Legislature(2013 - 2014)BARNES 124

02/20/2013 01:00 PM RESOURCES


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01:04:17 PM Start
01:04:35 PM HB72
03:08:07 PM Adjourn
* first hearing in first committee of referral
+ teleconferenced
= bill was previously heard/scheduled
+= HB 72 OIL AND GAS PRODUCTION TAX TELECONFERENCED
Heard & Held
-- Testimony <Invitation Only> --
- Presentation: Large Producers
+ Bills Previously Heard/Scheduled TELECONFERENCED
                    ALASKA STATE LEGISLATURE                                                                                  
               HOUSE RESOURCES STANDING COMMITTEE                                                                             
                       February 20, 2013                                                                                        
                           1:04 p.m.                                                                                            
                                                                                                                                
MEMBERS PRESENT                                                                                                               
                                                                                                                                
Representative Eric Feige, Co-Chair                                                                                             
Representative Dan Saddler, Co-Chair                                                                                            
Representative Peggy Wilson, Vice Chair                                                                                         
Representative Mike Hawker                                                                                                      
Representative Craig Johnson                                                                                                    
Representative Kurt Olson                                                                                                       
Representative Paul Seaton                                                                                                      
Representative Geran Tarr                                                                                                       
Representative Chris Tuck                                                                                                       
                                                                                                                                
MEMBERS ABSENT                                                                                                                
                                                                                                                                
All members present                                                                                                             
                                                                                                                                
COMMITTEE CALENDAR                                                                                                            
                                                                                                                                
HOUSE BILL NO. 72                                                                                                               
"An  Act relating  to appropriations  from taxes  paid under  the                                                               
Alaska  Net  Income  Tax  Act;   relating  to  the  oil  and  gas                                                               
production tax rate; relating to  gas used in the state; relating                                                               
to monthly  installment payments  of the  oil and  gas production                                                               
tax; relating to  oil and gas production tax  credits for certain                                                               
losses and expenditures;  relating to oil and  gas production tax                                                               
credit  certificates;  relating  to nontransferable  tax  credits                                                               
based  on production;  relating to  the  oil and  gas tax  credit                                                               
fund; relating  to annual statements by  producers and explorers;                                                               
relating to  the determination of  annual oil and  gas production                                                               
tax values including  adjustments based on a  percentage of gross                                                               
value  at  the  point  of   production  from  certain  leases  or                                                               
properties; making  conforming amendments;  and providing  for an                                                               
effective date."                                                                                                                
                                                                                                                                
     - HEARD & HELD                                                                                                             
                                                                                                                                
PREVIOUS COMMITTEE ACTION                                                                                                     
                                                                                                                                
BILL: HB 72                                                                                                                   
SHORT TITLE: OIL AND GAS PRODUCTION TAX                                                                                         
SPONSOR(s): RULES BY REQUEST OF THE GOVERNOR                                                                                    
                                                                                                                                
01/16/13       (H)       READ THE FIRST TIME - REFERRALS                                                                        

01/16/13 (H) RES, FIN 02/11/13 (H) RES AT 1:00 PM BARNES 124 02/11/13 (H) Heard & Held 02/11/13 (H) MINUTE(RES) 02/13/13 (H) RES AT 1:00 PM BARNES 124 02/13/13 (H) Heard & Held 02/13/13 (H) MINUTE(RES) 02/15/13 (H) RES AT 1:00 PM BARNES 124 02/15/13 (H) Heard & Held 02/15/13 (H) MINUTE(RES) 02/18/13 (H) RES AT 1:00 PM BARNES 124 02/18/13 (H) Heard & Held 02/18/13 (H) MINUTE(RES) 02/20/13 (H) RES AT 1:00 PM BARNES 124 WITNESS REGISTER THOMAS K. WILLIAMS, Senior Royalty and Tax Counsel BP Exploration (Alaska) Inc. Anchorage, Alaska POSITION STATEMENT: Testified during discussion of HB 72. DAMIAN BILBAO, Head of Finance BP Exploration (Alaska) Inc. Anchorage, Alaska POSITION STATEMENT: Testified during discussion of HB 72. SCOTT JEPSEN, Vice President External Affairs ConocoPhillips Alaska, Inc. Anchorage, Alaska POSITION STATEMENT: Provided a PowerPoint presentation and testified during discussion of HB 72. BOB HEINRICH, Vice President Finance ConocoPhillips Alaska, Inc. Anchorage, Alaska POSITION STATEMENT: Testified during discussion of HB 72. DAN SECKERS, Tax Counsel ExxonMobil Corporation Anchorage, Alaska POSITION STATEMENT: Testified during discussion of HB 72. ACTION NARRATIVE 1:04:17 PM CO-CHAIR ERIC FEIGE called the House Resources Standing Committee meeting to order at 1:04 p.m. Representatives Hawker, Johnson, Seaton, P. Wilson, Tuck, Saddler, and Feige were present at the call to order. Representatives Olson and Tarr arrived as the meeting was in progress. HB 72-OIL AND GAS PRODUCTION TAX 1:04:35 PM CO-CHAIR FEIGE announced that the only order of business would be HOUSE BILL NO. 72, "An Act relating to appropriations from taxes paid under the Alaska Net Income Tax Act; relating to the oil and gas production tax rate; relating to gas used in the state; relating to monthly installment payments of the oil and gas production tax; relating to oil and gas production tax credits for certain losses and expenditures; relating to oil and gas production tax credit certificates; relating to nontransferable tax credits based on production; relating to the oil and gas tax credit fund; relating to annual statements by producers and explorers; relating to the determination of annual oil and gas production tax values including adjustments based on a percentage of gross value at the point of production from certain leases or properties; making conforming amendments; and providing for an effective date." 1:06:12 PM THOMAS K. WILLIAMS, Senior Royalty and Tax Counsel, BP Exploration (Alaska) Inc., presented a PowerPoint titled "BP