FULLTEXT DEL 1 AV 1
Kvartalsrapport Q1 2023
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Q1
International Petroleum Corporation
Interim Condensed Consolidated
Financial Statements
For the three months ended March 31, 2023
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2
Contents
Interim Condensed Consolidated Statement of Operations 3
In
terim Condensed Consolidated Statement of Comprehensive Income 4
In
terim Condensed Consolidated Balance Sheet 5
In
terim Condensed Consolidated Statement of Cash Flow 6
In
terim Condensed Consolidated Statement of Changes in Equity 7
No
tes to the Interim Condensed Consolidated Financial Statements 8
Interim Condensed Consolidated Financial Statements
For the three months ended March 31, 2023 and 2022, UNAUDITED
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3
Interim Condensed Consolidated Statement of Operations
For the three months ended March 31, 2023 and 2022, UNAUDITED
Three months ended - March 31
USD Thousands Note 2023 2022
Revenue 2 192,516 259,782
Cost of sales
Production costs 3 (117,527) (110,549)
Depletion and decommissioning costs 7 (6,439) (27,952)
Depreciation of other tangible fixed assets 9 (2,558) (2,080)
Exploration and business development costs (1,609) (101)
Gross profit 2 64,383 119,100
General, administration and depreciation expenses (4,194) (4,173)
Profit before financial items 60,189 114,927
Finance income 4 4,924 3,131
Finance costs 5 (9,939) (9,738)
Net financial items (5,015) (6,607)
Profit before tax 55,174 108,320
Income tax expense 6 (15,611) (27,498)
Net result 39,563 80,822
Net result attributable to:
Shareholders of the Parent Company 39,557 80,807
Non-controlling interest 6 15
39,563 80,822
Earnings per share – USD
1 15 0.29 0.52
Earnings per share fully diluted – USD1 15 0.28 0.51
1 Based on net result attributable to shareholders of the Parent Company
See accompanying notes to the interim condensed consolidated financial statements
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4
Interim Condensed Consolidated Statement of Comprehensive Income
For the three months ended March 31, 2023 and 2022, UNAUDITED
Three months ended - March 31
USD Thousands Note 2023 2022
Net result 39,563 80,822
Other comprehensive income
Items that may be reclassified to profit or loss:
Reclassification of hedging (gains) / losses to profit or loss 2 (8,584) 256
Gains / (losses) on cash flow hedges 4,659 (13,118)
Income tax relating to these items 986 3,247
Currency translation adjustments 1,177 5,086
Total comprehensive income 37,801 76,293
Total comprehensive income attributable to:
Shareholders of the Parent Company 37,792 76,280
Non-controlling interest 9 13
37,801 76,293
See accompanying notes to the interim condensed consolidated financial statements
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5
Interim Condensed Consolidated Balance Sheet
As at March 31, 2023 and December 31, 2022, UNAUDITED
USD Thousands Note March 31, 2023 December 31, 2022
ASSETS
Non-current assets
Oil and gas properties 7 1,077,787 963,375
Other tangible fixed assets 9 31,266 33,374
Right-of-use assets 1,069 1,217
Deferred tax assets 6 20,463 1,960
Other assets 10 41,979 41,125
Total non-current assets 1,172,564 1,041,051
Current assets
Inventories
11 22,203 15,958
Trade and other receivables 12 120,216 123,609
Derivative instruments 19 13,233 11,741
Current tax receivables – 18
Cash and cash equivalents 13 378,466 487,240
Total current assets 534,118 638,566
TOTAL ASSETS 1,706,682 1,679,617
LIABILITIES
Non-current liabilities
Financial liabilities
16 8,003 8,711
Bonds 16 295,719 295,440
Lease liabilities 381 507
Provisions 17 233,076 203,389
Deferred tax liabilities 6 66,332 56,334
Total non-current liabilities 603,511 564,381
Current liabilities
Trade and other payables
18 123,034 118,726
Financial liabilities 16 3,507 3,431
Derivative instruments 19 6,567 1,155
Current tax liabilities 18,346 17,793
Lease liabilities 762 752
Provisions 17 9,637 8,048
Total current liabilities 161,853 149,905
EQUITY
Shareholders’ equity 941,118 965,140
Non-controlling interest 200 191
Net shareholders’ equity 941,318 965,331
TOTAL EQUITY AND LIABILITIES 1,706,682 1,679,617
Approved by the Board of Directors
(Signed) C. Ashley Heppenstall
(Signed) Mike Nicholson
Director
Director
See accompanying notes to the interim condensed consolidated financial statements
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6
Interim Condensed Consolidated Statement of Cash Flow
For the three months ended March 31, 2023 and 2022, UNAUDITED
Three months ended - March 31
USD Thousands Note 2023 2022
Cash flow from operating activities
Net result 39,563 80,822
Adjustments for non-cash related items:
Depletion, depreciation and amortization 7,9 9,380 30,435
Income tax 6 15,611 27,498
Amortization of capitalized financing fees 5 443 2,325
Foreign currency exchange 4,5 856 (3,059)
Interest expense 5 5,349 4,034
Interest income 4 (4,924) (55)
Unwinding of asset retirement obligation discount 5 3,068 2,760
Share-based costs 2,587 1,731
Other 178 250
Cash flow generated from operations (before working capital
adjustments and income taxes) 72,111 146,741
Changes in working capital (14,593) (25,487)
Decommissioning costs paid 17 (1,211) (1,327)
Other payments 17 (290) (598)
Income taxes received / (paid) (3,584) (974)
Interest received 4,965 55
Interest paid (10,947) (446)
Net cash flow from operating activities 46,451 117,964
Cash flow used in investing activities
Investment in oil and gas properties 7 (48,238) (38,353)
Acquisition of Cor4 net of cash acquired 8 (59,180) –
Investment in other fixed assets 9 (172) (48)
Net cash (outflow) from investing activities (107,590) (38,401)
Cash flow from financing activities
Borrowings / (Repayments)
16 (856) (98,742)
Bonds issuance 16 – 300,000
Paid financing fees 16 (507) (5,583)
Repurchase of own shares 14 (45,830) (21,029)
Other payments (186) (184)
Net cash (outflow) from financing activities (47,379) 174,462
Change in cash and cash equivalents (108,518) 254,025
Cash and cash equivalents at the beginning of the period 487,240 18,810
Currency exchange difference in cash and cash equivalents (256) (802)
Cash and cash equivalents at the end of the period 378,466 272,033
See accompanying notes to the interim condensed consolidated financial statements
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7
Interim Condensed Consolidated Statement of Changes in Equity
For the three months ended March 31, 2023 and 2022, UNAUDITED
USD Thousands
Share
capital and
premium
Retained
earnings CTA IFRS 2
reserve
MTM
reserve
Pension
reserve Total
Non-
controlling
interest
Total
equity
Balance at January 1, 2023 338,719 635,895 (31,292) 11,349 7,958 2,511 965,140 191 965,331
Net result – 39,557 – – – – 39,557 6 39,563
Acquisition of Cor41 – – – – 881 – 881 – 881
Cash flow hedge – – – – (3,820) – (3,820) – (3,820)
Currency translation difference – – 1,321 (153) 6 – 1,174 3 1,177
Total comprehensive income – 39,557 1,321 (153) (2,933) – 37,792 9 37,801
Repurchase of own shares2 (45,830) – – – – – (45,830) – (45,830)
Share based payments3 (12,931) – – (3,053) – – (15,984) – (15,984)
Balance at March 31, 2023 279,958 675,452 (29,971) 8,143 5,025 2,511 941,118 200 941,318
1 See Note 8
2 See Note 14
3 The third instalment of IPC RSP 2020 awards, the second instalment of IPC RSP 2021 awards, the first instalment of IPC RSP 2022 awards and
the IPC PSP 2020 awards vested on January 31, 2023, at a price of CAD 14.26 per award. The difference between the value at vesting date
and at grant (respectively CAD 4.35 per award, CAD 4.07 per award, CAD 9.09 per award and CAD 3.65 per award) was offset against share
premium.
USD Thousands
Share
capital and
premium
Retained
earnings CTA IFRS 2
reserve
MTM
reserve
Pension
reserve Total
Non-
controlling
interest
Total
equity
Balance at January 1, 2022 528,764 298,212 11,291 9,700 874 (1,455) 847,386 157 847,543
Net result – 80,807 – – – – 80,807 15 80,822
Cash flow hedge – – – – (9,615) – (9,615) – (9,615)
Currency translation difference – – 5,311 61 (284) – 5,088 (2) 5,086
Total comprehensive income – 80,807 5,311 61 (9,899) – 76,280 13 76,293
Repurchase of own shares1 (21,029) – – – – – (21,029) – (21,029)
Share based payments (2,432) – – (254) – – (2,686) – (2,686)
Balance at March 31, 2022 505,303 379,019 16,602 9,507 (9,025) (1,455) 899,951 170 900,121
1 See Note 14
See accompanying notes to the interim condensed consolidated financial statements.
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Notes to the Interim Condensed Consolidated Financial Statements
For the three months ended March 31, 2023 and 2022, UNAUDITED
1. CORPORATE INFORMATION
A. The Group
International Petroleum Corporation (“IPC” or the “Corporation” and, together with its subsidiaries, the “Group”) is in the business
of exploring for, developing and producing oil and gas. IPC holds a portfolio of oil and gas production assets and development
projects in Canada, Malaysia and France with exposure to growth opportunities.
The Corporation’s common shares are listed on the Toronto Stock Exchange (“TSX”) in Canada and the Nasdaq Stockholm
Exchange in Sweden. The Corporation is incorporated and domiciled in British Columbia, Canada under the Business Corporations
Act. The address of its registered office is Suite 2600, 595 Burrard Street, P .O. Box 49314, Vancouver, BC V7X 1L3, Canada and its
business address is Suite 2000, 885 West Georgia Street, Vancouver, BC V6C 3E8, Canada.
On March 3, 2023, IPC completed the acquisition (the “Cor4 acquisition”) of all of the issued and outstanding shares of Cor4 Oil
Corp. (“Cor4”).
B. Basis of preparation
The unaudited interim condensed consolidated financial statements have been prepared in accordance with International
Accounting Standard 34, Interim Financial Reporting using accounting policies consistent with International Financial Reporting
Standards (“IFRS”) as issued by the International Accounting Standards Board (“IASB”). The financial statements should be
read in conjunction with IPC’s annual consolidated financial statements for the year ended December 31, 2022, which have been
prepared in accordance with IFRS as issued by the IASB.
These unaudited interim consolidated financial statements are presented in United States Dollars (USD), which is the Group’s
presentation and functional currency. The unaudited interim consolidated financial statements have been prepared on a historical
cost basis, except for items that are required to be accounted for at fair value as detailed in the Group’s accounting policies.
Intercompany transactions and balances have been eliminated. Certain comparative figures have been reclassified to conform with
the financial statements presentation in the current year.
The unaudited interim condensed consolidated financial statements have been approved by the Board of Directors of IPC and
authorized for issuance on May 2, 2023.
The unaudited interim condensed consolidated financial statements have been prepared following the same accounting policies
and methods of application as those in the Group’s audited annual consolidated financial statements for the year ended December
31, 2022.
C. Going concern
The Group’s consolidated financial statements for the three months ended March 31, 2023, have been prepared on a going
concern basis, which assumes that the Group will be able to realize its assets and discharge its liabilities in the normal course of
business as they become due in the foreseeable future.
D. Changes in accounting policies and disclosures
During the three months ended March 31, 2023, the Group applied the amended accounting standards, interpretations and annual
improvement points that are effective as of January 1, 2023.
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2. SEGMENT INFORMATION
The Group operates within several geographical areas. Operating segments are reported at a country level which is consistent with
the internal reporting provided to the CEO, who is the chief operating decision maker.
The following tables present segment information regarding: revenue, production costs, exploration and evaluation costs and gross
profit. The Group derives its revenue from contracts with customers primarily through the transfer of oil and gas at a point in time.
In addition, certain identifiable asset segment information is reported in Note 7.
Three months ended - March 31, 2023
USD Thousands Canada Malaysia France Other Total
Crude oil 147,731 17,671 15,131 – 180,533
NGLs 190 – – – 190
Gas 20,483 – – – 20,483
Net sales of oil and gas 168,404 17,671 15,131 – 201,206
Change in under/over lift position – – 2,670 – 2,670
Royalties (18,665) – (1,474) – (20,139)
Hedging settlement 8,584 – – – 8,584
Other operating revenue 6 – 189 – 195
Revenue 158,329 17,671 16,516 – 192,516
Operating costs (59,531) (8,176) (7,738) – (75,445)
Cost of blending (47,817) – – – (47,817)
Change in inventory position (422) 5,872 285 – 5,735
Depletion and decommissioning costs1 2,523 (5,829) (3,133) – (6,439)
Depreciation of other tangible fixed assets – (2,558) – – (2,558)
Exploration and business development costs (831) – – (778) (1,609)
Gross profit/(loss) 52,251 6,980 5,930 (778) 64,383
1 In Canada, includes an adjustment for accelerated decommissioning activities funded by a non cash site rehabilitation program.
Three months ended - March 31, 2022
USD Thousands Canada Malaysia France Other Total
Crude oil 191,230 36,014 33,659 – 260,903
NGLs 227 – – – 227
Gas 30,216 – – – 30,216
Net sales of oil and gas 221,673 36,014 33,659 – 291,346
Change in under/over lift position – – (6,113) – (6,113)
Royalties (23,988) – (1,524) – (25,512)
Hedging settlement (256) – – – (256)
Other operating revenue 101 – 216 – 317
Revenue 197,530 36,014 26,238 – 259,782
Operating costs (52,436) (9,586) (9,439) – (71,461)
Cost of blending (42,641) – – – (42,641)
Change in inventory position 928 2,136 489 – 3,553
Depletion and decommissioning costs (17,859) (6,689) (3,404) – (27,952)
Depreciation of other tangible fixed assets – (2,080) – – (2,080)
Exploration and business development costs – – – (101) (101)
Gross profit/(loss) 85,522 19,795 13,884 (101) 119,100
Notes to the Interim Condensed Consolidated Financial Statements
For the three months ended March 31, 2023 and 2022, UNAUDITED
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3. PRODUCTION COSTS
Three months ended - March 31
USD Thousands 2023 2022
Cost of operations 64,774 60,704
Tariff and transportation expenses 9,499 9,328
Direct production taxes 1,172 1,429
Operating costs 75,445 71,461
Cost of blending1 47,817 42,641
Change in inventory position (5,735) (3,553)
Total production costs 117,527 110,549
1 In Canada, oil production is blended with purchased condensate diluent to meet pipeline specifications. Cost of blending represents the contracted
purchase of diluent used for blending.
4. FINANCE INCOME
Three months ended - March 31
USD Thousands 2023 2022
Foreign exchange gain, net – 3,059
Interest income 4,924 55
Other financial income – 17
Total finance income 4,924 3,131
5. FINANCE COSTS
Three months ended - March 31
USD Thousands 2023 2022
Foreign exchange loss, net 856 –
Interest expense 5,349 4,034
Unwinding of asset retirement obligation discount 3,068 2,760
Amortization of loan fees 164 2,139
Amortization of bond fees 279 186
Loan commitment fees 88 259
Other financial costs 135 360
Total finance costs 9,939 9,738
6. INCOME TAX
Three months ended - March 31
USD Thousands 2023 2022
Current tax (3,991) (4,123)
Deferred tax (11,620) (23,375)
Total tax recovery / (expense) (15,611) (27,498)
On September 30, 2022, the Council of the European Union (“EU“) agreed to impose an EU-wide windfall profits tax on energy
companies deriving income from operations in EU countries (“Solidarity Contribution”). In Q1 2023, the current tax includes a
Solidarity Contribution provision relating to the income in France amounting to USD 754 thousand.
