05 PM REPRESENTATIVE HERRON inquired as to the location of the red bars representing Alaska under ACES if HB 3001 were implemented. MR. CLARK said he hasn't seen such a chart from PFC Energy. However, he opined that the fiscal outcome of the implementation of HB 3001 would be similar to that of HB 110. REPRESENTATIVE HERRON asked whether ConocoPhillips has done any modeling on [the fiscal results of the implementation of HB 3001]. MR. CLARK answered that he would provide analysis during his presentation. 1:31:00 PM MR. CLARK, referring to the chart on slide 8, reminded the committee that progressivity is a situation in which as oil price or margin increases the state/government take increases. He explained that the chart on slide 8 relates the percent share of the industry, the federal government, and the state. This chart, he clarified, represents a marginal take rate. Therefore, it measures the take by a party as the price of oil increases. For example, if the price of oil rises from $110 per barrel to $111 per barrel, the total government take of that incremental dollar would be over 86 percent under ACES while the industry share would be about 13.5 percent of that. Mr. Clark then highlighted that progressivity has been impactful from $70- $125 price range and takes a larger and larger share of each incremental dollar. He pointed out that the chart on slide 8 is based on Fall 2011 Revenue Source Book data for fiscal year 2013. 1:33:03 PM CO-CHAIR SEATON pointed out that the chart specifies the prices are based on Alaska North Slope (ANS) West Coast oil prices although the percentages are based on production tax value, which subtracts all costs. Therefore, he surmised that it would be company specific such that the chart relates an average. MR. CLARK replied yes, adding that since the chart is based on Revenue Source Book data it's an amalgamation of the industry. For this fiscal year, the price [of ANS West Coast oil] is about $32 per barrel of oil. MR. JEPSEN clarified that the chart is relating the incremental dollar after all the costs and tax credits have been subtracted. Therefore, it's the marginal share of the profit. Once a $110 per barrel is earned, for the next dollar earned after $110 there are no more costs, tax credits, or capital costs to be subtracted from that dollar. Therefore, a pure $1 goes to the company and of that next dollar, at $110 per barrel, the state and federal government will take about $0.86. CO-CHAIR SEATON said members are familiar with effective tax rates on the overall barrel price sale versus the marginal that merely looks at an incremental price difference between one barrel and another. Although the numbers used on the chart on slide 8 may be from the Fall 2011 Revenue Source Book, he surmised that they're company specific in terms of the production tax value and that's from where incremental value comes. MR. CLARK offered that this slide could've utilized the production tax value margin (PTV), which would mean that $32 would be subtracted from each of the price points to obtain the margin. 1:35:27 PM REPRESENTATIVE SADDLER asked if this chart refers to the marginal share of the entire barrel of oil, not the profit. MR. CLARK said that the basic presumption is that the incremental dollar is all profit and nothing else is changing. For further clarification, Mr. Clark specified that both profit and the incremental price per barrel are the same. 1:36:03 PM REPRESENTATIVE TUCK asked whether the chart assumes the particular company isn't taking advantage of the tax credit as it lowers the tax rate on progressivity in addition to what the company can subtract for the credit. MR. CLARK explained that the tax works as follows: the West Coast revenue is calculated, transportation costs are subtracted as are all the qualified operating and capital expenses to reach a PTV, which is where the tax is calculated. Furthermore, for qualified capital expenditures there is tax credit, depending upon the type of expenditure. Once the tax is calculated, [the qualified capital expenditures] can be deducted. He further explained that in this particular analysis, when the price increases by $1, there is no change in credits, investment, or costs. Therefore, there's no particular impact on this marginal share take in that scenario. REPRESENTATIVE TUCK surmised then that in relation to this chart, it's irrelevant whether a company took advantage of the tax credits. MR. CLARK clarified that at an oil price of $110, the tax credits would've already been taken advantage of because there is no change in cost when going from $110 to $111 per barrel of oil. In further response to Representative Tuck, Mr. Clark confirmed that whether a company takes full or partial advantage of the tax credits, the chart remains the same. 1:37:58 PM MR. CLARK, returning to the presentation, directed attention to the chart on slide 9, which further illustrates the impact of progressivity. This chart uses dollar per barrel in order to take out the effects of changes in production. He highlighted that the green line representing ConocoPhillips' net income stays in a fairly tight range of plus or minus $20 per barrel, regardless of oil prices. Therefore, it illustrates that the upside isn't with the investor, ConocoPhillips. However, the state's share, represented by the red line, tracks fairly closely with oil price and thus when the oil price is up, the upside/share goes to the state. Moving on to slide 10 entitled "HB 3001 Provides More Equitable Split", he explained that the graphic illustrates the split of a barrel of oil in terms of costs, industry share, federal income tax, and Alaska's share at three different prices. Under ACES, when the price of oil rises from $100 to $150 per barrel the industry share increases from $20 per barrel to $28 per barrel, whereas the Alaska share increases from $37 to $75 per barrel. Again, that's the impact of progressivity in which the state takes the predominant share of the upside. In comparison, the graphic illustrates that under HB 3001 when oil is $100 per barrel the industry share increases from $23 to $36 per barrel while for the state the increase is from $32 per barrel to $62 per barrel. Although under HB 3001 the predominant portion of the upside still goes to the state, ConocoPhillips believes HB 3001 offers a more equitable split between the state and the industry. 1:41:46 PM REPRESENTATIVE GARDNER recalled that one of the goals of ACES is to encourage investment of [the investor's] profits thereby the tax rate is reduced on every dollar earned. She asked: Does that do that at all in your first, say, $100 barrel oil under ACES you have $37, the state's got $32. If you take ... $7 of those $37 invest in Alaska, the state picks up however much in the credits so of the $7 you invest it's roughly what would it be that we pay for and then it takes your total tax percentage rate down all the way, right? MR. CLARK reminded the committee that the deductions for ACES for capital and operating expenses are generous and all can be taken in the first year. That and the credits are available because the tax rates are so high. While this reflects a similar level of investment, if a company increases its investment it would reduce their tax rate. However, the company would have to operate under the presumption that it's investing in something that will generate a return. REPRESENTATIVE GARDNER emphasized, "That's the whole point." She opined that it provides an extra reason to invest and the expectation is that a company would invest in something that generates return, whether it's under ACES or HB 3001. MR. JEPSEN explained that tax credits lower the tax bill, but don't change the tax rate. The tax credits are applied after the tax is calculated. Mr. Jepsen related his understanding that Representative Gardner is referring to the effective tax rate in which the tax paid is divided by taxable revenue, which will change as a function of tax credits. However, the statutory tax rate doesn't change and the marginal tax rate is quite high. REPRESENTATIVE GARDNER related her understanding that the point of progressivity is based, in part, on the level of profit. If the company's profit is less, then the progressivity decreases. MR. JEPSEN specified that as the PTV decreases so does the progressivity. Under ACES, the base rate is 25 percent until the minimum is reached. Mr. Jepsen opined that the aforementioned makes Alaska a good place for investment. If there was ACES, with no progressivity, there would be more investment in Alaska, he further opined. 1:45:10 PM CO-CHAIR SEATON recalled the statement that the credits and instantaneous deductibility need to be high because the tax rate is high. In order to balance the aforementioned, does the credit and instantaneous deductibility need to be lowered so the two balance, he asked. MR. JEPSEN answered that the committee should review that and determine the appropriate balance between tax rates and tax credits. He reminded the committee that ConocoPhillips reviews the total government share and the industry share and whether it's sufficient to attract incremental capital. 1:46:15 PM REPRESENTATIVE GARDNER clarified that she meant that spending lowers a company's tax rate and asked if that's correct. MR. JEPSEN replied that is correct. 1:46:33 PM REPRESENTATIVE HERRON referred to the historical data on slide 9 and asked if HB 3001 passed, would ConocoPhillips' net income and the state's share remain the same [as it does under ACES]. MR. CLARK said that although he hasn't done that specific calculation, the line representing ConocoPhillips' net income and the state's share would move closer together and track similarly. 1:47:22 PM REPRESENTATIVE MUNOZ inquired as to how the return on capital in Alaska compares to that of the Lower 48. MR. CLARK, reviewing 2011 numbers for ConocoPhillips, related that in Alaska the cash margin was about $31 per barrel, while plays such as the Eagle Ford and the Bakken in the Lower 48 have significantly higher cash margins, closer to $50 per barrel. Although the earnings are less in the Lower 48, when one reviews specific oil plays there are much higher returns and that's what attracts the capital in ConocoPhillips. 1:48:41 PM CO-CHAIR SEATON requested an explanation of adding depreciation back in and how that influences the fact that Alaska has no depreciation because Alaska allows the capital to be written off in the first year. MR. JEPSEN specified that Co-Chair Seaton is referring to net income according to generally accepted accounting principles (GAAP) rules. The deductibility under ACES affects ConocoPhillips' tax rate, but doesn't impact the company's federal depreciation. Therefore, it's basically an after tax calculation that takes into consideration state and federal taxes. While ConocoPhillips is able to deduct operating and capital costs from revenue in order to determine the tax rate in Alaska, it's not the same as the depreciation for the federal tax return. Basically, it's the units of production, depletion of ConocoPhillips' capital invested over the North Slope. He said that it's a number that stays relatively constant over time. [Depreciation] is added back in because it reaches a [more accurate] cash position after tax than if it's subtracted. Mr. Jepsen said that's how the accountants require ConocoPhillips account for income as a large corporation. In further response to Co-Chair Seaton, Mr. Jepsen agreed to provide further information on the aforementioned calculation. 