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Whitecap Resources Inc. Interim / Quarterly Report 2023
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Interim / Quarterly Report
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Third Quarter 2023
The following management's discussion and analysis ("MD&A") of financial condition and results of operations for Whitecap Resources Inc. (the "Company" or "Whitecap") is dated October 24, 2023 and should be read in conjunction with the Company's unaudited interim consolidated financial statements and related notes for the period ended September 30, 2023, as well as the audited annual consolidated financial statements and related notes for the year ended December 31, 2022. The unaudited interim consolidated financial statements have been prepared in accordance with International Financial Reporting Standards ("IFRS"), specifically International Accounting Standard ("IAS") 34, Interim Financial Reporting, in Canadian dollars, except where indicated otherwise. Accounting policies adopted by the Company are set out in the notes to the audited annual consolidated financial statements for the year ended December 31, 2022 and Note 3 of the unaudited interim consolidated financial statements for the period ended September 30, 2023. The unaudited interim consolidated financial statements of Whitecap have been prepared by management and approved by the Company's Board of Directors. This MD&A should also be read in conjunction with Whitecap's disclosures under "Advisories" below. Additional information respecting Whitecap is available on the SEDAR+ website (www.sedarplus.ca) and on our website (www.wcap.ca).
DESCRIPTION OF BUSINESS
Whitecap is a Calgary based oil and gas company that is engaged in the business of acquiring, developing and holding interests in petroleum and natural gas properties and assets. Whitecap's common shares are traded on the Toronto Stock Exchange ("TSX") under the symbol WCP.
2023 STRATEGIC DISPOSITIONS
Non-core Asset Dispositions
In the first quarter of 2023, the Company closed the dispositions of non-core assets for total net consideration of $389.5 million. These assets were previously classified as held for sale at December 31, 2022 and upon closing of the transactions, a net gain on asset disposition of $68.7 million was recorded as the proceeds less cost of disposal exceeded their carrying amount.
2022 STRATEGIC ACQUISITIONS
TimberRock Energy Corp.
On January 10, 2022, the Company closed the TimberRock Energy Corp. ("TimberRock") acquisition. Whitecap acquired all the issued and outstanding common shares of TimberRock for consideration consisting of 12.4 million Whitecap common shares and $205.8 million in cash.
XTO Energy Canada
On August 31, 2022, the Company closed the XTO Energy Canada ("XTO") acquisition. Whitecap acquired XTO for total cash consideration of $1.9 billion.
2023 THIRD QUARTER FINANCIAL AND OPERATIONAL RESULTS
Production
Whitecap's average production volumes and commodity splits were as follows:
| Three months endedSeptember 30, | Nine months endedSeptember 30, | |||
|---|---|---|---|---|
| 2023 | 2022 | 2023 | 2022 | |
| Crude oil (bbls/d) (1) | 85,238 | 85,137 | 84,717 | 84,599 |
| NGLs (bbls/d) (1) | 17,804 | 16,513 | 16,640 | 14,863 |
| Natural gas (Mcf/d) (1) | 323,903 | 264,886 | 310,531 | 225,076 |
| Total (boe/d) (2) | 157,026 | 145,798 | 153,112 | 136,975 |
Notes:
(1) "Crude oil" refers to light and medium crude oil, tight oil, and condensate combined. "NGLs" refers to ethane, propane, butane and pentane combined. "Natural gas" refers to conventional natural gas and shale gas combined. For further breakdown of crude oil and natural gas production volumes refer to the "Product Type Information" section of this MD&A.
(2) Disclosure of production on a per boe basis in this MD&A consists of the constituent product types and their respective quantities disclosed in the "Product Type Information" section of this MD&A. Also refer to the "Boe Presentation" section of this MD&A.
Exhibit 1
Average production volumes increased eight percent to 157,026 boe/d in the third quarter of 2023 from 145,798 boe/d in the third quarter of 2022. Year to date, average production volumes increased 12 percent to 153,112 boe/d compared to 136,975 boe/d for the same period in 2022. The increases in production in the three and nine months ended September 30, 2023 were primarily due to the XTO acquisition completed in the third quarter of 2022 and the Company's ongoing successful drilling program. This was partially offset by the disposition of non-core assets in the first quarter of 2023, and natural declines.
Crude oil and NGLs weighting in the three and nine months ended September 30, 2023 was 66 percent, compared to 70 percent and 73 percent in the three and nine months ended September 30, 2022, respectively. The lower crude oil and NGLs weighting in the three and nine months ended September 30, 2023 compared to the same periods in 2022 are primarily due to the assets acquired from XTO in the third quarter of 2022 which have a higher natural gas weighting than the Company average in the three and nine months ended September 30, 2022.
Petroleum and Natural Gas Sales
A breakdown of petroleum and natural gas sales is as follows:
| Nine months ended | |||
|---|---|---|---|
| September 30, | |||
| 2023 | 2022 | 2023 | 2022 |
| 813.4 | 874.4 | 2,207.0 | 2,751.5 |
| 60.2 | 84.9 | 178.6 | 238.0 |
| 82.3 | 111.2 | 251.9 | 346.9 |
| 955.9 | 1,070.5 | 2,637.5 | 3,336.4 |
| (7.2) | (5.2) | (21.5) | (16.6) |
| 11.4 | 9.9 | 37.6 | 24.1 |
| 72.8 | 80.9 | 205.3 | 225.0 |
| 1,032.9 | 1,156.0 | 2,858.9 | 3,568.8 |
| September 30, | Three months ended |
Exhibit 2
Petroleum and natural gas revenues in the third quarter of 2023 decreased 11 percent to $1.0 billion from $1.1 billion in the third quarter of 2022. The decrease of $0.1 billion is attributed to lower realized prices. Year to date, petroleum and natural gas revenues decreased 21 percent to $2.6 billion from $3.3 billion for the same period in 2022. The decrease of $0.7 billion consists of $0.9 billion attributed to lower realized prices, partially offset by $0.2 billion attributed to higher production volumes.
Benchmark and Realized Prices
Average benchmark and realized prices are as follows:
| Three months ended | Nine months ended | ||||
|---|---|---|---|---|---|
| September 30, | September 30, | ||||
| 2023 | 2022 | 2023 | 2022 | ||
| Average benchmark prices | |||||
| WTI (US$/bbl) (1) | 82.26 | 91.56 | 77.39 | 98.09 | |
| Exchange rate (US$/C$) | 1.34 | 1.31 | 1.35 | 1.28 | |
| WTI (C$/bbl) | 110.38 | 119.46 | 104.13 | 125.77 | |
| MSW Par at Edmonton ($/bbl) (2) | 107.85 | 116.79 | 100.78 | 123.42 | |
| Fosterton Par at Regina ($/bbl) | 94.32 | 97.78 | 82.43 | 109.71 | |
| Midale Par at Cromer ($/bbl) | 110.39 | 117.59 | 100.65 | 124.02 | |
| LSB Par at Cromer ($/bbl) (3) | 108.80 | 116.82 | 100.50 | 123.80 | |
| AECO natural gas ($/Mcf) (4) | 2.60 | 4.16 | 2.76 | 5.38 | |
| Average realized prices (5) | |||||
| Crude oil ($/bbl) (6) | 103.72 | 111.64 | 95.43 | 119.13 | |
| NGLs ($/bbl) (6) | 36.75 | 55.87 | 39.32 | 58.65 | |
| Natural gas ($/Mcf) (6) | 2.76 | 4.56 | 2.97 | 5.65 | |
| Petroleum and natural gas revenues ($/boe) (6) | 66.17 | 79.81 | 63.10 | 89.22 |
Notes:
(1) WTI represents the calendar month average of West Texas Intermediate oil.
(2) Mixed Sweet Blend ("MSW").
(3) Light Sour Blend ("LSB").
(4) AECO represents the AECO 5A Daily Index price.
(5) Prior to the impact of risk management activities and tariffs.
(6) Supplementary financial measure. Refer to the "Supplementary Financial Measures" section of this MD&A for more information.
Exhibit 3
Whitecap's weighted average realized price prior to the impact of risk management activities and tariffs decreased 17 percent to $66.17 per boe in the third quarter of 2023 compared to $79.81 per boe in the third quarter of 2022. Year to date, Whitecap's weighted average realized price prior to the impact of risk management activities and tariffs decreased 29 percent to $63.10 per boe compared to $89.22 per boe for the same period in 2022.
Crude Oil
The WTI price decreased by ten percent to average US$82.26 per barrel in the third quarter of 2023 compared to US$91.56 per barrel in the third quarter of 2022. The WTI price decreased by 21 percent to average US$77.39 per barrel in the nine months ended September 30, 2023 compared to US$98.09 per barrel in the nine months ended September 30, 2022. The decreases for the three and nine months ended September 30, 2023 are primarily due to the normalization of global supply and demand balances.
West Division
Northern Alberta & British Columbia
The Company's realized crude oil prices in Northern Alberta & British Columbia are based on the MSW par at Edmonton. The MSW par oil price decreased by eight percent to average $107.85 per barrel in the third quarter of 2023 compared to $116.79 per barrel in the third quarter of 2022. The MSW par oil price decreased by 18 percent to average $100.78 per barrel in the nine months ended September 30, 2023 compared to $123.42 per barrel in the nine months ended September 30, 2022. The decreases are primarily due to lower WTI prices, partially offset by the weakening of the Canadian Dollar in 2023.
East Division
Central Alberta
The Company's realized crude oil price in the Central Alberta region is based on the MSW par at Edmonton, discussed above.
Western Saskatchewan
The Company's realized crude oil price in the West Central Saskatchewan region is based on the MSW par at Edmonton, discussed above.
The Company's realized crude oil price in the Southwest Saskatchewan region is based on the Fosterton par price at Regina. The Fosterton par price decreased four percent to average $94.32 per barrel in the third quarter of 2023 compared to $97.78 per barrel in the third quarter of 2022. The decrease is primarily due to lower WTI prices, partially offset by a 35 percent improvement in the underlying Western Canadian Select ("WCS") differential in the third quarter of 2023 compared to the third quarter of 2022. The Fosterton par price decreased by 25 percent to average $82.43 per barrel in the nine months ended September 30, 2023 compared to $109.71 per barrel in the nine months ended September 30, 2022. The decrease is primarily due to increased supply which weakened the underlying WCS differential by 12 percent.
