EX-99.1 2 eh1200461_ex9901.htm EXHIBIT 1 SUPPLEMENTARY OIL & GAS INFORMATION eh1200461_ex9901.htm
EXHIBIT 1
 
Supplementary Oil & Gas Information for
the Fiscal Year Ended December 31, 2011

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, financial information is prepared in accordance with International Financial Reporting Standards (“IFRS”). In addition, comparative financial information for 2010 has been restated from generally accepted accounting principles in the United States to reflect the adoption of IFRS.
 
For the years ended December 31, 2011 and 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 the Securities and Exchange Commission (“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, using 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, 2011 and 2010, the Company used the 12-month average price, defined by the SEC as the unweighted arithmetic average of the first-day-of-the-month price for each month within the 12-month period prior to the end of the reporting period. The Company has used the following 12-month average benchmark prices to determine its 2011 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)
96.19
77.74
96.03
110.96
104.60 
4.12 
3.77 
3.33 

A foreign exchange rate of US$1.0158/C$1.00 was used in the 2011 evaluation, determined on the same basis as the 12-month average price.
 
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, 2011, 2010, 2009 and 2008, the reports by GLJ Petroleum Consultants Ltd. (“GLJ”) covered 100% of the Company’s synthetic crude oil reserves. With the inclusion of non-traditional resources within the definition of “oil and gas producing activities” in the SEC’s modernization of oil and gas reporting rules (“Final Rule”), effective January 1, 2010 these reserves volumes are included within the Company’s crude oil and natural gas reserves totals.
—
For the years ended December 31, 2011, 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.
 
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, from 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 if the extraction is 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.
 
 
 
 
 
 
 
 
 
2
 
 
 
The following table summarizes the Company’s proved and proved developed crude oil and natural gas reserves, net of royalties, as at December 31, 2011, 2010, 2009, and 2008:
 
   
North America
                    
Crude Oil and NGLs (MMbbl)
  
Synthetic
Crude
Oil(1)
    
Bitumen(2)
    
Crude
Oil &
NGLs
    
North
 America
Total
    
North
Sea
    
Offshore
Africa
    
Total
  
Net Proved Reserves
                                          
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  
Extensions and discoveries
     –       78       28       106       –       –       106  
Improved recovery
     –       10       8       18       –       2       20  
Purchases of reserves in place
     –       –       6       6       –       –       6  
Sales of reserves in place
     –       –       –       –       –       –       –  
Production
     (14 )     (60 )     (28 )     (102 )     (11 )     (8 )     (121 )
Economic revisions due to prices
     18       (32 )     1       (13 )     26       –       13  
Revisions of prior estimates
     169       (5 )     23       187       (28 )     (8 )     151  
Reserves, December 31, 2011
     1,836       869       366       3,071       244       88       3,403  
Net proved developed reserves
                                                        
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  
December 31, 2011
     1,588       269       269       2,126       78       61       2,265  
(1)
Prior to December 31, 2009, the Company’s Oil Sands Mining and Upgrading 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 SCO 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 to the SEC’s Final Rule, the following SCO table has been provided to illustrate the changes in the Company’s Oil Sands Mining and Upgrading SCO reserves for the 2009 year.
Oil Sands Mining and Upgrading 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

 
 
3
 
 
Natural Gas (Bcf)
  
North
America
    
North
Sea
    
Offshore
Africa
    
Total
  
Net Proved Reserves
                        
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  
Extensions and discoveries
     154       –       –       154  
Improved recovery
     48       –       –       48  
Purchases of reserves in place
     375       –       –       375  
Sales of reserves in place
     (1 )     –       –       (1 )
Production
     (433 )     (2 )     (6 )     (441 )
Economic revisions due to prices
     (104 )     3       –       (101 )
Revisions of prior estimates
     39       18       (16 )     41  
Reserves, December 31, 2011
     3,499       97       54       3,650  
Net proved developed reserves
                                
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  
December 31, 2011
     2,637       60       47       2,744  
 
 
 
4
 
 
CAPITALIZED COSTS RELATED TO CRUDE OIL AND NATURAL GAS ACTIVITIES

 
2011
(millions of Canadian dollars)
North
America
North
Sea
Offshore
Africa(1)
Total
Proved properties
$
61,331 
$
4,147 
$
3,044 
$
68,522 
Unproved properties
  
2,442 
 
– 
 
33 
 
2,475 
   
63,773 
 
4,147 
 
3,077 
 
70,997 
Less: accumulated depletion
  and depreciation
  
(22,497)
  
(2,512)
  
(2,152)
  
(27,161)
Net capitalized costs
$
41,276  
$
1,635  
$
925 
$
43,836 
 
 
2010(2)
(millions of Canadian dollars)
North
America
North
Sea
Offshore
Africa (1)
Total
Proved properties
$
55,030 
$
3,813 
$
2,928 
$
61,771 
Unproved properties
  
2,366 
 
5 
 
31 
 
2,402 
   
57,396 
 
3,818 
 
2,959 
  
64,173 
Less: accumulated depletion
  and depreciation
  
(19,502)
  
(2,205)
  
(1,904)
  
(23,611)
Net capitalized costs
$
37,894  
$
1,613 
$
1,055 
$
40,562 
(1)
As at December 31, 2011 and 2010, the Company’s Other segment has been included in Offshore Africa.
(2)
Comparative amounts for 2010 have been restated to reflect the adoption of IFRS.
 

