With the increased positive outlook for commodity prices for the remainder of 2021, we have increased our 2021 capital budget by $275 million to $3.48 billion as we undertake lead activities for future growth opportunities. The increase includes $120 million for conventional and unconventional assets, $110 million for long life low decline assets and $45 million in additional well abandonment activities. These increased investments are being financed out of the repayment of the North West Redwater Partnership ("NWRP") subordinated debt. This additional capital, along with strong operating performance from our existing 2021 drilling program, now has us targeting natural gas production above our previous guided production range and corporate production on a BOE basis above the mid-point of our previous guided production range for the 2021 year.
As previously announced, the Oil Sands Pathways initiative to achieve net zero greenhouse gas emissions by 2050 is an unprecedented initiative by the Canadian energy industry, by which Canadian Natural and our industry partners will strengthen our leading environmental, social and governance ("ESG") performance, while delivering meaningful emissions reductions and balancing sustainable economic development. Collaboration with the federal and Alberta governments on this initiative will be critical for Canada to achieve its climate goals."
Canadian Natural's Chief Financial Officer, Mark Stainthorpe, added, "Canadian Natural's robust business model and world class assets delivered strong adjusted funds flow in Q2/21 of approximately $3.05 billion, resulting in approximately $1.5 billion in free cash flow after dividends and capital expenditures, excluding acquisitions.
In Q2/21, net debt was reduced by approximately $1.7 billion as we repaid and retired the remaining $2.125 billion on our non-revolving term loan originally maturing in June 2022. In addition, subsequent to quarter end, we exercised the par call option on our US$0.5 billion November 2021 public bond, allowing us to repay the bond early in August 2021, capturing interest cost savings and further retiring absolute debt.
Annual 2021 WTI strip pricing has continued to strengthen from Q2/21 quarter end and using an annual average of US$66/bbl WTI, our 2021 targeted free cash flow increases significantly to a range of $7.2 billion to $7.7 billion, after dividends and net capital expenditures, excluding acquisitions. As a result of this strong free cash flow and increasing balance sheet strength achieved through 2021, the Board of Directors has revised its share repurchase policy effective July 1, 2021 and has authorized management to increase returns to shareholders through incremental share repurchases of approximately 1% of shares outstanding, or approximately 11 million shares, per quarter. Additionally, the new policy provides that once the Company reaches an absolute debt level of $15 billion, currently targeted to occur in Q4/21, 50% of free cash flow is targeted to be allocated to share repurchases under the Company's Normal Course Issuer Bid ("NCIB"), with the remaining 50% allocated to further strengthening of the Company's balance sheet."
QUARTERLY HIGHLIGHTS
| | Three Months Ended |
|
| Six Months Ended |
|
| ($ millions, except per common share amounts) | | Jun 30
2021 | | | Mar 31
2021 | | | June 30
2020 | | | June 30
2021 | | | June 30
2020 | |
| Net earnings (loss) | $ | 1,551 | | $ | 1,377 |
| $ | (310 | ) | $ | 2,928 | | $ | (1,592 | ) |
| Per common share | - basic | $ | 1.31 | | $ | 1.16 |
| $ | (0.26 | ) | $ | 2.47 | | $ | (1.35 | ) |
| - diluted | $ | 1.30 | | $ | 1.16 |
| $ | (0.26 | ) | $ | 2.46 | | $ | (1.35 | ) |
| Adjusted net earnings (loss) from operations (1) | $ | 1,480 | | $ | 1,219 |
| $ | (772 | ) | $ | 2,699 | | $ | (1,067 | ) |
| Per common share | - basic | $ | 1.25 | | $ | 1.03 |
| $ | (0.65 | ) | $ | 2.28 | | $ | (0.90 | ) |
| - diluted | $ | 1.24 | | $ | 1.03 |
| $ | (0.65 | ) | $ | 2.27 | | $ | (0.90 | ) |
| Cash flows from (used in) operating activities | $ | 2,940 | | $ | 2,536 |
| $ | (351 | ) | $ | 5,476 | | $ | 1,374 |
|
| Adjusted funds flow (2) | $ | 3,049 | | $ | 2,712 |
| $ | 415 |
| $ | 5,761 | | $ | 1,752 |
|
| Per common share | - basic | $ | 2.57 | | $ | 2.29 |
| $ | 0.35 |
| $ | 4.86 | | $ | 1.48 |
|
| - diluted | $ | 2.56 | | $ | 2.28 |
| $ | 0.35 |
| $ | 4.85 | | $ | 1.48 |
|
| Cash flows used in investing activities | $ | 719 | | $ | 648 |
| $ | 693 |
| $ | 1,367 | | $ | 1,552 |
|
| Net capital expenditures, excluding net acquisition costs (3) | $ | 957 | | $ | 808 |
| $ | 421 |
| $ | 1,765 | | $ | 1,259 |
|
| Net capital expenditures, including net acquisition costs (3) | $ | 1,285 | | $ | 808 |
| $ | 421 |
| $ | 2,093 | | $ | 1,259 |
|
| | | |
| |
|
| |
|
| | |
| |
|
| Daily production, before royalties | | | |
| |
|
| |
|
| | |
| |
|
| Natural gas (MMcf/d) | | 1,614 | |
| 1,598 |
|
| 1,462 |
|
| 1,606 | |
| 1,451 |
|
| Crude oil and NGLs (bbl/d) | | 872,718 | |
| 979,352 |
|
| 921,895 |
|
| 925,741 | |
| 930,286 |
|
| Equivalent production (BOE/d) (4) | | 1,141,739 |
| | 1,245,703 | | | 1,165,487 | | | 1,193,434 |
| | 1,172,120 | |
Footnotes 1 through 3 describe non-GAAP financial measures that the Company considers key in evaluating its performance. Derivations of these measures are discussed in the "Advisory" section of this press release.
(1) Adjusted net earnings (loss) from operations demonstrates the Company's ability to generate after-tax operating earnings from its core business areas.
(2) Adjusted funds flow demonstrates the Company's ability to generate the cash flow necessary to fund future growth through capital investment and to repay debt.
(3) Net capital expenditures provides an understanding of the Company's capital spending activities in comparison to the Company's annual capital budget.
(4) A barrel of oil equivalent ("BOE") is derived by converting six thousand cubic feet ("Mcf") of natural gas to one barrel ("bbl") of crude oil (6 Mcf:1 bbl). This conversion may be misleading, particularly if used in isolation, or to compare the value ratio using current crude oil and natural gas prices since the 6 Mcf:1 bbl 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.
Net earnings of $1,551 million and adjusted net earnings from operations of $1,480 million were realized in Q2/21, a significant increase from Q2/20 levels, primarily as a result of higher realized pricing and effective and efficient operations.
Cash flows from operating activities were $2,940 million in Q2/21.
-
The strength of our assets, supported by safe, effective and efficient operations demonstrate our ability to generate significant and sustainable free cash flow over the long-term, making Canadian Natural's business unique, robust and sustainable.
As a result, Canadian Natural generated strong quarterly adjusted funds flow of $3,049 million in Q2/21, an increase of $2,634 million from Q2/20 levels, primarily as a result of higher realized pricing and effective and efficient operations.
