EX-99.1 2 eh1100179_ex9901.htm EXHIBIT 1 SUPPLEMENTARY OIL & GAS INFORMATION Unassociated Document
 
EXHIBIT 1

Supplementary Oil & Gas Information for
the Fiscal Year Ended December 31, 2010

SUPPLEMENTARY OIL & GAS INFORMATION (unaudited)
 
This supplementary crude oil and natural gas information is provided in accordance with the United States Financial Accounting Standards Board (“FASB”) Topic 932 – “Extractive Activities – Oil and Gas”, and where applicable is reconciled to the financial information prepared in accordance with generally accepted accounting principles in the United States (“US GAAP”).
 
For the year ended December 31, 2010, the Company filed its reserves information under National Instrument 51-101 – “Standards of Disclosure of Oil and Gas Activities” (”NI 51-101”), which prescribes the standards for the preparation and disclosure of reserves and related information for companies listed in Canada.  For years prior to 2010, the Company was granted an exemption from certain provisions of NI 51-101 allowing the Company to substitute SEC requirements under Regulations S-K and S-X for certain disclosures required under NI 51-101. Such exemption expired on December 31, 2010.
 
There are significant differences to the type of volumes disclosed and the basis from which the volumes are economically determined under the SEC requirements and NI 51-101.  The SEC requires disclosure of net reserves, after royalties, using 12-month average prices and current costs; whereas NI 51-101 requires gross reserves, before royalties, and future net revenue under forecast pricing and costs.  Therefore the difference between the reported numbers under the two disclosure standards can be material.
 
For the purposes of determining proved crude oil and natural gas reserves for SEC requirements as at December 31, 2010 and 2009, the Company used the 12-month average price, as defined by the SEC as the unweighted average price of the first day of the month within the 12-month period prior to the end of the reporting period. Prior to December 31, 2009 year end prices and costs were used in the reserves estimates. The Company has used the following 12-month average benchmark prices to determine its 2010 reserves for SEC requirements.
 
Crude Oil and NGLs
      
Natural Gas
  
WTI Cushing Oklahoma
WCS
Edmonton
Par
North Sea
Brent
Edmonton
C5+
Henry Hub
Louisiana
AECO
BC Westcoast
Station 2
(US$/bbl)
(C$/bbl)
(C$/bbl)
(US$/bbl)
(C$/bbl)
(US$/MMbtu)
(C$/MMbtu)
(C$/MMbtu)
79.43
67.40
77.98
79.02
84.43 
4.38 
4.06 
3.92 
 
A foreign exchange rate of US$0.967/C$1.00 was used in the 2010 evaluation.
 
NET PROVED CRUDE OIL AND NATURAL GAS RESERVES
 
The Company retains Independent Qualified Reserves Evaluators to evaluate the Company’s proved crude oil and natural gas reserves.
—
For the years ended December 31, 2010 and 2009, the reports by GLJ Petroleum Consultants Ltd. (“GLJ”) covered 100% of the Company’s synthetic crude oil reserves.  With the inclusion of the non-traditional resources within the definition of “oil and gas producing activities” within the SEC’s modernization of oil and gas reporting rules (“Final Rule”), effective January 1, 2010 these reserves volumes are now included within the Company’s crude oil and natural gas reserves totals.
—
For the years ended December 31, 2010, 2009, and 2008, the reports by Sproule Associates Limited and Sproule International Limited (together as “Sproule”) covered 100% of the Company’s bitumen, crude oil and natural gas liquids and natural gas reserves.
—
For the year ended December 31, 2007, the reports by Sproule and Ryder Scott Company covered 100% of the Company’s bitumen, crude oil and natural gas liquids and natural gas reserves.
 
Proved crude oil and natural gas reserves, as defined within the SEC’s Regulation S-X, under the Final Rule, are the estimated quantities of oil and gas that geoscience and engineering data demonstrate with reasonable certainty to be  economically producible, from a given date forward, under known reservoirs under existing economic conditions, operating methods and government regulations. Proved developed reserves are reserves that can be expected to be recovered from existing wells with existing equipment and operating methods or in which the cost of the required equipment is relatively minor compared to the cost of drilling a new well; and through installed extraction equipment and infrastructure operational at the time of the reserves estimate is the extraction by means not involving a well.
 
Estimates of crude oil and natural gas reserves are subject to uncertainty and will change as additional information regarding producing fields and technology becomes available and as future economic and operating conditions change.
 
