Legislature(2011 - 2012)SENATE FINANCE 532

03/15/2012 01:00 PM FINANCE

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01:05:34 PM Start
01:06:01 PM SB192
02:57:35 PM Adjourn
* first hearing in first committee of referral
+ teleconferenced
= bill was previously heard/scheduled
Heard & Held
+ Bills Previously Heard/Scheduled TELECONFERENCED
                 SENATE FINANCE COMMITTEE                                                                                       
                      March 15, 2012                                                                                            
                         1:05 p.m.                                                                                              
1:05:34 PM                                                                                                                    
CALL TO ORDER                                                                                                                 
Co-Chair Stedman called the Senate Finance Committee                                                                            
meeting to order at 1:05 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                                                                                                                
ALSO PRESENT                                                                                                                  
Senator Cathy Giessel; Senator Joe Paskvan; Senator Hollis                                                                      
French; Gerald Kepes, Partner and Head of Upstream and Gas,                                                                     
PFC Energy.                                                                                                                     
PRESENT VIA TELECONFERENCE                                                                                                    
Janak Mayer, PFC Energy, Washington, DC.                                                                                        
SB 192    OIL AND GAS PRODUCTION TAX RATES                                                                                      
          SB 192 was HEARD and HELD in committee for                                                                            
          further consideration.                                                                                                
SENATE BILL NO. 192                                                                                                           
     "An Act relating to the oil and gas production tax;                                                                        
     and providing for an effective date."                                                                                      
1:06:01 PM                                                                                                                    
GERALD  KEPES, PARTNER  AND HEAD  OF UPSTREAM  AND GAS,  PFC                                                                    
ENERGY, introduced himself.                                                                                                     
Mr.   Kepes    discussed   the    PowerPoint   Presentation:                                                                    
"Discussion Slides:  Alaska Senate Finance  Committee" (copy                                                                    
on file).  He stated  that since  the current  day's morning                                                                    
meeting, he  had conducted some global  context analysis for                                                                    
energy  and petroleum  and  upstream  investment. He  stated                                                                    
that there  was a  focus on the  Alaska Clear  and Equitable                                                                    
Share  Act (ACES);  different cost-producing  scenarios; and                                                                    
global comparison of average and marginal government take.                                                                      
Mr. Kepes  discussed slide 31,  "ACES versus CS SB  192." He                                                                    
stated  that the  slide  displayed  the differences  between                                                                    
ACES and  CS SB  192. He explained  that production  tax was                                                                    
not bracketed  in either case.  He furthered that CS  SB 192                                                                    
decoupled oil and gas. He  noted the difference in the rates                                                                    
for the  production tax:  ACES had a  maximum of  75 percent                                                                    
and CS  SB 192 had a  maximum of 60 percent.  He stated that                                                                    
the  progressivity  for  ACES  was  0.40  percent,  and  the                                                                    
progressivity for CS SB 192  was 0.35 percent. He added that                                                                    
CS SB 192 had an allowance for new oil.                                                                                         
JANAK    MAYER,   PFC    ENERGY,    WASHINGTON,   DC    (via                                                                    
teleconference),  stated that  CS SB  192 also  held a  flaw                                                                    
related to  the minimum rate  of production tax value  at 10                                                                    
percent  of gross  value for  large producers.  He explained                                                                    
that there would be a presentation of that analysis.                                                                            
Mr. Kepes  looked at slide  32, "ACES  (Existing Producer)."                                                                    
He explained that  the slide represented a  2000 barrels per                                                                    
day producer. He stated that  the government take, displayed                                                                    
in  the  upper right  hand  table,  varied from  roughly  68                                                                    
percent up to 81 or 82 percent as oil prices rose.                                                                              
1:11:20 PM                                                                                                                    
Mr.  Kepes   discussed  slide  33,  "CS   SB  192  (Existing                                                                    
Producer)." He noted  similar producing characteristics with                                                                    
ACES.  He pointed  out some  slight variations  between ACES                                                                    
and CS SB  192: the peak of government take  under CS SB 192                                                                    
lowered from 83  percent to 79 percent; and  the project net                                                                    
present value  of producers  under CS  SB 192  rose slightly                                                                    
for existing producers.                                                                                                         
Mr. Kepes looked  at slide 34, "ACES  (New Development)." He                                                                    
stated that  the slide  was an analysis  of the  higher cost                                                                    
development, peaking at 10,000  barrels per day representing                                                                    
a reserve size of approximately  65 million barrels, at $100                                                                    
a barrel.  He noted that  the total government  take started                                                                    
at 75 percent and peaked at 85 percent.                                                                                         
Mr.   Kepes   discussed   slide   35,  "CS   SB   192   (New                                                                    
Development)."  He noted  that the  government take  for new                                                                    
development was 80 percent at  its peak. He stated that both                                                                    
new development  projects were fairly  marginal at  $100 per                                                                    
barrel, and it did not change from ACES to CS SB 192.                                                                           
Co-Chair Stedman  requested an explanation of  each quadrant                                                                    
displayed in the  slide. Mr. Kepes explained  that the upper                                                                    
left hand  quadrant represented the  cash flow  analysis. He                                                                    
pointed out the periods  of negative revenue represented the                                                                    
initial   capital   expenditures  (CAPEX)   and   operations                                                                    
expenditures (OPEX) for a particular  project. He noted that                                                                    
the peak  CAPEX in  the third year  of development  was $300                                                                    
million,  which was  calculated  after  the capital  credits                                                                    
were  applied.  He  pointed out  that  the  operating  costs                                                                    
extended for  the lifetime of  the field. He  furthered that                                                                    
the black line  represented the after tax  cash flow (ACTF).                                                                    
The upper right  hand portion of the slide was  a table that                                                                    
coincided with the  cash flow analysis graph.  He noted that                                                                    
the  table displayed  a summary  at $40,  $60, and  $100 per                                                                    
barrel; the net  present value of the  project investment to                                                                    
the investor;  and the internal  rate of return (IR)  to the                                                                    
investor. At $100 per barrel,  the project represented a net                                                                    
present value  of $12 million, and  an IR of 10  percent. He                                                                    
stressed that at $100 per barrel,  from the point of view of                                                                    
the  investor, it  was a  relatively  marginal project.  The                                                                    
lower left  hand corner graph  displayed a breakdown  of the                                                                    
different   components   of   government   take.   The   red                                                                    
represented the  royalty, the yellow  represented production                                                                    
tax, the light blue represented  the property tax, the green                                                                    
represented the  state corporate  income tax (CIT),  and the                                                                    
dark blue represented the federal CIT.                                                                                          
1:16:42 PM                                                                                                                    
Co-Chair Stedman  wondered what the  lower-right-hand corner                                                                    
represented.  Mr. Kepes  replied  that it  was a  normalized                                                                    
representation  of the  level  and  composition of  relative                                                                    
government  take. He  stated that  the fiscal  system breaks                                                                    
down at  $40 to $60 per  barrel, because the price  would be                                                                    
too  low to  maintain at  the particular  fiscal system.  He                                                                    
furthered that as  the price of oil rose; the  royalty was a                                                                    
progressively smaller  percentage of the  overall government                                                                    
take. He  pointed out  the increase  of the  contribution of                                                                    
the  production  tax, because  of  the  where the  base  was                                                                    
located, and the "stepping" at the upper price ranges.                                                                          
Mr. Kepes  stated that  the same  quadrant structure  on the                                                                    
slide would be used throughout the presentation.                                                                                
Mr. Kepes looked  at slide 36, "Progressivity  Impact on New                                                                    
Development Project Economics." He  stated that the graph on                                                                    
the left  hand side  of the  slide represented  a comparison                                                                    
ACES  and predecessor  regimes  (actual  and proposed).  The                                                                    
right hand side  graph displayed a comparison  with ACES and                                                                    
CS SB 192 with bracketed amendments.                                                                                            
Co-Chair Stedman wondered if the  x-axis was ANS West Coast.                                                                    
Mr. Kepes responded  that it was ANS West Coast  at $100 per                                                                    
barrel, with a net present  value in millions of dollars for                                                                    
the investor.                                                                                                                   
Co-Chair  Stedman  requested  an  analysis of  PPT  and  its                                                                    
evolution.  Mr. Kepes  thanked the  chairman, and  agreed to                                                                    
provide that information.                                                                                                       
Mr.   Kepes  discussed   slide  37,   "New  Oil   Allowance:                                                                    
Incremental Production on a Declining Base":                                                                                    
     Central to  understanding the impact of  the "allowance                                                                    
     for 'new  oil'" is  an understanding  of the  impact of                                                                    
     new source  production on a company's  total production                                                                    
     volumes, when that new source  production is added to a                                                                    
     declining base portfolio.                                                                                                  
     The  charts assume  a  6 percent  decline  rate for  an                                                                    
     existing North  Slope producer currently  producing 200                                                                    
     million   barrels   per   day   (mb/d),   and   examine                                                                    
     hypothetical new source projects  that peak at 10 mb/d,                                                                    
     50  mb/d   and  100  mb/d  respectively(on   a  working                                                                    
     interest basis).                                                                                                           
     Given the  pace at which such  projects typically reach                                                                    
     peak production, only the 100  mb/d peak production new                                                                    
     source  development  is   actually  capable  of  adding                                                                    
     production   that  is   incremental  to   prior  years'                                                                    
1:23:49 PM                                                                                                                    
Co-Chair  Stedman wondered  why  200 mb/d  was  used in  the                                                                    
analysis. Mr. Kepes replied with slide 38.                                                                                      
Mr.  Kepes looked  at  slide 38,  "A  Hypothetical 100  mb/d                                                                    
(Working Interest) Development":                                                                                                
     A  new source  development  that produced  100 mb/d  at                                                                    
     peak for  a working  interest partner  would be  a very                                                                    
     significant  new development.   By  way of  comparison,                                                                    
     Kuparuk,  the second  largest field  in North  America,                                                                    
    peaked at approximately 320 mb/d gross production.                                                                          
     -This  represented   working  interest   production  to                                                                    
