CALGARY, AB – Crescent Point Energy Corp. (“Crescent Point” or the “Company”) (TSX: CPG) and (NYSE: CPG) is pleased to announce its operating and financial results for the year ended December 31, 2021 and increased share repurchases.
KEY HIGHLIGHTS
- Generated over $785 million of excess cash flow in 2021 with capital expenditures and production in-line with annual guidance.
- Increased PDP reserves by 17 percent with a strong FD&A recycle ratio of 2.7 times, including change in FDC.
- Replaced 197 percent of 2021 production on a 2P basis, resulting in a FD&A recycle ratio of 2.2 times, including change in FDC.
- Improved full-cycle returns in the Kaybob Duvernay through additional well cost reductions now totaling 20 percent.
- Achieved strong IP rate of over 825 boe/d per well, based on approximately 30 days, on first fully operated Kaybob Duvernay pad.
- Fully repaid $670 million of debt to acquire the Kaybob Duvernay assets, in addition to reducing net debt by $144 million in 2021.
- Disciplined 2022 budget, which is expected to generate approximately $1.1 billion of excess cash flow at US$80/bbl WTI.
- Increasing planned share repurchases to up to $150 million, to be executed by mid-2022, from $100 million announced previously.
- On track to meet or exceed targets to reduce emissions intensity and inactive wells, highlighting strong ESG practices.
“Our discipline and execution over the past few years positioned us to not only capitalize on strategic opportunities during 2021, but also to begin returning additional capital to shareholders,” said Craig Bryksa, President and CEO of Crescent Point. “We are very pleased with our initial success in the Kaybob Duvernay, including our strong operational execution that has resulted in increased rates of return. Due to our continued discipline and focus, we are on track to achieve our near-term leverage targets over the next six months at current commodity prices. As we continue to strengthen our balance sheet we will look to provide increased returns to shareholders in the context of a more defined return of capital framework.”
FINANCIAL HIGHLIGHTS
- For the year ended December 31, 2021, adjusted funds flow totaled $1.48 billion, or $2.57 per share diluted, driven by a strong operating netback of $42.43 per boe. In fourth quarter, adjusted funds flow totaled $432.5 million, or $0.74 per share diluted.
- For the year ended December 31, 2021, development capital expenditures, which included drilling and development, facilities and seismic costs, totaled $624.2 million, in-line with the Company’s annual guidance of $625 million.
- Crescent Point’s net debt as at December 31, 2021 was approximately $2.0 billion. The Company fully repaid approximately $670 million of debt incurred to acquire the Kaybob Duvernay assets, in addition to reducing its net debt by $144 million in 2021. In total, approximately $815 million of funds were directed to the balance sheet in 2021, including proceeds from dispositions.
- As previously announced, Crescent Point successfully renewed and extended its unsecured, covenant-based credit facilities of $2.3 billion with a maturity date of November 2025. The Company retains significant liquidity with an unutilized credit capacity of approximately $2.0 billion as at December 31, 2021.
- For the year ended December 31, 2021, Crescent Point reported net income of approximately $2.4 billion, primarily driven by a $2.5 billion ($1.9 billion after-tax) reversal of non-cash impairment in second quarter due to an increase in forward commodity prices and the independent engineers’ price forecast. In fourth quarter, net income totaled $121.6 million.
RETURN OF CAPITAL HIGHLIGHTS
- As previously announced, the Company’s Board of Directors (“Board”) approved and declared a first quarter 2022 dividend of $0.045 per share, payable on April 1, 2022 to shareholders of record on March 15, 2022. This equates to an annualized dividend of $0.18 per share, an increase of 50 percent from the prior level.
- The Board has approved the return of additional capital to shareholders given the continued strength in commodity prices and Crescent Point’s improving financial position. The Company is increasing its total planned share repurchases to up to $150 million, which it expects to execute by mid-2022, from $100 million announced previously. These planned repurchases were initiated in December 2021 with approximately 8.1 million shares repurchased and cancelled to-date for total consideration of approximately $60 million. Crescent Point has filed notice with the Toronto Stock Exchange (“TSX”) of the intention to renew its normal course issuer bid (“NCIB”), which is due to expire on March 8, 2022.
