Legislature(2011 - 2012)SENATE FINANCE 532

03/27/2012 01:00 PM FINANCE


Download Mp3. <- Right click and save file as

Audio Topic
01:08:58 PM Start
01:10:32 PM Presentation: Department of Natural Resources
02:19:37 PM SB192
03:32:14 PM Adjourn
* first hearing in first committee of referral
+ teleconferenced
= bill was previously heard/scheduled
+= SB 192 OIL AND GAS PRODUCTION TAX RATES TELECONFERENCED
Heard & Held
+ Bills Previously Heard/Scheduled TELECONFERENCED
                 SENATE FINANCE COMMITTEE                                                                                       
                      March 27, 2012                                                                                            
                         1:08 p.m.                                                                                              
                                                                                                                                
                                                                                                                                
1:08:58 PM                                                                                                                    
                                                                                                                                
CALL TO ORDER                                                                                                                 
                                                                                                                                
Co-Chair Stedman called the Senate Finance Committee                                                                            
meeting to order at 1:08 p.m.                                                                                                   
                                                                                                                                
MEMBERS PRESENT                                                                                                               
                                                                                                                                
Senator Lyman Hoffman, Co-Chair                                                                                                 
Senator Bert Stedman, Co-Chair                                                                                                  
Senator Lesil McGuire, Vice-Chair                                                                                               
Senator Johnny Ellis                                                                                                            
Senator Dennis Egan                                                                                                             
Senator Donny Olson                                                                                                             
Senator Joe Thomas                                                                                                              
                                                                                                                                
MEMBERS ABSENT                                                                                                                
                                                                                                                                
None                                                                                                                            
                                                                                                                                
ALSO PRESENT                                                                                                                  
                                                                                                                                
William  C.  Barron,  Director, Division  of  Oil  and  Gas,                                                                    
Department  of  Natural  Resources;  Janak  Mayer,  Manager,                                                                    
Upstream and  Gas, PFC Energy; Senator  Joe Paskvan; Senator                                                                    
Cathy Giessel;                                                                                                                  
                                                                                                                                
SUMMARY                                                                                                                       
                                                                                                                                
SB 192    OIL AND GAS PRODUCTION TAX RATES                                                                                      
                                                                                                                                
          SB 192 was HEARD and HELD in committee for                                                                            
          further consideration.                                                                                                
                                                                                                                                
PRESENTATION: DEPARTMENT OF NATURAL RESOURCES                                                                                   
          William C. Barron, Director, Division of Oil and                                                                      
          Gas, Department of Natural Resources                                                                                  
                                                                                                                                
                                                                                                                                
Co-Chair Stedman discussed the meeting's agenda.                                                                                
                                                                                                                                
SENATE BILL NO. 192                                                                                                           
                                                                                                                                
     "An Act relating to the oil and gas production tax;                                                                        
     and providing for an effective date."                                                                                      
                                                                                                                                
^PRESENTATION: DEPARTMENT OF NATURAL RESOURCES                                                                                
                                                                                                                                
1:10:32 PM                                                                                                                    
                                                                                                                                
WILLIAM  C.  BARRON,  DIRECTOR, DIVISION  OF  OIL  AND  GAS,                                                                    
DEPARTMENT  OF NATURAL  RESOURCES, continued  the Department                                                                    
of   Natural  Resources'   PowerPoint  presentation   titled                                                                    
"Senate  Finance Committee  26  March 2012"  (copy on  file)                                                                    
from  the  previous  meeting.  He  stated  that  during  the                                                                    
previous meeting, the presentation  had covered the ways and                                                                    
means  of  the  state's  ability  to  dispose  of  land  and                                                                    
furthered that the primary aspects  of land disposition were                                                                    
through the area wide lease sale.  He noted that some of the                                                                    
terms  and  conditions of  the  bonus  and rental  programs,                                                                    
which  were in  place  on  the North  Slope  and Cook  Inlet                                                                    
areas, had also been discussed in the prior meeting.                                                                            
                                                                                                                                
Mr.   Barron  explained   the  slide   on   page  6   titled                                                                    
"exploration   licensing  system."   He   stated  that   the                                                                    
exploration licensing  system was the other  opportunity for                                                                    
land disposition.                                                                                                               
                                                                                                                                
          Exploration Licensing System:                                                                                         
                                                                                                                                
                                                                                                                                
        · Areas not within area wide lease sales                                                                                
                                                                                                                                
        · No rental fee or upfront bonus payment                                                                                
                                                                                                                                
        · Term up to 10 years                                                                                                   
                                                                                                                                
             · When work commitment is fulfilled, licensee                                                                      
               may convert part or all of license area to                                                                       
               leases (subject to $3/acre rental fee and,                                                                       
               when producing, no less than 12.5% royalty)                                                                      
                                                                                                                                
                                                                                                                                
        · State is provided all geological & geophysical                                                                        
          information acquired                                                                                                  
                                                                                                                                
        · If competing proposals, highest bid for minimum                                                                       
          work commitment is selected                                                                                           
        · Imposes financial work commitments (AS 38.05.131-                                                                     
          .134)                                                                                                                 
                                                                                                                                
        · Licensee must commit 25% of total specified work                                                                      
          commitment by fourth anniversary of license                                                                           
          issuance                                                                                                              
                                                                                                                                
Mr.  Barron stated  that  the  exploration licensing  system                                                                    
applied to areas  that were not in the area  wide lease sale                                                                    
and that  the two  programs were  distinct and  separate. He                                                                    
explained that the  ten year term of  an exploration license                                                                    
operated on the  basis that companies would  come forward to                                                                    
designate  an area  of interest  and propose  financial work                                                                    
commitments. A company's license could  be revoked if it had                                                                    
not  completed 25  percent of  its fiscal  commitment within                                                                    
the first four  years. After the ten year  term expired, the                                                                    
area within the exploration license  could be converted to a                                                                    
lease, or multiple  leases, for another five  year term; the                                                                    
five  year extension  provided the  program with  additional                                                                    
exploration  and delineation,  and would  hopefully progress                                                                    
the  property into  development. He  stated that  there were                                                                    
only four  areas participating in the  exploration licensing                                                                    
system  and that  the program  was not  widely utilized.  He                                                                    
concluded that the  area wide lease sale was  more honed for                                                                    
the exploration of oil and gas in Alaska.                                                                                       
                                                                                                                                
1:13:31 PM                                                                                                                    
                                                                                                                                
Mr. Barron  explained the  slide on  page 7  titled "current                                                                    
status of state leases."                                                                                                        
                                                                                                                                
        · Active leases: 1416 leases (largest tract: 9                                                                          
          square    miles)                                                                                                      
                                                                                                                                
        · Of these, 46% of leases are in units (producing)                                                                      
                                                                                                                                
        · 0.5% are leases producing without being in units                                                                      
                                                                                                                                
        · 46% of leases are in the hands of companies                                                                           
          currently actively exploring on part of their                                                                         
          lease hold*                                                                                                           
                                                                                                                                
             · Apache, Buccaneer, Nordaq, LINC, Repsol,                                                                         
               Great Bear, Brooks Range, Anadarko                                                                               
             · Included in this number are Foothills leases                                                                     
               where lessees have conducted field work in                                                                       
               the past (gas-prone areas)                                                                                       
                                                                                                                                
        · The remaining 7.5% may or may not be under                                                                            
          exploration                                                                                                           
                                                                                                                                
             · A majority of these leases (approximately                                                                        
               95%) are held by individuals or groups of                                                                        
               individuals, not major corporations                                                                              
                                                                                                                                
   *The list is not extensive; this only includes companies                                                                     
    we know are currently actively exploring.                                                                                   
                                                                                                                                
Mr.  Barron explained  that the  slide did  not include  the                                                                    
December 2011  lease sale  on the North  Slope; most  of the                                                                    
North Slope leases had yet  to be adjudicated and were still                                                                    
within  the confines  of the  state's  ownership. He  stated                                                                    
that the 9 square mile plot  was included because it was the                                                                    
largest lease that  was allowed by statutes.  He pointed out                                                                    
that  many of  the  international arenas  used "blocks"  and                                                                    
that in  these countries,  a block could  be a  single lease                                                                    
that was  180 to  190 square  miles; a  block this  size was                                                                    
roughly half the  size of Prudhoe Bay. He  stated that there                                                                    
was  a  significant  difference of  understanding  regarding                                                                    
concessions in  international regimes  and what  occurred in                                                                    
Alaska.  He explained  that many  countries packaged  blocks                                                                    
together  and might  have as  many as  six different  blocks                                                                    
that were  offered at  the same time.  He referenced  the 46                                                                    
percent figure,  which was  in the  fourth bullet  point and                                                                    
explained that Apache had acquired  and explored a number of                                                                    
tracts in the  Cook Inlet lease sale the  prior year. Apache                                                                    
was  doing seismic  work  and  was systematically  "shooting                                                                    
seismic" that  would eventually cover  all of its  tracts of                                                                    
land.  He stated  that  the 46  percent  figure showed  that                                                                    
although  companies  might  not   be  actively  drilling  or                                                                    
shooting seismic  on every single  tract of land,  they were                                                                    
making progress through the activity.                                                                                           
                                                                                                                                
Mr.  Barron  pointed  out that  Alaska's  lease  terms  were                                                                    
competitive based  and that anyone  who was 18 years  of age                                                                    
could own a lease in Alaska.  He opined that there were many                                                                    
different  kinds   companies  in  the  oil   industry;  some                                                                    
companies  primarily  focused  on exploration,  some  had  a                                                                    
primary paradigm of development,  while others had a primary                                                                    
corporate  function  that  was referred  to  as  "brownfield                                                                    
operations."   He  explained   that   explorers  and   early                                                                    
developers   represented   "greenfield  operations",   while                                                                    
activities on mature fields were  referred to as "brownfield                                                                    
operations."                                                                                                                    
                                                                                                                                
Mr. Barron  stated that  speculators actively  purchased and                                                                    
marketed  leases to  other players  and that  they served  a                                                                    
critical function in lease sales.  He offered that Armstrong                                                                    
Alaska  was  a  good  example  of  company  that  was  in  a                                                                    
speculator  mode.  He   explained  that  Armstrong  Alaska's                                                                    
ability to market land had  attracted companies like Repsol,                                                                    
Pioneer  Natural   Resources  Alaska,  and   ENI  Petroleum;                                                                    
furthermore,   Armstrong  was   currently   doing  its   own                                                                    
development work  in the Kenai  Peninsula. He  observed that                                                                    
although a  company like Armstrong  tended to focus  on land                                                                    
management,  it served  a valuable  function in  the state's                                                                    
development of oil and gas.                                                                                                     
                                                                                                                                
1:19:54 PM                                                                                                                    
                                                                                                                                
Senator Thomas referenced the last  bullet point on slide 6.                                                                    
He inquired if  pursuing the sale of a  lease was considered                                                                    
a "work  commitment", or  if the term  meant that  a company                                                                    
must  commit to  some form  of exploration  and/or drilling.                                                                    
Mr.  Barron responded  that slide  6 dealt  with exploration                                                                    
licenses,  but that  a work  commitment was  not necessarily                                                                    
associated with  the area wide  lease sale. He  offered that                                                                    
work commitments  can be  part of  a lease  sale opportunity                                                                    
and  that  the  state  had   the  ability  to  specify  work                                                                    
commitments,  as  part  of  the  original  bid,  during  the                                                                    
exploration  phase; work  commitments were  imposed in  this                                                                    
fashion as  recently as last  year in  the case of  the Cook                                                                    
Inlet's  Cosmopolitan  Unit.  He   explained  that  for  the                                                                    
Cosmopolitan Unit,  the state had  required entities  to bid                                                                    
on  leases that  were  packaged together  and also  required                                                                    
that over  a period  of time,  the companies  must identify,                                                                    
drill, and  establish a participating  area (PA)  within the                                                                    
lease area.  He stated that  requiring a work  commitment as                                                                    
part  of  bid  might  have  some  merit,  but  that  it  was                                                                    
problematic  to require  a company  to know  what its  plans                                                                    
were  before it  had  won  the bid.  He  furthered that  the                                                                    
bidding system  was competitive and that  the problem facing                                                                    
a  company was  how  to  put together  a  work plan  without                                                                    
knowing what  it had  won or the  level of  prospectivity in                                                                    
the area that it was trying to develop.                                                                                         
                                                                                                                                
