Legislature(2015 - 2016)BUTROVICH 205

04/11/2016 03:30 PM RESOURCES

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Audio Topic
03:30:58 PM Start
03:31:38 PM SB130
03:32:25 PM Continuation of the Second Presentation: Additional Modeling and Scenario Analysis by Dor
08:08:34 PM Adjourn
* first hearing in first committee of referral
+ teleconferenced
= bill was previously heard/scheduled
+= HB 247 TAX;CREDITS;INTEREST;REFUNDS;O & G TELECONFERENCED
<Pending Referral> -- Invited Testimony Only --
+= SB 130 TAX;CREDITS;INTEREST;REFUNDS;O & G TELECONFERENCED
Heard & Held
-- Testimony <Invitation Only> --
+= HB 216 NAVIGABLE WATER; INTERFERENCE, DEFINITION TELECONFERENCED
Scheduled but Not Heard
-- Public Testimony --
+ HCR 17 SUPPORT AVIATION INDUSTRY; USE STATE LAND TELECONFERENCED
Scheduled but Not Heard
-- Public Testimony --
+ Bills Previously Heard/Scheduled TELECONFERENCED
                    ALASKA STATE LEGISLATURE                                                                                  
              SENATE RESOURCES STANDING COMMITTEE                                                                             
                         April 11, 2016                                                                                         
                           3:30 p.m.                                                                                            
                                                                                                                                
                                                                                                                                
MEMBERS PRESENT                                                                                                               
                                                                                                                                
Senator Cathy Giessel, Chair                                                                                                    
Senator Mia Costello, Vice Chair                                                                                                
Senator John Coghill                                                                                                            
Senator Peter Micciche                                                                                                          
Senator Bert Stedman                                                                                                            
Senator Bill Stoltze                                                                                                            
Senator Bill Wielechowski                                                                                                       
                                                                                                                                
MEMBERS ABSENT                                                                                                                
                                                                                                                                
All members present                                                                                                             
                                                                                                                                
OTHER MEMBERS PRESENT                                                                                                         
                                                                                                                                
Representative Mark Neuman                                                                                                      
Representative Tammie Wilson                                                                                                    
                                                                                                                                
COMMITTEE CALENDAR                                                                                                            
                                                                                                                                
HOUSE BILL NO. 247                                                                                                              
"An Act  relating to confidential  information status  and public                                                               
record status  of certificates  from the oil  and gas  tax credit                                                               
fund; relating  to a  minimum for gross  value at  information in                                                               
the  possession  of  the  Department   of  Revenue;  relating  to                                                               
interest the point of production;  relating to lease expenditures                                                               
and  tax  credits for  municipal  applicable  to delinquent  tax;                                                               
relating  to disclosure  of  oil and  gas  production tax  credit                                                               
entities;   adding   a    definition   for   "qualified   capital                                                               
expenditure"; adding  a definition  for information;  relating to                                                               
refunds for  the gas storage  facility tax credit,  the liquefied                                                               
"outstanding  liability  to the  state";  repealing  oil and  gas                                                               
exploration incentive  credits; natural gas storage  facility tax                                                               
credit,  and the  qualified in-state  oil refinery  repealing the                                                               
limitation on  the application of  credits against  tax liability                                                               
for  lease infrastructure  expenditures tax  credit; relating  to                                                               
the minimum tax for certain  oil and expenditures incurred before                                                               
January  1,  2011;  repealing  provisions   related  to  the  gas                                                               
production; relating  to the minimum tax  calculation for monthly                                                               
installment monthly  installment payments  for estimated  tax for                                                               
oil and gas  produced before payments of  estimated tax; relating                                                               
to interest on  monthly installment payments of  January 1, 2014;                                                               
repealing the  oil and  gas production  tax credit  for qualified                                                               
capital   estimated  tax;   relating  to   limitations  for   the                                                               
application of tax credits; relating  to oil and expenditures and                                                               
certain well expenditures; repealing  the calculation for certain                                                               
lease  gas   production  tax  credits  for   certain  losses  and                                                               
expenditures;   relating   to    limitations   for   expenditures                                                               
applicable before January 1,  2011; making conforming amendments;                                                               
and nontransferable oil  and gas production tax  credits based on                                                               
oil  production  and  the  providing   for  an  effective  date."                                                               
alternative tax credit  for oil and gas  exploration; relating to                                                               
purchase of tax credit                                                                                                          
                                                                                                                                
     - <PENDING REFERRAL> -- INVITED TESTIMONY ONLY --                                                                          
                                                                                                                                
SENATE BILL NO. 130                                                                                                             
"An Act  relating to confidential  information status  and public                                                               
record status  of certificates  from the oil  and gas  tax credit                                                               
fund; relating  to a  minimum for gross  value at  information in                                                               
the  possession  of  the  Department   of  Revenue;  relating  to                                                               
interest the point of production;  relating to lease expenditures                                                               
and  tax  credits for  municipal  applicable  to delinquent  tax;                                                               
relating  to disclosure  of  oil and  gas  production tax  credit                                                               
entities;   adding   a    definition   for   "qualified   capital                                                               
expenditure"; adding  a definition  for information;  relating to                                                               
refunds for  the gas storage  facility tax credit,  the liquefied                                                               
"outstanding  liability  to the  state";  repealing  oil and  gas                                                               
exploration incentive  credits; natural gas storage  facility tax                                                               
credit,  and the  qualified in-state  oil refinery  repealing the                                                               
limitation on  the application of  credits against  tax liability                                                               
for  lease infrastructure  expenditures tax  credit; relating  to                                                               
the minimum tax for certain  oil and expenditures incurred before                                                               
January  1,  2011;  repealing  provisions   related  to  the  gas                                                               
production; relating  to the minimum tax  calculation for monthly                                                               
installment monthly  installment payments  for estimated  tax for                                                               
oil and gas  produced before payments of  estimated tax; relating                                                               
to interest on  monthly installment payments of  January 1, 2014;                                                               
repealing the  oil and  gas production  tax credit  for qualified                                                               
capital   estimated  tax;   relating  to   limitations  for   the                                                               
application of tax credits; relating  to oil and expenditures and                                                               
certain well expenditures; repealing  the calculation for certain                                                               
lease  gas   production  tax  credits  for   certain  losses  and                                                               
expenditures;   relating   to    limitations   for   expenditures                                                               
applicable before January 1,  2011; making conforming amendments;                                                               
and nontransferable oil  and gas production tax  credits based on                                                               
oil  production  and  the  providing   for  an  effective  date."                                                               
alternative tax credit  for oil and gas  exploration; relating to                                                               
purchase of tax credit                                                                                                          
                                                                                                                                
     - HEARD & HELD                                                                                                             
                                                                                                                                
CS FOR HOUSE BILL NO. 216(RES)                                                                                                  
"An Act relating  to obstruction or interference  with a person's                                                               
free  passage on  or use  of  navigable water;  and amending  the                                                               
definition of 'navigable water' under the Alaska Land Act."                                                                     
                                                                                                                                
     - SCHEDULED BUT NOT HEARD                                                                                                  
                                                                                                                                
CS FOR HOUSE CONCURRENT RESOLUTION NO. 17(TRA)                                                                                  
Supporting  the aviation  industry;  and urging  the governor  to                                                               
make state-owned land available  to the unmanned aircraft systems                                                               
industry for  the management and  operation of  unmanned aircraft                                                               
systems  and   related  research,  manufacturing,   testing,  and                                                               
training.                                                                                                                       
                                                                                                                                
     - SCHEDULED BUT NOT HEARD                                                                                                  
                                                                                                                                
PREVIOUS COMMITTEE ACTION                                                                                                     
                                                                                                                                
BILL: SB 130                                                                                                                  
SHORT TITLE: TAX;CREDITS;INTEREST;REFUNDS;O & G                                                                                 
SPONSOR(s): RULES BY REQUEST OF THE GOVERNOR                                                                                    
                                                                                                                                