-
Year to date in 2021 to the end of July, Canadian Natural has delivered effective and efficient operations and by remaining nimble has executed on a number of strategic initiatives that have resulted in increasing free cash flow generation and long term shareholder value. These strategic initiatives are outlined below:
On June 30, 2021, the Company and the equity partners together with the toll payers, agreed to optimize the structure of NWRP, to better align the commercial interests of the equity partners and the toll payers. Under this Optimization Transaction, NWRP repaid the Company's subordinated debt advance of $555 million and the Company received a $400 million distribution from NWRP.
The Company owns approximately 6.4 million shares of Inter Pipeline Ltd. ("IPL"), which is currently subject to a third-party offer to purchase, with the current value of these shares being approximately $130 million to the Company, provided that all conditions of the third-party offer for IPL shares are satisfied.
-
As a result of these strategic initiatives Canadian Natural will realize cash proceeds of approximately $1,085 million, which will be allocated to our four pillars of capital allocation; balance sheet strength, returns to shareholders, economic resource development and opportunistic acquisitions. In this regard the Company has and will utilize a portion of these proceeds as follows:
Year to date, the Company has completed three opportunistic acquisitions. The first two acquisitions consisted of natural gas assets located in the Montney region of British Columbia, with aggregate production of approximately 11,100 BOE/d (consisting of 63 MMcf/d and 600 bbl/d of NGLs), approximately 107,000 acres of Montney lands, and related processing infrastructure with approximately 140 MMcf/d of capacity. These two acquisitions build on the Company's expansive natural gas operations in northeastern British Columbia increasing our total Montney lands to approximately 1.3 million acres. The third acquisition consisted of a 5% net carried interest on an existing Canadian Natural oil sands lease, from which all of our Horizon production is derived. Total cash consideration paid for these acquisitions was approximately $450 million and our 2021 capital expenditures will be increased by this amount.
-
To further invest in value adding opportunities on our vast asset base, the Company plans to increase its 2021 capital budget by $275 million, excluding acquisitions, to approximately $3.48 billion, including approximate additions of $120 million related to conventional and unconventional assets, $110 million related to long life low decline assets and additional $45 million related to abandonment and reclamation activities. The additional activities in the second half of 2021 are as follows:
Additional conventional and unconventional capital of approximately $120 million primarily relates to additional drilling of 78 crude oil wells and development activities, with a targeted capital efficiency from these expenditures of approximately $8,400 per flowing BOE and a 2021 exit rate of approximately 14,000 BOE/d.
Additional long life low decline asset capital of approximately $110 million, consisting of approximately $35 million for construction of three new pads at Primrose, two new pads at Kirby North and two new pads at Kirby South, which will support production additions in 2022 and beyond. At Horizon, the additional capital of approximately $75 million is primarily related to additional scopes completed and the extended turnaround in Q2/21.
Our area based abandonment programs have been highly cost effective and as a result incremental capital is being allocated to complete an additional 800 well abandonments over our initial 2021 target of 2,500, as we continue to prudently manage our liabilities and environmental footprint.
These additional expenditures will result in an estimated increase of 1,500 jobs across Alberta, British Columbia and Saskatchewan.
-
These additional expenditures, effective and efficient operations, strong operational and drilling performance, development activities, and acquisitions have resulted in increased annual corporate production.
Corporate annual natural gas production is targeted to be above the top end of the previously issued range in 2021, with annual production levels now targeted between 1,680 MMcf/d to 1,720 MMcf/d, with targeted year end exit volumes in excess of 1,800 MMcf/d.
Corporate annual liquids production is targeted to be above the mid-point of the previously issued range in 2021, with annual production levels now targeted between 940 Mbbl/d to 980 Mbbl/d.
Corporate annual production is targeted to be above the mid-point of the previously issued range in 2021, with annual production levels now targeted between 1,220 MBOE/d to 1,267 MBOE/d.
-
Annual 2021 free cash flow is targeted to be robust at a range of $7.2 billion to $7.7 billion using an annual average WTI of US$66/bbl, after dividends and budgeted capital expenditures, excluding net acquisitions.
-
Free cash flow generation has been significant in 2021 and the Company's balance sheet continues to strengthen, providing the Board of Directors the confidence to approve a more defined free cash flow allocation policy in accordance with the Company's four pillars of capital allocation. Effective July 1, 2021 under the new policy, the Company targets to allocate free cash flow as follows:
Increased returns to shareholders through incremental share repurchases of approximately 1% of common shares outstanding or approximately 11 million shares per quarter.
Once the Company reaches $15.0 billion in absolute debt, currently targeted to occur in Q4/21, 50% of free cash flow is targeted to be allocated to share repurchases under the Company's NCIB, with the remaining 50% allocated to further strengthening of the Company's balance sheet.
In Q2/21, reflecting the strength of our effective and efficient operations and our high quality, long life low decline asset base, Canadian Natural generated robust quarterly free cash flow of $1,535 million, after dividend payments of $557 million and net capital expenditures of $957 million, excluding acquisitions.
Canadian Natural executed on our commitment to further strengthen our balance sheet with strong financial results in Q2/21, reducing net debt by approximately $1.7 billion from Q1/21 levels. Net debt has decreased by approximately $3.1 billion in the first two quarters of 2021.
In Q2/21 the Company fully repaid and retired the remaining outstanding balance on its $2,125 million non-revolving term loan. The facility was originally due in June 2022.
Subsequent to quarter end the Company exercised a 90-day par call option on its US$500 million 3.45% notes originally due November 15, 2021 with repayment to occur on August 16, 2021.
-
Returns to shareholders year to date in 2021 have been significant, as Canadian Natural has returned approximately $1.5 billion by way of dividends and share repurchases up to and including August 4, 2021.
In March 2021, the Company declared a quarterly dividend of $0.47 per share, an increase of 11% from the previous level of $0.425 per share, marking 2021 as the Company's 21st consecutive year of dividend increases, reflecting the Board of Directors' confidence in Canadian Natural's strength and the robustness of the Company's assets and its ability to generate significant and sustainable free cash flow.
Subsequent to quarter end the Company declared a quarterly dividend of $0.47 per share, payable on October 5, 2021.
-
In March 2021, the Board of Directors authorized management to repurchase shares under a NCIB to approximately offset options exercised throughout the coming year, in order to minimize or eliminate dilution to shareholders.
Share repurchases for cancellation in 2021 up to and including August 4, 2021 total 11,044,400 common shares at a weighted average price of $42.00.
-
In Q2/21 the Company continued its focus on safe, effective and efficient operations averaging quarterly production volumes of 1,141,739 BOE/d, decreases of 2% and 8% from Q2/20 and Q1/21 levels respectively. The decreases from prior periods are primarily as a result of the timing of the planned turnaround at our Oil Sands Mining and Upgrading operations, in particular at Horizon and de-coking at the Scotford Upgrader ("Scotford") completed in the quarter.
-
Corporate natural gas production averaged 1,614 MMcf/d in Q2/21, an increase of 10% from Q2/20 levels and comparable with Q1/21 levels. The increase from Q2/20 was primarily as a result of acquired production in Q4/20 and strong drilling results, partially offset by natural field declines and the temporary full quarter shutdown of the Pine River Gas Plant, which resumed operations on July 24, 2021, restoring production of approximately 100 MMcf/d.
Quarterly liquids production volumes averaged 872,718 bbl/d in Q2/21, decreases of 5% and 11% from Q2/20 and Q1/21 levels respectively, primarily as a result of the timing of the planned turnaround at Horizon and de-coking at Scotford completed in the quarter.