Senator  Thomas acknowledged  that  it was  helpful to  have                                                                    
speculators, but  pointed out  that most  of the  people who                                                                    
were looking  to develop oil  or gas properties would  be at                                                                    
the lease  sale. He referenced  a speculator's  abilities to                                                                    
bid, buy, and hold onto land  and stated that he had assumed                                                                    
that both the  area wide lease sale  and exploration license                                                                    
systems had  work commitment  requirements. He  queried what                                                                    
the requirements were  on potential buyer, and  at what time                                                                    
was  the  lease  holder  required   to  deliver  a  work  or                                                                    
development plan.  Mr. Barron replied  that with  respect to                                                                    
an  exploration license,  a company  would identify  what it                                                                    
would  spend   on  a  property,   but  that  it   would  not                                                                    
necessarily define  the type  of work.  In the  state's area                                                                    
wide leasing system, the state  specified that companies pay                                                                    
a rental tax  for the first seven years that  they owned the                                                                    
property; if  no or little work  had been done by  the seven                                                                    
year point, the  rental rates would go  up significantly for                                                                    
years  eight, nine,  and ten.  He explained  that the  three                                                                    
year  period  of  increased rental  rates  was  intended  to                                                                    
encourage  companies of  interest  to  develop. He  observed                                                                    
that  there was  a  possibility of  blending  the area  wide                                                                    
lease  sale and  the exploration  license systems,  but that                                                                    
"is  not where  we  are  today." He  concluded  that if  the                                                                    
state's  area  wide  lease  system required  a  bid  and  an                                                                    
assured financial commitment from  an entity, it could limit                                                                    
the players that would be  willing to participate in the oil                                                                    
and gas sector in Alaska. He  offered that DNR's goal was to                                                                    
attract as many  people or companies as  possible to Alaska,                                                                    
encourage and support the  exploration efforts of companies,                                                                    
and to quickly drive discoveries into development.                                                                              
                                                                                                                                
1:26:48 PM                                                                                                                    
                                                                                                                                
Mr.  Barron  discussed the  slide  on  page 8  titled  "land                                                                    
management: When is  PA formed?" A "unit" was  formed when a                                                                    
discovery  was proven  to  have  moveable hydrocarbons.  The                                                                    
purpose of forming a unit  was the protection of all parties                                                                    
associated  with  the  reservoir.  He  explained  that  some                                                                    
reservoirs  crossed  over lease  boundaries  and  that as  a                                                                    
result, multiple leases were sometimes formed into a unit.                                                                      
                                                                                                                                
        · A PA is formed once the unitized reservoir is on                                                                      
          "sustained production": wells are producing into                                                                      
          a pipeline or other means of transportation to                                                                        
          market                                                                                                                
                                                                                                                                
        · Separate PA required for each producing horizon                                                                       
                                                                                                                                
        · Approval of a PA includes approval of allocation                                                                      
          factors                                                                                                               
                                                                                                                                
             · Sets out proportions of costs and revenues                                                                       
               paid and received by working interest owners                                                                     
             · Approval meets 11 AAC 83.303: Protect all                                                                        
               parties                                                                                                          
                                                                                                                                
Mr. Barron explained  the slide on page 9 titled  "What is a                                                                    
plan of development (POD)?"                                                                                                     
                                                                                                                                
        · Once a PA is formed, a POD is required under 11                                                                       
          AAC 83.343                                                                                                            
                                                                                                                                
             · Must be filed for approval if a PA is                                                                            
               proposed,    or     reservoir    sufficiently                                                                    
               delineated     to    initiate     development                                                                    
               activities                                                                                                       
             · POD is submitted annually for review and                                                                         
               approval                                                                                                         
             · If POD deemed insufficient for approval, DNR                                                                     
               may propose modifications. If Operator                                                                           
               agrees to modifications, POD approved.                                                                           
             · If not accepted by Operator, and no approved                                                                     
               POD, current POD may expire.                                                                                     
                                                                                                                                
        · Development activities must be conducted under an                                                                     
          approved POD                                                                                                        
                                                                                                                                
Co-Chair  Stedman requested  an accelerated  run through  of                                                                    
the  slides. He  noted  that the  committee  was focused  on                                                                    
budget issues,  while some  of the  slides were  more geared                                                                    
towards resources.                                                                                                              
                                                                                                                                
Mr.  Barron discussed  the slide  on page  11 titled  "North                                                                    
Slope units and  PAs: February 2012. 18  existing SOA units,                                                                    
42 PAs,  2 units  proposed." Mr.  Barron related  that there                                                                    
were 18  existing units, 42  PAs, and two proposed  units on                                                                    
the North Slope.                                                                                                                
                                                                                                                                
Mr.  Barron  discussed the  slide  on  page 12  titled  "POD                                                                    
process"  and explained  that the  process flow  diagram was                                                                    
for the committee's future reference.                                                                                           
                                                                                                                                
Mr.   Barron  discussed   the  slide   on  page   13  titled                                                                    
"evaluating PODs on a complex  unit - DOG evaluation tools."                                                                    
He stated that  the state used the "score  sheet" to compare                                                                    
past PODs.  The "bubble  map" helped  DNR identify  areas of                                                                    
concern or interest  that it would like a  company to target                                                                    
closer.                                                                                                                         
                                                                                                                                
Mr. Barron  explained the slide  on page 14  titled "Kuparuk                                                                    
River  Unit(KRU)  bubble  map."  He stated  that  the  slide                                                                    
depicted Kuparuk  and that  the map  showed a  "classic line                                                                    
drive waterflood"  reservoir. He  offered that the  map very                                                                    
clearly  showed  where the  water  was  pushing the  oil  to                                                                    
producers.                                                                                                                      
                                                                                                                                
Mr. Barron discussed the slide  on page 15 titled "southwest                                                                    
portion  Kuparuk River  Unit (KRU)."  He  observed that  the                                                                    
lower  left   hand  corner   of  the   map  was   devoid  of                                                                    
developments and  that the state had  several dialogues with                                                                    
ConocoPhillips, which had resulted  in the well Sharks Tooth                                                                    
being drilled in the area  "this winter." Sharks Tooth was a                                                                    
confidential well  and DNR  had not yet  seen the  logs from                                                                    
the development.                                                                                                                
                                                                                                                                
Mr. Barron  explained the slide  on page 16  titled "Prudhoe                                                                    
Bay  Unit"  and  explained  that   the  slide  depicted  how                                                                    
reservoirs were stacked  on top of each other.  PAs could be                                                                    
stacked on top of each other for every producing horizon.                                                                       
                                                                                                                                
1:31:21 PM                                                                                                                    
                                                                                                                                
Mr. Barron  discussed the slide  on page 17. He  stated that                                                                    
DNR was  in constant  discussion with  the operators  in the                                                                    
slide's  the two  mapped areas  regarding  future plans  for                                                                    
development,  increased  production,  and  development  area                                                                    
expansion.                                                                                                                      
                                                                                                                                
Mr. Barron  explained the slide  on page 20  titled "Prudhoe                                                                    
Bay Unit, oil  and water production rates."  He related that                                                                    
there  had been  a lot  of discussion  regarding facilities,                                                                    
facility   constraints,  future   development,  and   future                                                                    
operations. He  offered that the  perception was  that there                                                                    
was  excess capacity  in  the  Trans-Alaska Pipeline  System                                                                    
(TAPS). In  the original  development phase  of any  oil gas                                                                    
property,  facilities were  designed to  handle fluids  in a                                                                    
certain manner.  He stated  that in a  1,000 barrel  per day                                                                    
(bbl/d) facility,  900 of  the barrels  might be  oil, while                                                                    
100 barrels would be water;  it was still considered a 1,000                                                                    
bbl/d facility. He  furthered that as the life  of the field                                                                    
neared its end, there may 100  bbl/d of oil and 900 bbl/d of                                                                    
water  being  produced  from the  facility;  this  was  also                                                                    
considered a 1,000 bbl/d facility.  He added that regardless                                                                    
of the ratio  of water to oil, a 1,000  bbl/d facility would                                                                    
only  be able  to handle  1,000  bbl/d. He  stated that  the                                                                    
slide showed that Prudhoe Bay's oil was declining.                                                                              
                                                                                                                                
Mr. Barron  discussed the slide  on page 21  titled "Prudhoe                                                                    
Bay  Unit,  total  fluid   production  and  water  injection                                                                    
rates."  The   slide  showed   that  the   production  total                                                                    
throughput of oil and water  had basically remained constant                                                                    
since the  year 2000.  He added that  after 2000,  the rates                                                                    
did  drop a  little and  that  the question  was, what  else                                                                    
could be impacting  the production. He added  that there was                                                                    
excess  capacity  in the  Prudhoe  Bay  Unit, but  that  the                                                                    
system was handling more gas.                                                                                                   
                                                                                                                                
Mr. Barron  explained the slide  on page 22  titled "Prudhoe                                                                    
Bay water oil  ratio, Prudhoe Bay gas oil  ratio." He stated                                                                    
that the  water to oil ratio  and the gas to  oil ratio were                                                                    
depicted on the slide's two  graphs. As the Prudhoe Bay Unit                                                                    
injected gas  for pressure maintenance,  more gas had  to be                                                                    
processed; furthermore,  water was injected to  maintain the                                                                    
waterflood,  which resulted  in  a higher  demand for  water                                                                    
processing.  He  concluded  that  many of  the  Prudhoe  Bay                                                                    
facilities  were limited  in capacity  by water  or gas.  He                                                                    
related that  Prudhoe Bay's reservoir engineers  had done an                                                                    
"amazing" job  in the development  and asset  allocation for                                                                    
the field. He added that  originally, the field was expected                                                                    
to have  a 30  percent recovery rate,  but that  the current                                                                    
rate  was  approaching  60  percent.   He  stated  that  the                                                                    
engineers had  sophisticated reservoir simulation  tools and                                                                    
that they were able to  prognostic which wells would produce                                                                    
more water  or more gas;  the engineers "shut in"  the wells                                                                    
with more gas. The engineers'  process limited the amount of                                                                    
investments  that  were  needed for  facility  upgrades  and                                                                    
"debottlenecking", and enabled the  engineers to predict and                                                                    
control which wells  to turn on or off; well  work overs and                                                                    
recompletions would  then be  conducted for  the appropriate                                                                    
wells.                                                                                                                          
                                                                                                                                
Mr. Barron  discussed the slide  on page 23  titled "Kuparuk                                                                    
River,  oil  and water  production  rates."  He stated  that                                                                    
Kuparuk was experiencing  the same curves for  oil and water                                                                    
as Prudhoe Bay.                                                                                                                 
                                                                                                                                