Testimony to House Resources" and paraphrased from a prepared statement: Thank you for inviting us here to testify on House Bill 72, which has been introduced by Governor Parnell and proposes to amend the so called "ACES" production tax on oil and gas produced in Alaska. There are three primary changes that HB 72 would make to ACES: one, repeal progressivity, which we think is good; two, change the system of tax credits that now exists, which threatens to harm some producers even if it may help others; and three, create a new "gross revenue exclusion" for new production that we view as innovative but largely misdirected. My testimony today will review these changes in the context of the tax issues that my employer faces under the present tax, which the Governor and apparently the entire Legislature, with the introduction of Senate Bill 50, agree needs to be reformed. First, progressivity. As you know, progressivity is a sliding-rate tax that runs quickly up to a 25 percent rate and then rises more slowly above 25 percent. It is in addition to the basic 25 percent tax that is also levied on the "production tax value" of a producer's taxable production. Repealing progressivity is a good idea for a number of reasons, which AOGA has identified in its testimony on Monday and which other taxpayers will probably present to you as well. Many of those objections are for effects from progressivity that were intentional as part of the way progressivity was designed. What I'd like to do today is to describe two significant, unintended effects of progressivity that seem largely unknown and even less understood. I have eight slides to present that will show you exactly what these unintended consequences are. 1:08:01 PM MR. WILLIAMS directed attention to slide 3, "How ACES works," and continued: To begin, let me quickly review how the tax is calculated for the example I will use. If you look at this first slide, you will see the tax calculation for a hypothetical producer with 10,000 barrels of oil who sells it on the West Coast for $100 a barrel and receives a million dollars. It cost $150,000 - or $15 a barrel - to transport that oil from the field in Alaska to the West Coast, which leaves $850,000 as the gross value at the point of production or "GVPP." The producer had $300,000 of allowable lease expenditures, or field expense, to produce the oil, which leaves a taxable production tax value, or "PTV," of $550,000 or $55 a barrel. The base tax is 25% of the PTV, or $137,500. The progressivity rate equals four tenths of a percentage point times the difference between $30 and the producer's PTV per barrel. Here the difference between $30 and $55 is $25, and $25 times four tenths of a point per dollar equals 10 percent. Ten percent of $550,000 is $55,000 of progressivity tax. That plus the base tax of $137,500 equals a total tax of $192,500. So far there is nothing here that is new to you. So now let me begin to show you something you probably have not seen before. This scenario is not about what the producer has actually produced, but about an evaluation of what could happen from the development of a new reservoir or field if the investment is made. And let's suppose that this producer sees three different ways that she could potentially improve this investment. One is that she knows of a buyer willing to pay a premium of a dollar a barrel for the oil delivered on the West Coast, the second is a way to save $20,000 in transportation costs, and the third is a way to cut the costs for field operations by $30,000. If she can do all three, what is the change in the tax? 1:10:08 PM MR. WILLIAMS presented slide 4, "Example - The three changes together, and continued his explanation: In this slide we see the three changes. The extra dollar a barrel in the price increases the sales revenue from the oil to $1,010,000. The transportation savings reduces that cost from $150,000 to $130,000. Between the increased price and the transportation savings, the GVPP of the oil back in the field is $880,000 instead of $850,000. And the reduction in upstream lease expenditures raises the taxable PTV by another $30,000, for a total increase in PTV of $60,000 from $550,000 to $610,000. The 25% base tax is now $152,500 instead of $137,500. And with PTV per barrel now $61, the progressivity rate is $61 minus $30, or $31, times four tenths of a percentage point per dollar, or 12.4 percent. Twelve- point-four percent of $610,000 is $75,640, and the total tax is $228,140 instead of $192,500. This is an increase of $35,640. I have highlighted this change in yellow and recorded it in the upper right corner of the slide in order to keep it on screen so we can remember what it was, because in this scenario the producer next asks what the tax change is separately for each of these improvements to the investment. This next slide shows the change resulting only from the extra dollar in the West Coast price. 1:11:48 PM MR. WILLIAMS pointed to slide 5, "Price change only," and described: The higher price increases the sales proceeds by $10,000 to $1,010,000. And as you go down the "As Revised" column you see this $10,000 flowing down into the $860,000 GVPP and then into the taxable PTV, raising it to $560,000. The 25% base tax on $560,000 is $140,000. The progressivity rate is $56 minus $30, or $26, times four tenths of a percentage point per dollar, which is 10.4 percent. Ten-point-four percent of $560,000 is $58,240 and the total tax is $198,240, an increase of $5,740 from the base case. Again, I have recorded this at the right side of the table so we can remember what it is without having to flip back and forth between slides. The next slide shows the change in tax from the $20,000 savings in transportation costs. 1:12:44 PM MR. WILLIAMS summarized slide 6, "Transportation cost savings," and informed the committee: The $20,000 again flows straight down into the taxable PTV, increasing it from $550,000 to $570,000. The progressivity rate is now $57 dollars minus $30, or $27, times four tenths of a percentage point per dollar or 10.8 percent. That plus the 25 percent base rate on $570,000 of PTV yields a total tax of $204,060, an increase of $11,560 from the base case. This, too, I have recorded on the right side of the table. 1:13:24 PM MR. WILLIAMS furnished slide 7, "Whole is greater than the sum of its parts," and indicated: Finally, this next slide shows the effect of saving $30,000 in field expense. The PTV increases by $30,000 to $580,000, the progressivity rate is 11.2 percent. The base tax and progressivity add up to $209,960 - an increase of $17,460 from the base case. And here at last, this slide shows what it is that you probably have not seen before. The sum for the three changes separately is $34,760, which is in bold font to make it easier to spot. This is less than the $35,640 change in tax when all three are factored in at once (also in bold font). In other words, with progressivity, the whole is greater than the sum of its parts. And that's not all. The amount of tax that is calculated for each individual part changes, depending on what order you look at them. 1:14:24 PM MR. WILLIAMS directed attention to slide 8, "ACE's continuously changing tax effect," and continued his discussion: Here's a slide that looks at the $20,000 savings in transportation cost and the $30,000 reduction in field expense together. The two cost reductions together increase PTV by $50,000, to $600,000. The base tax on that is $150,000. Progressivity for $60 of PTV per barrel is $60 minus $30, or $30, times four tenths of a percentage point per dollar, or 12 percent, times $600,000, which is $72,000. The total tax change from the two is $29,500. From the previous cases where we considered each cost reduction separately, the tax increase with transportation only was $11,560 and for field BP expense only was $17,640, and these appear in the upper right of the slide. If we look at transportation first, it is equivalent to looking at it standing alone, and we have already calculated what that is - $11,560. So $11,560 of the combined $29,500 tax increase is from the change in transportation cost, and the rest - $17,940 - is for the change in field expense. But this means the field expense is almost $500 greater than what it is when it's standing alone. And if you reverse the order, then the field-expense tax increase is the same as when it stands alone, but now the tax increase for the transportation savings is different -$12,040 instead of the $11,560 when it stands alone or is taken first. What we have done here on this [eighth] slide is to look at the pair of cost savings for downstream transportation and upstream lease expenditures, and we've looked at that pair first, ahead of the change in market price. If we go back to the previous slide, we see that if we take transportation first and subtract its $5,740 from the total $35,640 tax effect for all three, then that leaves a different number - $29,900 - for this pair of changes instead of the $29,500 we have here on slide six when we calculate that pair back first. There is nothing special about this particular pair of changes that creates this