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Supplementary Oil & Gas Information for the Fiscal
Year Ended December 31, 2019 (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, 2019, 2018, 2017 and 2016 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, 2019, 2018, 2017 and 2016 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 2019 reserves for SEC requirements.
Crude Oil and NGLs      
 
Natural Gas
WTI Cushing Oklahoma
 

 
WCS

 
Canadian Light Sweet

 
Cromer LSB

 
North Sea Brent

 
Edmonton C5+

 
Henry Hub Louisiana

 
AECO

 
BC Westcoast Station 2

(US$/bbl)

 
(C$/bbl)

 
(C$/bbl)

 
(C$/bbl)

 
(US$/bbl)

 
(C$/bbl)


(US$/MMBtu)

 
(C$/MMBtu)

 
(C$/MMBtu)

55.73

 
57.29

 
66.77

 
66.85

 
62.54

 
68.71

 
2.54

 
2.02

 
1.13

A foreign exchange rate of US$1.00/C$1.3297 was used in the 2019 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 and review the Company's proved crude oil, bitumen, synthetic crude oil ("SCO"), natural gas, and natural gas liquids ("NGLs") reserves.
•
For the years ended December 31, 2019, 2018, 2017 and 2016, 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, 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, 2019, 2018, 2017 and 2016, the reports by Sproule Associates Limited and Sproule International Limited covered 100% of the Company’s crude oil, bitumen, natural gas and NGLs reserves.
Proved crude oil and natural gas reserves, as defined within the SEC's Regulation S-X, are the estimated quantities of oil and gas that by analysis of 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. Developed crude oil and natural gas reserves are reserves of any category 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. Undeveloped crude oil and natural gas reserves are reserves of any category that are expected to be recovered from new wells on undrilled acreage, or from existing wells where a relatively major expenditure is required for recompletion.
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.

Canadian Natural Resources Limited
1
Year Ended December 31, 2019

The following tables summarize the Company's proved and proved developed crude oil and natural gas reserves, net of royalties, as at December 31, 2019, 2018, 2017 and 2016:
 
 
North America
 
 
 
 
 
 
Crude Oil and NGLs (MMbbl)(1)
 
Synthetic
Crude Oil

 
Bitumen(2)

 
Crude
Oil & NGLs

 
North
America
Total

 
North
 Sea

 
Offshore
Africa

 
Total

Net Proved Reserves
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Reserves, December 31, 2016
 
2,542

 
1,301

 
504

 
4,347

 
93

 
74

 
4,514

Extensions and discoveries
 
—

 
28

 
17

 
45

 
—

 
—

 
45

Improved recovery
 
—

 
7

 
19

 
26

 
1

 
—

 
27

Purchases of reserves in place
 
2,232

 
37

 
67

 
2,336

 
—

 
—

 
2,336

Sales of reserves in place
 
—

 
—

 
—

 
—

 
—

 
—

 
—

Production
 
(100
)
 
(70
)
 
(44
)
 
(214
)
 
(9
)
 
(6
)
 
(229
)
Economic revisions due to prices
 
—

 
18

 
17

 
35

 
18

 
1

 
54

Revisions of prior estimates
 
282

 
44

 
14

 
340

 
4

 
—

 
344

Reserves, December 31, 2017
 
4,956

 
1,365

 
594

 
6,915

 
107

 
69

 
7,091

Extensions and discoveries
 
744

 
151

 
17

 
912

 
—

 
—

 
912

Improved recovery
 
—

 
10

 
50

 
60

 
1

 
3

 
64

Purchases of reserves in place
 
—

 
2

 
7

 
9

 
7

 
—

 
16

Sales of reserves in place
 
—

 
(4
)
 
—

 
(4
)
 
—

 
—

 
(4
)
Production
 
(148
)
 
(64
)
 
(47
)
 
(259
)
 
(9
)
 
(6
)
 
(274
)
Economic revisions due to prices
 
—

 
(45
)
 
(18
)
 
(63
)
 
11

 
1

 
(51
)
Revisions of prior estimates
 
109

 
54

 
1

 
164

 
(3
)
 
4

 
165

Reserves, December 31, 2018
 
5,661

 
1,469

 
604

 
7,734

 
114

 
71

 
7,919

Extensions and discoveries
 
334

 
18

 
12

 
364

 
—

 
—

 
364

Improved recovery
 
—

 
169

 
12

 
181

 
—

 
—

 
181

Purchases of reserves in place
 
—

 
666

 
2

 
668

 
—

 
—

 
668

Sales of reserves in place
 
—

 
—

 
—

 
—

 
—

 
—

 
—

Production
 
(137
)
 