1:35:32 PM                                                                                                                    
                                                                                                                                
Co-Chair Stedman asked  for a clarification on  slide 20. He                                                                    
observed that from 1987 and  onwards, the green line fit the                                                                    
definition of a parabolic curve  and inquired if it appeared                                                                    
to  be flattening.  Mr. Barron  queried if  Co-Chair Stedman                                                                    
was referring  to the  last three years  of the  green line.                                                                    
Co-Chair Stedman  responded in  the affirmative.  Mr. Barron                                                                    
stated that  the plot, from  an engineer's  perspective, was                                                                    
drawn  incorrectly.  He explained  that  the  y axis  for  a                                                                    
decline curve should be a  "log curve" [logarithmic] instead                                                                    
of  a "Cartesian  curve." He  explained that  in a  semi-log                                                                    
presentation, the line  would be close to  straight and that                                                                    
although  the  decline appeared  to  be  flattening, it  was                                                                    
almost straight; the  curve was referred to  as a "straight-                                                                    
line depression."                                                                                                               
                                                                                                                                
Co-Chair Stedman requested that  DNR's future charts reflect                                                                    
the oil  production in logarithmic  and nominal  scales. Mr.                                                                    
Barron responded that DNR would be happy to do so.                                                                              
                                                                                                                                
Mr. Barron  explained the slide  on page 24  titled "Kuparuk                                                                    
River, total  fluid production  and water  injection rates."                                                                    
He stated  that the Kuparuk  curves were similar  to Prudhoe                                                                    
Bay's  curves and  that  the gas  to oil  and  water to  oil                                                                    
ratios were  elevating. He  offered that  the curves  on the                                                                    
slide were  very similar to any  other primary, conventional                                                                    
oil and gas field in the  world; he added that shale oil was                                                                    
an  exception  to  the similarity.  He  concluded  that  the                                                                    
decline  curve analysis,  the oil  decreasing  with the  gas                                                                    
increasing,  and  the  water increasing  with  waterflooding                                                                    
were typical of other fields around the world.                                                                                  
                                                                                                                                
Co-Chair  Stedman asked  how long  ago DNR  would have  been                                                                    
able  to  "draw that  conclusion."  Mr.  Barron stated  that                                                                    
Prudhoe Bay's decline could have  been predicted as early as                                                                    
1989 to 1990.                                                                                                                   
                                                                                                                                
Co-Chair Stedman  inquired whether  the decline  curve would                                                                    
have been  expected when  the basin  was opened.  Mr. Barron                                                                    
replied that  the curve was  predictable in  a conventional,                                                                    
sandstone reservoir.  He added  that the field  would manage                                                                    
itself  and  that  the  exact   rate  of  decline  would  be                                                                    
determined later  on. He  stated that  a "type  curve match"                                                                    
analysis, which  used models of  similar fields,  could have                                                                    
predicted the flat section, the  plateau, and some sort of a                                                                    
rate of decline.                                                                                                                
                                                                                                                                
Co-Chair Stedman  inquired if the  analysis in  question was                                                                    
referred  to   as  a  "type  curve   analysis."  Mr.  Barron                                                                    
responded in the affirmative.                                                                                                   
                                                                                                                                
1:39:30 PM                                                                                                                    
                                                                                                                                
Co-Chair Stedman  observed that  some people  were surprised                                                                    
about  where  the rate  of  decline  was today.  Mr.  Barron                                                                    
voiced his agreement.                                                                                                           
                                                                                                                                
Senator Thomas referenced  slides 21 and 24.  He stated that                                                                    
in 1993, the  total liquids production from  Prudhoe Bay and                                                                    
Kuparuk combined  was approximately  3.2 million  bbl/d. Mr.                                                                    
Barron replied that he would  not argue the numbers. Senator                                                                    
Thomas  inquired if  gas handling  issues were  limiting the                                                                    
maximum level  of the fluid production  and water injections                                                                    
rates  in  the  two  fields. Mr.  Barron  responded  in  the                                                                    
affirmative.  He referenced  slide  22 and  stated that  gas                                                                    
handling  limitations   were  indicative  to  some   of  the                                                                    
facilities.                                                                                                                     
                                                                                                                                
Senator Thomas queried if the  facilities in Prudhoe Bay and                                                                    
Kuparuk had a  maximum level of oil and  water production of                                                                    
about 3.2 million bbl/d. Mr.  Barron agreed that 3.2 million                                                                    
bbl/d was probably a good number to use.                                                                                        
                                                                                                                                
Mr. Barron  explained the slide  on page 25  titled "Kuparuk                                                                    
River  water oil  ratio, Kuparuk  River gas  oil ratio."  He                                                                    
clarified that  if DNR  were examining  shale oil,  it would                                                                    
look at  similar models, such  as the Bakken,  Eagleford, or                                                                    
Marcellus shale  plays. He explained that  DNR would examine                                                                    
the production  profiles of different shale  developments in                                                                    
order to form predictive models  for shale oil in Alaska. He                                                                    
pointed  out  that  in  a  new  field,  engineers  typically                                                                    
examined the  type and  size the reservoir,  as well  as how                                                                    
many  wells would  need  to be  drilled.  He concluded  that                                                                    
originally, engineers  had reservoir  models, but  that they                                                                    
were  very  simplistic;  even still,  the  plateau  and  the                                                                    
inception of  the decline curve  could have  been predicted.                                                                    
He  reiterated  that  slides 21  through  25  represented  a                                                                    
typical exhibit of a major oil field's decline curve.                                                                           
                                                                                                                                
Mr.  Barron   discussed  the  slide  on   page  26.  General                                                                    
production facilities  were listed  on the slide.  He stated                                                                    
that  the table  depicted information  that the  Division of                                                                    
Oil and  Gas had gathered  from various companies.  He added                                                                    
that the information  on the table might not be  fully up to                                                                    
date. There  were red and green  bars on the far  right hand                                                                    
side of  the slide; the  red bars indicated that  there were                                                                    
limitations on  the unit,  while the  green bars  meant that                                                                    
there  were no  limitations. He  observed that  the red  and                                                                    
green  bars did  not render  very clearly  on the  slide. He                                                                    
pointed  out that  the North  Star Unit  had a  red bar  and                                                                    
discussed the  unit's limitations.  He stated that  DNR used                                                                    
the  slide's  information  to   assess  the  limitations  on                                                                    
producers and that some of  the information would be part of                                                                    
a  company's POD.  He  stated  that DNR  wanted  to know  if                                                                    
companies  were installing  more  facilities,  if they  were                                                                    
modeling efforts to control gas,  if gas handling facilities                                                                    
were needed, and how the  pressure maintenance was going. He                                                                    
pointed out that very few of  the facilities had a green bar                                                                    
associated with it.  He offered that the Badami  Unit was an                                                                    
underutilized  asset and  that companies  in the  area would                                                                    
likely  be  open  to a  production  sharing  and  processing                                                                    
facility  sharing agreement.  He  stated  that Oooguruk  and                                                                    
Nikaitchug  had no  limitations;  however,  the CPF-3  Unit,                                                                    
which did have limitations, was processing Oooguruk's oil.                                                                      
                                                                                                                                
Mr.   Barron  explained   the  slide   on  page   27  titled                                                                    
"facilities  access  agreements."  He explained  that  DNR's                                                                    
dialogue  had tended  to  revolve  around facilities  access                                                                    
agreements   and  that   the  agreements   were  "incredibly                                                                    
complicated" and  were between  players that  were sometimes                                                                    
competitive.                                                                                                                    
                                                                                                                                
1:45:38 PM                                                                                                                    
                                                                                                                                
Senator Thomas  asked for  a clarification  of the  chart on                                                                    
page 26. He  inquired if flow stations 1, 2,  and 3, as well                                                                    
as  gathering centers  1,  2, and  3 all  had  gas or  water                                                                    
handling   limitations.   Mr.   Barron  responded   in   the                                                                    
affirmative.                                                                                                                    
                                                                                                                                
Senator  Thomas queried  if the  stations  and centers  were                                                                    
limited  to a  total production  capacity regardless  of the                                                                    
makeup of what flowed through  them. Mr. Barron responded in                                                                    
the affirmative.                                                                                                                
                                                                                                                                
Mr. Barron continued to discuss the slide on page 27.                                                                           
                                                                                                                                
        · Facility   access   agreements   are   complicated                                                                    
          commercial agreements between multiple parties                                                                        
                                                                                                                                
        · Facility access agreements impact                                                                                     
             · Reservoir management                                                                                             
             · Process management                                                                                               
             · Influence and impact PODS, which in turn has                                                                     
               an impact on expense and capital exposure in                                                                     
               the state                                                                                                        
                                                                                                                                
                                                                                                                                
Mr. Barron  stated that it  became legally  and commercially                                                                    
complicated when a  new player joined a  facility. He listed                                                                    
possible complications in  the case of a  facility shut down                                                                    
as follows:  who was  responsible for  the loss  or deferred                                                                    
production, who gets  backed out of the  facility first, who                                                                    
has the right  to first access back in to  the facility, are                                                                    
there penalty clauses involved,  and would the state declare                                                                    
a loss  of revenue;  all of the  eventualities needed  to be                                                                    
considered from the perspectives  of commerciality and their                                                                    
impact   on  companies'   overall  asset   management.  Many                                                                    
companies had an internal  corporate culture, which dictated                                                                    
that it  would build its own  self-sufficient facilities. He                                                                    
pointed out  that some companies  preferred to ship  oil via                                                                    
the existing  pipeline network  and have  smaller production                                                                    
facilities rather  than relying  on someone else  to process                                                                    
fluids; he offered  that this model worked well  in a number                                                                    
of  areas.  He stated  that  in  Norway, using  an  existing                                                                    
offshore structure for  the common good of  many players was                                                                    
part of the  program. He explained that Norway  did not want                                                                    
to construct  new platforms, but  that it wanted  to utilize                                                                    
the facilities  that were in  place; in that  regard, Norway                                                                    
leased space on the platform for new facilities.                                                                                
                                                                                                                                
Mr. Barron explained  a slide on page  28 titled "facilities                                                                    
summary."                                                                                                                       
                                                                                                                                
        · The Prudhoe and Kuparuk units are experiencing                                                                        
          typical reservoir depletion which requires                                                                            
          handling and processing of increasing amounts of                                                                      
          water and gas, decisions on facility management,                                                                      
          effective well utilization, and complex reservoir                                                                     
          management.                                                                                                           
                                                                                                                                
                                                                                                                                
        · Facilities are designed to meet a wide range of                                                                       
          production profiles with varying water-oil and                                                                        
          gas-oil ratios (WOR and GOR, respectively). As                                                                        
          the reservoir matures, reservoir management and                                                                       
          facility debottlenecking for water and gas                                                                            
          handling, water and/or gas injection to maintain                                                                      
          reservoir pressure, well workovers, and new                                                                           
         infield development drilling is required.                                                                              
                                                                                                                                
                                                                                                                                
        · Pipeline capacity is available throughout most of                                                                     
          the North Slope, thus companies with new oil                                                                          
          discoveries will need to negotiate to share the                                                                       
          existing transport facilities.                                                                                        
                                                                                                                                
        · Corporate culture and size of a discovery                                                                             
          typically dictate decisions whether to build new                                                                      
          process facilities or enter into commercial                                                                           
         agreements to access existing facilities.                                                                              
                                                                                                                                