Adjusted funds flow, adjusted funds flow per share diluted, excess cash flow, recycle ratio, operating netback, net debt and net debt to adjusted funds flow are specified financial measures – refer to the Specified Financial Measures section in this press release for further information. All financial figures are approximate and in Canadian dollars unless otherwise noted. This press release contains forward-looking information and references to specified financial measures. Significant related assumptions and risk factors, and reconciliations are described under the Specified Financial Measures, Forward-Looking Statements and Reserves and Drilling Data sections of this press release, respectively. Further information breaking down the production information contained in this press release by product type can be found in the “Product Type Production Information” section of this press release. |
OPERATIONAL HIGHLIGHTS
- Achieved annual average production of 132,683 boe/d in 2021, comprised of over 80 percent oil and liquids, and in-line with the previously increased annual guidance.
- The Company continues to gain operational momentum in its Kaybob Duvernay play, realizing ongoing operational efficiencies and cost reductions. Recent well costs are trending at approximately $8.25 million, including drilling, completion, equip and tie-in, down from $8.75 million previously announced. Crescent Point has now removed approximately $2.0 million of per well costs, or approximately 20 percent, since entering the play in second quarter 2021. These savings have improved expected full-cycle rates of return and provide additional insulation to the Company’s capital budget in the current inflationary environment.
- Crescent Point’s Kaybob Duvernay wells are expected to generate full-cycle rates of return of over 120 percent and a payout of less than a year, at current commodity prices and budgeted cost inflation assumptions. These economics are based on an average of booked Proved plus Probable (“2P”) reserves per well within the Company’s current drilling program. These returns exclude any potential improvements to recoverable reserves resulting from Crescent Point utilizing a larger frac design than the prior operator. The Company will seek to further enhance returns in the play through ongoing drilling and completions optimization.
- Crescent Point recently brought onstream its first fully operated five-well pad in the Kaybob Duvernay, with approximately 30 days of production data now available. Initial production (“IP”) rates from these wells exceeded the 2P booked type well expectations, with an average IP rate of over 825 boe/d per well (74% condensate, 6% NGL and 20% shale gas). Crescent Point also completed and brought on production two multi-well pads, with a 50 percent working interest, as part of its previously announced farm-in agreement with a Kaybob Duvernay operator. The combined 30-day IP rate, net to the Company, for these three pads totaled over 11,000 boe/d (51% condensate, 9% NGL and 40% shale gas). This data includes a normal clean-up period for each well where pressure is maintained and production rates are moderated.
- Crescent Point continued to enhance returns by realizing efficiencies across its asset base in 2021, including reducing its drilling days within its Viewfield, Shaunavon and North Dakota resource plays by 10 to 15 percent. Such improvements provide the Company with sustainable cost efficiencies and further highlight its commitment to ongoing operational execution.
- The Company continued to advance its various decline mitigation initiatives in 2021, which included the successful conversion of approximately 135 producing wells to water injection wells. Crescent Point expects to execute a similar waterflood program in 2022. The Company also continues to progress its other decline mitigation programs, including the expansion of its polymer floods and pilot program to test carbon dioxide (CO2) sequestration and enhanced oil recovery in Saskatchewan.
- As part of its continued commitment to strong environmental, social and governance (“ESG”) practices, Crescent Point increased its target for emissions intensity reduction to 50 percent, up from 30 percent, by 2025, as previously announced. This target includes a 70 percent reduction in methane emissions. The Company is on track to meet or exceed its existing targets ahead of schedule and plans to revisit its current emissions reduction goals in second quarter 2022 in coordination with the release of its annual sustainability report. Crescent Point also made progress toward its target to reduce its inactive well count by approximately 30 percent by 2031 by safely retiring over 500 inactive wells during the year. The Company plans to retire approximately 350 additional wells in 2022.
RESERVES HIGHLIGHTS
“Our 2021 reserves and strong recycle ratios benefited from the addition of the Kaybob Duvernay asset, high-return development and improved recoveries from our decline mitigation programs,” said Bryksa. “As a result, our proved developed producing net asset value increased by approximately 15 percent on a per share basis, excluding year-over-year changes in pricing. We remain encouraged about the Kaybob Duvernay assets and the opportunity we have to further enhance shareholder value by achieving additional cost efficiencies, improving well productivity and adding reserves.”