-
Canadian Natural's North America E&P liquids production, including thermal in situ was strong in Q2/21 averaging 478,314 bbl/d, an increase of 16% from Q2/20 levels and comparable with Q1/21 levels.
North American E&P liquids, including thermal in situ, operating costs averaged $12.82/bbl (US$10.44/bbl) in Q2/21, an increase of 10% from Q2/20 levels and comparable with Q1/21 levels of $12.80/bbl. The increase in operating costs from Q2/20 was primarily due to increased energy costs.
-
Canadian Natural's thermal in situ production averaged 258,551 bbl/d in Q2/21, an increase of 21% over Q2/20 levels and a decrease of 3% from Q1/21 levels.
Thermal in situ assets operating costs averaged $11.78/bbl (US$9.59/bbl) in Q2/21, increases of 16% and 3% from Q2/20 and Q1/21 levels respectively. The increase in operating costs from Q2/20 was primarily due to increased energy costs and the increase from Q1/21 was primarily as a result of lower volumes in Q2/21 from Q1/21 levels.
-
The Company's world class Oil Sands Mining and Upgrading assets averaged quarterly production of 361,707 bbl/d of Synthetic Crude Oil ("SCO") in Q2/21, decreases of 22% and 23% from Q2/20 and Q1/21 levels respectively due to the timing of the planned turnaround at Horizon and de-coking at Scotford, which were both completed in the second quarter of 2021.
The Company's focus on continuous improvement initiatives delivered high utilization and reliability at the Company's Oil Sands Mining and Upgrading assets. As a result, record monthly SCO production of approximately 495,100 bbl/d was achieved in June 2021, an increase from the previous record of approximately 490,800 bbl/d of SCO achieved in December 2020.
OPERATIONS REVIEW AND CAPITAL ALLOCATION
Canadian Natural has a balanced and diverse portfolio of assets, primarily Canadian-based, with international exposure in the UK section of the North Sea and Offshore Africa. Canadian Natural's production is well balanced between light crude oil, medium crude oil, primary heavy crude oil, Pelican Lake heavy crude oil, bitumen (thermal oil) and SCO (herein collectively referred to as "crude oil") and natural gas and NGLs. This balance provides optionality for capital investments, maximizing value for the Company's shareholders.
Underpinning this asset base is the Company's long life low decline production, representing approximately 77% of our total liquids production in Q2/21, the majority of which is zero decline high value SCO production from the Company's world class Oil Sands Mining and Upgrading assets. The remaining balance of long life low decline production comes from Canadian Natural's top tier thermal in situ oil sands operations and the Company's Pelican Lake heavy crude oil assets. The combination of these long life low decline assets, low reserves replacement costs, and effective and efficient operations, results in substantial and sustainable adjusted funds flow throughout the commodity price cycle.
In addition, Canadian Natural maintains a substantial inventory of low capital exposure projects within the Company's conventional asset base. These projects can be executed quickly and, in the right economic conditions, provide excellent returns and maximizes value for our shareholders. Supporting these projects is the Company's undeveloped land base which enables large, repeatable drilling programs that can be optimized over time. Additionally, by owning and operating most of the related infrastructure, Canadian Natural is able to control major components of the Company's operating costs and minimize production commitments. Low capital exposure projects can be quickly stopped or started depending upon success, market conditions or corporate needs.
Canadian Natural's balanced portfolio, built with both long life low decline assets and low capital exposure assets, enables effective capital allocation, production growth and value creation.
| Drilling Activity |
| Six Months Ended June 30 |
|
| | 2021 | | | 2020 | |
| (number of wells) | | Gross | |
| Net |
| | Gross | |
| Net | |
| Crude oil | | 73 | |
| 71 |
| | 43 | |
| 37 |
|
| Natural gas | | 38 | |
| 31 |
| | 13 | |
| 12 |
|
| Dry |
| - |
|
| - | | | - |
| | - | |
| Subtotal | | 111 | |
| 102 |
| | 56 | |
| 49 |
|
| Stratigraphic test / service wells | | 396 | | | 329 |
|
| 424 | | | 371 | |
| Total | | 507 |
|
| 431 | |
| 480 | | | 420 | |
| Success rate (excluding stratigraphic test / service wells) | | | | | 100% | |
| | | | 100% | |
- The Company's total crude oil and natural gas drilling program of 102 net wells for the six months ended June 30, 2021, excluding stratigraphic/service wells, represents an increase of 53 net wells from the same period in 2020.
North America Exploration and Production
| Crude oil and NGLs - excluding Thermal In Situ Oil Sands |
|
|
|
|
|
|
|
| | Three Months Ended |
|
| Six Months Ended |
|
| | June 30
2021 | | | Mar 31
2021 | | | June 30
2020 | | | June 30
2021 | | | June 30
2020 | |
| Crude oil and NGLs production (bbl/d) | | 219,763 | | | 211,206 | | | 200,699 | |
| 215,508 |
| | 214,637 | |
| Net wells targeting crude oil |
| 22 | |
| 39 |
|
| 2 |
| | 61 | |
| 30 |
|
| Net successful wells drilled | | 22 | | | 39 |
|
| 2 |
| | 61 | |
| 30 | |
| Success rate | | 100% | | | 100% | | | 100% | |
| 100% | | | 100% | |
-
Canadian Natural's North America E&P crude oil and NGL production volumes, excluding thermal in situ averaged 219,763 bbl/d in Q2/21, increases of 9% and 4% from Q2/20 and Q1/21 levels respectively. The increases from prior periods were primarily due to strong drilling results and execution on high value volume adding development activities (recompletions, workovers and reactivations) that capture improved commodity pricing, partially offset by natural field declines.
-
Primary heavy crude oil production averaged 65,992 bbl/d in Q2/21, increases of 6% and 5% from Q2/20 and Q1/21 levels respectively, primarily due to strong drilling results and development activities, partially offset by natural field declines.
Operating costs in the Company's primary heavy crude oil operations averaged $19.32/bbl (US$15.73/bbl) in Q2/21, an increase of 8% from Q2/20 levels, primarily as a result of increased power costs.
At the Company's Clearwater play at Smith, 6 net horizontal multilateral wells are now all on-stream. Production from these 6 wells continues to be strong, currently totaling approximately 2,200 bbl/d, exceeding budgeted rates by 600 bbl/d from these wells.
The Company is currently drilling a second 6 net horizontal multilateral well pad at Smith, targeted to be on stream in Q4/21. This pad is targeting similarly strong productive rates of approximately 2,000 bbl/d.
-
Pelican Lake production was strong in Q2/21 averaging 55,212 bbl/d, comparable with prior periods, demonstrating the strength of this long life low decline asset and the continued success of the Company's world class polymer flood.
The Company continues to focus on safe, effective and efficient operations, realizing low operating costs in Q2/21 at Pelican Lake, averaging $6.90/bbl (US$5.62/bbl), an increase of 9% from Q2/20 primarily due to increased power costs. Operating costs decreased 7% from Q1/21 levels primarily due to the impact of seasonality.
The Company drilled and brought on stream 10 net wells throughout Q2/21 at Pelican Lake. Current production from these wells is strong totaling approximately 1,300 bbl/d, at an attractive capital efficiency of approximately $9,900 per flowing BOE for this long life low decline asset.
-
North America light crude oil and NGL production averaged 98,559 bbl/d in Q1/21, increases of 20% and 6% from Q2/20 and Q1/21 levels respectively. The increases are primarily due to strong drilling results and development activities.