Mr. Barron  related that Prudhoe  Bay and Kuparuk  were well                                                                    
managed properties and that the  two areas' gas reinjection,                                                                    
waterflood, and miscible flood  activities had all benefited                                                                    
the state.  Companies were managing Prudhoe  Bay and Kuparuk                                                                    
by turning  wells on  and off,  examining which  wells would                                                                    
have  too  much water  or  gas,  moving  the water  and  gas                                                                    
around,  maintaining  reservoir  pressure, and  knowing  the                                                                    
location of  the gas fronts  and water fronts.  He furthered                                                                    
that   retrofits,   debottlenecking,  well   workovers   and                                                                    
recompletions, and  the water and  gas shutoff  program were                                                                    
all  done on  a well  by well  and area  by area  assessment                                                                    
basis.  He added  that the  pipeline capacity  on the  North                                                                    
Slope  was robust  and that  new players  should not  have a                                                                    
problem entering into the existing pipeline networks.                                                                           
                                                                                                                                
1:50:30 PM                                                                                                                    
                                                                                                                                
Co-Chair Stedman remarked  that oil still had  to be brought                                                                    
to  the  pipeline.  Mr.  Barron  replied  that  on  any  new                                                                    
development, the  producer could lay  its own line  from its                                                                    
own  production  facility  that   would  tie  into  existing                                                                    
infrastructure;  this was  similar  to how  Alpine had  tied                                                                    
into Kuparuk in  order to get to Pump Station  1. He offered                                                                    
that  if Repsol  had  a  discovery on  a  well  that it  was                                                                    
drilling,  it would  install its  own production  facilities                                                                    
that  tied into  an  existing line.  He  related that  every                                                                    
field was  managed differently, but  that in  general, every                                                                    
well  had  to  be  hooked  up to  a  production  system.  He                                                                    
concluded that  oil cannot  flow from  a well  straight into                                                                    
the  pipeline because  of the  water, gas,  sand, or  debris                                                                    
that was produced along with the oil.                                                                                           
                                                                                                                                
                                                                                                                                
Co-Chair  Hoffman asked  what involvement  DNR had  with the                                                                    
facilities agreements. Mr. Barron  replied that DNR had very                                                                    
little involvement and that the  agreements were between the                                                                    
two parties; if  asked by either party, DNR  could "lean in"                                                                    
to encourage  facilities agreements.  He concluded  that DNR                                                                    
was very seldom engaged in those sorts of negotiations.                                                                         
                                                                                                                                
Co-Chair  Stedman inquired  if DNR  had an  idea of  what it                                                                    
would  take  for  facility upgrades  in  order  to  increase                                                                    
production. Mr.  Barron replied that  DNR did  not. Co-Chair                                                                    
Stedman  queried  if  DNR  ever looked  at  that  aspect  of                                                                    
facilities.  Mr.  Barron  responded   that  during  the  POD                                                                    
process,   DNR  examined   companies'  proposed   activities                                                                    
relative to  wells and facilities; this  opportunity allowed                                                                    
DNR to assess whether companies  would be making upgrades or                                                                    
modifications to the existing systems.                                                                                          
                                                                                                                                
Co-Chair Stedman  queried if DNR could  provide information,                                                                    
which could  be used  to increase production,  regarding the                                                                    
separation of  "below ground" and "above  ground" issues. He                                                                    
observed  that a  lot  of time  was  spent discussing  below                                                                    
ground  well workovers  or infill  drilling,  but that  very                                                                    
little time was spent  discussing facilities. He inquired if                                                                    
the  state  was  dealing with  facility  constraints,  below                                                                    
ground  constraints, or  a combination  of both.  He further                                                                    
inquired  if  DNR  knew  what it  would  take  to  stabilize                                                                    
production  at 600,000  bbl/d. Mr.  Barron  replied that  it                                                                    
would take a  combination of new exploration  and new infill                                                                    
drilling. He  stated that infill drilling  work had arrested                                                                    
the  state's  decline  curve  over  time;  the  decline  was                                                                    
occurring  at  a  lesser  pace  because  of  the  companies'                                                                    
investments, infield drilling,  well workovers, and facility                                                                    
modifications. He  stated that  in order to  further flatten                                                                    
the decline, all the parties  involved would have to install                                                                    
more  wells  and facilities.  He  furthered  that the  state                                                                    
needed new entries  into the market and  cited the potential                                                                    
entrants  as   follows:  Brooks  Range   Petroleum,  Repsol,                                                                    
Pioneer  Natural  Resources,  ENI  Petroleum,  the  Schrader                                                                    
Bluff  heavy oil,  as  well as  Great  Bear Petroleum's  and                                                                    
Royale  Energy Inc.'s  shale  oil; he  stated  that "all  of                                                                    
those  would  be  part  of  the play"  and  would  need  new                                                                    
facilities.                                                                                                                     
                                                                                                                                
Co-Chair Stedman  asked if DNR had  recommendation or advice                                                                    
for  the committee  regarding  potential  costs. Mr.  Barron                                                                    
replied that he did not.                                                                                                        
                                                                                                                                
1:55:22 PM                                                                                                                    
                                                                                                                                
Co-Chair Hoffman  stated that given the  inevitable decline,                                                                    
it would  potentially take hundreds  of millions  of dollars                                                                    
to increase facilities for new  oil. He inquired if it would                                                                    
be  more  financially prudent  for  the  state to  keep  the                                                                    
status  quo rather  than having  the industry  incur such  a                                                                    
large  investment. He  observed that  the question  might be                                                                    
one that  the committee  or DNR would  be unable  to answer.                                                                    
Mr. Barron  replied that the  North Slope basin was  still a                                                                    
robust   and  rich   oil   basin.   He  referenced   British                                                                    
Petroleum's  (BP)  heavy  oil development  at  Milne  Point,                                                                    
which had a recent well test  of 650 bbl/d in production; he                                                                    
indicated  that  this  production level  was  "beyond  world                                                                    
class" in terms of heavy  oil production from a single well.                                                                    
He stated  that developments like Milne  Point, in aggregate                                                                    
across the  state, are what  would drive  development beyond                                                                    
where it was  today. He opined that the  decline curve could                                                                    
be  flattened  and  reversed,  but  that  it  would  take  a                                                                    
"tremendous  effort"   by  industry   beyond  what   it  was                                                                    
currently spending. He added that  the new development plays                                                                    
and new exploration  work were critical to get  to where the                                                                    
state wanted to be.                                                                                                             
                                                                                                                                
Senator  Thomas  asked  for clarification  on  page  28  and                                                                    
inquired  if  the  third  bullet   point  was  referring  to                                                                    
"downstream" pipeline capacity. Mr.  Barron responded in the                                                                    
affirmative.  Senator Thomas  queried if  the non-downstream                                                                    
capacity  was being  used for  water and  gas handling.  Mr.                                                                    
Barron replied  in the affirmative. Senator  Thomas asked if                                                                    
the water  and gas injection  was required to  maintain well                                                                    
pressure,  or  whether gas  and  water  were in  the  system                                                                    
because there  was nothing  else to do  with it.  Mr. Barron                                                                    
replied  that  water  and  gas   injection  was  needed.  He                                                                    
referenced slide  14's bubble map,  which depicted  the line                                                                    
drive waterflood  in Kuparuk  and stated  that waterflooding                                                                    
was a  viable technique for maintaining  reservoir pressure;                                                                    
the water was used to "sweep"  oil away from an injector and                                                                    
bring  it  closer   to  a  producer.  He   stated  that  the                                                                    
reinjection of  gas into the  gas cap had  greatly benefited                                                                    
Prudhoe  Bay and  that it  resulted in  oil moving  from the                                                                    
upper elevations  of the reservoir into  the lower producing                                                                    
horizon. He pointed that water  and gas injections were very                                                                    
viable techniques  and mentioned  that both Prudhoe  Bay and                                                                    
Kuparuk  were experimenting  with  new reservoir  management                                                                    
techniques.                                                                                                                     
                                                                                                                                
2:00:01 PM                                                                                                                    
                                                                                                                                
Senator Thomas observed that the  only solution seemed to be                                                                    
to build more  facilities that could process  water and gas.                                                                    
He pointed out that gas and  water were needed, but that the                                                                    
facilities which  processed them were currently  at capacity                                                                    
limits. Mr. Barron responded that  areas of development that                                                                    
were  west of  the heart  of the  existing Prudhoe  Bay area                                                                    
still  had some  prospectivity; the  prospectivity in  these                                                                    
areas  would involve  new wells  and  facilities. He  stated                                                                    
that water and gas came out  of the wells naturally and that                                                                    
additional water  was introduced in the  general waterflood.                                                                    
He explained that  in order to maintain  the pressure, every                                                                    
barrel of  oil that  was taken  needed to  be replaced  by a                                                                    
barrel of water. He concluded that  in the case of the North                                                                    
Slope, the  water came from  the ocean and  was re-injected;                                                                    
needing more facilities  for water and gas  processing was a                                                                    
"self-fulfilling prophecy."                                                                                                     
                                                                                                                                
Co-Chair  Hoffman   referenced  the  Society   of  Petroleum                                                                    
Engineers'  western  regional meeting  in  May  of 1993  and                                                                    
quoted  engineers  from  BP   and  ConocoPhillips,  who  had                                                                    
reported that,                                                                                                                  
                                                                                                                                
     "Prudhoe Bay is  seen by many as a mature  oil field on                                                                    
     an inevitable  and irreversible  decline …  The field's                                                                    
     oil production  capacity dropped  below 1.5  MMSTB/D in                                                                    
     1988 *officially*  signaling the start of  decline. The                                                                    
     onset of  decline was  a direct  result of  limited gas                                                                    
     handling capacity as opposed  to limited oil production                                                                    
     capacity."(copy  on file)  [The quote  can be  found in                                                                    
     the  backup document  titled  "gas  and water  handling                                                                    
     constraints on Alaska's North Slope."]                                                                                     
                                                                                                                                
Co-Chair  Hoffman inquired  if  Mr. Barron  agreed with  the                                                                    
quoted  statements. Mr.  Barron  replied that  he tended  to                                                                    
agree  and that  gas handling  facilities seemed  to be  the                                                                    
bottleneck  at  the  current  time. He  added  that  it  was                                                                    
important  to  remember  the  necessity  of  being  able  to                                                                    
process  and re-inject  gas in  order to  maintain reservoir                                                                    
pressure and "sweep."                                                                                                           
                                                                                                                                
Co-Chair  Stedman noted  that ConocoPhillips  had stated  in                                                                    
prior testimony that increasing  production to 700,000 bbl/d                                                                    
or  1  million bbl/d  would  be  technically impossible.  He                                                                    
observed  that there  was  a technical  issue  versus a  tax                                                                    
issue  and  that  the  committee  was  struggling  with  the                                                                    
balance between  the technology  constraints and  the impact                                                                    
of  the tax  system.  He furthered  that  the committee  was                                                                    
trying  to  separate  what was  technically  feasible,  what                                                                    
would  be feasible  under  a zero  tax  structure, what  was                                                                    
feasible under the current tax  structure, and "where are we                                                                    
between that  zero and where  we are today." He  pointed out                                                                    
that  the  state  would  not  get  to  1  million  bbl/d  in                                                                    
production  and  that  some felt  that  it  would  difficult                                                                    
achieve 700,000  bbl/d. Mr. Barron responded  that testimony                                                                    
tended  to  get misconstrued  in  the  overall dialogue.  He                                                                    
opined  that  it was  unlikely  that  the decline  could  be                                                                    
arrested and  reversed to  1 million  bbl/d in  the existing                                                                    
Prudhoe Bay and Kuparuk fields.                                                                                                 
                                                                                                                                