- Crescent Point’s 2P reserves increased by seven percent at year-end 2021 to 712.4 million boe (“MMboe”), Proved (“1P”) reserves by 16 percent to 478.4 MMboe and Proved Developed Producing (“PDP”) reserves by 17 percent to 306.4 MMboe.
- On a 2P basis, the Company achieved reserve additions of 95.5 MMboe, replacing 197 percent of its 2021 production. Crescent Point benefited from the strategic Kaybob Duvernay acquisition, organic reserves additions, improved recovery factors associated with its decline mitigation programs and economic factors due to higher pricing. The Company’s 2P reserve life index (“RLI”) is approximately 15 years.
- Crescent Point generated 2P finding, development and acquisition (“FD&A”) costs, including change in future development capital (“FDC”), of $19.68 per boe, producing a recycle ratio of 2.2 times based on an operating netback of $42.43 per boe in 2021.
- On a PDP basis, the Company generated finding and development (“F&D”) costs, including change in FDC, of $12.22 per boe, producing a recycle ratio of 3.5 times. Crescent Point’s PDP FD&A costs, including change in FDC, totaled $15.93 per boe, resulting in a recycle ratio of 2.7 times.
- Crescent Point’s 2P and 1P net asset value (“NAV”) was $16.56 and $11.18 per share, respectively, at year-end 2021, based on independent engineering pricing. On a PDP basis, NAV was $7.62 per share and increased by approximately 15 percent compared to the prior year, adjusting for year-over-year changes in pricing and excluding land and seismic. This NAV forecast assumes an average WTI price of approximately US$69/bbl in the first five years.
- Crescent Point’s 2P FDC increased by approximately $400 million, or 10 percent, to $4.6 billion primarily driven by location additions from its Kaybob Duvernay play. This FDC equates to a conservative program that is also aligned with the Company’s current level of capital spending and five year plan.
In contrast to the prior year, Crescent Point elected to use a single independent evaluator to determine its 2021 corporate reserves, providing consistency across the evaluation process. Certain reserves metrics, including F&D costs, FD&A costs and recycle ratios, may not be meaningful or comparable year-over-year given significant portfolio changes executed over the last three years. Additional information on the Company’s 2021 reserves is provided in its Annual Information Form (“AIF”) for the year-ended December 31, 2021.
OUTLOOK
Crescent Point’s strong 2021 results highlight the continued success of its operational, financial and strategic execution.
The Company is on track to meet its 2022 average production guidance of 133,000 to 137,000 boe/d within its development capital expenditures budget of $825 to $900 million. This budget remains unchanged, despite a stronger commodity price environment, as management remains disciplined and focused on generating significant excess cash flow to create shareholder value. Crescent Point’s capital expenditures guidance also remains unchanged, despite continued cost inflation pressures, due to the Company’s ongoing efforts to realize internal efficiencies and its supply chain management. Assuming US$80/bbl WTI for the remainder of the year, Crescent Point’s budget is expected to generate approximately $1.1 billion of excess cash flow in 2022.
The Company continues to prioritize its balance sheet as it moves closer to achieving its near-term leverage target of approximately 1.0 times net debt to adjusted funds flow at US$55/bbl WTI, or approximately $1.3 to $1.4 billion of absolute net debt. At current commodity prices, Crescent Point expects to achieve this near-term debt target over the next six months.
The Company will look to provide increased returns to shareholders and a more defined return of capital framework as the balance sheet continues to strengthen. Based on Crescent Point’s continued successes and improving outlook, the Company is increasing its total planned share repurchases to up to $150 million, which it expects to execute by mid-2022, from $100 million announced previously.
Crescent Point is committed to a model that returns capital to shareholders while also generating additional returns through debt-adjusted per share growth.
Net debt to adjusted funds flow is a specified financial measure – refer to the Specified Financial Measures section in this press release for further information. |
Summary of Reserves
The Company’s reserves were independently evaluated by McDaniel & Associates Consultants Ltd. (“McDaniel”) as at December 31, 2021. The reserves evaluation and reporting was conducted in accordance with the definitions, standards and procedures contained in the COGEH and National Instrument 51-101 Standards for Disclosure of Oil and Gas Activities (“NI 51-101”).