(81
)
 
(49
)
 
(267
)
 
(10
)
 
(7
)
 
(285
)
Economic revisions due to prices(3)
(288
)
 
3

 
—

 
(285
)
 
(1
)
 
1

 
(285
)
Revisions of prior estimates
 
(17
)
 
(27
)
 
17

 
(28
)
 
3

 
6

 
(19
)
Reserves, December 31, 2019
 
5,554

 
2,216

 
598

 
8,368

 
105

 
70

 
8,544

Net proved developed reserves
 
 

 
 

 
 

 
 

 
 

 
 

 
 

December 31, 2016
 
2,527

 
384

 
353

 
3,264

 
12

 
31

 
3,307

December 31, 2017
 
4,967

 
410

 
399

 
5,776

 
28

 
21

 
5,825

December 31, 2018
 
5,661

 
461

 
378

 
6,500

 
37

 
34

 
6,571

December 31, 2019
 
5,452

 
661

 
354

 
6,466

 
38

 
39

 
6,543

(1)
Information in the reserves data tables may not add due to rounding.
(2)
Bitumen as defined by the SEC, "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.
(3)
Reflects the impact of increased royalties at Oil Sands Mining and Upgrading (SCO) due to higher Bitumen pricing resulting in higher royalties and lower net reserves.


Canadian Natural Resources Limited
2
Year Ended December 31, 2019

2019 total proved Crude Oil and NGLs reserves increased by 625 MMbbl:
•
Extensions and discoveries: Increase of 364 MMbbl primarily due to the transfer of reserves from the probable category at Oil Sands Mining and Upgrading (SCO) and extension drilling/future offset additions at various Bitumen, Crude Oil and natural gas (NGLs) properties.
•
Improved recovery: Increase of 181 MMbbl primarily due to increased steamflood recovery at the Primrose thermal oil (Bitumen) project.
•
Purchases of reserves in place: Increase of 668 MMbbl primarily due to Bitumen property acquisitions from Devon Canada.
•
Production: Decrease of 285 MMbbl.
•
Economic revisions due to prices: Decrease of 285 MMbbl primarily at Oil Sands Mining and Upgrading (SCO) due to higher Bitumen pricing resulting in higher royalties and lower net reserves.
•
Revisions of prior estimates: Decrease of 19 MMbbl primarily due to the 50-year reserves life cutoff at the Primrose thermal oil (Bitumen) project, increased royalties at Oil Sands Mining and Upgrading (SCO) as a result of lower operating costs, and the removal of future extension and infill undeveloped reserves in certain Crude Oil and Bitumen properties because of revised Company development plans, offset by improved performance at the Pelican Lake (Crude Oil) project and various natural gas (NGLs) properties.
2018 total proved Crude Oil and NGLs reserves increased by 828 MMbbl primarily due to the following:
•
Extensions and discoveries: Increase of 912 MMbbl primarily due to the addition of the Horizon South Pit to the Horizon oil sands mining and upgrading Project ("Horizon") (SCO), future thermal (Bitumen) well pad additions at Primrose and extension drilling/future offset additions at various primary heavy crude oil (Bitumen), Crude Oil and natural gas (NGLs) properties.
•
Improved recovery: Increase of 64 MMbbl primarily due to infill drilling/future offset additions at various primary heavy crude oil (Bitumen), thermal (Bitumen), Crude Oil and natural gas (NGLs) properties as well as thermal (Bitumen) improved recovery additions.
•
Purchases of reserves in place: Increase of 16 MMbbl primarily due to property acquisitions in North America and North Sea core areas.
•
Sales of reserves in place: Decrease of 4 MMbbl from the primary heavy crude oil (Bitumen) area.
•
Production: Decrease of 274 MMbbl.
•
Economic revisions due to prices: Decrease of 51 MMbbl primarily due to increased royalties at thermal (Bitumen) and Pelican Lake (Crude Oil) projects resulting from higher prices and uneconomic reserves at several North America natural gas (NGLs) core areas, partially offset by improved reserve life economics at the North Sea.
•
Revisions of prior estimates: Increase of 165 MMbbl primarily due to geological model changes and improved mine/extraction/upgrading performance at the oil sands mining and upgrading projects (SCO) and improved recoveries at Primrose (Bitumen).
2017 total proved Crude Oil and NGLs reserves increased by 2,577 MMbbl primarily due to the following:
•
Extensions and discoveries: Increase of 45 MMbbl primarily due to future thermal (Bitumen) well pad additions at Primrose and extension drilling/future offset additions at various primary heavy crude oil (Bitumen), Crude Oil and natural gas (NGLs) properties.
•
Improved recovery: Increase of 27 MMbbl primarily due to infill drilling/future offset additions at various primary heavy crude oil (Bitumen) and Crude Oil and natural gas (NGLs) properties.
•
Purchases of reserves in place: Increase of 2,336 MMbbl due to acquisitions of the Athabasca Oil Sands Project (SCO), Peace River thermal and Cliffdale primary heavy crude oil properties (Bitumen) and at Pelican Lake (Crude Oil).
•
Production: Decrease of 229 MMbbl.
•
Economic revisions due to prices: Increase of 54 MMbbl primarily due to improved reserves life economics at several North America Bitumen and Crude Oil core areas.
•
Revisions of prior estimates: Increase of 344 MMbbl primarily due to Horizon (SCO) revising the stratigraphic well density used to define proved reserves quantities and increasing the Horizon (SCO) total-volume-to-bitumen-in-place-ratio, partially offset by Horizon (SCO) adopting a low fines mine plan. Additionally, there were overall positive revisions at several North America Bitumen and Crude Oil core areas including improved recoveries at Primrose (Bitumen).