1:50:35 PM MR. JEPSEN, continuing on to slide 11 entitled "ConocoPhillips Capital Expenditures", directed attention to the chart that relates ConocoPhillips' capital investment profile in Alaska versus the Lower 48. As the chart indicates ConocoPhillips' investment in Alaska is fairly flat, which he attributed to the lack of returns in Alaska versus what is available in other places. The capital is going to places in the Lower 48 such as the Bakken, Eagle Ford, and Permian Basin. He noted that many of these locations are very mature basins. For instance, Permian Basin has been abandoned four to five times over the course of its history and reopened due to a technological or price breakthrough. Currently, Permian Basin is being reopened due to technological and price breakthroughs. Mr. Jepsen related his belief that there is a similar opportunity set in Alaska, and to some extent it's not realized how good it could be because Alaska doesn't have the same profit environment that oil companies experience in the Lower 48. MR. JEPSEN concluded with slide 12 that is a letter to all Alaskans from ConocoPhillips. He acknowledged that there is concern with regard to how the state can be certain that oil companies will invest more money and produce the results expected by the state enacting a tax change. However, by the nature of corporations and the size of investments required, it's difficult to sign a contract and move through the steps to the commitment desired. He partially attributed the aforementioned to the fact that a lot of these projects aren't at the point of going to the board of directors for approval. This letter attempts to place a lot of ConocoPhillips' credibility on the table by saying that if it observes changes in Alaska's fiscal system similar to those proposed in HB 110, ConocoPhillips will pursue more drilling activities in the North Slope, more satellite development and more exploration opportunities, and work with partners at Prudhoe Bay. He opined that the most underappreciated is that the $5 billion associated with the aforementioned opportunities is the tip of the iceberg and not the entire opportunity suite. Drawing from his years in the business, Mr. Jepsen emphasized that ConocoPhillips doesn't know today what it will be doing 20 years from now. The oil industry isn't that predictable, particularly since advances in technology continuously create new opportunities. For instance, in 1982 ConocoPhillips thought it would be done with Prudhoe Bay and Kuparuk River Unit by now. In fact, it was thought that the Trans-Alaska Pipeline System (TAPS) would be shut down by now. However, the situation is far from the aforementioned. Mr. Jepsen closed by relating that if Alaska implements a fiscal framework that allows investors to invest in the best opportunities, it will result in the best situation for the oil companies as well as the state. Such a change in the fiscal framework will result in more production, investment in [opportunities] with the nearest-term impact and the most profitability. Oil companies are resource focused, and thus they will continue to focus on heavy oil; there is no need for special legislation or tax breaks to incentivize the oil companies to invest. Oil companies have been doing so for 30 years, without the tax focus. Rather, he emphasized that oil companies need a tax regime that makes Alaska welcoming in terms of investing money and applies across the board. In parting, Mr. Jepsen related that the legacy fields hold the key to Alaska's future. Although the North Slope Basin has such potential, the fiscal framework in Alaska poses a challenge. 1:56:15 PM CO-CHAIR SEATON highlighted charts from the Alaska Oil and Gas Conservation Commission (AOGCC) regarding the number of wells drilled by ConocoPhillips, which doesn't seem to have any relationship to the price or the tax regime. Therefore, he questioned why the legislature should anticipate that a change in the fiscal framework would result in a change in the number of wells per year that ConocoPhillips drills. MR. JEPSEN informed the committee that from 1996 to now there has been a significant difference in the type of wells drilled. In the past, ConocoPhillips drilled rotary wells with a big hole and a single bore, whereas now they might enter 15 well bores and drill three to six horizontal wells from that individual well bore. Therefore, the wells ConocoPhillips drills today are more cost effective wells. The difference between 1996 and today is the type of well drilled and how they are counted. ConocoPhillips is not drilling 66 new holes in the ground from the surface down every year, rather the total number of wells includes the well bores being drilled from existing wells. From 1996 until a few years ago, there was a relatively stable oil price environment. Although the price of oil has increased dramatically since 2007/2008, the response that has been experienced elsewhere hasn't occurred in Alaska. He attributed the aforementioned to the fact that Alaska doesn't have the same overall economic impact of other locations. 1:59:02 PM REPRESENTATIVE SADDLER surmised then that in 1996 ConocoPhillips drilled 60 wells and now it's drilling multiple well bores from those 60 wells. Therefore, it's 60 times a factor of three to five. MR. JEPSEN replied no, and clarified that ConocoPhillips might have 10-15 existing well bores from which multi-laterals are drilled. In further response, Mr. Jepsen said that he would need to review the AOGCC data set before answering further because there are many ways in which to define wells. REPRESENTATIVE SADDLER then asked if more drilling is occurring now. MR. JEPSEN answered no, but confirmed that more well bores are being drilled from existing wells. Again, he expressed the need to review the AOGCC data. 2:01:05 PM REPRESENTATIVE P. WILSON inquired as to how long after a new tax regime is in place would the state see an increase in revenues because of an increase in production. MR. JEPSEN explained that when ConocoPhillips increases its capital investment one would likely observe more jobs, businesses, and a boost in the local economy across the state. However, he cautioned that it takes time to get a drilling rig to the North Slope. In fact, if a rig has to be built it could possibly take two to three years, whereas refurbishing a drilling rig from the Lower 48 might only take a year. If there is the need for a substantial capital investment in a new facility, it could take five to eight years before full production. Therefore, the timeframe depends upon how complicated the project. Mr. Jepsen confirmed that there won't be an instantaneous response in terms of production as a result of incremental capital investment, although there will be a response in the local economy. He told the committee that ConocoPhillips makes it a point to hire as many Alaskans as it can. REPRESENTATIVE P. WILSON asked if ConocoPhillips could provide any idea how long it would take to make the pipeline fuller than it is now. MR. JEPSEN said that ConocoPhillips shares that goal of making the pipeline fuller. However, how long it will take to flatten and potentially reverse the decline will be a function of the type of fiscal framework the state implements. In his opinion, ACES doesn't work and is broken from the standpoint of attracting additional investment in places where necessary. Mr. Jepsen opined that the response from the producers will be proportional to the change in the fiscal framework. 2:04:37 PM REPRESENTATIVE PETERSEN requested an explanation of ConocoPhillips reported 11,000 barrel per day increase in production. MR. CLARK reminded the committee that there was a shutdown on TAPS for over a week, which was related to a leak. The aforementioned was a significant impact to production, and thus ConocoPhillips production last year was understated because of the shutdown. REPRESENTATIVE PETERSEN, referring to slide 11, pointed out that the chart illustrates that the investment increases in the Lower 48 while remaining steady in Alaska. He asked whether ConocoPhillips is drilling in the North Dakota area where he recalled there is shale oil that requires drilling more often to ensure constant production. In such a situation Representative Petersen surmised that ConocoPhillips would need to invest more in order to maintain production as compared to traditional oil wells such as those on the North Slope. MR. JEPSEN acknowledged that shale wells typically have steep declines. If the goal is to maintain a flat or an increasing production profile, one must drill at a fairly steady pace in order to build upon past results. Therefore, Representative Petersen's conclusion is fairly accurate. However, he noted that on the North Slope the base decline in the existing fields is about 15 percent and when horizontal wells are drilled there are fairly steep declines after initial production as well. 2:07:07 PM CO-CHAIR FEIGE remarked that the committee is reviewing all the factors that go into investment decisions that companies make in order to determine what the legislature can do with the state's tax regime to encourage more production on the North Slope. He then asked if the committee is going down the right path of analysis. MR. JEPSEN answered that it's appropriate for the committee tp pursue the issues it believes necessary to better understand where ACES ranks in comparison to other opportunities around the world while trying to understand what's important to the companies. The aforementioned is why ConocoPhillips wanted to provide its insights to the committee in terms of how it makes decisions with regard to where to invest capital. Mr. Jepsen emphasized that ConocoPhillips isn't a single variable decision- making company that is ConocoPhillips doesn't just review present worth and rate of returns of a given project and invest. ConocoPhillips considers political stability, size of the resource, and long-term cash flow that might be generated from that investment. In Alaska, when a company invests it receives the capital and the tax credit, but once production begins the [well] is part of the base and subject to the high tax rates of ACES. Mr. Jepsen said that the long-term cash flow opportunities in Alaska don't match up with other opportunities that ConocoPhillips has. To the extent the committee can understand and focus on the aforementioned, it would be helpful in understanding what it will take to change the investment climate in Alaska, he opined. 2:09:44 PM CO-CHAIR SEATON related his understanding that Alaska represents about 58 percent of ConocoPhillips' liquid production in North America and 63-65 percent of ConocoPhillips' profits. He asked how Alaska would balance that in terms of cash flow when the reports that the cash flow per production from Alaska is higher than that of the other investments ConocoPhillips makes. MR. JEPSEN explained that when one reviews the data in terms of liquids to liquids, Alaska isn't higher than the Lower 48 and the places where ConocoPhillips is investing its money today. Statistics that indicate Alaska is better include natural gas production and natural gas liquids. There is a substantial portion of ConocoPhillips business in the Lower 48 that account for a lot of ConocoPhillips' production. Therefore, when all those things are rolled together on an amalgamated basis for the Lower 48, it amounts to a net income or cash margin per barrel that's less than Alaska. However, if the low value portions that ConocoPhillips isn't investing in any more are stripped out and only ConocoPhillips' liquid plays are considered, it's an entirely different story. 2:12:05 PM REPRESENTATIVE GARDNER, referring to slide 12 and the commitments to Alaska if HB 110 or similar legislation is passed, asked whether the inverse statements are true if nothing passes or nothing similar passes. MR. JEPSEN responded that if things stay the same, Alaska should expect the same focus as exists now. ConocoPhillips is still drilling, shooting seismic, and considering other opportunities. The difference is in terms of how fast the opportunities will be pursued and whether ConocoPhillips can fully exploit those opportunities. Mr. Jepsen opined: So, really changing ACES is about realizing potential that we have here in the state. If you don't change ACES, ... we're not moving everything out of Alaska tomorrow. We're still here, but you're basically going to see the same kind of investment that we see today. And I think we can have a much better future, a stronger economy, more jobs, more business opportunities in this state if we have a robust oil and gas business here. 2:13:43 PM REPRESENTATIVE FOSTER recalled the mention of the potential reversal of the decline, and requested that ConocoPhillips comment on that statement versus merely slowing the decline. MR. JEPSEN reiterated that the results ConocoPhillips achieves will be proportional to the changes in the fiscal framework. A robust fiscal framework that allows investors to invest where they think the best opportunities are will result in opportunities that may not have been thought of earlier. He expressed hope that shale oil, Great Bear, will be successful. Although he acquiesced that there is more potential in the legacy fields than the oil companies are willing to discuss, he was fairly confident that there won't be much change in what's happening in these fields if the fiscal structure doesn't change. He pointed out that going from 6 percent to 4 percent or 2 percent represent a substantial change to the state as it enhances the economic future of the state and oil business. 2:15:03 PM REPRESENTATIVE TUCK inquired as to ConocoPhillips' definition of reasonable profit in order to result in more activity. MR. JEPSEN clarified that ConocoPhillips has always and will continue to meet its lease obligations. The discussion today is regarding how to make Alaska a more attractive place for capital investment. Under all the variables used to make investment decisions, Alaska is handicapped by ACES. REPRESENTATIVE TUCK then inquired as to what percentage of every dollar Alaska gives to the industry is reinvested in Alaska. MR. JEPSEN said he couldn't answer that at this time, but offered that ConocoPhillips' response would be proportional [to Alaska's fiscal framework]. He then encouraged the committee to keep in mind that ConocoPhillips invests in Alaska because it does make a profit. Although he predicted additional investment, he maintained that ConocoPhillips will still have profits that come out of the state. 