EX-99.1 2 eh1400468_ex9901.htm EXHIBIT 1 SUPPLEMENTARY OIL & GAS INFORMATION
EXHIBIT 1
Supplementary Oil & Gas Information for
the Fiscal Year Ended December 31, 2013
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”).
For the years ended December 31, 2013, 2012, 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.
There are significant differences to the type of volumes disclosed and the basis from which the volumes are economically determined under the United States Securities and Exchange Commission (“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, 2013, 2012, 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 2013 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)
96.94 | 74.22 | 92.73 | 108.22 | 105.65 | 3.68 | 3.16 | 3.08

A foreign exchange rate of US$1.00/C$1.0291 was used in the 2013 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, bitumen, synthetic crude oil (“SCO”), natural gas liquids (“NGLs”) and natural gas reserves.

● | For the years ended December 31, 2013, 2012, 2011, and 2010, the reports by GLJ Petroleum Consultants Ltd. covered 100% of the Company’s SCO 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, 2013, 2012, 2011, and 2010, the reports by Sproule Associates Limited and Sproule International Limited covered 100% of the Company’s bitumen, crude oil and NGLs, 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.

The following tables summarize the Company’s proved and proved developed crude oil and natural gas reserves, net of royalties, as at December 31, 2013, 2012, 2011, and 2010:

|  | North America |  |  |  |  |  |  |  |  |  |
Crude Oil and NGLs (MMbbl) |  | Synthetic Crude Oil |  |  | Bitumen(1) |  |  | Crude Oil & NGLs |  |  | North America Total |  |  | North Sea |  |  | Offshore Africa |  |  | Total |
Net Proved Reserves |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
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 |
Extensions and discoveries |  |  | – |  |  |  | 90 |  |  |  | 5 |  |  |  | 95 |  |  |  | – |  |  |  | – |  |  |  | 95 |
Improved recovery |  |  | – |  |  |  | 25 |  |  |  | 9 |  |  |  | 34 |  |  |  | – |  |  |  | 1 |  |  |  | 35 |
Purchases of reserves in place |  |  | – |  |  |  | – |  |  |  | 2 |  |  |  | 2 |  |  |  | – |  |  |  | – |  |  |  | 2 |
Sales of reserves in place |  |  | – |  |  |  | – |  |  |  | – |  |  |  | – |  |  |  | – |  |  |  | – |  |  |  | – |
Production |  |  | (30 | ) |  |  | (70 | ) |  |  | (31 | ) |  |  | (131 | ) |  |  | (7 | ) |  |  | (5 | ) |  |  | (143 | )
Economic revisions due to prices |  |  | 34 |  |  |  | 6 |  |  |  | (20 | ) |  |  | 20 |  |  |  | 4 |  |  |  | – |  |  |  | 24 |
Revisions of prior estimates |  |  | 134 |  |  |  | 79 |  |  |  | 39 |  |  |  | 252 |  |  |  | (6 | ) |  |  | 1 |  |  |  | 247 |
Reserves, December 31, 2012 |  |  | 1,974 |  |  |  | 999 |  |  |  | 370 |  |  |  | 3,343 |  |  |  | 235 |  |  |  | 85 |  |  |  | 3,663 |
Extensions and discoveries |  |  | – |  |  |  | 76 |  |  |  | 13 |  |  |  | 89 |  |  |  | – |  |  |  | – |  |  |  | 89 |
Improved recovery |  |  | – |  |  |  | 9 |  |  |  | 7 |  |  |  | 16 |  |  |  | – |  |  |  | – |  |  |  | 16 |
Purchases of reserves in place |  |  | – |  |  |  | – |  |  |  | 8 |  |  |  | 8 |  |  |  | 6 |  |  |  | – |  |  |  | 14 |
Sales of reserves in place |  |  | – |  |  |  | – |  |  |  | – |  |  |  | – |  |  |  | – |  |  |  | – |  |  |  | – |
Production |  |  | (35 | ) |  |  | (71 | ) |  |  | (33 | ) |  |  | (139 | ) |  |  | (7 | ) |  |  | (5 | ) |  |  | (151 | )
Economic revisions due to prices |  |  | (10 | ) |  |  | (1 | ) |  |  | 4 |  |  |  | (7 | ) |  |  | – |  |  |  | (2 | ) |  |  | (9 | )
Revisions of prior estimates |  |  | (4 | ) |  |  | 56 |  |  |  | 11 |  |  |  | 63 |  |  |  | (2 | ) |  |  | 2 |  |  |  | 63 |
Reserves, December 31, 2013 |  |  | 1,925 |  |  |  | 1,068 |  |  |  | 380 |  |  |  | 3,373 |  |  |  | 232 |  |  |  | 80 |  |  |  | 3,685 |
Net proved developed reserves |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
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 |
December 31, 2012 |  |  | 1,612 |  |  |  | 348 |  |  |  | 295 |  |  |  | 2,255 |  |  |  | 66 |  |  |  | 55 |  |  |  | 2,376 |
December 31, 2013 |  |  | 1,621 |  |  |  | 431 |  |  |  | 298 |  |  |  | 2,350 |  |  |  | 59 |  |  |  | 30 |  |  |  | 2,439 |

(1) | 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 crude oil reserves have been classified as bitumen.