     ConocoPhillips (the operator  and majority shareholder)                                                                    
     of 170 mbo/d.                                                                                                              
     -Kuparuk took  11 years  (from 1981  to 1992)  to reach                                                                    
     this peak level of production.                                                                                             
Co-Chair Stedman  announced that there would  be discussions                                                                    
about   any  particular   tax  structure's   probability  of                                                                    
producing great amounts  of oil. Mr. Kepes  replied that the                                                                    
prospectivity  of  finding  an  on-shore  field  that  could                                                                    
produce 320  mb/d was  fairly low. It  was more  likely that                                                                    
new field prospectivity would be substantially low.                                                                             
Mr. Kepes discussed slide 39, "Assumptions":                                                                                    
     The following analysis assumes                                                                                             
     1. A 6  percent base portfolio decline, in  the case of                                                                    
     a producer currently producing 200 mb/d.                                                                                   
     2. Costs for the base production portfolio of:                                                                             
     -$12/ flowing bbl operating expenditure                                                                                    
     -$5/ flowing bbl maintenance capital expenditure                                                                           
     3.  Costs  for  the  100 mb/d  (working  interest)  New                                                                    
     Development project of:                                                                                                    
     -$13/ flowing bbl operating expenditure                                                                                    
     -$13/bbl reserves development capital expenditure                                                                          
     -$1/ flowing bbl maintenance capital expenditure                                                                           
     4.  These costs  are deliberately  somewhat lower  than                                                                    
     the  previously  referenced  10 mb/d  new  development,                                                                    
     since   the   hypothetical   development   modeled   is                                                                    
     significantly larger, and thus  likely to have somewhat                                                                    
     lower costs on a $/bbl basis.                                                                                              
1:28:36 PM                                                                                                                    
Mr. Kepes looked  at slide 40, "CS SB 192  Excluding New Oil                                                                    
Allowance  (Existing  Producer)."   He  explained  that  the                                                                    
description of  the investment, as discussed,  was displayed                                                                    
in the  slide, excluding  the new  oil allowance.  The slide                                                                    
was  attempting  to  isolate  the   impact  of  CS  SB  192,                                                                    
excluding the new  oil allowance. He stated that  the in the                                                                    
total government take in the  upper right hand corner ranged                                                                    
from 68  percent to 79 percent.  The NPV at $100  per barrel                                                                    
was approximately $16.7 million.                                                                                                
Mr. Kepes discussed  slide 41, "CS SB 192  Including $10 New                                                                    
Oil  Allowance  (Existing  Producer)." He  stated  that  the                                                                    
slide  followed the  same  model as  slide  40. An  existing                                                                    
producer  with  200,000  barrels  per day  would  develop  a                                                                    
100,000 per day working interest project at the same cost.                                                                      
Mr. Kepes looked  at slide 42, "CS SB 192  Excluding New Oil                                                                    
Allowance  (New 100  mb/d Development)."  He  looked at  the                                                                    
cash flow analysis  graph in the upper left  hand corner. He                                                                    
explained that the after tax cash  floor in 2009 to 2014 was                                                                    
negative  because of  CAPEX pre-production.  He stated  that                                                                    
production would  be initiated  in 2013,  and the  cash flow                                                                    
would  reach   into  the  positive.   He  stated   that  the                                                                    
investment  would represent  an  NPV  of approximately  $276                                                                    
million at  100 per barrel,  and an internal rate  of return                                                                    
at 11 percent. He directed  the committee's attention to the                                                                    
table  in the  upper right  hand  corner of  the slide,  and                                                                    
noted the total government take  rising from 69 percent to a                                                                    
maximum of 81 percent.                                                                                                          
1:33:24 PM                                                                                                                    
Co-Chair   Stedman   wondered   how  back-out   costs   from                                                                    
production facilities were  incorporated. Mr. Kepes deferred                                                                    
to Mr. Mayer.                                                                                                                   
Mr.   Mayer  stated   that  the   costs,  without   existing                                                                    
production,  would include  some additional  operating costs                                                                    
to account for no base production.                                                                                              
Co-Chair  Stedman   requested  more  detail   regarding  the                                                                    
inclusion of  the back  out fees  that were  negotiated with                                                                    
the existing  producers to use facilities,  to determine the                                                                    
overall  impact.  Mr. Kepes  replied  that  there were  some                                                                    
assumptions included in the OPEX,  and deferred to Mr. Mayer                                                                    
to provide  more information. Mr.  Mayer furthered  that the                                                                    
included OPEX  in new  development without  base production,                                                                    
was relatively high.                                                                                                            
Mr. Kepes discussed  slide 43, "CS SB 192  Including $10 New                                                                    
Oil  Allowance (New  100  mb/d  Development)." He  explained                                                                    
that the $10 new  oil allowance provided added approximately                                                                    
$50 million  of NPV to a  project, and the internal  rate of                                                                    
return was the  same. He surmised that  the changes provided                                                                    
by the  addition of the  $10 new oil allowance,  were fairly                                                                    
modest  with  respect  to  the model  without  the  new  oil                                                                    
Mr. Kepes looked at slide 44, "Oil/Gas Decoupling":                                                                             
     1. Under  ACES, production tax  value is assessed  on a                                                                    
     combined  BTU-equivalent basis  for  both  oil and  gas                                                                    
     -So  long  as no  major  gas  export project  is  under                                                                    
     development, this has no impact.                                                                                           
     -In the event of the  development of a major gas export                                                                    
     project,  however, when  gas  prices are  significantly                                                                    
     lower than  oil prices, this could  lead to significant                                                                    
     reductions in Government Take.                                                                                             
     2.  CSSB  192 includes  a  provision  to de-couple  the                                                                    
     calculation of production tax value  on North Slope gas                                                                    
     sold out-of-state,  in order  to eliminate  this impact                                                                    
     of gas production.                                                                                                         
     -The impact  of the  decreased government  take without                                                                    
     decoupling  is  only  pronounced   with  very  low  gas                                                                    
     prices, and very large gas production.                                                                                     
     -In order to illustrate the  impact at the extreme, the                                                                    
     following analysis thus assumes  a $1/mcf net-back sale                                                                    
     price  for  North Slope  gas,  and  a 2018  1bcf/d  gas                                                                    
     project.  Under less  extreme scenarios, the difference                                                                    
     with  and  without  decoupling would  be  significantly                                                                    
1:38:46 PM                                                                                                                    
Co-Chair  Stedman  remarked  that  the  "major  line"  would                                                                    
provide  $4.50 bcf  per day.  Mr. Kepes  stated that  it was                                                                    
larger than stated.                                                                                                             
Mr. Kepes discussed slide 45,  "CSSB 192 - Existing Producer                                                                    
with  2018 Gas  Project, No  Decoupling." He  looked at  the                                                                    
cash flow analysis  graph in the upper left  hand section of                                                                    
the slide,  and remarked that  in 2014  to 2018 there  was a                                                                    
"dip"  in  the after-tax  cash  flow  line. The  substantial                                                                    
"dip" represented CAPEX.  He furthered that the  NPV in that                                                                    
particular  portfolio was  equally substantial.  He remarked                                                                    
that the table  in the upper right hand corner  of the graph                                                                    
displayed a total  government take range from  67 percent to                                                                    
71 percent.                                                                                                                     
Mr. Kepes looked at slide  46, "CSSB 192 - Existing Producer                                                                    
with 2018  Gas Project,  Including Decoupling."  He remarked                                                                    
that the government  take changed from a peak  of 71 percent                                                                    
with no  decoupling to 78  percent including  decoupling. He                                                                    
felt that the impact was  relatively modest. He suggested an                                                                    
analysis be conducted  of $4 bcf per day,  because it seemed                                                                    
more realistic.                                                                                                                 
Co-Chair  Stedman  felt that  cash  flow  numbers were  more                                                                    
important   than  government   take  numbers,   because  the                                                                    
government take  numbers "hid" the  amount of cash  that was                                                                    
moved  around. He  noted  a letter  from  the Department  of                                                                    
Revenue  that stated  that combining  oil and  gas cost  the                                                                    
State $80 million a year with no gas sales.                                                                                     
Mr.  Kepes  discussed  slide  47,  "Regime  Competitiveness:                                                                    
Relative Government Take: Average  Government Take of Global                                                                    
Fiscal  Regimes  at  $100/bbl." He  stated  that  the  slide                                                                    
displayed a  comparison of different fiscal  regimes against                                                                    
a set  of regimes globally.  He pointed  out that CS  SB 192                                                                    
was  generating  a  government   take  of  approximately  76                                                                    
percent,  and pointed  out  how that  compared  to ACES  and                                                                    
other jurisdictions.                                                                                                            
1:43:54 PM                                                                                                                    
Mr.  Kepes  looked  at slide  48,  "Regime  Competitiveness:                                                                    
Relative Government Take: Average  Government Take of Global                                                                    
Fiscal Regimes  at $140/bbl."  He remarked  that it  was the                                                                    
same analysis as  slide 47, but at $140/bbl.  He pointed out                                                                    
that both ACES  and CS SB 192 moved "up  the scale somewhat"                                                                    
relative the other less progressive jurisdictions.                                                                              
Mr.  Kepes  discussed  slide  49,  "Regime  Competitiveness:                                                                    
Relative  Government  Take:   Marginal  government  Take  of                                                                    
Global  Fiscal  Regimes at  $100/bbl."  He  stated that  the                                                                    
analysis was  conducted with  a $1/bbl step  at a  time, and                                                                    
looked at  the change  in government  take on  that marginal                                                                    
Co-Chair  Stedman  noted  a slight  improvement.  Mr.  Kepes                                                                    
Mr.  Kepes touched  on  slide  50, "Regime  Competitiveness:                                                                    
Relative  Government  Take:   Marginal  Government  Take  of                                                                    
Global Fiscal Regimes at $140/bbl."                                                                                             
Mr.  Kepes discussed  slide 51,  "Conclusions  - Changes  to                                                                    
Progressivity,   Overall   Government  Take,   and   Oil/Gas                                                                    
     1.  CSSB   192  uses  two  key   mechanisms  to  reduce                                                                    
     government take relative to ACES:                                                                                          
     -A reduction in the  rate of progressivity that applies                                                                    