 
 
 
 
 
 
The following table summarizes the Company’s proved and proved developed crude oil and natural gas reserves, net of royalties, as at December 31, 2010, 2009, 2008, and 2007:
 
 
North America
      
Crude Oil and NGLs (MMbbl)
Synthetic
Crude Oil(1)
Bitumen(2)
Crude Oil
 & NGLs
North
America
Total
North
Sea
Offshore
West Africa
Total
Net Proved Reserves
              
Reserves, December 31, 2007
      
920
310
128
1,358
Extensions and discoveries
      
51
–
–
51
Improved recovery
      
17
6
4
27
Purchases of reserves in place
      
–
–
–
–
Sales of reserves in place
      
–
–
–
–
Production
      
(76)
(17)
(8)
(101)
Economic revisions due to prices
      
28
(81)
8
(45)
Revisions of prior estimates
      
8
38
10
56
Reserves, December 31, 2008
–
690
258
948
256
142
1,346
Extensions and discoveries
–
24
6
30
–
–
30
Improved recovery
–
8
75
83
–
–
83
SEC reliable technology(3)
–
7
–
7
–
–
7
SEC rule transition(4)
1,650
–
–
1,650
–
–
1,650
Purchases of reserves in place
–
–
1
1
–
–
1
Sales of reserves in place
–
–
–
–
–
–
–
Production
–
(49)
(24)
(73)
(14)
(11)
(98)
Economic revisions due to prices
–
(64)
(8)
(72)
57
(4)
(19)
Revisions of prior estimates
–
79
11
90
(59)
(4)
27
Reserves, December 31, 2009
1,650
695
319
2,664
240
123
3,027
Extensions and discoveries
–
55
9
64
–
–
64
Improved recovery
–
22
6
28
–
–
28
Purchases of reserves in place
–
92
15
107
–
–
107
Sales of reserves in place
–
–
–
–
–
–
–
Production
(32)
(54)
(26)
(112)
(12)
(10)
(134)
Economic revisions due to prices
(41)
(25)
–
(66)
28
–
(38)
Revisions of prior estimates
86
93
5
184
1
(11)
174
Reserves, December 31, 2010
1,663
878
328
2,869
257
102
3,228
Net proved developed reserves
              
December 31, 2007
      
426
240
70
736
December 31, 2008
      
428
97
107
632
December 31, 2009
1,589
268
204
2,061
94
106
2,261
December 31, 2010
1,546
262
240
2,048
94
83
2,225

(1)
Prior to December 31, 2009, the Company’s Horizon SCO reserves were reported separately in accordance with the SEC’s Industry Guide 7.  With the SEC’s Final Rule in effect January 1, 2010, this synthetic crude oil is now included in the Company’s crude oil and natural gas reserves totals.
(2)
Bitumen as defined by the SEC, under the Final Rule, “is petroleum in a solid or semi-solid state in natural deposits with a viscosity greater than 10,000 centipoise measured at original temperature in the deposit and atmospheric pressure, on a gas free basis.”  Under this definition, all the Company’s thermal and primary heavy oil reserves have been classified as bitumen.  Prior to December 31, 2009, these reserves would have been classified within the Company’s conventional crude oil and NGL totals.
 
 
 
 
 
 
 
(3)
SEC reliable technology accounts for reserves volumes added due to the reserves rule changes.
(4)
For continuity purposes, with respect to the transition from Industry Guide 7 into the SEC’s Final Rule, the following SCO table has been provided to illustrate the changes in the Company’s Horizon SCO reserves for the 2009 year.

Horizon SCO Reserves
Net proved (MMbbl)
Reserves, December 31, 2008
1,946
Production
(18)
Economic revisions due to prices
(307)
Revisions of prior estimates
29
Reserves, December 31, 2009
1,650

Natural Gas (Bcf)
North
America
North
Sea
Offshore
West Africa
Total
Net Proved Reserves
        
Reserves, December 31, 2007
3,521
81
64
3,666
Extensions and discoveries
140
–
–
140
Improved recovery
52
(1)
6
57
Purchases of reserves in place
77
–
–
77
Sales of reserves in place
(1)
–
–
(1)
Production
(449)
(4)
(4)
(457)
Economic revisions due to prices
(19)
(56)
6
(69)
Revisions of prior estimates
202
47
22
271
Reserves, December 31, 2008
3,523
67
94
3,684
Extensions and discoveries
92
–
–
92
Improved recovery
11
–
–
11
Purchases of reserves in place
15
–
–
15
Sales of reserves in place
(6)
–
–
(6)
Production
(443)
(4)
(6)
(453)
Economic revisions due to prices
(335)
12
(4)
(327)
Revisions of prior estimates
170
(8)
1
163
Reserves, December 31, 2009
3,027
67
85
3,179
Extensions and discoveries
249
–
–
249
Improved recovery
19
–
–
19
Purchases of reserves in place
364
–
–
364
Sales of reserves in place
–
–
–
–
Production
(426)
(4)
(5)
(435)
Economic revisions due to prices
105
6
–
111
Revisions of prior estimates
83
9
(4)
88
Reserves, December 31, 2010
3,421
78
76
3,575
Net proved developed reserves
        