01/19/16       (S)       READ THE FIRST TIME - REFERRALS                                                                        

01/19/16 (S) RES, FIN 04/04/16 (S) RES AT 3:30 PM BUTROVICH 205 04/04/16 (S) Heard & Held 04/04/16 (S) MINUTE(RES) 04/05/16 (S) RES AT 3:30 PM BUTROVICH 205 04/05/16 (S) Heard & Held 04/05/16 (S) MINUTE(RES) 04/06/16 (S) RES AT 3:30 PM BUTROVICH 205 04/06/16 (S) Heard & Held 04/06/16 (S) MINUTE(RES) 04/07/16 (S) RES AT 3:30 PM BUTROVICH 205 04/07/16 (S) Heard & Held 04/07/16 (S) MINUTE(RES) 04/08/16 (S) RES AT 3:30 PM BUTROVICH 205 04/08/16 (S) Heard & Held 04/08/16 (S) MINUTE(RES) 04/09/16 (S) RES AT 9:00 AM BUTROVICH 205 04/09/16 (S) Heard & Held 04/09/16 (S) MINUTE(RES) 04/09/16 (S) RES AT 2:30 PM BUTROVICH 205 04/09/16 (S) Heard & Held 04/09/16 (S) MINUTE(RES) 04/11/16 (S) RES AT 3:30 PM BUTROVICH 205 WITNESS REGISTER RANDALL HOFFBECK, Commissioner Department of Revenue (DOR) POSITION STATEMENT: Commented on SB 130. KEN ALPER, Director Tax Division Department of Revenue (DOR) Anchorage, Alaska POSITION STATEMENT: Commented on SB 130. AKIS GIOLOPSOS, staff to Senator Giessel and the Senate Resources Committee Alaska State Legislature Juneau, Alaska POSITION STATEMENT: Explained the changes in work draft \W to SB 130. JANAK MAYER, Partner enalytica Legislative Consultant Washington, D.C. POSITION STATEMENT: Commented on SB 130. ACTION NARRATIVE 3:30:58 PM CHAIR CATHY GIESSEL called the Senate Resources Standing Committee meeting to order at 3:30 p.m. Present at the call to order were Senators Costello, Stedman, Coghill, Wielechowski, and Chair Giessel. SB 130-TAX;CREDITS;INTEREST;REFUNDS;O & G [Contains discussion of the companion bill HB 247.] 3:31:38 PM CHAIR GIESSEL announced consideration of SB 130 and advised that the Department of Revenue would continue the Second Presentation: "Additional Modeling and Scenario Analysis" dated April 4, 2016, starting on slide 17. 3:31:55 PM SENATOR MICCICHE joined the committee. 3:32:01 PM RANDALL HOFFBECK, Commissioner, Department of Revenue (DOR), introduced himself. ^Continuation of the Second Presentation: Additional Modeling and Scenario Analysis by DOR 3:32:25 PM KEN ALPER, Director, Tax Division, Department of Revenue (DOR), Anchorage, Alaska, introduced himself and explained that he went back to slide 16, because it refreshes the conversation they are in. Going forward the next several changes would be on the subject of what they mean when they "strengthen" or "harden" the floor on the minimum tax. He explained that the carry forward NOLs present three different policy questions (slide 16). The first about the major producers that can't get cash for their NOLs as opposed to the small producers who can. They have discovered that those NOLs could be carried forward into the next year and be used to offset the minimum tax, effectively bringing tax payments down to zero. Preventing that from happening is one component of hardening the floor where the producers pay the full minimum tax and then carry forward those credits into a subsequent year where there would be enough tax liability to offset them. The second question deals with gross value reduction (GVR) for new oil. On those fields the issue is not the NOLs, but the per taxable barrel credit for legacy fields, what is currently hardened at the floor. That number cannot go below the 4 percent level. However, on the new oil fields the $5/barrel credit can go below the floor, and companies could effectively pay zero using those. SB 130 "hardens" the floor, as well, against that condition. The final question is a much smaller issue, especially because these credits are sunsetting: should the small producer credit and exploration credits be usable to reduce payments for any producer below the 4-percent floor. 3:33:41 PM SENATOR STOLTZE joined the committee. 3:33:59 PM SENATOR STEDMAN asked how much the small producer credit and the exploration credit alternative was in 2016 and 2017, so people at home can grasp the magnitude of what they are talking about. MR. ALPER explained in the universe of $40/oil, the gross value of is $30/barrel, presuming $10 for transportation. The department's rule of thumb number is that there are about 160 million taxable barrels produced per year from the North Slope, so calculation is 500,000 barrels/day times the year, minus the royalty barrels. So, 160 million barrels times $30 equals $4.8 billion, which is the gross value at the point of production. A 4 percent gross tax on that is $200 million. So, the total scope of what they are talking about peaks out at about $200 million. Within their forecast about $150 million will be lost to the NOL credits being used to go below the floor. The small producer and exploration credits are a very small, $10-15 million, and similarly the new oil part probably is about $25 million. 3:36:14 PM Preventing the companies from applying the NOL against the minimum tax is about their total lease expenditures exceeding their gross value at the point of production. That means they have negative income, or a loss, as defined in the Alaska production tax statutes. That will be different in general from what companies might show to their own stockholders, because of the way the state treats capital expenditures (it uses different accounting nuances). Often capital expenditures are treated on a cash-flow based, retained-earnings based calculation versus federal filings. MR. ALPER explained that the NOL is calculated on a calendar tax year and the idea is to ensure that any NOLs that aren't used to reduce the taxes below the minimum tax would be carried forward. So effectively, the state would be paying the credit not in the first year, but in whatever year the price of oil goes up subsequently, so that there is enough taxes to reduce it, but still stay above the 4 percent floor. 3:37:56 PM MR. ALPER presented slides 18-21 showing how the production tax works at $100/oil, $70/oil and $40/oil. The $100/oil is in some ways what the modeling looked like when they were last talking seriously about oil taxes with $10 for transportation cost and $90 gross value. The state receives about $35/oil in lease expenditures (operating and capital), which works out to a production tax value of $55 (what the tax calculation is based on), a 35 percent tax results in $19.25, less the $6 per-barrel credit. That means the state actually receives $13.25. But here a comparison is made to the 4-percent minimum tax, the floor, which results in $3.60, and since the state receives the "higher of," the actual tax it receives is $13.25 (on a gross of $90). That is multiplied by the 160,000 million. That would mean production tax revenue in a year of $100/oil would be around $2.1 billion. 3:38:48 PM CHAIR GIESSEL recognized Senator Bishop in the audience. MR. ALPER said at $70/barrel (slide 19), suddenly the minimum tax becomes a relevant part of the calculation. The transportation and lease expenditures are the same ($35) and result in a $60 gross value and that leaves a $25 net. Applying a 35-percent tax that net results in a tax of $8.75. The per- barrel credit applied here is the maximum level of $8.00 and results in a net payment of $0.75 per barrel. So, what takes precedence (in the "higher of" situation) is the minimum tax (4 percent of that $60 gross), which results in $2.40 or approximately $380 million per year in production tax revenue - still in the realm of positive numbers. At $40/oil, Mr. Alper explained, companies start suffering operating losses (slide 20). So if it costs $45 to produce and transport it to market, that results in a negative $5/barrel. This results in an aggregate number of $800 million per year in NOLs for the North Slope producers. Meanwhile the tax calculation effectively generates a negative number (-$1.75) and the minimum tax (4 percent of the $30 gross) results in $1.20. So, the "higher of" is $1.20 and that times the volume comes out to $190 million (roughly the $200 million he said in response to Senator Stedman's question). 3:40:40 PM Meanwhile, there is a $280 million carried forward loss into the second year. So, slide 21 shows what happens in a second consecutive year of low prices. The same calculation happens and results in $190 million in tax liability. Only now the $280 million in carried forward NOLs from year one gets used to offset that $190 million tax bill making the actual tax to the state zero. Another $90 million more remains to be carried forward, plus another $280 million earned in year 2 leading to $370 million carried forward into year three. And as long as prices stay low like that, "these NOL credits sort of stack up on us," Mr. Alper explained. The DOR's forecast shows about $750 million in stacked-up NOLs in 2018/9 before the price recovers sufficiently to where the companies start buying them down again. CHAIR GIESSEL asked if this assumes that a company that just suffered $800 million in operating losses will continue to do the same thing and expect different results in year two even though none of the variables have changed. MR. ALPER answered yes; the department doesn't forecast short term changes in behavior in their modeling. They get updates from companies twice a year and that gets built into their modeling going forward. To a certain extent, companies are reducing their expenditures through the laying down of rigs, but the labor that it takes to pump the existing oil is going to continue to be spent. However, companies will start to constrain their costs and the department expects that a loss will be lower in a second consecutive year. SENATOR COSTELLO asked at what year does the department forecast the price will be $70/barrel or above. MR. ALPER answered that the chart she was referring to goes out as far as the spring forecast for just 2025 when it is in the high $60s. Using the normal inflationary trend, he guessed it would go to $70 in 2026. SENATOR WIELECHOWSKI said SB 130 does not address the $8/per barrel credit in any way and asked how much the state is allowing to be deducted at $70/barrel through the per barrel credit. MR. ALPER answered that the tax is officially calculated by the companies that use the per-barrel credit until the tax bumps up against the minimum tax. So, on slide 19, the answer would $6.35. So, they would use $6.35 to bring the taxes down to the $2.40 minimum tax level. Then they would lose the rest of that credit. 3:44:24 PM SENATOR WIELECHOWSKI asked if the state did not have any per- barrel tax credit, how much more would it be getting at $6.45 per barrel in the $70/oil scenario. MR. ALPER answered the $8.75 in tax times the production volume would result in little bit less than $1.5 billion in revenue. A more appropriate comparison would be the flat $5/barrel credit in the original version of SB 21. In that scenario, at $70/oil, the state would see $3.75 as the net and the minimum tax wouldn't be triggered at the $70 level. That would lead to about a $600 million in revenue or $200 million more than in the example before them. 3:45:28 PM SENATOR WIELECHOWSKI asked if the state was allowing about $1.5 billion to be deducted at $70/oil with a per-barrel credit of $8. MR. ALPER answered that the $1.5 billion was with no per-barrel credit and $400 million in revenue. So, the difference is closer to $1.1 billion. SENATOR STEDMAN said another way of looking at it might be the marginal difference between the $5 and the $8 sliding scale that holds one in the minimum tax for another $10 extra in price range. MR. ALPER said that is a fair statement and that having that higher and steeper per barrel credit tends to make that crossover a higher price point. SENATOR MICCICHE asked for the actual crossover point. MR. ALPER answered that the current forecast has the crossover at $78/barrel. SENATOR MICCICHE answered that they had not modeled it within the current forecast. They were modeling it in 2013 based on their assumptions at the time, but he didn't have that in front of him now. 3:47:24 PM MR. ALPER said slide 22 sums up everything he just said and that the members' questions had done a good job of going into how the numbers move around. The idea in slide 22 is that at the end of the second year there are $370 million in carried forward NOL credits. MR. ALPER said the second part of strengthening the tax has to do with the gross value reduction (GVR) that new oil is eligible for and the $5/barrel credit. A simple graph on slides 23 & 24 showed how that tax calculation works for legacy fields versus GVR-eligible new oil fields at $80/oil, because that's a point where there is a distinctive difference between the two and at $60/oil. They used a cost of $46, which resulted in a net value of $34 (at $80/oil). 3:48:50 PM For legacy oil, the 35 percent tax rate would be applied to that $34, which results in $11.90, minus the $8 tax. So, $3.90 becomes the actual tax. The minimum tax in that scenario of $2.80 is not triggered. The crossover point is somewhere a little bit below $80/barrel (within a dollar). For the GVR-eligible field in this scenario, the $34 is adjusted by subtracting 20 percent of the gross value at the point of production. Gross is the well-head value after transport ($70) and 20 percent of that is $14. So, the $14 is subtracted from the $34 net to equal a taxable value of $20. The 35 percent tax rate is the same but it's applied to the smaller number ($20 rather $34) and the tax becomes $7, and then the $5-flat per- barrel credit (for GVR eligible fields) leads to a tax rate of $2. The $2 is below the minimum tax. However, in this circumstance, the GVR-eligible field would actually pay the $2/barrel tax and not the $2.80 minimum tax. This legislation proposes that GVR-eligible oil should also be subject to the minimum tax and pay the $2.80 rather than the $2 rate. The GVR remains the same; the $5 credit remains there, but in this circumstance the last $.80 of that $5 would be lost, similar to $1 and change in the $70 example he walked through for Senator Wielechowski. 3:50:10 PM SENATOR COSTELLO asked if he had been able to retroactively model how this would affect the state's bottom line, since it is on the books. MR. ALPER answered that the minimum tax didn't become a factor until the last part of 2014 and they hadn't precisely modeled it looking backwards, but he could say with some confidence it's about a $25-million line item. SENATOR WIELECHOWSKI asked the effective tax rate for legacy oil and GVR eligible oil on this slide at $80. MR. ALPER answered since the effective tax rate generally is a share of net profits (cash flow), the $3.90 tax on the legacy oil would be in the neighborhood of 12 percent and the $2 GVR- eligible oil would in the 6-7 percent range. 3:51:28 PM The same conversation at $60 oil reveals that legacy oil leads to a negative calculation when the per-barrel credit goes all the way to zero. So, the limiting factor under current law is the 4 percent minimum tax. With $60 oil, 4 percent of the $50 gross becomes $2/barrel. The GVR-eligible producer does the same calculation and can get as far as zero. The tax before the $5- credit is only $1.40. So $1.40 out of the $5 would be used; the other $3.60 would be lost. The company would pay zero. The bill proposed that that oil would also pay the $2-minimum tax. 3:52:30 PM MR. ALPER started explaining section 17(c) of SB 130 on migrating credits. It means that a per-barrel credit earned in one month could potentially be used to offset taxes from another month under certain circumstances. This condition is not built into the fiscal note modeling as having any value, because it's very specific to volatility. It only happens in years where some months fall under the minimum tax calculation and years where in some months the price of oil supports the higher tax. MR. ALPER said a classic example of that happened in 2014. He explained that the sliding scale credits were originally brought into SB 21 as a form of progressivity or reverse progressivity, because it is progressivity through subtraction rather than addition. But the idea was that the per-barrel credit itself is very much of a monthly calculation. It can, under current law, go up and down by the month. 