| Supplementary Oil and Gas Information | 2 8 .
Supplementary Oil and Gas Information (unaudited) The unaudited supplementary information on oil and natural gas exploration and production activities for 2021, 2020 and 2019 has been presented in accordance with the FASB’s ASC Topic 932, “Extractive Activities - Oil and Gas” and the SEC’s final rule, “Modernization of Oil and Gas Reporting”. Disclosures by geographic area include the United States and Canada. Proved Oil and Natural Gas Reserves The following reserves disclosures reflect estimates of proved reserves, proved developed reserves, and proved undeveloped reserves, net of third-party royalty interests of oil, NGLs and natural gas owned at each year end and changes in proved reserves during each of the last three years. The Company’s estimates of proved reserves are made using available geological and reservoir data as well as production performance data. These estimates are reviewed annually by internal reservoir engineers and revised, either upward or downward, as warranted by additional data. The results of infill drilling are treated as positive revisions due to increases to expected recovery. Other revisions are due to changes in, among other things, development plans, reservoir performance, commodity prices, economic conditions, and government restrictions. Estimates of proved reserves are inherently imprecise and are continually subject to revision based on production history, results of additional exploration and development, price changes and other factors. The following reference prices were utilized in the determination of reserves and future net revenue:
Oil & NGLs
Natural Gas
WTI ($/bbl)
Edmonton Condensate (C$/bbl)
Henry Hub ($/MMBtu)
AECO (C$/MMBtu)
Reserves Pricing (1)
2021
$
66.56
$
83.69
$
3.60
$
3.26
2020
39.62
49.77
1.98
2.13
2019
55.93
68.80
2.58
1.76
(1)
All prices were held constant in all future years when estimating net revenues and reserves. PROVED RESERVES (1) (12-MONTH AVERAGE TRAILING PRICES)
Oil (MMbbls)
NGLs (MMbbls)
Natural Gas (Bcf)
Total (MMBOE)
United States
Canada
Total
United States
Canada
Total
United States
Canada
Total
2019
Beginning of year
351.5
0.2
351.8
122.3
158.5
280.8
598
2,901
3,499
1,215.7
Revisions and improved recovery (2)
(56.4
)
0.8
(55.6
)
3.1
(20.2
)
(17.1
)
(31
)
(484
)
(515
)
(158.7
)
Extensions and discoveries
230.2
0.4
230.6
96.0
62.4
158.4
521
777
1,298
605.3
Purchase of reserves in place
262.0
-
262.0
217.2
-
217.2
1,904
-
1,904
796.6
Sale of reserves in place
(5.1
)
-
(5.1
)
(0.5
)
-
(0.5
)
(351
)
-
(351
)
(64.1
)
Production
(59.8
)
(0.2
)
(60.0
)
(28.6
)
(21.6
)
(50.2
)
(200
)
(376
)
(576
)
(206.2
)
End of year
722.4
1.3
723.7
409.4
179.1
588.5
2,441
2,818
5,259
2,188.8
Developed
291.0
1.2
292.2
211.3
68.4
279.8
1,375
1,439
2,815
1,041.1
Undeveloped
431.4
0.1
431.5
198.1
110.7
308.8
1,066
1,378
2,444
1,147.7
Total
722.4
1.3
723.7
409.4
179.1
588.5
2,441
2,818
5,259
2,188.8
2020
Beginning of year
722.4
1.3
723.7
409.4
179.1
588.5
2,441
2,818
5,259
2,188.8
Revisions and improved recovery (2)
(221.5
)
(0.5
)
(222.0
)
(29.1
)
(33.1
)
(62.2
)
(323
)
(161
)
(484
)
(364.9
)
Extensions and discoveries
144.3
0.1
144.4
78.1
27.7
105.8
392
372
764
377.5
Purchase of reserves in place
9.9
1.0
10.9
8.4
11.6
20.0
47
94
140
54.3
Sale of reserves in place
(9.3
)
-
(9.3
)
(7.9
)
(13.4
)
(21.4
)
(95
)
(106
)
(201
)
(64.1
)
Production
(55.2
)
(0.2
)
(55.4
)
(29.8
)
(20.5
)
(50.3
)
(194
)
(366
)
(560
)
(199.0
)
End of year
590.5
1.7
592.3
429.1
151.4
580.5