     above $30/bbl  Production Tax Value   (PTV) from  a 0.4                                                                    
     percent increase  for each one dollar  increase in PTV,                                                                    
     to a 0.35 percent increase.                                                                                                
     -A  reduction in  the maximum  rate of  production tax,                                                                    
     from  75 percent  at $342  PTV, to  60 percent  at $202                                                                    
     2.  The impact  of the  reduction in  the progressivity                                                                    
     coefficient on  overall levels  of government  take and                                                                    
     on  project economics  is limited  to  around a  single                                                                    
     percentage point of government take at $100 ANS crude.                                                                     
     3.  The  impact of  the  60  percent maximum  rate  for                                                                    
     production tax  is more significant,  but only  at very                                                                    
     high oil prices.                                                                                                           
     -On a  current-year basis,  government take  under CSSB                                                                    
     192 would  be significantly lower than  under ACES only                                                                    
     at ANS crude oil prices above $230.                                                                                        
     -On a  project-lifecycle basis,  that threshold  may be                                                                    
     lower,  as  a result  of  the  impact of  bracket-creep                                                                    
     (since  progressivity   thresholds  are   specified  in                                                                    
     nominal terms)  - but the  impact on  project economics                                                                    
     at likely price levels remains negligible.                                                                                 
Mr. Kepes looked at slide 52, "Conclusions - New Oil                                                                            
     1. Even  under highly aggressive  assumptions regarding                                                                    
     the potential for a new-source  development for a given                                                                    
     company, the impact of the  $10 allowance for "new oil"                                                                    
     is almost undetectable.                                                                                                    
     -In the  context of both  a development by  an existing                                                                    
     producer,  and   a  development  by  a   new  producer,                                                                    
     Relative Government  Take changes only by  fractions of                                                                    
     a percentage point, at most.                                                                                               
     -For an existing producer, portfolio  NPV rises by only                                                                    
     a tenth of a percentage point.                                                                                             
     -For a  new producer,  the impact  on project  value is                                                                    
     greater, but remains insignificant  in the context of a                                                                    
     $10 billion capital development.                                                                                           
     2. The  major reason  for this  is because  rather than                                                                    
     providing   an   ongoing   allowance   for   new-source                                                                    
     production,  the amendment  provides an  allowance only                                                                    
     for production  that, in a  given year,  is incremental                                                                    
     to the previous year's production.                                                                                         
     -For   an  existing   producer   with  declining   base                                                                    
     production, only  a very  large development  is capable                                                                    
     of producing "new oil" under this development at all.                                                                      
     -Even for  a new producer,  the value of  the allowance                                                                    
     remains highly limited.                                                                                                    
     3.  An allowance  which was  instead provided  for new-                                                                    
     source  production  could  potentially have  a  greater                                                                    
     impact,  however  adequately defining  such  new-source                                                                    
     production    could   be    difficult   in    practice,                                                                    
     particularly   in  an   environment   where  most   new                                                                    
     production will come from existing areas.                                                                                  
1:49:22 PM                                                                                                                    
Senator Thomas looked at slide  51, and wondered how many of                                                                    
the various  oil jurisdictions  had a  combined oil  and gas                                                                    
tax. Mr.  Kepes replied  that very  few jurisdictions  had a                                                                    
combined oil and  gas tax. He furthered  that most locations                                                                    
treated  gas  slightly  differently  from  one  another.  He                                                                    
stated that the differential  in value, whether calorific or                                                                    
value-based, had  become so large,  that a combined  oil and                                                                    
gas tax aggravates the system.                                                                                                  
Mr.  Kepes  introduced  the section,  "Global  Strategy  and                                                                    
Portfolio Overview of Major  Alaska Producers." He explained                                                                    
that the section provided an  assessment of the major Alaska                                                                    
producers'  portfolios,   priorities,  and   strategies.  He                                                                    
stated  that the  data that  was used  was either  public or                                                                    
from PFC Energy's proprietary databases.                                                                                        
Mr. Kepes discussed slide 55,  "BP: Global Areas of Upstream                                                                    
     Strategic Signature                                                                                                        
     -BP is a global  integrated company, with production in                                                                    
     16 countries  and upstream operations in  an additional                                                                    
     10 countries.                                                                                                              
     -In    2010,   total    global   production    averaged                                                                    
     approximately  3,773  mboe/d,   making  it  the  second                                                                    
     largest  company  in  the  peer  group  (superseded  by                                                                    
     ExxonMobil (approximately  4,450 mboe/d).    The Russia                                                                    
     &  Central   Asia  (RCA)  and  North   America  regions                                                                    
     accounted   for  approximately   55  percent   of  2010                                                                    
     -BP recorded a  4.5 percent drop in  production in 2010                                                                    
     over 2009,  reflecting the impact  of asset  sales, the                                                                    
     post-Macondo  slowdown in  US  GOM deepwater  activity,                                                                    
     and continued decline from  the company's deepwater and                                                                    
     mature shallow water assets.                                                                                               
     -Much  of  the post-Macondo  portfolio  rationalization                                                                    
     program   (targeting  $30   billion   in  asset   sales                                                                    
     including  mid/downstream assets)  has been  completed.                                                                    
     The result is a pared  down and more focused geographic                                                                    
     -BP expects  growth of 1  percent -2 percent  per annum                                                                    
     through 2015.   BP's  growth strategy  is three-pronged                                                                    
     based  on  Deepwater  Basins,  Global  Gas,  and  Giant                                                                    
     Oilfield  Development.   BP's  deep  water position  is                                                                    
     based on  operations in the  US GOM, Angola,  Egypt and                                                                    
     Brazil.    The  Global   Gas  position  is  principally                                                                    
     comprised  of US,  Trinidad &  Tobago,  and North  Sea.                                                                    
     Giant oil  fields are  dispersed throughout  the global                                                                    
     portfolio.  Based on  PFC  Energy  projects, growth  is                                                                    
     unlikely before 2015.                                                                                                      
     -The growth  strategy above includes  approximately $20                                                                    
     billion  net  investment   commitment  to  16  projects                                                                    
     sanctioned over  2010-2011.  This  is expected  to curb                                                                    
     ROCE performance for the coming 2-3 years.                                                                                 
     -With  the   burden  of  the  Macondo   oil  spill  and                                                                    
     reparations  continuing through  the mid-term,  BP will                                                                    
     be  hard pressed  to outperform  its peers  on any  key                                                                    
     metrics,  leaving the  company open  to calls  for more                                                                    
     radical restructuring                                                                                                      
He stated that, according to PFC Energy's analysis, BP                                                                          
considered Alaska a "harvest area."                                                                                             
1:59:56 PM                                                                                                                    
AT EASE                                                                                                                         
2:10:02 PM                                                                                                                    
2:10:09 PM                                                                                                                    
Mr. Kepes discussed slide 56, "BP Global Production                                                                             
Portfolio - 2010":                                                                                                              
     Russia:  BP's largest  producing country  (963 mboe/d),                                                                    
     representing approximately  26 percent of  2010 output.                                                                    
     Substantial  long  term  growth potential.    Continued                                                                    
     interest  in  Russia  (and Arctic)  expansion,  despite                                                                    
    limitations arising from the TNK-BP joint venture.                                                                          
     Canada:  modest  conventional production,  with  future                                                                    
     potential tied to oil sands.                                                                                               
     US: 2nd largest producing  country, with core deepwater                                                                    
     area.  Activity slowed  post-Macondo, yet expect strong                                                                    
     future   growth.     Onshore  L48   is  key   gas  area                                                                    
     (approximately 22 percent of  2010 global output), with                                                                    
     focus  on  unconventionals.  Alaska potential  tied  to                                                                    
     commercialization of Prudhoe Bay resources.                                                                                
     UK:   Declining position  from mature  offshore assets.                                                                    
     High-value  operating   area,  generating   large  cash                                                                    
     Trinidad  & Tobago:  Core gas  producing  area tied  to                                                                    
     Atlantic LNG.                                                                                                              
     Azerbaijan:  Participation in  2 large-scale  projects:                                                                    
     Azeri-Chirag-Guneshli & Shah Deniz.                                                                                        
     UAE:   Core position through equity  affiliates, though                                                                    
     concession are being re-negotiated.                                                                                        
     India:  2011 Partnership  with Reliance for exploration                                                                    
     in shallow and deepwater.                                                                                                  
     Australia  and Indonesia  are key  gas producing  areas                                                                    
     tied to investments in LNG.                                                                                                
     Iraq: Development of Rumailia oil field.                                                                                   
     Angola:   Sole  presence  in SSA  is Angola  deepwater.                                                                    
     High growth from 2002-2009,  now challenged with start-                                                                    
     up of several unsanctioned projects.                                                                                       
     Argentina:  onshore &  shallow  water  assets (held  by                                                                    
     PAE) were to be sold  to Bridas, but transaction failed                                                                    
     in 4Q:11.                                                                                                                  
He  stressed that  the analysis  was based  on PFC  Energy's                                                                    
assessment  and opinion.  He stated  that the  slide pointed                                                                    
out asset type, conventional on-shore, and conventional                                                                         
Mr. Kepes looked at slide 57, "Total Portfolio Evolution:                                                                       
BP vis-à-vis the Competition":                                                                                                  
     In  2010, BP  was the  second largest  producer of  the                                                                    
     peer group.   Yet, from  2010 to  2015, BP and  COP are                                                                    
     the only two companies to experience a reduction.                                                                          
     2000-2010:  Production   increases  from  approximately                                                                    
     3,080  mboe/d  to  approximately 3,780  mboe/d  due  to                                                                    