3:53:58 PM Slide 26 (labeled: section 17(c): Strengthen the Minimum Tax, "Credits "lost" to the minimum tax before annual true-up) graphs what 2014 looked like in actuality, Mr. Alper said. The total production tax for January, based on 35 percent of the net, was about $280 million. But the amount that the state actually received was close to $200 million (green bar), because the per- barrel credit of whatever the number was that month (probably around $45/barrel) reduced the payments. Below that, the red bar is where 4 percent of the gross would have been. If it were a minimum tax month, the state would have received the red number; but from January through October the state received the green bar height number ($200 million). He explained that the price of oil fell dramatically through the summer of 2014 and by October the state was just barely above the minimum tax. In November and December the tax went below the minimum. In November and December the state received roughly $30 to $40 million per month, the amount under the red bar. The shaded dotted areas above that (still on slide 26) represent the per-barrel credits that were unusable, because the whole $8 couldn't be used before they bumped up against the minimum tax in that month. In November they were able to use roughly $7 out of the $8; in December they were able to use $2 out of the $8. But when the annual true up was done for the entire tax year, slide 27 shows how the dotted areas were able to effectively offset taxes that were accrued in the month of January to reduce the payment in the dotted area below the $200 million all the way to a bit below the $100 million line. So that $112 million worth of credits that were usable in a monthly calculation were usable in an annual calculation to reduce the total payment. Mr. Alper said this hit them as a surprise. Until the claims for refunds came in the annual true up in the last week of March 2015, the department thought it had $100 million more than they actually did, and had to pay large refunds to the major producers. MR. ALPER said section 17(c) of the bill, while technically and complexly written, is simply intended to make the per-barrel of credit itself a strict monthly calculation and not to be used to offset taxes from a different month. CHAIR GIESSEL asked if the department is asking the taxpayer to accurately submit monthly tax returns. MR. ALPER answered no. Currently taxpayers are expected to do an estimated tax deposit based on the calculation for that month. Because they are actually paying the amount based on the monthly calculation already, it's based on an estimate of their lease expenditures divided by 12 for the year. Doing an expense calculation by the month would be far too onerous. The producers know how much oil they sold and what the price was. He explained that the per-barrel credits unclaimable in one month should be limited to that month. That particular credit which is calculated and earned on a monthly basis should also be used on a monthly basis and it's strictly constrained to the per taxable barrel credit. 3:57:46 PM SENATOR COSTELLO asked if this is what takes the state six years to audit. MR. ALPER answered no; this is all worked out within the tax year. It could be auditable like anything else, but this is a situation that comes up at the tax true up period in March of the year following the end of the tax year. SENATOR COSTELLO asked how often the state has to reimburse a company. MR. ALPER answered that this is a specific provision of SB 21, so it wasn't relevant before 2014. It was very relevant specifically in 2014 when there was that level of volatility. In 2015, which was just completed, every month in 2015 was below the minimum tax, and the state was in the red in the context of this chart. So, there was no ability to migrate, to offset taxes with used per barrel credits. The only time it would have occurred was in 2014 and they hope to protect the state's interest in statute in the event of a future year of high volatility. SENATOR MICCICHE commented that the only year one sees that extreme volatility is when there is extreme price variation with part of the year above the minimum tax. MR. ALPER agreed. SENATOR STEDMAN asked if he had calculated this in reverse, where the state comes off the minimum tax and goes into several months of extreme volatility upward. MR. ALPER answered yes; it works the same in reverse. Effectively, the way the tax true up is done is in the aggregate. The value for the year is added up along with the per-barrel credits and 4 percent of the whole year's total becomes the minimum tax. So, that is where the per-barrel credits could be used, because they are still above the year 4 percent instead of the month 4 percent. SENATOR MICCICHE said it looks like the most volatile year would have prices teetering at the $78 level. Is that right? MR. ALPER answered no. For instance, October in the graph before them is one of those months when the price of oil was down in the $70s. There isn't much "headroom" above the minimum tax, so the most that the state could lose is the difference between the minimum tax and the calculated tax after the use of the per barrel credit. If there were a bunch of months of $150 oil and a bunch of months of $30 oil, the very large per-barrel credits could reduce state production tax collection to the minimum tax. 4:02:41 PM The narrative on slide 28 mostly says greater price volatility means that the credit recovery could take a greater share of the production tax. Effectively, the minimum tax only protects the full year's revenue, because credits that cannot be used within a year can be recovered at year's end the way the law is currently written. Slides 29 and 30 show a more extreme version where the price of oil declines from $90 down to $50 earlier in the year. In this particular scenario the sum total of all of those dotted lines that begin in June to offset all of the green bars add up to $233 million, a little bit on the high end of what the state is expecting with a lot of volatility. Slide 30 shows $233 million in credits being applied to what otherwise would have been an $836-million revenue year, dropping it down $603 million. That is the migrating credits story, the hardest one to tell. It could reduce the state's taxes by close to 30 percent. It reduces the effective tax rate in that scenario from about 14.5 percent to 10 percent. Part of the rationale of any sort of monthly tax calculation is that the state should benefit from months with higher prices, and this phenomenon allows it to receive less revenue on the upside if it's within the same year that has low price months. That is why they are seeking to embed this section in the bill. 4:04:20 PM MR. ALPER said section 18 is a totally different concept that has to do with the interaction between the gross value reduction (GVR) for new and a net operating loss (NOL). One doesn't intuitively think of those two things as being related, because to get the gross value reduction it means you are a producer (you have production and sales) and you shouldn't be operating at a loss. There are multiple scenarios where a new producer could be operating at a loss - a new field, for instance. But at today's low prices, their costs do not meet their prices. The second situation would be if a company were involved in continuing to invest - drilling wells or working on a new project - they could, even at higher prices, bring themselves into an operating loss for the field. The understanding behind SB 21 was to try to build a flat level of state support at all price points in all circumstances on the North Slope, and the number that came out of the final version of the bill was 35 percent. So, the operating loss credit should be 35 percent of the operating loss. What is happening here is: in the earlier slide he talked about the GVR in the context of the minimum tax, but the GVR is a subtraction mechanism: subtract a number from your taxable value and pay taxes on the difference. If the taxable value is in essence a negative number, because you are at a loss, and you subtract from it, you create a larger negative number - a synthetically large operating loss - and 35 percent of that number becomes a number that is much greater than 35 percent of the actual loss, itself; in some case, more than 100 percent of the loss. The difference in the scenario on slide 33 means about $7.6 million to the state (through a larger than 35 percent NOL credit). 4:06:37 PM MR. ALPER apologized for the complicated slide 33 and explained that current law works down the left-hand column, a low price typical cost scenario ($40 oil), the $46 costs; the company is losing $6/barrel. Based on that loss, a 35 percent operating loss credit would normally result in a credit of $2.10/barrel, However, the GVR calculation is 20 percent of the gross, which is $30, which is another $6 subtracted from the negative $6 getting to negative $12 (circled in red on left column); 35 percent of that number leads to a $4.20 credit. So, effectively, the company is getting paid an operating loss credit by the state that represents 70 percent of their losses rather than 35 percent. He explained that the technical change in section 18 of the bill simply says, "In event of a loss, the GVR gets added back in for the calculation of an operating loss credit." This means that $6 calculation would be foregone in a loss circumstance, the negative $6 would represent the actual loss. The negative cash flow would be what be receiving the NOL credit at $2.10 (35 percent of the loss). 4:08:01 PM MR. ALPER said that was the intent and Mr. Mayer with enalytica had said this was an unforeseen circumstance and recommended retaining this provision. If slide 33 is talking about a single producer with a 10,000 barrel-a-day field, and that gets multiplied out for the year, it's the difference between a $15 million and $7.5 million NOL credit or about $7.5 million in savings to the state. SENATOR STEDMAN asked which fields fit this scenario and where Point Thomson lies in it. MR. ALPER answered that the three qualifications for the GVR are: you have to be unitized subsequent to 2003, and the two well-known producing fields that fall in that category are Oooguruk (Caelus) and Nikiatchuq (primarily ENI). They would classically fall into this sort of calculation. Should they have a loss, Mr. Foley from Caelus, when speaking to various versions of this legislation, has said that this change would impact his company. So, he can talk a little bit about it within the bounds of confidentiality because Mr. Foley already had. There are no other fields, yet, although any new fields that start up soon - for example, the Mustang field - would fall under this definition. Point Thomson will come in as GVR-eligible under the idea of a new participating area. Although that unit goes back to the early 70s, they haven't filed for a participating area (essentially, a pool) until after the settlement. So, well after the effective date of the bill. So, Point Thomson will get the GVR. There are extensions to existing fields, if producers meet certain criteria and if they are prepared to go through certain hurdles of metering and the like. A couple of examples like CD5 and the Southwest Kuparuk could plausibly qualify, but he couldn't say for sure that they actually did go through the hoops required to get the GVR in those extensions. SENATOR STEDMAN said it looks like Point Thomson would qualify for the 30 percent GVR. He assumed under that same pricing scenario, the credits in the new areas along with the 30 percent GVR, instead of being in the 70 percent range, would be somewhat higher than that. He asked Mr. Alper to explain that. And then he asked what other jurisdictions fall back at that rate of 70 percent. MR. ALPER clarified that he had asked that question of then DNR Commissioner Balash who brought out a lease chart of the Point Thomson area indicating that only a handful of the individual leases are above the 12.5 percent level. The requirement to get the higher level GVR is that every single lease has to be higher than the 12.5 percent. So, Point Thomson would come in at the 20 percent GVR, not the 30 percent. He explained that the scenario on slide 33 is based on something that could happen in the future, after the effective date of the bill. If something happened in 2014/15 there is a 45 percent NOL. Using the same scenario, the state would pay the difference between 45 percent and 90 percent of a company's losses. Depending on the rate of that loss, it could go to well over 100 percent in certain circumstances. 4:12:16 PM SENATOR STEDMAN asked what other states beside Texas and North Dakota reimburse on losses. MR. ALPER answered to his knowledge those states don't reimburse on losses. They have relatively flat gross tax rates and companies pay a percentage of the gross. That means that without the credits, at low prices companies are losing money and they are also paying a relatively small tax to the state. "That's pretty much the end of the story." SENATOR STEDMAN remarked, "Except for the royalty owner." MR. ALPER responded that everyone pays royalty and in those other states, the royalty, in most cases, goes to the private land owner, but in Alaska, the state enjoys most of it. 4:13:15 PM He said slide 35 makes the same calculation at a high price ($80/oil)/high cost scenario for a company that is spending $80/barrel building the next oil field - not because he is trying to lose money on this field, but because he is trying to get future production on line in a new field. In that circumstance, the producer with $80/oil, $80/lease expenditures, and $10/transportation costs is losing $10/barrel. If it was a straight 35-percent NOL credit, the proposed change is that they would get a $3.50 NOL credit. However, if the 20-percent GVR is applied to that -$10 (net value before GVR), that would result in a $14 adjustment (based on 20 percent of $70 well head value). So the adjusted negative value would be a -$24, and 35 percent of that is $8.40. Then the state would be paying effectively an 84 percent NOL credit to that producer. A 45-percent NOL credit would result in more than 100 percent of an NOL credit. The savings to the state in this model is the difference between a $30 million credit and a $12 million credit, or about $18 million. CHAIR GIESSEL asked if the NOL on the North Slope right now is at 45 percent until July 1. MR. ALPER answered that it went to 35 percent on January 1, 2016. He explained that many of the credits can be moved around within a year, but the NOLs are very much tied to the calendar year or the auditors get very upset. SENATOR STEDMAN remarked that Senator Wielechowski had asked for the history of the floor for some context to the floor discussion. MR. ALPER said he would get that. He added that the floor didn't have a lot of teeth until SB 21 came in and hardened it specifically to the per-taxable barrel credit. 4:17:04 PM He said sections 26 and 27 are a little bit different in that they don't talk about restrictions on the credits, themselves. These are restrictions on the ability to turn those credits into cash. They are within "028," the section of statute that controls the tax credit fund, itself, where money is put to repurchase credits. Four restrictions were added in SB 130 to the state's repurchase of credits. The first one says that if you are a very large company and have greater than $10 billion in annual revenue, then you are no longer eligible to get cash for your credits, the idea being these companies are generally better capitalized and have more robust balance sheets. They can hold the credits on their own books until such time as they have production and will use it to offset their future taxes. MR. ALPER said there is no magic to the number of $10 billion. Any number of oil companies fall in above that line, but roughly speaking, that's the state's all-in spending if you count federal money, the Permanent Fund, capital budget, and the General fund. The thought is if the company is bigger than the state, it doesn't need to pay them cash for their credits. The one change that has received a little more attention and will impact more companies is the $25-million per-company per- year limitation. If a company is earning a large amount of credits, the state will repurchase $25 million and the rest of the credits will be rolled forward effectively into the following year. If a project keeps building credits their payment would be based on a "first in/first out" basis where the oldest ones would get paid out at the rate of $25 million per year. That number was plucked from the original credit repurchase language that was in the PPT bill (HB 3001 in 2006), which created the idea for the first time of re-purchasable credits and then put in that $25 million cap. That cap was subsequently removed in the ACES bill a year or so later. 