Mr. Barron  related that there was  still a lot of  oil left                                                                    
to be discovered in the North  Slope and that it was still a                                                                    
target  rich environment.  He stated  that when  Prudhoe Bay                                                                    
was discovered, the expectation was  that it would have a 30                                                                    
percent recovery rate  and that the pipeline  would be empty                                                                    
by the year 2000. He observed  that in 2012, the North Slope                                                                    
was  still producing  600,000 bbl/d,  which was  well beyond                                                                    
the original concepts of what  was technically achievable at                                                                    
the time.  He pointed  out that 60  percent recovery  from a                                                                    
reservoir  was "astonishing"  and that  he did  not discount                                                                    
scientists' and  engineers' abilities to create  new ways to                                                                    
develop oil  and gas.  He opined that  it would  possible to                                                                    
arrest the six  percent decline in Prudhoe Bay  and bring it                                                                    
down  to four  percent for  a period  of time.  He furthered                                                                    
that it was  possible to flat line Prudhoe  Bay and Kuparuk,                                                                    
but  that new  technologies, new  development concepts,  new                                                                    
conventional fields, as  well as heavy and  shale oil needed                                                                    
to  come on  line and  be brought  to bear.  He stated  that                                                                    
Kuparuk  and   Prudhoe  Bay  could  not   be  considered  in                                                                    
singularity regarding  the future  development on  the North                                                                    
Slope.  He  concluded  the  work of  Savant  Alaska  LLC  at                                                                    
Badami, the  work of Repsol, ENI  Petroleum, Pioneer Natural                                                                    
Resources  Alaska, Brooks  Range Petroleum,  and Great  Bear                                                                    
Petroleum all  needed to be  part of the  equation regarding                                                                    
overall development  on the  North Slope;  the opportunities                                                                    
in these areas were "robust" and "tremendous."                                                                                  
                                                                                                                                
2:07:34 PM                                                                                                                    
                                                                                                                                
Co-Chair Stedman queried  if the magnitude of  a one percent                                                                    
or  two  percent recovery  rate  would  be much  greater  in                                                                    
Prudhoe  Bay than  it would  be in  other areas.  Mr. Barron                                                                    
responded in  the affirmative and related  that changing the                                                                    
decline profile  of Prudhoe Bay  by one percent, even  for a                                                                    
period of  time, would  be an  "amazing feat."  He concluded                                                                    
that Prudhoe Bay  was a huge field and that  trying to drill                                                                    
the right number of wells,  in the right locations, with the                                                                    
appropriate  production  facilities,  and doing  so  at  the                                                                    
right time  were all part  of the dynamics of  reservoir and                                                                    
production management.                                                                                                          
                                                                                                                                
2:08:28 PM                                                                                                                    
AT EASE                                                                                                                         
                                                                                                                                
2:18:21 PM                                                                                                                    
RECONVENED                                                                                                                      
                                                                                                                                
SENATE BILL NO. 192                                                                                                           
                                                                                                                                
     "An Act relating to the oil and gas production tax;                                                                        
     and providing for an effective date."                                                                                      
                                                                                                                                
Co-Chair Stedman  discussed the meeting's agenda.  He stated                                                                    
that   the    PFC   Energy   presentation    would   discuss                                                                    
progressivity options.  He observed that after  the meeting,                                                                    
the committee  should have a  general idea of  which options                                                                    
it would  focus on  and which  ones would  be taken  off the                                                                    
table.                                                                                                                          
                                                                                                                                
Co-Chair  Stedman  asked  for a  brief  description  of  PFC                                                                    
Energy.                                                                                                                         
                                                                                                                                
2:19:37 PM                                                                                                                    
                                                                                                                                
JANAK MAYER, MANAGER, UPSTREAM AND  GAS, PFC ENERGY, began a                                                                    
PowerPoint  presentation titled  "discussion slides:  Alaska                                                                    
Senate  Finance Committee."  (copy on  file) He  stated that                                                                    
PFC Energy was a global  consultancy that was focused solely                                                                    
on "upstream" and "downstream" oil  and gas issues; upstream                                                                    
referred to  all activities associated with  getting oil out                                                                    
of  the  ground,  while downstream  was  reflective  of  the                                                                    
refining, marketing,  and retail  sectors. PFC Energy  had a                                                                    
particular  expertise  in  above   ground  issues,  such  as                                                                    
understanding  markets and  market analysis,  political risk                                                                    
assessments,   understanding  fiscal   terms,   and  how   a                                                                    
government  set its  rules for  oil and  gas. He  added that                                                                    
companies needed  to understand the rules  that a government                                                                    
set in  order to be able  to do business. He  concluded that                                                                    
PFC  Energy worked  at the  nexus between  international oil                                                                    
companies, national oil companies, and governments.                                                                             
                                                                                                                                
Mr. Mayer explained the slide  on page 2 of the presentation                                                                    
titled "assessing  10 different  fiscal regime  options." He                                                                    
stated that  the slide  summarized, in  terms of  revenue to                                                                    
the  state,  the  different fiscal  options  that  had  been                                                                    
discussed in a previous  meeting; the options were presented                                                                    
in  the  context  of  Alaska's  Clear  and  Equitable  Share                                                                    
(ACES), HB 110, as well  as other permutations. He explained                                                                    
that under  PFC Energy's model and  at an oil price  of $100                                                                    
per  barrel,  ACES  netted  the   state  $3.686  billion  in                                                                    
production  revenue; by  contrast, HB  110 netted  the state                                                                    
$2.721  billion at  the same  price level.  The core  of the                                                                    
slide's  analysis  focused on  options  for  base levels  of                                                                    
taxation and progressivity  that slightly reduced government                                                                    
take at given price levels,  but did not dramatically reduce                                                                    
revenue  to  the  state;   furthermore,  the  options  would                                                                    
significantly  reduce progressivity  "beyond that  point" in                                                                    
order to  even the  split of  revenue between  companies and                                                                    
government. He  related that the committee  had examined how                                                                    
CSSB  192 might  look  if  the maximum  rate  was capped  50                                                                    
percent instead of 60 percent.  He stated that the committee                                                                    
had also looked  at CSSB 192 with a base  rate of 30 percent                                                                    
and a progressivity  rate of .2 percent. He  added that CSSB                                                                    
192 with  a cap of 40  percent on the maximum  rate was also                                                                    
discussed; without  a change to  the base rate,  this option                                                                    
did  not  necessarily  generate   a  significant  change  in                                                                    
numbers  from  the current  bill.  He  related that  another                                                                    
option  on  the  slide  was   taking  progressivity  out  of                                                                    
production tax  and instead instituting a  severance tax. He                                                                    
explained  that a  severance  tax  was a  tax  on gross  oil                                                                    
production  and that  it reflected  the gross  value at  the                                                                    
point of production.  He stated that there were  a number of                                                                    
advantages to  removing progressivity.  He offered  that the                                                                    
issue  of "decoupling"  had arisen  specifically due  to the                                                                    
inclusion  of  progressivity  in   the  production  tax.  He                                                                    
observed  that  if  the  production  tax  was  a  flat  tax,                                                                    
decoupling would  not be  an issue. He  stated that  using a                                                                    
flat severance  tax and  incorporating progressivity  at the                                                                    
gross level solved the problem  of decoupling without having                                                                    
to undergo  the administratively more complex  solution that                                                                    
was  in  CSSB  192.   Currently,  CSSB  192  specified  that                                                                    
production and  costs for  oil and gas  had to  be separated                                                                    
and presumably  required companies  to submit  two different                                                                    
tax returns. He reiterated  that a progressive severance tax                                                                    
referred  to  when  progressivity   was  taken  out  of  the                                                                    
production tax  and was instead  levied on the  gross level.                                                                    
He  added that  a  second benefit  of  having a  progressive                                                                    
severance tax  was that it  allowed for more  flexibility in                                                                    
incentivizing   new   production;   however,  as   long   as                                                                    
progressivity remained  part of the  profit-based production                                                                    
tax,  incentivizing new  production  was significantly  more                                                                    
difficult.  He explained  that  under  the existing  system,                                                                    
there  were few  options for  incentivizing new  production;                                                                    
one incentive could be a  dollar amount allowance that would                                                                    
be subtracted from  the production tax value  for "new oil."                                                                    
He discussed  the different  ways of  defining what  new oil                                                                    
was. He stated  that regardless of how new  oil was defined,                                                                    
the  mechanism   in  the   existing  system   that  provided                                                                    
incentives   for   new   production  was   complex;   taking                                                                    
progressivity of the  base production tax and  levying it on                                                                    
a gross  level created greater flexibility  with incentives.                                                                    
He offered that  if an entity wanted to provide  a very high                                                                    
level  of  incentives for  production  from  new areas,  the                                                                    
severance tax could be structured  to only apply to existing                                                                    
fields;  new fields  could  have a  zero  severance tax  and                                                                    
would only pay  the 25 percent flat base tax.  A lower level                                                                    
of severance  tax could also be  applied to new areas  or to                                                                    
production over  the base level.  He shared that the  HB 110                                                                    
(new), the  six percent  severance tax,  and the  25 percent                                                                    
flat  tax  options  represented hypothetical  exercises  and                                                                    
that  while they  served an  analytical purpose,  the dollar                                                                    
values  might not  reflect reality;  the three  options were                                                                    
included to  provide different ways of  structuring a system                                                                    
in order to incentivize new production.                                                                                         
                                                                                                                                
2:29:48 PM                                                                                                                    
                                                                                                                                
Co-Chair Stedman  asked for a  clarification on slide  2 and                                                                    
inquired  if the  "total federal  take" reflected  the total                                                                    
government  take  in dollars.  Mr.  Mayer  responded in  the                                                                    
affirmative. Co-Chair Stedman queried  why the industry take                                                                    
was not included on the  table. Mr. Mayer responded that PFC                                                                    
Energy  would  include  the  requested  information  in  the                                                                    
future.  Co-Chair Stedman  queried  if  the slide's  revenue                                                                    
comparisons  represented the  current  production in  legacy                                                                    
fields, the aggregate of all  production, or new production.                                                                    
Mr. Mayer replied  that the slide's revenue  reflected FY 13                                                                    
data,  including the  production and  cost levels,  after it                                                                    
was run  through PFC Energy's  model. He added  that anytime                                                                    
revenue  figures were  presented, the  information reflected                                                                    
FY 13  data. Co-Chair Stedman  remarked that the  slide used                                                                    
the "homogenized" FY 13 data  from the Revenue Sources Book.                                                                    
He inquired if  the values of the legacy  fields and smaller                                                                    
producers would reflect a different  set of numbers than the                                                                    
aggregated numbers  on the slide.  Mr. Mayer  responded that                                                                    
Co-Chair Stedman was correct.                                                                                                   
                                                                                                                                
                                                                                                                                
Co-Chair  Stedman inquired  what direction  the presentation                                                                    
would go  later in the  meeting. Mr. Mayer replied  that the                                                                    
presentation would examine  the regimes on slide  2 in terms                                                                    
of  their  levels of  government  take  and revenue  to  the                                                                    
state. He  added that the  presentation would  conclude with                                                                    
an analysis of the marginal rates in the same regimes.                                                                          
                                                                                                                                
Mr.  Mayer  discussed  the  slide on  page  3  titled  "ACES                                                                    
(existing producer)."  He stated  that the upper  left graph                                                                    
depicted a cash flow analysis  for a 200,000 bbl/d producer,                                                                    
under the  existing system,  with recent  cost levels  and a                                                                    
six  percent   decline  curve;  it  also   showed  different                                                                    
economic metrics  regarding the  Net Present Value  (NPV) at                                                                    
different prices. He stated that  the top right graph showed                                                                    
the level of government take  at different price levels; the                                                                    
red showed the total government  take and the blue reflected                                                                    
the total state share. Based on  a price spread from $100 to                                                                    
$230 per  barrel, the slide's scenario  had total government                                                                    
takes   ranging  from   75  percent   to  83   percent.  The                                                                    
percentages  on   the  top   right  table   represented  the                                                                    
divisible income and were added  horizontally to the get the                                                                    
total state or government takes.  He related that the bottom                                                                    
right  chart depicted  the percentage  levels of  government                                                                    
take, while the bottom left  chart showed the percentages in                                                                    
terms of dollars.                                                                                                               
                                                                                                                                