     addition   of   Russia  (approximately   960   mboe/d),                                                                    
     Trinidad  &  Tobago   (approximately  250  mboe/d)  and                                                                    
     Angola  (approximately  170  mboe/d).   This  expansion                                                                    
     offsets declines from  Europe (approximately 660 mboe/d                                                                    
     and North America approximately 350 mboe/d).                                                                               
     2011-2015: BP's production is  expected to decline from                                                                    
     2000-2015,  due   mostly  to  the   post-Macondo  asset                                                                    
     divestiture program,  combined with curbed  activity in                                                                    
     the GOM deepwater.                                                                                                         
Mr. Kepes discussed slide 58, "Reserves and Production: BP                                                                      
vis-à-vis the Competition":                                                                                                     
     2000 - 2003: BP  experienced significant reserve growth                                                                    
     (from  approximately  15,000   mmboe  to  approximately                                                                    
     18,000 mmboe)  equivalent to approximately  6.5 percent                                                                    
     CAGR. The increase  is the result of  added reserves in                                                                    
     Africa (Angola),  Equity Affiliates (Russia)  and Asia-                                                                    
     Pacific.   Production    grew   at   a    slower   pace                                                                    
    (approximately 3 percent CAGR) during this period.                                                                          
     2003  - 2004:  The formation  of TNK-BP  results in  an                                                                    
     increase  of  approximately  600 mboe/d  from  2003  to                                                                    
     2005-2010:  Production and  reserves remain  relatively                                                                    
     unchanged. Reserves  remain within the range  of 17.4 -                                                                    
     18.0 billion  boe. Production remains within  the range                                                                    
     of 1,462-1,389 mboe/d.                                                                                                     
2:16:07 PM                                                                                                                    
Mr. Kepes looked at slide 59, "Reserves and Production: BP                                                                      
Intra-Portfolio Performance":                                                                                                   
     Roughly  60  percent  of production  and  reserves  are                                                                    
     concentrated in  the US  and Equity  Affiliates (mostly                                                                    
     comprised of TNK-BP since 2003).                                                                                           
     European  production  (and reserves)  declined  rapidly                                                                    
     from 2000-2006 (Area is now  reported as UK and Rest of                                                                    
     Africa (mostly  Angola deepwater) production  more than                                                                    
     doubled from 2002 to 2009.                                                                                                 
Mr. Kepes discussed slide 60, "How the Portfolio is                                                                             
Financed: Sources and Uses of Cash":                                                                                            
     Over the  decade, Africa (mostly Angola  deepwater) has                                                                    
     rapidly  progressed from  an area  of investment  to an                                                                    
     area generating  cash surplus.  Africa was  BP's second                                                                    
     largest cash generator in 2010.                                                                                            
     The  US is  the  leading generator  of  cash flow  this                                                                    
    decade, allowing for re-investment in other areas.                                                                          
Mr. Kepes looked at slide 61, "Global Production: Evolution                                                                     
of the Portfolio."                                                                                                              
     Asia   Pacific:     Relatively  small   producing  area                                                                    
     (approximately  6 percent  of 2010  output). Production                                                                    
     largely  from  offshore  Australia and  Indonesia  with                                                                    
     lesser  volumes from  China. Partnership  with Reliance                                                                    
     (India)  creates  exploration opportunities.  Focus  on                                                                    
     deepwater  and CBM.   Divested  assets in  Pakistan and                                                                    
     farmed down in Vietnam.                                                                                                    
     Europe:  Mature  and   generally  declining  production                                                                    
     position  in  the  UK and  Norway,  mostly  in  shallow                                                                    
     waters.  Exploration   and  development   projects  are                                                                    
     ongoing, often leveraging  BP's existing infrastructure                                                                    
     and assets in the region.                                                                                                  
     Latin  America:  Growth  driven by  shallow  water  gas                                                                    
     developments  in Trinidad  & Tobago.  Focus on  onshore                                                                    
     gas  commercialization  in   Bolivia.  Failed  to  sell                                                                    
     Argentine assets (held through  PAE) to Bridas in 2011.                                                                    
     Brazil  deepwater offers  mid-  to long-term  potential                                                                    
     from newly acquired deepwater acreage.                                                                                     
     Middle  East  and  North Africa:  Position  built  from                                                                    
     collaboration with  NOCs (Adma-Opco,  GUPCO, Sonatrach,                                                                    
     LNOC,  etc.). Substantial  new  source growth  expected                                                                    
     from    Iraq,   Egypt    deepwater,   offshore    Oman.                                                                    
     Exploration opportunities in Jordan.                                                                                       
     North  America:  Second  largest  production  region  &                                                                    
     largest  cash  flow  generator.   Deepwater  GOM  holds                                                                    
     significant   growth    potential   after    years   of                                                                    
     investment.   US  L48   portfolio   is  material,   yet                                                                    
     declining, source  of gas, with  a growing  emphasis on                                                                    
     shale gas.  Additional future growth from  Canadian oil                                                                    
     Russia and Central Asia:  Principally comprised of TNK-                                                                    
     BP venture created in 2003,  now BP's largest source of                                                                    
     production,  characterized as  long-life, slow  decline                                                                    
     output. In  Azerbaijan, production is  from large-scale                                                                    
     ACG and  Shah-Deniz. The Region  is the  largest source                                                                    
     of new source volumes through 2015.                                                                                        
     Sub-Saharan  Africa:   Operates  only  in   the  Angola                                                                    
     deepwater  play, which  quickly emerged  as a  key oil-                                                                    
     producing country.  BP has collaborated  with operators                                                                    
     TOTAL  (Block  17)  and  Chevron  (Block  15).  In  the                                                                    
     future, development of BP-operated  blocks 31 and 18 is                                                                    
     expected to reverse the recent decline in production.                                                                      
2:23:51 PM                                                                                                                    
Co-Chair Hoffman  wondered if  slide 61  portrayed potential                                                                    
development, such  as the Beaufort and  Chukchi conventional                                                                    
shallow.  Mr.  Kepes replied  that  if  there was  a  viable                                                                    
potential project, it would be  included in the analysis. He                                                                    
furthered that if there was  a pure expiration play, without                                                                    
commercial field  development, it  would not be  included in                                                                    
the analysis. He added that  a project would not be included                                                                    
if there  was a heavy  oil or  viscous oil project  that was                                                                    
not considered commercial under existing commercial terms.                                                                      
Co-Chair  Stedman  requested  further detail  regarding  the                                                                    
Chuckchi  project.   Mr.  Kepes   agreed  to   provide  that                                                                    
information.  He  noted  the   potential  in  the  off-shore                                                                    
drilling, but felt that it would not be development for a                                                                       
few years down the line.                                                                                                        
Mr. Kepes discussed side 62, "Global Production: Country                                                                        
Growth Project Analysis":                                                                                                       
     Russia  is  a leading  source  of  mid-term new  source                                                                    
     volumes.  Production (from  TNK-BP) include  expansions                                                                    
     to  existing areas  such  as  Orenburg, and  greenfield                                                                    
     developments  such  as  the Uvat  and  Verkhnechonskoye                                                                    
     BP's participation  in Azerbaijan's  ACG Phases  1-4 is                                                                    
     among the  largest net  new source  projects in  the BP                                                                    
     Angola  deepwater provides  large share  of new  source                                                                    
     The Asia-Pacific Region  (Indonesia, Australia) and the                                                                    
     MENA  Region (Egypt,  Algeria, and  Oman)  are the  key                                                                    
     providers of new source gas in the medium term.                                                                            
     By 2015, the US represents  the largest area for BP, by                                                                    
     number  of  project.    The  US  holds  11  new  source                                                                    
     projects,  of  which 9  are  GOM  deepwater and  2  are                                                                    
     onshore Alaska.                                                                                                            
     BP's  new  source  Canadian   oil  sands  projects  are                                                                    
     expected on stream post-2015.                                                                                              
     BP's new  source portfolio is  driven by  (1) Deepwater                                                                    
     projects (Angola  and US GOM);  and (2)  Russia (mostly                                                                    
     onshore oil).                                                                                                              
     The Asia-Pacific remains a mostly gas-production area.                                                                     
     Unconventional  (Asia-Pacific  and North  America)  and                                                                    
     oil  sands  (Canada)  projects are  largely  immaterial                                                                    
     until 2020 or so.                                                                                                          
Co-Chair Stedman wondered if there was further information                                                                      
regarding BP's two onshore sights in Alaska. Mr. Kepes                                                                          
agreed to provide that information.                                                                                             
2:27:42 PM                                                                                                                    
Mr. Kepes touched on slide 63, "BP in Alaska." He stated                                                                        
that BP held North Start, Prudhoe Bay Gas, Liberty, and Pt.                                                                     
Thomson Gas fields in Alaska.                                                                                                   
Mr. Kepes stated that slide 64, "BP Alaska Activity and PFC                                                                     
Energy Assessment":                                                                                                             
     Most of  BP's assets  are located  on the  North Slope,                                                                    
     where  production   volumes  have   generally  declined                                                                    
     because of  the maturity of  the asset base  and/or gas                                                                    
     infrastructure   constraints.  Liquid   production  has                                                                    
     declined  from  approximately  224 mboe/d  in  2006  to                                                                    
     approximately 166 mboe/d in  2010, while gas production                                                                    
     has   fallen   from    approximately   67   mmcf/d   to                                                                    
     approximately 46 mmcf/d over the same period.                                                                              
     BP's  largest  source  of  production  is  the  Greater                                                                    
     Prudhoe  Area  (26  percent w.i.,  operated),  covering                                                                    
     approximately  150,000  acres   with  more  than  1,000                                                                    
     active  wells.   Gas resources  are currently  stranded                                                                    
     because of  the lack  of pipeline capacity  to southern                                                                    
     markets.    BP  and  ConocoPhillips had  teamed  up  to                                                                    
     propose  a new  natural  gas pipeline  (Denali) to  run                                                                    
     from Prudhoe Bay through western  Canada to US markets.                                                                    
     However,  in  May  2011, the  partners  announced  that                                                                    
     plans for the pipeline  had been terminated, citing the                                                                    
     lack  of long-term  purchase contracts.   The  proposed                                                                    