4:19:13 PM The third restriction is the cash for the Alaska-hire provision. The concept is if the state owes a company $10 million in credits, the DOR would look to the Department of Labor and Workforce Development (DOLWD) statistic of their instate hire percentage and their subcontractors in the prior calendar year. If it was 80 percent, the state would purchase $8 million out of that $10 million and the other $2 million would hold their value and be rolled forward for use in a future year against their taxes. Finally, they put in a 10-year sunset. If the credits are unusable they will expire 10 years after the date they were issued, which is where the "first in/first out" mechanism becomes important to make sure that the older ones get used up first. 4:20:08 PM SENATOR COSTELLO asked if he saw a difference between describing the credits as "unused" versus "unusable," because it's not within a company's power to use a credit until the price of oil goes above $70 or they are also in line and may never get to the front of the line. MR. ALPER answered he wouldn't say they were in line; it has nothing to do with their relationship with other companies. The $25 million per company cap would be for that company and then that company would be able to receive $25 million the next year. But it's fair to say some of those credits would be lost for being unusable, because they were not able to get them cashed out in time should the price not be high enough once they are in production to apply their tax liability against. SENATOR COSTELLO said it seems that the state has a hand in that, for example, when the governor vetoed some of the money for paying credits from last year. If the state is not going to be cashing them out or they expire, that could have a significant impact going both ways. MR. ALPER agreed that was a good point. One of the weaknesses of the governor's veto, administratively, was when there is not enough money the structure is "first in/first out." Putting some sort of limitation would create some ability to prorate the money if there was a limited amount of money rather than saying just because you got your credits processed through the DOR staff before someone else did, you're going to get paid but someone else is going to have to wait until next year. There is a little bit of arbitrariness in a cutoff without some mechanism that more equitably shares the impact of that cutoff, and that's the sort of thing they are looking to impose here. 4:22:58 PM SENATOR MICCICHE asked if he thought the Alaska-hire provision would pass constitutional muster. MR. ALPER replied that it is controversial and will certainly be challenged. It doesn't matter in how it will be adjudicated. The department's feeling is that because they aren't taking value per se from someone, just the timing of the ability to enjoy that value, that no one is going to lose their credits. They are just going to be earning them in a later year. It might be more likely to survive constitutional scrutiny than some other attempts at Alaska hire. Miss Gramling is the assistant attorney general handling this issue and she would know more. CHAIR GIESSEL noted that Miss Gramling was not on line. 4:24:29 PM SENATOR WIELECHOWSKI asked for data on the percentage of Alaska versus non-Alaskans who are getting laid off in the oil industry. MR. ALPER said he hadn't seen any information on how the layoffs are impacting local versus out-of-state employees. SENATOR WIELECHOWSKI asked if the $25 million limit was changed to $100 million in the House. MR. ALPER answered that the House Resources version had $200 million and the House Finance committee substitute had $100 million. SENATOR WIELECHOWSKI asked him the policy reasons behind why $25 million is better than $100 or $200 million. MR. ALPER answered that the department hadn't done the analysis until they started seeing the larger numbers, and that's when they went back through their records and calculated the number of companies that had come in at some of the higher price points. There has been exactly one transaction in 10 years the department has been paying tax credits where a single company made more than $200 million in a year, and he found only five circumstances where a company made between $100 and $200 million. There were 11 circumstances where a company earned between $50 and $100 million. So, a total of 17 instances of $50 million or more going to a single company. They did not count the $25 to $50 million, because there would be a lot of those. So the impact is quite broad. The discussion in the House Resources Committee of the $200 million was distinctly limited to the outlier event: Mr. Armstrong with his very large project on the North Slope could lead to the state having $600 or $800 million a year in credit liability during their peak construction years and that would be in advance of any revenue coming from the oil in that field. The state figured out a way to protect its interests with the $200 million. It was something of an insurance policy against the very extreme outlier. The $25 million would be a much broader- based reduction in payments to a much wider range of companies. COMMISSIONER HOFFBECK followed up that the broad policy decision after meeting with the companies was that that the NOL credit needed to be the key component that they felt needed protection, but it is also the one that is the most difficult to control. It's not project specific and there are a lot of different ways of ending up with an NOL. So, although they were willing to leave the NOL credit in play, because of the importance to the various companies, they still needed some way to limit the state's exposure to it in any given year. That was when the idea came up of putting the cap back in. It limits the state's exposure, but creates a longer tail on how long the credits last. 4:28:09 PM SENATOR WIELECHOWSKI asked once companies hit a loss and can write it off on future taxes, is the state providing an unnecessary incentive to do more things that will accrue losses to deduct in future years. MR. ALPER responded that he hoped not. The 35-percent figure is flat across the board. So, if someone spends an extra million on a gold plated object on the North Slope, they would only be getting $350,000 back from the state. This is one of the places where in some ways the loss of the steep progressivity from the prior tax regime works in the state's interest. Because there was in some ways more of an incentive to spend money because you weren't just getting a reduction in taxes based on a lower production tax value, but a company could lower its tax rate by reducing their per-barrel profits going down on the progressivity slope - essentially, a high marginal tax rate working in reverse. SENATOR WIELECHOWSKI said they talked a lot about the idea of incentivizing production in SB 21, but that's not really the case, because with NOLs the state is still allowing companies to write off expenditures. Is that correct? MR. ALPER answered yes. The NOL was always envisioned as a payback for someone who is under the development stage to kind of level the playing field between them and the producer. To a certain extent they were taken by surprise at dealing with producers having operating losses. It changed a lot of assumptions in their calculations in what they are seeing going forward. SENATOR STEDMAN digressed to the 30 percent GVR for new fields and said that nationwide royalty is around 20 percent. Alaska is at 12.8 and the newer ones are 16.5 percent. He asked if the 30 percent GVR wipes out the "modernistic" royalty rate. MR. ALPER answered that they modeled some fields and then modeled them again at the high North Slope royalty and found that the increment in additional royalty the state would get was "pretty evenly" offset by the additional reduction in production tax. 4:32:41 PM SENATOR COSTELLO commented that prior to SB 21 they were incentivizing investment and activity versus results. So, she could see companies looking for well lease expenditures or other types of tax credits, but to assume a company is trying to operate at a net operating loss is a curious suggestion. She asked Mr. Alper if he thinks companies are trying to lose money under the current system. MR. ALPER answered, "Most definitely not!" Except for the rare circumstance, the state is never paying anyone 100 cents on the dollar. Companies are losing money beyond what the state is paying them back. SENATOR COSTELLO said that is what she is hearing, too, and that companies are trying to operate more efficiently and are having to lay off people. 4:34:00 PM MR. ALPER said section 31 is simpler and a little bit obscure as well. With extended low prices, the state is facing a circumstance where potentially the gross value at the point of production could go less than zero either on the field level or on the slope level. Gross value at the point of production is a waystation in the tax calculation on the way to production tax value. So, the way this is written, if that part of the calculation is negative, it would reset to zero for further calculations to production tax value, and at $30/barrel it means there has to be a circumstance of $30 transportation costs. That is unusual, but it could certainly happen. If prices go below $20/barrel, he could envision even more circumstances where that would happen. Slide 38 displayed the different tax and feeder pipeline tariffs (all-in tariffs) before adding a rough average of $3.37 for the marine transport from Valdez to the typical refinery. So, for a base at Prudhoe Bay the tax tariff is $6.13, but if production is coming from Kuparuk, a company has to also pay the $0.32 feeder line to get it from Kuparuk to Pump Station 1, and you are paying $6.45. Something like Endicott has a two-hour feeder pipeline and gets it up to $8.35. But the outlier in there is Point Thomson, the newest field that is about to come into production this year; it has to get to Badami and the operator has filed a $19.17 tariff for that. This means that the total tariff to get to Valdez is $28.49, which added to the marine transport gets one to $31.86 transportation cost. So, if Point Thomson were to go into production for a year at $30 oil, they would effectively have a negative value at the wellhead of $1.86/barrel. So, over the expected production of 10,000 barrels/day, minus the royalty, there would be a negative gross value of $5.9 million. So, the provision proposed in SB 130 would be to say for any given field that wellhead value would have to reset to zero, meaning that negative $5.9 million wouldn't be allowed to offset positive gross values in other production from that producer on the North Slope. The effective tax there is about $2 million (35 percent of that little bit less than $6 million). CHAIR GIESSEL said Point Thomson is on the threshold of beginning production of gas liquids and they are operating under the Point Thomson Settlement Agreement, which requires them to produce liquids at a rate that they will be losing money (today, it's $40). MR. ALPER said yes, that was correct. He mentioned that there is a technical issue embedded in this section. That is although the gross value at the point of production is roughly comparable to what they collect royalty on, it's not a royalty value. So, the state doesn't run the risk of negative royalties. They do however, face the circumstance potentially of the private royalty tax being a negative calculation, which they had never contemplated and it needs to be fixed in some way. If there is production from private land - CD5 is an example - that production should happen to fall through negative gross value at the point of production, the statute doesn't account for what might happen if the state is supposed to be collecting 5 percent of that number in a private royalty tax. 4:38:21 PM SENATOR STEDMAN said he never thought much about the Point Thomson tariff, because it was never in their face. They still have to have operating and capital costs there and asked if Mr. Alper had any idea of what those are or do they use the average out of the Revenue Sources Book. MR. ALPER said presuming something along the lines of the average cost, maybe a little bit less because they have just come out of a very capital-heavy initial construction project, it's fair to say the break even at Point Thomson is close to $60/barrel. To a certain extent that is ameliorated by the fact that they own the feeder pipeline that is getting the $19 tariff (they are somewhat paying themselves). SENATOR STEDMAN said that puts a fine point on the difficulty the state has had in moving Point Thomson forward, and the big price exposure industry had in moving it forward, especially if they need $60 or $65 to break even. It doesn't help the state in developing the basin. 4:40:19 PM He asked under the settlement agreement to develop Point Thomson, if the state is forcing them to do things they might not otherwise do outside of that to minimize losses. MR. ALPER answered that he is not an expert on Point Thomson engineering, but it's a relatively simple system of only three wells. They are obligated to produce those wells and compress and reinject that gas for the next several years. In some ways, it's a test system to see how the reinjected gas migrates back through the field to determine the viability of an expanded cycling process: if the gasline comes in, can they get good production of liquids for a lot of the year while reinjecting gas into the ground or will it be more viable to blow it down? This is a "waystation" towards a much larger policy decision for the owners of that field. Their settlement has a decision point in 2018/19 over phase 2 when they are obligated to make a decision that will lead to some sort of additional investment for them in three or four years. SENATOR STEDMAN said let's hope for $80/barrel oil and they are profitable, so the state can make a little bit, too. CHAIR GIESSEL said she hoped they become profitable, because that is the state's gas pipeline. 