Notes to the Interim Condensed Consolidated Financial Statements
For the three months ended March 31, 2023 and 2022, UNAUDITED
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The deferred tax amount arises primarily where there is a difference in depletion for tax and accounting purposes. The deferred tax
charge in the statement of operations for the current period mainly relates to the tax profit incurred and the tax losses used during
the Q1 2023.
Specification of deferred tax assets and tax liabilities
1
USD Thousands March 31, 2023 December 31, 2022
Unused tax loss carry forward 42,468 32,815
Other 4,761 5,841
Deferred tax assets 47,229 38,656
Accelerated allowances 91,369 90,400
Other 1,729 2,630
Deferred tax liabilities 93,098 93,030
Deferred taxes, net (45,869) (54,374)
1 The specification of deferred tax assets and tax liabilities does not agree to the face of the balance sheet due to the netting off of balances in the
balance sheet when they relate to the same jurisdiction.
The deferred tax liabilities consist of accelerated allowances, being the difference between the book and the tax value of oil and
gas properties and site restoration provisions. The deferred tax liabilities will be released over the life of the oil and gas assets as
the book value is depleted for accounting purposes.
Deferred tax assets in relation to tax loss carried forwards are only recognized in so far that there is a reasonable certainty as to
the timing and the extent of their realization. The recognized unused tax loss carry forward mainly relates to Canada. The Group
has concluded that the deferred assets will be recoverable using the estimated future taxable income based on the approved
business plans and budgets.
7. OIL AND GAS PROPERTIES
USD Thousands 2023 2022
Exploration and Evaluation Assets 4,857 4,764
Property, plant and Equipment 1,072,930 958,611
Oil and gas properties 1,077,787 963,375
Exploration and Evaluation Assets
USD Thousands Canada Malaysia France Total
Cost
January 1, 2023 – – 4,764 4,764
Currency translation adjustments – – 93 93
Net book value March 31, 2023 – – 4,857 4,857
USD Thousands Canada Malaysia France Total
Cost
January 1, 2022 12,751 181 5,105 18,037
Additions
1 (802) 149 4 (649)
Reclassification (11,974) (330) – (12,304)
Currency translation adjustments 25 – (345) (320)
Net book value December 31, 2022 – – 4,764 4,764
1 Net revenues on appraisal projects are being offset against capitalized costs of Exploration and Evaluation assets.
Notes to the Interim Condensed Consolidated Financial Statements
For the three months ended March 31, 2023 and 2022, UNAUDITED
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Property, Plant and Equipment
USD Thousands Canada Malaysia France Total
Cost
January 1, 2023 1,089,789 566,606 399,237 2,055,632
Acquisition of Cor4 - See Note 8 72,003 – – 72,003
Additions 35,445 664 12,129 48,238
Currency translation adjustments (806) – 7,906 7,100
March 1, 2023 1,196,431 567,270 419,272 2,182,973
Accumulated depletion
January 1, 2023 (323,273) (485,034) (288,714) (1,097,021)
Depletion charge for the period (21,655) (5,829) (3,133) (30,617)
Other1 22,857 – – 22,857
Currency translation adjustments 357 – (5,619) (5,262)
March 31, 2023 (321,714) (490,863) (297,466) (1,110,043)
Net book value March 31, 2023 874,717 76,407 121,806 1,072,930
1 In Canada, includes an adjustment for accelerated decommissioning activities funded by a non cash site rehabilitation program.
USD Thousands Canada Malaysia France Total
Cost
January 1, 2022 1,021,944 534,443 408,211 1,964,598
Additions 118,762 27,305 12,244 158,311
Change in estimates 5,231 4,528 2,182 11,941
Reclassification 11,974 330 – 12,304
Currency translation adjustments (68,122) – (23,400) (91,522)
December 31, 2022 1,089,789 566,606 399,237 2,055,632
Accumulated depletion
January 1, 2022 (267,585) (450,347) (293,132) (1,011,064)
Depletion charge for the period (75,077) (34,687) (12,277) (122,041)
Currency translation adjustments 19,389 – 16,695 36,084
December 31, 2022 (323,273) (485,034) (288,714) (1,097,021)
Net book value December 31, 2022 766,516 81,572 110,523 958,611
Notes to the Interim Condensed Consolidated Financial Statements
For the three months ended March 31, 2023 and 2022, UNAUDITED
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8. COR4 ACQUISITION
On March 3, 2023, IPC completed the acquisition of all of the issued and outstanding shares of Cor4. At such date, Cor4 became
an indirect, wholly-owned subsidiary of IPC.
The Cor4 acquisition has been accounted for as a business combination with IPC being the acquirer, and in accordance with IFRS
3 Business Combinations, the assets acquired and liabilities assumed have been recorded at their fair values.
The total cash consideration paid, after preliminary closing adjustments, amounted to USD 62.0 million (CAD 84.3 million).
The amounts recognized in respect of the identifiable assets acquired and liabilities assumed are as set out in the table below:
USD Thousands
Cash 2,792
Trade and other receivables 7,671
Prepaid expenses and deposits 2,417
Fair value of risk management assets 1,144
Deferred tax assets 19,334
Right-of-use assets 109
Property, plant and equipment 72,003
Accounts payable and accrued liabilities (12,623)
Right-of-use liabilities (109)
Decommissioning liabilities (29,885)
Mark-To-Market (“MTM”) reserve in equity (881)
Total Consideration 61,972
Settled by:
Cash payment 61,972
The Corporation performed a preliminary purchase price allocation for the Cor4 acquisition. The amounts disclosed above were
determined provisionally pending the finalization of the valuation for those assets and liabilities. Up to twelve months from the
effective date of the Cor4 acquisition, further adjustments may be made to the fair values assigned to the identifiable assets
acquired and liabilities assumed.
Acquisition-related costs of approximately USD 0.8 million have been recognized in the statement of operations during Q1 2023.
Decommissioning liabilities
The fair value of the decommissioning liability at the acquisition date was based on the estimated future cash flows to
decommission the acquired oil and natural gas properties at the end of their useful life. The discount rate used to determine the
net present value of the decommissioning obligation was a credit risk adjusted rate of 8%.
Notes to the Interim Condensed Consolidated Financial Statements
For the three months ended March 31, 2023 and 2022, UNAUDITED
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9. OTHER TANGIBLE FIXED ASSETS
USD Thousands FPSO Other Total
Cost
January 1, 2023 204,853 9,779 214,632
Additions – 172 172
Currency translation adjustments 418 91 509
March 31, 2023 205,271 10,042 215,313
Accumulated depreciation
January 1, 2023 (173,311) (7,947) (181,258)
Depreciation charge for the period (2,558) (158) (2,716)
Currency translation adjustments – (73) (73)
March 31, 2023 (175,869) (8,178) (184,047)
Net book value March 31, 2023 29,402 1,864 31,266
USD Thousands FPSO Other Total
Cost
January 1, 2022 206,173 10,163 216,336
Additions – 151 151
Disposals – (44) (44)
Currency translation adjustments (1,320) (491) (1,811)
December 31, 2022 204,853 9,779 214,632
Accumulated depreciation
January 1, 2022 (162,524) (7,449) (169,973)
Depreciation charge for the period (10,787) (891) (11,678)
Disposals – 36 36
Currency translation adjustments – 357 357
December 31, 2022 (173,311) (7,947) (181,258)
Net book value December 31, 2022 31,542 1,832 33,374
The FPSO located on the Bertam field, Malaysia, is being depreciated on a unit of production basis based on the Bertam field
reserves cut-off at August 2025. The depreciation charge is included in the depreciation of other assets line in the statement of
operations.
For office equipment and other assets, the depreciation charge for the year is based on cost and an estimated useful life of 3 to
5 years. The depreciation charge is included within the general, administration and depreciation expenses in the statement of
operations.
Notes to the Interim Condensed Consolidated Financial Statements
For the three months ended March 31, 2023 and 2022, UNAUDITED
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10. OTHER NON-CURRENT ASSETS
USD Thousands March 31, 2023 December 31, 2022
Long-term receivables 28,106 28,154
Financial assets 13,873 12,971
41,979 41,125
Long-term receivables represent cash payments made to an asset retirement obligation fund and financial assets include
secured amounts of USD 7.7 million transferred for the future asset retirement obligation, in respect of the Bertam field,
Malaysia. In 2022, an amount of USD 1.9 million was paid into the asset retirement obligation fund which is held in local
currency. (Also see Note 17.)
11. INVENTORIES
USD Thousands March 31, 2023 December 31, 2022
Hydrocarbon stocks 14,613 8,988
Well supplies and operational spares 7,590 6,970
22,203 15,958
12. TRADE AND OTHER RECEIVABLES
USD Thousands March 31, 2023 December 31, 2022
Trade receivables 103,022 112,696
Underlift 3,317 599
Joint operations debtors 1,151 982
Prepaid expenses and accrued income 10,228 6,585
Other 2,498 2,747
120,216 123,609
13. CASH AND CASH EQUIVALENTS
Cash and cash equivalents include only cash at hand or held in bank accounts. As at March 31, 2023, an amount of USD 8.2 million
is restricted.
14. SHARE CAPITAL
The Group’s issued common share capital is as follows:
Number of shares
Balance at January 1, 2022 155,198,105
Cancellation following the Substantial Issuer Bid (8,258,064)
Cancellation of repurchased common shares (10,112,042)
Balance at December 31, 2022 136,827,999
Cancellation of repurchased common shares (4,758,053)
Balance at March 31, 2023 132,069,946
Notes to the Interim Condensed Consolidated Financial Statements
For the three months ended March 31, 2023 and 2022, UNAUDITED
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The common shares of IPC trade on both the Toronto Stock Exchange and the Nasdaq Stockholm Exchange.
As at January 1, 2022, IPC had a total of 155,198,105 common shares issued and outstanding, of which IPC held 1,160,651
common shares in treasury. All common shares held in treasury as at January 1, 2022 were cancelled during January 2022.
During 2022, under the normal course issuer bid/share repurchase program announced in December 2021 and renewed in
December 2022 (NCIB), IPC purchased and cancelled an aggregate of 8,951,391 common shares.
During Q2 2022, IPC commenced an offer to repurchase common shares under the substantial issuer bid (SIB). Under the SIB,
IPC purchased and cancelled an aggregate of 8,258,064 common shares.
As at December 31, 2022, IPC had a total of 136,827,999 common shares issued and outstanding, with no common shares held in
treasury.
During the Q1 2023, IPC purchased and cancelled a total of 4,758,053 common shares under the NCIB. As at March 31, 2023, IPC
had a total of 132,069,946 common shares issued and outstanding, with no common shares held in treasury.
In addition, IPC has 117,485,389 outstanding class A preferred shares, issued as a part of an internal corporate structuring to a
wholly-owned subsidiary of IPC. Such preferred shares are not listed on any stock exchange, do not carry the right to vote on
matters to be decided by the holders of IPC’s common shares and do not impact the earnings per share calculations.
15. EARNINGS PER SHARE
Basic earnings per share are based on net result attributable to the common shareholders and is calculated based upon the
weighted-average number of common shares outstanding during the periods presented.
Three months ended - March 31
USD Thousands 2023 2022
Net result attributable to shareholders of the Parent Company, USD 39,556,554 80,806,696
Weighted average number of shares for the period 136,774,538 155,150,553
Earnings per share, USD 0.29 0.52
Weighted average diluted number of shares for the period 138,932,433 158,049,693
Earnings per share fully diluted, USD 0.28 0.51
16. FINANCIAL LIABILITIES
USD Thousands March 31, 2023 December 31, 2022
Bank loans 11,510 12,142
Bonds 300,000 300,000
Capitalized financing fees (4,281) (4,560)
307,229 307,582
As at March 31, 2023, IPC had a EUR 13 million unsecured credit facility in France (the “France Facility“), with maturity in May
2026. IPC commenced quarterly repayments of the French Facility in August 2022. The amount remaining outstanding
under the France Facility as at March 31, 2023 was USD 12 million (EUR 11 million).
As at January 2022, the Group had a reserve-based lending (RBL) credit facility of USD 140 million in connection with its oil and
gas assets in France and Malaysia and a RBL credit facility of CAD 300 million in connection with its oil and gas assets in Canada.
In February 2022, IPC completed the issuance of USD 300 million of Bonds, which mature in February 2027 and have a fixed
coupon rate of 7.25% per annum, payable in semi-annual instalments in August and February. The Group used a portion of the
proceeds of the Bonds to fully repay the outstanding RBL credit facilities, which were then cancelled. At the same time, the Group
entered into a revolving credit facility of CAD 75 million (the “Canadian RCF”) in connection with its oil and gas assets in Canada.
In Q1 2023, the Group increased the Canadian RCF to CAD 150 million and extended the maturity to May 2025. No cash amounts
were drawn under the Canadian RCF as at March 31, 2023.
Notes to the Interim Condensed Consolidated Financial Statements
For the three months ended March 31, 2023 and 2022, UNAUDITED
===== SIDA 17 =====
17
The Bond repayment obligations as at March 31, 2023, are classified as non-current as there are no mandatory repayments within
the next twelve months.
An amount of USD 3.5 million (EUR 3.2 million) drawn under the France Facility as at March 31, 2023 is classified as current
representing the repayment planned within the next twelve months.
The Group is in compliance with the covenants of the Bonds and its financing facilities as at March 31, 2023.
17. PROVISIONS
USD Thousands
Asset
retirement
obligation
Farm-in
obligation
Pension
obligation Other Total
January 1, 2023 206,249 3,404 306 1,478 211,437
Acquisition of Cor4 - See Note 8 29,885 – – – 29,885
Additions – – – 161 161
Unwinding of asset retirement obligation discount 3,068 – – – 3,068
Payments (1,211) – – (290) (1,501)
Other1 (1,266) – – – (1,266)
Currency translation adjustments 920 (6) – 15 929
March 31, 2023 237,645 3,398 306 1,364 242,713
Non-current 229,141 2,265 306 1,364 233,076
Current 8,504 1,133 – – 9,637
Total 237,645 3,398 306 1,364 242,713
1 Includes accelerated decommissioning activities funded by a non cash site rehabilitation program.
USD Thousands
Asset
retirement
obligation
Farm-in
obligation
Pension
obligation Other Total
January 1, 2022 196,362 4,199 4,448 1,357 206,366
Additions – – 542 1,034 1,576
Unwinding of asset retirement obligation discount 10,758 – – – 10,758
Changes in estimates 11,375 567 (3,778) – 8,164
Payments (5,809) (1,153) (718) (865) (8,545)
Reclassification 1 1,909 – – – 1,909
Currency translation adjustments (8,346) (209) (188) (48) (8,791)
December 31, 2022 206,249 3,404 306 1,478 211,437
Non-current 199,335 2,270 306 1,478 203,389
Current 6,914 1,134 – – 8,048
Total 206,249 3,404 306 1,478 211,437
1 The reclassification of the asset retirement obligation related to the 2022 payment to the asset retirement obligation fund in respect of the Bertam
asset, Malaysia (see Note 10).