Operating costs in the Company's North America light crude oil and NGL areas averaged $14.39/bbl (US$11.72/bbl) in Q2/21, comparable with Q2/20 levels, and a decrease of 10% from Q1/21 levels primarily as a result of higher production volumes and effective and efficient operations, offset by increased power costs.
-
The Company continues to advance its high value Montney light crude oil development plan at Wembley, where 13 net wells have been drilled to date, ahead of schedule and under cost, of the budgeted 18 net wells targeted to be on stream in 2021.
Cost efficiencies have been realized on the Wembley drilling program as targeted costs are 12% lower than budgeted levels, resulting in a strong capital efficiency of approximately $8,300 per flowing BOE once on stream.
Construction of the new crude oil battery and gathering system is approximately 45 days ahead of schedule, now targeted to be on stream in mid-August 2021, with costs targeted to be 11% under budget.
This project is targeting to exit 2021 at total production rates of approximately 8,500 bbl/d of liquids and 30 MMcf/d of natural gas.
| Thermal In Situ Oil Sands |
|
|
|
|
|
|
|
|
| Three Months Ended |
|
| Six Months Ended |
|
| | June 30
2021 | | | Mar 31
2021 |
|
| June 30
2020 | | | June 30
2021 | | | June 30
2020 | |
| Bitumen production (bbl/d) | | 258,551 | | | 267,530 | | | 212,807 | | | 263,016 | | | 220,555 | |
| Net wells targeting bitumen | | 4 | |
| 3 |
|
| - |
|
| 7 | |
| 6 |
|
| Net successful wells drilled | | 4 |
| | 3 | | | - | | | 7 |
| | 6 | |
| Success rate | | 100% | | | 100% | | | -% | | | 100% | | | 100% | |
-
Canadian Natural's thermal in situ production averaged 258,551 bbl/d in Q2/21, an increase of 21% over Q2/20 levels and a decrease of 3% from Q1/21 levels.
Strong operating costs from the Company's thermal in situ assets were achieved in Q2/21, averaging $11.78/bbl (US$9.59/bbl), increases of 16% and 3% from Q2/20 and Q1/21 levels respectively. The increase in operating costs from Q2/20 was primarily due to increased energy costs and the increase from Q1/21 was primarily as a result of lower volumes in Q2/21 from Q1/21 levels.
-
Solvent enhanced oil recovery technology is being piloted by the Company with an objective to increase bitumen production, reduce the Steam to Oil Ratio ("SOR"), reduce greenhouse gas ("GHG") intensity and have high solvent recovery. This technology has the potential for application throughout the Company's extensive thermal in situ asset base.
At Kirby South, results from our on-going two year pilot of this technology indicate a significant SOR and GHG intensity reduction of approximately 45%, within the targeted range, can be achieved with the process. Monitoring of solvent recovery will continue for the remainder of 2021 to conclude the pilot results.
At Primrose, in the steam flood area, a solvent injection pilot is targeted to commence in Q4/21. The Company's second pilot will consist of 9 net wells (5 producers and 4 injectors) and similar to the first pilot at Kirby South, is targeted to operate for a two year period.
| North America Natural Gas |
|
|
|
|
|
|
|
|
| Three Months Ended |
|
| Six Months Ended |
|
| | June 30
2021 | | | Mar 31
2021 | | | June 30
2020 | | | June 30
2021 | | | June 30
2020 | |
| Natural gas production (MMcf/d) | | 1,594 | |
| 1,585 |
|
| 1,431 |
|
| 1,589 |
|
| 1,419 | |
| Net wells targeting natural gas | | 9 | |
| 22 |
|
| 1 |
|
| 31 |
|
| 12 |
|
| Net successful wells drilled |
| 9 | | | 22 | | | 1 | | | 31 | | | 12 | |
| Success rate |
| 100% |
| | 100% | | | 100% | | | 100% | | | 100% | |
-
North America natural gas production was strong in Q2/21 averaging 1,594 MMcf/d, an increase of 11% from Q2/20 levels and comparable with Q1/21 levels. The increase from Q2/20 was primarily as a result of acquired production in Q4/20 and strong drilling results, partially offset by natural field declines and the temporary full quarter shutdown of the Pine River Gas Plant, which resumed operations on July 24, 2021, restoring production of approximately 100 MMcf/d.
-
As part of the 2021 budget, in the liquids rich Montney, the Company targets to utilize facility capacity through its drill to fill strategy adding low cost, high value liquids rich natural gas volumes.
-
At Septimus, a 5 net well pad came on stream in June 2021 as budgeted, with total rates currently limited to approximately 30 MMcf/d of natural gas and 230 bbl/d of liquids, resulting in a strong capital efficiency of approximately $5,000 per flowing BOE.
As a result, production at Septimus reached full facility capacity of 150 MMcf/d of natural gas and 9,000 bbl/d of liquids in June 2021 and targets to remain at full capacity for the remainder of 2021.
Operating costs at Septimus remained strong in Q2/21, averaging $0.32/Mcfe, comparable with Q2/20 levels of $0.31/Mcfe.
-
At Townsend, a 6 net well pad came on stream in June 2021, with total rates of approximately 55 MMcf/d of natural gas, exceeding targeted rates by approximately 11 MMcf/d, resulting in a strong capital efficiency of approximately $4,000 per flowing BOE.
International Exploration and Production
|
| Three Months Ended |
|
| Six Months Ended |
|
| | June 30
2021 | | | Mar 31
2021 | | | June 30
2020 | | | June 30
2021 | | | June 30
2020 | |
| Crude oil production (bbl/d) | |
| |
|
|
|
|
|
| |
| |
|
|
|
| North Sea | | 16,458 | | | 19,959 | | | 26,627 | | | 18,199 | | | 27,191 | |
| Offshore Africa | | 16,239 | |
| 11,854 |
|
| 17,444 |
| | 14,059 | |
| 16,694 | |
| Natural gas production (MMcf/d) | | | |
| |
|
| |
| | | |
| |
|
| North Sea | | 4 | |
| 4 |
|
| 15 |
| | 4 | |
| 19 |
|
| Offshore Africa | | 16 | | | 9 | | | 16 | |
| 13 | | | 13 | |
| Net wells targeting crude oil | | 1.0 | |
| 2.0 |
|
| - |
| | 3.0 | |
| 1.0 |
|
| Net successful wells drilled | | 1.0 | | | 2.0 | | | - | |
| 3.0 |
| | 1.0 | |
| Success rate | | 100% | | | 100% | | | -% | | | 100% | | | 100% | |
-
International E&P crude oil production volumes averaged 32,697 bbl/d in Q2/21, a decrease of 26% from Q2/20 levels and a 3% increase from Q1/21 levels. The fluctuations in production from prior periods was primarily as a result of planned maintenance activities, natural field declines and the permanent cessation of production from the Banff and Kyle fields in 2020.
Crude oil operating costs increased from prior periods primarily due to lower volumes due to planned maintenance activities in the North Sea and Offshore Africa on a relatively fixed cost base and increased energy and GHG costs in the North Sea.
In Q3/21 the Company is planning turnarounds at the Ninian Central platform in the North Sea and at Espoir in Offshore Africa. Targeted production impacts were included in the Company's annual 2021 budgeted production volume range.