4:42:35 PM MR. ALPER went to the last part of the bill, the "deep" section concerning municipal utility limitations. This was discovered through paying historic tax credits and finding that is the literal interpretation of the law. If a company is producing most of the gas themselves (if they are a utility that owns a gas field and a great bulk is going to their own turbines) that use of gas isn't a sale for tax purposes - its' just their own gas. But if they have a little bit of extra and sell to a third party, that's a sale. That becomes revenue. For the purpose of various credits, the question is whether the expenses that offset that small amount of sale - the way the law is written that all of the expense could offset that revenue, thus creating (similar to the GVR NOL section) synthetic NOL (NOLs that don't reflect the actual profitability of that company). They propose to say that only the pro-rata share of the costs would be usable to offset the revenue. The chart on the right side of slide 40 is current law illustrated by using a utility using 20 million feet per day, burning 18 million feet in their turbine and selling 2 million feet to someone else. If that gas is worth $8/mcf, the revenue based on selling 2 million per day over the course of the year is about $6 million feet. If their lease expenditure is $3 (on all the gas), that's $21 million worth of lease expenditure. They could share a net operating loss effectively of $16 million even though they didn't really lose $16 million, and in Cook Inlet the state would be paying them a 25 percent NOL credit of $4 million. The bill proposes to say if you're selling only 10 percent of the gas and using 90 percent of it yourself, you only get to account 10 percent of your lease expenditures against that revenue for the purposes of any tax or operating loss. In this case, they would be shown to be profitable, because only 10 percent of that $22 million - $2 million - would be deductible. They would show a $3 million operating profit and would not be receiving an NOL. It's a relatively simple and technical non-controversial change that is just trying to fix a literal interpretation of the law. SENATOR MICCICHE said that is roughly an $8 million difference in that case. He asked the overall effect statewide of utilities not being taxed on volumes sold to third parties. MR. ALPER answered that they are taxed on the volumes sold to third parties (currently $0.17/mcf in Cook Inlet), and it would be in the tens or low hundreds of thousands of dollars in production tax as opposed to the $16 million operating loss that would lead to the $4 million NOL. So, effectively that 2 mcf/day times 700 mcf/year times the $0.17 tax is what that company would be subject to. SENATOR MICCICHE asked what the overall effect is on the allowable lease expenditures. MR. ALPER answered in the single digit millions of dollars. SENATOR STOLTZE asked what their discussions have been with the municipalities that have utilities that run on gas. Two come to mind: the North Slope Borough and the Municipality of Anchorage. COMMISSIONER HOFFBECK answered that he didn't know if they had any contact with the North Slope Borough or ML&P. MR. ALPER answered that the North Slope Borough is a little bit different in this circumstance, because they are not the same entity as those who own the gas fields and the production that supply that. There is an actual transaction that occurs when they sell their gas. SENATOR STOLTZE said it seems a little odd that ML&P or the mayor's office wouldn't have been a little more involved to protect the interests of their consumers or be part of their discussion. Have they outreached to them? MR. ALPER answered they didn't specifically reach out to them, but they are well aware of this issue. He hadn't heard anything from them. The department is in contact with them through their role as taxpayers, and it was in that role that they became aware of the circumstance. Perhaps their non-responsiveness indicates their recognition that this might be something that should be corrected, but he didn't want to speak for them. SENATOR STOLTZE said he would like to coax a response from the largest municipality in the state on the impact to their customer base. 4:49:22 PM CHAIR GIESSEL said both committees in the other body that heard this bill invited ML&P and they did not respond and they declined to present to this committee a few days ago when the other utilities were there. She is in the process of sending a letter to the mayor to ask if he had a comment on this, but it hadn't been executed yet. SENATOR MICCICHE commented that this looks like it can't be more than a half to three-quarter million dollar problem on an annual basis in comparison to the hundreds of millions in chunks of revenue they are talking about, and looks like a cost that will be shifted to the ratepayer. MR. ALPER replied that any tax that a utility would be paying the state would be minimal and would most likely be offset by the small producer credit, anyway. The credits they are enjoying by having all of their lease expenditures, which could be in the tens of millions of dollars per year to operate that field, are only being offset by a relatively small amount of sales, then the state could see losses in the tens of millions of dollars with 25 percent of that eligible for an NOL credit. 4:51:28 PM Slide 41 gets into the scenario analysis modeling for this piece of legislation that came as requests from individual legislators over the previous interim. In some ways they have copied stylistically some modeling from PFC Energy and enalytica, the legislature's consultants. Typically, the DOR has modeled oil and gas as a North Slope-wide or Cook Inlet-wide model so there is per-barrel spending on operating and capital, but it doesn't really capture the nuance of an individual investment where the capital spending is not evenly spread throughout the lifecycle of the field. In fact, it's very front loaded. Likewise, the operating doesn't happen until after they are in production and it tends to be scaled with the production. And then the production itself is on a curve that ramps up and ramps down. Every small field follows the same left curve they see on Prudhoe Bay. This life cycle model shows the cash flow over the 30-40 year life of a project for both the state's production tax and credits as a standalone item, the all-state revenues (general fund revenue), and also the producers' cash flow. They applied a discount rate to all of these using the most recent track record of the Permanent Fund earnings, which is 6.15 percent, to represent the time value of money for the state's money in Alaska, if the alternative is having the money in savings. 4:53:05 PM The model looks at $30, $60, and $80/oil as well as the fall forecast scenarios. They also worked in higher and lower price scenarios due to a request from the House Finance Committee, which he promised to provide this committee. They also modeled the status quo versus the sum total of the changes in the governor's bill. They looked at new field on the North Slope with 50-million barrels in the ground. This really means it peaks-out in the 10- 15,000/barrel/day range, comparable to smaller fields like Oooguruk, the Nikiatchuq, and the Mustangs. They also looked at a much larger field, the 750-million/barrel in-place field comparable to the Armstrong field. That was done in three different iterations using the 12.5 percent royalty, the 20 percent GVR, the higher royalty with the higher GVR (as Senator Stedman alluded to earlier), and also what happens if half of it is on private land. They also modeled the Cook Inlet scenario for a 50-million/barrel field with a big question mark floating above in 2022 when the tax caps in statute go away. He didn't feel comfortable inventing a tax regime for Cook Inlet, so they have a high and a low scenario, caps are extended effectively with no production tax into the future versus when tax caps go away, meaning the 35 percent net tax without any per-barrel credit. However, he said, the real answer probably lies somewhere between the two sets of modeling runs. MR. ALPER said the committee substitutes that have passed in the other body include a Cook Inlet-specific working group to look at proposing a new regime for the next legislature to revise in future years. 4:56:06 PM Finally, slide 43 models gas scenarios of 670 bcf/ Cook Inlet and Middle Earth gas fields that are roughly analogous to what BlueCrest is looking to do; it would peak-out at about 50 mcf/day. CHAIR GIESSEL asked where Furie would fall. MR. ALPER answered that Furie is a little bit of an unknown. Their phase 1 is probably around the same size, but from their claims and from their somewhat aggressive investing in offshore platforms, they have alluded to having a somewhat larger resource base. What they talk about is having about 400/bcf. In some of their earlier reports they talked about having trillions of feet in place. Everyone is hopeful, but no one really knows until they start deviating further out from their central point to see how big the resource becomes. 4:57:21 PM He said all the slides use the structure graphic. The upper left hand corner is the production tax and tax credit alone scenario. (Slide 44) This is credits the state is paying the producer based on whatever it is they might be earning. In the case of a North Slope field, it is almost entirely NOLs. The production tax received is the blue curve in revenues starting after construction is finished. MR. ALPER explained when he talks about 50-million/barrels of oil in place, there is an assumption of capex - maybe $12- $18/barrel - that becomes the aggregate times the number of barrels produced. So, a $12/barrel capex scenario for 50 million barrels means $600 million is going to be spent, and most of it will be spent in the first two years, but it get the 35 percent NOL credit over several years. The state's negative cash flow peaks out at around $50 million per year at the highest level of construction. The total state general fund cash flow (including the oil money that goes to the Permanent Fund) is in the upper right-hand corner. The production tax is represented by the green and royalty is indicated by blue. In most years, royalty is the state's largest revenue source. The purple line is the state corporate income tax and a "small wedge" that isn't quite visible at this level of resolution is the state's share of the property tax. He said on the North Slope a large percentage of the property tax actually accrues to the North Slope Borough and that didn't show up on this graph. The producers' cash flow was graphed on the lower left; the green bars represent a positive after-tax cash flow after having been partially reimbursed by the credits, once they are in production. Finally, the lower right has some of the sum total data from the colored graphs separated into the three chunks: the top one is the production tax. In this scenario - $60 oil for a small stand-alone oil field on the North Slope - the state spends $162 million on credits and receives $183 million in production taxes, a positive revenue of $21 million. But if a time value of money is assigned (net present value) to that calculation, indicating that the state would be negative $37 million on the production tax, alone, on that field. Meanwhile, the second "chunk" is the total state cash flow where the losses are a little smaller (negative $121 million). The difference between that and the negative $162 million is there are some years where the state is still paying out credits when production has started and paying a little bit of royalty revenue. In this "very stylized new North Slope field" the state gains a value of $136 million. The same calculation is done for the producers. The same discount rate was used, but the producers look for a higher return on investment than 6 percent. If that were the case, the so-called hurdle rate is where they would be seeing a smaller number if they were to apply a 10 or 12 percent discount rate. This is the status quo scenario. 5:02:30 PM MR. ALPER said he had three different scenarios in this presentation and he would be happy to meet with any member individually to discuss this "stuff" at length. 5:02:38 PM He said these slides refer to HB 247 and he apologized for not updating them to SB 130. The most visually different thing on the tax credit side (in the upper left) is suddenly the negative numbers get cut off at $25 million per year. However, as those credits are earned for more years into the future the "tax credit spend" gets shifted forward and creates some distortions in the companies' cash flow (in the lower left). So, they really need to look at the net effect changes. The state's production tax discounted value, at $45/46 oil, goes from a negative $37 [million] to a negative $10 [million], while the credit outlay goes from a negative $162 [million] to negative $101 [million]. Meanwhile, the total discounted value of all the state's taxes goes from $136 million to $163 million. Of course, as the state is gaining value from the companies, their discounted cash flow goes from $112 million to $93 million. Delaying payment of some of the credits creates value to the state through the time value of that money. MR. ALPER said those numbers are relatively small if one can consider $163 million small. The numbers get much larger when looking at a large field. They modeled this at $80/oil with the expectation that it's unlikely that someone will make what quite literally is a $10 billion sanctioning investment to build out a field of this size without an expectation of a higher oil price. 5:04:31 PM He looked at a 750-million/barrel field at $80/oil. The most jarring thing with a front-loaded field and that level of expenditure is that the state's credit outlay is $2.8 billion before it sees production taxes off that field. At the highest point, the state is paying $800 million per year and for the top three years about $550 million per year. That is the data set that led the House Resources Committee to put in a $200-million cap, because that is when the credits are really outside the state's capacity no matter what else is going on - although that would be a single partner. He explained that any of the caps in the various versions of the legislation haven't accounted for partnerships. If there are four partners, each earning a $25 million cap that would actually be $100 million, which would change these numbers dramatically. 5:05:42 PM In this field the state gets almost $9 billion in production tax against the $3 billion in credit. With the time value of money, the state makes $869 million. The state makes over $1 billion a year for a few years at the peak of this project, an extraordinarily good thing if it can get built. With a discounted value of $3.5 billion and a relatively robust value for the producer based on all of their assumptions (which by their very nature are wrong), the company would get $2 billion from this project. 5:06:21 PM What Mr. Alper learned when he overlaid the $25-million per-year cap is that this probably created too large a distortion for this field. The state's cash-out went from $2.8 billion to only $100 million; the state about doubled its discounted production tax value from less than $900 million to $1.7 billion, and its all-in cash went from $3.5 billion to $4.3 billion. Meanwhile the company lost about one-third of the value from this field going down from $2.2 billion discounted to about $1.4 billion (slide 47). It's unlikely that someone is going to do this alone with the governor's bill and four partners and a $100-million-a- year cap, and the answer would fall somewhere between his two examples. 5:07:29 PM Being pressed for time, Mr. Alper jumped past the Cook Inlet scenario that is similar to the North Slope small field scenario, as far as how the numbers move. The Cook Inlet was modeled for both the Cook Inlet tax cap expired and also the Cook Inlet tax caps extended (not in the bill), but he wanted to highlight that the larger presentations have summary tables at the back. He put all of the summary tables in this presentation so they are easily available. Slide 50 looks at the North Slope oil scenarios and slide 51 looks at the non-standard royalty scenarios (high and private royalty), the Cook Inlet oil scenarios were on slide 52, and slide 53 had the various gas scenarios for both Cook Inlet and Middle Earth (that has its own statutory tax caps). CHAIR GIESSEL thanked him for his presentation and recessed the meeting to 7:00 p.m. to continue work on SB 130. 7:01:31 PM CHAIR GIESSEL reconvened the Senate Resources Committee meeting at 7:01 p.m. Present at the call to order were Senators Stedman, Coghill, Costello, Wielechowski and Chair Giessel. SENATOR COSTELLO moved the work draft CSSB 130(RES), version 29- GS2609\W, as the working document. CHAIR GIESSEL objected for explanation purposes. 7:02:36 PM AKIS GIALOPSOS, staff to Senator Giessel and the Senate Resources Committee, Alaska State Legislature, Juneau, Alaska, explained the changes in the proposed work draft \W and contrasted those to the changes in existing work order \A. SENATOR MICCICHE joined the committee. SENATOR STOLTZE joined the committee. MR. GIALOPSOS said the changes were as follows: 1. The title is changed to reflect subsequent changes in the committee substitute, and to conform to legislative drafting protocol. 2. Section. 6 of the previous version A of the bill, dealing with confidentiality requirements (in the event that the qualified capital expenditure and well lease expenditure credits in the A version were removed, but the NOL credit had remained) is removed. 3. Language on page 2, line 31 to page 3, line 25 amends the previous Section. 7 of version A by changing the interest rate to 7 percent above the Federal Reserve rate. However, rather than the full six years of accruing a compounded quarterly rate, the interest will only accrue for only three years, and no interest after year three. However, the statute of limitations would be for the full six years. 4. Section. 8 of the previous version A of the bill, dealing with confidentiality requirements, is removed. 