The farm-in obligation relates to future payments for historic costs on Block PM307 in Malaysia payable on reaching certain Bertam
field production milestones.
In calculating the present value of the asset retirement obligation provision, a blended rate of 6% (2022: 6%) per annum was used,
based on a credit risk adjusted rate.
Notes to the Interim Condensed Consolidated Financial Statements
For the three months ended March 31, 2023 and 2022, UNAUDITED
===== SIDA 18 =====
18
18. TRADE AND OTHER PAYABLES
USD Thousands March 31, 2023 December 31, 2022
Trade payables 29,156 20,547
Joint operations creditors 13,823 14,348
Accrued expenses 76,492 78,206
Other 3,563 5,625
123,034 118,726
19. FINANCIAL ASSETS AND LIABILITIES
Financial assets and liabilities by category
The accounting policies for financial instruments have been applied to the line items below:
March 31, 2023
USD Thousands
Total
Financial assets
at amortized
cost
Fair value
recognized in
profit or loss
(FVTPL)
Derivatives
used for
hedging
Other assets1 41,979 41,979 – –
Derivative instruments 13,233 – – 13,233
Joint operation debtors 1,151 1,151 – –
Other current receivables2 108,837 105,520 3,317 –
Cash and cash equivalents 378,466 378,466 – –
Financial assets 543,666 527,116 3,317 13,233
1 See Note 10
2 Prepayments are not included in other current assets as prepayments are not deemed to be financial instruments.
March 31, 2023
USD Thousands
Total
Financial
liabilities at
amortized cost
Fair value
recognized in
profit or loss
(FVTPL)
Derivatives
used for
hedging
Non-current financial liabilities 303,722 303,722 – –
Current financial liabilities 3,507 3,507 – –
Derivative instruments 6,567 – – 6,567
Joint operation creditors 13,823 13,823 – –
Other current liabilities 127,557 127,557 – –
Financial liabilities 455,176 448,609 – 6,567
December 31, 2022
USD Thousands
Total Financial assets
at amortized cost
Fair value
recognized in
profit or loss
(FVTPL)
Derivatives used
for hedging
Other assets1 41,125 41,125 – –
Derivative instruments 11,741 – – 11,741
Joint operation debtors 982 982 – –
Other current receivables2 116,060 115,461 599 –
Cash and cash equivalents 487,240 487,240 – –
Financial assets 657,148 644,808 599 11,741
1 See Note 10
2 Prepayments are not included in other current assets as prepayments are not deemed to be financial instruments.
Notes to the Interim Condensed Consolidated Financial Statements
For the three months ended March 31, 2023 and 2022, UNAUDITED
===== SIDA 19 =====
19
December 31, 2022
USD Thousands
Total
Financial
liabilities at
amortized cost
Fair value
recognized in
profit or loss
(FVTPL)
Derivatives
used for
hedging
Non-current financial liabilities 304,151 304,151 – –
Current financial liabilities 3,431 3,431 – –
Derivative instruments 1,155 – – 1,155
Joint operation creditors 14,348 14,348 – –
Other current liabilities 122,171 122,171 – –
Financial liabilities 445,256 444,101 – 1,155
The carrying amount of the Group’s financial assets approximate their fair values at the balance sheet dates.
For financial instruments measured at fair value in the balance sheet, the following fair value measurement hierarchy is used:
– Level 1: based on quoted prices in active markets;
– Level 2: based on inputs other than quoted prices as within level 1, that are either directly or indirectly observable;
– Level 3: based on inputs which are not based on observable market data.
Based on this hierarchy, financial instruments measured at fair value can be detailed as follows:
March 31, 2023
USD Thousands Level 1 Level 2 Level 3
Other current receivables 3,317 – –
Derivative instruments – current – 13,233 –
Financial assets 3,317 13,233 –
Derivative instruments – current – 6,567 –
Financial liabilities – 6,567 –
December 31, 2022
USD Thousands Level 1 Level 2 Level 3
Other current receivables 599 – –
Derivative instruments – current – 11,741 –
Financial assets 599 11,741 –
Derivative instruments – current – 1,155 –
Financial liabilities – 1,155 –
The Group had gas price sale financial hedges outstanding as at March 31, 2023, which are summarized as follows:
Period Volume (Gigajoules (GJ) per day) Type Average Pricing
April 1, 2023 – October 31, 2023 35,0001 AECO Swap CAD 3.95/GJ
1 Equivalent to 33,700 Mcfpd at CAD 4.10/Mcf.
The Group had oil price sale financial hedges outstanding as at March 31, 2023 which are summarized as follows:
Period Volume (barrels per day) Type Average Pricing
April 1, 2023 - December 31, 2023 12,000 WCS/ARV Differential USD - 10.08/bbl
In October 2022, IPC entered into currency hedge swaps for 2023 to buy CAD 15 million per month, sell USD at an average
exchange rate of 1.3619 and to buy EUR 3 million per month, sell USD at an average exchange rate of 1.0000. This is to partially
fund operational expenditures in those currencies in Canada and France respectively.
All of the above hedges are treated as effective and changes to the fair value are reflected in other comprehensive income.
Notes to the Interim Condensed Consolidated Financial Statements
For the three months ended March 31, 2023 and 2022, UNAUDITED
===== SIDA 20 =====
20
20. CONTRACTUAL OBLIGATIONS AND COMMITMENTS
In Canada, an oil pipeline from the Onion Lake Thermal field to a gathering system has been built by a third party for the exclusive
use of IPC. The initial investment in the pipeline was met by the pipeline owner and is to be recovered through an agreed tariff
charged to IPC. IPC has committed to a firm transportation service for 15 years from commencement of service in April 2022, with
total remaining tariffs committed as shown in the table below:
2023 2024 2025 2026 2027 Thereafter
Transportation service (MCAD) 20.6 28.0 28.4 29.0 28.2 275.2
In Malaysia, IPC has an obligation to make payments towards historic costs on Block PM307 payable on the Bertam field for every
1 MMboe gross that the field produces above 10 MMboe gross. The estimated liability based on current 2P reserves and which is
capped at cumulative production of 27.5 MMboe gross, has been provided for in the Group’s Balance Sheet (see Note 17).
21. RELATED PARTIES
During Q1 2023, there were no significant cash transactions with related parties.
All transactions with related parties are in the normal course of business and are made on the same terms and conditions as with
parties at arm’s length.
22. SUBSEQUENT EVENTS
No events have occurred since March 31, 2023, that are expected to have a substantial effect on this report.
Notes to the Interim Condensed Consolidated Financial Statements
For the three months ended March 31, 2023 and 2022, UNAUDITED
===== SIDA 21 =====
Corporate Office
International Petroleum Corp
Suite 2000
885 West Georgia Street
Vancouver, BC
V6C 3E8, Canada
Tel: +1 604 689 7842
E-mail: info@international-petroleum.com
Web: international-petroleum.com□
===== SIDA 22 =====
Q1
International Petroleum Corporation
Management’s Discussion
and Analysis
For the three months ended March 31, 2023
===== SIDA 23 =====
Management’s Discussion and Analysis
For the three months ended March 31, 2023
Contents
Non-IFRS Measures
References are made in this MD&A to “operating cash flow” (OCF), “free cash flow” (FCF), “Earnings Before Interest, Tax, Depreciation and Amortization” (EBITDA),
“operating costs” and “net debt”/”net cash” which are not generally accepted accounting measures under International Financial Reporting Standards (IFRS) and do
not have any standardized meaning prescribed by IFRS and, therefore, may not be comparable with definitions of OCF , FCF , EBITDA, operating costs and net debt/
net cash that may be used by other public companies. Management believes that OCF , FCF , EBITDA, operating costs and net debt/net cash are useful supplemental
measures that may assist shareholders and investors in assessing the cash generated by and the financial performance and position of the Corporation. Non-IFRS
measures should not be considered in isolation or as a substitute for measures prepared in accordance with IFRS. The definition and reconciliation of each non-IFRS
measure is presented in this MD&A. See “Non-IFRS Measures” on page 17.
Forward-Looking Statements
Certain statements contained in this MD&A constitute “forward-looking statements” or “forward-looking information” (within the meaning of applicable securities
legislation). Such statements and information (together, “forward-looking statements”) relate to future events, including the Corporation’s future performance, business
prospects or opportunities. Any statements that express or involve discussions with respect to predictions, expectations, beliefs, plans, projections, forecasts,
guidance, budgets, objectives, assumptions or future events or performance (often, but not always, using words or phrases such as “seek“, “anticipate“, “plan“,
“continue“, “estimate“, “expect“, “may“, “will“, “project“, “forecast”, “predict“, “potential“, “targeting“, “intend“, “could“, “might“, “should“, “believe“, “budget“
and similar expressions) are not statements of historical fact and may be “forward-looking statements“. Although IPC believes that the expectations and assumptions
on which such forward-looking statements are based are reasonable, undue reliance should not be placed on the forward-looking statements because IPC can give no
assurances that they will prove to be correct. Since forward-looking statements address future events and conditions, by their very nature they involve inherent risks
and uncertainties. Actual results could differ materially from those currently anticipated due to a number of factors and risks. For additional information underlying
forward-looking statements, refer to the “Cautionary Statement Regarding Forward-Looking Information” on page 22.
Reserves estimates, contingent resource estimates and estimates of future net revenue in respect of IPC’s oil and gas assets in Canada (other than the assets acquired
in the acquisition of Cor4) are effective as of December 31, 2022, and are included in the reports prepared by Sproule Associates Limited (Sproule), an independent
qualified reserves evaluator, in accordance with National Instrument 51-101 – Standards of Disclosure for Oil and Gas Activities (NI 51-101) and the Canadian Oil and Gas
Evaluation Handbook (the COGE Handbook) and using Sproule’s December 31, 2022, price forecasts.
Reserve estimates, contingent resource estimates and estimates of future net revenue in respect of IPC’s oil and gas assets in France and Malaysia are effective as of
December 31, 2022, and are included in the report prepared by ERC Equipoise Ltd. (ERCE), an independent qualified reserves auditor, in accordance with NI 51-101 and
the COGE Handbook, and using Sproule’s December 31, 2022, price forecasts.
Reserve estimates and estimates of future net revenue in respect of the oil and gas assets acquired in the Cor4 acquisition are effective as of December 31, 2022, and
have been audited by a qualified reserves auditor (as defined in NI 51-101), in accordance with NI 51-101 and the COGE Handbook, and using Sproule’s December 31,
2022, price forecasts.
Certain abbreviations and technical terms used in this MD&A are defined or described under the heading “Other Supplementary Information”.
INTRODUCTION 3
H
IGHLIGHTS 4
OP
ERATIONS REVIEW 5
• Bu
siness Overview 5
• Op
erations Overview 7
FI
NANCIAL REVIEW 10
• Fin
ancial Results 10
• Ca
pital Expenditure 16
• Fin
ancial Position and Liquidity 17
• No
n-IFRS Measures 17
• Of
f-Balance Sheet Arrangements 19
• Ou
tstanding Share Data 19
• Co
ntractual Obligations and Commitments 20
• Cr
itical Accounting Policies and Estimates 20
• Tr
ansactions with Related Parties 20
• Fin
ancial Risk Management 20
R
ISK AND UNCERTAINTIES 21
D
ISCLOSURE CONTROLS AND INTERNAL CONTROL OVER FINANCIAL REPORTING 22
C
AUTIONARY STATEMENT REGARDING FORWARD-LOOKING INFORMATION 22
R
ESERVES AND RESOURCES ADVISORY 24
O
THER SUPPLEMENTARY INFORMATION 26
2
===== SIDA 24 =====
Management’s Discussion and Analysis
For the three months ended March 31, 2023
INTRODUCTION
This management’s discussion and analysis (“MD&A”) for International Petroleum Corporation (“IPC” or the “Corporation” and,
together with its subsidiaries, the “Group”) is dated May 2, 2023 and is intended to provide an overview of the Group’s operations,
financial performance and current and future business opportunities. This MD&A should be read in conjunction with IPC’s audited
consolidated financial statements and accompanying notes for the year ended December 31, 2022 (“Financial Statements”).
Group Overview
The Group is in the business of exploring for, developing and producing oil and gas. IPC holds a portfolio of oil and gas production
assets and development projects in Canada, Malaysia and France with exposure to growth opportunities.
The Corporation’s common shares are listed on the Toronto Stock Exchange in Canada and the Nasdaq Stockholm Exchange in
Sweden. The Corporation is incorporated and domiciled in British Columbia, Canada, under the Business Corporations Act. The
address of its registered office is Suite 2600, 595 Burrard Street, P .O. Box 49314, Vancouver, BC V7X 1L3, Canada and its business
address is Suite 2000, 885 West Georgia Street, Vancouver, BC V6C 3E8, Canada.
Basis of Preparation
The MD&A and the Financial Statements have been prepared in accordance with International Financial Reporting Standards
(“IFRS”) as issued by the International Accounting Standards Board (“IASB”).
Financial information is presented in United States Dollars (“USD”). However, as the Group operates in Europe and in Canada,
certain financial information prepared by subsidiaries has been reported in Euros (“EUR”) and in Canadian Dollars (“CAD”). In
addition, certain costs relating to the operations in Malaysia, which are reported in USD, are incurred in Malaysian Ringgit (“MYR”).
Exchange rates for the relevant currencies of the Group with respect to the US Dollar are as follows:
March 31, 2023 March 31, 2022 December 31, 2022
Average Period end Average Period end Average Year end
1 EUR equals USD 1.0730 1.0875 1.1225 1.1101 1.0539 1.0666
1 USD equals CAD 1.3521 1.3551 1.2666 1.2518 1.3015 1.3538
1 USD equals MYR 4.3865 4.4125 4.1923 4.2048 4.3995 4.4050
IPC completed the acquisition of Cor4 Oil Corp. (“Cor4”) on March 3, 2023. In accordance with IFRS, the Financial Statements
have been prepared on that basis, with revenues and expenses related to the assets acquired in the Cor4 acquisition included in
the Financial Statements from March 3, 2023. See also “Cor4 Acquisition” below. Certain historical and forecast operational and
financial information included in the MD&A, including production, reserves, operating costs, OCF , FCF and EBITDA related to the
assets acquired in the Cor4 acquisition, are reported based on the effective date of the Cor4 acquisition of January 1, 2023. See
also “Operations Overview – Production” and “Non-IFRS Measures” below.
3
===== SIDA 25 =====
Management’s Discussion and Analysis
For the three months ended March 31, 2023
HIGHLIGHTS
Q1 2023 Business Highlights
• Record quarterly average net production of approximately 52,800 barrels of oil equivalent (boe) per day (boepd) for the first
quarter of 2023 (50% heavy crude oil, 18% light and medium crude oil and 32% natural gas).
• Decision taken to advance the development of Phase 1 of the Blackrod project in Canada, maturing 218 million barrels of oil
equivalent (MMboe) of 2P reserves.
(1)(2)
• Successful completion of the Cor4 acquisition in Canada forecast to add approximately 4,000 boepd of average production
over 2023 and 15.9 MMboe of 2P reserves.
(1)(2)
• Ten-year extension signed for the Bertam Field, Malaysia production sharing contract (PSC) to 2035.
• 4.76 million common shares purchased and cancelled during Q1 2023 under IPC’s normal course issuer bid (NCIB).
