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