2:35:03 PM                                                                                                                    
                                                                                                                                
Mr.  Mayer discussed  the slide  on  page 4  titled "HB  110                                                                    
(existing   producer)"  and   offered  that   companies  had                                                                    
referred  to  HB  110  as   the  "threshold  for  meaningful                                                                    
reform." He observed that at a  price of $100 per barrel, HB                                                                    
110 would  have a  government take of  about 67  percent; at                                                                    
higher price  ranges, it had  a maximum level  of government                                                                    
take  of 71  percent. He  explained that  the slide's  lower                                                                    
government take  resulted in a  corresponding effect  of the                                                                    
cash flow line rising and the NPV going up.                                                                                     
                                                                                                                                
Mr. Mayer  discussed the  slide on page  5 titled  "CSSB 192                                                                    
(existing producer)."  He stated  that under  this scenario,                                                                    
there  was very  little  difference in  the government  take                                                                    
below  the $100  per  barrel  price level  and  that the  75                                                                    
percent  government take  had dropped  to  74 percent  [Both                                                                    
statements were made in comparison  to slide 3.]. He offered                                                                    
that the  slide's one  percent drop  in government  take was                                                                    
probably  a function  of rounding  and that  in reality  the                                                                    
change was  even smaller  than the  slide showed.  He stated                                                                    
that the scenario did see  changes to the government take at                                                                    
higher  price   levels  and  that   its  maximum   level  of                                                                    
government take flattened  out at 79 percent  to 80 percent.                                                                    
He added that  the slide depicted a life  cycle analysis and                                                                    
that it  reflected the  effect of inflation  on some  of the                                                                    
nominal  thresholds; PFC  Energy factored  in the  inflation                                                                    
and saw the  government take flattening out at  an oil price                                                                    
around the  mid-$100s per barrel.  He furthered that  if the                                                                    
slide  had  been  forecasted  solely on  FY  13  basis,  the                                                                    
flattening effect  would probably  not occur until  the $230                                                                    
per  barrel level;  in that  respect,  there was  relatively                                                                    
little difference between CSSB 192  and ACES as it currently                                                                    
stood.                                                                                                                          
                                                                                                                                
Mr. Mayer  explained the  slide on page  6 titled  "CSSB 192                                                                    
with 50  % cap (existing  producer)."   He stated that  if a                                                                    
maximum rate cap  of 50 percent were put in  place of the 60                                                                    
percent  cap,  the  levels of  government  take  were  "very                                                                    
slightly" reduced at a price  of $100 per barrel. He offered                                                                    
that under a  50 percent cap, the levels  of government take                                                                    
remained  flat  in the  mid-70  percent  range, whereas  the                                                                    
current form of CSSB 192 was  projected to have almost an 80                                                                    
percent government  take at higher  price levels.  He stated                                                                    
that lowering the cap to  50 percent minimized the extent to                                                                    
which upside was reduced at  high oil prices, such as prices                                                                    
above the  $120 to  $130 per barrel  level; however,  the 50                                                                    
percent  cap did  not have  a large  effect at  price levels                                                                    
below $120 per barrel.                                                                                                          
                                                                                                                                
Mr. Mayer  explained the  slide on page  7 titled  "CSSB 192                                                                    
with  40  % (existing  producer)."  He  stated that  if  the                                                                    
maximum rate  cap was  lowered even  further to  40 percent,                                                                    
there  would  be a  flattening  of  out of  government  take                                                                    
"altogether".  He furthered  that the  40 percent  cap would                                                                    
result in a more neutral system  that had a 69 percent to 70                                                                    
percent government take  at almost all of  the price levels.                                                                    
He concluded  that "correspondingly, in each  of these cases                                                                    
we see  the net present  value for each of  these portfolios                                                                    
rising."                                                                                                                        
                                                                                                                                
Co-Chair Stedman  asked for a  clarification on slide  7. He                                                                    
noted that  at $40  per barrel, the  slide's NPV  was $2.588                                                                    
billion in comparison to ACES'  NPV of $2.812 billion at the                                                                    
same  price  level.  He  requested  an  explanation  of  the                                                                    
slide's NPV table. Mr. Mayer  stated that at $40 per barrel,                                                                    
the value  of the  portfolio was reduced  under CSSB  192 in                                                                    
comparison  to  ACES; he  added  that  the reduction  was  a                                                                    
function  of CSSB  192's  higher minimum  level  of tax.  He                                                                    
explained  that  while current  regime  had  a four  percent                                                                    
minimum tax  at lower price  levels, CSSB 192 set  a minimum                                                                    
tax of ten  percent for certain larger  producing assets. He                                                                    
concluded that  at $40 per barrel,  the NP was lower  in all                                                                    
of  the  CSSB  192  options  than  it  was  under  ACES.  By                                                                    
contrast, the NPVs of ACES and  the CSSB 192 were similar at                                                                    
$60   per  barrel;   the  similarity   was  a   function  of                                                                    
progressivity not  coming into  play at  the $60  per barrel                                                                    
price level,  given the  costs. He stated  that at  the $100                                                                    
per  barrel  level, there  were  modest  differences in  NPV                                                                    
between ACES and the CSSB 192 options.                                                                                          
                                                                                                                                
2:40:24 PM                                                                                                                    
                                                                                                                                
Mr. Mayer  explained the  slide on page  8 titled  "30% base                                                                    
rate, 0.02% progressivity, 40%  cap (existing producer)." He                                                                    
shared  that   the  slide  presented  an   option  that  had                                                                    
previously  been discussed  in  the  committee. The  slide's                                                                    
option proposed  to raise the  base rate  in CSSB 192  to 30                                                                    
percent  from   25  percent   and  to   substantially  lower                                                                    
progressivity to  0.2 percent from  0.4 percent.  He pointed                                                                    
out  that the  slide had  a typographic  error and  that the                                                                    
0.02 percent  figure, which was  in the title of  the slide,                                                                    
should be at 0.2 percent.  The scenario also instituted a 40                                                                    
percent  cap  on  the minimum  rate.  The  slide's  analysis                                                                    
showed that compared to slide  7, reducing the progressivity                                                                    
to .2 percent and adjusting the  base rate to 30 percent had                                                                    
relatively  little  difference  at  most  price  levels;  he                                                                    
offered  that  the  NPVs  on  slides 7  and  8  were  almost                                                                    
identical  at prices  above the  $100 per  barrel level.  He                                                                    
observed that at  $60 per barrel, slide 8's  addition of the                                                                    
increased  base rate  and  the  lower progressivity  feature                                                                    
resulted in a  "notably reduced" NPV in  comparison to slide                                                                    
7, which  only had  the 40 percent  cap; by  contrast, there                                                                    
was relatively  little difference between the  NPV of slides                                                                    
7 and 8 at even lower  price levels, such as $40 per barrel.                                                                    
He stated  that at $40  per barrel level, the  "floor binds"                                                                    
and that it was the  floor, and not the progressivity scale,                                                                    
that  ultimately  set  the government  take  at  that  price                                                                    
level.                                                                                                                          
                                                                                                                                
Co-Chair  Stedman inquired  if  the $50  to  $70 dollar  per                                                                    
barrel price  range was  the point at  which the  30 percent                                                                    
base rate  began "pushing the  present values  under water."                                                                    
Mr. Mayer responded that Co-Chair Stedman was correct.                                                                          
                                                                                                                                
Mr. Mayer offered that a  possible benefit of increasing the                                                                    
base  rate to  30 percent  was a  reduction to  the marginal                                                                    
rates under  the production tax  system. He added  that high                                                                    
marginal  rates had  been perceived  as a  problem with  the                                                                    
production tax  system. He  warned that  addressing marginal                                                                    
rates with  a solution  that worked  in the  $50 to  $70 per                                                                    
barrel  range would  worsen the  economics  on projects  and                                                                    
would be  a solution  with a worse  impact than  the problem                                                                    
that it solved. He added  that the next several slides would                                                                    
examine the 50  percent cap, the 40 percent cap,  and the 30                                                                    
percent  base  rate options  as  they  would apply  for  new                                                                    
developments  and  that  the 30  percent  base  rate  option                                                                    
experienced a  notable worsening  of the NPV  at the  $40 to                                                                    
$60 per barrel price level for new developments.                                                                                
                                                                                                                                
Mr. Mayer discussed  the slides on pages 9, 10,  and 11. The                                                                    
three slides simulated the same  options as slides 6, 7, and                                                                    
8 but  for new developments.  He offered that slides  9, 10,                                                                    
and 11  showed the  same "significant  worsening" of  NPV at                                                                    
lower price  ranges that could be  seen on slides 6,  7, and                                                                    
8; this was  particularly true at around a price  of $60 per                                                                    
barrel. The drop in NPV also  occurred at the $40 per barrel                                                                    
level because  the language in  CSSB 192 specified  that the                                                                    
floor  level  of  production value  only  applied  to  large                                                                    
existing fields, as opposed to  smaller new developments. He                                                                    
concluded that for new developments,  the negative impact of                                                                    
the higher  base rate  extended to  the lowest  price ranges                                                                    
because the floor level of taxation was not an issue.                                                                           
                                                                                                                                
2:46:11 PM                                                                                                                    
                                                                                                                                
Mr. Mayer explained  the slide on page  12 titled "severance                                                                    
tax-  20% maximum  (existing producer)  .25 %  progressivity                                                                    
from  $70  to $130,  then  .10%  progressivity to  180."  He                                                                    
stated that the slide showed what  SB 192 would look like if                                                                    
progressivity  were removed  from the  production tax  and a                                                                    
severance  tax   was  implemented.   He  explained   that  a                                                                    
severance  tax was  based solely  on production  volumes and                                                                    
that it was  progressive over price. He related  that he had                                                                    
spent some  time examining  how the  different progressivity                                                                    
thresholds  and rates  for a  severance tax  would work.  He                                                                    
explained that  the slide modeled  a severance tax  that was                                                                    
levied on  the gross value  at the point of  production; all                                                                    
the prices quoted on the  slide were under the definition in                                                                    
the  legislation  of  the  gross   value  at  the  point  of                                                                    
production. He furthered  that the gross volume  and the net                                                                    
of  royalties were  what was  being taxed  on the  slide. He                                                                    
stated that model's  tax started at a zero rate  and that it                                                                    
did not kick  in until the $70 per barrel  price level; with                                                                    
each  $1  increase  above   $70  per  barrel,  progressivity                                                                    
increased   by   .25   percent.  He   furthered   that   the                                                                    
progressivity in  the tax reached  a local maximum  of about                                                                    
16 percent at  $130 per barrel, and that for  every $1 price                                                                    
increase  from $130  to $180  per barrel,  the progressivity                                                                    
increased at a  lower rate of .1  percent; the progressivity                                                                    
reached its maximum  rate of 20 percent at  $180 per barrel.                                                                    
He explained  that the model  had a similar  government take                                                                    
profile as  the two 40 percent  cap options on slides  7 and                                                                    
8, but  that it enabled  an easier method of  addressing the                                                                    
decoupling issue  and allowed  for particular  incentives to                                                                    
be made for  new production. The purple  bar represented the                                                                    
severance tax and the yellow  bar represented the production                                                                    
tax. The  yellow of  the production tax  had a  flat profile                                                                    
because the model  had a flat 25 percent  production tax. He                                                                    
stated  that   the  model  would  normally   be  a  slightly                                                                    
regressive  regime  because  of  the  impact  of  the  fixed                                                                    
royalty,  but  that  the  severance  tax  made  it  slightly                                                                    
progressive. He added  that the model was  "ever so slightly                                                                    
progressive," but  that it was  largely fixed around  the 70                                                                    
percent government take level.                                                                                                  
                                                                                                                                