Eastern Saskatchewan
The Company's realized crude oil price in the Weyburn region is based on the Midale par price at Cromer. The Midale par price decreased six percent to average $110.39 per barrel in the third quarter of 2023 compared to $117.59 per barrel in the third quarter of 2022. The Midale par price decreased by 19 percent to average $100.65 per barrel in the nine months ended September 30, 2023 compared to $124.02 per barrel in the nine months ended September 30, 2022. The decreases are primarily due to lower WTI prices.
The Company's realized crude oil prices in the South-Central Saskatchewan and Southeast Saskatchewan regions are based on the LSB par price at Cromer. The LSB oil price decreased seven percent to average $108.80 per barrel in the third quarter of 2023 compared to $116.82 per barrel in the third quarter of 2022. The LSB oil price decreased 19 percent to average $100.50 per barrel in the nine months ended September 30, 2023 compared to $123.80 per barrel in the nine months ended September 30, 2022. The decreases are primarily due to lower WTI prices.
Natural Gas Liquids
The natural gas liquids realized price decreased 34 percent to average $36.75 per barrel in the third quarter of 2023 compared to $55.87 per barrel in the third quarter of 2022. The natural gas liquids realized price decreased 33 percent to average $39.32 per barrel in the nine months ended September 30, 2023 compared to $58.65 per barrel in the nine months ended September 30, 2022. The decreases are primarily due to high North American inventory levels and lower WTI prices in the three and nine months ended September 30, 2023 compared to the same periods in 2022.
Natural Gas
The AECO daily spot price decreased 38 percent to average $2.60 per Mcf in the third quarter of 2023 compared to an average of $4.16 per Mcf in the third quarter of 2022. The AECO daily spot price decreased 49 percent to average $2.76 per Mcf in the nine months ended September 30, 2023 compared to $5.38 per Mcf in the nine months ended September 30, 2022. The decreases in the three and nine months ended September 30, 2023 are primarily due to lower demand as a result of mild weather during the winter period and higher production in Canada and the United States resulting in higher seasonal storage levels compared to the same periods in 2022.
Risk Management
Whitecap maintains an ongoing risk management program to reduce the volatility of revenues in order to fund capital expenditures and pay cash dividends to shareholders.
The Company incurred a realized gain of $0.6 million and $21.6 million on its commodity risk management contracts for the three and nine months ended September 30, 2023, respectively.
The unrealized gains and losses are a result of the non-cash change in the mark-to-market values period over period. The significant assumptions made in determining the fair value of financial instruments are disclosed in Note 4 to the Company's unaudited interim consolidated financial statements for the three and nine months ended September 30, 2023.
| Three months ended | Nine months ended | ||||
|---|---|---|---|---|---|
| September 30, | September 30, | ||||
| Risk Management Contracts ($ millions) | 2023 | 2022 | 2023 | 2022 | |
| Realized gain (loss) on commodity contracts | 0.6 | (29.5) | 21.6 | (223.6) | |
| Unrealized gain (loss) on commodity contracts | (81.5) | 104.5 | (7.3) | 48.3 | |
| Net gain (loss) on commodity contracts | (80.9) | 75.0 | 14.3 | (175.3) | |
| Realized gain on interest rate contracts (1) | 4.0 | 1.6 | 11.0 | 0.8 | |
| Unrealized gain (loss) on interest rate contracts (1) | (2.4) | 3.1 | (3.4) | 19.4 | |
| Realized gain on equity contracts (2) | - | 0.2 | 5.6 | 15.2 | |
| Unrealized gain (loss) on equity contracts (2) | 0.7 | (0.4) | (5.6) | (5.0) | |
| Net gain (loss) on risk management contracts | (78.6) | 79.4 | 21.9 | (145.0) |
Notes:
Exhibit 4
(1) The gains (losses) on interest rate risk management contracts are included in interest and financing expenses.
(2) The gains (losses) on equity contracts are included in stock-based compensation expenses.
At September 30, 2023, the following risk management contracts were outstanding with an asset fair market value of $33.3 million and a liability fair market value of $43.7 million:
WTI Crude Oil Derivative Contracts
| Bought Put | |||||
|---|---|---|---|---|---|
| Volume | Price | Sold Call Price | Swap Price | ||
| Type | Remaining Term | (bbls/d) | (C$/bbl) (1) | (C$/bbl) (1) | (C$/bbl) (1) |
| Swap | Oct - Dec 2023 | 7,000 | 101.88 | ||
| Swap | Jan - Jun 2024 | 4,000 | 99.26 | ||
| Swap | Jul - Dec 2024 | 3,000 | 98.33 | ||
| Swap | Jan - Dec 2024 | 4,000 | 109.57 | ||
| Swap | Jan - Jun 2025 | 3,000 | 102.18 | ||
| Swap | Jul - Dec 2025 | 1,000 | 100.05 | ||
| Swap | Jan - Dec 2025 | 4,000 | 101.08 | ||
| Collar | Oct - Dec 2023 | 6,000 | 74.17 | 101.03 | |
| Collar | Jan - Dec 2024 | 5,000 | 82.00 | 116.98 |
Note:
(1) Prices reported are the weighted average prices for the period.
Natural Gas Derivative Contracts
| Bought Put | |||||
|---|---|---|---|---|---|
| Type | Remaining Term | Volume(GJ/d) | Price(C$/GJ) (1) | Sold Call Price(C$/GJ) (1) | Swap Price(C$/GJ) (1) |
| Swap | Oct 2023 | 70,000 | 3.88 | ||
| Swap | Nov 2023 - Mar 2024 | 5,000 | 3.51 | ||
| Swap | Jan - Dec 2024 | 10,000 | 4.02 | ||
| Swap | Apr - Oct 2024 | 15,000 | 2.50 | ||
| Swap | Nov 2024 - Mar 2025 | 10,000 | 3.58 | ||
| Swap | Jan - Dec 2025 | 10,000 | 3.53 | ||
| Collar | Oct - Dec 2023 | 14,000 | 3.32 | 6.13 |
Note:
(1) Prices reported are the weighted average prices for the period.
Power Derivative Contracts
| Volume | Fixed Rate | ||
|---|---|---|---|
| Type | Remaining Term | (MWh) | ($/MWh) (1) |
| Swap | Oct - Dec 2023 | 11,040 | 124.00 |
| Swap | Oct 2023 - Dec 2024 | 54,324 | 115.00 |
| Swap | Jan - Dec 2024 | 43,920 | 99.00 |
| Swap | Jan - Dec 2025 | 43,800 | 71.75 |
Note:
(1) Prices reported are the weighted average prices for the period.
Interest Rate Contracts
| Amount | Fixed Rate | ||||
|---|---|---|---|---|---|
| Type | Term | ($ millions) | (%) (1) | Index (2) | |
| Swap | Aug 6, 2019 | Aug 6, 2024 | 200.0 | 1.5540 | CDOR |
| Swap | May 5, 2021 | May 5, 2025 | 200.0 | 1.2315 | CDOR |
Notes:
(1) Rates reported are the weighted average rates for the period.
(2) Canadian Dollar Offered Rate ("CDOR").
Equity Derivative Contracts
| Notional | |||
|---|---|---|---|
| Amount | Share Volume | ||
| Type | Remaining Term | ($ millions) (1) | (millions) |
| Swap | Oct 1, 2023 | 0.7 | 0.3 |
Note: (1) Notional amount is calculated as the share volume for the period multiplied by the weighted average prices for the period.
Contracts entered into subsequent to September 30, 2023
WTI Crude Oil Derivative Contracts
| Volume | Swap Price | ||
|---|---|---|---|
| Type | Remaining Term | (bbls/d) | (C$/bbl) (1) |
| Swap | Jan - Dec 2024 | 2,000 | 111.25 |
| Swap | Jan - Dec 2025 | 2,000 | 102.60 |
Note:
(1) Prices reported are the weighted average prices for the period.
Natural Gas Derivative Contracts
| Volume | Swap Price | ||
|---|---|---|---|
| Type | Remaining Term | (GJ/d) | (C$/GJ) (1) |
| Swap | Nov 2023 - Mar 2024 | 15,000 | 3.01 |
| Swap | Jan 2024 - Dec 2025 | 10,000 | 3.30 |
| Swap | Apr - Oct 2024 | 10,000 | 2.65 |
| Swap | Jan - Dec 2025 | 10,000 | 3.50 |
Note:
(1) Prices reported are the weighted average prices for the period.
Royalties
| Three months endedSeptember 30, | Nine months endedSeptember 30, | |||
|---|---|---|---|---|
| ($ millions, except per boe amounts) | 2023 | 2022 | 2023 | 2022 |
| Royalties | 166.6 | 218.5 | 455.5 | 657.6 |
| As a % of petroleum and natural gas revenues (1) | 17.4 | 20.4 | 17.3 | 19.7 |
| $ per boe (1) | 11.53 | 16.29 | 10.90 | 17.58 |
Note:
(1) Supplementary financial measure. Refer to the "Supplementary Financial Measures" section of this MD&A for more information.
Royalties as a percentage of petroleum and natural gas revenues decreased to 17.4 percent in the third quarter of 2023 compared to 20.4 percent in the third quarter of 2022. Year to date, royalties as a percentage of petroleum and natural gas revenues decreased to 17.3 percent compared to 19.7 percent for the same period in 2022. The decreases in royalties as a percentage of petroleum and natural gas revenues in the three and nine months ended September 30, 2023, were primarily attributable to lower commodity prices compared to the same periods in 2022 and gas cost allowance credits received in 2023.
Whitecap pays royalties to the provincial governments and mineral owners in Alberta, Saskatchewan, Manitoba and British Columbia. Each province has separate royalty regimes which impact Whitecap's overall corporate royalty rate.
Operating Expenses
| Three months ended | Nine months ended | |||||
|---|---|---|---|---|---|---|
| September 30, | September 30, | |||||
| ($ millions, except per boe amounts) | 2023 | 2022 | 2023 | 2022 | ||
| Operating expenses | 201.8 | 199.2 | 599.9 | 550.0 | ||
| $ per boe (1) | 13.97 | 14.85 | 14.35 | 14.71 |
Note:
(1) Supplementary financial measure. Refer to the "Supplementary Financial Measures" section of this MD&A for more information.