2,268
2,650
4,918
1,992.5
Developed
279.1
1.7
280.9
242.3
76.9
319.3
1,327
1,740
3,067
1,111.3
Undeveloped
311.4
-
311.4
186.7
74.5
261.2
941
910
1,851
881.1
Total
590.5
1.7
592.3
429.1
151.4
580.5
2,268
2,650
4,918
1,992.5
2021
Beginning of year
590.5
1.7
592.3
429.1
151.4
580.5
2,268
2,650
4,918
1,992.5
Revisions and improved recovery (2)
(78.7
)
0.7
(78.0
)
(30.0
)
(20.3
)
(50.3
)
61
302
363
(67.8
)
Extensions and discoveries
121.2
0.3
121.5
75.1
66.9
142.0
428
1,538
1,966
591.2
Purchase of reserves in place
2.6
-
2.6
1.6
0.9
2.5
7
6
13
7.3
Sale of reserves in place
(27.0
)
(1.6
)
(28.6
)
(12.6
)
(8.4
)
(21.0
)
(50
)
(73
)
(123
)
(70.2
)
Production
(51.1
)
(0.1
)
(51.2
)
(28.5
)
(20.5
)
(49.0
)
(179
)
(389
)
(568
)
(194.9
)
End of year
557.5
1.1
558.6
434.7
170.0
604.7
2,536
4,033
6,570
2,258.2
Developed
291.0
0.7
291.7
264.3
84.5
348.8
1,621
2,490
4,111
1,325.7
Undeveloped
266.6
0.3
266.9
170.5
85.4
255.9
915
1,543
2,458
932.5
Total
557.5
1.1
558.6
434.7
170.0
604.7
2,536
4,033
6,570
2,258.2
(1)
Numbers may not add due to rounding.
(2)
Changes in reserve estimates resulting from application of improved recovery techniques are included in revisions of previous estimates. Definitions:
a.
“Proved” oil and gas reserves are those quantities of oil and gas which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible from a given date forward, from known reservoirs, and under existing economic conditions, operating methods and government regulations.
b.
“Developed” oil and gas reserves are reserves of any category that are expected to be recovered through 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 a new well.
c.
“Undeveloped” oil and 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.
Total Proved reserves increased 265.7
•
Revisions and improved recovery of oil, NGLs and natural gas were negative primarily due to changes in the approved development plan of 396.1 MMBOE, partially offset by positive performance revisions of 160.6 MMBOE, higher 12-month average trailing prices of 144.5 MMBOE and 23.2 MMBOE from infill drilling locations.
•
Extensions and discoveries of oil, NGLs and natural gas increased proved reserves by 591.2 MMBOE due to successful drilling and technical delineation, as well as new proved undeveloped locations resulting from updated development plans in the Montney, Permian and Anadarko assets
•
Purchases of 7.3 MMBOE were primarily in the Permian asset and a result of acreage trades
•
Sale of reserves in place decreased proved developed reserves by 70.2 MMBOE primarily due to the divestitures of the Eagle Ford assets located in south Texas and the Duvernay assets located in west central Alberta. Total Proved reserves decreased 196.3
•
Revisions and improved recovery of oil, NGLs and natural gas were negative primarily due to changes in the approved development plan of 382.2 MMBOE and lower 12-month average trailing prices of 167.1 MMBOE, partially offset by positive revisions from well performance and development strategy changes of 182.0 MMBOE and from infill drilling locations of 2.4 MMBOE.
•
Extensions and discoveries of oil, NGLs and natural gas increased proved reserves by 377.5 MMBOE due to successful drilling and technical delineation, as well as new proved undeveloped locations resulting from development plan changes in the Permian, Montney, Anadarko and Uinta assets.
•
Purchases of 54.3 MMBOE were primarily in the Permian asset and a result of the partition of certain Duvernay shale assets between Ovintiv and PCC.