difference. There would be a similar difference if we pair price with transportation or price with lease expenditures. With either one, we'd get one set of tax effects for this pair if we calculate them first, and a different set of tax effects if we calculate the effect of the unpaired change first. And, as here, within each pair, there is a different cost for each change in that pairing depending on whether its effect is calculated first or the other's effect is first. These examples involve a triplet of categories of change that could be made to improve the economics of the project: an increase in price, a reduction in transportation costs to market, and greater efficiency in field operations. But I have simplified these examples by using lease expenditures generically as a single cost category. In the real world a would-be investor would look at capital expenditures separately from operating costs because the timing for when the two kinds of cost are incurred is different and - especially important in the context of analyzing tax effects - the capex generates a 20 percent Qualified Capital Expenditure tax credit in addition to changing the PTV and the progressivity rate. So there are really four categories of change to look at: changes in sales price, changes in transportation costs, changes in operating expense, and changes in capital expenditures. For each one of these four categories, its respective tax effect can be calculated separately from the other three, either ahead of them or after them. And each such triplet of changes has the same analysis and the same variations in tax effect for individual changes that we have seen in the entire analysis that we have just gone through in this and the four earlier slides. 1:19:35 PM CO-CHAIR SADDLER asked for clarification to the same change in tax, $29,500, for both the revised and change in tax on slide 8. MR. WILLIAMS explained that when they were paired together it was $29,500, but if the previous slide was reviewed, he noted the total of $35,640, which, when $5,740 was subtracted, would leave $29,900 as the difference. He clarified that this was different than the $29,500 on slide 8, the result of calculating the pair. He declared that the point was that "even for a pair, its value changes depending on the order that you do with respect to the unpaired one." 1:20:32 PM REPRESENTATIVE SEATON compared this calculation to the education funding formula, as the regulations for both dictated the order for the calculations. He expressed his presumption that the Department of Revenue (DOR) had regulations for the order of the calculations for the production tax value. He pointed out that this was a "step-wise calculation" and he asked for the difference of this to any other important sequential formulas used by the state. MR. WILLIAMS responded that DOR had regulations about the order in which to take the tax credits, but there were not regulations for the order in which to calculate the tax. He declared that the aggregate amount was being used in this sensitivity analysis to compare the effects of changes on other parts, and that there was not a correct answer for the amount of tax on a particular parameter in the equation. REPRESENTATIVE SEATON opined that, as there had not yet been an audit, DOR needed to specify the order of calculations to allow an answer. 1:23:18 PM CO-CHAIR FEIGE pointed out that this assumption was not so much for the actual payment of the tax, but rather for the "what if" analysis when determining the effect on the company of an investment. MR. WILLIAMS agreed and explained that the tax calculation was simple, as it was all three components taken together, and it was affected by the sequence. He clarified that these were examples of investment scenarios when it was not possible to make all the individual changes. He stated that these "what if" analyses would not offer a clear answer, and could vary greatly when applied to many components. He noted that these differences were small until applied on a large scale. 1:25:14 PM CO-CHAIR SADDLER directed attention to slide 7, and asked for an explanation to the $35,640 total for all three taxes, which was different than the $34,760 when each was added together. MR. WILLIAMS replied that this was a result of the three numbers being calculated separately. 1:26:02 PM MR. WILLIAMS declared that the point of slide 7 was to show that for each of the categories, its respective tax effect could be calculated separately from the others. If you looked at one at a time, the effect for each triplet would vary, and the complexity would compound on itself, especially when the fourth category for capital expenditures was added. He stated that "each triplet will again have the same effect that the sum of the individual components will be smaller than the tax effect from looking at all three of them together... and if it sounds complicated, that's the problem." Directing attention back to slide 8, he stated: the tax effect for the entire triplet being greater than the sum of the effects for the individual categories in it; the different amount for the unpaired category in each triplet relative to the pair of other categories, depending on whether the effect of the pair is calculated first or second; and within each such pair, the different amount depending on which category in that pair is calculated first. Each of these numerous variations and combinations will divide the $35,640 total tax effect up into a different set of amounts calculated for the four categories. Yet even with all those sets of calculated amounts for the categories, none of those sets will add up to the tax effect for all the changes taken together as a whole. And all this complexity doesn't begin to reflect the likelihood that there may well be several different changes that could be made within one or more of these four basic cost categories. These bizarre effects are not mere abstract curiosities. If you are an investor and you have a variety of ways to try to improve the performance of an investment, these effects from progressivity mean there is no single correct answer about how much each one changes the tax and improves the investment. The more ways you have to improve the investment, the more the change in tax for each one depends on where you put it in the sequence of calculating the changes for all of the opportunities. This is because each opportunity in that sequence not only increases the PTV, but it also increases the progressivity rate applicable to the base case PTV plus all the PTV that has been added by the prior opportunities in the sequence. Interestingly, the Department of Revenue has exactly the same problem when it audits a taxpayer and makes multiple changes to figures reported on the tax return and increases the amount of tax. The auditor can quantify the whole tax increase from all the changes, but he or she cannot make a definitively correct determination of the amount of any one of those changes. A taxpayer might have an interesting time in an appeal having an auditor admit, issue by issue, that there is no correct amount for each one. 1:29:44 PM MR. WILLIAMS briefed the committee on slide 9, "Flat price scenario." There is a second unintended consequence of progressivity that is also important. I call it a tax on price volatility because it increases the tax when prices change during a tax year even though the total PTV is exactly the same as if the prices had stayed constant at the average price for the year. On this slide we see such a "flat price" scenario. To fit conveniently within the space available in a slide, the table omits columns for West Coast prices, transportation costs and field expenses, and starts instead with the PTV that is calculated from them. Here the PTV is $61.25 per barrel, and with 2 million barrels of production a month, the amount of the taxable PTV is $122.5 million a month. Progressivity starts when the PTV per barrel exceeds $30, and it reaches 25 percent at a PTV Progressivity starts when the PTV per barrel exceeds $30, and it reaches 25 percent at a PTV per barrel of $92.50. I have chosen $61.25 as the PTV per barrel in this base case because it is half way between $30 and $92.50. The progressivity rate at this price is $61.25 minus $30, or $31.25, times four tenths of a percentage point per dollar, or 12.5 percent. This also is half way between the zero rate at $30 and the 25% rate at $92.50. As you can see, each month the PTV is $122.5 million, the progressivity rate is always 12.5 percent, and the progressivity tax is exactly the same for each month as $15.31 million. Total progressivity for the year is $183.75 million. 