Marketing and Midstream Revenues and Operating Costs and Expenses

The details of the changes in marketing and midstream revenues, operating costs and expenses and the resulting operating profit between 2005 and 2007 are shown in the table below.

  Year Ended December 31,
  2007   2007 vs
2006(1)		   2006   2006 vs
2005(1)		   2005  
Marketing and midstream ($ in millions):
   Revenues		 $ 1,736     +4 %   1,672     -7 %   1,792  
   Operating costs and expenses   1,227     -1 %   1,236     -8 %   1,342  
   Operating profit $ 509     +17 %   436     -3 %   450  

(1) All percentage changes included in this table are based on actual figures and not the rounded figures included in this table.

2007 vs. 2006 Marketing and midstream revenues increased $64 million, while operating costs and expenses decreased $9 million, causing operating profit to increase $73 million. Revenues increased primarily due to higher prices realized on NGL sales.

2006 vs. 2005 Marketing and midstream revenues decreased $120 million, and operating costs and expenses also decreased $106 million, causing operating profit to decrease $14 million. Both revenues and expenses in 2006 decreased primarily due to lower natural gas prices, partially offset by the effect of higher gas pipeline throughput.

Oil, Gas and NGL Production and Operating Expenses

The details of the changes in oil, gas and NGL production and operating expenses between 2005 and 2007 are shown in the table below.

  Year Ended December 31,
  2007   2007 vs
2006(1)		   2006   2006 vs
2005(1)		   2005  
Production and operating expenses ($ in millions):
   Lease operating expenses		 $ 1,828     +28 %   1,425     +15 %   1,244  
   Production taxes   340     —     341     +2 %   335  
   Total production and operating expenses $ 2,168     +23 %   1,766     +12 %   1,579  
Production and operating expenses per Boe:
   Lease operating expenses		 $ 8.16     +15 %   7.11     +18 %   6.03  
   Production taxes   1.52     -11 %   1.70     + 5 %   1.62  
   Total production and operating expenses per Boe $ 9.68     +10 %   8.81     +15 %   7.65  

(1) All percentage changes included in this table are based on actual figures and not the rounded figures included in this table.

Lease Operating Expenses ("LOE")

2007 vs. 2006 LOE increased $403 million in 2007. The largest contributor to this increase was our 12% growth in production, which caused an increase of $168 million. Another key contributor to the LOE increase was the continued effects of inflationary pressure driven by increased competition for field services. Increased demand for these services continue to drive costs higher for materials, equipment and personnel used in both recurring activities as well as well-workover projects. Furthermore, changes in the exchange rate between the U.S. and Canadian dollar also caused LOE to increase $40 million.

2006 vs. 2005 LOE increased $181 million in 2006 largely due to higher commodity prices. Commodity price increases in 2005 and the first half of 2006 contributed to industry-wide inflationary pressures on materials and personnel costs. Additionally, the availability of higher commodity prices contributed to our decision to perform more well workovers and maintenance projects to maintain or improve production volumes. Commodity price increases also caused operating costs such as ad valorem taxes, power and fuel costs to rise.

A higher Canadian-to-U.S. dollar exchange rate in 2006 caused LOE to increase $34 million. LOE also increased $33 million due to the June 2006 Chief acquisition and the payouts of our carried interests in Azerbaijan in the last half of 2006. The increases in our LOE were partially offset by a decrease of $82 million related to properties that were sold in 2005.

The factors described above were also the primary factors causing LOE per Boe to increase during 2006. Although we divested properties in 2005 that had higher per-unit operating costs, the cost escalation largely related to higher commodity prices and the weaker U.S. dollar had a greater effect on our per unit costs than the property divestitures.

Production Taxes

The following table details the changes in production taxes between 2005 and 2007. The majority of our production taxes are assessed on our onshore domestic properties. In the U.S., most of the production taxes are based on a fixed percentage of revenues. Therefore, the changes due to revenues in the table primarily relate to changes in oil, gas and NGL revenues from our U.S. onshore properties.

  (In millions)
2005 production taxes $ 335  
   Change due to revenues   (25 )
   Change due to rate   31  
2006 production taxes   341  
   Change due to revenues   65  
   Change due to rate   (66 )
2007 production taxes $ 340  

2007 vs. 2006 Production taxes decreased $66 million due to a decrease in the effective production tax rate in 2007. Our lower production tax rates in 2007 were primarily due to an increase in tax credits received on certain horizontal wells in the state of Texas and the increase in Azerbaijan revenues subsequent to the payouts of our carried interests in the last half of 2006. Our Azerbaijan revenues are not subject to production taxes. Therefore, the increased revenues generated in Azerbaijan in 2007 caused our overall rate of production taxes to decrease.

2006 vs. 2005 Production taxes increased $31 million due to an increase in the effective production tax rate in 2006. A new Chinese "Special Petroleum Gain" tax was the primary contributor to the higher rate.