Operating expenses per boe in the third quarter of 2023 decreased six percent to $13.97 per boe compared to $14.85 per boe in the third quarter of 2022. Year to date, operating expenses decreased two percent to $14.35 per boe compared to $14.71 per boe for the same period in 2022. The decreases in operating expenses per boe for the three and nine months ended September 30, 2023 are primarily due to increased production and lower workover and turnaround costs compared to the same periods in 2022, partially offset by the impact of inflationary pressures on other cost categories.
Transportation Expenses
| Three months ended | Nine months ended | ||||
|---|---|---|---|---|---|
| September 30, | September 30, | ||||
| ($ millions, except per boe amounts) | 2023 | 2022 | 2023 | 2022 | |
| Transportation expenses | 32.1 | 30.5 | 91.7 | 82.3 | |
| $ per boe (1) | 2.22 | 2.27 | 2.19 | 2.20 |
Note:
(1) Supplementary financial measure. Refer to the "Supplementary Financial Measures" section of this MD&A for more information.
Transportation expenses per boe in the three and nine months ended September 30, 2023 remained generally consistent compared to the same periods in 2022.
Transportation expenses per boe will fluctuate quarterly based on pipeline connectivity or downtime, weather, shipper status and pipeline shipping arrangements. When Whitecap has shipper status, pipeline tariffs incurred by the Company are included in transportation expenses. When Whitecap does not have shipper status, pipeline tariffs incurred by commodity purchasers subsequent to the delivery of the Company's product are charged back to Whitecap and are netted against petroleum and natural gas sales.
Marketing Revenues and Expenses
| Three months ended | Nine months ended | |||
|---|---|---|---|---|
| September 30, | September 30, | |||
| ($ millions, except per boe amounts) | 2023 | 2022 | 2023 | 2022 |
| Marketing revenues | 72.8 | 80.9 | 205.3 | 225.0 |
| $ per boe (1) | 5.04 | 6.03 | 4.91 | 6.02 |
| Marketing expenses | 72.1 | 80.5 | 204.3 | 223.3 |
| $ per boe (1) | 4.99 | 6.00 | 4.89 | 5.97 |
Note:
(1) Supplementary financial measure. Refer to the "Supplementary Financial Measures" section of this MD&A for more information.
Marketing revenues and expenses per boe in the third quarter of 2023 decreased 16 percent and 17 percent, respectively, compared to the third quarter of 2022. Marketing revenues and expenses per boe in the nine months ended September 30, 2023 decreased 18 percent compared to the nine months ended September 30, 2022. The decreases in marketing revenues and expenses are attributable to lower pricing and volumes related to purchases of third-party volumes for resale and blending activities. Marketing activities will fluctuate and may occur when there is a sufficiently large variance between crude oil sales stream prices and where there is both sufficient facility and pipeline capacity.
Operating Netbacks
The components of operating netbacks are shown below:
| Three months ended | Nine months ended | ||||
|---|---|---|---|---|---|
| September 30, | September 30, | ||||
| Operating Netbacks ($ millions) | 2023 | 2022 | 2023 | 2022 | |
| Petroleum and natural gas revenues | 955.9 | 1,070.5 | 2,637.5 | 3,336.4 | |
| Tariffs | (7.2) | (5.2) | (21.5) | (16.6) | |
| Processing & other income | 11.4 | 9.9 | 37.6 | 24.1 | |
| Marketing revenues | 72.8 | 80.9 | 205.3 | 225.0 | |
| Petroleum and natural gas sales | 1,032.9 | 1,156.0 | 2,858.9 | 3,568.8 | |
| Realized gain (loss) on commodity contracts | 0.6 | (29.5) | 21.6 | (223.6) | |
| Royalties | (166.6) | (218.5) | (455.5) | (657.6) | |
| Operating expenses | (201.8) | (199.2) | (599.9) | (550.0) | |
| Transportation expenses | (32.1) | (30.5) | (91.7) | (82.3) | |
| Marketing expenses | (72.1) | (80.5) | (204.3) | (223.3) | |
| Operating netbacks (1) | 560.9 | 598.0 | 1,529.1 | 1,832.0 |
Note: (1)
"Operating netback" is a non-GAAP financial measure determined by adding marketing revenues and processing & other income, deducting realized losses on commodity risk management contracts or adding realized gains on commodity risk management contracts and deducting tariffs, royalties, operating expenses, transportation expenses and marketing expenses from petroleum and natural gas revenues. The most directly comparable financial measure to operating netback disclosed in the primary financial statements is petroleum and natural gas sales. Operating netback is a measure used in operational and capital allocation decisions. Operating netback is not a standardized financial measure under IFRS and, therefore, may not be comparable with the calculation of similar financial measures disclosed by other entities.
The components of operating netbacks per boe are shown below:
| Three months ended | Nine months ended | ||||
|---|---|---|---|---|---|
| September 30, | September 30, | ||||
| Operating Netbacks ($ per boe) | 2023 | 2022 | 2023 | 2022 | |
| Petroleum and natural gas revenues (1) | 66.17 | 79.81 | 63.10 | 89.22 | |
| Tariffs (1) | (0.50) | (0.39) | (0.51) | (0.44) | |
| Processing & other income (1) | 0.79 | 0.74 | 0.90 | 0.64 | |
| Marketing revenues (1) | 5.04 | 6.03 | 4.91 | 6.02 | |
| Petroleum and natural gas sales (1) | 71.50 | 86.19 | 68.40 | 95.44 | |
| Realized gain (loss) on commodity contracts (1) | 0.04 | (2.20) | 0.52 | (5.98) | |
| Royalties (1) | (11.53) | (16.29) | (10.90) | (17.58) | |
| Operating expenses (1) | (13.97) | (14.85) | (14.35) | (14.71) | |
| Transportation expenses (1) | (2.22) | (2.27) | (2.19) | (2.20) | |
| Marketing expenses (1) | (4.99) | (6.00) | (4.89) | (5.97) | |
| Operating netbacks (2) | 38.83 | 44.58 | 36.59 | 49.00 |
Notes:
(1) Supplementary financial measure. Refer to the "Supplementary Financial Measures" section of this MD&A for more information.
(2) "Operating netback per boe" is a non-GAAP ratio calculated by dividing operating netbacks by the total production for the period. Operating netback is a non-GAAP financial measure component of operating netback per boe. Operating netback per boe is not a standardized financial measure under IFRS and, therefore, may not be comparable with the calculation of similar financial measures disclosed by other entities. Presenting operating netback on a per boe basis allows management to better analyze performance against prior periods on a comparable basis.
General and Administrative Expenses
| Three months ended | Nine months ended | ||||
|---|---|---|---|---|---|
| September 30, | September 30, | ||||
| ($ millions, except per boe amounts) | 2023 | 2022 | 2023 | 2022 | |
| Gross G&A costs | 23.1 | 22.3 | 71.5 | 64.4 | |
| Recoveries | (6.7) | (6.9) | (18.8) | (18.0) | |
| Capitalized G&A | (2.0) | (2.1) | (11.0) | (9.1) | |
| G&A expenses | 14.4 | 13.4 | 41.7 | 37.3 | |
| $ per boe (1) | 1.00 | 1.00 | 1.00 | 1.00 |
Note:
(1) Supplementary financial measure. Refer to the "Supplementary Financial Measures" section of this MD&A for more information.
General and administrative ("G&A") expenses per boe in the three and nine months ended September 30, 2023 remained consistent compared to the same periods in 2022.
The increases in gross G&A costs in the three and nine months ended September 30, 2023 compared to the same periods in 2022 were primarily due to additional personnel and office related expenses as a result of the Company's growth year over year.
Recoveries and Capitalized G&A remained consistent in the three and nine months ended September 30, 2023 compared to the same periods in 2022.
Stock-based Compensation Expense
| Three months ended | Nine months ended | ||||
|---|---|---|---|---|---|
| September 30, | September 30, | ||||
| ($ millions, except per boe amounts) | 2023 | 2022 | 2023 | 2022 | |
| Stock-based compensation | 16.8 | 15.0 | 43.9 | 44.3 | |
| Realized gain on equity contracts | - | (0.2) | (5.6) | (15.2) | |
| Unrealized (gain) loss on equity contracts | (0.7) | 0.4 | 5.6 | 5.0 | |
| Capitalized stock-based compensation | (3.1) | (3.0) | (8.3) | (9.1) | |
| Stock-based compensation expenses | 13.0 | 12.3 | 35.6 | 25.0 | |
| $ per boe (1) | 0.90 | 0.91 | 0.85 | 0.67 |
Note:
(1) Supplementary financial measure. Refer to the "Supplementary Financial Measures" section of this MD&A for more information.
In the three and nine months ended September 30, 2023, the Company recorded stock-based compensation of $16.8 million and $43.9 million, respectively, compared to $15.0 million and $44.3 million in the same periods in 2022, respectively.
Stock-based compensation and capitalized stock-based compensation for the three and nine months ended September 30, 2023 remained consistent compared to the three and nine months ended September 30, 2022.
Stock-based compensation will fluctuate with changes to the expected payout multipliers associated with the performance awards, vesting of existing grants, additional grants under the Award Incentive Plan, as well as changes in fair value for awards that are accounted for as cash-settled.
Lower realized gain on equity contracts in the three and nine months ended September 30, 2023 was primarily due to less contracts outstanding at the time of contract settlement compared to the same periods in 2022. Unrealized gain on equity contracts in the third quarter of 2023 was primarily due to a share price increase in the third quarter of 2023 compared to a share price decrease in the third quarter of 2022. Year to date, unrealized loss on equity contracts resulted from the settlement of contracts.
Award Incentive Plan
The Award Incentive Plan has time-based awards and performance awards which may be granted to directors, officers, employees of the Company and other service providers. Independent outside directors receive only timebased awards as long-term compensation. As at September 30, 2023, the maximum number of common shares issuable under the plan shall not at any time exceed 3.755 percent of the total common shares outstanding. Vesting is determined by the Company's Board of Directors. Time-based awards and performance awards issued to employees of the Company and independent outside directors have vesting periods ranging from 1 to 3 years. A copy of the Company's Award Incentive Plan may be accessed through the SEDAR+ website (www.sedarplus.ca).