1:31:22 PM MR. WILLIAMS moved on to slide 10, "Progressivity increases taxes with fluctuating price even when the economics don't change." In this next slide the left half is exactly the same as the previous one with the flat-price scenario. The right half of the table shows what happens when there are six months in the year when the PTV per barrel is $30 and six when it is $92.50. In this case the first three months and the last three have the $30 PTV per barrel, and the middle six from April through September have the $92.50. This price profile resembles what actually happened with West Coast prices for North Slope oil during 2008, when they peaked at the all-time record of $144.59 a barrel on July 3rd. For the six months when the PTV per barrel is $30, the progressivity tax rate is zero because $30 of PTV per barrel minus the $30 threshold for progressivity is zero. So, as you can see, there is no progressivity tax for the first three months of the year and the last three. In the middle six, the PTV per barrel is $92.50. That is $62.50 higher than the $30 threshold, so the progressivity rate is four tenths of a percentage point times 62.50, or 25.00 percent. At $92.50 a barrel, the progressivity tax on two million barrels a month is $46.25 million, so the total progressivity tax for the six non-zero months is $277.5 million. The progressivity tax under the changing-price scenario is 51 percent higher than the $183.75 million of progressivity for the flat-rate scenario. This tax increase is entirely the result of the fact that prices changed during the year instead of being flat. You can see this for yourselves. The total PTV for the year in the right-hand column is 1,470 millions of dollars, or $1.47 billion - exactly the same as in the flat-price scenario on the left. Total production for the year is exactly the same - 24 million barrels. Dividing $1.47 billion of PTV by 24 million barrels equals $61.25 per barrel, exactly the same. But progressivity is 51 percent higher. And if you look at the monthly calculations in the changing- price scenario, you can see that the monthly progressivity tax will be exactly the same for each of the $30 months no matter what order you put those months in. The same is true for the $92.50 months. So this phenomenon is different from what I showed you earlier about the whole being greater than the sum of its parts, because here there are no changes in the actual progressivity calculation for a $30 month or a $92.50 one. 1:34:31 PM MR. WILLIAMS continued: The bottom line here is this. The year under the changing-price scenario is just as profitable as the flat-price one, and for the same amount of production. The tax base to which progressivity applies is exactly the same for the year. Yet the tax is 51 percent higher when prices change during the year. Now, I have chosen these PTV-per-barrel figures so they would show the greatest amount of tax increase resulting from prices that are not flat all year long. I did this because, if I showed you an example with a smaller effect, someone would surely ask me what the maximum effect could be. My example gives you that answer at the same time it explains the phenomenon. 1:35:05 PM CO-CHAIR SADDLER asked to clarify that this reflected one real scenario. MR. WILLIAMS replied that it resembled what happened in 2008, as the year started out with lower prices, spiked in mid-year, and then declined later in the year. 1:35:37 PM REPRESENTATIVE SEATON noted that the monthly calculation was specifically designed as a windfall profits tax calculation. He asked to clarify that the objection was for the windfall profits section to progressivity which was calculated monthly to take into account this scenario of a huge spike, and not to the mechanics. MR. WILLIAMS clarified his objection, stating that there was no windfall for the year, as it was a yearly tax with estimated monthly payments. He stated that part of the reason was that the source was the calculation of progressivity with monthly prices and an average for the annual cost. 1:37:08 PM REPRESENTATIVE SEATON questioned whether this was a yearly tax or a monthly tax calculation with an annual true-up. MR. WILLIAMS agreed that it was part of the design, but he did not know if the intent was for the tax to add up for the year, without a windfall. He declared that the tax was potentially 51 percent higher because prices changed, and that the tax worked as if there was a windfall, even if there was not one. 1:38:31 PM REPRESENTATIVE HAWKER declared that it had been a conscious policy call of the legislature. MR. WILLIAMS recalled it had been intended to avoid tax payment when prices fell at the end of the year, instead using higher price estimates that had occurred earlier. He opined that there was not an intended effect for taxes merely because prices changed, but there was intent to provide tax relief for the installment payments at the end of the year if prices were going down. He offered an apology if he had misunderstood or mischaracterized the intent. REPRESENTATIVE HAWKER agreed that there was not a point to debate, although he emphasized that this was the way it was intended to work, "right or wrong, good or bad." 1:40:51 PM CO-CHAIR FEIGE expressed his belief that Mr. Williams' point that "it is the way it is" made a forecast much trickier. MR. WILLIAMS repeated that for one scenario there was still a 51 percent higher tax on the same production. 1:41:14 PM CO-CHAIR SADDLER offered a metaphorical comment that progressivity treated "the peak of a storm surge as the mean high tide level in taxes accordingly." MR. WILLIAMS agreed. 1:41:28 PM REPRESENTATIVE P. WILSON reflected that, with all the activity and amendments on the floor at the time of ACES, some members did not understand the ramifications. She offered her belief that there had not been adequate discussion for the relationships. 1:42:21 PM DAMIAN BILBAO, Head of Finance, BP Exploration (Alaska) Inc., affirmed that, whatever the intent, there were unintended consequences from this policy, one of those being that it was not possible to fix just one piece, as another piece would impact the model. He declared that it was not just progressivity, but the fundamental effect of each piece on each other, including the credits and the base rate. He emphasized that it was important to understand the effect of each factor on each other. 1:43:23 PM REPRESENTATIVE SEATON offered some background on the early decisions regarding progressivity. He stated that, as the original PPT bill was designed, progressivity was reviewed and established as a windfall profits component in the first committee of referral, the House Resources Standing Committee (HRES), and not on the House floor. He reported that, although the numbers may have changed, progressivity was included in ACES. He clarified that HRES had designed progressivity as a "fundamental building block" of the original PPT legislation, and it was ultimately included in ACES. 1:45:05 PM REPRESENTATIVE P. WILSON reflected that there had been discussion about a windfall tax. 1:45:18 PM CO-CHAIR FEIGE suggested a continuation of the presentation. 1:45:27 PM MR. BILBAO pointed out that this was an attempt to illustrate the impact of that intent, whatever that intent was, and how it affected the decision making. He declared that, as there was not a flat price, the average price produced a significantly different yearend tax, which had consequences for business decisions. 1:45:56 PM MR. WILLIAMS announced that, in light of this discussion, he would modify somewhat from his written testimony. He stated that progressivity had at least one unintended consequence, and another consequence that was larger than originally intended. He summarized: First, when you are analyzing combinations of steps to take to improve an investment opportunity, the whole is greater than the sum of its parts. Second, if you do not take into account the effect from price volatility during each year in an investment's life, the progressivity could turn out to be 50 percent higher than what you have estimated. Both of these unintended effects promise to increase the risks and reduce the competitiveness of an Alaskan investment relative to a comparable one elsewhere. These negatives of progressivity complement what AOGA told you during its testimony last Monday. Without repeating that testimony here, I will only list AOGA's main points. One, progressivity sacrifices the one advantage Alaska has from its economic remoteness - namely, the greater improvement in financial performance for investments here if prices turn out better than projected - because progressivity taxes away more and more of that improvement the better it turns out to be. And two, progressivity makes the tax extraordinarily complex and inconsistent to compute, and to analyze. For these reasons BP fully endorses the proposed repeal of progressivity that House Bill 72 proposes. 