December 31, 2007
2,731
58
53
2,842
December 31, 2008
2,690
45
89
2,824
December 31, 2009
2,333
45
81
2,459
December 31, 2010
2,557
49
72
2,678
 
 
 
 
 

CAPITALIZED COSTS RELATED TO CRUDE OIL AND NATURAL GAS ACTIVITIES
 
 
2010
(millions of Canadian dollars)
North
America(1)
North
Sea
Offshore
West Africa
 
Other
Total
Proved properties
$
53,859
$
3,757
$
2,943
$
14
$
60,573
Unproved properties
  
3,284
  
–
  
–
  
31
  
3,315
   
57,143
  
3,757
  
2,943
  
45
  
63,888
Less: accumulated depletion and depreciation
  
(25,547)
  
(3,371)
  
(2,071)
  
(14)
  
(31,003)
Net capitalized costs
$
31,596
$
386
$
872
$
31
$
32,885
 
(1) 
As at December 31, 2010, the Company’s Oil Sands Mining and Upgrading segment has been included in North America capitalized costs in accordance with revisions to SEC oil and gas disclosures in Regulations S–K and S–X and FASB Topic 932 – “Extractive Activities – Oil and Gas”.
 
 
2009
(millions of Canadian dollars)
North
America (1)
North
Sea
Offshore
West Africa
 
Other
Total
Proved properties
$
49,052
$
3,875
$
2,195
$
14
$
55,136
Unproved properties
  
2,854
  
4
  
666
  
28
  
3,552
   
51,906
  
3,879
  
2,861
  
42
  
58,688
Less: accumulated depletion and depreciation
  
(24,216)
  
(3,260)
  
(1,170)
  
(14)
  
(28,660)
Net capitalized costs
$
27,690
$
619
$
1,691
$
28
$
30,028
 
(1) 
As at December 31, 2009, the Company’s Oil Sands Mining and Upgrading segment has been included in North America capitalized costs in accordance with revisions to SEC  oil and gas disclosures in Regulations S–K and S–X and FASB Topic 932 – “Extractive Activities – Oil and Gas”.
 
 
2008
(millions of Canadian dollars)
North
America
North
Sea
Offshore
West Africa
 
Other
Total
Proved properties
$
34,386
$
4,155
$
2,076
$
14
$
40,631
Unproved properties
  
2,271
  
12
  
595
  
26
  
2,904
   
36,657
  
4,167
  
2,671
  
40
  
43,535
Less: accumulated depletion and depreciation
  
(21,857)
  
(3,366)
  
(777)
  
(14)
  
(26,014)
Net capitalized costs
$
14,800
$
801
$
1,894
$
26
$
17,521
 

 
 
 
 
COSTS INCURRED IN CRUDE OIL AND NATURAL GAS ACTIVITIES
 
 
2010
(millions of Canadian dollars)
North
America(1)
North
Sea
Offshore
West Africa
 
Other
Total
Property acquisitions
                    
Proved
$
1,904
$
–
$
–
$
–
$
1,904
Unproved
  
141
  
–
  
–
  
–
  
141
Exploration
  
267
  
12
  
1
  
–
  
280
Development
  
2,926
  
96
  
235
  
3
  
3,260
Costs incurred
$
5,238
$
108
$
236
$
3
$
5,585
 
(1) 
As at December 31, 2010, the Company’s Oil Sands Mining and Upgrading segment has been included in North America costs incurred in crude oil and natural gas activities in accordance with revisions to SEC oil and gas disclosures in Regulations S–K and S–X and FASB Topic 932 – “Extractive Activities – Oil and Gas”.

 
2009
(millions of Canadian dollars)
North
America (1)
North
Sea
Offshore
West Africa
 
Other
Total
Property acquisitions
                    
Proved
$
6
$
–
$
–
$
–
$
6
Unproved
  
69
  
–
  
–
  
–
  
69
Exploration
  
173
  
36
  
1
  
–
  
210
Development
  
1,480
  
278
  
654
  
2
  
2,414
Costs incurred
$
1,728
$
314
$
655
$
2
$
2,699

(1)   Excludes additions related to the Company’s Oil Sands Mining and Upgrading Segment.
 