Each time-based award may, in the Company's sole discretion, entitle the holder to be issued the number of common shares designated in the time-based award plus dividend equivalents or payment in cash. Decisions regarding settlement method for insider and non-insider awards are mutually exclusive. Awards granted to insiders are currently accounted for as cash-settled, and awards granted to non-insiders are currently accounted for as equity-settled. Performance awards are also subject to a performance multiplier. This multiplier, ranging from zero to two, will be applied on vesting and is dependent on the performance of the Company relative to predefined corporate performance measures set by the Board of Directors for the associated period.
A forfeiture rate is estimated on the grant date and is adjusted to reflect the actual number of awards that vest. Based on the terms of the Award Incentive Plan, the fair value of share awards is equal to the underlying share price on grant date. The fair value of awards that are accounted for as cash-settled transactions are subsequently adjusted to the underlying share price at each period end. Performance awards are also adjusted by an estimated payout multiplier. The resulting stock-based compensation expense is recognized on a straight-line basis over the vesting period, with a corresponding increase to contributed surplus in the case of awards accounted for as equity-settled, or share awards liability in the case of awards accounted for as cash-settled. Upon the vesting of the awards that are accounted for as equity-settled, the associated amount in contributed surplus is recorded as an increase to share capital. At September 30, 2023, the Company had 7.2 million awards outstanding.
| Three months endedSeptember 30, | Nine months endedSeptember 30, | |||
|---|---|---|---|---|
| ($ millions, except per boe amounts) | 2023 | 2022 | 2023 | 2022 |
| Interest | 21.3 | 15.3 | 66.5 | 34.7 |
| Realized gain on interest rate contracts | (4.0) | (1.6) | (11.0) | (0.8) |
| Unrealized (gain) loss on interest rate contracts | 2.4 | (3.1) | 3.4 | (19.4) |
| Interest and financing expenses | 19.7 | 10.6 | 58.9 | 14.6 |
| $ per boe (1) | 1.36 | 0.79 | 1.41 | 0.39 |
Interest and Financing Expenses
Note:
(1) Supplementary financial measure. Refer to the "Supplementary Financial Measures" section of this MD&A for more information.
The increases in interest are primarily attributable to higher interest rates and higher average debt levels in the three and nine months ended September 30, 2023 compared to the same periods in 2022.
Realized gains in the three and nine months ended September 30, 2023 were primarily due to higher fair value of interest rate contracts at the time of settlement compared to the same periods in 2022.
Unrealized losses in the three and nine months ended September 30, 2023 were primarily due to the settlement of interest rate contracts. Unrealized gains in the three and nine months ended September 30, 2022 were due primarily due to an increase in forward interest rates.
Depletion, Depreciation and Amortization
| Three months ended | Nine months ended | ||||
|---|---|---|---|---|---|
| September 30, | September 30, | ||||
| ($ millions, except per boe amounts) | 2023 | 2022 | 2023 | 2022 | |
| Depletion, depreciation and amortization | 220.0 | 208.0 | 643.3 | 582.2 | |
| $ per boe (1) | 15.23 | 15.51 | 15.39 | 15.57 |
Note:
(1) Supplementary financial measure. Refer to the "Supplementary Financial Measures" section of this MD&A for more information.
Depletion, depreciation, and amortization ("DD&A") per boe for the three and nine months ended September 30, 2023 remained consistent compared to the same periods in 2022.
DD&A per boe will fluctuate from one period to the next depending on the amount and type of capital spending, changes in decommissioning asset, the recognition or reversal of impairments, the amount of reserves added and production volumes. The depletion rates are calculated on proved and probable oil and natural gas reserves, taking into account the future development costs to produce the reserves.
Impairment Reversal
| Three months ended | Nine months ended | |||||
|---|---|---|---|---|---|---|
| September 30, | September 30, | |||||
| ($ millions) | 2023 | 2022 | 2023 | 2022 | ||
| Impairment reversal | - | - | - | (629.7) |
At September 30, 2023, there were no indicators of impairment or impairment reversal.
March 31, 2022 Impairment Reversal
At March 31, 2022, the Company determined that the fair value less cost of disposal ("FVLCD") of each of the Company's CGUs with impairment losses recognized in prior periods that were not subsequently fully reversed exceeded their carrying amounts:
| Impairment | |||
|---|---|---|---|
| ($ millions) | FVLCD | Carrying Value | Reversal (1) |
| Central Alberta | 1,881.7 | 1,601.3 | (280.4) |
| Western Saskatchewan | 1,736.0 | 1,386.7 | (349.3) |
| Total | 3,617.7 | 2,988.0 | (629.7) |
Note:
(1) The impairment recovery is limited to a maximum of the estimated depleted historical cost if the impairment had not been recognized.
The full amount of impairment reversal was attributed to PP&E and, as a result, a total impairment reversal of $629.7 million was recorded in the Consolidated Statement of Comprehensive Income in the first quarter of 2022. The impairment reversal was primarily a result of higher forecast benchmark commodity prices at March 31, 2022 compared to December 31, 2021.
Income Taxes
| Three months ended | Nine months endedSeptember 30, | ||||
|---|---|---|---|---|---|
| September 30, | |||||
| ($ millions) | 2023 | 2022 | 2023 | 2022 | |
| Current income tax expense | 43.8 | - | 61.0 | - | |
| Deferred income tax expense | 5.9 | 111.8 | 136.3 | 453.4 |
Current Income Tax
During the three and nine months ended September 30, 2023 the Company recognized current income tax expense of $43.8 million and $61.0 million, respectively, compared to no current income tax expense for the same periods in 2022. Current income tax expense for the three and nine months ended September 30, 2023 is primarily due to expected income earned in excess of allowable tax pool deductions in 2023.
Deferred Income Tax
During the three and nine months ended September 30, 2023 the Company recognized deferred income tax expense of $5.9 million and $136.3 million, respectively, compared to deferred income tax expense of $111.8 million and $453.4 million, respectively, for the same periods in 2022. The decreases in deferred income tax expense are primarily due to lower net income in the three and nine months ended September 30, 2023 compared to the same periods in 2022.
Reassessments
In 2023, Whitecap received reassessments from the Canada Revenue Agency (the "CRA") and the Alberta Tax and Revenue Administration ("ATRA") for a former subsidiary that deny non-capital loss deductions relevant to the calculation of income taxes for the years 2018 and 2019.
Whitecap has received advice from its tax advisors that it should be entitled to deduct the non-capital losses and is of the opinion that its tax filings to date are correct. As such, Whitecap has not recognized any provision in its unaudited interim consolidated financial statements with respect to the reassessments.
Whitecap has filed a notice of objection for each CRA notice of reassessment which required the Company to concurrently pay 50 percent of the reassessed taxes, interest, and penalties as a deposit to the CRA ($65.3 million). Whitecap will file a notice of objection for each ATRA notice of reassessment in the fourth quarter of 2023 and will be required to concurrently pay 50 percent of the reassessed taxes, interest, and penalties as a deposit to the ATRA ($17.7 million). If the CRA is not in agreement with Whitecap's notice of objection, within a prescribed period, Whitecap would have a right to appeal to the Tax Court of Canada. Whitecap currently estimates that the ultimate resolution of the matter may take two to four years. If Whitecap is ultimately successful in defending its position, then any taxes, interest and penalties paid to the CRA would be refunded plus interest, and if the CRA is successful then any remaining taxes payable plus interest and any penalties would have to be remitted by Whitecap.
By way of background, Whitecap acquired a private entity in 2014 that held an interest in certain oil and natural gas assets and which had accrued non-capital losses in its business. The reassessments seek to disallow the deduction of approximately $494 million of these non-capital losses under the Income Tax Act (Canada) for the years 2018 and 2019.
Net Income and Other Comprehensive Income
For the three and nine months ended September 30, 2023 the Company recognized net income of $152.7 million and $590.7 million, respectively, compared to net income of $324.5 million and $1,357.5 million for the same periods in 2022. The following changes impacted the net income:
Exhibit 5
The factors causing these changes are discussed in the preceding sections.
Cash Flow from Operating Activities, Funds Flow and Payout Ratios
The following table reconciles cash flow from operating activities to funds flow and free funds flow:
| Three months ended | Nine months ended | |||
|---|---|---|---|---|
| ($ millions, except percentages and per share | September 30, | September 30, | ||
| amounts) | 2023 | 2022 | 2023 | 2022 |
| Cash flow from operating activities | 382.8 | 559.9 | 1,266.3 | 1,627.2 |
| Net change in non-cash working capital items | 83.2 | (13.1) | 62.8 | 101.9 |
| Funds flow (1) | 466.0 | 546.8 | 1,329.1 | 1,729.1 |
| Expenditures on PP&E | 281.9 | 208.0 | 753.3 | 507.5 |
| Free funds flow (2) | 184.1 | 338.8 | 575.8 | 1,221.6 |
| Dividends declared | 87.8 | 67.2 | 263.2 | 170.0 |
| Basic payout ratio (%) (3) | 19 | 12 | 20 | 10 |
| Total payout ratio (%) (4) | 79 | 50 | 76 | 39 |
| Funds flow per share, basic (1) | 0.77 | 0.89 | 2.19 | 2.80 |
| Funds flow per share, diluted (1) | 0.76 | 0.88 | 2.18 | 2.77 |
| Dividends declared per share | 0.15 | 0.11 | 0.43 | 0.28 |
Notes:
(1) Refer to Note 5(e)(ii) "Capital Management - Funds Flow" to the Company's unaudited interim consolidated financial statements for the three and nine months ended September 30, 2023. "Funds flow", "funds flow per share, basic" and "funds flow per share, diluted" are capital management measures and are key measures of operating performance as they demonstrate Whitecap's ability to generate the cash necessary to pay dividends, repay debt, make capital investments, and/or to repurchase common shares under the Company's normal course issuer bid ("NCIB"). Management believes that by excluding the temporary impact of changes in non-cash operating working capital, funds flow, funds flow per share, basic and funds flow per share, diluted provide useful measures of Whitecap's ability to generate cash that are not subject to short-term movements in non-cash operating working capital. Whitecap reports funds flow in total and on a per share basis (basic and diluted), which is calculated by dividing funds flow by the weighted average number of shares (basic and diluted) outstanding for the relevant period. See Note 5(e)(ii) "Capital Management – Funds Flow" in the Company's unaudited interim consolidated financial statements for the three and nine months ended September 30, 2023 for a detailed calculation.