1:48:17 PM MR. WILLIAMS addressed slide 11, "Production Decline is Real," and continued with his testimony: Let me now turn to the second main feature in this Bill - the changes it proposes to the present system of tax credits, and in particular to the sunset of the credit for "qualified capital expenditures" or "QCE" at the end of this calendar year. The first, and probably most important observation I can offer about tax credits in general is they would not be so significant for the economics of oil and gas production here if the production tax were not so high. Second, the QCE tax credit depends solely on how much a company invests for oil and gas exploration, development and production in Alaska. Period. If you want to address the North Slope decline curve, there have to be investments here leading to more production - not just by finding and developing new fields and new reservoirs, but also by getting more recovery out of fields already in production. The QCE tax credit is a direct incentive for making these investments. And it costs the State nothing unless there are investments: if investment is zero, then 20 percent of zero is zero. The QCE tax credit arises only when it succeeds, and costs nothing if it doesn't. The QCE tax credit is not affected by oil prices, the costs of transporting oil and gas to market, nor the operating costs of the field. Consequently its value to a business like BP's is the same for a given amount of QCE expenditure, regardless of the price and the transportation and field operating cost scenarios that the business estimates in its investment decisions. And it is the same regardless of how prices and those other costs actually turn out. Progressivity, on the other hand, is dependent on prices and costs in a twofold way: once in determining the amount of PTV that is subject to tax, and again in calculating the tax rate that progressivity will apply to that PTV. Thus, the point where the cost of losing the QCE credit year begins to outweigh the benefit from repealing progressivity depends both on the price of oil and, for each individual producer, on that producer's own unique portion of the lease expenditures for the North Slope. 1:50:23 PM CO-CHAIR SADDLER, noting that this was a key point, requested it be repeated. MR. WILLIAMS repeated that "the point where the cost of losing the QCE credit year begins to outweigh the benefit from repealing progressivity depends both on the price of oil and, for each individual producer, on that producer's own unique portion of the lease expenditures for the North Slope." He then continued with his presentation: For BP's own business and expenditures, this crossover comes at a higher price level - in the mid to upper 90s - than that which Econ One and others are presenting for North Slope producers as a whole. So the improvement to our investment economics from the repeal of progressivity stands to be substantially undone by the sunset of the QCE tax credit. Since I am a tax man who is here to testify about this tax, I would ask, please, for your patience for just a few minutes if you have questions regarding this point, so I can quickly finish up and Mr. Bilbao can testify. The third major feature in HB 72 is its proposed "gross revenue exclusion" or "GRE" which is something new. It would exclude from the taxable PTV (production tax value) a percentage of the gross value at the point of production for additional or new volumes of oil or gas being produced. This concept could have significant potential, and indeed it may prove very valuable for explorers and others who can bring new fields and reservoirs into production. Unfortunately, the proposed GRE aims away from the significant opportunities for new production that BP has identified for its business. HB 72 would allow a GRE only for production "from a lease or property that does not contain land that was within a unit on January 1, 2003[,]" or if it does have land that was in a unit before 2003, "the oil or gas is produced from a participating area established after ... 2011 [that] does not contain a reservoir that had previously been in a participating area established before ... 2012." BP's business centers primarily around units that were established before 2003 - the Prudhoe Bay Unit, Kuparuk River Unit, Duck Island Unit and Milne Point Unit. These units are fully explored, and the likelihood is small that any significant new participating area will be established in them that "does not contain a reservoir that had previously been in a participating area established before ... 2012." So these units are unlikely to receive any GRE, as the Bill reads now. 1:52:56 PM CO-CHAIR FEIGE asked if this indicated that there were reservoirs within the unit and that a previous participating area was contracted. MR. BILBAO asked to clarify that the question was whether BP expected to see any producing areas extended in the future. CO-CHAIR FEIGE referred to the statement, "does not contain a reservoir that had previously been in a participating area established before ... 2012." He asked if there were reservoirs that had previously been in a participating area, but were no longer. MR. BILBAO, offering a short answer, stated that BP did not envision the necessity for expansion of any producing areas for the ongoing development of the fields. MR. WILLIAMS mused that the confusion could arise from his quote of the statute, rather than a paraphrase for clarity. CO-CHAIR FEIGE expressed his understanding. 1:54:38 PM REPRESENTATIVE TUCK, noting that some previously explored units would not qualify for the GRE, asked if BP planned for any new exploration. MR. BILBAO replied that the BP focus in Alaska was in the existing units, as these had more resource opportunity than anywhere in the world, other than the Lower 48. He stated that the concentration would be on development of those resources, not in exploration for new units, either on or off shore. 1:55:28 PM REPRESENTATIVE TUCK asked to clarify that the GRE would not benefit BP, specifically for the already explored units. MR. BILBAO expressed agreement that there was not an expectation for expansion, or creation of new producing areas, that would fall under this characterization. 1:56:02 PM MR. WILLIAMS, continuing with this presentation, stated: The present focus of the proposed GRE is misdirected. Econ One a week ago told you that an estimated 29.1 billion barrels of oil and barrel-equivalents of gas on the North Slope and offshore in the OCS is "Economically Recoverable @ $90/bbl". But, as AOGA pointed out it its testimony on Monday, only 10 percent of that resource is in an area that Alaska has any direct economic stake in and control over - the central North Slope. Of the 3 billion barrels there that Econ One identified, AOGA's testimony (in which we and the other members of AOGA all concurred) estimated that "2.5 billion barrels or more stands to come from Prudhoe Bay, Kuparuk and other legacy fields already in production" that have little or no chance of getting any GRE under the Bill. If you're going to hunt for eggs, you have to look where the hens nest. The same is true for oil. If you are going to provide an incentive to increase production rates and ultimate recovery, offer it where the oil is. There are several problems with the present ACES law that HB 72 does not address, and I will quickly brief you about them. The first is the disallowance under AS 43.55.165(e)(19) of "costs incurred for repair, replacement, or deferred maintenance" of production facilities "in response to a failure, problem, or event that results in the unscheduled interruption … or reduction in the rate of … production … or in response to … an unpermitted release of a hazardous substance or [natural] gas[.]" This was enacted in 2007 in response to the partial shutdown of Prudhoe Bay in 2006 after two corrosion-caused leaks were discovered. BP is not seeking change to the substance of the disallowance itself, but we think the statutory language should be improved to establish clarity about its applicability. There are minor hiccups in production operations almost every day in fields around the world, and Alaska's fields are no exception. The present statute sets no standard of materiality for an "unscheduled interruption .. or reduction" in production. If production at a facility is "interrupted" for five minutes because of a temporary hiccup in operations, does that cause a disallowed expense? If production is "reduced" by five barrels a day for a field producing over 400,000 barrels daily, does that cause a disallowed expense? If production is interrupted for a material period of time, but ultimately it turns out to cost only $10 to respond to it, is it worthwhile to identify and quantify this $10 so it can be disallowed? There is no answer to these and similar questions in the statute, and the Department of Revenue has not adopted regulations that answer them. We are not asking you to try to write the answers to these questions in the statute, although you certainly could if you want do to all that work. But we suggest, instead, that you expressly give the Department of Revenue not only the authority, but the duty, to adopt regulations that set reasonable thresholds for materiality about how long an "interruption" has to last, about how large a "reduction" in production has to be, about how much an unauthorized release has to be or in what circumstances must it occur, and about how much the cost "incurred … in response to" such situations has to be, in order to trigger the disallowance. As you know, I worked in the Department of Revenue some 30-odd years ago, and if I had to administer this statute in light of the circumstances and controversy that led to its enactment, I would be reluctant to adopt regulations on my own initiative to establish such thresholds unless I