2:17:07 PM REPRESENTATIVE SADDLER inquired as to how long ConocoPhillips will continue to do [business] in Alaska if there's no change [in the fiscal framework]. More specifically, he inquired as to what kind of future ConocoPhillips would predict for Alaska if the pipeline continued for 50 years, as has been assured by a judge, with no changes [in the fiscal framework]. MR. JEPSEN responded that he didn't want to discuss ongoing litigation. With regard to how long ConocoPhillips will do what it's doing, Mr. Jepsen said that will be a function of the price environment, costs, profitability, and technical risks that tend to increase as the fields mature. In further response to Representative Saddler, Mr. Jepsen confirmed that the committee can't assume that if the state does nothing, things will be fine forever. 2:18:27 PM CO-CHAIR FEIGE related his understanding that there is a limit on the well spacing allowed in the Kuparuk River Unit, and asked whether it would be a factor. Specifically, he asked whether ConocoPhillips would be able to increase production if the well spacing was reduced. MR. JEPSEN, noting his presumption that Co-Chair Feige was referring to well spacing for producers and injectors, he said he wasn't aware that additional well spacing requests were rejected. Typically, if a case for closer well spacing can be made, it's brought before an entity such as AOGCC who determines whether that's the best way to recover the resource from the reservoir. Mr. Jepsen further said that he wasn't aware that ConocoPhillips had any issues with well spacing, particularly in the Kuparuk River Unit. 2:20:00 PM CO-CHAIR SEATON asked whether ConocoPhillips considers the reduction of the maximum production tax rate from 75 percent to 60 percent in HB 3001 as significant. MR. JEPSEN remarked that if the maximum production tax rate was reduced to the point that impacted the price range in which ConocoPhillips is operating would be beneficial. However, if the reduction only impacts the $180-$220 per barrel environment, then it's not very helpful. 2:20:55 PM REPRESENTATIVE MUNOZ requested examples of ConocoPhillips' decision not to proceed with certain projects due to ACES. MR. JEPSEN replied that the Eastern North East West Sak (NEWS) project is very much at risk. Although ConocoPhillips may pursue part of the Eastern NEWS project under ACES, no change to ACES may impact how fast and the extent to which it's pursued. The aforementioned is probably the case for most potential projects. Currently, the magnitude of the state tax is fairly significant, he remarked. 2:21:57 PM CO-CHAIR SEATON highlighted that a royalty reduction application is available for an uneconomic project. He inquired as to why that isn't a factor for a project that's marginally economic. MR. JEPSEN advised that he's not an expert on what's required to seek royalty relief, but opined that the royalty relief statute wasn't crafted to address [the fact] that every field, even with a change in ACES, will have some accumulation that's uneconomic. CO-CHAIR SEATON encouraged Mr. Jepsen to investigate the royalty relief statute further. 2:22:57 PM REPRESENTATIVE OLSON inquired as to states, provinces, or plays in North America where ConocoPhillips is currently aggressive. MR. JEPSEN answered that ConocoPhillips is aggressive in the oil sands of Canada, the Bakken, Permian Basin, and Eagle Ford, all of which are liquid plays and located in places with much more favorable tax regimes than Alaska. 2:23:39 PM MR. JEPSEN, in response to Representative Foster, explained that Eastern NEWS is the next tranche of West Sak or viscous oil that ConocoPhillips is considering developing. 2:24:03 PM REPRESENTATIVE HERRON recalled that at the hearing yesterday consultants advised the committee to negotiate a decline curve and incentivize incremental production. He asked if a 2 percent decline curve would be reasonable to negotiate. MR. JEPSEN answered that a 2 percent decline curve would take a lot of investment. Furthermore, he didn't believe it would change much. 2:24:52 PM REPRESENTATIVE GARDNER asked if a reduction in taxes by 30 percent would result in ConocoPhillips experiencing an increase in investment by 30 percent. MR. JEPSEN explained that the changes wouldn't be proportional since the changes would be a function of the available projects that make sense in the existing fiscal framework. Mr. Jepsen clarified that he's saying that making the fiscal framework better will result in more investment whereas a small change in the fiscal framework will likely not result in any change in behavior [from the producers]. 2:26:09 PM CO-CHAIR FEIGE inquired as to the best method to incentivize new production in terms of the decline curve. MR. JEPSEN responded that he would want to give that answer some thought and consideration. ConocoPhillips believes there needs to be a blanket change to the tax framework that applies to all production in order to avoid complications arising from managing a decline curve and tracking new, old, and incremental oil. ConocoPhillips is looking for a way forward that makes Alaska a good place to invest. Mr. Jepsen said that the focus of ConocoPhillips is to establish a framework similar to what's in Australia where the industry takes 40 percent of the net [profits]. 2:28:48 PM CO-CHAIR FEIGE acknowledged that each well has its own decline curve, but opined that tracking each individual well's decline curve wouldn't be the most efficient method. He highlighted that the North Slope has a decline curve that's aggregated over all the companies and the fields across the North Slope. If the state was to set a decline curve, what would be the appropriate level of aggregation, he asked. MR. JEPSEN again related the need to give additional thought to the question. 2:30:23 PM CO-CHAIR SEATON encouraged Mr. Jepsen and the upcoming industry representatives to make all the considerations and get the information back to the committee. 2:31:00 PM REPRESENTATIVE SADDLER expressed the need to provide ConocoPhillips the opportunity to dispel any misconceptions or fallacies about ConocoPhillips and its operations in Alaska that have been portrayed in the public discussion. MR. JEPSEN agreed that here has been a lot of rhetoric, but didn't believe there was any particular point worthy of focus. He expressed hope that the testimony today illustrates that ConocoPhillips is a diligent operator that's here to stay, although it would like a different tax environment so that there could be more investment in Alaska. With regard to the discussion surrounding "harvest", Mr. Jepsen opined that harvest isn't drilling wells, shooting seismic, considering new recovery techniques, and pursuing technology. He mentioned that he has worked in places where there has been harvest assets and there is a large difference between what's done with a field that's on its last leg and is about to be divested versus what's occurring in Alaska. 2:32:59 PM CO-CHAIR SEATON asked if the unanimity aspect of some of the working interest owner agreements on the North Slope has been a problem. MR. JEPSEN, drawing from his experience working in Alaska since the early 1980s when much of his work was with partners and peers, said he wasn't aware of a situation when partner differences delayed or put off production or investment in locations that were good investments. Although there were times when companies had different positions from an analysis perspective, they all had the same goal of reserve additions, production, and generating net income for the companies. Generally, those things line up and move ahead. 2:35:03 PM REPRESENTATIVE FOSTER asked whether outside of Alaska ConocoPhillips is subject to an incentive program that involves declining curves. MR. JEPSEN and MR. CLARK both said they weren't aware of any other location with such an incentive program. 2:35:43 PM The committee took an at-ease from 2:35 p.m. to 2:49 p.m. BP  2:50:06 PM CO-CHAIR SEATON invited BP to provide its testimony. 2:51:01 PM DAMIAN BILBAO, Head of Finance, Developments and Resources, BP, began by relating that BP believes HB 3001 would deliver meaningful tax change for Alaska and result in a progression as much as $5 billion in new projects, as a first step. Referring to slide 3, he highlighted that BP opened its office in Anchorage in 1959. A year later geologists arrived and began working on opportunities on the North Slope. In the last 10 years BP has invested over $13.4 billion just with Alaska firms, which doesn't include BP's total investment over the last 10 years. Along with the investment has been a lot of learning, including a deep understanding of the opportunity to partner with the state in the development of local talent and resources. Over the last 10 years, BP has worked closely with the University of Alaska system and other institutions to support the capability in the state. Currently, BP in Alaska has over 2,100 employees, of which over 80 percent are Alaska residents. He characterized hiring Alaskans as just good business. He then highlighted the 275 Alaska Process Industry Careers Consortium (APICC) students that have been hired in the last 10 years, the 54 internships BP has offered over the last five years. Mr. Bilbao related an example that illustrates why BP believes its partnership/work with the state's institutions has paid off. In addition to the 2,100 employees BP has over 6,000 contractors who work primarily on the North Slope. Of those 6,000 contractors, about 5 of 6 work to renew the infrastructure on the North Slope in order to ensure that the infrastructure is fit for the next 30 to 50 years of opportunity that BP foresees in Alaska. One of the six or about 1,000 contractors is focused on bringing new barrels into production, which reflects the investment climate in Alaska. He then highlighted BP's $70 million of direct community investment since 2001.   2:57:18 2:58:01 PM MR. BILBAO turned the committee's attention to how BP makes investment decisions. He noted that he listened to the hearing in which PFC provided a presentation regarding how investment decisions are made. While BP doesn't agree with PFC on every point, PFC's analysis was sound and based on deep experience with the industry. Therefore, he said he is comfortable talking within the framework PFC presented to the committee. He then echoed ConocoPhillips' testimony that the investment fund isn't an unlimited amount of money. In the year prior to a project, the corporation determines what the appropriate total level of investment for the next year is based on factors including the view on oil price, the suite of opportunities, circumstances around the globe, and the obligation to manage the balance sheet and meet the commitment to shareholders and other stakeholders. The year begins in competition for a defined amount of money, which is particularly impactful on the growth projects given the fact the underlying activity to support the safe and efficient management of the fields will occur as needed. The growth projects, in particular, have to compete globally for the limited amount of funds. Mr. Bilbao moved on to the graph on slide 5 entitled "Global investment is limited and goes to the most attractive regions." The chart shows production curves for the following four different oil producing regions: Texas, Alaska, North Dakota, and Alberta as well as the price for each barrel of oil over that time. The chart spans the timeframe of 1977 to 2010. He mentioned his understanding from the Department of Revenue's (DOR) testimony that just last week North Dakota passed Alaska in total production volume. The graph relates just four examples of regions competing for investment, and thus growth projects from these regions or other regions have to compete for the same group of funds on a consistent set of metrics. The chart illustrates that despite the increasing price of oil globally over the last few years, production in Alaska has declined and continues to do so whereas the other three regions have experienced increased production. 3:01:03 PM REPRESENTATIVE KAWASAKI recalled from PFC's testimony that of all three majors on the North Slope, BP's portfolio illustrates more of a harvest situation for upstream investment. He inquired as to how to guarantee under HB 3001 that Alaska would get more money for future development if BP is spending more money where there is growth. MR. BILBAO clarified that the growth follows the investment opportunity, and thus if the investment climate is more attractive, the funds and investment will follow and result in growth. The growth won't occur without the appropriate investment climate. Mr. Bilbao emphasized that Alaska remains BP's largest resource base globally, with the exception of Russia. Therefore, it's not a question of opportunity and resource but rather is a question of investment attractiveness. If Alaska isn't competing in BP's portfolio as the graph illustrates, then the investment will not come to Alaska at the same velocity it does to other regions and as a result there won't be growth. 