•
Sale of reserves in place decreased proved developed reserves by 64.1 MMBOE primarily due to divestitures in the Anadarko and Permian assets, and the partition of certain Duvernay shale assets between Ovintiv and PCC. Total Proved reserves increased 973.1
•
Revisions and improved recovery of oil, NGLs and natural gas were negative primarily due to changes in the approved development plan of 97.5 MMBOE and lower 12-month average trailing oil and NGL prices of 118.4 MMBOE, partially offset by positive performance revisions of 57.3 MMBOE resulting from well performance and development strategy.
•
Extensions and discoveries of oil, NGLs and natural gas increased proved reserves by 605.3 MMBOE due to the extension of proved acreage primarily from successful drilling and delineation in the Permian, Anadarko, Montney, Eagle Ford, Bakken and Duvernay assets.
•
Purchases of 796.6 MMBOE were primarily in the acquisition of Newfield Exploration.
•
Sale of reserves in place decreased proved developed reserves by 64.1 MMBOE primarily due to the divestiture of the Arkoma asset located in Oklahoma. STANDARDIZED MEASURE OF DISCOUNTED FUTURE NET CASH FLOWS RELATING TO PROVED OIL AND GAS RESERVES In calculating the standardized measure of discounted future net cash flows, constant price and cost assumptions were applied to Ovintiv’s annual future production from proved reserves to determine cash inflows. Estimates of future net cash flows from proved reserves are computed based on the average beginning-of-the-month prices during the 12-month period for the year. Future production and development costs include estimates for abandonment and dismantlement costs associated with asset retirement obligations and assume the continuation of existing economic, operating and regulatory conditions. Future income taxes are calculated by applying statutory income tax rates to future pre-tax cash flows after provision for the tax cost of the oil and natural gas properties based upon existing laws and regulations. The effect of tax credits is also considered in determining the income tax expense. The discount was computed by application of a 10 percent discount factor to the future net cash flows. Ovintiv cautions that the discounted future net cash flows relating to proved oil and gas reserves are an indication of neither the fair market value of Ovintiv’s oil and gas properties, nor the future net cash flows expected to be generated from such properties. The discounted future net cash flows do not include the fair market value of exploratory properties and probable or possible oil and gas reserves, nor is consideration given to the effect of anticipated future changes in oil and natural gas prices, development, asset retirement and production costs, and possible changes to tax and royalty regulations. The prescribed discount rate of 10 percent may not appropriately reflect future interest rates.
United States
Canada
2021
2020
2019
2021
2020
2019
Future Cash Inflows
$
51,473
$
26,093
$
46,076
$
18,312
$
7,156
$
10,404
Less Future:
Production costs
12,272
8,864
13,064
7,679
4,202
4,791
Development costs
5,767
6,187
10,795
2,061
1,859
3,024
Income taxes
5,480
74
2,262
1,695
-
-
Future Net Cash Flows
27,954
10,968
19,955
6,877
1,095
2,589
Less 10% annual discount for estimated timing of cash flows
13,663
5,895
9,914
2,393
246
1,014
Discounted Future Net Cash Flows
$
14,291
$
5,073
$
10,041
$
4,484
$
849
$
1,575
Total
2021
2020
2019
Future Cash Inflows
$
69,785
$
33,249
$
56,480
Less Future:
Production costs
19,951
13,066
17,855
Development costs
7,828
8,046
13,819
Income taxes
7,175
74
2,262
Future Net Cash Flows
34,831
12,063
22,544
Less 10% annual discount for estimated timing of cash flows
16,056
6,141
10,928
Discounted Future Net Cash Flows
$
18,775
$
5,922
$
11,616
CHANGES IN STANDARDIZED MEASURE OF DISCOUNTED FUTURE NET CASH FLOWS RELATING TO PROVED OIL AND GAS RESERVES
United States
Canada
2021
2020
2019
2021
2020
2019
Balance, Beginning of Year
$
5,073
$
10,041
$
6,950
$
849
$
1,575
$
2,654
Changes Resulting From:
Sales of oil and gas produced during the year
(3,608
)
(1,605
)
(2,893
)
(1,479
)
(405
)
(654
)
Discoveries and extensions, net of related costs
3,102
1,080
2,893
2,119
140
544
Purchases of proved reserves in place
63
98
5,581
13
44
-
Sales and transfers of proved reserves in place
(199
)
(255
)
(931
)
(38
)
(97
)
-
Net change in prices and production costs
10,702
(7,119
)
(2,629
)
3,266
(1,563
)
(1,219
)
Revisions to quantity estimates
(407
)
(2,346
)
(850
)
201
(188
)
(550
)
Accretion of discount
508
1,064
749
85
158
297
Development costs incurred during the year
1,139
1,341
2,115
397
535
545
Changes in estimated future development costs
(83
)
2,183
(885
)
41
652
(364
)
Other
1
-
-
-
(2
)
1
Net change in income taxes
(2,000
)
591
(59
)
(970
)
-
321
Balance, End of Year
$
14,291
$
5,073
$
10,041
$
4,484
$
849
$
1,575
Total
2021
2020
2019
Balance, Beginning of Year
$
5,922
$
11,616
$
9,604
Changes Resulting From:
Sales of oil and gas produced during the year
(5,087
)
(2,010
)
(3,547
)
Discoveries and extensions, net of related costs
5,221
1,220
3,437
Purchases of proved reserves in place
76
142
5,581
Sales and transfers of proved reserves in place
(237
)
(352
)
(931
)
Net change in prices and production costs
13,968
(8,682
)
(3,848
)
Revisions to quantity estimates
(206
)
(2,534
)
(1,400
)
Accretion of discount
593
1,222
1,046
Development costs incurred during the year
1,536
1,876
2,660
Changes in estimated future development costs
(42
)
2,835
(1,249
)
Other
1
(2
)
1
Net change in income taxes
(2,970
)
591
262
Balance, End of Year
$
18,775
$
5,922
$
11,616
RESULTS OF OPERATIONS The following table sets forth revenue and direct cost information relating to the Company’s oil and gas exploration and production activities.
United States
Canada
2021
2020
2019
2021
2020
2019
Oil, NGL and Natural Gas Revenues (1)
$
4,883
$
2,701
$
4,163
$
2,542
$
1,349
$
1,654
Less:
Production, mineral and other taxes
278
158
238
15
15
16
Transportation and processing
507
453
466
937
829
859
Operating
490
485
566
111
100
125
Depreciation, depletion and amortization
837
1,378
1,593
332
427
383
Impairments
-
5,580
-
-
-
-
Accretion of asset retirement obligation
11
13
15
11
16
21
Operating Income (Loss)
2,760
(5,366
)
1,285
1,136
(38
)
250
Income Taxes
673
(1,309
)
313
272
(9
)
60
Results of Operations
$
2,087
$
(4,057
)
$
972
$
864
$
(29
)
$
190
China (2)
Total
2021
2020
2019
2021
2020
2019
Oil, NGL and Natural Gas Revenues (1)
$
-
$
-
$
37
$
7,425
$
4,050
$
5,854
Less:
Production, mineral and other taxes
-
-
-
293
173
254
Transportation and processing
-
-
-
1,444
1,282
1,325
Operating
-
-
16
601
585
707
Depreciation, depletion and amortization
-
-
-
1,169
1,805
1,976
Impairments
-
-
-
-
5,580
-
Accretion of asset retirement obligation
-
-
1
22
29
37
Operating Income (Loss)
-
-
20
3,896
(5,404
)
1,555
Income Taxes
-
-
4
945
(1,318
)
377
Results of Operations
$
-
$
-
$
16
$
2,951
$
(4,086
)
$
1,178
(1)
Excludes gains (losses) on risk management.