had some kind of go-ahead or permission from the Legislature. Perhaps the Department is waiting for such a sign from you. The second unaddressed problem comes from the changes that ACES made to AS 43.55.150, the statute that determines the gross value at the point of production on the basis of destination prices or values minus the costs of transporting the oil or gas to those destinations from the point of production in the field. As amended, the actual cost that a producer pays to a regulated pipeline carrier to ship the producer's oil could be set aside if the producer and carrier are "affiliated." The Department has adopted regulations calling for "cost-based" tariff calculations in lieu of the actual regulated tariffs that are paid. But under those regulations these calculations of the "cost-based" tariffs are made by the Department, not the taxpayer, and there is no deadline in the regulations or in AS 43.55.150 for the Department to make its calculations and share the results with the taxpayer. The only deadline is the six-year statute of limitations under AS 43.55.075(a). We concur with AOGA's testimony about the interplay between this six-year statute and interest at 11 percent APR, compounded quarterly, for any tax underpayment that, in this regulated-pipeline situation, might result from the Department's calculation of a lower tariff than the one allowed by the governmental regulatory agency having jurisdiction over that tariff. Six years at 11 percent almost doubles-up the amount of a tax increase from such a "cost-based" tariff. Further, the tax laws of the State are not an appropriate place for Alaska to try to regulate pipeline tariffs. That is a function of the Police Power, and the Regulatory Commission of Alaska has been established as the executive agency to exercise that regulatory power. The Federal Energy Regulatory Commission has similarly been created by Congress to regulate pipeline tariffs for interstate shipments under the Congressional power created by the United States Constitution power to regulate interstate commerce. State tax authorities have no business trying to supplant either of these agencies. Any further matters regarding HB 72 that we would bring to your attention have already been addressed by AOGA in its testimony to you on Monday. 2:03:46 PM MR. BILBAO added that the testimony had gone into detail for the committee to better understand the impacts when modeling for business investments. 2:04:12 PM REPRESENTATIVE SEATON, directing attention to slide 4, asked about the criteria for analysis which included a $30,000 reduction in field expense, and its impact through progressivity. He declared that the purpose of progressivity was to incentivize investment, yet the analysis portrayed a reduction in investment. He asked if lowering the investment in Alaska would cause a higher tax. MR. WILLIAMS expressed his agreement, stating that an incentive was not useful if its worth was unknown. He cited this as the point, that it was not possible to calculate the tax benefit for this investment. 2:05:40 PM REPRESENTATIVE SEATON pointed out that the slide indicated a lowering of a $30,000 investment in field cost operations, instead of increasing the investment. MR. WILLIAMS replied that the reduction had not been classified as a capital expense, and could be for efficiency, although the same problem still existed. He stated that efficiency should be encouraged, yet, in this instance, there was a penalty. 2:06:29 PM CO-CHAIR FEIGE suggested that efficiencies in the field could be attained through investments, yet he agreed that if it was difficult to quantify a savings, it would be difficult to justify an investment. MR. WILLIAMS expressed agreement that the calculated tax effects had to be quantified for certainty. MR. BILBAO added that efficiency and new technology both allowed for more economic production, and that this was beneficial to both the producer and the state. 2:08:38 PM REPRESENTATIVE HAWKER shared his concern that the axiom, "the power to tax necessarily involves the power to destroy," was being proven true by the State of Alaska. 2:09:15 PM REPRESENTATIVE TUCK reflected on the increase of the original Prudhoe Bay production estimate from 9 billion barrels of oil to 12 billion barrels, and asked how efficiency had produced more oil. MR. BILBAO replied that the efficiency was on a broad spectrum, and offered an example of rigs drilling more wells and doing it more efficiently, so that cost savings would be leveraged. He pointed out that the management of inflation to maintain the same production as the previous year was also a means for efficiency. 2:10:37 PM REPRESENTATIVE TUCK asked for a forecast for the oil production in Prudhoe Bay. MR. BILBAO replied that, first and foremost, "the resource opportunity in Alaska is tremendous, unparalleled" and that BP did not see many other greater opportunities for oil and gas. He declared that the challenge was above the ground surface, and he offered that the current forecast for recoverable oil in Prudhoe Bay was now 14 billion barrels. He pointed out that the fiscal policy would ultimately affect the amount of oil recovered in all the fields. 2:12:02 PM REPRESENTATIVE JOHNSON offered his belief that Alaska was penalizing companies for "doing good business," declaring that efficiency was not a bad thing. 2:13:13 PM REPRESENTATIVE SEATON pointed to the difficulties for the design of taxes which work to align interests on the North Slope. He referred to testimony by an engineering company that a project to enhance oil projects had been cancelled because one investor had declined to invest. He asked if it was possible to incentivize investment when there was misalignment between the three producers in Prudhoe Bay. MR. BILBAO declared that his experience in Alaska and elsewhere dictated that when a project made economic sense, everyone would quickly align. He reported that tax policy had a very clear impact on this, and suggested that there had not been enduring misalignment on specific field projects if the policy encouraged good projects. He stated that both the oil producers and the state would benefit. 2:15:04 PM REPRESENTATIVE SEATON clarified that he was not talking about alignment between the state and the producers in Prudhoe Bay, but rather between the operators themselves. He asked if tax policy would help drive the investments. MR. BILBAO emphasized that this legislature had the opportunity to make Alaska competitive for investment, which would affect the decisions of the working interest owners in any of the fields. He affirmed that if a fiscal policy allowed a project to be economic, then the working interest owners would agree to move the projects forward. He observed that a policy which tried to pick winners had the unintended consequence of creating misalignment. 2:18:06 PM SCOTT JEPSEN, Vice President External Affairs, ConocoPhillips Alaska, Inc., offered to discuss the Alaska tax framework for oil and gas production on the North Slope. He reviewed slide 2, "Topics," which listed the topics that he would discuss. MR. JEPSEN stated that he would start with the first topic, and he indicated slide 3, "Alaska Decline Continues While Lower 48 Production Continues to Increase." He pointed to the top line, which reflected oil production in the Lower 48 over the last 8 years, noting that the incredible resurgence driven by production increases in Texas and North Dakota correlated to the decline in Alaska. He observed that it was a natural question to ask what was happening. He explained that the Lower 48 had resources which included the shale and resurgence in the conventional drilling. He pointed that many of these were now viable as oil prices and technology had improved, both of which had tremendous economic impact on production. 2:20:44 PM MR. JEPSEN indicated that the other favorable point for production and investment in the Lower 48 was the tax framework, as there was a more equitable split of revenue between producer, investor, royalty owners, and government. As the prices went up, everyone shared. He pointed out that Alaska was different. There were resources, specifically in the legacy fields. Technology would always play a role in Alaska, and, although costs were a challenge, the technology helped make oil production economic. He noted the challenge for cost, as oil was far from market, in a remote, hostile environment. He observed that the current tax framework in Alaska was not an incentive for investment, and, although some aspects of ACES had merit, these did not offset the high progressivity and tax rate. 2:22:11 PM MR. JEPSEN introduced slide 4, "Alaska - A Challenging Investment Climate Investment Criteria: How Alaska Ranks." He stated that this addressed some of the investment questions for a company. He pointed to the arrows, either red or green, which rated each of the categories as favorable or not favorable. The first category, exploration potential, was not favorable as the average field size discovery was now only about 100 million barrels, which did not compare with the multi-billion barrel prospects found elsewhere. He addressed the next category, costs, and reported that this was challenging in Alaska, as the transportation costs were high, and the North Slope was a hostile environment for business in the winter and environmentally sensitive in the summer. He compared this to the simplicity of operating in Texas. He pointed to the next category, cycle time, noting that it took a much longer time to bring a well into production in Alaska, and that this was also an unfavorable rating. He offered an example of the more than 10 years to bring on the new drill site at the Alpine Field, stating that it took "pretty deep pockets, a lot of staying power, in order to do business in an environment where you have those kinds of cycle times." 