Q1 2023 Financial Highlights
• Operating costs per boe of USD 17.3 for Q1 2023 in line with CMD guidance for Q1 2023. (1)(3)
• Operating cash flow (OCF) generation for Q1 2023 amounted to MUSD 76. (1)(3)
• Capital and decommissioning expenditures of MUSD 55 for Q1 2023 in line with CMD guidance. (1)
• Free cash flow (FCF) generation for Q1 2023 amounted to MUSD 16. (1)(3)
• Net cash of MUSD 67 as at March 31, 2023.(3)
• Increased Canadian Revolving Credit Facility (RCF) from CAD 75 to 150 million (fully committed and undrawn) and
extended maturity from February 2024 to May 2025.
• Net result of MUSD 40 for Q1 2023.
Reserves and Resources
• Total 2P reserves as at December 31, 2022 of 487 million boe (MMboe), with a reserves life index (RLI) of 27 years. (1)(2)
• Contingent resources (best estimate, unrisked) as at December 31, 2022 of 1,162 MMboe.(1)(2)
2023 Annual Guidance
• Full year 2023 average net production forecast expected to be at the upper end of 48,000 to 50,000 boepd guidance range.
(1)
• Full year 2023 operating costs guidance forecast at USD 17.5 to 18 per boe.(1)(3)
• Full year 2023 OCF guidance estimated at between MUSD 250 to 495 (assuming Brent USD 70 to 100 per barrel). (1)(3)
• Full year 2023 capital and decommissioning expenditures guidance forecast at MUSD 365, including MUSD 287 relating to
Phase 1 of the Blackrod project.
(1)
• Full year 2023 FCF forecast ranges from approximately MUSD -145 to 105 (assuming Brent USD 70 to 100 per barrel) after
taking into account MUSD 287 of proposed 2023 Blackrod capital expenditures. (1)(3)
Three months ended March 31
USD Thousands 2023 2022
Revenue 192,516 259,782
Gross profit 40,205 119,100
Net result 39,563 80,822
Operating cash flow(3) 75,900 145,110
Free cash flow(3) 16,259 96,479
EBITDA(3) 76,079 145,463
Net Cash/(Debt)(3) 66,956 (42,367)
4
===== SIDA 26 =====
Management’s Discussion and Analysis
For the three months ended March 31, 2023
OPERATIONS REVIEW
Business Overview
During the first quarter of 2023, oil and gas prices weakened on demand concerns, as rising interest rates aimed at taming high
inflation, stoked recessionary fears. This was further exacerbated by the unfolding banking crisis during the quarter. Brent prices
averaged slightly over USD 80 per barrel during the quarter, down by around ten per cent compared with the fourth quarter of
2022. The surprise production cuts announced by OPEC+ in early April are a second pre-emptive move by the group, aimed at
ensuring recent oil price weakness, is not sustained. While inventory levels have built back close to the five-year average levels,
the OPEC+ cuts are expected by market observers to push the oil market back into deficit for the remainder of 2023.
The first quarter 2023 West Texas Intermediate (WTI) to Western Canadian Select (WCS) crude price differentials averaged around
USD 25 per barrel, USD 5 per barrel wider than our base case 2023 market guidance. Those market factors that have driven
differentials wider such as the US Strategic Petroleum Reserve (SPR) releases, higher natural gas prices and refinery outages have
now turned to provide more favourable tailwinds to Canadian differentials going forward. In addition, the expansion of the Trans
Mountain pipeline (590,000 barrels per day of extra capacity linking Edmonton to the port of Vancouver) due in service in Q1 2024
as well as a reduction in Mexican heavy oil exports to the US as domestic refinery capacity increases by more than 200,000 barrels
per day is expected to provide stronger support to WTI/WCS differentials going forward. Current WTI/WCS differentials have
tightened to less than USD 16 per barrel for the remainder of 2023 and the whole of 2024 as a result of these favourable market
developments.
Gas markets weakened significantly during the first quarter of 2023. IPC’s average realised gas price was CAD 3.10 per Mcf
compared with CAD 5.90 per Mcf during the fourth quarter of 2022. The recent weakness seen in North American gas prices,
was to a large extent, driven by a much milder winter in Europe and the reduced demand for US LNG as a result. IPC was partially
protected by AECO gas price hedges that were put in place when gas prices were much stronger in late 2022: 33.7 MMcf per day
at CAD 6.26 per Mcf in Q1 2023 and at CAD 4.10 per Mcf from April to October 2023.
First Quarter 2023 Highlights and Full Year 2023 Guidance
During the first quarter of 2023, our assets delivered average net production of 52,800 boepd, above our high-end guidance for the
quarter and a record high for IPC. This was made possible by the very high uptime performance across all our assets as well as the
production contribution from our recent Cor4 acquisition in Canada. Given the very strong start to the year, full year 2023 average
net production is expected to be towards the upper end of the guidance range of 48,000 to 50,000 boepd.
(1)
Our operating costs per boe for the first quarter of 2023 was USD 17.3, in line with our latest guidance. Full year 2023 operating
costs per boe guidance of USD 17.5 to 18.0 per boe remains unchanged.
(1)(3)
Operating cash flow (OCF) generation for the first quarter of 2023 was USD 76 million. Full year 2023 OCF guidance of USD 250 to
495 million (assumed Brent USD 70 to 100 per barrel is unchanged).
(1)(3)
Capital and decommissioning expenditure for the first quarter of 2023 was USD 55 million in line with guidance. Full year 2023
capital and decommissioning expenditure of USD 365 million is unchanged.
(1)
Free cash flow (FCF) generation was USD 16 million during the first quarter of 2023. Full year 2023 FCF guidance of USD -145 to
105 million (assumed Brent USD 70 to 100 per barrel) remains unchanged.
(1)(3)
During the first quarter of 2023, IPC’s net cash position of USD 175 million was reduced to USD 67 million, largely driven by the
funding of USD 62 million for the Cor4 acquisition and USD 46 million for the continuing share repurchase program (NCIB).
(3) Gross
cash on the balance sheet as at March 31, 2023 amounts to USD 378 million providing a significant war chest to pursue our three
strategic pillars of returning value to stakeholders, pursuing value adding M&A and focusing on organic growth.
In addition, IPC
further strengthened its liquidity position during the first quarter by increasing its Canadian Revolving Credit Facility (RCF) from
CAD 75 to 150 million.
Phase 1 Blackrod Project
Following the successful completion of FEED studies and the continued strong production performance from well pair three during
2022, IPC took the decision in Q1 2023 to advance the development of Phase 1 of the Blackrod project. Development capital
expenditure to first oil is estimated at approximately USD 850 million (including inflation and contingencies). First oil of the Phase 1
development is estimated to be in late 2026, with forecast production of 30,000 bopd by 2028. The breakeven oil price estimated
by IPC assuming a 10% discount rate is a West Texas Intermediate (WTI) price of approximately USD 59 per barrel. Using the
December 31, 2022 price forecasts of our qualified independent reserves evaluator, Sproule Associates Limited (Sproule), the net
present value as at that date, at a 10% discount rate (after tax), of Phase 1 of the Blackrod project is USD 807 million. IPC intends
to fund the Phase 1 development with cash on hand and forecast FCF generated by its operations.
(1)(2)
During the first quarter, the Phase 1 development early ground works and the final facility engineering activities have progressed in
line with schedule and budget. Preparations to enter in the major central processing facility build contract are on track to be finalised
in the second quarter. This is expected to provide a high degree of certainty for the fixed price element of the Phase I development
capital expenditure which represents close to 50% of the overall Phase I budget to first oil.
5
===== SIDA 27 =====
Management’s Discussion and Analysis
For the three months ended March 31, 2023
M&A
During Q1 2023, IPC announced and completed its fifth acquisition in five years. IPC acquired 15.9 MMboe of 2P reserves
adjacent to our Suffield property in Alberta, Canada, through the Cor4 acquisition. This acquisition is forecast to add approximately
4,000 boepd to our Suffield area production in 2023. The producing assets are complementary to both our Suffield asset and a
recent land acquisition on the same geological trend that IPC concluded in the fourth quarter of 2022. Following these acquisitions,
we now have over 25 drilling inventory locations on the Ellerslie play fairway that extends from the west of our Suffield asset to
our new land acquisition and into the properties acquired in the Cor4 acquisition. Three wells were successfully drilled and brought
on production since the beginning of the year and we plan to drill another three wells on this exciting play in 2023. The Cor4
acquisition was completed on March 3, 2023 with the consideration funded using existing cash on hand.
(1)(2)
2023 Capital Allocation Framework
Normal Course Issuer Bid
In Q4 2022, IPC announced the renewal of the NCIB, with the ability to repurchase up to approximately 9.3 million common shares
over the twelve-month period to December 2023. IPC repurchased in December 2022 and subsequently cancelled approximately
0.73 million common shares. By the end of March 2023, IPC purchased and cancelled a further approximately 4.76 million
common shares under the NCIB. The average price of common shares purchased under the renewed NCIB during the period of
December 2022 to March 2023 was SEK 102 / CAD 13.25 per share.
As at March 31, 2023, IPC had a total of 132,069,946 common shares issued and outstanding, with no common shares held in
treasury.
2023 Capital Allocation Plans
IPC’s capital allocation framework consists of distributing to shareholders a minimum of 40% of the FCF generated by the
business, provided that IPC’s net debt to EBITDA ratio is at or below 1 time.
(3) These shareholder distributions are planned to be
implemented by continued share repurchases under the NCIB as well as the consideration by IPC of other forms of shareholder
distributions, subject to further applicable regulatory and corporate approvals.
Despite the higher level of capital investment, and notwithstanding the capital allocation framework described above, IPC plans
to continue to purchase and cancel common shares under the NCIB to the remaining limit as at March 31, 2023 of 3.8 million
common shares by the end of December 2023, resulting in the anticipated cancellation of 7% of shares outstanding as of
December 2022. We believe a combination of materially growing our 2P reserves, production and asset value whilst reducing our
share count is a winning combination for shareholders.
Environmental, Social and Governance (ESG) Performance
During the first quarter of 2023, IPC recorded no material safety or environmental incidents.
As previously announced, IPC targets a reduction of our net GHG emissions intensity by the end of 2025 to 50% of IPC’s 2019
baseline and IPC remains on track to achieve this reduction. During the first quarter of 2023, IPC extended our commitment to
remain at 2025 levels of 20 kg CO
2/boe through to the end of 2027.
Notes:
(1) See “Supplemental Information regarding Product Types” in “Reserves and Resources Advisory” below
. See also the
annual information form for the year ended December 31, 2022 (AIF) available on IPC’s website at www.international-
petroleum.com and under IPC’s profile on SEDAR at www.sedar.com. IPC completed the acquisition of Cor4 on March
3, 2023. The Financial Statements have been prepared on that basis, with revenues and expenses related to the assets
acquired in the Cor4 acquisition included in the Financial Statements from March 3, 2023. Certain historical and forecast
operational and financial information included in the MD&A, including production, reserves, operating costs, OCF , FCF
and EBITDA related to the assets acquired in the Cor4 acquisition, are reported based on the effective date of the Cor4
acquisition of January 1, 2023.
(2)
See ”Reserves and Resources Advisory” below. Further information with respect to IPC’
s reserves, contingent resources
and estimates of future net revenue, including assumptions relating to the calculation of NPV, are described in the AIF . 2P
reserves as at December 31, 2022 of 487 MMboe includes 471 MMboe attributable to IPC’s oil and gas assets and 15.9
MMboe attributable to the oil and gas assets acquired in the Cor4 acquisition.
(3)
Non-IFRS measure, see “Non-IFRS Measures” below.
6
===== SIDA 28 =====
Management’s Discussion and Analysis
For the three months ended March 31, 2023
Operations Overview
Reserves and Resources
The 2P reserves attributable to IPC’s oil and gas assets are 487 MMboe as at December 31, 2022, with 471 MMboe certified by
independent third party reserve auditors and 15.9 MMboe related to the Cor4 acquisition audited by an internal qualified reserves
auditor. The proved plus probable reserve life index (RLI) as at December 31, 2022, is approximately 27 years. Best estimate
contingent resources as at December 31, 2022, are 1,162 MMboe (unrisked). See “Reserves and Resources Advisory” below.
With the acquisition of the Cor4 assets in the Suffield area and the major investment associated with the sanction of the
Blackrod Phase 1 development in 2023, IPC has set a reduced base business capital budget for the year. In Canada, the Blackrod
Phase 1 development commenced in Q1 with early works in line with schedule and budget. In the Suffield area, oil well drilling
commenced with three out of the six planned Ellerslie play wells drilled in Q1 2023. In France, drilling operations that commenced
in 2022 have been successfully completed with all three Villeperdue West oil wells in the early stages of clean up with results
expected in Q2 2023. The planned Merisier side-track well has also been successfully completed and is expected online in Q2
2023. In Malaysia, evaluation of a potential next phase of field development is progressing in line with schedule. IPC remains
focused on organic growth and continues to mature future development projects across all operated assets, with a significant
portfolio of drilling and optimisation opportunities ready for sanction at the discretion of the Group.
Production
A new average daily net production record of 52,800 boepd was achieved in the first quarter of 2023. In Canada, both the Suffield
oil and gas producing assets continue to deliver strong results. Production optimisation activity at Suffield Gas was supported
by a more moderate freeze-off period in Q1 2023. This was supplemented by initial strong production performance at the newly
acquired Suffield Cor4 assets. In addition, in Malaysia the Bertam field continued to deliver excellent results with production well
rate optimisation activity and high facility uptime. In France, a short duration disruption from protestors was experienced in March
that had a minor negative impact on production.
With the exceptional production performance in Q1 2023 above high end guidance, full year 2023 average net production is
expected to be at the upper end of the original guidance range of 48,000 to 50,000 boepd.
The production during Q1 2023 with comparatives is summarized below:
Production
in Mboepd
Three months ended
March 31
Year ended
December 31
2023 2022 2022
Crude oil
Canada – Northern Assets 15.8 14.8 15.6
Canada – Southern Assets1 12.7 8.4 8.7
Malaysia 5.1 4.1 5.3
France 2.5 2.9 2.7
Total crude oil production 36.1 30.2 32.3
Gas
Canada – Northern Assets 0.4 0.1 0.1
Canada – Southern Assets 16.3 15.5 16.2
Total gas production 16.7 15.6 16.3
Total production 52.8 45.8 48.6
Quantity in MMboe 4.75 4.12 17.74
1 Includes production from the Cor4 assets in the Suffield area from January 1, 2023. The acquisition of Cor4 was completed on March 3, 2023.
See “Supplemental Information regarding Product Types” in “Reserves and Resources Advisory”.
7
===== SIDA 29 =====
Management’s Discussion and Analysis
For the three months ended March 31, 2023
CANADA
Production
in Mboepd WI
Three months ended
March 31
Year ended
December 31
2023 2022 2022
- Oil Onion Lake Thermal 100% 13.3 11.9 12.7
- Oil Suffield Area1 100% 10.7 7.4 7.1
- Oil Ferguson 100% 2.0 1.0 1.6
- Oil Other 50-100% 2.5 2.9 2.9
- Gas1 ~100%2 16.7 15.6 16.3
Canada 45.2 38.8 40.6
1 Including the production contribution of the Cor4 acquisition from the effective date of January 1, 2023. The acquisition of Cor4 was completed
on March 3, 2023.