3:03:13 PM CO-CHAIR SEATON recalled that in the 1990s it was said that [BP's focus was] harvest, and questioned then why one would anticipate a reversal if the state changes the tax regime. MR. BILBAO specified that there are periods of time in any field where funds will flow in to build the infrastructure and the wells, as was the case in Alaska, and during those times funds come out of other regions to fund the infrastructure on the North Slope. After that massive initial investment, there's a period of production during which funds are used for ongoing operations and growth in other areas. He said that's how all companies work as it's managing the portfolio. Therefore, it's important to consider the longer term investment in that context. With regard to what will change going forward, Mr. Bilbao stated that if Alaska is competitive globally, the funds will flow. However, currently Alaska is not competing for growth projects. As the graph illustrates, Alaska in comparison to three other North American oil producing regions, the funds aren't flowing. Furthermore, Alaska's production decline for the past five years continues to drop. In fact, from last April to this April, BP's production has dropped by 8 percent. Therefore, the [tax regime] has a real impact on how BP competes for those funds with other locations. 3:05:34 PM MR. BILBAO, in response to Representative Saddler, stated that the chart is from a DOR slide that's BP felt was representative of a broader process. For BP, there would be alternatives such as Russia and Angola where there have been a production increase. Although the messages/conclusions would remain the same, he offered to provide the committee with further information if it so desired. 3:06:26 PM REPRESENTATIVE KAWASAKI pointed out that ConocoPhillips' slide 7 entitled "ACES - High Average Government Take" shows that Azerbaijan's tax rate is well above that of Alaska under ACES new development. Furthermore, the chart shows that Angola's tax rate is similarly placed with Alaska under ACES for new development and Russia's tax rate falls slightly below Alaska under ACES for existing producers. Representative Kawasaki opined that although taxes may move companies in a certain direction somewhat, BP is working in places with higher taxes than Alaska. Therefore, he invited discussion on that point. MR. BILBAO informed the committee that over the last three years he has been working with Indonesia supporting some of BP's liquefied natural gas (LNG) operations. Indonesia is comparable to Alaska on the chart presented on slide 7. However, the chart doesn't relate that the production sharing contract framework Indonesia employs allows companies to cost recover their investment earlier on, which is a significant impact on the economics. Similarly, the fiscal mechanism of other areas on the chart allows the economics to be competitive. He acknowledged that the total government take is higher overall, but pointed out that to be the case because there is an incentive earlier on to make the investment. The aforementioned isn't the case in Alaska. Mr. Bilbao emphasized the need to consider the entirety of the structure, not just individual pieces, in order to obtain a good sense of the investment decision. REPRESENTATIVE KAWASAKI commented that legislators haven't received much [detailed] information from the administration or other [stakeholders], and therefore legislators don't have much detailed information. 3:09:37 PM REPRESENTATIVE TUCK directed attention to the obligation that BP may have with Russia and the maintenance of the existing pipelines BP acquired in Russia. With BP's desire to build assets elsewhere, he questioned how the state can be assured that the money Alaska gives BP won't be used elsewhere. MR. BILBAO said that Russia is a great example of a joint venture that has had difficulties, but the financial performance of the unit has been strong. Furthermore, to a large extent the venture has self-funded much of its own growth. While the fiscal system in Russia does present certain limits, the unit has remained effective and the material is a very strategic material part of BP's portfolio. Mr. Bilbao surmised that Representative Tuck is inquiring as to how to ensure Alaska will receive the benefit from a meaningful tax change. He echoed Mr. Jepsen's comment that good projects move forward. Unfortunately, projects [in Alaska] aren't in the conversation because they don't compete globally. REPRESENTATIVE TUCK pointed out that recently the oil industry has been making more due to the rising price of oil rather than production itself. Therefore, he pondered whether producing more works against the company's best interest because there would be more available supply and reduced price, which would decrease the profit per barrel. Besides competitiveness, he inquired as to what other major factors are reviewed for strategy planning when considering markets. MR. BILBAO specified that BP doesn't enter and control markets as a first leader. Although BP may be the largest producer/leaseholder when it enters a market and takes a material position, BP doesn't control the markets. He reiterated that BP progresses good projects. Furthermore, BP never looks to consider the impact of its decisions to the price of oil globally. As a company, BP's total production is a small portion of the global oil production, and therefore one project isn't going to impact the global price of oil. Therefore, BP considers projects and does what it can to ensure the projects leverage the best technology and are efficient, and the projects move forward if they are good projects. 3:14:25 PM REPRESENTATIVE TUCK inquired as to what happened under the economic limit factor (ELF) when 15 out of 19 wells weren't paying any production tax. More specifically, he inquired as to what decisions prevented more investment in the state. MR. BILBAO responded that he isn't prepared to answer that question as his experience is primarily under the ACES environment. Under ACES, BP is running fewer rigs than in the past and hasn't sanctioned a major resource progression project since the passage of ACES. However, BP is investing to ensure that the infrastructure is renewed for 30 years and would like to invest in projects that use that infrastructure for 30 years, but ACES doesn't that allow to happen. 3:15:19 PM CO-CHAIR SEATON highlighted that Alaska has the number one or two ranked credit system in the world in terms of credit allowances on capital infusion as well as immediate deduction and no depreciation. Therefore, Co-Chair Seaton inquired as to how the return on capital [in Azerbaijan] is quicker than the 100 percent deduction and the credit system that's allowed in Alaska. MR. BILBAO said he could discuss the production sharing contract BP has with Indonesia, with which he is more familiar. Since it's tremendously complicated, he agreed to do so in writing. Mr. Bilbao remarked that in BP's view, it isn't able to attract the investment it would like. In terms of oil and gas rates, Alaska is last. 3:18:12 PM MR. BILBAO, returning to his presentation, directed attention to slide 6. He told the committee that Alaska has really good rocks and it's BP's largest resource base outside of Russia. The three things that move the opportunities to production growth/additional investment include efficiency, technology, and tax change. Efficiency and technology are within the producer's control. He noted that efficiency ensures that the appropriate people are working on the appropriate things in the appropriate way. Alaska hire is one way to achieve the aforementioned. With regard to technology, Mr. Bilbao said that Alaska has a fantastic track record of developing and implementing new technologies, which he would continue to expect. The third lever is the fiscal environment, which is the tax change that is within the legislature's control. Therefore, BP does what it can with the first two levers, efficiency and technology. However, the more the lever on tax change is pulled, the lower the obstacles surrounding efficiency and technology become. Although it's a combination of the three that result in more investment, it's ultimately a tax change that will determine how many projects move out of the funnel. As has been publicly stated by BP Alaska's president, there is a minimum of $5 billion in first phase development of potential projects that would move forward with meaningful tax change. However, if taxes don't change, the hurdles for efficiency and technology become larger. Frankly, if the taxes don't change, the business will have to change because the hurdles around efficiency and technology become much larger. Mr. Bilbao pointed out that the $5 billion in projects has been consistently mentioned by the three producers and will be pursued once the efficiency and technology challenges have been overcome. Still, a reduction in taxes would make those technology and efficiency challenges less difficult to overcome. 3:22:01 PM REPRESENTATIVE PETERSEN inquired as to the timeframe of the potential $5 billion in new investment. MR. BILBAO responded that the majority of the new investment would be over 5-10 years. He noted that most of the activity listed on slide 6 will be drilling led, and thus it will depend upon getting the rigs on the North Slope. Mr. Bilbao stated that BP would start the drilling the day after a tax change passed. 3:23:19 PM MR. BILBAO, in response to Representative Gardner, clarified that the day after a tax change passed BP would move forward with the projects [listed on slide 6] by getting the equipment to the North Slope. If BP knew the right fiscal environment was in place, BP would work on procuring and moving more rigs to the North Slope. REPRESENTATIVE GARDNER asked whether BP would have to perform the calculations to determine whether projects are competitive or have those calculations already been done. MR. BILBAO said that although BP would have to go through the process, there have been internal and external conversations on many of these. Therefore, BP has a fairly good idea of where it stands on the projects. Drilling opportunities are among the least difficult conversations as they tend to be more about equipment availability and less so about economic hurdles. Once drilling opportunities become economically viable and competitive, they tend to progress more quickly. 3:24:51 PM CO-CHAIR SEATON asked whether the Parker rigs were a problem. MR. BILBAO said that BP always ensures that all the equipment that it uses is ready to be used in the manner expected. Once the Parker rigs are deemed ready to be put into service, BP would need to decide whether they should be added to the existing fleet or replace existing less efficient rigs in the fleet to maintain the overall level of activity. The aforementioned will revolve around how many of BP's opportunities are economic, and therefore it's more about equipment than the economic threshold. 3:26:16 PM REPRESENTATIVE GARDNER recalled hearing from all the companies repeatedly that no one can promise that a project can be green lighted [merely because of a tax change], although it will improve the possibility/opportunity. She clarified that she's asking whether this spending commitment has already been made and it's just a matter of timing or does the project, due to a change in the economics of the project, have to obtain approval to move forward. MR. BILBAO answered that those projects haven't been green lighted because they aren't economic currently. If economics change through improved efficiency, technology, or a tax change, BP would reevaluate the projects. He clarified that his comment was that those discussions about drilling opportunities tend to be less difficult because the technology and efficiency challenges are typically better understood as is the inventory. The company knows there are great rocks it just needs to ensure that it's pursuing economic projects. 