2:25:25 PM MR. JEPSEN moved to the next category on slide 4, Taxes, offering his belief that Alaska's tax environment did not encourage investment. He reported that ACES took away the upside, even with the tax credits to offset some of the costs. He declared that long term cash flow was a criterion for investment, and that ACES did not incentivize investment. MR. JEPSEN summarized the last category, Legacy Field Opportunities, which he declared to be a very big positive for Alaska, as there was tremendous resource potential. He announced that investments for near term production to stop the decline would focus on these fields. He affirmed that the legislature could "do something about taxes if it so chooses," which would help to equalize the investment playing field by making taxes comparable to other places that were attracting large amounts of capital. He encouraged the legislature to consider providing investment incentives, and to spread them across the board, which would include investment in the legacy fields. 2:27:00 PM MR. JEPSEN indicated slide 5, "Alaska Legacy Fields Still Provide Significant Opportunity." He reported that this graph was taken from the 2009 DOR production forecast data for 2010 - 2050. He pointed out that the majority of the resource lies in the legacy fields: Kuparuk, Prudhoe, and Alpine areas, with more than 4 billion barrels of expected future production, which offered the "greatest bang for the buck for investment." MR. JEPSEN considered slide 6, "Alaska's Days of 'Easy Oil' Are Gone: High Costs and High Government Take Present Challenges," which had been prepared by PFC Energy, and compared costs between Alaska and the Lower 48. He pointed out, as it cost half as much to drill in the Lower 48 than Alaska, with lower taxes, that it was a simple equation for where to invest. 2:28:55 PM MR. JEPSEN explained slide 7, "Easy Oil In the Legacy Fields Is Gone," and stated that the first wells were relatively straight forward. He affirmed that this had changed, and although there was still a lot of oil, it was trapped in isolated fault blocks and other places, which required complicated high cost wells. He agreed that the complicated new wells in the legacy fields were still cheaper than drilling new grass root wells. He stated that the reserve targets were smaller, and they were pursuing the satellite fields, which had added a lot of production to the North Slope. He noted, however, that development of the satellite fields often required new infrastructure, new pipelines, and long cycle times, which was all more expensive than drilling in existing facilities. He reported that viscous oil was also being developed, with almost 15,000 barrels each day online in Kuparek. He said that this will be a long term continuous evolvement of technology before this viscous oil resource can be fully developed. He acknowledged that wells were also producing water, as water was often injected to push oil out of the reservoir, and this increased the cost for oil production. He summarized that the days of low cost, straight forward well bores for 100 percent oil were gone, and the focus was now on oil production that required good prices, good technology, and a good tax environment. 2:32:03 PM MR. JEPSEN reported that the initial Alpine development cost about $1.4 billion in 2000, with 92 wells, 2 satellite drill sites, connecting roads, pads, an airstrip, pipelines, and facilities and had initial production of about 80,000 barrels each day. He compared this to a similar CD-5 type development which would have 16-22 wells, with small test facilities, and pipelines, and would produce 15 - 18,000 barrels at peak rate, and noted the increase in the cost of doing business on the North Slope. MR. JEPSEN concluded that progressivity was "really a big disincentive for investment here in the state." He reported that proposed HB 72 did address this, but the elimination of tax credits would still disadvantage Alaska, as the cost of doing business was so much higher. He suggested that incentives for investment, specifically in the legacy fields, would be a necessary key component in a tax policy. 2:34:15 PM REPRESENTATIVE P. WILSON asked about the cost for the CD-5 type development. MR. JEPSEN replied that the new development would cost about $1 billion. 2:34:43 PM BOB HEINRICH, Vice President Finance, ConocoPhillips Alaska, Inc., began with a review of the positive elements of Alaska's Clear and Equitable Share (ACES), slide 8, "ACES Observations." He stated that the tax credits were an important aspect of the structure of ACES, as they offset a small part of the high tax rates which resulted from the calculations. He declared that a large amount of the credits had gone toward exploration, although the producers also used them to offset the high cost environment. He pointed out that the tax credits also applied to both the new fields and the legacy fields. He explained that these tax credits were not enough to offset the high average and high marginal tax rates which resulted from progressivity. He noted that the gross minimum tax also demanded a tax, often when the revenue did not cover the cost. He directed attention to the graph of marginal shares on slide 8, which depicted the industry, federal, and state shares per barrel of oil from a range of prices under ACES. He reported that, under the current price environment of $110 per barrel, the marginal tax rate was about 80 percent. He referred to the lower chart on slide 8, representing the ConocoPhillips earnings per barrel, which ranged from $22 - $25 per barrel, even as the price had ranged from $60 - $110 per barrel. He stated that the majority of the upside had been paid to the State of Alaska. 2:37:17 PM MR. HEINRICH presented slide 9, "ConocoPhillips Capital Allocation," which graphed investments in Alaska and the Lower 48. He declared that, although there were "great new opportunities" in the Lower 48, the reason for significant investment there was for the cash return, more than a 50 percent greater return than in Alaska. He stated that the trend of investment for the greatest profit opportunity would continue. He reported that ConocoPhillips had invested more than $20 billion since 2000 in Alaska activities, however the current investments were "into liquids rich oil plays, which generates substantially better margins." Alaska was still an important part of the portfolio, but ACES was preventing a greater capital investment. 2:38:35 PM MR. HEINRICH offered slide 10, "Producer Share under HB 72," which analyzed the difference between ACES and HB 72 on a producer share basis, defined as "the available cash after cost and taxes that are retained by the producers." He declared this to be the inverse of the state or government share. He explained that the producer share was affected by assumptions on capital spending and operating costs, which could vary from field to field and from producer to producer. He reported that this graph used 2012 revenue sources data, which represented all the producers with a tax liability on the North Slope. He clarified that the graph was projected for the single year FY 2014, and was not a field life or a five year calculation. He opined that the first year of a forecast was the most reliable. He pointed out that the crossover point for the two tax systems, HB 72 and ACES, was about $93 per barrel and that above that price, HB 72 produced a higher percentage share from the producer perspective. Below this price line essentially resulted in a tax increase for the producers. This had forced the producers to analyze the effects of the proposed bill, which would trade off the benefits of a better tax environment at higher prices with a worse tax environment at prices slightly lower than the current price per barrel. He declared that it was important for project analysis to review a probable range of prices. He noted that the shape of the curve was similar to that in many of the Lower 48 states, but that Alaska's high operating cost environment did not tilt the equation toward Alaska investments. He suggested that a flattening of the curve would lower the tax increase at lower prices, and that expansion of the incentives for legacy fields would also "improve the likelihood of the state achieving its goals." 