2 On a well count basis
Production
Net production from IPC’s Canadian assets during Q1 2023 was ahead of guidance at 45,200 boepd primarily due to strong
performance from the Suffield area assets. Production optimisation activity at Suffield Gas was supported by a more moderate
freeze off period in Q1 2023. This was supplemented by initial strong production performance at the newly acquired Cor4 assets
in the Suffield area. Stable operational performance and high production uptimes continued at the Onion Lake Thermal asset in Q1
2023.
Organic Growth and Capital Projects
In Canada, the Blackrod Phase 1 development has been sanctioned with civil works and the main central processing facility
build (engineering, procurement and fabrication) scheduled to commence in Q3 2023. A reduced base business budget for the
remainder of the assets in Canada has been set for the year with a focus on oil well drilling in the Suffield Ellerslie formation and
the completion of the next production sustaining Pad L at Onion Lake Thermal.
In Q1 2023 at Blackrod, the Phase 1 development early ground works and final facility engineering activity have progressed in line
with schedule and budget. Preparations to enter into the major central processing facility build contract are on track to be finalised
in Q2 2023.
At Suffield, three out of six of the planned Ellerslie play wells in 2023 have been drilled and brought online with encouraging
indications as the wells clean up.
At Onion Lake Thermal, the next sustaining production Pad L completion, facility works and tie ins are progressing in line with
expectations with first oil from the Pad expected in Q4 2023.
MALAYSIA
Production
in Mboepd WI
Three months ended
March 31
Year ended
December 31
2023 2022 2022
Bertam 100% 5.1 4.1 5.3
Production
Strong performance in Q1 2023 from Bertam field on Block PM307 with average net production ahead of guidance at 5,100 boepd.
Exceptional facility and well performance continued with facility uptimes registered in excess of 99%.
Organic Growth and Capital Projects
In Malaysia, a limited capital budget was set for 2023 with our focus now on studying the remaining undeveloped potential of the
Bertam field following the successful results from the latest development drilling campaign in the north east of the field.
8
===== SIDA 30 =====
Management’s Discussion and Analysis
For the three months ended March 31, 2023
FRANCE
Production
in Mboepd WI
Three months ended
March 31
Year ended
December 31
2023 2022 2022
France
- Paris Basin 100%1 2.1 2.5 2.4
- Aquitaine 50% 0.4 0.4 0.3
2.5 2.9 2.7
1 Except for the working interest in the Dommartin Lettree field of 43%
Production
Net production in France during Q1 2023 was in line with the guidance at 2,500 boepd. Production was curtailed for a short
duration in March 2023 with political protests impacting oil export trucking and refining operations.
Organic Growth
In France, at the end of Q1 2023, all three planned Villeperdue West oil wells have been successfully completed and brought
online. The wells are cleaning up. The planned Merisier side-track oil well has also been successfully drilled and is expected online
in Q2 2023.
IPC continues to mature future development projects in France, with focus towards the undeveloped resource base within the
Paris Basin.
9
===== SIDA 31 =====
Management’s Discussion and Analysis
For the three months ended March 31, 2023
FINANCIAL REVIEW
Financial Results
Selected Annual Financial Information
Selected consolidated statement of operations is as follows:
USD Thousands Q1-23 Q4-22 Q3-22 Q2-22 Q1-22 Q4-21 Q3-21 Q2-21
Revenue 192,516 255,200 299,361 315,540 259,782 215,296 172,551 144,278
Gross profit 64,383 95,411 140,489 161,709 119,100 79,469 58,636 34,286
Net result 39,563 61,183 90,503 105,217 80,822 66,918 30,557 21,693
Earnings per share – USD 0.29 0.45 0.63 0.70 0.52 0.43 0.20 0.14
Earnings per share fully
diluted – USD 0.28 0.44 0.62 0.68 0.51 0.42 0.19 0.14
Operating cash flow1 75,900 113,668 171,654 192,515 145,110 110,687 91,365 66,959
Free cash flow1 16,259 65,288 116,681 151,792 96,479 86,960 76,607 50,366
EBITDA1 76,079 125,651 174,328 194,038 145,463 110,087 89,223 65,181
Net cash / (debt) at period end1 66,956 175,098 88,615 14,382 (42,367) (94,312) (161,199) (240,617)
1 See definition on page 17 under “Non-IFRS measures”
Summarized consolidated balance sheet information is as follows:
USD Thousands March 31, 2023 December 31, 2022
Non-current assets 1,172,564 1,041,051
Current assets 534,118 638,566
Total assets 1,706,682 1,679,617
Total non-current liabilities 603,511 564,381
Current liabilities 161,853 149,905
Total liabilities 765,364 714,286
Net assets 941,318 965,331
Working capital (including cash) 372,265 488,661
10
===== SIDA 32 =====
Management’s Discussion and Analysis
For the three months ended March 31, 2023
Selected Interim Financial Information
The Group operates within several geographical areas. Operating segments are reported at a country level, with Canada being
further analyzed by main areas: (i) Canada – Northern Assets (comprising mainly of the Onion Lake Thermal asset) and (ii) Canada –
Southern Assets (comprising of the Suffield assets (including the Cor4 acquisition) and the Ferguson asset). This is consistent with
the internal reporting provided to IPC management. The following tables present certain segment information.
Three months ended – March 31, 2023
USD Thousands Canada –
Northern Assets
Canada –
Southern Assets Malaysia1 France Other Total
Crude oil 95,829 51,902 17,671 15,131 – 180,533
NGLs – 190 – – – 190
Gas 94 20,389 – – – 20,483
Net sales of oil and gas 95,923 72,481 17,671 15,131 – 201,206
Change in under/over lift position – – – 2,670 – 2,670
Royalties (10,819) (7,846) – (1,474) – (20,139)
Hedging settlement 636 7,948 – – – 8,584
Other operating revenue – 6 – 189 – 195
Revenue 85,740 72,589 17,671 16,516 – 192,516
Operating costs (25,033) (34,498) (8,176) (7,738) – (75,445)
Cost of blending (40,740) (7,077) – – – (47,817)
Change in inventory position (461) 39 5,872 285 – 5,735
Depletion1 3,105 (582) (5,829) (3,133) – (6,439)
Depreciation of other assets – – (2,558) – – (2,558)
Exploration and business
development costs – (831) – – (778) (1,609)
Gross profit/(loss) 22,611 29,640 6,980 5,930 (778) 64,383
1 In Canada, includes an adjustment for accelerated decommissioning activities funded by a non cash site rehabilitation program.
Three months ended – March 31, 2022
USD Thousands Canada –
Northern Assets
Canada –
Southern Assets Malaysia1 France Other Total
Crude oil 124,307 66,923 36,014 33,659 – 260,903
NGLs – 227 – – – 227
Gas 265 29,951 – – – 30,216
Net sales of oil and gas 124,572 97,101 36,014 33,659 – 291,346
Change in under/over lift position – – – (6,113) – (6,113)
Royalties (15,065) (8,923) – (1,524) – (25,512)
Hedging settlement 147 (403) – – – (256)
Other operating revenue – 101 – 216 – 317
Revenue 109,654 87,876 36,014 26,238 – 259,782
Operating costs (25,220) (27,216) (9,586) (9,439) – (71,461)
Cost of blending (32,938) (9,703) – – – (42,641)
Change in inventory position 1,323 (395) 2,136 489 – 3,553
Depletion (7,887) (9,972) (6,689) (3,404) – (27,952)
Depreciation of other assets – – (2,080) – – (2,080)
Exploration and business
development costs – – – – (101) (101)
Gross profit/(loss) 44,932 40,590 19,795 13,884 (101) 119,100
11
===== SIDA 33 =====
Management’s Discussion and Analysis
For the three months ended March 31, 2023
Three months ended March 31, 2023, Review
Revenue
Total revenue amounted to USD 192,516 thousand for Q1 2023, compared to USD 259,782 thousand for Q1 2022 and is analyzed
as follows:
USD Thousands
Three months ended March 31
2023 2022
Crude oil sales 180,533 260,903
Gas and NGL sales 20,673 30,443
Change in under/overlift position 2,670 (6,113)
Royalties (20,139) (25,512)
Hedging settlement 8,584 (256)
Other operating revenue 195 317
Total revenue 192,516 259,782
The main components of total revenue for Q1 2023 and Q1 2022, respectively, are detailed below.
Crude oil sales
Three months ended – March 31, 2023
USD Thousands Canada –
Northern Assets
Canada –
Southern Assets Malaysia France Total
Crude oil sales
- Revenue in USD thousands 95,829 51,902 17,671 15,131 180,533
- Quantity sold in bbls 1,914,797 976,258 205,338 185,934 3,282,327
- Average price realized USD per bbl 50.05 53.16 86.06 81.38 55.00
Three months ended – March 31, 2022
USD Thousands Canada –
Northern Assets
Canada –
Southern Assets Malaysia France Total
Crude oil sales
- Revenue in USD thousands 124,307 66,923 36,014 33,659 260,903
- Quantity sold in bbls 1,578,764 849,717 290,293 351,323 3,070,097
- Average price realized USD per bbl 78.74 78.76 124.06 95.81 84.98
Crude oil revenue was 31% lower in Q1 2023 compared to Q1 2022 mainly due to lower oil prices and a higher differential on
Canadian pricing in Q1 2023 compared to Q1 2022.
The Suffield area assets and Onion Lake crude oil in Canada are blended with purchased condensate diluent volumes
to meet pipeline specifications. As a result of the blended volumes, actual sales volumes are higher than produced volumes for
Canada. The Canadian realized sales price is based on the Western Canadian Select (“WCS”) price which trades at a discount to
West Texas Intermediate (“WTI”). For Q1 2023, WTI averaged USD 76 per bbl compared to USD 95 per bbl for Q1 2022 and the
average discount to WCS used in our pricing formula was USD 25 per bbl compared to USD 15 per bbl for Q1 2022.
The realized sales price for Malaysia and France is based on Dated Brent crude oil prices. There was one cargo lifting in Malaysia
during Q1 2023 in March 2023 and one cargo lifting in Q1 2022. Produced unsold oil barrels from Bertam at the end of Q1 2023
amounted to 275,000 barrels, see Change in Inventory Position section below. There was no Aquitaine cargo in France lifted in Q1
2023 compared to one in Q1 2022. The average Dated Brent crude oil price was USD 81 per bbl for Q1 2023 compared to USD
102 per bbl for the comparative period.
12
===== SIDA 34 =====
Management’s Discussion and Analysis
For the three months ended March 31, 2023
Gas and NGL sales
Three months ended – March 31, 2023
Canada –
Southern Assets
Canada –
Northern Assets Total
Gas and NGL sales
- Revenue in USD thousands 20,579 94 20,673
- Quantity sold in Mcf 7,645,299 53,049 7,698,348
- Average price realized USD per Mcf 2.69 1.76 2.69
Three months ended – March 31, 2022
Canada –
Southern Assets
Canada –
Northern Assets Total
Gas and NGL sales
- Revenue in USD thousands 30,178 265 30,443
- Quantity sold in Mcf 7,670,925 66,189 7,737,114
- Average price realized USD per Mcf 3.93 4.00 3.93
Gas and NGL sales revenue was 32% lower for Q1 2023 compared to Q1 2022 mainly due to the lower achieved gas price.
IPC’s achieved gas price is based on AECO pricing plus a premium. For Q1 2023, IPC realized an average price of CAD 3.60 per
Mcf compared to AECO average pricing of CAD 3.17 per Mcf.
Hedging settlement
IPC enters into risk management contracts in order to ensure a certain level of cash flow. It focuses mainly on oil price swaps to
limit pricing exposure. The oil and gas pricing contracts are not entered into for speculative purposes.
The realized hedging settlement for Q1 2023 amounted to a gain of USD 8,584 thousand and consisted of a gain of USD 1,679
thousand on the oil contracts and a gain of USD 6,905 thousand on the gas contracts. Also see the Financial Position and Liquidity
and the Financial Risk Management sections below.
Other operating revenue
Other operating revenue amounted to USD 195 thousand for Q1 2023 compared to USD 317 thousand for Q1 2022 and mainly
consists of tariff income and fees for strategic storage of inventory in France.
Production costs
Production costs including inventory movements amounted to USD 117,527 thousand for Q1 2023 compared to USD 110,549
thousand for Q1 2022 and is analyzed as follows:
Three months ended – March 31, 2023
USD Thousands Canada –
Southern Assets
Canada –
Northern Assets Malaysia France Other 3 Total
Operating costs1 34,498 25,033 12,226 7,738 (4,050) 75,445
USD/boe2 15.80 17.16 26.76 34.52 n/a 17.31
Cost of blending 7,077 40,740 – – – 47,817
Change in inventory position (39) 461 (5,872) (285) – (5,735)
Production costs 41,536 66,234 6,354 7,453 (4,050) 117,527
13
===== SIDA 35 =====
Management’s Discussion and Analysis
For the three months ended March 31, 2023
Three months ended – March 31, 2022
USD Thousands Canada –
Southern Assets
Canada –
Northern Assets Malaysia France Other 3 Total
Operating costs1 27,216 25,220 13,636 9,439 (4,050) 71,461
USD/boe2 12.63 18.83 36.71 36.76 n/a 17.33
Cost of blending 9,703 32,938 – – – 42,641
Change in inventory position 395 (1,323) (2,136) (489) – (3,553)
Production costs 37,314 56,835 11,500 8,950 (4,050) 110,549
1 See definition on page 17 under “Non-IFRS measures”.
2 USD/boe in the tables above is calculated by dividing the cost by the production volume for each country for the period and includes Cor4 from
January 1, 2023.
3 Included in the Malaysia operating costs is the lease cost for the FPSO Bertam which is owned by the Group. Other represents the FPSO Bertam
lease fee self-to-self payment elimination. Netting the self-to-self elimination against the operating costs in Malaysia reduces the operating costs
per boe for Malaysia to USD 17.90 and USD 25.80 for Q1 2023 and Q1 2022 respectively.
Operating costs
Operating costs amounted to USD 75,445 thousand for Q1 2023 compared to USD 71,461 thousand for Q1 2022. The increase in
costs in Q1 2023 compared to Q1 2022 is due mainly to higher electricity prices. Operating costs per boe amounted to USD 17.31
per boe in Q1 2023 in line with CMD guidance for the quarter and compared with USD 17.33 per boe in Q1 2022. The full year
CMD guidance of USD 17.5 to 18 per boe remains unchanged.
Cost of blending
For the Suffield area assets in Canada, oil production is blended with purchased condensate diluent to meet pipeline specifications.
As a result of the blending, actual sales volumes are higher than produced barrels and the realized sales price of a blended barrel
is higher than an unblended barrel. The majority of Onion Lake oil production is also blended and exported by pipeline since April
2022 with the commissioning of a third party export pipeline from the Onion Lake field to the gathering system.
The cost of the diluent net of proceeds from the sale of surplus diluent amounted to USD 47,817 thousand for Q1 2023 compared
to USD 42,641 thousand for Q1 2022. The increase versus the comparative period is attributable to larger Onion Lake blending
volumes in Q1 2023 with less volumes blended in Q1 2022 when the export pipeline for blended barrels was being commissioned.