Natural Gas (Bcf) |  | North America |  |  | North Sea |  |  | Offshore Africa |  |  | Total |
Net Proved Reserves |  |  |  |  |  |  |  |  |  |  |  |
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 |
Extensions and discoveries |  |  | 50 |  |  |  | – |  |  |  | – |  |  |  | 50 |
Improved recovery |  |  | 11 |  |  |  | – |  |  |  | – |  |  |  | 11 |
Purchases of reserves in place |  |  | 34 |  |  |  | – |  |  |  | – |  |  |  | 34 |
Sales of reserves in place |  |  | (1 | ) |  |  | – |  |  |  | – |  |  |  | (1 | )
Production |  |  | (429 | ) |  |  | (1 | ) |  |  | (6 | ) |  |  | (436 | )
Economic revisions due to prices |  |  | (596 | ) |  |  | 1 |  |  |  | – |  |  |  | (595 | )
Revisions of prior estimates |  |  | 79 |  |  |  | (14 | ) |  |  | – |  |  |  | 65 |
Reserves, December 31, 2012 |  |  | 2,647 |  |  |  | 83 |  |  |  | 48 |  |  |  | 2,778 |
Extensions and discoveries |  |  | 126 |  |  |  | – |  |  |  | – |  |  |  | 126 |
Improved recovery |  |  | 62 |  |  |  | – |  |  |  | – |  |  |  | 62 |
Purchases of reserves in place |  |  | 99 |  |  |  | 14 |  |  |  | – |  |  |  | 113 |
Sales of reserves in place |  |  | (1 | ) |  |  | – |  |  |  | – |  |  |  | (1 | )
Production |  |  | (394 | ) |  |  | (1 | ) |  |  | (8 | ) |  |  | (403 | )
Economic revisions due to prices |  |  | 489 |  |  |  | – |  |  |  | (2 | ) |  |  | 487 |
Revisions of prior estimates |  |  | 206 |  |  |  | (4 | ) |  |  | (1 | ) |  |  | 201 |
Reserves, December 31, 2013 |  |  | 3,234 |  |  |  | 92 |  |  |  | 37 |  |  |  | 3,363 |
Net proved developed reserves |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
December 31, 2010 |  |  | 2,557 |  |  |  | 49 |  |  |  | 72 |  |  |  | 2,678 |
December 31, 2011 |  |  | 2,637 |  |  |  | 60 |  |  |  | 47 |  |  |  | 2,744 |
December 31, 2012 |  |  | 2,060 |  |  |  | 58 |  |  |  | 39 |  |  |  | 2,157 |
December 31, 2013 |  |  | 2,342 |  |  |  | 72 |  |  |  | 27 |  |  |  | 2,441 |

CAPITALIZED COSTS RELATED TO CRUDE OIL AND NATURAL GAS ACTIVITIES

|  | 2013 |
(millions of Canadian dollars) |  | North America |  |  | North Sea |  |  | Offshore Africa |  |  | Total |
Proved properties |  | $ | 73,176 |  |  | $ | 5,200 |  |  | $ | 3,356 |  |  | $ | 81,732 |
Unproved properties |  |  | 2,570 |  |  |  | – |  |  |  | 39 |  |  |  | 2,609 |
|  |  | 75,746 |  |  |  | 5,200 |  |  |  | 3,395 |  |  |  | 84,341 |
Less: accumulated depletion and depreciation |  |  | (29,729 | ) |  |  | (3,467 | ) |  |  | (2,551 | ) |  |  | (35,747 | )
Net capitalized costs |  | $ | 46,017 |  |  | $ | 1,733 |  |  | $ | 844 |  |  | $ | 48,594 |