     pipeline  would have  accommodated 4  bcf/d of  natural                                                                    
     BP   and  partners   are   moving   forward  with   the                                                                    
     development of  gas liquids on the  approximately 8 tcf                                                                    
     Point  Thomson field  (32 percent  w.i., non-operator).                                                                    
     The  gas   cycling  project  is  expected   to  produce                                                                    
     approximately 10  mb/d of liquids; first  production is                                                                    
     targeted for  2014.  Full field  development awaits gas                                                                    
     transport infrastructure.                                                                                                  
     In  the Beaufort  Sea,  BP has  suspended  work on  the                                                                    
     extended-reach  drilling  program  on the  Liberty  oil                                                                    
     field (100  percent w.i.), pending revision  of project                                                                    
     design and schedule.                                                                                                       
     BP  is also  seeking to  develop viscous  (Kuparuk) and                                                                    
     heavy (Milne) oil resources on the North Slope.                                                                            
     PFC ENERGY ASSESMENT:                                                                                                      
     Current  production volumes  are modest  and declining,                                                                    
     yet  significant   potential  lies  in   the  long-term                                                                    
     commercialization of Prudhoe Bay  and Point Thomson gas                                                                    
     resources.   Cancellation  of the  Denali gas  pipeline                                                                    
     proposal  leaves  BP  as a  potential  supplier  to  an                                                                    
     alternative  pipeline-export  option,   should  one  be                                                                    
     approved and developed.                                                                                                    
Co-Chair Hoffman looked at slide 63, and wondered where the                                                                     
project was that was planned for the following summer.                                                                          
Mr. Kepes stated that there were many wells that were being                                                                     
drilled, but were not considered official projects.                                                                             
Co-Chair   Hoffman   queried   Shell's   offshore   drilling                                                                    
projects. Mr. Kepes replied that the wells were still                                                                           
expiration wells, but were still fairly speculative.                                                                            
Mr. Kepes looked at slide 65, "PFC-Identified Challenges":                                                                      
     1.  Re-establish its  operator  profile  in the  global                                                                    
     deepwater:   While   its   competitors   extend   their                                                                    
     commitments  to global  LNG,  unconventional shale  gas                                                                    
     exploitation,  and oil  sands development  in order  to                                                                    
     drive  future portfolio  growth,  BP  has deepened  its                                                                    
     commitment to  the global  deepwater play,  despite the                                                                    
     ongoing fallout  from the Macondo oil  spill. Expansion                                                                    
     of  its  US  GOM  lease  holdings  (through  the  Devon                                                                    
     portfolio   acquisition),   entry   into   the   Brazil                                                                    
     deepwater, and  a material commitment to  the K-G Basin                                                                    
     deepwater  play in  India, together  with phased  field                                                                    
     development  offshore Angola  and  West  Nile Delta  in                                                                    
     Egypt, positions  BP as arguably the  premier deepwater                                                                    
     player in  the Global  Player peer group.   BP  will be                                                                    
     under the  spotlight regarding  its future  conduct and                                                                    
    performance throughout the global deepwater basins.                                                                         
     2. Resolve  shareholder relationship issues  within the                                                                    
     TNK-BP JV:  Accounting for approximately 26  percent of                                                                    
     total worldwide  production in 2010  (and approximately                                                                    
     36  percent of  total  worldwide  oil production),  the                                                                    
     TNK-BP position is absolutely core  to the BP portfolio                                                                    
     from   a    volumetric   perspective.    However,   the                                                                    
     unsuccessful  attempt to  partner with  Rosneft in  the                                                                    
     Russia Arctic  raises concern over how  much value TNK-                                                                    
     BP  can continue  to  create for  BP.  With TNK-BP  now                                                                    
     focused on international expansion,  must BP settle for                                                                    
     lower returns  from what  has until  now been  a highly                                                                    
     lucrative position?                                                                                                        
     3. Complete the  portfolio rationalization process: The                                                                    
     strength  of  the   global  asset  transactions  market                                                                    
     prompted BP  to expand its divestiture  program from an                                                                    
     initial  $20 billion  to $30  billion, divesting  large                                                                    
     swaths  of its  portfolio deemed  non-Core and/or  non-                                                                    
     aligned  with the  company's growth  focus.   While the                                                                    
     company  did  not  plan  on   the  depth  of  portfolio                                                                    
     rationalization  undertaken to  date,  this  is a  rare                                                                    
     opportunity  to  high-grade  asset  holdings  with  the                                                                    
     blessing  of shareholders  and analysts  alike.   BP is                                                                    
     expecting to complete the divestiture process by end-                                                                      
     4. Determine  a path  forward in the  Brazil deepwater:                                                                    
     Having  secured Brazil  government approval  to acquire                                                                    
     the  Devon  asset  portfolio,   BP  has  established  a                                                                    
     foothold in the Brazil  deepwater, with potentially the                                                                    
     largest operated pre-salt  portfolio outside Petrobras.                                                                    
     The next step is  to determine the appropriate approach                                                                    
     to growth in  the pre-salt play.   With legislation now                                                                    
     in place  granting NOC Petrobras  a minimum  30 percent                                                                    
     w.i.  and  operatorship   in  all  unlicensed  pre-salt                                                                    
     acreage,  this  may  be another  case  of  executing  a                                                                    
     strategic  alliance  (similar   to  that  secured  with                                                                    
     Reliance  in India  and proposed  with  Rosneft in  the                                                                    
     Russia Arctic).                                                                                                            
     5. Accelerate development  of US Onshore unconventional                                                                    
     gas resource: BP received a  very competitive price for                                                                    
     the Permian  Basin and Western Canada  conventional gas                                                                    
     assets  sold  to   Apache  (totaling  approximately  75                                                                    
     mboe/d  of production  and approximately  340 mmboe  of                                                                    
     reserves,  equivalent  to approximately  $24.60/boe  of                                                                    
     reserves    in    the     ground    or    approximately                                                                    
     $109,000/flowing   boe   of    production).   This   is                                                                    
     particularly  so given  what  is shaping  up  to be  an                                                                    
     extended  period of  gas price  weakness  in the  North                                                                    
     America market.  To make  up for  lost volumes,  BP may                                                                    
     look  to accelerate  production from  its approximately                                                                    
     10  tcf  of  reserves in  the  Woodford,  Fayetteville,                                                                    
     Haynesville, and Eagle Ford shale gas plays.                                                                               
     6.  Accelerate development  of BP's  oil sands  leases:                                                                    
     BP has  built up a  material oil sands  lease portfolio                                                                    
     in  Western Canada,  including 50  percent w.i.  in the                                                                    
     Sunrise  in  situ  development project  (sanctioned  in                                                                    
     November  2010), a  75  percent w.i.  in  the Terre  de                                                                    
     Grace  in  situ project  (secured  in  March 2010  from                                                                    
     Value Creation for approximately  $900 million), and 50                                                                    
     percent  w.i. in  the Kirby  in situ  oil sands  leases                                                                    
     (with the other  50 percent divested to  Devon in March                                                                    
     2010).    Full  development  of  these  projects  could                                                                    
     represent  500-600  mbo/d   of  stable,  long-life  oil                                                                    
     production,  complementing   the  "Giant   Oil  Fields"                                                                    
     growth  platform  and   providing  a  portfolio  buffer                                                                    
     against   the   steep   decline   production   profiles                                                                    
     associated with deepwater developments.                                                                                    
2:33:53 PM                                                                                                                    
Mr. Kepes discussed slide 66, "ConocoPhillips: Company                                                                          
     Strategic Signature                                                                                                        
     Following  two years  of corporate  net income  losses,                                                                    
     steep decline  in its share  price, and  a persistently                                                                    
     high    debt-to-capital    ratio,   in    March    2010                                                                    
     ConocoPhillips  announced  a   new  strategic  pathway,                                                                    
     directing  proceeds from  an approximately  $15 billion                                                                    
     asset and  joint venture  divestment program  to reduce                                                                    
     its   debt-to-capital   position,  increase   near-term                                                                    
     shareholder   returns,  shift   further   out  of   the                                                                    
     downstream, and position the  company for future growth                                                                    
    from a smaller but higher-value portfolio position.                                                                         
     Since the  announcement of the  2010-2012 Restructuring                                                                    
     Plan, ConocoPhillips  has executed on  approximately $7                                                                    
     billion in asset sales, divested  its entire 20 percent                                                                    
     equity interest  in LUKOIL, and directed  proceeds from                                                                    
     these sales to debt  reduction and share repurchase. In                                                                    
     July 2011,  ConocoPhillips announced  the next  step in                                                                    
     its  restructuring:   the  creation  of   two  separate                                                                    
     corporate entities, Downstream and a pure play, E&P.                                                                       
     With   production   in   15  countries   and   upstream                                                                    
     operations    in    an    additional    7    countries,                                                                    
     ConocoPhillips'    most   recent    guidance   suggests                                                                    
     production reaching a low  of approximately 1.5 mmboe/d                                                                    
     in 2012,  recovering to 1.64-1.69 mmboe/d  by 2015. The                                                                    
     company  will rely  on  a  large, diversified  upstream                                                                    
     portfolio positioned heavily  in OECD countries (namely                                                                    
     the  US,  Canada,  Australia,  UK,  and  Norway,  which                                                                    
     accounted  for approximately  72  percent of  worldwide                                                                    
     production in 2010).                                                                                                       
     Growth of 0.5 percent per  annum from 2012 through 2015                                                                    
     is  forecast  to come  from  Global  Gas/LNG, SAGD  Oil                                                                    
     Sands,  and  Unconventional developments.  However,  as                                                                    
     ConocoPhillips   now  stands   to   compete  with   the                                                                    
     Independent,  non-integrated oil  & gas  companies, the                                                                    
     company's future strategy remains uncertain.                                                                               
Mr. Kepes  discussed slide 67, "ConocoPhilips:  Global Areas                                                                    
of  Upstream  Operations." He  felt  that  Alaska should  be                                                                    
considered  a "core  area" for  ConocoPhilips. He  explained                                                                    
that  ConocoPhillips  had  several   areas  of  activity  in                                                                    
Alaska:  expiration  activity  off-shore,  Cook  Inlet,  and                                                                    
North  Slope.  He  opined  that the  North  Slope  would  be                                                                    