Change in inventory position
The Bertam field in Malaysia is located offshore and production is lifted and sold from the FPSO Bertam when a cargo parcel size
is reached. Accordingly, the timing of a lifting varies based on the inventory level on the FPSO facility and the change in inventory
position varies, both positively and negatively, from period to period. Inventories are valued at the lower of cost including depletion,
and market value, and the difference in the valuation between period ends is reflected in the change in inventory position in the
statement of operations. At the end of Q1 2023, IPC had crude entitlement of 275,000 barrels of oil on the FPSO Bertam facility
(crude produced but unsold). One crude cargo was lifted from Bertam in early March 2023 with the next lifting in April 2023.
Depletion and decommissioning costs
The total depletion of oil and gas properties amounted to USD 6,439 thousand for Q1 2023 (including an adjustment for
accelerated decommissioning activities amounting to USD 24,178 thousand) compared to USD 27,952 thousand for Q1 2022. The
depletion charge is analyzed in the following tables:
Three months ended – March 31, 2023
USD Thousands Canada –
Southern Assets
Canada –
Northern Assets Malaysia France Total
Depletion cost in USD thousands1 12,302 9,353 5,829 3,133 30,617
USD per boe2 5.65 6.41 12.76 13.98 6.96
Three months ended – March 31, 2022
USD Thousands Canada –
Southern Assets
Canada –
Northern Assets Malaysia France Total
Depletion cost in USD thousands 9,972 7,887 6,689 3,404 27,952
USD per boe2 4.63 5.89 18.01 13.26 6.78
1 In Canada, excludes the adjustment for accelerated decommissioning activities.
2 USD/boe in the tables above is calculated by dividing the depletion cost by the production volume for each country for the period and includes
Cor4 from January 1, 2023.
14
===== SIDA 36 =====
Management’s Discussion and Analysis
For the three months ended March 31, 2023
The depletion charge is derived by applying the depletion rate per boe to the volumes produced in the period by each field. The
depletion rate in Malaysia has significantly decreased compared to the prior year following the extension to the Bertam field
production sharing contract and consequent increase in field reserves announced at the end of 2022. In addition, the depletion rate
in Canada has increased compared to the prior year as a result of the Cor4 acquisition.
Depreciation of other tangible fixed assets
The total depreciation of other assets amounted to USD 2,558 thousand for Q1 2023 compared to USD 2,080 thousand for
Q1
2022. This relates to the depreciation of the FPSO Bertam, which is being depreciated on a unit of production basis based on
the Bertam field reserves cut-off at August 2025.
Exploration and business development costs
The total exploration and business developments costs amounted to USD 1,609 thousand for Q1 2023. These costs mainly related
to Cor4 acquisition related costs amounting to USD 831 thousand and to other business development costs.
General, administrative and depreciation expenses
General, administrative and depreciation expenses amounted to USD 4,194 thousand for the three months ended March 31, 2023
compared to USD 4,173 thousand for the three months ended March 31, 2022.
Net financial items
Net financial items amounted to a charge of USD 5,015 thousand for Q1 2023, compared to a charge of USD 6,607 thousand
for Q1 2022, and included a non-cash net foreign exchange loss of USD 856 thousand for Q1 2023 compared to a net foreign
exchange gain of USD 3,059 thousand for Q1 2022. The foreign exchange movements during Q1 2023 are mainly resulting from
the revaluation of intra-group loan funding balances.
Excluding foreign exchange movements, the net financial items amounted to a charge of USD 4,159 thousand for Q1 2023,
compared to a charge of USD 9,666 thousand for Q1 2022.
The interest expense amounted to USD 5,349 thousand for Q1 2023, compared to USD 4,034 thousand for the comparative period
in 2022. Interest income generated on cash balances held in Q1 2023 amounted to USD 4,924 thousand.
The unwinding of the asset retirement obligation discount rate amounted to USD 3,068 thousand for Q1 2023, compared to
USD
2,760 thousand for Q1 2022.
Income tax
The corporate income tax amounted to a charge of USD 15,611 thousand for Q1 2023, compared to a charge of USD 27,498
thousand for Q1 2022 and included deferred taxes of USD 11,620 thousand and USD 23,375 thousand respectively
.
The current income tax charge amounted to USD 3,991 thousand in Q1 2023 and mainly related to France and Malaysia. No
corporate income tax was payable in Canada in respect of Q1 2023 due to the usage of historical tax pools. On September 30,
2022, the Council of the European Union (“EU“) agreed to impose an EU-wide windfall profits tax on energy companies deriving
income from operations in EU countries (“Solidarity Contribution”) in 2022 and potentially 2023. The current tax charge in Q1 2023
includes a Solidarity Contribution provision relating to the income in France of USD 754 thousand.
15
===== SIDA 37 =====
Management’s Discussion and Analysis
For the three months ended March 31, 2023
Capital Expenditure
Development and exploration and evaluation expenditure incurred in Q1 2023 was as follows:
USD Thousands Canada –
Southern Assets
Canada –
Northern Assets Malaysia France Total
Development 4,538 30,907 664 12,129 48,238
Capital expenditure of USD 48,238 thousand was mainly spent in Canada on the Blackrod Phase 1 Development project and on the
Pad L completion at Onion Lake Thermal and in France on the drilling of the Villeperdue West oil wells.
An additional USD 5,821 thousand of capital expenditure was spent on the Cor4 assets mainly on drilling from January 1, 2023 to
the completion date of March 3, 2023.
Cor4 Acquisition
On March 3, 2023, IPC completed the acquisition of all of the issued and outstanding shares of Cor4 Oil Corp. (“Cor4”). At such
date, Cor4 became an indirect wholly-owned subsidiary of IPC.
The Cor4 acquisition has been accounted for as a business combination with IPC being the acquirer, and in accordance with IFRS 3
Business Combinations, the assets acquired and liabilities assumed have been recorded at their fair values.
Total cash consideration paid, after preliminary closing adjustments, amounted to USD 62.0 million (CAD 84.3 million).
The amounts recognized in respect of the identifiable assets acquired and liabilities assumed are as set out in the table below.
USD Thousands
Cash 2,792
Trade and other receivables 7,671
Prepaid expenses and deposits 2,417
Fair value of risk management assets 1,144
Deferred tax assets 19,334
Right-of-use assets 109
Property, plant and equipment 72,003
Accounts payable and accrued liabilities (12,623)
Right-of-use liabilities (109)
Decommissioning liabilities (29,885)
Mark-To-Market reserve in equity (881)
Total Consideration 61,972
Settled by:
Cash payment 61,972
The Corporation performed a preliminary purchase price allocation for the Cor4 acquisition. The amounts disclosed above were
determined provisionally pending the finalization of the valuation for those assets and liabilities. Up to twelve months from the
effective date of the Cor4 acquisition, further adjustments may be made to the fair values assigned to the identifiable assets
acquired and liabilities assumed.
Acquisition-related costs of approximately USD 0.8 million have been recognized in the statement of operations during Q1 2023.
Decommissioning liabilities
The fair value of the decommissioning liability at the acquisition date was based on the estimated future cash flows to
decommission the acquired oil and natural gas properties at the end of their useful life. The discount rate used to determine the
net present value of the decommissioning obligation was a credit risk adjusted rate of 8%.
Other tangible fixed assets
Other tangible fixed assets amounted to USD 31,266 thousand as at March 31, 2023, which included USD 29,402 thousand in
respect of the FPSO Bertam. The FPSO Bertam is being depreciated on a unit of production basis based on the Bertam field
reserves cut-off at August 2025.
16
===== SIDA 38 =====
Management’s Discussion and Analysis
For the three months ended March 31, 2023
Financial Position and Liquidity
Financing
As at March 31, 2023, IPC had a EUR 13 million unsecured credit facility in France (the “France Facility“), with maturity in May
2026. IPC commenced quarterly repayments of the French Facility in August 2022. The amount remaining outstanding under the
France Facility as at March 31, 2023 was USD 12 million (EUR 11 million).
In February 2022, IPC completed the issuance of USD 300 million of Bonds, which mature in February 2027 and have a fixed
coupon rate of 7.25% per annum, payable in semi-annual instalments in August and February. The Group used a portion of the
proceeds of the Bonds to fully repay the outstanding RBL credit facilities, which were then cancelled. At the same time, the Group
entered into a revolving credit facility of CAD 75 million (the “Canadian RCF”) in connection with its oil and gas assets in Canada.
In Q1 2023, the Group increased the Canadian RCF to CAD 150 million and extended the maturity to May 2025. No cash amounts
were drawn under the Canadian RCF as at March 31, 2023.
Total net cash as at March 31, 2023 amounted to USD 67 million.
IPC intends to fund the Blackrod Phase 1 development with cash on hand and forecast FCF generated by its operations.
The Bond repayment obligations as at March 31, 2023, are classified as non-current as there are no mandatory repayments within
the next twelve months.
An amount of USD 3.5 million (EUR 3.2 million) drawn under the France Facility as at March 31, 2023 is classified as current
representing the repayment planned within the next twelve months.
The Group is in compliance with the covenants of the Bonds and its financing facilities as at March 31, 2023.
Cash and cash equivalents held amounted to USD 378 million as at March 31, 2023 of which USD 8.2 million was restricted.
Working Capital
As at March 31, 2023, the Group had a net working capital balance including cash of USD 372,265 thousand compared to USD
488,661 thousand as at December 31, 2022. The difference as at March 31, 2023, from December 31, 2022, is mainly a result of
the lower cash balances held following the Cor4 acquisition and the continuing NCIB program.
Non-IFRS Measures
In addition to using financial measures prescribed under IFRS, references are made in this MD&A to “operating cash flow”, “free
cash flow”, “EBITDA”, “operating costs” and “net debt”/”net cash”, which are non-IFRS measures. Non-IFRS measures do
not have any standardized meaning prescribed by IFRS and therefore may not be comparable to similar measures presented by
other public companies. Non-IFRS measures should not be considered in isolation or as a substitute for measures prepared in
accordance with IFRS.
The Corporation uses non-IFRS measures to provide investors with supplemental measures to assess cash generated by and
the financial performance and condition of the Corporation. Management also uses non-IFRS measures internally in order to
facilitate operating performance comparisons from period to period, prepare annual operating budgets and assess the Group’s
ability to meet its future capital expenditure and working capital requirements. Management believes these non-IFRS measures
are important supplemental measures of operating performance because they highlight trends in the core business that may
not otherwise be apparent when relying solely on IFRS financial measures. Management believes such measures allow for
assessment of the Group’s operating performance and financial condition on a basis that is more consistent and comparable
between reporting periods. The Corporation also believes that securities analysts, investors and other interested parties
frequently use non-IFRS measures in the evaluation of public companies. Forward-looking statements are provided for the
purpose of presenting information about management’s current expectations and plans relating to the future and readers are
cautioned that such statements may not be appropriate for other purposes.
“Operating cash flow” is calculated as revenue less production costs less current tax. Operating cash flow is used to analyze the
amount of cash that is being generated available for capital investment and servicing debt.
“Free cash flow” is calculated as operating cash flow less capital expenditures less decommissioning and farm-in expenditures
less general, administration and depreciation expenses before depreciation and less cash financial items. Free cash flow is used
to analyze the amount of cash that is being generated by the business and that is available for such purposes as repaying debt,
funding acquisitions and returning capital to shareholders.
“EBITDA” is calculated as net result before financial items, taxes, depletion of oil and gas properties, exploration costs,
impairment costs and depreciation and adjusted for non-recurring profit/loss on sale of assets and other income.
“Operating cost” is calculated as production costs excluding any change in the inventory position and the cost of blending and is
used to analyze the cash cost of producing the oil and gas volumes.
“Net debt” is calculated as bank loans and Bonds less cash and cash equivalents. “Net cash” is calculated as cash and cash
equivalents less bank loans and Bonds.
17
===== SIDA 39 =====
Management’s Discussion and Analysis
For the three months ended March 31, 2023
Reconciliation of Non-IFRS Measures
Operating cash flow
The following table sets out how operating cash flow is calculated from figures shown in the Financial Statements:
USD Thousands
Three months ended March 31
2023 2022
Revenue 192,516 259,782
Production costs (117,527) (110,549)
Current tax (3,991) (4,123)
Operating cash flow 70,998 145,110
The operating cash flow for the three months ended March 31, 2023 including the operating cash flow contribution of the Cor4
acquisition from the effective date of January 1, 2023 to the completion date of March 3, 2023 amounts to USD 75,900 thousand.
Free cash flow
The following table sets out how free cash flow is calculated from figures shown in the Financial Statements:
USD Thousands
Three months ended March 31
2023 2022
Operating cash flow - see above 70,998 145,110
Capital expenditures (48,238) (38,353)
Abandonment and farm-in expenditures1 (1,211) (1,925)
General, administration and depreciation expenses before depreciation2 (3,811) (3,770)
Cash financial items3 (648) (4,581)
Free cash flow 17,090 96,481
1 See note 17 to the Financial Statements
2 Depreciation is not specifically disclosed in the Financial Statements
3 See notes 4 and 5 to the Financial Statements.
The free cash flow for the three months ended March 31, 2023 including the free cash flow contribution of the Cor4 acquisition
from the effective date of January 1, 2023 to the completion date of March 3, 2023 amounts to USD 16,259 thousand.
EBITDA
The following table sets out the reconciliation from net result from the consolidated statement of operations to EBITDA:
USD Thousands
Three months ended March 31
2023 2022
Net result 39,563 80,822
Net financial items 5,015 6,607
Income tax 15,611 27,498
Depletion 6,439 27,952
Depreciation of other tangible fixed assets 2,558 2,080
Exploration and business development costs 1,609 101
Depreciation included in general, administration and depreciation
expenses1 383 403
EBITDA 71,178 145,463
1 Item is not shown in the Financial Statements.
18
===== SIDA 40 =====
Management’s Discussion and Analysis
For the three months ended March 31, 2023
The EBITDA for the three months ended March 31, 2023 including the EBITDA contribution of the Cor4 acquisition from the
effective date of January 1, 2023 to the completion date of March 3, 2023 amounts to USD 76,079 thousand.
Operating costs
The following table sets out how operating costs is calculated:
USD Thousands
Three months ended March 31
2023 2022
Production costs 117,527 110,549
Cost of blending (47,817) (42,641)
Change in inventory position 5,735 3,553
Operating costs 75,445 71,461
The operating costs for the three months ended March 31, 2023 including the operating costs contribution of the Cor4 acquisition
from the effective date of January 1, 2023 to the completion date of March 3, 2023 amounts to USD 82,246 thousand.
Net cash
The following table sets out how net cash is calculated from figures shown in the Financial Statements:
USD Thousands March 31, 2023 December 31, 2022
Bank loans (11,510) (12,142)
Bonds (300,000) (300,000)
Cash and cash equivalents 378,466 487,240
Net cash 66,956 175,098
Off-Balance Sheet Arrangements
IPC, through its subsidiary IPC Canada Ltd, has issued three letters of credit as follows: (a) CAD 2.6 million in respect of its
obligations to purchase diluent; (b) CAD 0.8 million in respect of its obligations related to the Ferguson asset, increasing by
CAD
0.1 million annually to a maximum of CAD 1.0 million; and (c) CAD 1.3 million in respect of pipeline access.
Outstanding Share Data
The common shares of IPC trade on both the T
oronto Stock Exchange and the Nasdaq Stockholm Exchange.
As at January 1, 2022, IPC had a total of 155,198,105 common shares issued and outstanding, of which IPC held 1,160,651
common shares in treasury. All common shares held in treasury as at January 1, 2022 were cancelled during January 2022.