(2) "Free funds flow" is a non-GAAP financial measure calculated as funds flow less expenditures on PP&E. Management believes that free funds flow provides a useful measure of Whitecap's ability to increase returns to shareholders and to grow the Company's business. Free funds flow is not a standardized financial measure under IFRS and, therefore, may not be comparable with the calculation of similar financial measures disclosed by other entities. The most directly comparable financial measure to free funds flow disclosed in the primary financial statements is cash flow from operating activities.
(3) "Basic payout ratio" is a supplementary financial measure calculated as dividends declared divided by funds flow. Management believes that basic payout ratio provides a useful measure of Whitecap's dividend policy and the amount of funds flow retained by the Company for capital reinvestment.
(4) "Total payout ratio" is a supplementary financial measure calculated as dividends declared plus expenditures on PP&E, divided by funds flow. Management believes that total payout ratio provides a useful measure of Whitecap's capital reinvestment and dividend policy, as a percentage of the amount of funds flow.
Dividends are only declared once they are approved by the Company's Board of Directors. The Board of Directors reviews Whitecap's dividend payment on a monthly basis.
Cash flow from operating activities for the three and nine months ended September 30, 2023 was $382.8 million and $1,266.3 million, respectively, compared to $559.9 million and $1,627.2 million for the same periods in 2022. The following changes impacted cash flow from operating activities:
Exhibit 6
Funds flow for the three and nine months ended September 30, 2023 was $466.0 million and $1,329.1 million, respectively, compared to $546.8 million and $1,729.1 million for the same periods in 2022. The decreases are primarily due to lower commodity prices, partially offset by higher production volumes in the three and nine months ended September 30, 2023 compared to the same periods in 2022.
Free funds flow for the three and nine months ended September 30, 2023 was $184.1 million and $575.8 million, respectively, compared to $338.8 million and $1,221.6 million for the same periods in 2022. The decreases in free funds flow are primarily attributed to lower funds flow and higher capital expenditures in the three and nine months ended September 30, 2023 compared to the same periods in 2022.
Expenditures on Property, Plant and Equipment
| Three months ended | Nine months ended | |||
|---|---|---|---|---|
| September 30, | September 30, | |||
| ($ millions) | 2023 | 2022 | 2023 | 2022 |
| Land and geological | 1.3 | 0.4 | 4.3 | 3.1 |
| Drilling and completions | 236.9 | 179.6 | 619.4 | 403.1 |
| Investment in facilities | 41.1 | 24.0 | 117.7 | 87.7 |
| Capitalized administration | 2.0 | 2.1 | 11.0 | 9.1 |
| Corporate and other assets | 0.6 | 1.9 | 0.9 | 4.5 |
| Expenditures on property, plant and equipment | 281.9 | 208.0 | 753.3 | 507.5 |
For the third quarter of 2023, expenditures on property, plant and equipment totaled $281.9 million with 99 percent spent on drilling, completions, and facilities. Year to date, expenditures on property, plant and equipment totaled $753.3 million with 98 percent spent on drilling, completions, and facilities.
For the three and nine months ended September 30, 2023, Whitecap's drilling activity was as follows:
| Three months endedSeptember 30, 2023 | Nine months endedSeptember 30, 2023 | |||
|---|---|---|---|---|
| Gross | Net | Gross | Net | |
| East Division | 76 | 63.7 | 173 | 153.0 |
| West Division | 13 | 11.8 | 28 | 24.9 |
| Total | 89 | 75.5 | 201 | 177.9 |
For the three and nine months ended September 30, 2022, Whitecap's drilling activity was as follows:
| Three months endedSeptember 30, 2022 | Nine months endedSeptember 30, 2022 | ||||
|---|---|---|---|---|---|
| Gross | Net | Gross | Net | ||
| East Division | 73 | 58.7 | 141 | 118.1 | |
| West Division | 11 | 9.7 | 23 | 20.1 | |
| Total | 84 | 68.4 | 164 | 138.2 |
Decommissioning Liability
At September 30, 2023, the Company's decommissioning liability balance was $0.9 billion ($1.0 billion at December 31, 2022) for future abandonment and reclamation of the Company's properties. The decrease in the decommissioning liability at September 30, 2023 compared to December 31, 2022 is primarily attributed to the increase in the risk-free rate from 3.3 percent at December 31, 2022 to 3.8 percent at September 30, 2023. Estimates are based on both operational knowledge of the properties and updated industry guidance provided by the Alberta Energy Regulator, the Saskatchewan Ministry of the Economy and the BC Oil and Gas Commission. The estimates are reviewed quarterly and adjusted as new information regarding the liability is determined.
Exhibit 7
Capital Resources and Liquidity
At September 30, 2023, the Company had a total credit capacity of $3.1 billion which consisted of a $2.0 billion credit facility, a $705 million term loan facility, and $395 million in senior secured notes.
Credit Facility
At September 30, 2023, the Company had a $2.0 billion credit facility with a syndicate of banks. The credit facility consists of a $1.93 billion revolving syndicated facility and a $75.0 million revolving operating facility, with a maturity date of May 31, 2026. At September 30, 2023, the amount drawn on the credit facilities was $0.1 billion. Prior to any anniversary date, being May 31 of each year, Whitecap may request an extension of the then current maturity date, subject to approval by the banks. Following the granting of such extension, the term to maturity of the credit facilities shall not exceed four years. The credit facility provides that advances may be made by way of direct advances, banker's acceptances or letters of credit/guarantees. The credit facility bears interest at the bank's prime lending or bankers' acceptance rates plus applicable margins. The applicable margin charged by the bank is dependent upon the Company's debt to earnings before interest, taxes, depreciation and amortization ("EBITDA") ratio for the most recent quarter. The bankers' acceptances bear interest at the applicable banker's acceptance rate plus an explicit stamping fee based upon the Company's debt to EBITDA ratio. The credit facilities are secured by a floating charge debenture on the assets of the Company.
The following table lists Whitecap's financial covenants as at September 30, 2023:
| Covenant Description | September 30, 2023 | |
|---|---|---|
| Debt to EBITDA (1) (2) | Maximum Ratio 4.00 | 0.57 |
| EBITDA to interest expense (1) | Minimum Ratio 3.50 | 26.23 |
Notes:
(1) The EBITDA used in the covenant calculation is adjusted for non-cash items, transaction costs and extraordinary and non-recurring items such as material acquisitions or dispositions.
(2) The debt used in the covenant calculation includes bank indebtedness, letters of credit, and dividends declared.
At September 30, 2023, the Company was compliant with all covenants provided for in the credit agreement. Copies of the Company's credit agreements and amendments may be accessed through the SEDAR+ website (www.sedarplus.ca).
Term Loan
At September 30, 2023, the Company had a $705 million term loan facility, which was obtained in conjunction with the closing of the XTO acquisition. The term loan has a maturity date of May 31, 2026 and is repayable at any time with no penalty. At September 30, 2023, the amount of the term loan outstanding was $705 million. The term loan provides that advances may be made by way of direct advances or banker's acceptances. The term loan bears interest at the bank's prime lending or bankers' acceptance rates plus applicable margins. The applicable margin charged by the bank is dependent upon the Company's debt to EBITDA ratio for the most recent quarter.
The term loan is subject to the same debt to EBITDA ratio and EBITDA to interest expense ratio described under the credit facility. At September 30, 2023, the Company was compliant with all covenants provided for in the term loan agreement**.** A copy of the Company's term loan agreement may be accessed through the SEDAR+ website (www.sedarplus.ca).
Senior Secured Notes
At September 30, 2023, the Company had issued $395 million senior secured notes. The notes rank equally with Whitecap's obligations under its credit facility and term loan.
The terms, rates and principals of the Company's outstanding senior notes are detailed below:
| ($ millions) | |||
|---|---|---|---|
| Issue Date | Maturity Date | Coupon Rate | Principal |
| May 31, 2017 | May 31, 2024 | 3.54% | 200.0 |
| December 20, 2017 | December 20, 2026 | 3.90% | 195.0 |
| Balance at September 30, 2023 | 395.0 |
The senior secured notes are subject to the same debt to EBITDA ratio and EBITDA to interest expense ratio described under the credit facility. At September 30, 2023, the Company was compliant with all covenants provided for in the note agreements. Copies of the Company's note agreements and amendments may be accessed through the SEDAR+ website (www.sedarplus.ca).
Equity
On May 17, 2023, the Company announced the approval of its renewed NCIB by the TSX (the "2023 NCIB"). The 2023 NCIB allows the Company to purchase up to 59,724,590 common shares over a period of twelve months commencing on May 23, 2023.
On May 16, 2022, the Company announced the approval of its renewed NCIB by the TSX (the "2022 NCIB"). The 2022 NCIB allowed the Company to purchase up to 58,341,984 common shares over a period of twelve months commencing on May 21, 2022.
On May 17, 2021, the Company announced the approval of its renewed NCIB by the TSX (the "2021 NCIB"). The 2021 NCIB allowed the Company to purchase up to 29,894,096 common shares over a period of twelve months commencing on May 21, 2021. On March 22, 2022, the Company amended its 2021 NCIB to increase the number of common shares that it may purchase to 58,947,076 during the twelve month period commencing on May 21, 2021. No other terms of the 2021 NCIB changed.
Purchases are made on the open market through the TSX or alternative platforms at the market price of such common shares. All common shares purchased under the NCIB are cancelled. The total cost paid, including commissions and fees, is first charged to share capital to the extent of the average carrying value of Whitecap's common shares and the excess is charged to retained earnings.
The following table summarizes the share repurchase activities during the periods:
| Three months endedSeptember 30, | Nine months endedSeptember 30, | ||||
|---|---|---|---|---|---|
| (millions except per share amounts) | 2023 | 2022 | 2023 | 2022 | |
| Shares repurchased | - | 8.4 | 3.5 | 20.1 | |
| Average cost ($/share) | - | 8.45 | 9.56 | 9.53 | |
| Amounts charged to | |||||
| Share capital ($) | - | 67.2 | 27.6 | 162.0 | |
| Retained earnings ($) | - | 3.5 | 5.4 | 29.5 | |
| Share repurchase cost ($) | - | 70.7 | 33.0 | 191.5 |
The Company is authorized to issue an unlimited number of common shares without nominal or par value. The Company is also authorized to issue an unlimited number of preferred shares without nominal or par value provided that, if the authorized preferred shares are to be assigned voting or conversion rights, the number of preferred shares to be issued may not exceed twenty percent of the number of issued and outstanding common shares at the time of issuance of any such preferred shares. At October 24, 2023, there were 606.2 million common shares and 7.2 million share awards outstanding.