considered a harvest area for ConocoPhilips.                                                                                    
Mr.  Kepes   looked  at  slide  68,   "ConocoPhilips  Global                                                                    
Production Portfolio - 2010":                                                                                                   
     Russia: LUKOIL  sale leaves ConocoPhillips  with modest                                                                    
     production  from  its  two  joint  ventures  in  Russia                                                                    
     (Polar Lights Company  and Naryanmarneftegaz). Regional                                                                    
     production  is forecast  to drop  from  21 percent  of'                                                                    
     worldwide production  in 2009 to a  projected 3 percent                                                                    
     in 2011.                                                                                                                   
     Canada:  Among the  largest  natural  gas producers  in                                                                    
     Canada.  Three  SAGD oil  sands  developments-Christina                                                                    
     Lake,  Foster Creek,  and Surmont-have  added long-life                                                                    
     production volumes to ConocoPhillips' portfolio.                                                                           
     US:   Largest   producing   country,  with   core   L48                                                                    
     production  where liquid-rich  areas (Eagle  Ford) will                                                                    
     be  prioritized  over  gas assets.    Declining  mature                                                                    
     assets  in  Alaska  could   be  offset  by  prospective                                                                    
     deepwater volumes in long-term.                                                                                            
     UK   and  Norway:   Region  characterized   by  mature,                                                                    
     declining assets; satellite  projects planned to offset                                                                    
     regional base declines.                                                                                                    
     China: Modest offshore production from Bohai Bay.                                                                          
     Qatar: Qatargas 3  (onstream in 2010) is  key driver to                                                                    
     regional gas growth.                                                                                                       
     Nigeria: Interests  in six  onshore assets,  serving as                                                                    
     feedstock to Nigeria LNG Trains 4-6.                                                                                       
     Australia: APLNG  Phase 1  sanctioned in  2011; longer-                                                                    
     term upside in Australia could  stem from assets in the                                                                    
     Browse Basin or Timor Sea (e.g. Greater Sunrise).                                                                          
     Vietnam:  Continued  development  of  mature  Cuu  Long                                                                    
     Basin; potential divestment target.                                                                                        
     Malaysia:   Development  of deepwater  fields (Gumusut-                                                                    
     Kakap   and  Kebabangan)   will  bring   Malaysia  into                                                                    
     ConocoPhillips' producing country portfolio.                                                                               
     Indonesia:   Largest    contributor   to   Asia-Pacific                                                                    
     production;  ongoing development  of  Corridor PSC  and                                                                    
     South Natuna Block B.                                                                                                      
     Libya:  Legacy onshore  Waha  concession; above  ground                                                                    
     conflict will delay new source oil projects.                                                                               
     Algeria:  Onshore  oil   field  production;  additional                                                                    
     volumes from El Merk (EMK) expected for 2012 start-up.                                                                     
2:37:57 PM                                                                                                                    
Mr. Kepes discussed slide 69, "Total Portfolio Evolution:                                                                       
ConocoPhilips vis-à-vis the Competition":                                                                                       
     ConocoPhillips' 2010-2012  Restructuring Plan  will see                                                                    
     the  company become  the  largest  of the  Independent,                                                                    
     non-integrated  international  oil   &  gas  companies,                                                                    
     compared to  its former position as  the third-smallest                                                                    
    of PFC Energy's expanded Global Player peer group.                                                                          
     2000-2010: Production  increases largely driven  by the                                                                    
     merger of Conoco  and Phillips in the  beginning of the                                                                    
     decade  (growing volumes  from  698 mboe/d  in 2000  to                                                                    
     1,082  mboe/d in  2002)  and  the Burlington  Resources                                                                    
     purchase in 2006 (growing volumes  from 1,824 mboe/d in                                                                    
     2005 to 2,358 mboe/d  in 2006). The gradual acquisition                                                                    
     of a  20 percent stake  in LUKOIL  was a key  driver to                                                                    
     mid-decade growth.                                                                                                         
     2011-2015: ConocoPhillips's  production is  expected to                                                                    
     decline from 2010-2015, due  to the company's intensive                                                                    
     asset  divestiture program  (the initial  approximately                                                                    
     $15  billion    asset   and  joint  venture  divestment                                                                    
     program  was  expanded   in  2011  when  ConocoPhillips                                                                    
     announced it  would shed an additional  $5 billion -$10                                                                    
     billion  in non-Core assets  by end-2012).  Volumes are                                                                    
     forecast to decline from  approximately 2,078 mboe/d in                                                                    
     2010 to approximately 1,674 mboe/d in 2015.                                                                                
Mr. Kepes looked at slide 70, "Reserves and Production:                                                                         
ConocoPhilips vis-à-vis the Competition":                                                                                       
     2000-2006:    Production  and reserves  grow  steadily,                                                                    
     largely a  result of acquisition:  from 271  mboe/d and                                                                    
     5,019 mmboe in  2000 to 682 mboe/d and  11,469 mmboe in                                                                    
     2006.   R/P  ratio  declines from  approximately 18  to                                                                    
     approximately 13 years.                                                                                                    
     2006-2010:   Both production and reserves  experience a                                                                    
     reversal   in  growth;   however  reserves   fall  more                                                                    
     steeply.    By  2010,  production was  776  mboe/d  and                                                                    
     reserves  decreased to  8,310 mmboe,  resulting in  the                                                                    
     lowest   R/P   ratio   recorded  in   the   decade   at                                                                    
     approximately  11   years.     In  2010,   declines  in                                                                    
     production  were primarily  due to  field decline,  the                                                                    
     impact   of  higher   prices   on  production   sharing                                                                    
     arrangements, and the sale of Syncrude.                                                                                    
Mr. Kepes discussed slide 73, "Global Production: Evolution                                                                     
of the Portfolio":                                                                                                              
     Asia  Pacific: Project  queue  14  projects deep  makes                                                                    
     Asia-Pacific  the largest  development pipeline  in all                                                                    
     of  ConocoPhillips'  portfolio.   Region  estimated  to                                                                    
     occupy 20 percent of 2011  upstream CAPEX. New projects                                                                    
     in  both  legacy  countries  (Indonesia,  Vietnam)  are                                                                    
     being  complimented by  startups in  Malaysia (Gumusut-                                                                    
     Kekap, Kebabangan) and Australia (APLNG).                                                                                  
     Europe:  Mature  and   generally  declining  production                                                                    
     position  in  the  UK and  Norway,  mostly  in  shallow                                                                    
     waters.  Satellite projects  poised to  somewhat offset                                                                    
     base declines.                                                                                                             
     Latin America: After  reaching historic peak production                                                                    
     in  2005,  volumes  fell to  zero  in  2009. The  Latin                                                                    
     America   portfolio,  largely   acquired  through   the                                                                    
     Burlington transaction, has never  been a material part                                                                    
     of  ConocoPhillips'  global  operations.  With  no  new                                                                    
     volumes anticipated  in the portfolio, a  complete exit                                                                    
     from the region could be likely.                                                                                           
     Middle East and North  Africa: Future growth is largely                                                                    
     tied to  the Qatargas 3  LNG project and El  Merk (EMK)                                                                    
     in Algeria.  Longer-term growth is poised  to stem from                                                                    
     Libya (as yet unsanctioned joint  NC 98 and North Gialo                                                                    
     developments)  assuming  a  timely  re-commencement  of                                                                    
     upstream activities.                                                                                                       
     North America: Largest production  region and cash flow                                                                    
     generator.    New   growth    initiatives   focus    on                                                                    
     exploitation of  Eagle Ford shale liquids  and Canadian                                                                    
     oil sands (Christina Lake,  Foster Creek, and Surmont),                                                                    
     which are projected to reverse  the decline in Canadian                                                                    
     production by  2014 and  deliver medium-  and long-term                                                                    
     volume growth.                                                                                                             
     Russia   and   Central   Asia:   LUKOIL   sale   leaves                                                                    
     ConocoPhillips  with only  modest  production from  its                                                                    
     two   joint  ventures   in   Russia   and  few   growth                                                                    
     opportunities within the  remaining portfolio. The sole                                                                    
     growth asset  is an 8.4  percent stake in  the Kashagan                                                                    
     field, which continues to face major challenges.                                                                           
     Sub-Saharan Africa:  Onshore assets serve  as feedstock                                                                    
     to Nigeria  LNG Trains 4-6. Longer-term  upside tied to                                                                    
     feedstock  for   the  yet-to-be-sanctioned   Brass  LNG                                                                    
     plant,  while  2011   re-positioning  in  Angola  could                                                                    
     provide exploration opportunities  critical to securing                                                                    
     new source ventures for long-term growth.                                                                                  
Mr. Kepes looked at slide 74, "Global Production: Country                                                                       
Growth Project Analysis":                                                                                                       
     ConocoPhillips's new source portfolio  is driven by (1)                                                                    
     Shallow  water  gas  production (Qatar);  (2)  Canadian                                                                    
     SAGD Oil Sands Developments;  and (3) US Unconventional                                                                    
     production (Eagle Ford).                                                                                                   
     Deepwater projects sourced mainly from the Asia-                                                                           
     Pacific  region (Malaysia)  and  the  US GOM  deepwater                                                                    
     (mostly non-operated positions),  will ramp up steadily                                                                    
     over  the  decade;  by  2020  deepwater  is  poised  to                                                                    
     represent  7 percent  of  global  volumes (compared  to                                                                    
     approximately 2 percent in 2010).                                                                                          
2:42:04 PM                                                                                                                    
Mr. Kepes looked at slide 79, "PFC-Identified Challenges":                                                                      
     Competing as a "Pure  Play" E&P Company: The separation                                                                    
     of  ConocoPhillips into  two, stand-alone  Upstream and                                                                    
     Downstream  entities is  scheduled to  be finalized  in                                                                    
     1H:  2012.  The  approximately   85  percent  of  total                                                                    
     portfolio  value residing  in E&P  assets will  thereby                                                                    
     become  the  largest  "pure play"  E&P  Independent,  a                                                                    
     competitor   landscape   position  the   company   held                                                                    
     uncomfortably   prior  to   the  Burlington   Resources                                                                    
     acquisition  in   2006.  Can   ConocoPhillips  Upstream                                                                    
     compete  successfully  in  the Independent's  space  by                                                                    
     delivering  either   leading  shareholder   returns  or                                                                    
     leading  production  growth?  Or   has  it  simply  re-                                                                    