Co-Chair Stedman asked  for a clarification on  slide 12. He                                                                    
observed that at a price of  $40 per barrel, the slide's NPV                                                                    
was  lower  than  the  NPV in  the  ACES  existing  producer                                                                    
scenario, which was on slide  3. Mr. Mayer responded that in                                                                    
the case  of a  $40 per  barrel price, the  NPV on  slide 12                                                                    
should be similar to NPV under  CSSB 192, which was on slide                                                                    
5. Co-Chair Stedman  queried what basis slides 3,  5, and 12                                                                    
were run  on. Mr. Meyer responded  that slides 3, 5,  and 12                                                                    
had all used  200,000 bbl/d as the basis  for production. He                                                                    
stated that  at $40 per barrel,  the NPV on slide  12 should                                                                    
be identical  to the NPV on  slide 5. He related  that there                                                                    
was a  decrease to  the NPV  when you  compared, at  $40 per                                                                    
barrel, the NPV of  slide 12 to the NPV of  ACES on slide 3.                                                                    
He stated  that slides 5  and 12  were modeled on  CSSB 192,                                                                    
which had a higher price floor;  the reduction in NPV at $40                                                                    
per barrel was a direct result of the higher price floor.                                                                       
                                                                                                                                
2:51:42 PM                                                                                                                    
                                                                                                                                
Co-Chair Stedman clarified that the  effect of the floor was                                                                    
responsible for moving slide 3's  NPV of $2.812 billion down                                                                    
to $2.587 billion, which was the  NPV on slide 12. Mr. Mayer                                                                    
responded that Co-Chair Stedman was correct.                                                                                    
                                                                                                                                
Co-Chair  Stedman  inquired  if  PFC Energy  could  run  the                                                                    
models with  the NPV  displayed in  $10 increments  from $40                                                                    
per  barrel  upwards. Mr.  Mayer  responded  that PFC  could                                                                    
accommodate the request.                                                                                                        
                                                                                                                                
Co-Chair  Stedman requested  a  clarification regarding  the                                                                    
lower right hand chart on page  12 and inquired if the chart                                                                    
implied that the  split of profit oil  between the producers                                                                    
and  the state  remained  constant at  $130  per barrel  and                                                                    
onwards.  Mr.  Mayer  responded that  Co-Chair  Stedman  was                                                                    
correct. Co-Chair  Stedman queried if this  meant that "both                                                                    
dollars increase  as the  price advances,  and/or decrease."                                                                    
Mr. Mayer responded in the affirmative.                                                                                         
                                                                                                                                
Co-Chair Stedman related that how  do deal with the split of                                                                    
profit oil  when oil prices  were high was major  issue that                                                                    
the committee had been struggling with.                                                                                         
                                                                                                                                
Mr.  Mayer  stated that  one  of  the advantages  of  taking                                                                    
progressivity out  of the production  tax and  instituting a                                                                    
gross  progressive  tax  was  that  it  made  the  issue  of                                                                    
decoupling easier to  deal with; the other  advantage was in                                                                    
regard to the ways new  production could be incentivized. He                                                                    
noted that the following two  slides would cover options for                                                                    
incentivizing  new  production and  that  it  was useful  to                                                                    
think of the slides in the  context of regimes that might be                                                                    
put in place for entirely new areas and new producers.                                                                          
                                                                                                                                
Mr. Mayer discussed  the slide on page  13 titled "severance                                                                    
tax  -   6  %  maximum   (existing  producer)   .05  percent                                                                    
progressivity  from $70  to $190."  He stated  that for  new                                                                    
production, the  severance tax  could be  reduced to  have a                                                                    
maximum rate  of six  percent. He added  that the  tax would                                                                    
start with  a zero base  and have .05  percent progressivity                                                                    
for each $1 price increase from  $70 to $190 per barrel; the                                                                    
maximum  rate would  remain flat  at six  percent at  prices                                                                    
over $190  per barrel.  He stated  that the  government take                                                                    
figures  for  this  scenario  would  be  around  the  mid-60                                                                    
percent range.                                                                                                                  
                                                                                                                                
Mr. Mayer explained the slide  on page 14 titled "25 percent                                                                    
production  tax." He  related that  if the  state wanted  to                                                                    
incentivize  entirely new  developments, it  could take  out                                                                    
the progressive severance tax and  institute nothing but the                                                                    
25 percent  flat production tax;  this scenario would  see a                                                                    
reduction  in  government  take  to the  63  percent  or  62                                                                    
percent level.  He explained  that the  25 percent  flat tax                                                                    
option  could be  instituted on  an indefinite  basis or  it                                                                    
could be for  particular time period, such as  the first ten                                                                    
years  of production.  He stated  that  production from  new                                                                    
areas, production from  particular initiatives' agreed plans                                                                    
and development,  and oil  production that  was above  a set                                                                    
decline curve  were three  types of  new production  that an                                                                    
entity might  wanted to incentivize.  He added that  for any                                                                    
of   those  three   options,  incentivizing   could  involve                                                                    
tweaking and a  combination of the two options  on slides 13                                                                    
and 14,  and that  how this  would be  done depended  on how                                                                    
great an incentive one wanted  to provide. He concluded that                                                                    
removing   progressivity  and   instead   levying  a   gross                                                                    
production tax  enabled incentivizing because  it simplified                                                                    
the  accounting that  went into  the  production tax;  under                                                                    
this system,  it was simply  a question of how  many barrels                                                                    
were produced and what the oil price was.                                                                                       
                                                                                                                                
2:56:49 PM                                                                                                                    
                                                                                                                                
Mr. Mayer explained  the slide on page  15 titled "assessing                                                                    
10  different fiscal  regime options."  He  stated that  the                                                                    
slide showed  the dollar figures  that were  associated with                                                                    
the  options. He  related that  in terms  of production  tax                                                                    
revenue  and at  a  $100 per  barrel  basis, ACES  generated                                                                    
about  $3.7  billion  in  comparison  to  the  $2.7  billion                                                                    
generated  by  HB  110.  He  reiterated  that  industry  had                                                                    
testified  that   HB  110  was  "threshold   for  meaningful                                                                    
reform." The  three options  that were  modeled on  CSSB 192                                                                    
reduced the  production tax revenue  from ACES to  just over                                                                    
$3.5 billion. He related that  the two CSSB 192 options that                                                                    
kept the base  level the same had identical  results to ACES                                                                    
at  the $60  per barrel  level,  higher results  at $40  per                                                                    
barrel,   and  generated   significantly  less   revenue  at                                                                    
"extremely high" price levels.  He stated that the severance                                                                    
tax could be  reworked to determine at what  point it should                                                                    
kick in,  whether it should have  a zero or small  base, and                                                                    
what its progressivity coefficient  would be. He stated that                                                                    
at  the $40  and $60  per barrel  price levels,  the options                                                                    
that  used a  25  percent base  rate  had identical  results                                                                    
because the only  thing occurring at those  price levels was                                                                    
the  base rate.  In  the 20  percent  severance tax  option,                                                                    
revenue was  reduced to  a little above  $3 billion  at $100                                                                    
per barrel; at  the prices of $150 and $200  per barrel, the                                                                    
option  had similar  revenue in  comparison to  some of  the                                                                    
capped  CSSB 192  variants. He  related that  for particular                                                                    
fields that were being incentivized  through the six percent                                                                    
lowered severance tax  and the 25 percent  flat tax options,                                                                    
it was  not accurate  to think  of the  figures in  terms of                                                                    
revenue to the state; these  options showed what the reduced                                                                    
numbers would  look like and  how they would compare  to the                                                                    
15 percent reduced rate for  new production, which was in HB                                                                    
110.                                                                                                                            
                                                                                                                                
Co-Chair Stedman discussed slide 15  and pointed out that at                                                                    
a price of  $100 per barrel, there was  a significant spread                                                                    
between the  $7.2 billion in  state take that  was generated                                                                    
by  ACES and  the $6.6  billion in  state take  that the  20                                                                    
percent severance tax option generated.  He inquired how the                                                                    
severance tax model  could be changed in order  to get close                                                                    
to the $100 per barrel cash  position of ACES. He noted that                                                                    
the 20  percent severance  option "deteriorated"  above $100                                                                    
per barrel  and got "even  worse" at extremely  high prices.                                                                    
He  requested Mr.  Mayer  to run  the  20 percent  severance                                                                    
scenario with  a progressivity  rate that  was north  of .25                                                                    
percent. Mr. Mayer  responded that he would do  so. He added                                                                    
that  the  20  percent  severance  option  was  the  closest                                                                    
structure  that  he  had  found in  terms  of  matching  the                                                                    
percentage  of government  take  figures,  but that  through                                                                    
further manipulation,  the option  could be adjusted  to get                                                                    
closer to the  levels of revenue the state  currently had at                                                                    
$100  per barrel;  one way  of doing  this was  to impose  a                                                                    
small base  on the  severance tax instead  of having  a zero                                                                    
base rate, as well making other changes to progressivity.                                                                       
                                                                                                                                
3:01:52 PM                                                                                                                    
                                                                                                                                
Co-Chair   Stedman  pointed   out  that   the  steeper   the                                                                    
progressivity  was,  the  more   it  impacted  marginal  tax                                                                    
structure.  Mr. Mayer  responded that  Co-Chair Stedman  was                                                                    
correct. He added  that there were a number  of factors that                                                                    
had led him  to start with the 20  percent severance option,                                                                    
but that it could be refined.                                                                                                   
                                                                                                                                
Co-Chair  Hoffman  requested  that future  slides  show  $10                                                                    
increments between  the price  levels of  $100 and  $150 per                                                                    
barrel.                                                                                                                         
                                                                                                                                
Co-Chair  Stedman  observed that  the  split  of profit  oil                                                                    
would  probably  be  frozen  at prices  north  of  $150  per                                                                    
barrel. He requested that future  slides show $10 increments                                                                    
from $60  to $150  per barrel. Mr.  Mayer responded  that he                                                                    
would provide the requested information.                                                                                        
                                                                                                                                