5. Language on page 3, line 26, to page 4, line 28, amends the previous Sections. 9, 10, and 11 of version A of the bill, by incorporating a new definition of outstanding liability to the state that is created in a later section. 6. Section. 12 of the previous version A of the bill, hardening the floor at 5 percent, is removed. 7:05:00 PM 7. Page 4, line 29 to page 5, line 19, adds a new Section. 10, repealing the calculation for the Cook Inlet tax cap, as well as the subsection for the tax calculation for gas produced elsewhere in the state for use in-state. 8. Page 5, line 20 to page 7, line 4, adds a new Section. 11, conforming to Section 10. 7:05:34 PM 9. Page 7, lines 5-10, adds a new Section. 12, making oil and gas produced in the Cook Inlet sedimentary basin after January 1, 2018, exempt from any production tax, and prevents an explorer or producer in the basin from acquiring credits. 10. Page 7, line 11 through page 15, line 1, amends the previous Section. 13 in the A version of the bill by removing references to hardening the gross minimum floor, and conforming to the new Section. 10. 7:05:46 PM 11. Page 15, lines 2-23, repeals the previous Section. 14 in the A version of the bill, dealing with interest calculations, and conforming to the new Section. 6 on interest calculations (compounding interest only year one through three). 12. Page 15, lines 24 through page 17, line 10, conforms Sections. 15, 16 of the bill to the new Section. 6 on interest calculations and further conforming to those changes. 7:06:27 PM 13. Section. 17 of the previous version A of the bill, dealing with recalculating the per-barrel credit on a monthly rather than a yearly basis, is removed. 14. Page 17, lines 11-30, adds a new Section. 17 and reduces the Qualified Capital Expenditure Credit to 10 percent as of January 1, 2017. 15. Page 17, line 31, through page 18, line 21, adds a new Section. 18, eliminating the Qualified Capital Expenditure Credit for the Cook Inlet sedimentary basin as of January 1, 2018. 16. Page 18, line 22, through page 19, line 17, amends the prior Section. 18 of the A version of the bill, by eliminating the provision that expired net operating loss credits after 10 years, and adds new language that lowers the Net Operating Loss Credit for non-North Slope activity to 15 percent as of January 1, 2017. The provision that prevented the Gross Value Reduction from enhancing a Net Operating Loss remains in the Committee Substitute. 7:07:24 PM 17. Page 19, line 18, through page 20, line 15, adds a new Section. 20 by conforming to Section. 19 of the Committee Substitute, eliminating the Net Operating Loss Credit for the Cook Inlet sedimentary basin as of January 1, 2018. 18. Page 20, line 16, through page 21, line 2, removes the language in the previous Section. 20 of the A version of the bill, related to the expiration of Net Operating Loss Credits after 10 years. 7:07:51 PM 19. Page 21, lines 3-14, conforms to renumber subsections earlier in the bill. 20. Section. 22 of the previous version A of the bill, dealing with confidentiality requirements, was removed. 21. Sections. 23, 24, and 25 of the previous version A of the bill, provisions that hardened the minimum tax floor, were removed. 22. Page 21, line 15, through page 22, line 7, adds a new Section. 23, lowering the Well Lease Expenditure Credit to 20 percent by January 1, 2017. 7:08:29 PM 23. Page 22, line 8, through page 23, line 3, adds a new Section. 24, conforming to Section. 23 and eliminating the Well Lease Expenditure Credit for the Cook Inlet sedimentary basin by January 1, 2018. 24. Page 23, line 4, through page 24, line 11, adds a new Section. 25 that grandfathers exploration activity that has spudded but not completed in the Frontier Basins (referring to statutes ending in 025). 25. Page 24, line 12, through page 25, line 5, amends the previous Section. 26 of the A version of the bill by removing the limitation on companies to receive credits if their global revenues are in excess of $10 billion/year. It raises the per- company annual refund credit from $25 million to $85 million, and adds language to prevent a company from splitting into subsidiaries in order to claim more than the per-company annual refund limit. 7:09:33 PM 26. Page 25, lines 6-20, amends the previous Section. 27 of the A version of the bill, related to Alaska resident hire. Rather than tying the percentage of cashable credits to a company based upon the rate of Alaska resident hire, the Department of Revenue would be required to promulgate regulations, giving priority for payment from the tax credit fund for companies whose employees, and contractors, have a resident hire rate in excess of 75 percent. 27. Page 25, line 21, through page 26, line 5, amends the previous Section. 27 of the A version of the bill, related to a definition of an outstanding liability to the state. The current definition now defines that only the same amount of a liability to the state for oil and gas-related activity can be used to reserve a credit refund. 7:10:18 PM 28. Page 26, line 8, conforms to the elimination of the Net Operating Loss Credit in the Cook Inlet sedimentary basin; is essentially the same language, renumbered, as the previous Section. 28 of the A version of the bill. 29. The previous Section. 31 of the A version of the bill, preventing the Gross Value at the Point of Production, from going below 0, is removed. 30. Page 27, line 31, through page 30, line 14, adds a new Section. 32 to conform to the elimination of the Cook Inlet tax cap calculation, and the calculation for the tax on gas produced elsewhere in state for use in-state. 7:10:58 PM 31. Page 30, line 15, through page 31, line 34, adds a new Section. 33, conforming to Section. 10 and 33 of the bill. 32. Page 31, lines 5, through page 32, line 18, adds new Sections. 34 and 35, putting a lifespan on oil or gas qualifying for the Gross Value Reduction (new oil), to five years after the production of commercial quantities. For oil or gas that qualifies for the Gross Value Reduction that is in production as of January 1, 2017, the Gross Value Reduction expires on January 1, 2021. 33. Page 36, lines 16-24, adds a new Section. 39 to conform to the changes in Section. 10 of the bill. 7:11:37 PM 34. Page 37, lines 19-25, amends the previous Section. 37 of the A version of the bill, related to the limiting of a tax credit to the municipal entity. The only changes were conforming changes to the legislative drafting manual. 35. The previous Section. 39 of the A version of the bill, the prior definition of outstanding liability to the state, is removed. 7:12:05 PM 36. Page 38, line 19, through page 39, line 27, adds a new Section. 44, requiring a taxpayer seeking a refundable tax credit, to post a surety bond in the amount of $250,000. The bond would serve as financial relief to political subdivisions and local contractors in Alaska in the event the taxpayer entered into bankruptcy. 37. Page 39, lines 28, through page 40, line 2, conforms the Sections. 45, 46, and 47, related to repealing statutes earlier in the bill. 38. Page 40, lines 3-6, adds a new Section. 48, makes Sections. 7-9, 26 and 28 effective January 1, 2017. 39. Page 40, line 7, through page 42, line 9, adds new Sections. 49, 50, 51, and 52 placing transition language for the Qualified Capital Expenditure Credit and the Well Lease Expenditure Credit; the Net Operating Loss Credit and filing of a tax credit. 40. Page 43, line 3, adds a new Section. 55, making Sections. 25 and 53 effective immediately. 41. Page 43, lines 4-5, adds a new Section. 56, making Sections. 10-16, 18, 20, 24, 32, 33, 39, 46, 51 and 52 effective January 1, 2018. 42. Page 43, lines 6-7, adds a new Section. 57, making Sections. 21, 22, 29-31, 36-38, 40, 41, 43, 47, 49, and 50 effective January 1, 2022. 43. Page 43, lines 8-9, adds a new Section. 58, providing that, except for Sections. 55-57, the Act takes effect January 1, 2017. CHAIR GIESSEL opened committee discussion and invited Senator Costello to talk about the interest rate. 7:14:14 PM SENATOR COSTELLO said the average time it takes states to adjust the interest rate for an audit is about three to four years, but in Alaska it takes six years. So the CS goes back to 7 percent compounded quarterly for the first three years and that is followed by three years of no interest rate. The intent is to have the interest rate be less punitive, but at the same time not incentivize the department to take so long, because it is not in anybody's best interest to have this take six years. CHAIR GIESSEL asked her to also comment on how long it takes for the new oil to become mature. SENATOR COSTELLO responded that the first provision is fairer to the companies and takes into account the effect of new oil on the state's treasury and caps new oil at five years, much like a child who passes the infancy stage. So, they said that five years after commercial operations have started, the oil no longer qualifies for the new oil credits. CHAIR GIESSEL said Middle Earth is part of Senator Coghill's district and they have heard from those producers that they are just getting started, and asked him to comment on the changes in the CS related to that. 7:17:06 PM SENATOR COGHILL said it looks like they are grandfathered in except that new language was added saying expenditures for wells and exploration that had to be shown to be "spudded in" by July, 2016. There were no changes to the 023 credits, so "it's workable." CHAIR GIESSEL remarked that that area is working on energy security for the Interior. She asked Senator Stoltze to explain the new approach to the Alaska hire provision. 7:17:52 PM SENATOR STOLTZE said that most Alaskans agree with the governor in the laudable goal of trying to have resident preferences and this bill provides "about as good a defendable chance" as any. He liked that fact that a company is being judged on their previous year's employment performance. It's a more honest approach. Alaska hire is worth "pushing it as far as we can." CHAIR GIESSEL invited Senator Micciche to comment about the surety bond requirement for companies that go bankrupt, something that happened a couple of times in his district on the Kenai. 7:19:34 PM SENATOR MICCICHE said it was a key issue during the Senate Oil and Gas Working group discussions. Some larger companies that were service providers as well as Mom and Pops will never recover a penny from a couple of the companies that "bailed" and dissolved. He explained that the surety bond is proposed for $250,000 and it guarantees that first to be paid would be state and political subdivisions that have an outstanding tax bill or some other liability. Then the most important are identified as persons furnishing labor, material, or renting or supplying equipment to the applicant. He told a story about how a very small Mom and Pop on the Kenai Peninsula that was just simply servicing septic tanks was left holding the bag for thousands of dollars that they couldn't afford. This would clarify that small Alaska companies should come first and be protected when a company can't live up to its financial obligations. This is a reasonable approach that allows a cash deposit if a company chooses not to take out a bond. It is required until a company goes into production and then the company can be relieved by the commissioner or the surety. CHAIR GIESSEL said that Cook Inlet credits were deleted as of 2018, a significant step, with a step down in 2017 when the well lease expenditure credits will drop down to 20 percent, qualified capital expenditures will drop down to 10 percent, and a well down to 10 percent. Then in January, 2018, all credits are removed from the Inlet. Also, going forward, they agree to have no tax structure in Cook Inlet. She said the chart that enalytica provided to both bodies was "pretty jaw dropping." She said that the North Slope companies received $200 million in credits in 2015, and Cook Inlet received $400 million in credits and there was virtually nothing in any kind of revenue to the state. The approach here is to get government's fingers out of the Cook Inlet and let the free market work. Why 2018? Chair Giessel said there are four reasons. Number one, they are in the process of giving Agrium a "go-ahead" to restart the fertilizer plant in Cook Inlet with corporate tax relief that will be equal to the royalty for the gas that they will be using. They will need about 80/mcf/day, which makes it an anchor tenant. This de-constrains the market in Cook Inlet. Second reason: Donlin Creek's pipeline EIS will be completed around 2018. Here is another user of 10-30/mcf gas out of Cook Inlet. Third, Hilcorp has a consent decree from the RCA that will expire in 2018 freeing up a free market paradigm for the pricing of natural gas. And, fourth, by 2018 they will know whether AKLNG is going forward or not. 7:24:32 PM Another change in the CS was made by eliminating the work group that has been proposed by the House. The reason is that establishing a working group going forward is like labeling a "draft" on anything they do this year. The idea here is to rip the Band-Aid off and take care of Cook Inlet and take care of Middle Earth, do some changes on the credits for the North Slope that they believe will still allow companies to go forward, but will also help address Director Alper's chart, which shows the state in unpaid credit card debt that continues to grow each year. 7:26:00 PM SENATOR WIELECHOWSKI asked when other members got this CS; he just got it at 5:50 p.m. CHAIR GIESSEL said it was not distributed before then. SENATOR WIELECHOWSKI said there were quite a few changes and asked if the administration could testify. SENATOR MICCICHE asked what the chair's plan is for a consultant review of the bill's effects. CHAIR GIESSEL answered that Janak Mayer was listening on line and the Department of Revenue and the governor had been briefed on this an hour and a half ago. She also thanked Representatives Mark Neuman and Tammie Wilson for being here. She also mentioned that working group members Senators Wielechowski, Stoltze, Micciche were there and thanked them. She invited the administration forward. 7:27:52 PM COMMISSIONER HOFFBECK said as an overview, the department is largely in agreement with many areas of SB 130, and agrees that this is significant legislation in terms of Cook Inlet. Allowing the Middle Earth credits to stay in place longer is something they recognized also in their bill, because it is an area that is in its infancy and needs a little bit more time to get going. There were no changes to the Governor's bill on NOLs for North Slope. However, it changes the cash flow credit cap, which the governor had capped at $25 million. The earlier versions went to $200 million and $100 million. Now it's at $85 million, which they will model tomorrow. Their biggest concern was that leaving the NOLs in place left the state exposed to paying large sums in credits and some kind of control was needed for the state's annual outlay. SB 130 did not adopt the 5 percent hard floor, one area they don't see exactly the same. But the Governor said this is all in pencil recognizing that this bill has a lot of savings and the answer is in the total numbers, not necessarily in any individual provision. COMMISSIONER HOFFBECK said they would have liked more confidential information disclosure, because when dealing with NOL credits is a little harder than well lease expenditures or qualified capital expenditures that are a little more project- focused and might be a little easier to report. 7:31:23 PM The GVR sunset at five years is another very significant provision that wasn't in the Governor's bill. It was discussed and that is seen as a very significant difference. The interest of 7 percent for three years and no interest after that: their goal is to audit within three years and they don't have a lot of heartburn with giving themselves a little more incentive to get to the three-year audit window. They also recognize how onerous six years of high interest rates can be on an adjustment and this provision provides a balance. They appreciated the fact that the provision allowing for credits to be applied against outstanding liabilities was left in place. 