North America Oil Sands Mining and Upgrading
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| Three Months Ended |
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| Six Months Ended |
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| | June 30
2021 | | | Mar 31
2021 | | | June 30
2020 | | | June 30
2021 | | | June 30
2020 | |
| Synthetic crude oil production (bbl/d) (1) (2) | | 361,707 | | | 468,803 | | | 464,318 | | | 414,959 | | | 451,210 | |
(1) SCO production before royalties and excludes volumes consumed internally as diesel.
(2) Consists of heavy and light synthetic crude oil products.
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The Company's world class Oil Sands Mining and Upgrading assets averaged quarterly production of 361,707 bbl/d of SCO in Q2/21, decreases of 22% and 23% from Q2/20 and Q1/21 levels respectively, due to the timing of the planned turnaround at Horizon and de-coking at Scotford, which were both completed in the second quarter of 2021.
Operating costs from the Company's Oil Sands Mining and Upgrading assets remain top tier averaging $25.46/bbl (US$20.73/bbl) of SCO in Q2/21, strong results given significantly less quarterly sales volumes of approximately 100,000 bbl/d compared to Q1/21 levels as a result of the planned turnaround at Horizon, de-coking at Scotford and maintenance activities at the Albian mines.
The Company's focus on continuous improvement initiatives delivered high utilization and reliability at the Company's Oil Sands Mining and Upgrading assets. As a result, record monthly SCO production of approximately 495,100 bbl/d was achieved in June 2021, an increase from the previous record of approximately 490,800 bbl/d of SCO achieved in December 2020.
MARKETING
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| Three Months Ended |
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| Six Months Ended |
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| | Jun 30
2021 | | | Mar 31
2021 | | | June 30
2020 | | | June 30
2021 | | | June 30
2020 | |
| Crude oil and NGLs pricing | |
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| |
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| WTI benchmark price (US$/bbl) (1) | $ | 66.06 | | $ | 57.80 |
| $ | 27.85 |
| $ | 61.95 | | $ | 36.97 |
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| WCS heavy differential as a percentage of WTI (%) (2) | | 17% | |
| 21% |
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| 41% |
| | 19% | |
| 43% |
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| SCO price (US$/bbl) | $ | 66.49 | | $ | 54.30 |
| $ | 23.28 |
| $ | 60.43 | | $ | 33.33 |
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| Condensate benchmark pricing (US$/bbl) | $ | 66.39 | | $ | 57.99 |
| $ | 22.19 |
| $ | 62.22 | | $ | 33.86 |
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| Average realized pricing before risk management (C$/bbl) (3) | $ | 61.20 | | $ | 52.68 |
| $ | 18.97 |
| $ | 56.87 | | $ | 22.70 |
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| Natural gas pricing |
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| |
|
| |
| | | |
| |
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| AECO benchmark price (C$/GJ) | $ | 2.70 | | $ | 2.77 |
| $ | 1.81 |
| $ | 2.74 | | $ | 1.92 |
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| Average realized pricing before risk management (C$/Mcf) | $ | 3.17 | | $ | 3.42 | | $ | 2.03 | | $ | 3.29 | | $ | 2.13 | |
(1) West Texas Intermediate ("WTI").
(2) Western Canadian Select ("WCS").
(3) Average crude oil and NGL pricing excludes SCO. Pricing is net of blending costs and excluding risk management activities.
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Crude oil prices continue to improve with WTI averaging US$66.06/bbl in Q2/21, an increase of 137% from Q2/20 levels. The increase in WTI from comparable periods primarily reflected increased demand as a result of the positive impact of the global roll out of COVID-19 vaccinations on economic activity, the continuation of agreements by OPEC+ to maintain the majority of production cuts implemented in 2020 and the strengthening of the global economy.
As at July 26, 2021 for crude oil, annual WTI pricing of US$66.31/bbl is currently 68% higher than 2020 levels and the annual WCS heavy oil differential has improved significantly from 2020, currently at approximately 20% discount to WTI, in line with average historical levels.
Natural gas prices continue to improve with AECO averaging $2.70/GJ in Q2/21, an increase of 49% from Q2/20 levels. The increase in natural gas prices from the comparable period primarily reflected lower storage levels and increased NYMEX benchmark pricing.
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Market egress is targeted to improve in the short- and mid-term as construction is progressing on the Trans Mountain Expansion ("TMX") and the Enbridge Line 3 replacement.
Enbridge Line 3 is targeted to be on stream in Q4/21.
Canadian Natural is committed to approximately 10,000 bbl/d of the targeted 50,000 bbl/d base Keystone export pipeline optimization expansion, which is targeted to be on-stream in the latter half of 2021.
TMX construction is on track for a targeted on stream date in early 2023, on which Canadian Natural has 94,000 bbl/d committed capacity.
The North West Redwater ("NWR") Refinery has targeted processing capacity of approximately 80,000 bbl/d of diluted bitumen, which improves heavy oil demand in western Canada, effectively increasing egress out of the WCSB. For more details, please contact the North West Redwater Partnership.
FINANCIAL REVIEW
The Company continues to implement proven strategies including its disciplined approach to capital allocation. As a result, the financial position of Canadian Natural remains strong. Canadian Natural's adjusted funds flow generation, credit facilities, US commercial paper program, access to capital markets, diverse asset base and related flexible capital expenditure program, all support a flexible financial position and provide the appropriate financial resources for the near-, mid- and long-term.
The Company's strategy to maintain a diverse portfolio, balanced across various commodity types, averaged quarterly production of 1,141,739 BOE/d in Q2/21, with approximately 98% of total production located in G7 countries.
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In Q2/21, reflecting the strength of our effective and efficient operations and our high quality, long life low decline asset base, Canadian Natural generated robust quarterly free cash flow of $1,535 million, after dividend payments of $557 million and net capital expenditures of $957 million, excluding acquisitions.
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Returns to shareholders year to date in 2021 have been significant, as Canadian Natural has returned approximately $1.5 billion by way of dividends and share repurchases up to and including August 4, 2021.
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In March 2021, the Company declared a quarterly dividend of $0.47 per share, an increase of 11% from the previous level of $0.425 per share, marking 2021 as the Company's 21st consecutive year of dividend increases, reflecting the Board of Directors' confidence in Canadian Natural's strength and the robustness of the Company's assets and its ability to generate significant and sustainable free cash flow.
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In March 2021, the Board of Directors authorized management to repurchase shares under a NCIB to approximately offset options exercised throughout the coming year, in order to minimize or eliminate dilution to shareholders.
Share repurchases for cancellation in 2021 up to and including August 4, 2021 total 11,044,400 common shares at a weighted average price of $42.00.
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Annual 2021 free cash flow is targeted to be robust at a range of $7.2 billion to $7.7 billion using an annual average WTI of US$66/bbl, after dividends and budgeted capital expenditures, excluding net acquisitions.
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Free cash flow generation has been significant in 2021 and the Company's balance sheet continues to strengthen, providing the Board of Directors the confidence to approve a more defined free cash flow allocation policy in accordance with the Company's four pillars of capital allocation. Effective July 1, 2021 under the new policy, the Company targets to allocate free cash flow as follows:
Increased returns to shareholders through incremental share repurchases of approximately 1% of common shares outstanding or approximately 11 million shares per quarter.
Once the Company reaches $15.0 billion in absolute debt, currently targeted to occur in Q4/21, 50% of free cash flow is targeted to be allocated to share repurchases under the Company's NCIB, with the remaining 50% allocated to further strengthening of the Company's balance sheet.