Canadian Natural Resources Limited
3
Year Ended December 31, 2019

Natural Gas (Bcf)(1)
 
North
 America

 
North
 Sea

 
Offshore
 Africa

 
Total

Net Proved Reserves
 
 
 
 
 
 
 
 
Reserves, December 31, 2016
 
4,594

 
25

 
25

 
4,644

Extensions and discoveries
 
261

 
—

 
—

 
261

Improved recovery
 
179

 
—

 
—

 
179

Purchases of reserves in place
 
106

 
—

 
—

 
106

Sales of reserves in place
 
—

 
—

 
—

 
—

Production
 
(558
)
 
(14
)
 
(7
)
 
(579
)
Economic revisions due to prices
 
403

 
5

 
(1
)
 
407

Revisions of prior estimates
 
214

 
9

 
(1
)
 
222

Reserves, December 31, 2017
 
5,199

 
25

 
16

 
5,240

Extensions and discoveries
 
90

 
—

 
—

 
90

Improved recovery
 
414

 
—

 
—

 
414

Purchases of reserves in place
 
67

 
—

 
—

 
67

Sales of reserves in place
 
(3
)
 
—

 
—

 
(3
)
Production
 
(523
)
 
(11
)
 
(8
)
 
(542
)
Economic revisions due to prices
 
(746
)
 
—

 
(2
)
 
(748
)
Revisions of prior estimates
 
(192
)
 
13

 
15

 
(164
)
Reserves, December 31, 2018
 
4,306

 
27

 
21

 
4,354

Extensions and discoveries
 
106

 
—

 
—

 
106

Improved recovery
 
202

 
—

 
—

 
202

Purchases of reserves in place
 
34

 
—

 
—

 
34

Sales of reserves in place
 
—

 
—

 
—

 
—

Production
 
(511
)
 
(9
)
 
(8
)
 
(528
)
Economic revisions due to prices
 
246

 
—

 
2

 
248

Revisions of prior estimates
 
346

 
(2
)
 
23

 
367

Reserves, December 31, 2019
 
4,728

 
16

 
38

 
4,782

Net proved developed reserves
 
 

 
 

 
 

 
 

December 31, 2016
 
2,805

 
18

 
18

 
2,841

December 31, 2017
 
3,081

 
22

 
9

 
3,112

December 31, 2018
 
2,382

 
23

 
12

 
2,417

December 31, 2019
 
2,342

 
11

 
28

 
2,381

(1)
Information in the reserves data tables may not add due to rounding.