Depreciation, Depletion and Amortization of Oil and Gas Properties ("DD&A")

DD&A of oil and gas properties is calculated by multiplying the percentage of total proved reserve volumes produced during the year, by the "depletable base." The depletable base represents our net capitalized investment plus future development costs related to proved undeveloped reserves. Generally, if reserve volumes are revised up or down, then the DD&A rate per unit of production will change inversely. However, if the depletable base changes, then the DD&A rate moves in the same direction. The per unit DD&A rate is not affected by production volumes. Absolute or total DD&A, as opposed to the rate per unit of production, generally moves in the same direction as production volumes. Oil and gas property DD&A is calculated separately on a country-by-country basis.

The changes in our production volumes, DD&A rate per unit and DD&A of oil and gas properties between 2005 and 2007 are shown in the table below.

  Year Ended December 31,
  2007   2007 vs
2006(1)		   2006   2006 vs
2005(1)		   2005  
Total production volumes (MMBoe)   224     +12 %   200     -3 %   206  
DD&A rate ($ per Boe) $ 11.85     +15 %   10.27     +20 %   8.56  
DD&A expense ($ in millions) $ 2,655     +29 %   2,058     +16 %   1,767  

(1) All percentage changes included in this table are based on actual figures and not the rounded figures included in this table.

The following table details the increases and decreases in DD&A of oil and gas properties between 2005 and 2007 due to the changes in production volumes and DD&A rate presented in the table above.

  (In millions)
2005 DD&A $ 1,767  
   Change due to volumes   (51 )
   Change due to rate   342  
2006 DD&A   2,058  
   Change due to volumes   242  
   Change due to rate   355  
2007 DD&A $ 2,655  

2007 vs. 2006 The 12% production increase caused oil and gas property related DD&A to increase $242 million. In addition, oil and gas property related DD&A increased $355 million due to a 15% increase in the DD&A rate. The largest contributor to the rate increase was inflationary pressure on both the costs incurred during 2007 as well as the estimated development costs to be spent in future periods on proved undeveloped reserves. Other factors contributing to the rate increase include the transfer of previously unproved costs to the depletable base as a result of 2007 drilling activities and a higher Canadian-to-U.S. dollar exchange rate in 2007. The effect of these increases was partially offset by a decrease resulting from higher reserve estimates due to the effects of higher 2007 year-end commodity prices.

2006 vs. 2005 The 3% production decrease caused oil and gas property related DD&A to decrease $51 million. However, oil and gas property related DD&A increased $342 million due to a 20% increase in the DD&A rate. The largest contributor to the rate increase was inflationary pressure on both the costs incurred during 2006 as well as the estimated development costs to be spent in future periods on proved undeveloped reserves. Other factors contributing to the rate increase included the June 2006 Chief acquisition and the transfer of previously unproved costs to the depletable base as a result of 2006 drilling activities. A reduction in reserve estimates due to the effects of lower 2006 year-end commodity prices also contributed to the rate increase.

General and Administrative Expenses ("G&A")

Our net G&A consists of three primary components. The largest of these components is the gross amount of expenses incurred for personnel costs, office expenses, professional fees and other G&A items. The gross amount of these expenses is partially reduced by two offsetting components. One is the amount of G&A capitalized pursuant to the full cost method of accounting related to exploration and development activities. The other is the amount of G&A reimbursed by working interest owners of properties for which we serve as the operator. These reimbursements are received during both the drilling and operational stages of a property's life. The gross amount of G&A incurred, less the amounts capitalized and reimbursed, is recorded as net G&A in the consolidated statements of operations. Net G&A includes expenses related to oil, gas and NGL exploration and production activities, as well as marketing and midstream activities. See the following table for a summary of G&A expenses by component.

  Year Ended December 31,
  2007   2007 vs
2006(1)		   2006   2006 vs
2005(1)		   2005  
  (In millions)
Gross G&A $ 947     +26 %   749     +34 %   560  
Capitalized G&A   (312 )   +28 %   (243 )   +54 %   (158 )
Reimbursed G&A   (122 )   +12 %   (109 )   -2 %   (111 )
   Net G&A $ 513     +29 %   397     +36 %   291  

(1) All percentage changes included in this table are based on actual figures and not the rounded figures included in this table.

2007 vs. 2006 Gross G&A increased $198 million. The largest contributors to this increase were higher employee compensation and benefits costs. These cost increases, which were related to our continued growth and industry inflation, caused gross G&A to increase $134 million. Of this increase, $55 million related to higher stock compensation. In addition, changes in the Canadian-to-U.S. dollar exchange rate caused a $13 million increase in costs.

2006 vs. 2005 Gross G&A increased $189 million. Higher employee compensation and benefits costs caused gross G&A to increase $148 million. Of this increase, $34 million represented stock option expense recognized pursuant to our adoption in 2006 of Statement of Financial Accounting Standard No. 123(R), Share-Based Payment. An additional $28 million of the increase related to higher restricted stock compensation. In addition, changes in the Canadian-to-U.S. dollar exchange rate caused an $11 million increase in costs.

The factors discussed above were also the primary factors that caused the $69 million and $85 million increases in capitalized G&A in 2007 and 2006, respectively.

Interest Expense

The following schedule includes the components of interest expense between 2005 and 2007.

  Year Ended December 31,
  2007   2006   2005  
  (In millions)
Interest based on debt outstanding $ 508     486     507  
Capitalized interest   (102 )   (79 )   (70 )
Other interest   24     14     96  
   Total interest expense $ 430     421     533  
"continued"