7:32:41 PM COMMISSIONER HOFFBECK said they see some leakage of value in changing the annual true-up to monthly, but that is something that only applies in years of significant volatility and they understand the concern. They support Alaska hire, but had not thought about using it as a mechanism for cuing a company to the front of the credit program. They thought that incentive was a good way of dealing with it if there is ever a shortage in the money available to pay the credits. He said that SB 130 takes out the municipal loophole with the surety bond, and that is also a good idea. Eliminating the working group is consistent with the Governor's treatment of Cook Inlet. They agree that the working group inserted uncertainty into the process. People want to know what they are working with and want a decision to be made. The sliding scale a little different, but again, the Commissioner said it needs to be modeled within the totality of the numbers. He said they could have the model done by mid-day tomorrow. CHAIR GIESSEL said that would great and thanked him. 7:35:38 PM SENATOR MICCICHE asked the logic behind picking $25 million for the credit cap since this bill caps it at $85 million. COMMISSIONER HOFFBECK answered that it was an "anchor number" that had been used in past legislation. They used it as a starting point recognizing that it would be a point of discussion. They also talked about inflation proofing, which would have brought it up into the $40-million range. 7:36:39 PM CHAIR GIESSEL said the $85 million is close to what the 028 fund, at $73 million, is this year. SENATOR COSTELLO commented that the Governor has stated that transparency is important and asked if she assumes correctly that companies can provide information related to their business and receive some assistance. COMMISSIONER HOFFBECK answered that is envisioned in SB 130. If they come forward and ask for additional cashable support, it would be in an open process, and therefore, there would be little bit more knowledge of it. The transparency issues helps the legislature and the public more, because the department sees all the numbers and knows what is going on, but they can't share those numbers to help people understand the thought process and why they are moving forward. But the public has every right to know why the state is "writing big checks." 7:38:46 PM SENATOR MICCICHE said 2014 was a perfect storm situation for the annual versus monthly true-up, and he asked if they recognize that their example has a fairly low probability of becoming a typical trend in oil prices and if that is a significant issue for the state. COMMISSIONER HOFFBECK answered that it could be. Right now it looks like oil prices are going to be constrained between $35 and $65. At $35, people start laying down their equipment, because they are losing money. So, you see a reduction in supply as fields decline. Once the supply/demand becomes unbalanced, prices will start to climb. When they hit the $65 price point, a lot of oil can be brought on line relatively quickly. So, they think it's going to bounce around in that range for quite a while, and when it's in that range it won't be a huge issue. But because there is only about a 3 percent oversupply currently being produced, there is a chance that a spike in price could happen temporarily. Certainly, this bill is consistent with the fact that the state has an annual production tax, and it, therefore, is a policy decision. MR. ALPER added that looking back through the modern era and Alaska as a net profits tax regime, he could imagine an impact if a similar tax regime were in place in the later months of 2008 and the early months of 2009 when the price of oil dipped from the high $140s down to $30-something and then came back up to the $60s through the 2009 legislative session. Everyone could all hope for volatility on the upside next year. SENATOR WIELECHOWSKI asked for a sense of how much more or less SB 130 will generate for the state compared to the governor's bill. MR. ALPER replied that he would try to be evasive until tomorrow after the modeling has been done. In a general sense, all of the fiscal notes that the chart format is using are a mixture of revenues items and savings from expenditures on credits. The CS before the committee, with the absence of the floor hardening provisions, definitely wouldn't see as much on the revenue side, but with the more aggressive Cook Inlet ramp-down they would probably see more on the savings of credit spending, especially in the permanent savings of credits. The more aggressive tax caps in the governor's bill have a bigger short-term impact without question, but to a certain extent, some of that rolls forward into future years where they might see a smaller or even a negative impact as companies are getting the second, third and fourth chunk of their $25 million cap a year. That would have a flatter impact than the $85 million limit. He guessed it's going to be a larger fiscal note than the House Finance CS, but somewhat smaller than the governor's original bill. SENATOR WIELECHOWSKI asked if the House's fiscal note is $900 million. MR. ALPER answered about $150 million. SENATOR WIELECHOWSKI said the fiscal note says "leaves same" on the Senate version of the North Slope NOLs. COMMISSIONER HOFFBECK answered that means the same as the governor's bill. 7:44:27 PM SENATOR WIELECHOWSKI asked him to explain what the explanatory paper says about the sliding scale. The Governor's bill says no change in scale - can't take below 5 percent, and SB 130 says no change in scale - 4 percent status quo. MR. ALPER explained the one part of SB 21 that truly hardened the floor referred to the sliding-scale, per-barrel credit for legacy oil from zero to $8. That calculation cannot bring a tax below 4 percent, and that is solid. This is where the state's revenue came from in 2015 and that it is still getting. The Governor's bill proposed saying other credits - the operating loss credit, the $5/barrel credit, small producer credit, et cetera also - could not go below the floor. That is the part that was removed from the CS. The Governor also proposed bringing all of that to 5 percent. So, the sliding-scale credit continues to be hardened to 4 percent as in current law, and it's not being increased to 5 percent as in the governor's proposal. CHAIR GIESSEL clarified that she drew up the quick reference document he was referring to. SENATOR WIELECHOWSKI said he would just wait for the department's analysis tomorrow. SENATOR MICCICHE said it looks like at $40/barrel the state saves about $28 million in hardening the floor from 4 to 5 percent until the price goes over the minimum range at $75. He asked Mr. Alper if he agreed that the reduction in Cook Inlet credit dramatically offsets hardening the floor. MR. ALPER answered that the chart Senator Micciche was referring to talked about the specific impact of increasing the floor from 4 to 5 percent. That was sort of the second phase of the minimum tax change, the first phase being hardening the other credits to the 4 percent level and that change brought in about another $50 million in addition to the $50 million in the original bill (according to the fall forecast). But by the time the spring forecast came out, the North Slope major producers applied for much larger NOL credits, and the fiscal impact of the hardening became close to a $150 million line item (with that chart, it boosted the revenue to about $200 million). That is the full revenue impact of the floor hardening and increasing provision that is not in the CS. SENATOR MICCICHE asked a question about how the value of hardening the Cook Inlet credits versus eliminating them would compare to keeping the 4 percent floor. MR. ALPER responded that the Cook Inlet credits in the enalytica's chart were $404 million in 2015 and that number is scheduled to step down a little bit just because of a reduction in activity in the Cook Inlet. Whatever that number is reduced by is what they will be saving. Hardening the floor means that NOLs aren't being used to go below the floor and they will eventually be paid to the company through reduced taxes in a future year. Other than the time value there is "something of a net zero in that hardening," but that increases as the stack of NOL credits get carried forward. CHAIR GIESSEL removed her objection to adopting the CS and finding no other objections, announced that CSSB 130(RES), 29- GS2609\W, was before the committee. She then invited Mr. Mayer to comment on the CS, which was posted on BASIS an hour and a half ago. 7:49:59 PM JANAK MAYER, enalytica, Legislative Consultant, Washington, D.C., said he liked the way the chair framed the Cook Inlet versus North Slope credit/revenue picture in the context of enalytica's slide. He said they tried to highlight consistently that for FY15 they are talking $2.2 billion in total restricted and un-restricted revenues. Compare that to [$324 million] in credits. Cook Inlet is a very different ratio with less than $100 million in revenues and more than $400 million in credits for FY15. Other types of credits: the North Slope has two credit areas left. One is the trailing expenditure things like exploration credit, the small producer credit, the dollar per-barrel credit, and the NOL credit, a mechanism of deducting expenses when there isn't sufficient revenue to deduct it in a current year. All net profit taxes have the ability to deduct expenses in an appropriate year, in most cases as a carry forward against a future liability. In all situations, the amount of the NOLs isn't changed by any of the proposals before them. Whether the credits can be used to go below the floor or when the credit can be taken are simply about the timing of payments, not about the actual amounts of the payments. 7:54:51 PM MR. ALPER said having priorities makes a lot of sense. What is proposed in Cook Inlet goes beyond the Governor's bill or some of the House proposals. What they have said consistently on Cook Inlet is that with ongoing drilling one doesn't have all the expenses of new facility developments; simple ongoing drilling in the mature fields is economic in a wide range of circumstances. Enalytica has said economics are most difficult when they are constrained by a new development with substantial facilities, since those are additional capital expenditures. Those could be economic if one has a substantial resource and demand, but without that, they are very difficult. The obvious concern with this approach is the timing. If one simply cuts off all of the credits except the net operating loss effective July 2016, companies have already committed to major work programs. So, that suddenly puts them in jeopardy and potentially prevents the work from going ahead. Pushing that date out would allow ramping down a little more slowly and could resolve that problem. MR. MAYER said the small independent producers are stopping now; in particular, Furie at Kitchen Lights started production last year and now has had a small amount of gas production. BlueCrest is making substantial progress towards their oil project; one wants to see companies like that able to continue the work they are doing through next year and able to get to the point where they have recovered some substantial portion of their initial investment and can at least be cash-flow-sustaining moving forward. Hopefully Cook Inlet can get to the point of broad free market principles going forward from 2018 rather than continuing to rely on government intervention. 7:58:47 PM He said stopping the massive outlay of credits is okay as long as that can be seen as genuine and durable and there is every reason to think that could be quite a favorable environment for investment - in particular for ongoing reinvestment in the mature fields. The biggest barrier to that at the moment is the much uncertainty as to what the future fiscal regime looks like. One could address that by making it very clear that this is absolutely the future of the regime and it's not going to change. On the North Slope the question of old versus new oil: at the moment the 4 percent floor is essentially hard all the way down until the point that a company stops being eligible for a net operating loss (NOL). That is a substantial change from the situation under ACES and before where most of the production tax revenue for the last year or two has come from. Once a company reaches the point of being eligible for NOL credits, that by definition is levying a tax on a producer with nothing but a loss. In that sense, one should be very careful about proceeding with floor hardening in terms of it coming at a time when companies are most strapped for cash or when cash is actually negative and going out the door. Trying to extract more on that front seems like not necessarily an ideal policy move. MR. MAYER advised because one can carry expenses forward, the impact of the floor hardening is a question of timing and not of absolute amounts. One needs to keep in mind what the dynamic of pushing those payments out into future years looks like in a time when eventually oil prices do rise and how that plays into how the system works. At the moment it's relatively easy for the Alaska public to understand that the state's fiscal situation is highly constrained because of low oil prices. It's one thing to understand that, but it's another for prices to start to rise and to find that the state is still financially constrained, not because of oil prices, but because of the hangover, a substantial hangover potentially, of having to pay deferred credits. Hardening the floor simply means that there is this trailing tail of NOL credits that can be carried forward potentially into many years. Not hardening the floor means not putting more pain on the companies that are cash-flow negative at the moment. But it also recognizes essentially that liability to the state now rather than pushing it off into future years. 8:03:12 PM On the question of the cashable NOL amounts, Mr. Mayer said they have said that the $25-million cap has a substantial impact on companies that are eligible for the cashable NOL credit who are currently developing. In many cases, that could mean one is making a $1.3 billion capital investment. For that sort of project, one might only need $300 or $400 million of initial capitalization combined with cashable NOL credits to make it work before it came self-sustaining from the cash flow perspective. A $25-million cap substantially changes that picture. It could take a $350-million project and turn it into a $500 million project in many cases. For companies currently undertaking this activity, that is a major impact. The impact, for instance, of the $100-million cap is much less in most cases, at the moment not binding on most companies and simply will protect against a future major development that could lead to major credit outflows for the state. An $85-million cap might start to have some effect on some current companies, but it avoids many of the worst effects of a $25-million cap. 8:05:17 PM Finally, Mr. Mayer talked about the impact of moving the gross value reduction (GVR) to five years. When SB 21 question of should this time be limited for the life of a new project was discussed. One could structure that benefit in a range of ways, but one of the key things to understand is that for many new developments, there are several years of substantial ongoing drilling and reinvestment that takes place before a project can sustain that initial production plateau for five years and become a taxpayer. While there is substantial merit around the question of extending the GVR indefinitely or not, he could do some modeling, but it may well be the case that for many new developments a five-year limit actually means that the GVR itself, has very little impact at all either on economics or on the total amount of tax that the project pays. The question then is for existing GVR project owners and investors the substantial change in the tax system and in those circumstances the GVR is actually delivering the benefit it was designed to do - in terms of making the economics of a new field on the North Slope more attractive. 8:07:34 PM CHAIR GIESSEL asked when his analysis would be available. MR. MAYER answered tomorrow afternoon. [SB 130 was held in committee.] 8:08:34 PM CHAIR GIESSEL adjourned the Senate Resources Standing Committee meeting at 8:08 p.m.