 
2008
(millions of Canadian dollars)
North
America
North
Sea
Offshore
West Africa
 
Other
Total
Property acquisitions
                    
Proved
$
299
$
(7)
$
44
$
–
$
336
Unproved
  
84
  
1
  
1
  
–
  
86
Exploration
  
144
  
3
  
–
  
1
  
148
Development
  
1,810
  
195
  
772
  
–
  
2,777
Costs incurred
$
2,337
$
192
$
817
$
1
$
3,347
 
 
 
 
 
 
RESULTS OF OPERATIONS FROM CRUDE OIL AND NATURAL GAS PRODUCING ACTIVITIES

The Company’s results of operations from crude oil and natural gas producing activities for the years ended December 31, 2010, 2009, and 2008 are summarized in the following tables:
 
 
2010
(millions of Canadian dollars)
North
America(1)
North
Sea
Offshore
West Africa
Total
Crude oil and natural gas revenue, net of royalties and blending costs
$
9,673
$
1,059
$
821
$
11,553
Production
  
(2,883)
  
(385)
  
(167)
  
(3,435)
Transportation
  
(365)
  
(8)
  
(1)
  
(374)
Depletion, depreciation and amortization (2)
  
(1,349)
  
(249)
  
(937)
  
(2,535)
Asset retirement obligation accretion
  
(68)
  
(33)
  
(6)
  
(107)
Petroleum revenue tax
  
–
  
(97)
  
–
  
(97)
Income tax
  
(1,407)
  
(144)
  
141
  
(1,410)
Results of operations
$
3,601
$
143
$
(149)
$
3,595
 
(1)
For the year ended December 31, 2010, the Company’s Oil Sands Mining and Upgrading segment has been included in North America results of operations from crude oil and natural gas producing activities in accordance with revisions to SEC oil and gas disclosures in Regulations S–K and S–X and FASB Topic 932 – “Extractive Activities – Oil and Gas”.
(2)
Includes the impact of a ceiling test impairment at December 31, 2010 of $684 million, pre-tax.

 
 
2009
(millions of Canadian dollars)
North
America
North
Sea
Offshore
West Africa
Total
Crude oil and natural gas revenue, net of royalties and blending costs
$
7,121
$
1,334
$
832
$
9,287
Production
  
(1,748)
  
(376)
  
(179)
  
(2,303)
Transportation
  
(284)
  
(8)
  
(1)
  
(293)
Depletion, depreciation and amortization (1)
  
(2,186)
  
(207)
  
(527)
  
(2,920)
Asset retirement obligation accretion
  
(41)
  
(24)
  
(4)
  
(69)
Petroleum revenue tax
  
–
  
(85)
  
–
  
(85)
Income tax
  
(833)
  
(317)
  
(30)
  
(1,180)
Results of operations
$
2,029
$
317
$
91
$
2,437

(1)   Includes the impact of ceiling test impairments at December 31, 2009 of $1,108 million, pre-tax.

   
 
2008
(millions of Canadian dollars)
North
America
North
Sea
Offshore
West Africa
Total
Crude oil and natural gas revenue, net of royalties and blending costs
$
8,126
$
1,731
$
801
$
10,658
Production
  
(1,881)
  
(457)
  
(102)
  
(2,440)
Transportation
  
(327)
  
(10)
  
(1)
  
(338)
Depletion, depreciation and amortization (1)
  
(9,661)
  
(1,564)
  
(132)
  
(11,357)
Asset retirement obligation accretion
  
(42)
  
(27)
  
(2)
  
(71)
Petroleum revenue tax
  
–
  
(143)
  
–
  
(143)
Income tax
  
1,128
  
235
  
(141)
  
1,222
Results of operations
$
(2,657)
$
(235)
$
423
$
(2,469)

(1)   Includes the impact of ceiling test impairments at December 31, 2008 of $8,665 million, pre-tax.