2:41:46 PM MR. HEINRICH summarized his observations of proposed HB 72, slide 11, "Recap of ConocoPhillips Perspective." He reported that, under ACES, progressivity took away the price upside, and discouraged investment; although the tax credit structure did reduce the overall effective tax rate, it was not enough to offset the negative effects of progressivity at higher prices. He declared that proposed HB 72 was a positive step toward an improved investment climate, as the elimination of progressivity resolved the problem of the high marginal tax at increased prices and made Alaska more competitive at those higher prices, which he defined as more than $100 barrel. He noted that the proposed bill made Alaska less competitive than ACES at lower prices, and it represented a tax increase to the producers. He declared that the gross revenue exclusion was not broad enough to incentivize new production, as it did not include the legacy fields, where the vast majority of future production was expected. 2:43:02 PM REPRESENTATIVE P. WILSON asked how many years after investment would it take for an increase in production. MR. JEPSEN recognized the necessity for the producers to respond to a positive tax structure. He shared that it was possible to more quickly bring on a new drill rig than to build a new drill site, although there were plans and ideas for projects after a change in the tax environment. He offered his belief that the closest differential time frame would be 1 - 2 years, with other projects coming on line at later dates. He pointed out that there was already a high demand for drilling equipment, given the high price of oil, but that an incentive for investment would be actively pursued. 2:45:00 PM CO-CHAIR SADDLER directed attention to the investment criteria on slide 4, and asked which was the most important consideration for investment. MR. JEPSEN replied that these criteria were in order of occurrence, as each determined the next stage. CO-CHAIR SADDLER asked which was the most important to consider. MR. JEPSEN, in response, stated that there was not an absolute answer as it was a function of the fit for all the variables. 2:46:57 PM REPRESENTATIVE SEATON identified slide 10, and asked why the projected oil price of $93 per barrel differed from the Palantir projection of $120 per barrel as the crossover point. He asked if this price was production tax value. MR. HEINRICH responded that the price depended on the assumptions made for cost of capital. He declared that these prices represented the undiscounted cash flow for FY 2014. He stated that he was not aware of the presentation, noting that it was important to make sure both were for the same time durations. 2:48:57 PM REPRESENTATIVE SEATON asked to clarify that it was for the full life cycle of a capital intensive project by a producer. MR. HEINRICH replied that it was based on a portfolio perspective from DOR sources. 2:51:02 PM DAN SECKERS, Tax Counsel, ExxonMobil Corporation, directed attention to his submitted written testimony, [Included in members' packets] and he invited any questions to that testimony. He offered to summarize the ExxonMobil perspective for proposed HB 72, and declared support for the earlier testimonies from BP and ConocoPhillips. He endorsed the efforts of the governor and the legislature for examining the Alaska investment climate, specifically ACES. He emphasized that Alaska was no longer competitive hence it was not attracting the necessary investments. For ExxonMobil, it was necessary for any effective tax policy to address two main components of ACES, progressivity and the overall high government take. He noted that the producers agreed that these were a major disincentive to move any investment opportunities forward. He affirmed that proposed HB 72 offered significant progress toward making the Alaska investment climate more competitive. He stated that progressivity created complexities, and it took away a lot of the upside potential that other tax jurisdictions allowed the producers to retain. He assessed that this was important in Alaska, as the costs were high, and the investments long term, high risk, and capital intensive; therefore, mitigation for this was the upside potential. He stressed that the elimination of progressivity was a significant improvement, and would allow Alaska to be more competitive and increase investment. He reported that the gross revenue exclusions did not apply to the legacy fields, and that it was important to incentivize both new production and existing fields. He pointed out that a small increase in the recoverable reserves at Prudhoe Bay would dwarf any new field on the North Slope. He confirmed that, although proposed HB 72 offered significant progress, there were still some concerns. He noted that the base rate was still too high. Benchmarking government take against other regimes was important, but it did not tell the entire picture, as Alaska had some of the highest costs. He offered his belief that Alaska should strive to make companies want to invest in Alaska, as the other factors were all deterrents. 2:57:09 PM MR. SECKERS addressed the issue for tax credits, recognizing the necessity to balance long term state needs with wide band price scenarios. He stated that tax credits offered investors that opportunity, as it downsized risks, and mitigated the costs for capital investments. He suggested consideration for the maintenance of the tax credits. He stated that the gross revenue exclusions should be expanded to cover all the fields, not just new fields, and that the base tax rate should be reviewed and compared with other states. He conveyed that Alaska was important to the ExxonMobil long term investment portfolio, and they looked forward to staying in Alaska. He cited that it was critical that Alaska continue to exam its oil tax policies. He asked if the Alaska legislators were comfortable with "the path Alaska's currently on." He summarized that any encouragement for investment in Alaska should be examined to improve the investment climate, and he declared that proposed HB 72 was "a good step in that direction." 2:59:16 PM REPRESENTATIVE SEATON asked if a change for the base tax rate to an equivalent of 17 percent would be less complex than broad application for the gross revenue exclusions. MR. SECKERS replied that this was a part of the necessary analysis for the legislature. He offered his belief that taxation was just math, and could be made to work in a number of different ways. He shared that the question should be for competitiveness, with a goal to make Alaska attractive for investors. 3:00:49 PM REPRESENTATIVE SEATON, referring to the call for the elimination of progressivity, asked whether, if the upside potential was eliminated for the state, the floor amount should be changed so that the oil industry had some downside risk as a balance. MR. SECKERS agreed it was a difficult challenge to balance the tax structure across all prices. He opined that the floor, as it was based on gross, could be exceptionally harsh, and could lead to a tax situation even though there was not any profit. He stated that progressivity was the most punitive aspect of ACES, and to address that issue was a step in the right direction. 3:02:24 PM CO-CHAIR SADDLER asked to what degree ExxonMobil Corporation would require durability for tax policy. MR. SECKERS replied that stability was very important to Exxon Mobil, although it was only as good as the cost it came under. He said that investment decisions were impacted by continual regulatory changes. He commented that any changes had to make Alaska more competitive. 3:03:50 PM REPRESENTATIVE TUCK asked how long ago Texas and North Dakota had changed their tax policies in order to have the current level of production. MR. SECKERS stated that he did not know the historical tax treatments for either of those states, or how often either had changed its system. He opined that neither had made many recent changes, but their systems were "a lot more favorable." He added that the dynamics of new technology and the increase in oil price had made both places more attractive. 3:05:31 PM REPRESENTATIVE TUCK asked how much more quickly was the turnaround time for unconventional oil development to production in Texas and North Dakota. MR. SECKERS offered his belief that the turnaround time would be quicker in the Lower 48. 3:06:31 PM REPRESENTATIVE SEATON detailed that some consultants had stated that the return on capital employed was the most important factor, and asked what the most important factor was for ExxonMobil. MR. SECKERS explained that the decision making process, for ExxonMobil, was confidential, although they reviewed a wide spectrum. He expressed agreement with ConocoPhillips that there was no one lynchpin factor for decision making. [HB 72 was held over.] 3:08:07 PM ADJOURNMENT There being no further business before the committee, the House Resources Standing Committee meeting was adjourned at 3:08 p.m.

Document Name Date/Time Subjects
HRES HB 72 ExxonMobil 2.20.13.pdf HRES 2/20/2013 1:00:00 PM
HB 72
HRES HB72 BP 2.20.13.pdf HRES 2/20/2013 1:00:00 PM
HB 72
HRES HB 72 BP Written Testimony 2.20.13.pdf HRES 2/20/2013 1:00:00 PM
HB 72
HRES HB 72 ConocoPhps 2.13.20.pdf HRES 2/20/2013 1:00:00 PM
HB 72