Subsequent to quarter end, in July 2021, the Company filed base shelf prospectuses that allow for the offer for sale from time to time of up to $3,000 million of medium-term notes in Canada and US$3,000 million of debt securities in the United States, which expire August 2023, replacing the Company's previous base shelf prospectuses which would have expired in August 2021. If issued, these securities may be offered in amounts and at prices, including interest rates, to be determined based on market conditions at the time of issuance.
ENVIRONMENTAL, SOCIAL AND GOVERNANCE ("ESG") HIGHLIGHTS
Canada and Canadian Natural are well positioned to deliver responsibly produced energy that the world needs through leading ESG performance. Canadian Natural's culture of continuous improvement provides a significant advantage and results in continued improvement in the Company's environmental performance.
On June 9, 2021 Canadian Natural together with oil sands industry participants formally announced the Oil Sands Pathways to Net Zero initiative. Canadian Natural and these companies operate approximately 90% of Canada's oil sands production. The goal of this unique alliance, working collectively with the federal and Alberta governments, is to achieve net zero GHG emissions from oil sands operations by 2050 to help Canada meet its climate goals, including its Paris Agreement commitments and 2050 net zero aspirations.
This collaborative effort follows welcome announcements from the Government of Canada and the Government of Alberta of important support programs for emissions-reduction projects and infrastructure. Collaboration between industry and government will be critical to progressing the Oil Sands Pathways to Net Zero vision and achieving Canada's climate goals.
The Pathways vision is anchored by a major Carbon Capture, Utilization and Storage ("CCUS") trunkline connected to a carbon sequestration hub to enable multi-sector 'tie-in' projects for expanded emissions reductions. The proposed CCUS system is similar to the multi-billion dollar Longship/Northern Lights project in Norway as well as other CCUS projects in the Netherlands, UK and USA, all of which involve significant collaboration between industry and government.
The Pathways initiative is ambitious and will require significant investment on the part of both industry and government to advance the research and development of new and emerging technologies.
The companies involved look forward to continuing to work with governments and to engage with Indigenous and local communities in northern Alberta, to make this ambitious, major emissions-reduction vision a reality so those communities can continue to benefit from Canadian resource development.
Canadian Natural plans to publish its 2020 Stewardship Report to Stakeholders in August, which will be available on the Company's website at https://www.cnrl.com/report-to-stakeholders. The report displays how Canadian Natural continues to focus on safe, reliable, effective and efficient operations while minimizing its environmental footprint. Canadian Natural outlined its pathway to lower carbon emissions and its journey to achieve its goal of net zero GHG emissions in the oil sands. Highlights from the Company's 2020 report are as follows:
Canadian Natural's corporate GHG emissions intensity continues to improve, decreasing by 18% from 2016 to 2020, a material reduction in emissions intensity.
The Company reduced methane emissions in its North American E&P segment by 28% from 2016 to 2020.
The Company continues to improve corporate total recordable injury frequency ("TRIF") in 2020, with a TRIF of 0.21 in 2020 compared to 0.50 in 2016. The Company's TRIF is down 58% since 2016, while man-hours have increased over this time period.
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Canadian Natural is one of the largest owners of Carbon Capture and Storage ("CCS") and sequestration capacity in the oil and natural gas sector globally through projects at Horizon, the Company's 70% owned Quest CCS facility located at Scotford, and its 50% working interest in the NWR Refinery. As part of our comprehensive GHG emissions reduction strategy, our CCS projects include carbon dioxide ("CO2") storage in geological formations, the use of CO2 in enhanced oil recovery techniques and injection of CO2 into tailings. Gross carbon capture capacity through these projects combined is approximately 2.7 million tonnes of CO2 annually, equivalent to taking approximately 576,000 cars off the road per year.
The Quest CCS (70% Company ownership) facility captures and stores approximately 1.1 million tonnes of CO2 per year, the equivalent of removing approximately 235,000 cars off the road annually. In May 2020 Quest reached the milestone of 5 million tonnes of stored carbon dioxide, equal to the emissions from approximately 1.25 million cars.
At Horizon, annual capture capacity is approximately 0.4 million tonnes of CO2 from the hydrogen plant, the equivalent of removing approximately 85,000 cars off the road annually.
At the NWR Refinery, captured CO2 from the refinery began delivery in March 2020 to the Alberta Carbon Truck Line for enhanced oil recovery and permanent storage in central Alberta. At full capacity, approximately 1.2 million tonnes of CO2 per year will be captured, the equivalent of removing approximately 256,000 cars off the road annually.
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The Company continues to increase the level of third party verified direct GHG emissions and indirect energy use.
In 2020 the Company planted its one millionth tree at AOSP and its one and a half millionth tree at Horizon, reclaiming land and contributing to increased carbon capture.
The Government of Canada's announcement on April 19, 2021 of its 2021 budget recognized the important role of carbon capture, utilization and storage projects for the oil sands sector to continue contributing to Canada's economic growth while working towards climate objectives. As a leader in Carbon, CCUS, Canadian Natural sees many opportunities for industry to advance investments in CCUS projects. Details of the proposed government program are important and the Company looks forward to working together with government through the consultation period.
ENVIRONMENTAL TARGETS
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The Company has successfully achieved our four previously issued environmental targets relating to GHG emissions intensity reductions, methane emissions reductions and reduced fresh water usage as follows:
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25% reduction in oil sands GHG emissions intensity by 2025, from a 2016 baseline.
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20% reduction in North America E&P, including thermal in situ, methane emissions by 2025, from a 2016 baseline.
As of 2020, Canadian Natural reduced North America E&P, including thermal in situ, methane emissions by 28%.
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50% reduction of in situ fresh water usage intensity by 2022, from a 2012 baseline.
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30% reduction in mining fresh river water usage intensity by 2022, from a 2012 baseline.
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Based on achieving the Company's interim environmental targets referred to above, Canadian Natural has committed to new environmental targets as follows:
50% reduction in North America E&P, including thermal in situ, methane emissions by 2030, from a 2016 baseline.
40% reduction in thermal in situ fresh water usage intensity by 2026, from a 2017 baseline.
40% reduction in mining fresh river water usage intensity by 2026, from a 2017 baseline.
In 2018, Canadian Natural was one of the first oil companies to announce an aspirational goal of achieving net zero emissions in its oil sands operations.
Through the Company's participation in the Oil Sands Pathways to Net Zero Initiative with our industry partners and collaboration with the federal and Alberta governments, the Company is further refining its goal by targeting to achieve net zero emissions in its oil sands operations by 2050.
The Company is currently working through the details with members of the net zero initiative alliance to advance key milestones to be achieved over the next decade as we accelerate related projects through the Pathways initiative.
CORPORATE UPDATE
Canadian Natural is pleased to announce the appointment of Ms. Dawn L. Farrell to the Board of Directors of the Company, effective August 4, 2021. Ms. Farrell was most recently the President and Chief Executive Officer of TransAlta Corporation since 2012, before retiring in March of this year, having previously held roles as Chief Operating Officer from 2009 to 2011 and Executive Vice-President, Commercial Operations and Development from 2008 to 2009. Ms. Farrell has over 30 years of experience in the electric energy industry, holding executive leadership positions at both TransAlta and at BC Hydro and currently sits on the Board of Directors of The Chemours Company, a NYSE listed chemicals company, and is Chancellor of Mount Royal University. Ms. Farrell holds a Bachelor of Commerce and a Master of Arts in Economics, both from the University of Calgary, and has attended the Advanced Management Program at Harvard University.