Liquidity
The Company generally relies on funds flow and its credit facility to fund its capital requirements, dividend payments and provide liquidity. From time to time, the Company accesses capital markets to meet its additional financing needs for acquisitions. Future liquidity depends primarily on funds flow, existing credit facilities and the ability to access debt and equity markets. All repayments on the revolving production and operating facilities are due at the term maturity date. The Company expects, has the discretion, and has sufficient capacity to refinance its senior notes maturing on May 31, 2024 under its existing credit facility. As none of the facilities mature within the next year, all liabilities related to the Company's debt are considered to be non-current. At September 30, 2023, the Company had $1.9 billion of unutilized credit to cover any working capital deficiencies. The Company believes that available credit facilities, combined with anticipated funds flow, will be sufficient to satisfy the remainder of Whitecap's 2023 development capital program and dividend payments for the remainder of the 2023 fiscal year.
Contractual Obligations
Whitecap has contractual obligations in the normal course of business which may include purchase of assets and services, operating agreements, transportation commitments, sales commitments, royalty obligations, lease rental obligations, employee agreements and debt. These obligations are of a recurring, consistent nature and impact Whitecap's cash flows in an ongoing manner.
The Company is committed to future payments under the following agreements:
| ($ millions) | 2023 | 2024 | 2025 | 2026+ | Total |
|---|---|---|---|---|---|
| Long-term debt (1) | 3.7 | 210.5 | 7.6 | 1,066.9 | 1,288.7 |
| Transportation agreements | 30.8 | 106.1 | 90.7 | 466.4 | 694.0 |
| CO2 purchase commitments | 9.1 | 37.1 | 37.7 | 217.6 | 301.5 |
| Lease liabilities (1) | 2.2 | 8.4 | 7.7 | 31.5 | 49.8 |
| Service agreements | 1.1 | 4.7 | 4.0 | 25.0 | 34.8 |
| Total | 46.9 | 366.8 | 147.7 | 1,807.4 | 2,368.8 |
Note:
(1) These amounts include the notional principal and interest payments.
Related Party Transactions
The Company has retained the law firm of Burnet, Duckworth & Palmer LLP ("BD&P") to provide Whitecap with legal services. A director of Whitecap is a partner of this firm. During the three and nine months ended September 30, 2023, the Company incurred $0.4 million and $1.8 million, respectively, for legal fees and disbursements ($0.2 million and $0.8 million for the three and nine months ended September 30, 2022, respectively). These amounts have been recorded at the amounts that have been agreed upon by the two parties. The Company expects to retain the services of BD&P from time to time. At September 30, 2023, the payable balance was nil (nil – September 30, 2022).
Changes in Accounting Policies Including Initial Adoption
There were no changes that had a material effect on the reported income or net assets of the Company.
Standards Issued but not yet Effective
There are no other standards or interpretations issued, but not yet adopted, that are anticipated to have a material effect on the reported net income or net assets of the Company.
Off Balance Sheet Arrangements
The Company does not have any special purpose entities nor is it party to any arrangements that would be excluded from the balance sheet other than commitments disclosed in Note 18 "Commitments" to the Company's unaudited interim consolidated financial statements for the three and nine months ended September 30, 2023.
Critical Accounting Estimates
Whitecap's financial and operating results may incorporate certain estimates including:
- estimated revenues, royalties and operating expenses on production as at a specific reporting date but for which actual revenues and expenses have not yet been received;
- estimated expenditures on property, plant and equipment on projects that are in progress;
- estimated depletion, depreciation, amortization and accretion that are based on estimates of oil and gas reserves that the Company expects to recover in the future, commodity prices, estimated future salvage values and estimated future capital costs;
- estimated fair values of derivative contracts that are subject to fluctuation depending upon the underlying commodity prices and foreign exchange rates;
- estimated value of decommissioning liabilities that are dependent upon estimates of future costs, timing of expenditures and the risk-free rate;
- estimated income and other tax liabilities requiring interpretation of complex laws and regulations. All tax filings are subject to audit and potential reassessment after the lapse of considerable time;
- estimated stock-based compensation expense using the Black-Scholes option pricing model;
- estimated fair value of business combinations and goodwill requires management to make assumptions and estimates about future events. The assumptions and estimates with respect to determining the fair value of PP&E and exploration and evaluation assets acquired generally require the most judgment and include estimates of reserves acquired, forecast benchmark commodity prices, future costs and discount rates; and
- estimated recoverable amounts are based on estimated proved plus probable oil and natural gas reserves, production rates, benchmark commodity prices, future costs, discount rates and other relevant assumptions, used in impairment (reversal) calculations and the assessment of appropriate accounting treatment of sale of royalty interests.
For more details regarding the Company's use of estimates and judgements, refer to Note 2(d) "Use of Estimates and Judgements" to the Company's audited annual consolidated financial statements for the year ended December 31, 2022.
The Company has hired individuals and consultants who have the skills required to make such estimates and ensures that individuals or departments with the most knowledge of the activity are responsible for the estimates. Furthermore, past estimates are reviewed and compared to actual results, and actual results are compared to budgets in order to make more informed decisions on future estimates.
Business Risks
Whitecap's exploration and production activities are concentrated in the Western Canadian Sedimentary Basin, where activity is highly competitive and includes a variety of different-sized companies. Whitecap is subject to a number of risks that are also common to other organizations involved in the oil and gas industry. Such risks include finding and developing oil and gas reserves at economic costs, estimating amounts of recoverable reserves, production of oil and gas in commercial quantities, marketability of oil and gas produced, fluctuations in commodity prices, stock market volatility, debt service which may limit timing or amount of dividends as well as market price of shares, financial and liquidity risks and environmental and safety risks.
In order to reduce exploration risk, Whitecap employs or contracts highly qualified and motivated professionals who have demonstrated the ability to generate quality proprietary geological and geophysical prospects. Whitecap has retained independent petroleum consultants that assist the Company in evaluating recoverable amounts of oil and gas reserves. Values of recoverable reserves are based on a number of variable factors and assumptions such as commodity prices, projected production, future production costs and government regulations. Such estimates will vary from actual results and such variations may be material.
The Company mitigates its risk related to producing hydrocarbons through the utilization of current technology and information systems. In addition, Whitecap strives to operate the majority of its prospects, thereby maintaining operational control. When the Company does not operate, it relies on its partners in jointly owned properties to maintain operational control.
Whitecap is exposed to market risk to the extent that the demand for oil and gas produced by the Company exists within Canada and the United States. External factors beyond the Company's control may affect the marketability of oil and gas produced. These factors include commodity prices and variations in the Canada–United States currency exchange rate which, in turn, responds to economic and political circumstances throughout the world. Oil prices are affected by worldwide supply and demand fundamentals while natural gas prices are affected by North American supply and demand fundamentals. Whitecap uses futures and options contracts to mitigate its exposure to the potential adverse impact of commodity price volatility. The primary objective of the risk management program is to provide a measure of stability to Whitecap dividends and its capital development program.
Exploration and production for oil and gas is capital intensive. In addition to funds flow, the Company accesses the equity markets as a source of new capital. In addition, Whitecap utilizes bank financing to support ongoing capital investments which exposes the Company to fluctuations in interest rates on its bank debt. Funds flow also fluctuates with changing commodity prices. Equity and debt capital are subject to market conditions, and availability and cost may increase or decrease from time to time.
The Company's business, operations and financial condition were significantly adversely affected by COVID-19. Actions taken to reduce the spread of COVID-19 resulted in volatility and disruptions in regular business operations, supply chains and financial markets, as well as declining trade and market sentiment. In 2020, COVID-19, as well as other factors, resulted in the deepest drop in crude oil prices that global markets have seen since 1991. The extent to which Whitecap's operational and financial results are affected by COVID-19, or any other potential pandemic, in the future will depend on whether, and to what extent, actions are taken by businesses and governments in response to any resurgence of the pandemic and the speed and effectiveness of responses to combat any such resurgence of the virus.
Environmental Risks
General Risks
Oil and gas exploration and production can involve environmental risks such as litigation, physical and regulatory risks. Physical risks include the pollution of the environment, climate change and destruction of natural habitat, as well as safety risks such as personal injury. The Company works hard to identify the potential environmental impacts of its new projects in the planning stage and during operations. The Company conducts its operations with high standards in order to protect the environment, its employees and consultants, and the general public. Whitecap maintains current insurance coverage for comprehensive and general liability as well as limited pollution liability. The amount and terms of this insurance are reviewed on an ongoing basis and adjusted as necessary to reflect current corporate requirements, as well as industry standards and government regulations. Without such insurance, and if the Company becomes subject to environmental liabilities, the payment of such liabilities could reduce or eliminate its available funds or could exceed the funds the Company has available and result in financial distress.
Climate Change Risks
Our exploration and production facilities and other operations and activities emit greenhouse gasses ("GHG") which may require us to comply with federal and/or provincial GHG emissions legislation. Climate change policy is evolving at regional, national and international levels, and political and economic events may significantly affect the scope and timing of climate change measures that are ultimately put in place to prevent climate change or mitigate its effects. The direct or indirect costs of compliance with GHG-related regulations may have a material adverse effect on our business, financial condition, results of operations and prospects. Some of our significant facilities may ultimately be subject to future regional, provincial and/or federal climate change regulations to manage GHG emissions. In addition, climate change has been linked to long-term shifts in climate patterns and extreme weather conditions both of which pose the risk of causing operational difficulties.
Additional information regarding risk factors including, but not limited to, business risks and environmental risks is available in our Annual Information Form for the year ended December 31, 2022, a copy of which may be accessed through the SEDAR+ website (www.sedarplus.ca).