 
 
 
 
 

 
STANDARDIZED MEASURE OF DISCOUNTED FUTURE NET CASH FLOWS FROM PROVED CRUDE OIL AND NATURAL GAS RESERVES AND CHANGES THEREIN

The following standardized measure of discounted future net cash flows from proved crude oil and natural gas reserves has been computed using the average first-day-of-the-month price during the previous 12-month period, costs as at the balance sheet date and year-end statutory income tax rates. A discount factor of 10% has been applied in determining the standardized measure of discounted future net cash flows. The Company does not believe that the standardized measure of discounted future net cash flows will be representative of actual future net cash flows and should not be considered to represent the fair value of the crude oil and natural gas properties. Actual net cash flows will differ from the presented estimated future net cash flows due to several factors including:

—
Future production will include production not only from proved properties, but may also include production from probable and possible reserves;
—
Future production of crude oil and natural gas from proved properties will differ from reserves estimated;
—
Future production rates will vary from those estimated;
—
Future rather than average first-day-of-the-month prices during the previous 12-month period and costs as at the balance sheet date will apply;
—
Economic factors such as interest rates, income tax rates, regulatory and fiscal environments and operating conditions will change;
—
Future estimated income taxes do not take into account the effects of future exploration expenditures; and
—
Future development and asset retirement obligations will differ from those estimated.

Future net revenues, development, production and restoration costs have been based upon the estimates referred to above. The following tables summarize the Company’s future net cash flows relating to proved crude oil and natural gas reserves based on the standardized measure as prescribed in FASB Topic 932 – “Extractive Activities – Oil and Gas”:

 
2010
(millions of Canadian dollars)
North
America
North
Sea
Offshore
West Africa
Total
Future cash inflows
$
221,337
$
21,117
$
8,268
$
250,722
Future production costs
  
(96,899)
  
(8,596)
  
(1,884)
  
(107,379)
Future development and asset retirement obligations
  
(35,424)
  
(5,448)
  
(688)
  
(41,560)
Future income taxes
  
(17,249)
  
(5,572)
  
(1,760)
  
(24,581)
Future net cash flows
  
71,765
  
1,501
  
3,936
  
77,202
10% annual discount for timing of future cash flows
  
(47,687)
  
(722)
  
(1,906)
  
(50,315)
Standardized measure of future net cash flows
$
24,078
$
779
$
2,030
$
26,887
         
 
2009
(millions of Canadian dollars)
North
America
North
Sea
Offshore
West Africa
Total
Future cash inflows
$
176,866
$
16,304
$
8,305
$
201,475
Future production costs
  
(88,134)
  
(6,929)
  
(3,255)
  
(98,318)
Future development and asset retirement obligations
  
(22,767)
  
(5,271)
  
(975)
  
(29,013)
Future income taxes
  
(11,237)
  
(3,487)
  
(1,229)
  
(15,953)
Future net cash flows
  
54,728
  
617
  
2,846
  
58,191
10% annual discount for timing of future cash flows
  
(35,526)
  
(275)
  
(1,345)
  
(37,146)
Standardized measure of future net cash flows
$
19,202
$
342
$
1,501
$
21,045

 
 
 
 
 

 
 
2008
(millions of Canadian dollars)
North
America
North
Sea
Offshore
West Africa
Total
Future cash inflows
$
51,913
$
13,681
$
6,789
$
72,383
Future production costs
  
(23,747)
  
(6,845)
  
(3,000)
  
(33,592)
Future development and asset retirement obligations
  
(9,238)
  
(4,674)
  
(364)
  
(14,276)
Future income taxes
  
(3,097)
  
(2,011)
  
(1,061)
  
(6,169)
Future net cash flows
  
15,831
  
151
  
2,364
  
18,346
10% annual discount for timing of future cash flows
  
(6,872)
  
(76)
  
(1,011)
  
(7,959)
Standardized measure of future net cash flows
$
8,959
$
75
$
1,353
$
10,387

The principal sources of change in the standardized measure of discounted future net cash flows are summarized in the following table:

(millions of Canadian dollars)
2010
2009
2008
Sales of crude oil and natural gas produced, net of production costs
$
(7,641)
$
(5,437)
$
(9,679)
Net changes in sales prices and production costs
  
14,748
  
16,808
  
(14,680)
Extensions, discoveries and improved recovery
  
1,636
  
4,222
  
820
Changes in estimated future development costs
  
(5,208)
  
(2,752)
  
(715)
Purchases of proved reserves in place
  
1,894
  
53
  
113
Sales of proved reserves in place
  
–
  
(7)
  
(1)
Revisions of previous reserve estimates
  
2,567
  
220
  
112
Accretion of discount
  
2,757
  
1,375
  
3,468
SEC reliable technology
  
–
  
254
  
–
SEC rule transition
  
–
  
7,332
  
–
Changes in production timing and other
  
(895)
  
(2,788)
  
767
Net change in income taxes
  
(4,016)
  
(8,622)
  
8,462
Net change
  
5,842
  
10,658
  
(11,333)
Balance – beginning of year
  
21,045
  
10,387
  
21,720
Balance – end of year
$
26,887
$
21,045
$
10,387