     established its  original dilemma-too large  to compete                                                                    
     with the faster  moving International Independents, and                                                                    
     too small to  compete with the Global Players?   And if                                                                    
     so, does it survive?                                                                                                       
     Re-Establishing  a  Value Proposition:  ConocoPhillips'                                                                    
     new strategic  focus on  Sustained Value  Generation is                                                                    
     intended  to  re-establish  the  company's  competitive                                                                    
     advantage  in  the E&P  space.  In  the near-term,  the                                                                    
     2010-2013  Restructuring Plan  will  deliver a  smaller                                                                    
     company with limited  medium-term production growth and                                                                    
     improved,  but   unlikely  to  be  leading,   ROCE  and                                                                    
     financial performance. Clearly,  the cannibalization of                                                                    
     the  company's  assets  and recycling  of  proceeds  to                                                                    
     shareholders in  order to shore up  share valuation and                                                                    
     total  shareholder returns  is a  stop-gap strategy  at                                                                    
     best.  Given   continuing  financial   and  operational                                                                    
     challenges   (ROCE,  production   cost,  upstream   net                                                                    
     income, etc.),  ConocoPhillips may struggle  to deliver                                                                    
     a value  proposition that will compete  successfully in                                                                    
     either the Global  Player or International Independents                                                                    
     peer group.                                                                                                                
     Improving   Operational   Performance:  While   showing                                                                    
     improvement   in   finding   and   development   costs,                                                                    
     ConocoPhillips  ranks  at or  near  the  bottom of  the                                                                    
     expanded Global  Players peer group in  net income/boe,                                                                    
     production costs/boe,  and Upstream ROCE.   The current                                                                    
     portfolio high-grading  has already  delivered Upstream                                                                    
     ROCE improvement (from 7 percent  in 2009 to 10 percent                                                                    
     in 2010) and should  deliver improvement in operational                                                                    
     metrics;  both Syncrude  and the  LUKOIL holdings  were                                                                    
     arguably  underperforming  positions.  With  long  lead                                                                    
     time, large scale,  capital intensive developments like                                                                    
     Qatargas  3, Jasmine,  Kashagan  Phase  1, and  Surmont                                                                    
     poised to  deliver material  production and  cash flow,                                                                    
     ConocoPhillips should see  the flow-through benefits in                                                                    
     terms   of  more   competitive  ROCE   and  operational                                                                    
     Delivering  Production  Growth:  The  share  repurchase                                                                    
     program  accompanying  portfolio rationalization  under                                                                    
     the   Restructuring  Plan   is  projected   to  deliver                                                                    
     approximately 3 percent growth  in per share production                                                                    
     in  2010  and  2011.  However,  physical  volumes  will                                                                    
     decline in absolute terms  over the 2010-2011 period-by                                                                    
     approximately 208  mboe/d in 2010 from  2009 levels and                                                                    
     a further  approximately 360 mboe/d in  2011 from 2010.                                                                    
     The  only region  poised to  deliver higher  production                                                                    
     volumes  in 2020  versus 2010  is the  relatively minor                                                                    
     MENA  region,  projected  to  reach  approximately  177                                                                    
     mboe/d in  2020 versus 72  mboe/d in 2010.   New source                                                                    
     volumes in  Canada and the  North Sea will  struggle to                                                                    
     offset   mature   asset   declines,   delivering   flat                                                                    
     production  in  the  core   North  America  and  Europe                                                                    
     regions, while  the LUKOIL  sell-down will  dampen what                                                                    
     was once considered a core  driver of future growth for                                                                    
     the company.  While boasting a 10  billion boe resource                                                                    
     base, it  is not clear how  ConocoPhillips will deliver                                                                    
     the  promised surge  in organic  growth over  the 2015-                                                                    
     2020  period from  its captured  portfolio-although the                                                                    
     enhanced CAPEX spend  in the Eagle Ford play  is a good                                                                    
     starting   point.   Barring  a   material   acquisition                                                                    
     (certainly not  out of the question),  the company will                                                                    
     be looking  to its  exploration portfolio to  deliver a                                                                    
     medium term "engine of growth".                                                                                            
Mr. Kepes discussed slide 80, "ExxonMobil: Company                                                                              
     ExxonMobil  is the  largest  global integrated  company                                                                    
     (volumes averaged approximately  4,450 mboe/d in 2010),                                                                    
     with   production   in   21  countries   and   upstream                                                                    
     operations in an additional 20 countries.                                                                                  
     ExxonMobil has long adhered to  a growth strategy based                                                                    
     on  scale, basin  dominance, and  execution excellence,                                                                    
     which  has  required  the company  to  seek  continuous                                                                    
     access  to investment  opportunities  of adequate  size                                                                    
     and materiality.                                                                                                           
     In  2010, faced  with  the commissioning  of the  final                                                                    
     elements of the company's  Qatar project portfolio (the                                                                    
     final four approved LNG trains  at RasGas and Qatargas,                                                                    
     and Phase 2  of the Al Khaleej  gas project), declining                                                                    
     production  in  Europe  and Asia-Pacific,  and  already                                                                    
     holding  a  considerable  stake  in  the  Canadian  oil                                                                    
     sands,   ExxonMobil  took   an  aggressive   move  into                                                                    
     unconventional shale gas exploitation.                                                                                     
     The 2009  acquisition of XTO Energy  brings materiality                                                                    
     to ExxonMobil's technical expertise  in tight gas, CBM,                                                                    
     and shale oil and  gas exploitation, with approximately                                                                    
     2.3 bcf/d and 87  mboe/d of production, proved reserves                                                                    
     of approximately  2.3 billion boe, and  a resource base                                                                    
     of  7.5  billion  boe.     From  a  position  of  basin                                                                    
     dominance in  the US Onshore,  ExxonMobil will  seek to                                                                    
     build a  global unconventional portfolio; as  such, the                                                                    
     company  has   already  begun   purchasing  prospective                                                                    
     acreage in Argentina,  Germany, Poland, Indonesia, and,                                                                    
     most recently, China.                                                                                                      
     Largely  a   result  of  the   acquisition,  ExxonMobil                                                                    
     recorded a  13 percent  increase in production  in 2010                                                                    
     over 2009. The company will  seek growth of 4-5 percent                                                                    
     per annum over the 2009-2014 period.                                                                                       
Mr. Kepes looked  at slide 81, "ExxonMobil:  Global Areas of                                                                    
Upstream Operations." He explained  that PFC Energy analyzes                                                                    
each company's  portfolio to look  at the  growth prospects,                                                                    
decline  rates, amount  of re-investments,  and materiality.                                                                    
He remarked  that 50,000 barrels  per day to a  company that                                                                    
produces  4.4 million  barrels per  day  was much  different                                                                    
than  50,000  barrels  a  day to  a  company  that  produces                                                                    
200,000  barrels   per  day.   He  stressed   that  relative                                                                    
materiality must  be factored into  the analysis.  He stated                                                                    
that Qatar  was the  largest single country  contribution to                                                                    
the United States  as of 2011. In 2011,  ExxonMobil bought a                                                                    
large shale gas  company, XTO, which made  the United States                                                                    
the largest single country producer  again. He noted that it                                                                    
was remarkable for Qatar to  contribute so much, because the                                                                    
country was  so small. He  added that Alaska was  a "harvest                                                                    
area" for ExxonMobil.                                                                                                           
Mr. Kepes discussed slide 82, "ExxonMobil Global Production                                                                     
Portfolio - 2010":                                                                                                              
     UK and  Norway: Mature North Sea  assets have delivered                                                                    
     volume declines  of approximately  5 percent  per annum                                                                    
     in Europe over the last 5 years.                                                                                           
     Russia: Strong  performance track record at  Sakhalin I                                                                    
     and Arkutun-Dagi.  Rosneft Strategic  partnership could                                                                    
     be a dial-turner in Russia  (Arctic exploration & tight                                                                    
     oil resource exploitation).                                                                                                
     Kazakhstan:  Participation in  2 large-scale  projects:                                                                    
     Tengiz & Kashagan.                                                                                                         
     Canada:  Oil sands  volumes (Cold  Lake, Syncrude,  and                                                                    
     Kearl  projects)  will   dominate  out-year  production                                                                    
     Germany:  Legacy  gas   assets;  recent  unconventional                                                                    
     acreage acquisition.                                                                                                       
     US:  Largest  producing country;  regional  decade-long                                                                    
     decline  reversed with  purchase of  XTO. XTO  combined                                                                    
     with three additional  unconventional acquisitions will                                                                    
     make the Onshore L48 the cornerstone of future growth.                                                                     
     Qatar:  Represented approximately  20  percent of  2010                                                                    
     output.   Decade-long  double  digit  growth driven  by                                                                    
    final tranche of sanctioned LNG capacity in Qatar.                                                                          
     Nigeria:  Generally declining  shallow- and  deep-water                                                                    
     Australia:  Gas oriented  region, with  growth stemming                                                                    
     from  Gorgon LNG  project and  Gippsland Basin  shallow                                                                    
     water projects (Kipper and Turrum).                                                                                        
     Indonesia: Near-term  gas volumes will  hold production                                                                    
     steady as ExxonMobil positions for  new ventures in the                                                                    
     unconventional space (coal bed methane).                                                                                   
     Malaysia:  Key gas  producing area;  focus on  enhanced                                                                    
     oil recovery (EOR) and field life extension schemes.                                                                       
     Argentina:   legacy,  declining   gas  assets;   recent                                                                    
     acreage  positioning   in  prospective   shale  Neuquen                                                                    
     Angola:  Multi-field new  source developments  (Kizomba                                                                    
     Satellites Phase  1, Pazflor, and CLOV)  drive regional                                                                    
     Papua  New Guinea:  Formerly small  contributor to  the                                                                    
     ExxonMobil  portfolio,  PNG  will  rise  in  prominence                                                                    
     within the  portfolio through  the monetization  of gas                                                                    
     reserves at PLNG.                                                                                                          
2:47:13 PM                                                                                                                    
Mr. Kepes  looked at slide  83, "Total  Portfolio Evolution:                                                                    
ExxonMobil vis-à-vis  the Competition." He pointed  out that                                                                    
ExxonMobil was  not designed to "grow",  because there focus                                                                    