3:27:24 PM CO-CHAIR SEATON, referring to the deployment of capital, inquired as to the availability [of capital] for Prudhoe Bay or any of the North Slope developments in terms of being able to sanction those projects. MR. BILBAO replied no, the only challenge BP faces in Alaska for attracting more capital is the investment climate. CO-CHAIR SEATON asked if any projects have been delayed by one of the three partners not being in alignment with the others. MR. BILBAO related his experience that good projects move forward. Although he acknowledged that the partners may not always agree on the technical details and execution of the project, he opined that the cumulative debate is best for the state and the producers. CO-CHAIR SEATON surmised that Mr. Bilbao agreed with ConocoPhillips that some projects may have been delayed, but those delays were due to internal debates. He further surmised that there weren't projects that were canceled by one party being in a different strategic point in time as the investments were going forward. MR. BILBAO replied that he wasn't aware of such. 3:29:57 PM REPRESENTATIVE PRUITT inquired as to the meaning of additional drilling in legacy fields and how BP would differentiate additional drilling in legacy fields from the drilling BP would do if there was no change in the tax structure. MR. BILBAO clarified that additional drilling at the legacy fields means that there are drilling opportunities at Prudhoe Bay and Kuparuk River Unit that currently don't meet BP's thresholds to compete for funds globally, which is why BP has less rigs running on the North Slope than it has historically. If costs continue to increase on the North Slope, those increases would put further pressure on the opportunities, which would mean BP would continue to monitor those in terms of the global competitiveness of those opportunities. REPRESENTATIVE PRUITT asked whether there are certain types of drilling that's absolutely off the table. For instance, is BP doing down hole work, but not new wells starting at the surface. Or, are there opportunities in the legacy fields that are productive under the current system such that drilling can start at the surface, he asked. MR. BILBAO replied yes, adding that the largest opportunities on the North Slope are within the legacy fields. However, he noted that BP is on an ongoing basis entering and sidetracking existing well bores. The biggest addition of new rate is when a new reservoir or a new pad is constructed. The aforementioned are the type of growth investments that have the most difficult time competing under ACES globally. For example, constructing a new pad on the west side of Prudhoe Bay would be a significant investment because of the high upfront capital investment required for such a project. While it would be the most effective way to manage the decline, it would be among the most challenged for investment under the current tax regime. REPRESENTATIVE PRUITT surmised then that there are still opportunities, "ground down infrastructure", in the legacy fields that have not been touched. MR. BILBAO opined that what's lost in the conversation is the appreciation for how much work goes into reaching that 6-8 percent. Considering the rock itself with no investment and only ensuring that the operations were safe and efficient, Mr. Bilbao related that the rocks would produce 16-18 percent less the next year than the year prior. He then emphasized that BP invests a significant amount of money with a lot of people just to reach the 6-8 percent decline. The aforementioned is one of the reasons not to ignore those operations and only focus above a certain decline rate. He surmised that Representative Pruitt is getting to the point that the best place to look for oil is in the [legacy] fields. There are billions of barrels left in the legacy fields within Prudhoe Bay and Kuparuk River Unit, which is why BP focuses on that and doesn't explore outside of the legacy fields. 3:36:05 PM REPRESENTATIVE P. WILSON surmised that BP means that it wants to wait to develop until it's economic as compared to other projects in the U.S. and the world. MR. BILBAO clarified that when he says that [Alaska's] projects aren't competitive globally he's saying that while BP continues to work on projects [in Alaska] to better understand what can be done with the efficiency and the technology, the gap between where the projects stand now competitively and where BP would like them to be as even an option versus where they would need to be to materially compete is quite large. Although BP is reviewing ways to gain efficiency and technology to address the gap, the gap can be narrowed significantly with the appropriate tax system in place. REPRESENTATIVE P. WILSON maintained that because the tax regime is better elsewhere, it's more economic for BP to do business there than in Alaska. The economics aren't related merely to whether a project can be done in Alaska rather it's whether a project is economic in the broad scheme. MR. BILBAO agreed with Representative P. Wilson's summation broadly, but added that Alaska is a high cost operating environment with one of the most restrictive fiscal environments on the planet. 3:39:19 PM REPRESENTATIVE SADDLER asked whether the term "economic" is a relative or absolute term when BP uses it. MR. BILBAO answered that it's a combination, but noted that there are certain minimum expectations. He recalled that PFC testified that companies will have minimum expectations in regard to what a project will deliver. REPRESENTATIVE SADDLER asked whether BP has to reshuffle the deck every year and compare opportunities globally. MR. BILBAO explained that typically the company has a fairly good idea of where [projects/opportunities] are from the previous year. Typically, the analysis will be in regard to what has changed whether it is efficiencies, new technology, or a tax structure change. 3:41:03 PM CO-CHAIR SEATON recalled being told that companies have different hurdle rates, although the testimony has been that projects haven't been canceled [because one partner is at a different point]. Therefore, he surmised that the goal [for Alaska] is to make something work for the toughest in the group [of producers]. MR. BILBAO pointed out that the various producers are discussing the same projects and magnitude of changes, which is a fairly strong statement given the legal constraints the producers are under. He specified that tax change is one aspect of the challenges that must be overcome [in Alaska]. 3:43:28 PM MR. BILBAO, returning to his presentation, announced that he would now focus on what growth in investment could mean for Alaska's future. He then directed attention to slide 8, which presents a graphical representation of the OMB data that compares state revenue versus state expenses. In response to Co-Chair Seaton, Mr. Bilbao explained that the 4 percent growth line represents a 4 percent growth on expenses. Therefore, the OMB data assumes that from 2014, expenses grew by 4 percent. He pointed out that BP added some lines to OMB's graph. BP had concerns with regard to the forecast in revenue versus the track record of production decline over the last several years. [Alaska] has experienced a 6-8 percent decline and the revenue forecast is largely a flat line. The line for revenue at a 6 percent decline provides an idea of what the difference would be if production wasn't flat but was declining at 6 percent. The graph illustrates that if prices were flat and production declined at 6 percent, one would expect a budget deficit in 2018 of about $1.8 billion. BP also added a line that denotes a 4 percent decline. If there was a way to manage the production decline at 4 percent through additional investment, the deficit would be just under $1 billion less than it would be with a 6 percent production decline. Mr. Bilbao then recalled DOR Commissioner Butcher's testimony estimating that next year the break-even price for the budget to be $95 per barrel of oil. He further recalled DOR testimony relating that over the last five to six years the price of oil has been above $100 per barrel about 20-30 percent of the time and below $100 per barrel 70-80 percent of the time, which raises concerns with regard to the reliability of $100-$110 price forecasts. Furthermore, that challenge can't be managed overnight and one can't wait until 2017 or 2018 to produce more. More production has to begin now because projects take four to six years before they bring forth material production. Mr. Bilbao then told the committee that with a 6 percent decline, the only way the general fund revenue forecast works is to assume the price of oil is rising by 6 percent per year. "If you assume production continues to decline at 6 percent, then the only way the revenue stays flat is if the price of oil goes up 6 percent every year, which basically would mean that the state is betting its future on a high oil price." He suggested that there's an opportunity for the state and the producers to work together to begin to progress some of the projects that will deliver an impact to the projected deficit now, not in five or six years. 3:48:50 PM CO-CHAIR SEATON asked whether a change from a 6 percent decline to a 4 percent decline would be a realistic change if HB 3001 was enacted. 3:49:24 PM MR. BILBAO, in response to Co-Chair Seaton, directed attention to the chart on slide 9. He explained that the bar on the left represents 2012 production and is broken down between the natural base decline and the continued well work and drilling. The drilling and well work that occurs annually generates 40- 50,000 barrels a day. In the context of the North Slope, the Oooguruk field is currently producing 6,000 barrels a day. Therefore, annually there would need to be about eight new fields producing at the level of the Oooguruk field to replace what BP is bringing in new drilling and well work annually. He then turned to the bar representing 2020 production, and highlighted that the natural base decline is 16 percent plus. Therefore, if BP did nothing production from the North Slope would be about 150,000 barrels a day. He opined that it's only because BP is spending billions of dollars with many capable people that BP manages the decline at closer to 6-8 percent. Turning to the continued well work and drilling in 2020, Mr. Bilbao pointed out that continued well work and drilling makes up two-thirds of the production in 2020, which is generated from activity between 2012 and 2020. The activity and nature of the challenge to deliver production from a 16 percent decline to a 6 percent decline is significant. Furthermore, one must keep in mind that those barrels of oil are slightly more expensive than the prior year because of the impacts of inflation and the fact that the best wells are drilled first. He encouraged consideration of not only the investment and production above the 6 percent decline but also the ongoing, increasingly more expensive and more marginal activity that gets to the 6-8 percent. In response to Co-Chair Seaton's question about the 4 percent decline, he pointed out the portion of the 2020 production bar representing the $5 billion in new projects with meaningful tax change as represented in HB 3001. As has been mentioned before, the $5 billion is the first opportunity/phase. He confirmed that it would be possible with legacy and non- legacy opportunities to manage that decline to closer to 2 percent. Further, it's probable that with meaningful tax change [the production decline] could get closer to 4 percent with the $5 billion. Although it will take more than just the legacy fields, it will have to start with the legacy fields because that's where most of the oil is located. 3:53:29 PM MR. BILBAO, returning to slide 6, emphasized that to move from today to the 2020 profile would mean that BP would have to do a lot with efficiency and technology, which will only happen with meaningful tax change. 3:54:17 PM REPRESENTATIVE PETERSEN, referring to slide 9, inquired as to what BP considers additional opportunities on the 2020 bar. MR. BILBAO clarified that the $5 billion of projects is the first step and represents the projects that BP has worked most thoroughly and understands more definitively. Beyond those, more opportunities will be found when the economic environment is right. The first place one will find opportunities is in the existing fields. Due to the current economic environment, BP doesn't have the attention it could to the next phase. With the right investment climate, more opportunities could be found and moved forward. However, he noted that BP has a sense of some of the candidates for the additional opportunities, where they would fall in BP's natural progression of projects, and what it would take to move them forward. He opined that it's premature to specify the opportunities because they could very easily be passed over. 3:55:53 PM MR. BILBAO, referring to slide 10 entitled "Key Messages," concluded his presentation. He related BP's opinion, which he said the evidence supports, that ACES is a no growth policy as growth projects don't compete for investment. Furthermore, ACES bets Alaska's future on high oil prices. He further related that any ability to manage the decline has to start with the legacy fields since that's where most of the oil is located and the infrastructure already exists. The legacy fields are the only near-term option for new production. If the taxes don't change, BP's business will have to change, he opined. Mr. Bilbao then highlighted that other regions, such as Alberta, have worked cooperatively between the state and the producers to reduce taxes and increase investment and production. 