Canadian Natural Resources Limited
4
Year Ended December 31, 2019

2019 total proved Natural Gas reserves increased by 428 Bcf primarily due to the following:
•
Extensions and discoveries: Increase of 106 Bcf primarily due to extension drilling/future offset additions in the Montney formation of northwest Alberta and northeast British Columbia.
•
Improved recovery: Increase of 202 Bcf primarily due to infill drilling/future offset additions in the Montney formation of northwest Alberta and northeast British Columbia.
•
Purchases of reserves in place: Increase of 34 Bcf primarily due to property acquisitions in several North America core areas.
•
Production: Decrease of 528 Bcf.
•
Economic revisions due to prices: Increase of 248 Bcf primarily due to increased Natural Gas price in North America.
•
Revisions of prior estimates: Increase of 367 Bcf primarily due to overall positive revisions in several North America and Offshore Africa core areas as a result of increased recovery and category transfers from probable to proved. The increase is also due to improved economics on undeveloped reserves which, when combined with lower long term royalty rates, results in increased net, after royalties, reserves.
2018 total proved Natural Gas reserves decreased by 886 Bcf primarily due to the following:
•
Extensions and discoveries: Increase of 90 Bcf primarily due to extension drilling/future offset additions in the Montney formation of northwest Alberta and northeast British Columbia.
•
Improved recovery: Increase of 414 Bcf primarily due to infill drilling/future offset additions in the Montney formation of northwest Alberta and northeast British Columbia.
•
Purchases of reserves in place: Increase of 67 Bcf primarily due to property acquisitions in several North America core areas.
•
Sales of reserves in place: Decrease of 3 Bcf.
•
Production: Decrease of 542 Bcf.
•
Economic revisions due to prices: Decrease of 748 Bcf due to uneconomic reserves at several North America Natural Gas core areas.
•
Revisions of prior estimates: Decrease of 164 Bcf primarily due to the removal of future extension and infill undeveloped reserves at several North America properties as a result of revised Company development plans.
2017 total proved Natural Gas reserves increased by 596 Bcf primarily due to the following:
•
Extensions and discoveries: Increase of 261 Bcf primarily due to extension drilling/future offset additions in the Montney and Spirit River formations of northwest Alberta and northeast British Columbia.
•
Improved recovery: Increase of 179 Bcf primarily due to infill drilling/future offset additions in the Montney and Spirit River formations of northwest Alberta and northeast British Columbia.
•
Purchases of reserves in place: Increase of 106 Bcf primarily due to property acquisitions in several North America core areas.
•
Production: Decrease of 579 Bcf.
•
Economic revisions due to prices: Increase of 407 Bcf due to improved reserves life economics at several North America Natural Gas core areas.
•
Revisions of prior estimates: Increase of 222 Bcf primarily due to overall positive revisions at several North America core areas triggered by production optimizations and reduced production costs.


Canadian Natural Resources Limited
5
Year Ended December 31, 2019

Capitalized Costs Related to Crude Oil and Natural Gas Activities
 
 
2019
(millions of Canadian dollars)
 
North
 America

 
North
 Sea

 
Offshore
 Africa

 
Total

Proved properties
 
$
117,643

 
$
7,296

 
$
3,933

 
$
128,872

Unproved properties
 
2,510

 
—

 
69

 
2,579

 
 
120,153

 
7,296

 
4,002

 
131,451

Less: accumulated depletion and depreciation
 
(52,824
)
 
(5,712
)
 
(2,712
)
 
(61,248
)
Net capitalized costs
 
$
67,329

 
$
1,584

 
$
1,290

 
$
70,203

 
 
 
2018
(millions of Canadian dollars)
 
North
 America

 
North
 Sea

 
Offshore
 Africa

 
Total

Proved properties
 
$
110,154

 
$
7,321

 
$
5,471

 
$
122,946

Unproved properties
 
2,600

 
—

 
37

 
2,637

 
 
112,754

 
7,321

 
5,508

 
125,583

Less: accumulated depletion and depreciation
 
(48,862
)
 
(5,735
)
 
(4,203
)
 
(58,800
)
Net capitalized costs
 
$
63,892

 
$
1,586

 
$
1,305

 
$
66,783

 
 
 
2017
(millions of Canadian dollars)
 
North
 America

 
North
 Sea

 
Offshore
 Africa

 
Total

Proved properties
 
$
106,900

 
$
7,126

 
$
4,881

 
$
118,907

Unproved properties
 
2,541

 
—

 
91

 
2,632

 
 
109,441

 
7,126

 
4,972

 
121,539

Less: accumulated depletion and depreciation
 
(44,779
)
 
(5,653
)
 