(2 )
Effective July 31, 2019, the production sharing contract with CNOOC was terminated and the Company exited its China Operations. CAPITALIZED COSTS Capitalized costs include the cost of properties, equipment and facilities for oil and natural gas producing activities. Capitalized costs for proved properties include costs for oil and natural gas leaseholds where proved reserves have been identified, development wells and related equipment and facilities, including development wells in progress. Capitalized costs for unproved properties include costs for acquiring oil and natural gas leaseholds where no proved reserves have been identified.
United States
Canada
2021
2020
2019
2021
2020
2019
Proved Oil and Gas Properties
$
39,145
$
37,875
$
35,870
$
16,330
$
16,008
$
15,284
Unproved Oil and Gas Properties
1,884
2,785
3,491
60
177
223
Total Capital Cost
41,029
40,660
39,361
16,390
16,185
15,507
Accumulated DD&A
33,418
32,581
25,623
15,450
15,056
14,320
Net Capitalized Costs
$
7,611
$
8,079
$
13,738
$
940
$
1,129
$
1,187
Other
Total
2021
2020
2019
2021
2020
2019
Proved Oil and Gas Properties
$
-
$
-
$
56
$
55,475
$
53,883
$
51,210
Unproved Oil and Gas Properties
-
-
-
1,944
2,962
3,714
Total Capital Cost
-
-
56
57,419
56,845
54,924
Accumulated DD&A
-
-
56
48,868
47,637
39,999
Net Capitalized Costs
$
-
$
-
$
-
$
8,551
$
9,208
$
14,925
COSTS INCURRED Costs incurred includes both capitalized costs and costs charged to expense when incurred. Costs incurred also includes internal costs directly related to acquisition, exploration, and development activities, new asset retirement costs established in the current year as well as increases or decreases to the asset retirement obligations resulting from changes to cost estimates during the year.
United States
Canada
2021
2020
2019
2021
2020
2019
Acquisition Costs
Unproved
$
2
$
16
$
843
$
-
$
-
$
-
Proved
9
3
5,963
-
-
-
Total Acquisition Costs
11
19
6,806
-
-
-
Exploration Costs
10
12
5
5
-
-
Development Costs
1,148
1,352
2,129
388
353
480
Total Costs Incurred
$
1,169
$
1,383
$
8,940
$
393
$
353
$
480
Total
2021
2020
2019
Acquisition Costs
Unproved
$
2
$
16
$
843
Proved
9
3
5,963
Total Acquisition Costs
11
19
6,806
Exploration Costs
15
12
5
Development Costs
1,536
1,705
2,609
Total Costs Incurred
$
1,562
$
1,736
$
9,420
COSTS NOT SUBJECT TO DEPLETION OR AMORTIZATION Upstream costs in respect of significant unproved properties are excluded from the country cost center’s depletable base as follows:
As at December 31
2021
2020
United States
$
1,884
$
2,785
Canada
60
177
$
1,944
$
2,962
The following is a summary of the costs related to Ovintiv’s unproved properties as at December 31, 2021:
2021
2020
2019
Prior to 2019
Total
Acquisition Costs
$
2
$
22
$
810
$
954
$
1,788
Exploration Costs
11
7
3
135
156
$
13
$
29
$
813
$
1,089
$
1,944
Acquisition costs primarily include costs incurred to acquire or lease properties. Exploration costs primarily include costs related to geological and geophysical studies and unevaluated costs associated with drilling and equipping exploratory wells. Ultimate recoverability of these costs and the timing of inclusion within the applicable country cost center’s depletable base is dependent upon either the finding of proved oil, NGL and natural gas reserves, expiration of leases or recognition of impairments. The $1.9 billion of oil and natural gas properties not subject to depletion or amortization primarily includes leasehold and mineral costs related to the acquisition of Permian, Anadarko and Bakken. These acquisition costs are associated with acquired acreage for which proved reserves have yet to be assigned from future development. The Company continually assesses the development timeline of the acquired acreage. The timing and amount of the transfer of property acquisition costs into the depletable base are based on several factors and may be subject to changes over time from drilling plans, drilling results, availability of capital, project economics and other assessments of the property. The inclusion of these acquisition costs in the depletable base is expected to occur within two to three years. The remaining costs excluded from depletion are related to properties which are not individually significant. |