3:57:48 PM REPRESENTATIVE HERRON reminded the committee of PFC's recommendation for the state to negotiate a decline curve with the majors and then incentivize production. He asked if 2 percent is legitimate or are [the percentages] presented by BP more reasonable. MR. BILBAO returned to slide 9 and the opportunity set with the $5 billion in investment that could achieve the 4 percent decline. Although BP also sees opportunities beyond that, to accomplish that the base business has to be healthy. As illustrated on slide 9, two-thirds of the production in 2020 will come from activity taking place between 2012 and 2020. To ignore the aforementioned and try to incentivize activity beyond that would create a foundation on top of which it would be difficult to support incremental large spending that projects require. He then explained that when there is a differentiation above and below a certain line, the concern is that it creates certain unintended consequences. If, as was the case with SB 192, there is an attempt to apply a different decline target for each producer, there is the risk of giving different producers incentive to move projects from one field versus the other. The producers, he explained, want to hit their target and [will move] when they can reach their target more effectively in one field than another. Similarly, the result of establishing a certain decline rate in a field or the North Slope is different for each producer because they decline at different rates due to the blend of their portfolios. Therefore, establishing specific decline rates may result in a tax break without additional effort for one producer while another producer may need a significant amount of investment to reach that rate. More fundamental than the aforementioned, when BP runs the economics for the next project, he questioned how BP will know whether that's the project that achieves the 6 percent or above the 6 percent. He further questioned what assumptions would be used. He said BP would have to run the economics on a more conservative higher tax system. Therefore, Mr. Bilbao encouraged the committee to develop an alternative that considers the business as a whole. Again, he told the committee that if the investment climate is attractive, projects will move forward. 4:01:18 PM REPRESENTATIVE HERRON, referring to slide 10, asked whether the benchmarks presented for Alberta remained the same as introduced or were they whittled down or up. MR. BILBAO responded that he didn't know specifically. However, he offered that the conversations he has had with the industry and Alberta have related that it was a collaborative effort between the producers and the state, such that they determined what would deliver additional investment while still allowing the state to manage certain fiscal requirements. He said that it only works when there is a conversation. 4:02:48 PM CO-CHAIR SEATON directed attention to the provision in HB 3001 that changes the maximum tax rate from 75 percent production tax to 60 percent. He then asked whether BP considers that a significant/meaningful piece of the legislation. MR. BILBAO said that it takes everything in the legislation to make it work. Therefore, when BP considers its economics, it considers the entirety of the legislation. The legislation, he opined, will shift BP's projects into a more competitive conversation. Picking and choosing will result in legislation that may incentivize some level of activity, but won't approach the over $5 million worth of opportunity that's available. 4:03:46 PM REPRESENTATIVE GARDNER highlighted the option under ACES for royalty relief when a field is deemed worthy of development except for the tax rate. She asked if there has been discussion of asking for royalty relief. MR. BILBAO related that internal conversations within BP suggest that typically royalty relief wouldn't be offered to the projects BP is considering. However, he expressed the need to review the matter further and provide the committee more information. 4:05:18 PM REPRESENTATIVE P. WILSON inquired as to with whom BP would deal if it takes advantage of the royalty relief option. CO-CHAIR SEATON explained that the legislature authorized royalty relief that is administered and granted by the Department of Natural Resources (DNR). The intention of royalty relief was to provide an opportunity for projects that aren't economic under conditions to become economic and move forward. If royalty relief isn't working, then the legislature may need to consider policy changes. 4:06:47 PM REPRESENTATIVE PETERSEN informed the committee that more smaller/midsized oil companies have come to Alaska to work in the oil fields. One of the reasons for the aforementioned is the generous tax credits of ACES. In fact, he related his understanding that [Alaska] under ACES may be the second best place for tax credits. If other companies view ACES as working because of the tax credits, why would BP not view it the same. MR. BILBAO answered that fundamentally it's distinguishing between an exploration period and a production period. During an exploration period, which can take 7-10 years, the activity tends to be drilling a well, shooting seismic, analyzing the seismic, and drilling a well all the way to the point of making a development decision and prior to the construction of a facility, roads, or pipeline. It's only at the point of the decision to make a large infrastructure investment when the company would begin to consider the impact of ACES on the economics [of the project]. Mr. Bilbao specified that ACES is very generous for the period of time prior to producing a barrel of oil, when the company is trying to find oil. Certainly, ACES has attracted new players. However, ACES isn't very generous for the period of the life of a field when the company tries to get the barrel out of the field and into the market. In fact, during the aforementioned time period, ACES is quite prohibitive. 4:09:17 PM REPRESENTATIVE GARDNER inquired as to an estimation of the investment it would take to reduce the decline from the legacy fields by 2 percent across the board. MR. BILBAO explained that to reduce the decline by 2 percent would mean that it would decline from 6 percent to 4 percent, which is equivalent to the $5 billion in investment that BP has already committed to publicly. 4:10:10 PM REPRESENTATIVE PRUITT, referring to slide 10, inquired as to what BP will have to do if taxes don't change. MR. BILBAO opined that the impact of no tax change and no investment increase in Alaska will be felt far beyond the direct oil and gas industry. The three producers generate 90 percent of the revenue for the state, but more importantly they generate a large part of the jobs, both directly and indirectly. He reminded the committee that last year's McDowell report said that for every direct oil industry job nine indirect jobs are created in the state. With more investment, there would be more indirect jobs and it would mean that property owners wouldn't have to be concerned about a reduction in property value nor would the legislature have to be concerned about finding a new way to bring in revenue to the state. If the oil industry experiences a challenge to investing, the average citizen will experience it day-to-day in many ways. 4:14:06 PM The committee took an at-ease from 4:14 p.m. to 4:23 p.m. Pioneer  4:23:14 PM CO-CHAIR SEATON invited Pioneer Natural Resources, Alaska to provide its testimony. 4:24:04 PM TODD ABBOTT, President, Pioneer Natural Resources, Alaska, began by drawing attention to slide 2 entitled "Forward Looking Statements." He then informed the committee that Pioneer Natural Resources, Alaska ("Pioneer Alaska") is a wholly owned subsidiary of Pioneer Natural Resources ("Pioneer"). Pioneer Alaska is headquartered in Anchorage with about 70 full-time Alaska employees and 120 Alaska contract workers in Anchorage and the North Slope. Mr. Abbott highlighted that Pioneer Alaska is the first independent operator on the North Slope, which was achieved with the Oooguruk project that commenced production in the fall of 2008. Currently, Oooguruk produces about 6,900 barrels a day and over the life of the project Pioneer Alaska will invest about $1 billion. Referring to slide 4, he explained that the slide illustrates what Pioneer looked like from 1997-2005, which was a time with the Lower 48 fields were considered mature and oil prices were much lower than they are today. Therefore, companies were going abroad seeking growth projects as the projects in the Lower 48 weren't economic. Pioneer was no different as it explored abroad in West Africa, drilled in Tunisia and South Africa, it had operations in Argentina, and worked in Canada. Pioneer also did a lot of work in the deepwater of the Gulf of Mexico, which was quite successful, and of course, Alaska as well. He then related that Pioneer entered Alaska to grow its business because its Lower 48 holdings were mature and Pioneer felt its fields were in decline. Alaska, with its very large oil resources and prolific oil and gas basin, fit the bill. Furthermore, the state was actively courting independents to join the majors in Alaska. The aforementioned left Pioneer feeling as if it could enter Alaska with a more independent mindset. Pioneer entered Alaska with a lower cost structure and more agility in terms of quick decision making. Moreover, things that are less material to the major producers are very material to Pioneer Alaska, which leads Pioneer Alaska to aggressively pursue options that may not be [economic] for the majors. In fact, Pioneer Alaska does well when it can come in after the majors and pickup things that weren't material to the majors. Referring to slide 6 entitled "North Slope Exploration History", Mr. Abbott told the committee that from 2003-2007 Pioneer Alaska drilled 11 exploration wells that resulted in one project, Oooguruk. Exploration is difficult, even in a basin as prolific as the North Slope. Although Pioneer Alaska found hydrocarbons in almost all of the 11 exploration wells, to have a commercial project one must find the right kind of hydrocarbons in the right types of reservoirs and in large enough accumulations by the right infrastructure. MR. ABBOTT, moving on to slide 7 entitled "Alaska's Severance Tax" explained that Pioneer decided to enter Alaska under the ELF. The Oooguruk project was sanctioned under ELF and construction began under the petroleum production profits tax (PPT). Drilling began and the first oil was revealed under ACES. Therefore, slide 7 illustrates that it's a long lead time from exploration to first production and that Pioneer Alaska was always chasing a moving target on the tax structure. He emphasized that certainty [with regard to the tax structure] is critical when a company is making decisions to sanction a project, especially when there is such a long lead time prior to production. Referring to slide 8, Mr. Abbott addressed what has changed in the ensuing eight years after [the first oil at Oooguruk]. The first change is that oil prices have increased dramatically and gas prices have decreased dramatically. The higher oil price allows Pioneer Alaska to use the horizontal drilling and facturing technology that has been available for some time, although it has been extremely expensive to use until now. The aforementioned has created the shale boom in the Lower 48 and now the landscape has changed such that the Lower 48 is no longer considered mature. Companies are no longer going [abroad] to find an economic project because now it can be done in the U.S. where there is a stable tax structure. He then directed attention to slide 9 entitled "Fixed-Royalty Jurisdictions in US Lower 48 Are A Key Competitor to Alaska for Investment Dollars", which he borrowed from PFC Energy. The slide illustrates that from 2003-2005 North America was exporting cash while from 2008-2010 capital is returning to the U.S. and being invested in the U.S. because of the higher [oil] prices, technology, and the tax structures available in the Lower 48. 