(3,719
)
 
(54,151
)
Net capitalized costs
 
$
64,662

 
$
1,473

 
$
1,253

 
$
67,388


Canadian Natural Resources Limited
6
Year Ended December 31, 2019

Costs Incurred in Crude Oil and Natural Gas Activities
 
 
2019
(millions of Canadian dollars)
 
North
 America

 
North
 Sea

 
Offshore
 Africa

 
Total

Property acquisitions
 
 
 
 
 
 
 
 
Proved
 
$
3,405

 
$
—

 
$
—

 
$
3,405

Unproved
 
91

 
—

 
—

 
91

Exploration
 
38

 
—

 
33

 
71

Development
 
4,687

 
349

 
233

 
5,269

Costs incurred
 
$
8,221

 
$
349

 
$
266

 
$
8,836

 
 
 
2018
(millions of Canadian dollars)
 
North
 America

 
North
 Sea

 
Offshore
 Africa

 
Total

Property acquisitions
 
 

 
 

 
 

 
 

Proved
 
$
214

 
$
127

 
$
—

 
$
341

Unproved
 
340

 
—

 
(89
)
 
251

Exploration
 
116

 
—

 
35

 
151

Development
 
3,245

 
110

 
212

 
3,567

Costs incurred
 
$
3,915

 
$
237

 
$
158

 
$
4,310

 
 
 
2017
(millions of Canadian dollars)
 
North
 America

 
North
 Sea

 
Offshore
 Africa

 
Total

Property acquisitions
 
 

 
 

 
 

 
 

Proved
 
$
15,091

 
$
—

 
$
—

 
$
15,091

Unproved
 
321

 
—

 
—

 
321

Exploration
 
112

 
—

 
15

 
127

Development
 
3,753

 
255

 
101

 
4,109

Costs incurred
 
$
19,277

 
$
255

 
$
116

 
$
19,648


Canadian Natural Resources Limited
7
Year Ended December 31, 2019

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, 2019, 2018 and 2017 are summarized in the following tables:
 
 
2019
(millions of Canadian dollars)
 
North
 America

 
North
 Sea

 
Offshore
 Africa

 
Total

Crude oil and natural gas revenue, net of royalties,
blending and feedstock costs
 
$
17,348

 
$
920

 
$
676

 
$
18,944

Production
 
(5,701
)
 
(391
)
 
(109
)
 
(6,201
)
Transportation
 
(968
)
 
(19
)
 
(2
)
 
(989
)
Depletion, depreciation and amortization
 
(4,982
)
 
(308
)
 
(242
)
 
(5,532
)
Asset retirement obligation accretion
 
(156
)
 
(28
)
 
(6
)
 
(190
)
Petroleum revenue tax
 
—

 
88

 
—

 
88

Income tax
 
(1,468
)
 
(105
)
 
(79
)
 
(1,652
)
Results of operations
 
$
4,073

 
$
157

 
$
238

 
$
4,468

 
 
 
2018
(millions of Canadian dollars)
 
North
 America

 
North
 Sea

 
Offshore
 Africa

 
Total

Crude oil and natural gas revenue, net of royalties,
blending and feedstock costs
 
$
16,065

 
$
891

 
$
647

 
$
17,603

Production
 
(5,772
)
 
(405
)
 
(208
)
 
(6,385
)
Transportation
 
(929
)
 
(22
)
 
(2
)
 
(953
)
Depletion, depreciation and amortization
 
(4,689
)
 
(257
)
 
(201
)
 
(5,147
)
Asset retirement obligation accretion
 
(148
)
 
(29
)
 
(9
)
 
(186
)
Petroleum revenue tax
 
—

 
12

 
—

 
12

Income tax
 
(1,223
)
 
(76
)
 
(51
)
 
(1,350
)
Results of operations
 
$
3,304

 
$
114

 
$
176

 
$
3,594

 
 
 
2017
(millions of Canadian dollars)
 
North
 America

 
North
 Sea

 
Offshore
 Africa

 
Total

Crude oil and natural gas revenue, net of royalties,
blending and feedstock costs
 
$
13,083

 
$
784

 
$
578

 
$
14,445

Production
 
(4,962
)
 
(400
)
 
(226
)
 
(5,588
)
Transportation
 
(790
)
 
(31
)
 
(1
)
 
(822
)
Depletion, depreciation and amortization
 
(4,463
)
 
(509
)
 