During 2022, under the normal course issuer bid/share repurchase program announced in December 2021 and renewed in
December 2022 (NCIB), IPC purchased and cancelled an aggregate of 8,951,391 common shares.
During Q2 2022, IPC commenced an offer to repurchase common shares under the substantial issuer bid (SIB). Under the SIB,
IPC purchased and cancelled an aggregate of 8,258,064 common shares.
As at December 31, 2022, IPC had a total of 136,827,999 common shares issued and outstanding, with no common shares held in
treasury.
During the Q1 2023, IPC purchased and cancelled a total of 4,758,053 common shares under the NCIB. As at March 31, 2023, IPC
had a total of 132,069,946 common shares issued and outstanding, with no common shares held in treasury.
Nemesia S.à.r.l., an investment company ultimately controlled by trusts whose settlor is the late Adolf H. Lundin, holds 40,697,533
common shares in IPC, representing 30.8% of the outstanding common shares as at May 2, 2023.
In addition, IPC has 117,485,389 outstanding class A preferred shares, issued as a part of an internal corporate structuring to a
wholly-owned subsidiary of IPC. Such preferred shares are not listed on any stock exchange and do not carry the right to vote on
matters to be decided by the holders of IPC’s common shares.
IPC has 4,554,188 IPC Share Unit Plan awards outstanding as at May 2, 2023 (10,703 awards granted in January 2020, 25,335
awards granted in July 2020, 21,216 awards granted in January 2021, 334,566 awards granted in March 2021, 1,716,000 awards
granted in May 2021, 10,067 awards granted in July 2021 and 12,543 awards granted in January 2022, 1,257,314 awards granted
in March 2022, 5,487 awards granted in July 2022, 2,072 awards granted in January 2023 and 1,158,885 awards granted in March
2023).
19
===== SIDA 41 =====
Management’s Discussion and Analysis
For the three months ended March 31, 2023
Contractual Obligations and Commitments
In Canada, an oil pipeline from the Onion Lake Thermal field to a gathering system has been built by a third party for the exclusive
use of IPC. The initial investment in the pipeline was met by the pipeline owner and is to be recovered through an agreed tariff
charged to IPC. IPC has committed to a firm transportation service for 15 years from commencement of service in April 2022, with
total remaining tariffs committed as shown in the table below:
2023 2024 2025 2026 2027 Thereafter
Transportation service (MCAD) 20.6 28.0 28.4 29.0 28.2 275.2
In Malaysia, IPC has an obligation to make payments towards historic costs on Block PM307 payable on the Bertam field for every
1 MMboe gross that the field produces above 10 MMboe gross. The estimated liability based on current 2P reserves and which is
capped at cumulative production of 27.5 MMboe gross, has been provided for in the Group’s Balance Sheet – see Note 17
Provisions of the Financial Statements.
Critical Accounting Policies and Estimates
In connection with the preparation of the Corporation’s consolidated financial statements, management has made assumptions
and estimates about future events and applied judgments that affect the reported values of assets, liabilities, revenues, expenses
and related disclosures. These assumptions, estimates and judgments are based on historical experience, current trends and other
factors that they believe to be relevant at the time the financial statements are prepared. The management reviews the accounting
policies, assumptions, estimates and judgments to ensure that the financial statements are presented fairly in accordance with
IFRS. However, because future events and their effects cannot be determined with certainty, actual results could differ from these
assumptions and estimates, and such differences could be material.
Transactions with Related Parties
During Q1 2023, there were no significant cash transactions with related parties.
All transactions with related parties are in the normal course of business and are made on the same terms and conditions as with
parties at arm’s length.
Financial Risk Management
As an international oil and gas exploration and production company, IPC is exposed to financial risks such as interest rate risk,
currency risk, credit risk, liquidity risks as well as the risk related to the fluctuation in the oil price. The Group seeks to control
these risks through sound management practice and the use of internationally accepted financial instruments, such as oil and gas
price, interest rate or foreign exchange hedges as the case may be. Financial instruments will be solely used for the purpose of
managing risks in the business. As at March 31, 2023, the Corporation had entered into oil and gas price hedges – see below.
Management believes that the cash resources, other current assets and cash flow from operations are sufficient to finance the
Group’s operations and capital expenditures program over the next year.
Capital Management
The Group’s objectives when managing capital are to safeguard the Group’s ability to continue as a going concern and to meet its
committed financial liabilities and work program requirements in order to create shareholder value. The Group may put in place
new bonds or credit facilities, repay debt, or pursue other such restructuring activities as appropriate.
Management of the Corporation will continuously monitor and manage the Group’s capital, liquidity and net debt position in order
to assess the requirement for changes to the capital structure to meet the objectives and to maintain flexibility.
Price of Oil and Gas
Prices of oil and gas are affected by the normal economic drivers of supply and demand as well as by financial investors and
market uncertainty. Factors that influence these prices include operational decisions, prices of competing fuels, natural disasters,
economic conditions, transportation constraints, political instability or conflicts or actions by major oil exporting countries. Price
fluctuations will affect the Group’s financial position.
Based on analysis of the circumstances, management assesses the benefits of forward hedging monthly sales contracts for the
purpose of protecting cash flow. If management believes that a hedging contract will appropriately help manage cash flow then it
may choose to enter into a commodity price hedge. The Group does not currently have any covenants under its current financing
facilities to hedge future production.
20
===== SIDA 42 =====
Management’s Discussion and Analysis
For the three months ended March 31, 2023
The Group had oil price sale financial hedges outstanding as at March 31, 2023, which are summarized as follows:
Period Volume (barrels per day) Type Average Pricing
April 1, 2023 – December 31, 2023 12,000 WCS/ARV Differential USD - 10.08/bbl
The Group had gas price sale financial hedges outstanding as at March 31, 2023, which are summarized as follows:
Period Volume (Gigajoules (GJ) per Day) Type Average Pricing
April 1, 2023 – October 31, 2023 35,0001 AECO Swap CAD 3.95/GJ
1 Equivalent to 33,700 Mcfpd at CAD 4.10/Mcf.
The above hedges are treated as effective and changes to the fair value are reflected in other comprehensive income. The hedges had
a positive fair value of USD 2,602 thousand as at March 31, 2023.
Currency Risk
The Group’s policy on currency rate hedging is, in the case of currency exposure, to consider fixing the rate of exchange. The
Group will take into account the currency exposure, current rates of exchange and market expectations in comparison to historic
trends and volatility in making the decision to hedge.
In October 2022, IPC entered into currency hedge swaps for 2023 to buy CAD 15 million per month, sell USD at an average
exchange rate of 1.3619 and to buy EUR 3 million per month, sell USD at an average exchange rate of 1.0000. This is to partially
fund operational expenditures in those currencies in Canada and France respectively.
The above hedge is treated as effective and changes to the fair value are reflected in other comprehensive income. The currency
hedge swaps had a positive fair value of USD 3,287 thousand as at March 31, 2023.
Interest Rate Risk
Interest rate risk is the risk to earnings due to uncertain future interest rates on borrowings. The Group will take into account the
level of external debt, current interest rates and market expectations in comparison to historic trends and volatility in making the
decision to hedge.
Credit Risk
The Group may be exposed to third party credit risk through contractual arrangements with counterparties who buy the Group’s
hydrocarbon products. The Group’s policy is to limit credit risk by only entering into oil and gas sales agreements with reputable
and creditworthy oil and gas and trading companies. Where it is determined that there is a credit risk for oil and gas sales, the
Group’s policy is to require credit enhancement from the purchaser.
The Group’s policy on joint venture parties is to rely on the provisions of the underlying joint operating agreements to take
possession of the licence or the joint venture partner’s share of production for non-payment of cash calls or other amounts due. In
addition, cash is to be held and transacted only through major banks.
RISK AND UNCERTAINTIES
IPC is engaged in the exploration, development and production of oil and gas and is exposed to various operational,
environmental, market and financial risks and uncertainties. For further information and discussion of these risks and
uncertainties, please see IPC’s Annual Information Form for the year ended December 31, 2022 (”AIF”) available on SEDAR at
www.sedar.com or on IPC’s website at www.international-petroleum.com. See also “Cautionary Statement Regarding Forward
Looking Information” and “Reserves and Resource Advisory” in this MD&A.
21
===== SIDA 43 =====
Management’s Discussion and Analysis
For the three months ended March 31, 2023
DISCLOSURE CONTROLS AND INTERNAL CONTROL OVER FINANCIAL REPORTING
Disclosure Controls and Procedures
Disclosure controls and procedures have been designed to provide reasonable assurance that information required to be
disclosed by the Corporation in its annual filings, interim filings or other reports filed or submitted by it under securities legislation
is recorded, processed, summarized and reported within the time periods specified in the securities legislation. Management,
under the supervision of the Chief Executive Officer and the Chief Financial Officer, is responsible for the design and operation of
disclosure controls and procedures.
Internal Controls over Financial Reporting
Management is also responsible for the design of the Group’s internal controls over financial reporting in order to provide reasonable
assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in
accordance with IFRS. However, due to inherent limitations, internal control over financial reporting may not prevent or detect all
misstatements and fraud.
There have been no material changes to the Groups internal control over financial reporting during the three month period ended
March 31, 2023, that have materially affected, or are reasonably likely to materially affect, the Group’s internal control over financial
reporting.
Control Framework
Management assesses the effectiveness of the Corporation’s internal control over financial reporting using the Internal Control
– Integrated Framework (2013 Framework) issued by the Committee of Sponsoring Organizations of the Treadway Commission
(COSO).
CAUTIONARY STATEMENT REGARDING FORWARD-LOOKING INFORMATION
This MD&A contains statements and information which constitute “forward-looking statements“ or “forward-looking information“
(within the meaning of applicable securities legislation). Such statements and information (together, “forward-looking statements“)
relate to future events, including the Corporation’s future performance, business prospects or opportunities. Actual results may differ
materially from those expressed or implied by forward-looking statements. The forward-looking statements contained in this MD&A
are expressly qualified by this cautionary statement. Forward-looking statements speak only as of the date of this MD&A, unless
otherwise indicated. IPC does not intend, and does not assume any obligation, to update these forward-looking statements, except
as required by applicable laws.
All statements other than statements of historical fact may be forward-looking statements. Any statements that express or
involve discussions with respect to predictions, expectations, beliefs, plans, projections, forecasts, guidance, budgets, objectives,
assumptions or future events or performance (often, but not always, using words or phrases such as “seek“, “anticipate“, “plan“,
“continue“, “estimate“, “expect“, “may“, “will“, “project“, “forecast”, “predict“, “potential“, “targeting“, “intend“, “could“,
“might“, “should“, “believe“, “budget“ and similar expressions) are not statements of historical fact and may be “forward-looking
statements“.
Forward-looking statements include, but are not limited to, statements with respect to:
•
The potential for an improved economic environment resulting from a lack of capital investment and drilling in the oil and gas
industry;
• 2023 production range, operating costs and capital and decommissioning expenditure estimates;
• Estimates of future production, cash flows, operating costs and capital expenditures that are based on IPC’s current business
plans and assumptions regarding the business environment, which are subject to change;
•
IPC’s financial and operational flexibility to continue to react to recent events and navigate the Corporation through periods of
volatile commodity prices;
•
IPC’s continued access to its existing credit facilities, including current financial headroom, on terms acceptable to the
Corporation;
•
The ability to fully fund future expenditures from cash flows and current borrowing capacity;
• IPC’s ability to maintain operations, production and business in light of the current and any pandemics and the restrictions
and disruptions related thereto, including risks related to production delays and interruptions, changes in laws and regulat
ions
and reliance on third-party operators and infrastructure;
• IPC’s intention and ability to continue to implement our strategies to build long-term shareholder value;
• The ability of IPC’s portfolio of assets to provide a solid foundation for organic and inorganic growth;
• The continued facility uptime and reservoir performance in IPC’s areas of operation;
• Future development potential of the Suffield and Ferguson operations in Canada, including the timing and success of future
oil and gas drilling and optimisation programs;
•
Development of the Blackrod project in Canada, including estimates of resource volumes, future production, timing,
regulatory approvals, third party commercial arrangements, breakeven oil prices and net present values;
•
Current and future drilling pad production and timing and success of facility upgrades, tie-in work and infill drilling at Onion
Lake Thermal;
•
The ability of IPC to achieve and maintain current and forecast production and take advantage of production growth and
development upside opportunities related to the assets acquired in the Cor4 acquisition;
• The ability of IPC to integrate the assets acquired in the Cor4 acquisition into its current operations;
• The existence of drill-ready opportunities in respect of the assets acquired in the Cor4 acquisition and their ability to add
further near-term production;
22
===== SIDA 44 =====
Management’s Discussion and Analysis
For the three months ended March 31, 2023
• The potential improvement in the Canadian oil egress situation and IPC’s ability to benefit from any such improvements;
• The timing and success of the future development projects and other organic growth opportunities in France;
• The ability to maintain current and forecast production in France;
• The ability of IPC to achieve and maintain current and forecast production in Malaysia;
• The ability to IPC to acquire further common shares under the NCIB, including the timing of any such purchases;
• The return of value to IPC’s shareholders as a result of the NCIB;
• The ability of IPC to implement further shareholder distributions in addition to the NCIB;
• IPC’s ability to implement its GHG emissions intensity and climate strategies and to achieve its net GHG emissions intensity
reduction targets;
• Estimates of reserves and contingent resources;
• The ability to generate free cash flows and use that cash to repay debt;
• IPC’s ability to identify and complete future acquisitions; and
• Future drilling and other exploration and development activities.
Statements relating to “reserves“ and “contingent resources“ are also deemed to be forward-looking statements, as they involve
the implied assessment, based on certain estimates and assumptions, that the reserves and resources described exist in the
quantities predicted or estimated and that the reserves and resources can be profitably produced in the future. Ultimate recovery
of reserves or resources is based on forecasts of future results, estimates of amounts not yet determinable and assumptions of
management. See also “Reserves and Resource Advisory“.
The forward-looking statements are based on certain key expectations and assumptions made by IPC, including expectations
and assumptions concerning: prevailing commodity prices and currency exchange rates; applicable royalty rates and tax laws;
interest rates; future well production rates and reserve and contingent resource volumes; operating costs; the timing of r
eceipt of
regulatory approvals; the performance of existing wells; the success obtained in drilling new wells; anticipated timing and results
of capital expenditures; the sufficiency of budgeted capital expenditures in carrying out planned activities; the timing, location
and extent of future drilling operations; the successful completion of acquisitions and dispositions; the benefits of acquisitions;
the state of the economy and the exploration and production business in the jurisdictions in which IPC operates and globally;
the availability and cost of financing, labour and services; and the ability to market crude oil, natural gas and natural gas liquids
successfully.
Although IPC believes that the expectations and assumptions on which such forward-looking statements are based are reasonable,
undue reliance should not be placed on the forward-looking statements because IPC can give no assurances that they will prove to
be correct. Since forward-looking statements address future events and conditions, by their very nature they involve inherent risks
and uncertainties. Actual results could differ materially from those currently anticipated due to a number of factors and risks.