4:31:45 PM MR. ABBOTT, continuing with slide 10 entitled "Current Pioneer Operations Footprint", informed the committee that Pioneer's current operations are only in the U.S., which is a much simpler operation with fewer contractual issues. Pioneer has sold off its holdings abroad and has, to a large extent, left the high risk exploration gain [operations] and is focused on resource potential, shale plays, and even conventional resources. He then told the committee that his job as president for Pioneer Alaska is to bring capital and investment to Alaska. Slide 11 highlights Pioneer's plays in Texas and provides some perspective of what Pioneer Alaska is up against. He informed the committee that the following three plays in Texas are shale plays: the Barnett Shale, Eagle Ford Shale, and Horizontal Wolfcamp Shale. The Spraberry Vertical in Texas can be considered more of a conventional play as there are vertical wells that are fractured. Pioneer is probably the largest acreage holder, by far, in the Spraberry Vertical. Furthermore, Pioneer has 20,000-plus drilling locations yet to drill. He related that the Horizontal Wolfcamp Shale is the most similar well to that of a well Pioneer Alaska would drill in Alaska. Mr. Abbott highlighted the scale of activity in the Lower 48 and the economic impact apart from the state revenue. The aforementioned operations in Texas have a very low geologic risk similar to what exists in Alaska and have very short project cycle times as compared to Alaska. He explained that in the Lower 48 when a company makes an investment, the company can drill five wells and decide to stop drilling after those five wells. However, in Alaska the operations are more like deepwater operations in that the company has to invest hundreds of millions of dollars before the first few wells are drilled. Therefore, in Alaska a company will have a lot of money on the table before getting significant results from development projects in Alaska. Therefore, the executive committee of Pioneer has to have tremendous confidence in the economics of projects in Alaska because they won't take a lot of risk with such a large stake on the table before getting results. Moving on to slide 12, he reviewed a graph that illustrates the competition for capital with the wells in Texas versus all the North Slope wells and reviewed the economic impact felt in Texas. Mr. Abbott moved on to slide 13 entitled "2012E Capital Spending and Cash Flow", and explained that the chart on slide 13 allows Pioneer to predict its cash flow for any given year. One can select the oil and gas price for next year, which will be Pioneer's corporate cash flow, including hedging and costs. For example, at current market prices [Pioneer will have] about $2.2 billion of cash flow and will spend about $2.4 billion in capital. Pioneer will spend about $1.8 billion in the Permian Basin, most of which will be spent in the vertical play of the Spraberry Basin and a significant portion in the horizontal wells. He then highlighted that Pioneer is spending about $135 million, which is roughly 6 percent of Pioneer's capital budget, in Alaska versus $1.8 billion and an additional investment in the Eagle Ford and Barnett Shale plays. He opined that the company's decision to make the best return for their shareholders speaks volumes. 4:38:56 PM MR. ABBOTT, referring to the map on slide 14, reviewed the Oooguruk site. Pioneer Alaska continues to drill at Oooguruk as there is one rig on site. The next step with Oooguruk is the Torok area. Pioneer Alaska drilled two wells this year, one of which was an unrelated exploration well and the other was an appraisal well from the Nuna-1 drill site. With regard to what's next for Pioneer or the incremental investment for Pioneer that could be impacted by tax policy, Nuna-1 is the answer. Nuna-1 has been drilled, test production has been run, the results are being evaluated now, and the recommendations are being prepared. He acknowledged that there are a wide range of outcomes that could result from Nuna-1 with the most likely outcomes being that tax policy has a tremendous impact. As noted on slide 15, Nuna-1 is one or two onshore drill sites depending upon the extent of the development. Nuna-1 is large and is more like an oil shale project that would be in the Lower 48 as it's highly laminated shale. For Nuna-1 Pioneer Alaska is drilling long horizontal wells and the largest frack job on the North Slope is in one of these wells. The [Nuna-1] project could result in a significant amount of jobs for Pioneer as well as for the service and construction companies that work in the area. Still, this project is up against projects in the Lower 48 that have lower operating costs, a better tax structure, and vast resources of which Alaska once had the monopoly. As related by slide 16, both Alaska and the Lower 48 have resource potential while Alaska would be more favorable in terms of resource competition because it doesn't have the number of independents as there are in the Lower 48. With regard to oil bias, he opined that Alaska has a tremendous amount of oil ready to be produced. However, the ease of the regulatory process is better in the Lower 48 while in terms of land acquisition Alaska is in a better position than the Lower 48. Although Alaska looks fairly good from a resource perspective, Alaska is lacking from the profitability side, which includes cycle times, execution risk, operational flexibility, and low operating cost. Therefore, Alaska needs a better tax structure than what's in the Lower 48, he opined. The aforementioned, he said, is illustrated on slide 17 entitled "Average Government Take", which the committee has already seen in previous presentations. 4:43:50 PM MR. ABBOTT, referring to slide 18, stated that there are some aspects to HB 3001 that are a good start, such as that it incents a wide array of projects, reduces the negative impact of progressivity, and makes Alaska projects significantly more competitive. However, an improvement to HB 3001 would be to include the small producer tax credit extension because it makes a real difference for small producers such as Pioneer. He noted that the small producer tax credit is really a reduction of the small producer's tax liability. Mr. Abbott opined that Pioneer has some good projects in Alaska that it would like to forward. He said he wants to bring additional capital to Alaska, and therefore he will do his absolute best to do so. Tax policy, he emphasized, would go a long way in terms of supporting the capital coming to Alaska otherwise it's an uphill battle. With regard to the Oooguruk expansion, Mr. Abbott clarified that the Torok expansion is not a done deal and Pioneer Alaska is not anywhere near sanctioning the development. The hope is that the expansion is so good that tax policy doesn't matter, although it's more likely that tax policy will matter. There are a lot of other projects on the North Slope like the Torok expansion and for them tax policy matters. He noted that Torok would bring new barrels into TAPS and create construction and development jobs. In closing, Mr. Abbott reiterated that HB 3001 will have a positive and a material impact. 4:46:24 PM REPRESENTATIVE GARDNER asked if when ACES went into effect Pioneer was one of the companies eligible for the claw back provisions. If so, what was that worth, she asked. She further asked whether Pioneer was one of the companies that received royalty relief, and if so, she inquired as to the experience of it. MR. ABBOTT said that he didn't know the answer to the question regarding the claw back, but offered to obtain it and provide it to the committee. He confirmed that Pioneer did apply and receive royalty relief for the Oooguruk project. The receipt of the royalty relief was primarily driven by Pioneer's 30 percent net profits lease in addition to ACES. As far as quantifying the value of the royalty relief, he offered to research that and provide the information to the committee. In further response to Representative Gardner, Mr. Abbott explained that the 30 percent net profits lease is an additional burden placed on the Oooguruk lease, basically it's an income tax on Oooguruk. CO-CHAIR SEATON interjected that the 30 percent net profits lease was a bid term on the lease at the time, prior to Pioneer picking up that lease. He explained that there are competitive lease sales and bonus bids. At the time, the bidder bid the 30 percent net profits as part of the bonus bid to obtain the lease. He asked if that bid term also applies to the expansion project. MR. ABBOTT related his understanding that it would apply to anything within that lease, which includes Torok. In further response to Co-Chair Seaton, Mr. Abbott clarified that it was a royalty reduction not royalty elimination. Therefore, Pioneer pays royalty and once it pays out it will pay a [30 percent] net profits lease. He further clarified that the 30 percent net profits is in addition to the reduced royalty. CO-CHAIR SEATON asked whether the royalty was reduced through royalty relief for a period of time until a certain point, such as when profitability is reached. MR. ABBOTT said he would have to review the specifics of the terms. CO-CHAIR SEATON remarked that he would appreciate the information because it would help the committee determine whether the existing royalty relief provisions function well or not. MR. ABBOTT, returning to Representative Gardner's earlier question regarding the difficulty of the process, related his understanding that the process was extraordinarily difficult and there was quite a bit of documentation work. Royalty relief isn't an easy administrative process as it's something that takes a lot of data, time, and analysis. 4:51:13 PM CO-CHAIR SEATON asked if the 30 percent net profits portion of the lease is after the production tax and all other property taxes. He further asked if the profit is before or after corporate income tax. MR. ABBOTT clarified that [the 30 percent net profits lease] is after and in addition. He offered to prepare information to provide to the committee. 4:52:04 PM CO-CHAIR SEATON inquired as to whether the change from the 75 percent maximum tax to the 60 percent maximum tax is a significant piece in the calculation for being able to draw capital to a project in Alaska. MR. ABBOTT responded that it's hard to say without the specifics for Torok. However, more broadly, the change is a good provision, but he said he didn't know if it's material enough to achieve the type of investment being sought. 4:53:07 PM CO-CHAIR SEATON asked if Pioneer has a process facility sharing agreement with existing producers or does Pioneer have its own processing facility. MR. ABBOTT confirmed that Pioneer has an agreement such that all of Pioneer Alaska's crude production oil, water, and gas is processed through ConocoPhillips' production facilities. Pioneer has a facilities sharing agreement to do so. In further response to Co-Chair Seaton, he confirmed the facilities sharing agreement would likely remain for any expansions, although it depends upon the size. He explained that it would have to be an extraordinarily large find for Pioneer to justify building its own processing facilities rather than availing themselves of those of ConocoPhillips. CO-CHAIR SEATON surmised that when incentivizing multiple things, including legacy fields that are water or gas constrained, there could be issues. He then mentioned that Brooks Range approached the state about a state loan for funds to construct mobile processing facilities that could process about 15,000 barrels per day. If that was available for an Alaska project, he asked whether that would materially impact the sanctioning of a project. MR. ABBOTT mentioned that in his last position with Pioneer he was vice president of corporate finance. He then informed the committee that Pioneer measures the profitability of its projects as a discount return on investment (DRI), which is the value divided by the discounted capital. For every dollar invested, one wants to obtain the highest value for that dollar. Therefore, having something that's a lower cost of debt through the state would decrease the amount of capital the company would have to deploy and decrease the discount rate against which the project is measured. The aforementioned is positive, but the question is regarding the ratio of that piece of capital versus the overall project size. In further response to Co-Chair Seaton, Mr. Abbott opined that the way it's being described really isn't a relief of capital but rather it's a financing mechanism. In that case, the company would still pay the dollars and the interest rate would make the difference. A change in the interest rate on a $200 million investment could help over the life of a project, but it would need to be a project that's [already] very close to being economic. 4:58:15 PM REPRESENTATIVE HERRON posed a scenario in which the 40 percent gross reduction is reduced, and asked when it wouldn't be meaningful when only changing that. MR. ABBOTT responded that is very difficult to answer. The corporation reviews [HB 3001] in terms of its overall value, and thus [to only consider the percent gross reduction] would be project dependent. REPRESENTATIVE HERRON appreciated Pioneer, which is a nimble and successful company, providing comments today. 