(205
)
 
(5,177
)
Asset retirement obligation accretion
 
(128
)
 
(27
)
 
(9
)
 
(164
)
Petroleum revenue tax
 
—

 
78

 
—

 
78

Income tax
 
(740
)
 
42

 
(28
)
 
(726
)
Results of operations
 
$
2,000

 
$
(63
)
 
$
109

 
$
2,046




Canadian Natural Resources Limited
8
Year Ended December 31, 2019

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":
 
 
2019
(millions of Canadian dollars)
 
North
 America

 
North
 Sea

 
Offshore
 Africa

 
Total

Future cash inflows
 
$
515,864

 
$
10,030

 
$
5,858

 
$
531,752

Future production costs
 
(194,076
)
 
(4,893
)
 
(2,081
)
 
(201,050
)
Future development costs and asset retirement obligations
 
(70,879
)
 
(2,648
)
 
(1,076
)
 
(74,603
)
Future income taxes
 
(53,759
)
 
(936
)
 
(547
)
 
(55,242
)
Future net cash flows
 
197,150

 
1,553

 
2,154

 
200,857

10% annual discount for timing of future cash flows
 
(136,616
)
 
(1
)
 
(715
)
 
(137,332
)
Standardized measure of future net cash flows
 
$
60,534

 
$
1,552

 
$
1,439

 
$
63,525

 
 
 
2018
(millions of Canadian dollars)
 
North
 America

 
North
 Sea

 
Offshore
 Africa

 
Total

Future cash inflows
 
$
500,557

 
$
12,002

 
$
6,447

 
$
519,006

Future production costs
 
(193,387
)
 
(5,148
)
 
(2,284
)
 
(200,819
)
Future development costs and asset retirement obligations
 
(63,202
)
 
(2,909
)
 
(1,099
)
 
(67,210
)
Future income taxes
 
(60,526
)
 
(1,484
)
 
(626
)
 
(62,636
)
Future net cash flows
 
183,442

 
2,461

 
2,438

 
188,341

10% annual discount for timing of future cash flows
 
(126,699
)
 
(545
)
 
(771
)
 
(128,015
)
Standardized measure of future net cash flows
 
$
56,743

 
$
1,916

 
$
1,667

 
$
60,326


Canadian Natural Resources Limited
9
Year Ended December 31, 2019

 
 
2017
(millions of Canadian dollars)
 
North
 America

 
North
 Sea

 
Offshore
 Africa

 
Total

Future cash inflows
 
$
413,180

 
$
8,740

 
$
4,786

 
$
426,706

Future production costs
 
(198,304
)
 
(4,168
)
 
(1,876
)
 
(204,348
)
Future development costs and asset retirement obligations
 
(61,169
)
 
(2,853
)
 
(1,258
)
 
(65,280
)
Future income taxes
 
(35,645
)
 
(595
)
 
(248
)
 
(36,488
)
Future net cash flows
 
118,062

 
1,124

 
1,404

 
120,590

10% annual discount for timing of future cash flows
 
(73,171
)
 
(59
)
 
(455
)
 
(73,685
)
Standardized measure of future net cash flows
 
$
44,891

 
$
1,065

 
$
949

 
$
46,905


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)
 
2019

 
2018

 
2017

Sales of crude oil and natural gas produced, net of production costs
 
$
(11,807
)
 
$
(10,229
)
 
$
(8,013
)
Net changes in sales prices and production costs
 
(3,515
)
 
20,386

 
7,466

Extensions, discoveries and improved recovery
 
5,883

 
2,807

 
481

Changes in estimated future development costs
 
(1,889
)
 
(698
)
 
(5,548
)
Purchases of proved reserves in place
 
7,418

 
396

 
25,782

Sales of proved reserves in place
 
—

 
(55
)
 
—

Revisions of previous reserve estimates
 
(3,384
)
 
2,711

 
4,245

Accretion of discount
 
8,062

 
6,119

 
3,075

Changes in production timing and other
 
447

 
(955
)
 
(662
)
Net change in income taxes
 
1,984

 
(7,061
)
 
(4,236
)
Net change
 
3,199

 
13,421

 
22,590

Balance - beginning of year
 
60,326

 
46,905

 
24,315

Balance - end of year
 
$
63,525

 
$
60,326

 
$
46,905


 
 






Canadian Natural Resources Limited
10
Year Ended December 31, 2019