Mr. Mayer  discussed the  slide on  page 16  titled "revenue                                                                    
from  production tax  under  different  options" and  stated                                                                    
that the slide graphically  depicted the dollar figures from                                                                    
the  previous  slide. He  related  that  the top  two  lines                                                                    
reflected ACES  and CSSB  192 and that  the two  regimes had                                                                    
little difference  between them.  The next line  down, which                                                                    
was navy blue with diagonal crosses  on it, was the CSSB 192                                                                    
50 percent  cap option;  this option  was identical  to CSSB                                                                    
192 at the  $140 per barrel level, but  "diverges" from that                                                                    
point  onward. He  noted that  the CSSB  192 40  percent cap                                                                    
option,  which was  represented by  the pink  line with  the                                                                    
vertical bar,  was also  identical to  CSSB 192  until about                                                                    
the $110  per barrel level,  but that it diverged  from that                                                                    
point onward. He  observed that the CSSB 192  40 percent cap                                                                    
option generated  significantly higher  revenue than  HB 110                                                                    
at the $110 per barrel  level, but had slightly less revenue                                                                    
than HB  110 from the $180  per barrel level and  onward. He                                                                    
related that the 20 percent  severance tax option, which was                                                                    
reflected by the light pink line,  was a little above HB 110                                                                    
at high price  levels, but that it converged with  HB 110 at                                                                    
the "top of the deck"; at  the $100 per barrel level, the 20                                                                    
percent severance  option was much  closer to CSSB  192 than                                                                    
HB 110 was. The bottom  three lines represented what some of                                                                    
the  incentives  for new  production  could  look like.  The                                                                    
electric  blue line  with  the  triangle marker  represented                                                                    
what  HB 110  would look  like  with the  incentive for  new                                                                    
production.  The  lighter  blue  line  represented  the  six                                                                    
percent severance tax option. He  related that at around the                                                                    
$160  per barrel  level, the  six  percent severance  option                                                                    
generated higher  revenue than  HB 110  because of  HB 110's                                                                    
low 15  percent base  rate for  new production;  however, at                                                                    
the highest  price levels, the six  percent severance option                                                                    
was below HB  110 in terms of revenue. He  related that from                                                                    
$130 per barrel and upwards,  the 25 percent flat tax option                                                                    
had a lower level of taxation than HB 110's new production.                                                                     
                                                                                                                                
3:06:55 PM                                                                                                                    
                                                                                                                                
Co-Chair Stedman inquired if the  chart was based on 200,000                                                                    
bbl/d in  production. Mr. Mayer responded  that any analysis                                                                    
that included dollar  figures would be based on  the FY 2013                                                                    
numbers.  Co-Chair  Stedman  clarified that  the  chart  was                                                                    
based on FY 2013 numbers.  Mr. Mayer responded that Co-Chair                                                                    
Stedman was correct.                                                                                                            
                                                                                                                                
3:07:18 PM                                                                                                                    
AT EASE                                                                                                                         
                                                                                                                                
3:20:41 PM                                                                                                                    
RECONVENED                                                                                                                      
                                                                                                                                
Mr.  Mayer discussed  the  slide on  page  17 titled  "total                                                                    
state  take  under different  options"  and  stated that  it                                                                    
depicted  the data  equivalent to  slide 16  in total  state                                                                    
take. He  explained that slide  17 was similar to  slide 16,                                                                    
but that  it had less  differentiation because of  the other                                                                    
sources of revenue that accrued to the state.                                                                                   
                                                                                                                                
Mr. Mayer stated  that the next set of  slides would examine                                                                    
the marginal  take under each  of the regimes that  had been                                                                    
examined.                                                                                                                       
                                                                                                                                
Mr.  Mayer explained  the slide  on page  18 titled  "ACES -                                                                    
marginal  take (FY  2013 data)."  He noted  that one  of the                                                                    
criticisms  of the  existing ACES  system was  how high  the                                                                    
marginal  government  take  could be,  particularly  at  the                                                                    
current prices levels. He added  that the slide included not                                                                    
just the  production tax,  but that  it also  calculated all                                                                    
the  components of  the regime  combined.  He observed  that                                                                    
ACES generated  a peak in  marginal government take  of more                                                                    
than  90 percent  at the  current price  levels of  ANS west                                                                    
coast crude; currently,  for every $1 increase  to the price                                                                    
of  ANS  west  coast  crude,  the  state  was  retaining  90                                                                    
percent.  Co-Chair Stedman  commented  that  the rate  would                                                                    
decline soon.                                                                                                                   
                                                                                                                                
Co-Chair Stedman  requested that the effective  tax rates be                                                                    
represented  on   the  charts   when  future   options  were                                                                    
presented to the committee. Mr.  Mayer replied that he would                                                                    
provide the requested information.                                                                                              
                                                                                                                                
Mr. Mayer  discussed the slide on  page 19 titled "HB  110 -                                                                    
marginal government take (FY 2013  data)." He stated that HB                                                                    
110  would  put a  bracketing  system  in place  that  would                                                                    
enable  it to  substantially reduce  the marginal  levels of                                                                    
government  take; this  scenario had  a marginal  government                                                                    
take below 70 percent for all price ranges.                                                                                     
                                                                                                                                
Mr. Mayer explained the slide on  page 20 titled "CSSB 192 -                                                                    
marginal  government take  (FY 2013  data)." He  stated that                                                                    
CSSB 192 looked very similar to  ACES and that it also had a                                                                    
marginal government  take that peaked above  90 percent. The                                                                    
peak occurred  at slightly higher price  range in comparison                                                                    
to ACES because of the .35 coefficient.                                                                                         
                                                                                                                                
Mr. Mayer  discussed the slide  on page 21 titled  "CSSB 192                                                                    
with 50% cap - marginal  government take (FY 2013 Data)" and                                                                    
observed that  it did not  have a significant  difference in                                                                    
comparison  to  ACES  regarding the  peak  of  the  marginal                                                                    
rates.  After the  50 percent  cap  option's marginal  peak,                                                                    
which was  around the  $130 per  barrel level,  the marginal                                                                    
take  flattened  out  because   the  progressivity  did  not                                                                    
increase past the 50 percent rate.                                                                                              
                                                                                                                                
Mr. Mayer  explained the slide  on page 22 titled  "CSSB 192                                                                    
with a 40 % cap -  marginal government take (FY 2013 data)."                                                                    
He  stated that  reducing  the maximum  rate  to 40  percent                                                                    
would, in  part, address areas  of the marginal  take issue;                                                                    
the system  still had  a peak that  was characteristic  of a                                                                    
non-bracketed  progressivity system,  but the  peak occurred                                                                    
at the  low-80 percent  level instead of  at 90  percent and                                                                    
above;  the  change  to where  the  system's  marginal  take                                                                    
peaked  was a  result of  lowering  the maximum  rate to  40                                                                    
percent.                                                                                                                        
                                                                                                                                
Mr. Mayer discussed the slide  on page 23 titled "30 percent                                                                    
base  rate,  0.02  %  progressivity, 40  %  cap  -  marginal                                                                    
government take  (FY 2013  data)."[Mr. Mayer  had previously                                                                    
pointed out  that the .02 percent  in the slides was  a typo                                                                    
and that  it should be  .2 percent instead.] He  stated that                                                                    
this scenario  reduced the peak  of the  marginal government                                                                    
take to  the mid-70 percent  range. He pointed out  that the                                                                    
scenario  had worsened  project  economics  for all  assets,                                                                    
particularly  at around  the $60  per barrel  level and  for                                                                    
small  high  cost developments.  He  added  that under  this                                                                    
model,  small  high  cost  developments  might  not  trigger                                                                    
progressivity, even at higher  prices, because of their high                                                                    
cost structure.                                                                                                                 
                                                                                                                                
3:25:51 PM                                                                                                                    
                                                                                                                                
Mr. Mayer explained  the slide on page  24 titled "severance                                                                    
tax  - 20  percent maximum  - marginal  government take  (FY                                                                    
2013  data)"  and  stated   that  following  this  structure                                                                    
resulted  in a  peak of  marginal  tax rates  around the  80                                                                    
percent rate.                                                                                                                   
                                                                                                                                
Mr. Mayer discussed the slide  on pages 25 titled "severance                                                                    
tax  - 6  %  maximum  - marginal  government  take (FY  2013                                                                    
data)." He explained that the  six percent maximum severance                                                                    
tax rate was  for incentivizing new production  and that the                                                                    
marginal  rates  dropped  even  further  on  this  slide  in                                                                    
comparison to previous slides.                                                                                                  
                                                                                                                                
Mr. Mayer  explained the slide  on page 26 titled  "25% flat                                                                    
production tax - marginal government take (FY 2013 data)."                                                                      
He stated  that the slide's  flat 25 percent  production tax                                                                    
for particular  categories of new  production resulted  in a                                                                    
flat marginal government take that  was slightly over the 60                                                                    
percent level.                                                                                                                  
                                                                                                                                
Mr.  Mayer discussed  the slide  on page  27 titled  "regime                                                                    
competiveness:  average  government  take." He  pointed  out                                                                    
that there was  an error in one of the  data points and that                                                                    
he would provide a correction.  He explained that HB 110 was                                                                    
represented  too low  on the  slide because  the 15  percent                                                                    
base rate  for new  production, rather  than the  25 percent                                                                    
rate,  had been  applied; HB  110  should be  around the  67                                                                    
percent rate  on the  slide rather  than the  low-60 percent                                                                    
range. He apologized for the error.                                                                                             
                                                                                                                                
Co-Chair Stedman noted that the  slide could be reprinted in                                                                    
the  future and  that  there were  other modifications  that                                                                    
needed to be done to several slides.                                                                                            
                                                                                                                                
Co-Chair  Stedman  requested  that   PFC  Energy  tweak  the                                                                    
numbers in the 20 percent  severance option in order to work                                                                    
with  the balance  between the  marginal  and effective  tax                                                                    
rates;  He furthered  that he  wanted the  option worked  so                                                                    
that the state's  current cash position did not  change at a                                                                    
price  of  $100  per  barrel. Mr.  Mayer  responded  in  the                                                                    
affirmative.                                                                                                                    
                                                                                                                                
Mr. Mayer continued to speak to  slide 27 and stated that an                                                                    
ACES  existing  producer was  only  a  little below  Norway,                                                                    
which was  the slide's highest taxing  OECD jurisdiction. He                                                                    
stated that  as the caps of  50 percent and 40  percent were                                                                    
implemented  on progressivity,  the  government take  levels                                                                    
dropped closer to the 70  percent mark. He furthered that as                                                                    
it  was   currently  structured,  the  20   percent  maximum                                                                    
severance  tax option  put  Alaska  just above  Haynesville,                                                                    
which was the highest of  the slide's North American onshore                                                                    
producers.    He   explained    that   under    the   slide,                                                                    
unconventional  production from  Haynesville, Louisiana  had                                                                    
a government take in the  high-60 percent range and that the                                                                    
20  percent  severance tax  option  reached  69 percent.  He                                                                    
pointed  out  that  potential  changes  to  the  20  percent                                                                    
severance option  could increase  the expected  maximum rate                                                                    
slightly. He related that if  the 25 percent flat production                                                                    
tax was  offered as an incentive  for incremental production                                                                    
from new and  existing fields, the government  take could be                                                                    
in the low-60 percent range  for that increment and would be                                                                    
competitive.                                                                                                                    
                                                                                                                                
3:30:30 PM                                                                                                                    
                                                                                                                                
Co-Chair Stedman pointed  out that the flat  tax option also                                                                    
showed the  effect of a  25 percent  base tax, which  had no                                                                    
progressivity,  in  order  to   show  a  comparison  of  tax                                                                    
structures. He requested  that PFC Energy change  the x axis                                                                    
and "bring it  in" to $150 per barrel, tweak  the 20 percent                                                                    
severance option,  and show comparisons of  the marginal and                                                                    
effective tax rates in percentages and dollars.                                                                                 
                                                                                                                                
Co-Chair Stedman discussed the following meeting's agenda.                                                                      
                                                                                                                                
SB  192  was  HEARD  and   HELD  in  committee  for  further                                                                    
consideration.                                                                                                                  
                                                                                                                                
ADJOURNMENT                                                                                                                   
3:32:14 PM                                                                                                                    
                                                                                                                                
The meeting was adjourned at 3:32 PM.                                                                                           
                                                                                                                                
                                                                                                                                

Document Name Date/Time Subjects
SB 192 PFC Alaska Senate Finance - March 27, 2012.pdf SFIN 3/27/2012 1:00:00 PM
SB 192