Summary of Quarterly Results
| 2023 | 2022 | 2021 | ||||||
|---|---|---|---|---|---|---|---|---|
| ($ millions, except as noted) | Q3 | Q2 | Q1 | Q4 | Q3 | Q2 | Q1 | Q4 |
| Financial | ||||||||
| Petroleum and natural gas | ||||||||
| revenues | 955.9 | 797.9 | 883.7 | 1,116.5 | 1,070.5 | 1,262.0 | 1,003.9 | 785.8 |
| Funds flow (1) | 466.0 | 415.1 | 448.0 | 593.6 | 546.8 | 676.6 | 505.7 | 350.6 |
| Basic ($/share) (1) | 0.77 | 0.69 | 0.74 | 0.97 | 0.89 | 1.09 | 0.81 | 0.56 |
| Diluted ($/share) (1) | 0.76 | 0.68 | 0.73 | 0.97 | 0.88 | 1.08 | 0.80 | 0.55 |
| Net income | 152.7 | 175.4 | 262.6 | 318.7 | 324.5 | 380.7 | 652.3 | 223.8 |
| Basic ($/share) | 0.25 | 0.29 | 0.43 | 0.52 | 0.53 | 0.62 | 1.04 | 0.36 |
| Diluted ($/share) | 0.25 | 0.29 | 0.43 | 0.52 | 0.53 | 0.61 | 1.03 | 0.35 |
| Expenditures on PP&E | 281.9 | 217.8 | 253.6 | 179.0 | 208.0 | 88.0 | 211.5 | 134.9 |
| Total assets | 9,207.1 | 9,151.7 | 9,163.2 | 9,529.8 | 9,555.6 | 7,695.9 | 7,815.3 | 6,878.2 |
| Long-term debt | 1,177.1 | 1,259.5 | 1,336.7 | 1,844.6 | 2,045.6 | 845.0 | 1,067.8 | 1,055.7 |
| Net debt (2) | 1,260.2 | 1,361.2 | 1,471.1 | 1,913.1 | 2,192.3 | 673.8 | 1,093.3 | 1,154.6 |
| Common shares | ||||||||
| outstanding (millions) | 606.2 | 605.8 | 603.0 | 608.7 | 610.6 | 618.6 | 626.3 | 615.8 |
| Dividends declared per | ||||||||
| share | 0.15 | 0.15 | 0.15 | 0.11 | 0.11 | 0.09 | 0.08 | 0.07 |
| Operational | ||||||||
| Average daily production | ||||||||
| Crude oil (bbls/d) (3) | 85,238 | 82,649 | 86,276 | 91,812 | 85,137 | 85,657 | 82,980 | 79,315 |
| NGLs (bbls/d) (3) | 17,804 | 15,448 | 16,655 | 17,473 | 16,513 | 13,465 | 14,591 | 10,568 |
| Natural gas (Mcf/d) (3) | 323,903 | 294,412 | 313,159 | 342,640 | 264,886 | 199,026 | 210,720 | 180,820 |
| Total (boe/d) (4) | 157,026 | 147,166 | 155,124 | 166,392 | 145,798 | 132,293 | 132,691 | 120,020 |
Notes:
(1) Refer to Note 5(e) "Capital Management" to the Company's unaudited interim consolidated financial statements for the three and nine months ended September 30, 2023, to the section entitled "Cash Flow from Operating Activities, Funds Flow and Payout Ratios" contained within this MD&A and to the disclosure regarding net debt below.
(2) "Net Debt" is a capital management measure and is key to assessing the Company's liquidity. See Note 5(e)(i) "Capital Management – Net Debt and Total Capitalization" in the Company's unaudited interim consolidated financial statements for the three and nine months ended September 30, 2023 for a detailed calculation. The following table reconciles the Company's long-term debt to net debt:
| 2023 | 2022 | 2021 | ||||||
|---|---|---|---|---|---|---|---|---|
| ($ millions) | Q3 | Q2 | Q1 | Q4 | Q3 | Q2 | Q1 | Q4 |
| Long-term debt | 1,177.1 | 1,259.5 | 1,336.7 | 1,844.6 | 2,045.6 | 845.0 | 1,067.8 | 1,055.7 |
| Accounts receivable | (452.3) | (357.5) | (405.8) | (480.2) | (468.4) | (504.5) | (498.5) | (304.8) |
| Deposits and prepaid | ||||||||
| expenses | (44.9) | (28.1) | (18.1) | (22.7) | (16.6) | (198.0) | (8.7) | (10.5) |
| Non-current deposits | (65.3) | - | - | - | - | - | - | - |
| Accounts payable and | ||||||||
| accrued liabilities | 616.4 | 458.1 | 529.2 | 549.1 | 609.2 | 512.7 | 513.9 | 400.4 |
| Dividends payable | 29.2 | 29.2 | 29.1 | 22.3 | 22.4 | 18.6 | 18.9 | 13.8 |
| Net debt | 1,260.2 | 1,361.2 | 1,471.1 | 1,913.1 | 2,192.3 | 673.8 | 1,093.3 | 1,154.6 |
(3) "Crude oil" refers to light and medium crude oil, tight oil, and condensate combined. "NGLs" refers to ethane, propane, butane and pentane combined. "Natural gas" refers to conventional natural gas and shale gas combined. For further breakdown of crude oil and natural gas production volumes refer to the "Product Type Information" section of this MD&A.
(4) Disclosure of production on a per boe basis in this MD&A consists of the constituent product types and their respective quantities disclosed in the "Product Type Information" section of this MD&A. Also refer to the "Boe Presentation" section of this MD&A.
Over the past eight quarters, fluctuations in production volumes and realized commodity prices have impacted the Company's petroleum and natural gas revenues and funds flow. Net income has fluctuated due to changes in funds flow, impairment expenses and reversals, and unrealized risk management gains and losses which fluctuate with the changes in forward benchmark commodity prices and exchange rates. Capital expenditures and production volumes have fluctuated over time as a result of the timing of acquisitions and dispositions and the impact of market conditions on the Company's development capital expenditures.
The following outlines the significant events over the past eight quarters:
In the third quarter of 2023, the Board of Directors approved an increase to the monthly dividend from $0.0483 per common share to $0.0608 per common share ($0.73 per common share annualized). The dividend increase will be effective for the October 2023 dividend paid in November 2023.
In the second quarter of 2023, wildfires in Alberta impacted the Company's operations in northern Alberta and in northeast British Columbia, which at times resulted in significant volumes of production being shut-in.
In the first quarter of 2023, the Company closed the previously announced dispositions of certain non-core assets for total consideration of $389.5 million. The Company repurchased 3.5 million common shares at an average price of $9.56 per share during the first quarter of 2023.
In the fourth quarter of 2022, the Company announced that it had entered into three definitive agreements to dispose of certain non-core assets, effective October 1, 2022. The assets were classified as held for sale at December 31, 2022. In December 2022, Whitecap's Board of Directors approved an increase to the monthly dividend from $0.0367 per common share to $0.0483 per common share ($0.58 per common share annualized). The dividend increase was effective for the January 2023 dividend paid in February 2023. The Company repurchased 4.9 million common shares at an average price of $10.50 per share during the fourth quarter of 2022.
In the third quarter of 2022, the Company closed the acquisition of XTO Energy Canada and achieved record production. In connection with the XTO acquisition, the Company closed the issuance of a new term loan of $705 million and increased the existing syndicated facility by $395 million to $1.93 billion, resulting in an increase to the Company's total credit capacity to $3.1 billion. The Company repurchased 8.4 million common shares at an average price of $8.45 per share during the third quarter of 2022.
In the second quarter of 2022, Whitecap's Board of Directors approved an increase to the monthly dividend from $0.03 per common share to $0.0367 per common share ($0.44 per common share annualized). The dividend increase was effective for the July 2022 dividend paid in August 2022. The Company repurchased 11.7 million common shares at an average price of $10.30 per share during the second quarter of 2022.
In the first quarter of 2022, the Company closed the acquisition of TimberRock. In February 2022, as a result of the strong operational performance and the successful integration of the acquisitions completed in 2021 and 2022, Whitecap's Board of Directors approved an increase to the monthly dividend from $0.0225 per common share to $0.03 per common share ($0.36 per common share annualized). The dividend increase was effective for the March 2022 dividend paid in April 2022. Additionally, as a result of higher forecast benchmark commodity prices at March 31, 2022 compared to December 31, 2021, the Company recognized impairment reversals of $629.7 million attributable to PP&E.
In the fourth quarter of 2021, the Company extended the maturity date on its credit facility to May 31, 2026 and increased the credit facility to $1.6 billion. The Company repurchased 19.2 million Whitecap common shares at an average price of $6.96 per share, during the fourth quarter of 2021, executed by way of a block trade under its NCIB.
INTERNAL CONTROLS UPDATE
Whitecap is required to comply with National Instrument 52-109 Certification of Disclosure in Issuers' Annual and Interim Filings ("NI 52-109"). NI 52-109 requires that Whitecap disclose in its interim MD&A any material weaknesses relating to design existing at the end of the period in Whitecap's internal control over financial reporting and/or any changes in Whitecap's internal control over financial reporting that occurred during the period that have materially affected, or are reasonably likely to materially affect, Whitecap's internal controls over financial reporting. Whitecap confirms that no material weaknesses or such changes were identified in Whitecap's internal controls over financial reporting at the end of or during the third quarter of 2023.
ADVISORIES
Boe Presentation
"Boe" means barrel of oil equivalent. All boe conversions in this MD&A are derived by converting gas to oil at the ratio of six thousand cubic feet ("Mcf") of natural gas to one barrel ("bbl") of oil. Boe may be misleading, particularly if used in isolation. A boe conversion rate of 1 bbl : 6 Mcf is based on an energy equivalency conversion method primarily applicable at the burner tip and does not represent a value equivalency at the wellhead. Given that the value ratio of oil compared to natural gas based on currently prevailing prices is significantly different than the energy equivalency ratio of 1 bbl : 6 Mcf, utilizing a conversion ratio of 1 bbl : 6 Mcf may be misleading as an indication of value.
Supplementary Financial Measures
Average realized prices for crude oil, NGLs and natural gas are supplementary financial measures calculated by dividing each of these components of petroleum and natural gas revenues, disclosed in Note 15 "Revenue" to the Company's unaudited interim consolidated financial statements for the three and nine months ended September 30, 2023, by their respective production volumes for the period.
Per boe disclosures for petroleum and natural gas revenues, tariffs, processing and other income and marketing revenues are supplementary financial measures calculated by dividing each of these components of petroleum and natural gas sales, disclosed in Note 15 "Revenue" to the Company's unaudited interim consolidated financial statements for the three and nine months ended September 30, 2023, by the Company's total production volumes for the period.