|  | 2012 |
(millions of Canadian dollars) |  | North America |  |  | North Sea |  |  | Offshore Africa |  |  | Total |
Proved properties |  | $ | 67,287 |  |  | $ | 4,574 |  |  | $ | 3,045 |  |  | $ | 74,906 |
Unproved properties |  |  | 2,564 |  |  |  | – |  |  |  | 47 |  |  |  | 2,611 |
|  |  | 69,851 |  |  |  | 4,574 |  |  |  | 3,092 |  |  |  | 77,517 |
Less: accumulated depletion and depreciation |  |  | (26,193 | ) |  |  | (2,709 | ) |  |  | (2,273 | ) |  |  | (31,175 | )
Net capitalized costs |  | $ | 43,658 |  |  | $ | 1,865 |  |  | $ | 819 |  |  | $ | 46,342 |

|  | 2011 |
(millions of Canadian dollars) |  | North America |  |  | North Sea |  |  | Offshore Africa |  |  | 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 |

COSTS INCURRED IN CRUDE OIL AND NATURAL GAS ACTIVITIES

|  | 2013 |
(millions of Canadian dollars) |  | North America |  |  | North Sea |  |  | Offshore Africa |  |  | Total |
Property acquisitions |  |  |  |  |  |  |  |  |  |  |  |
Proved |  | $ | 250 |  |  | $ | 2 |  |  | $ | – |  |  | $ | 252 |
Unproved |  |  | 92 |  |  |  | – |  |  |  | 4 |  |  |  | 96 |
Exploration |  |  | (2 | ) |  |  | – |  |  |  | 25 |  |  |  | 23 |
Development |  |  | 6,152 |  |  |  | 297 |  |  |  | 97 |  |  |  | 6,546 |
Costs incurred |  | $ | 6,492 |  |  | $ | 299 |  |  | $ | 126 |  |  | $ | 6,917 |

|  | 2012 |
(millions of Canadian dollars) |  | North America |  |  | North Sea |  |  | Offshore Africa |  |  | Total |
Property acquisitions |  |  |  |  |  |  |  |  |  |  |  |
Proved |  | $ | 144 |  |  | $ | – |  |  | $ | – |  |  | $ | 144 |
Unproved |  |  | 44 |  |  |  | – |  |  |  | 3 |  |  |  | 47 |
Exploration |  |  | 251 |  |  |  | – |  |  |  | 11 |  |  |  | 262 |
Development |  |  | 5,773 |  |  |  | 556 |  |  |  | 75 |  |  |  | 6,404 |
Costs incurred |  | $ | 6,212 |  |  | $ | 556 |  |  | $ | 89 |  |  | $ | 6,857 |

|  | 2011 |
(millions of Canadian dollars) |  | North America |  |  | North Sea |  |  | Offshore Africa |  |  | 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 |

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, 2013, 2012 and 2011 are summarized in the following tables:

|  | 2013 |
(millions of Canadian dollars) |  | North America |  |  | North Sea |  |  | Offshore Africa |  |  | Total |
Crude oil and natural gas revenue, net of royalties and blending costs |  | $ | 12,274 |  |  | $ | 726 |  |  | $ | 687 |  |  | $ | 13,687 |
Production |  |  | (3,918 | ) |  |  | (436 | ) |  |  | (191 | ) |  |  | (4,545 | )
Transportation |  |  | (483 | ) |  |  | (6 | ) |  |  | (1 | ) |  |  | (490 | )
Depletion, depreciation and amortization |  |  | (4,150 | ) |  |  | (552 | ) |  |  | (134 | ) |  |  | (4,836 | )
Asset retirement obligation accretion |  |  | (126 | ) |  |  | (35 | ) |  |  | (10 | ) |  |  | (171 | )
Petroleum revenue tax |  |  | – |  |  |  | 188 |  |  |  | – |  |  |  | 188 |
Income tax |  |  | (903 | ) |  |  | 71 |  |  |  | (88 | ) |  |  | (920 | )
Results of operations |  | $ | 2,694 |  |  | $ | (44 | ) |  | $ | 263 |  |  | $ | 2,913 |

|  | 2012 |
(millions of Canadian dollars) |  | North America |  |  | North Sea |  |  | Offshore Africa |  |  | Total |
Crude oil and natural gas revenue, net of royalties and blending costs |  | $ | 10,609 |  |  | $ | 837 |  |  | $ | 574 |  |  | $ | 12,020 |
Production |  |  | (3,669 | ) |  |  | (402 | ) |  |  | (163 | ) |  |  | (4,234 | )
Transportation |  |  | (479 | ) |  |  | (10 | ) |  |  | (1 | ) |  |  | (490 | )
Depletion, depreciation and amortization |  |  | (3,860 | ) |  |  | (296 | ) |  |  | (165 | ) |  |  | (4,321 | )
Asset retirement obligation accretion |  |  | (117 | ) |  |  | (27 | ) |  |  | (7 | ) |  |  | (151 | )
Petroleum revenue tax |  |  | – |  |  |  | (14 | ) |  |  | – |  |  |  | (14 | )
Income tax |  |  | (623 | ) |  |  | (55 | ) |  |  | (55 | ) |  |  | (733 | )
Results of operations |  | $ | 1,861 |  |  | $ | 33 |  |  | $ | 183 |  |  | $ | 2,077 |