was  on the  financial  efficiency and  return. He  stressed                                                                    
that ExxonMobil  would not pursue an  investment opportunity                                                                    
for growth purposes.                                                                                                            
     Averaging   approximately   4.45   mmboe/d   in   2010,                                                                    
     ExxonMobil continues  to lead  its peer group  in terms                                                                    
     of production.                                                                                                             
     2000-2010:  For much  of  the  last decade,  production                                                                    
     oscillated,  rising  between  2000 and  2002  and  then                                                                    
     again  2005-2007; however,  by 2009  production volumes                                                                    
     were only  slightly above levels recorded  at the start                                                                    
     of  the decade,  averaging approximately  3.92 mmboe/d.                                                                    
     In  2010,  ExxonMobil   secured  production  growth  of                                                                    
     approximately  13  percent   (approximately  6  percent                                                                    
     excluding the XTO  acquisition), reaching approximately                                                                    
     4.45 mmboe/d.  For a  company that has prided itself on                                                                    
     organic  reserves   and  production  growth,   the  XTO                                                                    
     acquisition  marks a  considerable departure  in growth                                                                    
     strategy for ExxonMobil.                                                                                                   
     2011-2015: ExxonMobil's production  is forecast to grow                                                                    
     modestly   between  2010   and   2015,  reaching   only                                                                    
     approximately 4.54  mmboe/d in  2015. While  PFC Energy                                                                    
     estimates  are  lower   than  ExxonMobil  targets,  the                                                                    
     absence   of   guidance   regarding   growth   projects                                                                    
     associated  with the  XTO portfolio  make  the pace  of                                                                    
     future growth uncertain.                                                                                                   
Mr. Kepes discussed slide 84, "Reserves and Production:                                                                         
ExxonMobil vis-à-vis the Competition":                                                                                          
     ExxonMobil has recorded one of  the most consistent R/P                                                                    
     ratios of all  of the Global Majors.  A slight increase                                                                    
     over the  past decade  (from approximately 13  years in                                                                    
     2000 to  approximately 15 years  in 2010)  reflects the                                                                    
     increase of  reserves in the context  of generally flat                                                                    
     line production.                                                                                                           
2:50:08 PM                                                                                                                    
Mr. Kepes looked at slide 87, "Global Production: Evolution                                                                     
of the Portfolio":                                                                                                              
     Europe's  dwindling R/P  ratio  is largely  due to  the                                                                    
     maturity of the asset base.                                                                                                
     A focus  on exploitation  (as compared  to exploration)                                                                    
     in Africa  has resulted  in a  decline in  the region's                                                                    
     R/P ratio.                                                                                                                 
     Largely due  to the XTO acquisition,  both reserves and                                                                    
     production experienced  a large bump in  2010; in turn,                                                                    
     the US  R/P ratio grew  from approximately 17  years to                                                                    
     approximately 21 years.                                                                                                    
     In  2009,   ExxonMobil  began  reporting   Bitumen  and                                                                    
     Syncrude  as  distinct  reporting  regions,  which,  in                                                                    
     turn, resulted in a sharp  decrease in oil reserves and                                                                    
     production  reported  under  the  Canada/South  America                                                                    
     reporting region.                                                                                                          
Mr. Kepes discussed slide 88, "Global Production: Country                                                                       
Growth Project Analysis":                                                                                                       
     ExxonMobil's  US new  source portfolio  will dwarf  new                                                                    
     source  production from  all  other countries.  Through                                                                    
     2015,  the  US will  contribute  nearly  40 percent  of                                                                    
     global new  source incremental  volumes, 99  percent of                                                                    
     which  will  stem  from  the  company's  unconventional                                                                    
     activities  (acquisitions plus  the Piceance  tight gas                                                                    
     Production  from  Qatar  will   primarily  be  tied  to                                                                    
     development  of the  North Field  and the  Qatargas and                                                                    
     RasGas LNG projects,  while the rest of  the new source                                                                    
     landscape  reflects   ExxonMobil's  expansive  upstream                                                                    
     International  unconventional  developments are  likely                                                                    
     to be largely immaterial until 2020 or thereafter                                                                          
Mr. Kepes looked at slide 90, "ExxonMobil Alaska Activity                                                                       
and PFC Energy Assessment":                                                                                                     
     In Alaska,  ExxonMobil holds  interests in  the Greater                                                                    
     Prudhoe,  Greater Point  McIntyre, and  Greater Kuparuk                                                                    
     areas.  The  company is one of the  largest North Slope                                                                    
     producers,  although  production  from  the  region  is                                                                    
     declining;  2010 net  production averaged  117 mb/d  of                                                                    
     Development  activities continued  at Point  Thomson in                                                                    
     2010 (35 percent w.i.,  operated), and first production                                                                    
     of gas liquids is  anticipated in 2014. The longer-term                                                                    
     potential   lies  in   commercialization  of   the  gas                                                                    
     reserves,  which   is  dependent  on  building   a  gas                                                                    
     PFC ENERGY ASSESSMENT:                                                                                                     
     Material  harvest position.  As the  largest holder  of                                                                    
     discovered gas resources  on the North Slope  and a co-                                                                    
     operator   of   the    Prudhoe   Bay   Western   Region                                                                    
     development,  ExxonMobil holds  a  leading position  in                                                                    
2:54:56 PM                                                                                                                    
Mr. Kepes discussed slide 91, "PFC-Identified Challenges":                                                                      
     Deliver  on unconventional  resource positioning:   The                                                                    
     XTO  Energy   acquisition  and  subsequent   shale  gas                                                                    
     acreage transactions  have made  ExxonMobil a  force in                                                                    
     the North  America unconventional resource play.   That                                                                    
     said,  the company  has  provided  limited guidance  on                                                                    
     pace of  forward development despite  continued acreage                                                                    
     accumulation.    Furthermore,  given the  weak  US  gas                                                                    
     price   environment,   it   is  unclear   how   rapidly                                                                    
     ExxonMobil's  management   will  grow   sales  volumes.                                                                    
     ExxonMobil  is counting  on additional  long-term value                                                                    
     arising  from the  XTO transaction  through development                                                                    
     of   its    expanding   portfolio    of   International                                                                    
     unconventional resource holdings.                                                                                          
     Execute on  Asia-Pacific LNG Projects:   ExxonMobil has                                                                    
     a queue of LNG  developments in Asia-Pacific, including                                                                    
     Gorgon  LNG (operated  by Chevron),  PNG  LNG, and  the                                                                    
     potential  Scarborough gas  field  development, all  of                                                                    
     which  are   poised  to  generate   longer-term  volume                                                                    
     growth.  Each of  these projects comes with significant                                                                    
     technical  challenges-CO2   capture  and   disposal  at                                                                    
     Gorgon  LNG,  remote  gas field  development  and  long                                                                    
     distance  pipeline transport  in the  case of  PNG LNG,                                                                    
     and  the remote  offshore location  of the  Scarborough                                                                    
     field in the  Carnarvon Basin (which may  result in the                                                                    
     field being dedicated as feedstock  supply to the Pluto                                                                    
     or Wheatstone  LNG projects,  rather than  a greenfield                                                                    
     LNG  development).   Performance  will  be critical  to                                                                    
     ensuring long-term regional portfolio growth.                                                                              
     Maintain  leadership  in  share buy-back  and  dividend                                                                    
     performance:   ExxonMobil has been  a clear  peer group                                                                    
     leader   in  returns   to  shareholders,   distributing                                                                    
     approximately  $19.7  billion   through  dividends  and                                                                    
     share  buy-backs  in  2010 and  spending  approximately                                                                    
     $114  billion on  share repurchase  over the  2006-2010                                                                    
     period.   With the  increased emphasis being  placed on                                                                    
     unconventional gas  resources to deliver  future volume                                                                    
     growth, shareholders will be  looking for ExxonMobil to                                                                    
     continue  its  leading   dividend  and  share  buy-back                                                                    
     performance,  as  the   core  differentiator  from  its                                                                    
     faster  growing   (in  volumetric  terms)   peer  group                                                                    
     Replace   volume   growth   from  Qatar   North   Field                                                                    
     commercialization:   With  full  ramp-up  of the  final                                                                    
     four  liquefaction trains  at the  RasGas and  Qatargas                                                                    
     LNG   complexes,   and   continued  imposition   of   a                                                                    
     development moratorium for the  North Field resource by                                                                    
     the Qatar government, ExxonMobil  will be challenged to                                                                    
     deliver material global growth.                                                                                            
     -It is not clear  how aggressively ExxonMobil will look                                                                    
     to   develop   its   US  Onshore   unconventional   gas                                                                    
     resources, given  current and projected gas  pricing in                                                                    
     the North America market;                                                                                                  
     -Monetization  of captured  frontier  gas resources  in                                                                    
     North  America (Alaska  North  Slope, Mackenzie  Delta)                                                                    
     continues  to face  delays in  the  form of  regulatory                                                                    
     hurdles (recently removed for  the Mackenzie Valley gas                                                                    
     pipeline   project)   and  gas   market   supply-demand                                                                    
     -Development of  captured oil  reserves in  the Caspian                                                                    
     region  have experienced  significant  delays and  cost                                                                    
     over-runs,  and are  coming  under increased  political                                                                    
     risk through accelerating resource nationalism;                                                                            
     -ExxonMobil  was   successful  in  securing   a  growth                                                                    
     position   in    Iraq   through   the    West   Qurna-1                                                                    
     redevelopment  project,  but  will have  to  share  the                                                                    
     larger Iraqi resource  prize with a number  of IOCs and                                                                    
     NOCs.   It is  not clear  that Iraq  can become  a Core                                                                    
     growth area for the company.                                                                                               
SB 192 was HEARD and HELD in committee for further                                                                              
Co-Chair Stedman discussed the following day's agenda.                                                                          
2:57:35 PM                                                                                                                    
The meeting was adjourned at 2:57 PM.                                                                                           

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