Realized gain (loss) on commodity contracts per boe is a supplementary financial measure calculated by dividing realized gain (loss) on commodity contracts, disclosed in Note 5(d) "Financial Instruments and Risk Management – Market Risk" to the Company's unaudited interim consolidated financial statements for the three and nine months ended September 30, 2023, by the Company's total production volumes for the period.
Per boe disclosures for petroleum and natural gas sales, royalties, operating expenses, transportation expenses, marketing expenses, G&A expenses, stock-based compensation expenses, interest and financing expenses, and depletion, depreciation and amortization are supplementary financial measures that are calculated by dividing each of these respective GAAP measures by the Company's total production volumes for the period.
Royalties as a percentage of petroleum and natural gas revenues is a supplementary financial measure calculated by dividing royalties by petroleum and natural gas revenues, disclosed in Note 15 "Revenue" to the Company's unaudited interim consolidated financial statements for the three and nine months ended September 30, 2023.
Product Type Information
This MD&A includes references to crude oil, NGLs, natural gas and total average daily production.
NI 51-101 includes condensate within the natural gas liquids ("NGLs") product type. The Company has disclosed condensate as combined with crude oil and separately from other natural gas liquids in this MD&A since the price of condensate as compared to other natural gas liquids is currently significantly higher and the Company believes that this combined crude oil and condensate presentation provides a more accurate description of its operations and results therefrom. Crude oil therefore refers to light, medium and tight oil and condensate combined. NGLs refers to ethane, propane, butane and pentane combined. Natural gas refers to conventional natural gas and shale gas combined.
The Company's aggregate average production for the past eight quarters and the references to "crude oil", "NGLs", and "natural gas" reported in this MD&A consist of the following product types, as defined in NI 51-101 (except as noted above) and using a conversion ratio of 1 bbl : 6 Mcf where applicable:
| 2023 | 2022 | 2021 | ||||||
|---|---|---|---|---|---|---|---|---|
| Q3 | Q2 | Q1 | Q4 | Q3 | Q2 | Q1 | Q4 | |
| Light and medium oil | ||||||||
| (bbls/d) (1) | 74,981 | 72,896 | 76,917 | 80,776 | 79,180 | 82,401 | 79,406 | 75,628 |
| Tight oil (bbls/d) | 10,257 | 9,753 | 9,359 | 11,036 | 5,957 | 3,256 | 3,574 | 3,687 |
| Crude oil (bbls/d) | 85,238 | 82,649 | 86,276 | 91,812 | 85,137 | 85,657 | 82,980 | 79,315 |
| NGLs (bbls/d) | 17,804 | 15,448 | 16,655 | 17,473 | 16,513 | 13,465 | 14,591 | 10,568 |
| Shale gas (Mcf/d)Conventional natural gas | 172,384 | 157,329 | 158,024 | 181,478 | 104,358 | 50,250 | 51,605 | 42,993 |
| (Mcf/d) | 151,519 | 137,083 | 155,135 | 161,162 | 160,528 | 148,776 | 159,115 | 137,827 |
| Natural gas (Mcf/d) | 323,903 | 294,412 | 313,159 | 342,640 | 264,886 | 199,026 | 210,720 | 180,820 |
| Total (boe/d) | 157,026 | 147,166 | 155,124 | 166,392 | 145,798 | 132,293 | 132,691 | 120,020 |
Note:
(1) Light and medium oil includes condensate.
The Company's aggregate average production for the nine months ended September 30, 2023 and 2022 and the references to "crude oil", "NGLs", and "natural gas" reported in this MD&A consist of the following product types, as defined in NI 51-101 (except as noted above) and using a conversion ratio of 1 bbl : 6 Mcf where applicable:
| Nine months ended | ||
|---|---|---|
| September 30, | ||
| 2023 | 2022 | |
| Light and medium oil (bbls/d) (1) | 74,924 | 80,328 |
| Tight oil (bbls/d) | 9,793 | 4,271 |
| Crude oil (bbls/d) | 84,717 | 84,599 |
| NGLs (bbls/d) | 16,640 | 14,863 |
| Shale gas (Mcf/d) | 162,632 | 68,931 |
| Conventional natural gas (Mcf/d) | 147,899 | 156,145 |
| Natural gas (Mcf/d) | 310,531 | 225,076 |
| Total (boe/d) | 153,112 | 136,975 |
Note:
(1) Light and medium oil includes condensate.
Forward-Looking Information and Statements
Certain statements contained in this MD&A constitute forward-looking statements and are based on Whitecap's beliefs and assumptions based on information available at the time the assumption was made. By its nature, such forward-looking information involves known and unknown risks, uncertainties and other factors that may cause actual results or events to differ materially from those anticipated in such forward-looking statements. The Company believes the expectations reflected in those forward-looking statements are reasonable, but no assurance can be given that these expectations will prove to be correct and such forward-looking statements should not be unduly relied upon.
This MD&A contains certain forward-looking information and statements within the meaning of applicable securities laws. The use of any of the words "expect", "anticipate", "estimate", "objective", "ongoing", "may", "will", "project", "believe", "measure", "stability", "depends", "could", "sustainability" and similar expressions are intended to identify forward-looking information or statements. In particular, but without limiting the foregoing, this MD&A contains forward-looking information and statements pertaining to the following: Whitecap's focus and strategy; Whitecap's ongoing risk management program and the benefits to be derived therefrom; the factors that may affect Whitecap's marketing activities; our expectation that income earned in 2023 will exceed allowable tax pool deductions in 2023; our intention to file a notice of objection for each ATRA notice of assessment and the amount of the deposit that we anticipate paying in connection therewith; our estimate of the length of time it may take to resolve the reassessments discussed herein; our view that if Whitecap is ultimately successful in defending its position in respect of such reassessments, then any taxes, interest, and penalties paid would be refunded plus interest, and if the CRA is successful then any remaining taxes payable plus interest and any penalties would have to be remitted by Whitecap; our estimate of the amount of our future decommissioning liabilities for future abandonment and reclamation of our properties; the sources and amounts of our future liquidity and financial capacity, including our expectation that we will be able to refinance our senior secured notes maturing in May 2024 under our existing credit facility; the belief that available credit facilities combined with anticipated funds flow will be sufficient to satisfy the remainder of Whitecap's 2023 development capital program and dividend payments for the remainder of the 2023 fiscal year; and the actions Whitecap expects to take to mitigate the business, environmental and other risks that it faces.
The forward-looking information and statements contained in this MD&A reflect several material factors and expectations and assumptions of Whitecap including, without limitation: the availability and amount of the non-capital losses available to us; expectations and assumptions concerning applicable tax laws and the precedential value of historical Canadian tax case law; that Whitecap will continue to conduct its operations in a manner consistent with past operations; the general continuance or improvement in current industry conditions; the continuance of existing (and in certain circumstances, the implementation of proposed) tax, royalty and regulatory regimes; that the COVID-19 pandemic will not have a material impact going forward on (i) the demand for crude oil, NGLs and natural gas, (ii) our supply chain, including our ability to obtain the equipment and services we require, and (iii) our ability to produce, transport and/or sell our crude oil, NGLs and natural gas; the accuracy of the estimates of Whitecap's reserve volumes; the impact of increasing competition; the general stability of the economic and political environment in which Whitecap operates; the ability of Whitecap to obtain qualified staff, equipment supplies and services in a timely and cost efficient manner; the ability of Whitecap to efficiently integrate assets and employees acquired through acquisitions; drilling results; the ability of the operator of the projects which the Company has an interest in to operate in a safe, efficient and effective manner; field production and decline rates; future operating costs; the ability to replace and expand oil and natural gas reserves through acquisition, development or exploration; the timing and costs of pipeline, storage and facility construction and expansion; the ability of the Company to secure adequate product transportation; future petroleum and natural gas prices; currency, exchange, inflation and interest rates; the continued availability of adequate debt and equity financing and funds flow to fund Whitecap's planned expenditures, dividends, and share repurchases; the ability of OPEC+ nations and other major producers of crude oil to adjust production and thereby manage world crude oil prices; the impact (and duration, thereof) of the ongoing military actions between Russia and Ukraine and related sanctions on crude oil, NGLs, and natural gas prices; and the ability to maintain dividend payments at current levels. Whitecap believes the material factors, expectations and assumptions reflected in the forward-looking information and statements are reasonable, but no assurance can be given that these factors, expectations and assumptions will prove to be correct.
The forward-looking information and statements included in this MD&A are not guarantees of future performance and should not be unduly relied upon. Such information and statements involve known and unknown risks, uncertainties and other factors that may cause actual results or events to differ materially from those anticipated in such forwardlooking information or statements including, without limitation: imprecision and uncertainty in estimates of tax pools, tax shelters and tax deductions available to us; the interpretation of tax legislation and regulations applicable to us;
the risk that the CRA's and the ATRA's reassessments described herein are successful and that this outcome has a negative effect on the availability or quantum of our non-capital losses; the risk that the tax impact to us, in the event the non-capital losses are not available, is materially different than those currently contemplated; that the reassessment of our tax filings and the continuation or timing of such process is outside of our control; litigation risk associated with the reassessments of our tax filings; changes to tax legislation and administrative policies; changes in commodity prices; changes in the demand for or supply of Whitecap's products; the impact from any resurgence of the COVID-19, or any other pandemic; unanticipated operating results or production declines; changes in tax or environmental laws, royalty rates or other regulatory matters; changes in Whitecap's development plans or by third party operators of Whitecap's properties; competition from other producers; inability to retain drilling rigs and other services; failure to realize the anticipated benefits of acquisitions; incorrect assessment of the value of acquisitions; delays resulting from or inability to obtain required regulatory approvals; increased debt levels or debt service requirements; increased interest rates; inaccurate estimation of Whitecap's oil and gas reserve volumes; limited, unfavourable or a lack of access to capital markets; increased costs, whether due to high inflation rates, supply chain disruptions or other factors; availability of qualified staff, equipment supply and services; a lack of adequate insurance coverage; the impact of competitors; and certain other risks detailed from time to time in Whitecap's public disclosure documents (including, without limitation, those risks identified in this MD&A) which may be accessed through the SEDAR+ website (www.sedarplus.ca).
The forward-looking information and statements contained in this MD&A speak only as of the date of this MD&A, and Whitecap does not assume any obligation to publicly update or revise them to reflect new events or circumstances, except as may be required pursuant to applicable laws.