5:00:37 PM CO-CHAIR SEATON recalled that there had been questions regarding decline curves, and asked whether that would apply to Pioneer's projects. MR. ABBOTT said that reviewing a decline curve segregation in terms of new oil versus old oil is an interesting way to look at it. Although he said he likes the idea, he said it's difficult to comment until he has the details. For something like Oooguruk, Pioneer produces out of several different horizons each of which has its own decline. Pioneer's production profile, he related, would historically increase, decrease slightly, and then start increasing again. As the various reservoirs deplete at different rates and the water flood impacts at different times, there will be varying rates. Therefore, the challenge is how to determine the schedule of future volumes based on existing production. He opined that it's a difficult number to ascertain and negotiation of it would be quite an exercise between the state and the companies. Again, if implemented correctly, it could work. 5:03:22 PM REPRESENTATIVE PETERSEN recalled hearing that some of the new players on the North Slope had found impediments to growth and potential due to difficulties accessing facilities and excessive costs for shipping oil down the pipeline. He asked if Pioneer has experienced such. MR. ABBOTT acknowledged negotiations to use ConocoPhillips' facilities were difficult and took a long time. He further acknowledged that from time-to-time there are disagreements, but it's a business transaction and is worked out. ConocoPhillips has worked with Pioneer on its facilities. For example, ConocoPhillips is doing capital planning for a couple of years out and has inquired as to Pioneer's needs. Although the relationship between Pioneer and ConocoPhillips is a business relationship, it works. 5:05:27 PM REPRESENTATIVE GARDNER commented that it's interesting that Mr. Abbott could conceive of a play that would be so wonderful and economic that tax policy wouldn't matter. MR. ABBOTT indicated that he's an optimist. 5:05:54 PM CO-CHAIR SEATON related his understanding that Pioneer would like the small producer tax credit included in HB 3001. He asked if an expiration of 2022, a 10-year extension, would provide enough time to recruit the capital. MR. ABBOTT replied yes, adding that 2022 would be a reasonable timeframe for the extension. Having more certainty would help. CO-CHAIR SEATON recalled comments that the small producer tax credit wasn't inflation proofed. He asked if Mr. Abbott saw any need to change that from the $12 million to $15 million or is it immaterial for most small producers. MR. ABBOTT opined that $3 million a year of an $800 million project is unlikely to change Pioneer's decision on a project. Although [the small producer tax credit] helps with Oooguruk, tweaking it reaches a point of diminishing returns, he remarked. AOGA  5:08:25 PM CO-CHAIR SEATON invited testimony from the Alaska Oil and Gas Association (AOGA). 5:08:47 PM KARA MORIARTY, Executive Director, Alaska Oil and Gas Association (AOGA), began by informing the committee that AOGA is a business trade association with the mission to foster the long-term viability of the oil and gas industry for the benefit of all Alaskans. The association's 16-member companies are a diverse group and the committee has heard from two of the member companies today. She informed the committee that AOGA's member companies have both an onshore and offshore presence and are located in the Cook Inlet and the North Slope. Furthermore, AOGA member companies are on federal and state lands. The member companies include legacy companies, new entrants, three in-state refineries, and the Alyeska Pipeline Service Company. In total AOGA's members hold more than 1.2 million acres of land. Therefore, there's little doubt AOGA represents the majority of oil and gas exploration, development, transportation, refining, and marketing activities in the state. She pointed out that one of the key purposes of any trade organization, especially AOGA, is to provide a forum for the discussion of matters of general interest for its members. She highlighted the policy of AOGA to have 100 percent consensus on tax policy matters, and emphasized that all 16-member companies concur with the statements she's going to make today. MS. MORIARTY reminded the committee that AOGA didn't support the tax changes that were made in 2006 and 2007 because AOGA believed then and now that the current tax system is uncompetitive for investment dollars, long-term development, and production. Furthermore, all of AOGA's member companies believe that meaningful changes to the tax system are necessary to stem the decline in production. In fact, today's testimony marks the sixth time that AOGA has testified before the Twenty-Seventh Alaska State Legislature regarding the need for oil tax reform. Throughout AOGA's testimony to the legislature and the public it has stressed the graph entitled "Production Decline is Real", which illustrates that declining production is a problem that cannot be ignored. She acknowledged that [the legislature] isn't ignoring it. The graph shows the historical production in the past decade with DOR's forecast for the next decade. Upon examining the past three years a bit closer, one will find that production is declining by just under 40,000 barrels per day. Furthermore, the DOR forecast moving forward is that almost half of the new production will be from new oil that is oil yet to be developed. In fact, the recently released DOR spring 2012 forecast forecasts that in 2013 71,000 new barrels per day will need to be in production. 5:12:22 PM MS. MORIARTY stated that as a trade association, AOGA's main question is from where this new oil is going to come, especially in the short term. She informed the committee that Oooguruk and Nikaitchuq, new fields, are each expected to peak at around 20,000-28,000 barrels per day. She then reiterated that the current production decline is about the same as these two new fields combined each year. In other words, to simply offset the current decline two new fields like Oooguruk and Nikaitchuq need to come on each year. Moreover, to reach DOR's forecast for 2013 three fields of this size need to come on line in the next year. Unfortunately, she knew of no new fields expected to produce oil in the next three to five years. She recalled that in 2006 and 2007 many companies testified that ACES wouldn't attract the investment Alaska needed to stem the production curve. Not only did that prediction came true, production is significantly lower today than what was forecast when ACES was passed in 2007. As the chart entitled "Forecast in 2007 vs. 2011 Actual Production" shows the Department of Revenue predicted that in 2011 Alaska would produce 754,000 barrels per day, but production was only at 603,000 barrels per day. Moving on to the chart entitled "Current Industry Investment", Ms. Moriarty pointed out that the chart relates the total operating expenses in Alaska industry wide and the capital investment. The chart relates that the industry investment totals has remained stagnate over the last three years. Capital investment has averaged $1.7 billion, which resulted in a loss of about 40,000 barrels per day over the same three years. Therefore, current investment levels aren't even stemming the production decline, never mind increasing production. Without bold and meaningful reforms Alaska's production will continue to decline at a rate, according to the Office of Management & Budget, that would create potential deficits as early as 2015 that would increase in each succeeding year. From AOGA's perspective, there's a production problem that's going to soon result in a serious revenue problem for the state. MS. MORIARTY pointed out that AOGA's member companies and others have testified about what's happening with businesses on the North Slope, the interrelationship between new levels of new investment each year and the rate of decline in Alaska North Slope production as well as the impact of taxes on investment decisions. "These explanations are not threats, but they're not bluffs either," she stressed. Rather, the testimony has been candid attempts to describe how those companies evaluate investment opportunities in Alaska versus elsewhere and how Alaska's tax regime can influence decisions regarding which opportunities to take. She further recalled that recently the legislature's own consultants explained to this committee how investment decisions are made and provided a similar conclusion that investment decisions reflect the expectations of the company's respective shareholders and that companies will choose the opportunities they perceive to be best, all things considered, including taxes. Ms. Moriarty stated that the level of investment in Alaska since enactment of ACES isn't retaliation rather the investments are nothing more than the results of the competition of opportunities in Alaska versus those elsewhere. Therefore, AOGA believes that declining production is a slope-wide problem that needs a slope-wide solution. John Norman, the commissioner of the Alaska Oil and Gas Conservation Commission, recently described Alaska's legacy fields as an "anchor tenant." Ms. Moriarty said that AOGA continues to use the analogy that the North Slope is like a tree with the two great legacy fields being its trunk and the other fields branching out and rising out of that trunk. Therefore, if one peels the bark off all the way around the trunk and makes the tree unhealthy, all the other branches will become unhealthy as well, no matter how robust they might have been if the trunk had stayed strong. 5:18:07 PM MS. MORIARTY, referring to the slide entitled "Rich In Resources", said that if one considers the resources remaining on the North Slope, one should be encouraged. In fact, the legacy fields, the conventional line of 5 billion barrels of oil remaining, hold the most promise in the short term. Additionally, during this time of record high oil prices Alaska should see a flurry of activity and increased investment levels to get these resources to market. The producers of the existing non-legacy fields on the North Slope and the developers of any new fields that may be discovered need as much production as possible flowing from the legacy fields through TAPS in order to maintain affordable costs to ship oil from the North Slope to refinery destinations. She confirmed Representative Petersen's concern for high transportation costs and characterized it as a real concern that could cripple the economics of any new fields as well as the economics of any non-legacy fields currently in production. Ms. Moriarty emphasized, "So, we believe that Alaska and Alaskans need to appreciate the North Slope production with a great level of concern and react with bold and meaningful reforms." Without comprehensive reform for the legacy fields as well as other production and future production, the entire North Slope will be harmed. As Mr. Abbott told the committee, tax policy does impact business decisions and the competition for investment dollars is real. Therefore, AOGA encourages the committee to put Alaska in a better and more competitive position for near-term and long-term development. The legislation, HB 3001, before the committee does recognize the overall government take in Alaska is too high and does provide meaningful reform. Ms. Moriarty acknowledged that a solution that benefits all fields may not be achieved this special session because it appears the legislature is fragmented on this issue. However, AOGA will continue to work with the legislature until meaningful tax reform is reached for all fields on the North Slope. 5:20:37 PM REPRESENTATIVE FOSTER inquired as to how many barrels have gone through TAPS. MS. MORIARTY answered that over 16 billion barrels of oil has gone through TAPS. If one were to include production for Cook Inlet, just over 17 billion barrels of oil has been produced since statehood. 5:21:13 PM REPRESENTATIVE HERRON inquired as to when a decrease in the percentage alone is not meaningful to AOGA. MS. MORIARTY said that's difficult for her to answer because she has to have 100 percent consensus. In all of the discussions, reducing the base rate and changing progressivity would provide the most meaningful reform. 5:23:03 PM CO-CHAIR SEATON directed attention to the committee packet that includes testimony from the ExxonMobil Corporation whose representative couldn't be present today. He told the committee members could submit questions for ExxonMobil Corporation. He reviewed the committee's upcoming schedule. 5:25:18 PM MR. BILBAO, in response to Representative Gardner's question regarding a discrepancy in the decline curve BP presented versus that of DOR, noted that he has sent a text to his office to confirm whether the data submitted by all the producers included the projects associated with the incremental $5 billion and whether that accounts for the difference in production. Therefore, Mr. Bilbao said he would like to double check that. [HB 3001 was held over.] 5:27:00 PM ADJOURNMENT  There being no further business before the committee, the House Resources Standing Committee meeting was adjourned at 5:27 p.m.