These include, but are not limited to:
•
The risks associated with the oil and gas industry in general such as operational risks in development, exploration and
production;
• Delays or changes in plans with respect to exploration or development projects or capital expenditures;
• The uncertainty of estimates and projections relating to reserves, resources, production, revenues, costs and expenses;
• Health, safety and environmental risks;
• Commodity price fluctuations;
• Interest rate and exchange rate fluctuations;
• Marketing and transportation;
• Loss of markets;
• Environmental risks;
• Competition;
• Incorrect assessment of the value of acquisitions;
• Failure to complete or realize the anticipated benefits of acquisitions or dispositions;
• The ability to access sufficient capital from internal and external sources;
• Failure to obtain required regulatory and other approvals; and
• Changes in legislation, including but not limited to tax laws, royalties, environmental and abandonment regulations.
Readers are cautioned that the foregoing list of factors is not exhaustive. See also “Risk and Uncertainties”
Estimated FCF generation is based on IPC’s current business plans over the periods of 2023 to 2027 and 2028 to 2032.
Assumptions include average net production of approximately 50 Mboepd over the period of 2023 to 2027, average net production
of approximately 65 Mboepd over the period of 2028 to 2032, average Brent oil prices of USD 75 to 95 per boe escalating by 2%
per year
, and average Brent to Western Canadian Select differentials and average gas prices as estimated by IPC’s independent
reserves evaluator and as further described in the AIF . IPC’s current business plans and assumptions, and the business
environment, are subject to change. Actual results may differ materially from forward-looking estimates and forecasts.
Additional information on these and other factors that could affect IPC, or its operations or financial results, are included in the
Financial Statements, the Corporation’s Annual Information Form (AIF) for the year ended December 31, 2022, (See “Cautionary
Statement Regarding Forward-Looking Information”, “Reserves and Resources Advisory” and “Risk and Uncertainties”) and other
reports on file with applicable securities regulatory authorities, including previous financial reports, management’s discussion and
analysis and material change reports, which may be accessed through the SEDAR website (www.sedar.com) or IPC’s website
(www.international-petroleum.com).
23
===== SIDA 45 =====
Management’s Discussion and Analysis
For the three months ended March 31, 2023
RESERVES AND RESOURCES ADVISORY
This MD&A contains references to estimates of gross and net reserves and resources attributed to the Corporation’s oil and gas
assets. Gross reserves/resources are the working interest (operating or non-operating) share before deduction of royalties and
without including any royalty interests. Net reserves/resources are the working interest (operating or non-operating) share after
deduction of royalty obligations, plus royalty interests in reserves/resources, and in respect of PSCs in Malaysia, adjusted for cost
and profit oil. Unless otherwise indicated, reserves/resource volumes are presented on a gross basis.
Reserve estimates, contingent resource estimates and estimates of future net revenue in respect of IPC’s oil and gas assets in
Canada (other than the assets acquired in the Cor4 acquisition) are effective as of December 31, 2022, and are included in the
reports prepared by Sproule Associates Limited (Sproule), an independent qualified reserves evaluator, in accordance with National
Instrument 51-101 – Standards of Disclosure for Oil and Gas Activities (NI 51-101) and the Canadian Oil and Gas Evaluation
Handbook (the COGE Handbook) and using Sproule’s December 31, 2022 price forecasts.
Reserve estimates, contingent resource estimates and estimates of future net revenue in respect of IPC’s oil and gas assets in
France and Malaysia are effective as of December 31, 2022, and are included in the report prepared by ERC Equipoise Ltd. (ERCE),
an independent qualified reserves auditor, in accordance with NI 51-101 and the COGE Handbook, and using Sproule’s December
31, 2022 price forecasts.
Reserve estimates and estimates of future net revenue in respect of the oil and gas assets acquired in the Cor4 acquisition are
effective as of December 31, 2022, and have been audited by a qualified reserves auditor (as defined in NI 51-101), in accordance
with NI 51-101 and the COGE Handbook, and using Sproule’s December 31, 2022, price forecasts.
The price forecasts used in the Sproule and ERCE reports, and in respect of the assets acquired in the Cor4 acquisition, are
available on the website of Sproule (sproule. com) and are contained in the AIF . These price forecasts are as at December 31, 2022
and may not be reflective of current and future forecast commodity prices.
The reserve life index (RLI) is calculated by dividing the 2P reserves of 487 MMboe as at December 31, 2022 (including 15.9
MMboe acquired in the Cor4 acquisition), by the mid-point of the 2023 CMD production guidance of 48,000 to 50,000 boepd.
The product types comprising the 2P reserves described in this MD&A are contained in the AIF . See also “Supplemental
Information regarding Product Types” below. Light, medium and heavy crude oil reserves/resources disclosed in this MD&A
include solution gas and other by-products.
“2P reserves“ means proved plus probable reserves. “Proved reserves“ are those reserves that can be estimated with a high
degree of certainty to be recoverable. It is likely that the actual remaining quantities recovered will exceed the estimated proved
reserves. “Probable reserves“ are those additional reserves that are less certain to be recovered than proved reserves. It is equally
likely that the actual remaining quantities recovered will be greater or less than the sum of the estimated proved plus probable
reserves.
Each of the reserves categories reported (proved and probable) may be divided into developed and undeveloped categories.
“Developed reserves” are those reserves that are expected to be recovered from existing wells and installed facilities or, if
facilities have not been installed, that would involve a low expenditure (for example, when compared to the cost of drilling a well)
to put the reserves on production. The developed category may be subdivided into producing and non-producing. “Developed
producing reserves” are those reserves that are expected to be recovered from completion intervals open at the time of the
estimate. These reserves may be currently producing or, if shut-in, they must have previously been on production, and the date
of resumption of production must be known with reasonable certainty. “Developed non-producing reserves” are those reserves
that either have not been on production, or have previously been on production, but are shut-in, and the date of resumption
of production is unknown. “Undeveloped reserves” are those reserves expected to be recovered from known accumulations
where a significant expenditure (for example, when compared to the cost of drilling a well) is required to render them capable of
production. They must fully meet the requirements of the reserves classification (proved, probable) to which they are assigned.
Contingent resources are those quantities of petroleum estimated, as of a given date, to be potentially recoverable from known
accumulations using established technology or technology under development, but which are not currently considered to be
commercially recoverable due to one or more contingencies. Contingencies are conditions that must be satisfied for a portion
of contingent resources to be classified as reserves that are: (a) specific to the project being evaluated; and (b) expected to be
resolved within a reasonable timeframe. Contingencies may include factors such as economic, legal, environmental, political,
and regulatory matters, or a lack of markets. It is also appropriate to classify as contingent resources the estimated discovered
recoverable quantities associated with a project in the early evaluation stage. Contingent resources are further classified in
accordance with the level of certainty associated with the estimates and may be sub-classified based on a project maturity and/or
characterized by their economic status.
There are three classifications of contingent resources: low estimate, best estimate and high estimate. Best estimate is a
classification of estimated resources described in the COGE Handbook as the best estimate of the quantity that will be actually
recovered. It is equally likely that the actual remaining quantities recovered will be greater or less than the best estimate. If
probabilistic methods are used, there should be at least a 50% probability that the quantities actually recovered will equal or
exceed the best estimate.
24
===== SIDA 46 =====
Management’s Discussion and Analysis
For the three months ended March 31, 2023
Contingent resources are further classified based on project maturity. The project maturity subclasses include development
pending, development on hold, development unclarified and development not viable. All of the Corporation’s contingent resources
are classified as either development on hold or development unclarified. Development on hold is defined as a contingent
resource where there is a reasonable chance of development, but there are major non-technical contingencies to be resolved
that are usually beyond the control of the operator. Development unclarified is defined as a contingent resource that requires
further appraisal to clarify the potential for development and has been assigned a lower chance of development until commercial
considerations can be clearly defined. Chance of development is the probability of a project being commercially viable.
References to “unrisked“ contingent resources volumes means that the reported volumes of contingent resources have not
been risked (or adjusted) based on the chance of commerciality of such resources. In accordance with the COGE Handbook
guidance for contingent resources, the chance of commerciality is solely based on the chance of development associated with
the resolution of all contingencies required for the re-classification of the contingent resources as reserves. Therefore volumes
of contingent resources do not reflect the risking (or adjustment) of such volumes based on the chance of development of such
resources.
The contingent resources reported in the MD&A are estimates only. The estimates are based upon a number of factors and
assumptions each of which contains estimation error which could result in future revisions of the estimates as more technical and
commercial information becomes available. The estimation factors include, but are not limited to, the mapped extent of the oil
and gas accumulations, geologic characteristics of the reservoirs, and dynamic reservoir performance. There are numerous risks
and uncertainties associated with recovery of such resources, including many factors beyond the Corporation’s control. There is
uncertainty that it will be commercially viable to produce any portion of the contingent resources referred to in the MD&A.
2P reserves and contingent resources included in the reports prepared by Sproule and ERCE in respect of IPC’s oil and gas
assets in Canada, France and Malaysia, and 2P reserves in respect of the oil and gas assets acquired in the Cor4 acquisition, have
been aggregated by IPC. Estimates of reserves, resources and future net revenue for individual properties may not reflect the
same level of confidence as estimates of reserves, resources and future net revenue for all properties, due to aggregation. This
MD&A contains estimates of the net present value of the future net revenue from IPC’s reserves and contingent resources. The
estimated values of future net revenue disclosed in this MD&A do not represent fair market value. There is no assurance that
the forecast prices and cost assumptions used in the reserve and resources evaluations will be attained and variances could be
material.
References to “contingent resources” do not constitute, and should be distinguished from, references to “reserves”.
BOEs may be misleading, particularly if used in isolation. A BOE conversion ratio of 6 thousand cubic feet (Mcf) per 1 barrel
(bbl) is based on an energy equivalency conversion method primarily applicable at the burner tip and does not represent a value
equivalency at the wellhead. As the value ratio between natural gas and crude oil based on the current prices of natural gas and
crude oil is significantly different from the energy equivalency of 6:1, utilizing a 6:1 conversion basis may be misleading as an
indication of value.
Supplemental Information regarding Product Types
The following table is intended to provide supplemental information about the product type composition of IPC’s net average daily
production figures provided in this document:
Heavy Crude Oil
(Mbopd)
Light and Medium
Crude Oil (Mbopd)
Conventional Natural Gas
(per day)
Total
(Mboepd)
Three months ended
March 31, 2023 26.6 9.5 99.9 MMcf
(16.7 Mboe) 52.8
March 31, 2022 22.2 8.0 93.6 MMcf
(15.6 Mboe) 45.8
Year ended December 31, 2022
December 31, 2022
22.6 9.6 98.1MMcf
(16.4 Mboe) 48.6
This document also makes reference to IPC’s forecast average daily production of 48,000 to 50,000 boepd for 2023. IPC
estimates that approximately 50% of that production will be comprised of heavy oil, approximately 17% will be comprised of light
and medium crude oil and approximately 33% will be comprised of conventional natural gas.
25
===== SIDA 47 =====
Management’s Discussion and Analysis
For the three months ended March 31, 2023
OTHER SUPPLEMENTARY INFORMATION
Abbreviations
CAD
Canadian dollar
MCAD
Million Canadian dollar
EUR Euro
USD
US dollar
MUSD
Million US dollar
MYR
Malaysian Ringgit
FPSO
Floating Production Storage and Offloading (facility)
Oil related terms and measurements
AECO
The daily average benchmark price for natural gas at the AECO hub in southeast Alberta
API An indication of the specific gravity of crude oil on the API (American Petroleum Institute) gravity scale
Alkaline surfactant polymer (an EOR process)
ARV
Argus WCS Houston (a reference price for the cost of transporting WCS quality oil from Alberta to Houston)
bbl Barrel (1 barrel = 159 litres)
boe1 Barrels of oil equivalents
boepd Barrels of oil equivalents per day
bopd Barrels of oil per day
Bcf
Billion cubic feet
Bscf Billion standard cubic feet
Empress The benchmark price for natural gas at the Empress point at the Alberta/Saskatchewan border
EOR Enhanced Oil Recovery
GJ Gigajoules
Mbbl Thousand barrels
MMbbl Million barrels
Mboe Thousand barrels of oil equivalents
Mboepd Thousand barrels of oil equivalents per day
Mbopd Thousand barrels of oil per day
MMboe Million barrels of oil equivalents
MMbtu Million British thermal units
Mcf Thousand cubic feet
Mcfpd
Thousand cubic feet per day
MMcf Million cubic feet
NGL Natural gas liquid
SAGD Steam assisted gravity drainage (a thermal recovery process)
WTI West T
exas Intermediate (a light oil reference price)
WCS Western Canadian Select (a heavy oil reference price)
1 All volume references to boe are calculated on the basis of six thousand cubic feet of natural gas to one barrel of oil equivalent (6 Mcf: 1 bbl)
unless otherwise indicated. This conversion ratio is based on an energy equivalency conversion method primarily applicable at the burner tip and
does not represent a value equivalency at the wellhead. Boes may be misleading, particularly if used in isolation. Given that the value ratio based
on the current price of crude oil as compared to natural gas is significantly different from the energy equivalency of 6:1, utilizing a conversion on a
6:1 basis may be misleading as an indication of value.
26
===== SIDA 48 =====
Management’s Discussion and Analysis
For the three months ended March 31, 2023
DIRECTORS
C. Ashley Heppenstall
Director, Chair
London, England
Mike Nicholson
Director, President and Chief Executive Officer
Geneva, Switzerland
Chris Bruijnzeels
Director
Abcoude, The Netherlands
Donald K. Charter
Director
Toronto, Ontario, Canada
Emily Moore
Director
Toronto, Ontario, Canada
Lukas (Harry) H. Lundin
Director
Toronto, Ontario, Canada
OFFICERS
Christophe Nerguararian
Chief Financial Officer
Geneva, Switzerland
William Lundin
Chief Operating Officer
Geneva, Switzerland
Jeffrey Fountain
General Counsel and Corporate Secretary
Geneva, Switzerland
Rebecca Gordon
VP Corporate Planning and Investor Relations
Geneva, Switzerland
Chris Hogue
Senior Vice President Canada
Calgary, Alberta, Canada
Ryan Adair
Vice President Asset Management and
Corporate Planning Canada
Calgary, Alberta, Canada
MEDIA AND INVESTOR RELATIONS
Robert Eriksson
Stockholm, Sweden
Sophia Shane
Vancouver, British Columbia, Canada
CORPORATE OFFICE
Suite 2000 – 885 West Georgia Street Vancouver,
British Columbia V6C 3E8 Canada
Telephone: +1 604 689 7842
Website: www.international-petroleum.com
OPERATIONS OFFICE
5 Chemin de la Pallanterie
1222 Vésenaz
Switzerland
Telephone: +41 22 595 10 50
E-mail: info@international-petroleum.com
REGISTERED AND RECORDS OFFICE
Suite 2600 - 595 Burrard Street
Vancouver, British Columbia
V7X 1L3 Canada
INDEPENDENT AUDITORS
PricewaterhouseCoopers SA, Switzerland
TRANSFER AGENT
Computershare Trust Company of Canada
Calgary, Alberta, and Toronto, Ontario
STOCK EXCHANGE LISTINGS
Toronto Stock Exchange and NASDAQ Stockholm
Trading Symbol: IPCO
27
===== SIDA 49 =====
Corporate Office
International Petroleum Corp
Suite 2000
885 West Georgia Street
Vancouver, BC
V6C 3E8, Canada
Tel: +1 604 689 7842
E-mail: info@international-petroleum.com
Web: international-petroleum.com□