COSTS INCURRED IN CRUDE OIL AND NATURAL GAS ACTIVITIES

 
2011
(millions of Canadian dollars)
North
America
North
Sea
Offshore
Africa(1)
Total
Property acquisitions
                
Proved
$
1,012
$
–
$
–
$
1,012
Unproved
  
59
  
–
  
–
  
59
Exploration
  
250
  
1
  
2
  
253
Development
  
5,559
  
235
  
76
  
5,870
Costs incurred
$
6,880
$
236
$
78
$
7,194
 
 
2010(2)
(millions of Canadian dollars)
North
America
North
Sea
Offshore
Africa(1)
Total
Property acquisitions
                
Proved
$
1,482
$
–
$
–
$
1,482
Unproved
  
522
  
–
  
–
  
522
Exploration
  
41
  
6
  
3
  
50
Development
  
3,332
  
190
  
254
  
3,776
Costs incurred
$
5,377
$
196
$
257
$
5,830
 (1)
As at December 31, 2011 and 2010, the Company’s Other segment has been included in Offshore Africa.
 (2)
Comparative amounts for 2010 have been restated to reflect the adoption of IFRS.
 
 
 
5
 
 
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, 2011 and 2010 are summarized in the following tables:
 
 
2011
(millions of Canadian dollars)
North
America
North
Sea
Offshore
Africa
Total
Crude oil and natural gas revenue, net of
  royalties and blending costs
$
9,600 
$
1,206 
$
828 
$
11,634 
Production
  
(3,060)
  
(412)
  
(186)
  
(3,658)
Transportation
  
(374)
  
(13)
  
(1)
  
(388)
Depletion, depreciation and amortization
  
(3,488)
  
(248)
  
(242)
  
(3,978)
Asset retirement obligation accretion
  
(90)
  
(33)
  
(7)
  
(130)
Petroleum revenue tax
  
–
  
(130)
  
–
  
(130)
Income tax
  
(688)
  
(218)
  
(89)
  
(995)
Results of operations
$
1,900 
$
152 
$
303 
$
2,355 
 
 
 
2010(2)
(millions of Canadian dollars)
North
America
North
Sea
Offshore
Africa
Total
Crude oil and natural gas revenue, net of
  royalties and blending costs
$
9,687 
$
1,059 
$
821 
$
11,567 
Production
  
(2,883)
  
(387)
  
(167)
  
(3,437)
Transportation
  
(365)
  
(8)
  
(1)
  
(374)
Depletion, depreciation and amortization(1)
  
(2,869))
  
(295)
  
(935)
  
(4,099)
Asset retirement obligation accretion
  
(80)
  
(36)
  
(7)
  
(123)
Petroleum revenue tax
  
– 
 
(59)
  
– 
 
(59)
Income tax
  
(980)
  
(137)
  
146 
 
(971)
Results of operations
$
2,510 
$
137 
$
(143)
$
2,504 
(1) Includes the impact of an impairment relating to Gabon, Offshore Africa at December 31, 2010 of $637 million.
(2) Comparative amounts for 2010 have been restated to reflect the adoption of IFRS.

 
 
6
 
 
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 12-month average price, defined by the SEC as the unweighted arithmetic average of the first-day-of-the-month price for each month within the 12-month period prior to the end of the reporting 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 prices and costs rather than 12-month average prices 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 and evaluation expenditures; and
·
Future development and asset retirement obligations will differ from those estimated.
 
Future net revenues, development, production and asset retirement obligation 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”:

 
2011
(millions of Canadian dollars)
North
America
North
Sea
Offshore
Africa
Total
Future cash inflows
$
280,809 
$
26,887 
$
8,257 
$
315,953 
Future production costs
  
(109,586)
  
(8,908)
  
(2,058)
  
(120,552)
Future development costs and asset retirement
  obligations
  
(37,486)
  
(6,821)
  
(1,669)
  
(45,976)
Future income taxes
  
(23,100)
  
(8,095)
  
(1,070)
  
(32,265)
Future net cash flows
  
110,637 
 
3,063 
 
3,460 
 
117,160 
10% annual discount for timing of future
   cash flows
  
(75,438)
  
(1,376)
  
(1,623)
  
(78,437)
Standardized measure of future net cash flows
$
35,199 
$
1,687 
$
1,837 
$
38,723 
         
 
 
2010
(millions of Canadian dollars)
North
America
North
Sea
Offshore
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 costs 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 
 
 
7
 
 
 
2009
(millions of Canadian dollars)
North
America
North
Sea
Offshore
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 costs 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 

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)
2011
2010
2009
Sales of crude oil and natural gas produced, net of production costs
$
(7,727)
$
(7,641)
$
(5,437)
Net changes in sales prices and production costs
  
15,802 
 
14,748 
 
16,808 
Extensions, discoveries and improved recovery
  
1,328 
 
1,636 
 
4,222 
Changes in estimated future development costs
  
(2,022)
  
(5,208)
  
(2,752)
Purchases of proved reserves in place
  
803 
 
1,894 
 
53 
Sales of proved reserves in place
  
– 
 
– 
 
(7)
Revisions of previous reserve estimates
  
4,154 
 
2,567 
 
220 
Accretion of discount
  
3,648 
 
2,757 
 
1,375 
SEC reliable technology
  
– 
 
– 
 
254 
SEC rule transition
  
– 
   
– 
 
7,332 
Changes in production timing and other
  
(1,141)
  
(895)
  
(2,788)
Net change in income taxes
  
(3,009)
  
(4,016)
  
(8,622)
Net change
  
11,836 
 
5,842 
 
10,658 
Balance – beginning of year
  
26,887 
 
21,045 
 
10,387 
Balance – end of year
$
38,723 
$
26,887 
$
21,045 

 
 
 
8