ADVISORY
Special Note Regarding Forward-Looking Statements
Certain statements relating to Canadian Natural Resources Limited (the "Company") in this document or documents incorporated herein by reference constitute forward-looking statements or information (collectively referred to herein as "forward-looking statements") within the meaning of applicable securities legislation. Forward-looking statements can be identified by the words "believe", "anticipate", "expect", "plan", "estimate", "target", "continue", "could", "intend", "may", "potential", "predict", "should", "will", "objective", "project", "forecast", "goal", "guidance", "outlook", "effort", "seeks", "schedule", "proposed", "aspiration" or expressions of a similar nature suggesting future outcome or statements regarding an outlook. Disclosure related to expected future commodity pricing, the disposition of shares of Inter Pipeline Ltd. ("IPL") to a third-party provided that all conditions to the third-party offer are satisfied, forecast or anticipated production volumes, royalties, production expenses, capital expenditures, income tax expenses and other targets provided throughout this press release and the Company's Management's Discussion and Analysis ("MD&A") of the financial condition and results of operations of the Company, constitute forward-looking statements. Disclosure of plans relating to and expected results of existing and future developments, including, without limitation, those in relation to the Company's assets at Horizon Oil Sands ("Horizon"), the Athabasca Oil Sands Project ("AOSP"), Primrose thermal oil projects, the Pelican Lake water and polymer flood projects, the Kirby Thermal Oil Sands Project, the Jackfish Thermal Oil Sands Project, the North West Redwater bitumen upgrader and refinery, construction by third parties of new, or expansion of existing, pipeline capacity or other means of transportation of bitumen, crude oil, natural gas, natural gas liquids ("NGLs") or synthetic crude oil ("SCO") that the Company may be reliant upon to transport its products to market, the development and deployment of technology and technological innovations, and the financial capacity of the Company to complete its growth projects and responsibly and sustainably grow in the long term also constitute forward-looking statements. These forward-looking statements are based on annual budgets and multi-year forecasts, and are reviewed and revised throughout the year as necessary in the context of targeted financial ratios, project returns, product pricing expectations and balance in project risk and time horizons. These statements are not guarantees of future performance and are subject to certain risks. The reader should not place undue reliance on these forward-looking statements as there can be no assurances that the plans, initiatives or expectations upon which they are based will occur.
In addition, statements relating to "reserves" are deemed to be forward-looking statements as they involve the implied assessment based on certain estimates and assumptions that the reserves described can be profitably produced in the future. There are numerous uncertainties inherent in estimating quantities of proved and proved plus probable crude oil, natural gas and NGLs reserves and in projecting future rates of production and the timing of development expenditures. The total amount or timing of actual future production may vary significantly from reserves and production estimates.
The forward-looking statements are based on current expectations, estimates and projections about the Company and the industry in which the Company operates, which speak only as of the earlier of the date such statements were made or as of the date of the report or document in which they are contained, and are subject to known and unknown risks and uncertainties that could cause the actual results, performance or achievements of the Company to be materially different from any future results, performance or achievements expressed or implied by such forward-looking statements. Such risks and uncertainties include, among others: general economic and business conditions (including as a result of effects of the novel coronavirus ("COVID-19") pandemic and the actions of the Organization of the Petroleum Exporting Countries Plus ("OPEC+") which may impact, among other things, demand and supply for and market prices of the Company's products, and the availability and cost of resources required by the Company's operations; volatility of and assumptions regarding crude oil and natural gas and NGLs prices including due to actions of OPEC+ taken in response to COVID-19 or otherwise; fluctuations in currency and interest rates; assumptions on which the Company's current targets are based; economic conditions in the countries and regions in which the Company conducts business; political uncertainty, including actions of or against terrorists, insurgent groups or other conflict including conflict between states; industry capacity; ability of the Company to implement its business strategy, including exploration and development activities; impact of competition; the Company's defense of lawsuits; availability and cost of seismic, drilling and other equipment; ability of the Company and its subsidiaries to complete capital programs; the Company's and its subsidiaries' ability to secure adequate transportation for its products; unexpected disruptions or delays in the mining, extracting or upgrading of the Company's bitumen products; potential delays or changes in plans with respect to exploration or development projects or capital expenditures; ability of the Company to attract the necessary labour required to build, maintain, and operate its thermal and oil sands mining projects; operating hazards and other difficulties inherent in the exploration for and production and sale of crude oil and natural gas and in mining, extracting or upgrading the Company's bitumen products; availability and cost of financing; the Company's and its subsidiaries' success of exploration and development activities and its ability to replace and expand crude oil and natural gas reserves; the Company's ability to meet its targeted production levels; timing and success of integrating the business and operations of acquired companies and assets; production levels; imprecision of reserves estimates and estimates of recoverable quantities of crude oil, natural gas and NGLs not currently classified as proved; actions by governmental authorities (including production curtailments mandated by the Government of Alberta); government regulations and the expenditures required to comply with them (especially safety and environmental laws and regulations and the impact of climate change initiatives on capital expenditures and production expenses); asset retirement obligations; the sufficiency of the Company's liquidity to support its growth strategy and to sustain its operations in the short, medium, and long term; the strength of the Company's balance sheet; the flexibility of the Company's capital structure; the adequacy of the Company's provision for taxes; the continued availability of the Canada Emergency Wage Subsidy ("CEWS") or other subsidies; and other circumstances affecting revenues and expenses.
The Company's operations have been, and in the future may be, affected by political developments and by national, federal, provincial, state and local laws and regulations such as restrictions on production, changes in taxes, royalties and other amounts payable to governments or governmental agencies, price or gathering rate controls and environmental protection regulations. Should one or more of these risks or uncertainties materialize, or should any of the Company's assumptions prove incorrect, actual results may vary in material respects from those projected in the forward-looking statements. The impact of any one factor on a particular forward-looking statement is not determinable with certainty as such factors are dependent upon other factors, and the Company's course of action would depend upon its assessment of the future considering all information then available.
Readers are cautioned that the foregoing list of factors is not exhaustive. Unpredictable or unknown factors not discussed in this press release or the Company's MD&A could also have adverse effects on forward-looking statements. Although the Company believes that the expectations conveyed by the forward-looking statements are reasonable based on information available to it on the date such forward-looking statements are made, no assurances can be given as to future results, levels of activity and achievements. All subsequent forward-looking statements, whether written or oral, attributable to the Company or persons acting on its behalf are expressly qualified in their entirety by these cautionary statements. Except as required by applicable law, the Company assumes no obligation to update forward-looking statements in this press release or the Company's MD&A, whether as a result of new information, future events or other factors, or the foregoing factors affecting this information, should circumstances or the Company's estimates or opinions change.
Special Note Regarding non-GAAP Financial Measures
This press release includes references to financial measures commonly used in the crude oil and natural gas industry, such as: adjusted net earnings (loss) from operations, adjusted funds flow and net capital expenditures. These financial measures are not defined by International Financial Reporting Standards ("IFRS") and therefore are referred to as non-GAAP financial measures. The non-GAAP financial measures used by the Company may not be comparable to similar measures presented by other companies. The Company uses these non-GAAP financial measures to evaluate its performance. The non-GAAP financial measures should not be considered an alternative to or more meaningful than net earnings (loss), cash flows from (used in) operating activities, and cash flows used in investing activities as determined in accordance with IFRS, as an indication of the Company's performance.