Document Name Date/Time Subjects
CSHB 216(RES) - Sponsor Statement.pdf SRES 4/11/2016 3:30:00 PM
HB 216
CSHB 216(RES) - Legislation Ver. N.pdf SRES 4/11/2016 3:30:00 PM
HB 216
CSHB 216(RES) - Sectional Analysis.pdf SRES 4/11/2016 3:30:00 PM
HB 216
CSHB 216(RES) - Fiscal Note - DNR-MLW-3-14-2016.pdf SRES 4/11/2016 3:30:00 PM
HB 216
CSHB 216(RES) - Summary of Changes (Ver. W to N).pdf SRES 4/11/2016 3:30:00 PM
HB 216
HCR17 Sponsor Statement 2-1-2016.pdf SRES 4/11/2016 3:30:00 PM
HCR 17
CSHCR17 Summary of Changes 3-15-2016.pdf SRES 4/11/2016 3:30:00 PM
HCR 17
HCR17-LEG-COU-03-15-16.pdf SRES 4/11/2016 3:30:00 PM
HCR 17
HCR17-Final Version E.PDF SRES 4/11/2016 3:30:00 PM
HCR 17
CSSB130-Explanation of Changes-Version W.pdf SRES 4/11/2016 3:30:00 PM
SB 130
CSSB130-Version W.pdf SRES 4/11/2016 3:30:00 PM
SB 130