|  | 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 |

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”:

|  | 2013 |
(millions of Canadian dollars) |  | North America |  |  | North Sea |  |  | Offshore Africa |  |  | Total |
Future cash inflows |  | $ | 290,892 |  |  | $ | 26,378 |  |  | $ | 9,146 |  |  | $ | 326,416 |
Future production costs |  |  | (116,984 | ) |  |  | (9,921 | ) |  |  | (2,560 | ) |  |  | (129,465 | )
Future development costs and asset retirement obligations |  |  | (51,749 | ) |  |  | (7,602 | ) |  |  | (1,840 | ) |  |  | (61,191 | )
Future income taxes |  |  | (20,384 | ) |  |  | (6,586 | ) |  |  | (1,154 | ) |  |  | (28,124 | )
Future net cash flows |  |  | 101,775 |  |  |  | 2,269 |  |  |  | 3,592 |  |  |  | 107,636 |
10% annual discount for timing of future cash flows |  |  | (65,063 | ) |  |  | (976 | ) |  |  | (1,755 | ) |  |  | (67,794 | )
Standardized measure of future net cash flows |  | $ | 36,712 |  |  | $ | 1,293 |  |  | $ | 1,837 |  |  | $ | 39,842 |

|  | 2012 |
(millions of Canadian dollars) |  | North America |  |  | North Sea |  |  | Offshore Africa |  |  | Total |
Future cash inflows |  | $ | 273,167 |  |  | $ | 26,922 |  |  | $ | 7,985 |  |  | $ | 308,074 |
Future production costs |  |  | (114,825 | ) |  |  | (9,369 | ) |  |  | (2,428 | ) |  |  | (126,622 | )
Future development costs and asset retirement obligations |  |  | (49,226 | ) |  |  | (7,032 | ) |  |  | (1,640 | ) |  |  | (57,898 | )
Future income taxes |  |  | (16,688 | ) |  |  | (7,662 | ) |  |  | (949 | ) |  |  | (25,299 | )
Future net cash flows |  |  | 92,428 |  |  |  | 2,859 |  |  |  | 2,968 |  |  |  | 98,255 |
10% annual discount for timing of future cash flows |  |  | (61,878 | ) |  |  | (1,330 | ) |  |  | (1,313 | ) |  |  | (64,521 | )
Standardized measure of future net cash flows |  | $ | 30,550 |  |  | $ | 1,529 |  |  | $ | 1,655 |  |  | $ | 33,734 |

|  | 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 |

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) |  | 2013 |  |  | 2012 |  |  | 2011 |
Sales of crude oil and natural gas produced, net of production costs |  | $ | (8,525 | ) |  | $ | (7,895 | ) |  | $ | (7,727 | )
Net changes in sales prices and production costs |  |  | 6,992 |  |  |  | (7,994 | ) |  |  | 15,802 |
Extensions, discoveries and improved recovery |  |  | 2,304 |  |  |  | 1,834 |  |  |  | 1,328 |
Changes in estimated future development costs |  |  | (1,536 | ) |  |  | (3,492 | ) |  |  | (2,022 | )
Purchases of proved reserves in place |  |  | 638 |  |  |  | 83 |  |  |  | 803 |
Sales of proved reserves in place |  |  | (1 | ) |  |  | (1 | ) |  |  | – |
Revisions of previous reserve estimates |  |  | 622 |  |  |  | 4,266 |  |  |  | 4,154 |
Accretion of discount |  |  | 4,388 |  |  |  | 5,110 |  |  |  | 3,648 |
Changes in production timing and other |  |  | 2,341 |  |  |  | 946 |  |  |  | (1,141 | )
Net change in income taxes |  |  | (1,115 | ) |  |  | 2,154 |  |  |  | (3,009 | )
Net change |  |  | 6,108 |  |  |  | (4,989 | ) |  |  | 11,836 |
Balance – beginning of year |  |  | 33,734 |  |  |  | 38,723 |  |  |  | 26,887 |
Balance – end of year |  | $ | 39,842 |  |  | $ | 33,734 |  |  | $ | 38,723 |