Adjusted net earnings (loss) from operations is a non-GAAP financial measure that represents net earnings (loss), as determined in accordance with IFRS, as presented in the Company's consolidated Statements of Earnings (Loss), adjusted for the after-tax effects of certain items of a non-operational nature. The Company considers adjusted net earnings (loss) from operations a key measure in evaluating its performance, as it demonstrates the Company's ability to generate after-tax operating earnings from its core business areas. Adjusted net earnings (loss) from operations may not be comparable to similar measures presented by other companies.
Adjusted funds flow is a non-GAAP financial measure that represents cash flows from (used in) operating activities, as determined in accordance with IFRS, as presented in the Company's consolidated Statements of Cash Flows, adjusted for the net change in non-cash working capital, abandonment expenditures excluding the impact of government grant income under the provincial well-site rehabilitation programs, and movements in other long-term assets, including the unamortized cost of the share bonus program, accrued interest on subordinated debt advances to North West Redwater Partnership ("NWRP"), and prepaid cost of service tolls. The Company considers adjusted funds flow a key measure in evaluating its performance, as it demonstrates the Company's ability to generate the cash flow necessary to fund future growth through capital investment and to repay debt. Adjusted funds flow may not be comparable to similar measures presented by other companies.
Net capital expenditures is a non-GAAP financial measure, as determined in accordance with IFRS, that represents cash flows used in investing activities as presented in the Company's consolidated Statements of Cash Flows, adjusted for the net change in non-cash working capital, the repayment of NWRP subordinated debt advances, abandonment expenditures including the impact of government grant income under the provincial well-site rehabilitation programs, and the settlement of long-term debt assumed in acquisitions. The Company considers net capital expenditures a key measure in evaluating its performance, as it provides an understanding of the Company's capital spending activities in comparison to the Company's annual capital budget. Net capital expenditures may not be comparable to similar measures presented by other companies.
Free cash flow is a non-GAAP measure that represents cash flows from operating activities as presented in the Company's consolidated Statements of Cash Flows, adjusted for the net change in non-cash working capital from operating activities, abandonment, certain movements in other long-term assets, less net capital expenditures and dividends on common shares. The Company considers free cash flow a key measure in demonstrating the Company's ability to generate cash flow to fund future growth through capital investment, pay returns to shareholders, and to repay debt.
Adjusted EBITDA is a non-GAAP measure that represents net earnings (loss) as presented in the Company's consolidated Statements of Earnings (Loss), adjusted for interest, taxes, depletion, depreciation and amortization, stock based compensation expense (recovery), unrealized risk management gains (losses), unrealized foreign exchange gains (losses), and accretion of the Company's asset retirement obligation. The Company considers adjusted EBITDA a key measure in evaluating its operating profitability by excluding non-cash items.
Long-term debt, net and net debt are other financial measures that are calculated as net current and long-term debt less cash and cash equivalents.
Debt to adjusted EBITDA is a non-GAAP measure that is derived as the current and long-term portions of long-term debt, divided by the 12 month trailing Adjusted EBITDA, as defined above. The Company considers this ratio to be a key measure in evaluating the Company's ability to pay off its debt.
Debt to book capitalization is a non-GAAP measure that is derived as net current and long-term debt, divided by the book value of common shareholders' equity plus net current and long-term debt. The Company considers this ratio to be a key measure in evaluating the Company's ability to pay off its debt.
Available liquidity is a non-GAAP measure that is derived as cash and cash equivalents, total bank and term credit facilities and short term investments, less amounts drawn on the bank and credit facilities including under the commercial paper program. The Company considers available liquidity a key measure in evaluating the sustainability of the Company's operations and ability to fund future growth. See note 8 - Long-term Debt in the Company's consolidated financial statements.
Special Note Regarding Currency, Financial Information and Production
This press release should be read in conjunction with the unaudited interim consolidated financial statements for the three and six months ended June 30, 2021 and the Company's MD&A and audited consolidated financial statements for the year ended December 31, 2020. All dollar amounts are referenced in millions of Canadian dollars, except where noted otherwise. The Company's unaudited interim consolidated financial statements for the three and six months ended June 30, 2021 and the Company's MD&A have been prepared in accordance with IFRS as issued by the International Accounting Standards Board ("IASB").
Production volumes and per unit statistics are presented throughout the Company's MD&A on a "before royalties" or "company gross" basis, and realized prices are net of blending and feedstock costs and exclude the effect of risk management activities. In addition, reference is made to crude oil and natural gas in common units called barrel of oil equivalent ("BOE"). A BOE is derived by converting six thousand cubic feet ("Mcf") of natural gas to one barrel ("bbl") of crude oil (6 Mcf:1 bbl). This conversion may be misleading, particularly if used in isolation, since the 6 Mcf:1 bbl 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. In comparing the value ratio using current crude oil prices relative to natural gas prices, the 6 Mcf:1 bbl conversion ratio may be misleading as an indication of value. In addition, for the purposes of the Company's MD&A, crude oil is defined to include the following commodities: light and medium crude oil, primary heavy crude oil, Pelican Lake heavy crude oil, bitumen (thermal oil), and SCO. Production on an "after royalties" or "company net" basis is also presented for information purposes only.
The Company's 2021 targeted annual adjusted funds flow, free cash flow and net debt are based upon forecasted commodity prices of US$66.31 WTI/bbl, WCS discount of US$12.94/bbl, AECO price of C$3.29/GJ and FX of US$1.00 to C$1.25. Forecasted net debt reflects estimated timing of cash receipts and expenditures.
Additional information relating to the Company, including its Annual Information Form for the year ended December 31, 2020, is available on SEDAR at www.sedar.com, and on EDGAR at www.sec.gov. Information on the Company's website does not form part of and is not incorporated by reference in the Company's MD&A.
CONFERENCE CALL
Canadian Natural Resources Limited (TSX: CNQ) (NYSE: CNQ) will be issuing its 2021 Second Quarter Earnings Results, Thursday, August 5, 2021 before market open.
A conference call will be held at 9:00 a.m. Mountain Time, 11:00 a.m. Eastern Time on Thursday, August 5, 2021.
The conference call will also be webcast and can be accessed on the home page our website at www.cnrl.com.
The North American conference call number is 833-670-0711 and the international conference call number is 001-236-714-2926. You will also be required to enter the following Passcode 9841366 for the call. When prompted, please record your name and company name.
An archive of the broadcast will be available until 6:00 p.m. Mountain Time, Thursday, August 19, 2021. To access the rebroadcast in North America, dial 1-800-585-8367. Those outside of North America, dial 001-416-621-4642. The conference archive ID number is 9841366.
Canadian Natural is a senior oil and natural gas production company, with continuing operations in its core areas located in Western Canada, the U.K. portion of the North Sea and Offshore Africa.
CANADIAN NATURAL RESOURCES LIMITED
2100, 855 - 2nd Street S.W. Calgary, Alberta, T2P4J8
Phone: 403-514-7777 Email: ir@cnrl.com
www.cnrl.com
TIM S. MCKAY
President
MARK A. STAINTHORPE
Chief Financial Officer and Senior Vice-President, Finance
JASON M. POPKO
Manager, Investor Relations
Trading Symbol - CNQ
Toronto Stock Exchange
New York Stock Exchange
To view the source version of this press release, please visit https://www.newsfilecorp.com/release/92153