As at December 31, 2021 (1) (2) (3) (4)
Tight Oil (Mbbls) |
Light and Medium Oil (Mbbls) |
Heavy Oil (Mbbls) |
Natural Gas Liquids (Mbbls) |
|||||
Reserves Category | Gross | Net | Gross | Net | Gross | Net | Gross | Net |
Proved Developed Producing |
118,028 | 109,274 | 46,241 | 41,857 | 20,230 | 16,839 | 71,949 | 63,859 |
Proved Developed Non-Producing |
1,761 | 1,462 | 528 | 505 | 2,352 | 2,136 | 504 | 418 |
Proved Undeveloped | 61,755 | 55,934 | 14,353 | 13,561 | 1,677 | 1,460 | 57,577 | 51,195 |
Total Proved | 181,545 | 166,669 | 61,122 | 55,922 | 24,259 | 20,434 | 130,029 | 115,471 |
Total Probable | 107,868 | 98,235 | 40,574 | 36,729 | 7,255 | 6,091 | 47,742 | 40,108 |
Total Proved plus Probable | 289,413 | 264,905 | 101,696 | 92,651 | 31,514 | 26,525 | 177,772 | 155,579 |
Shale Gas
(MMcf) |
Natural Gas
(MMcf) |
Total
(Mboe) |
||||
Reserves Category | Gross | Net | Gross | Net | Gross | Net |
Proved Developed Producing |
259,805 | 241,945 | 39,979 | 36,719 | 306,412 | 278,273 |
Proved Developed Non-Producing |
1,504 | 1,239 | 165 | 148 | 5,423 | 4,751 |
Proved Undeveloped | 183,576 | 169,285 | 3,468 | 3,223 | 166,536 | 150,900 |
Total Proved | 444,884 | 412,469 | 43,612 | 40,090 | 478,371 | 433,924 |
Total Probable | 158,493 | 144,084 | 25,077 | 23,108 | 234,035 | 209,029 |
Total Proved plus Probable | 603,377 | 556,553 | 68,690 | 63,198 | 712,406 | 642,952 |
(1) | Based on three evaluator’s average (McDaniel, GLJ Ltd. and Sproule Associates Ltd.) December 31, 2021, escalated price forecast. |
(2) | “Gross Reserves” are the total Company’s working-interest share before the deduction of any royalties and without including any royalty interest of the Company. |
(3) | “Net Reserves” are the total Company’s interest share after deducting royalties and including any royalty interest. |
(4) | Numbers may not add due to rounding. |
Summary of Before Tax Net Present Values
As at December 31, 2021 (1) (2)
Before Tax Net Present Value ($ millions) | ||||||
Discount Rate | ||||||
Price Deck | Reserves Category | Gross Reserves (Mboe) |
0% | 5% | 10% | 15% |
Three Evaluator Average |
Proved Developed Producing | 306,412 | 8,628 | 7,119 | 5,995 | 5,207 |
Total Proved | 478,371 | 12,600 | 9,948 | 8,078 | 6,781 | |
Total Proved plus Probable | 712,406 | 20,714 | 14,723 | 11,230 | 9,037 |
(1) | Price deck based on three evaluator’s average (McDaniel, GLJ Ltd. and Sproule Associates Ltd.) December 31, 2021, escalated price forecast. |
(2) | Numbers may not add due to rounding. |
RESERVES RECONCILIATION
Gross Reserves (1) (2) (3) (4)
Tight Oil
(Mbbls) |
Light and Medium Oil
(Mbbls) |
Heavy Oil
(Mbbls) |
|||||||
Factors | Proved | Probable | Proved plus Probable |
Proved | Probable | Proved plus P robable |
Proved | Probable | Proved plus Probable |
December 31, 2020 | 206,262 | 136,923 | 343,185 | 83,454 | 53,678 | 137,131 | 24,935 | 6,665 | 31,600 |
Extensions and Improved Recovery | 12,139 | 216 | 12,355 | 6,786 | 1,753 | 8,539 | 1,810 | 1,362 | 3,173 |
Technical Revisions | (17,677) | (27,407) | (45,085) | (3,267) | (2,184) | (5,451) | (1,863) | (939) | (2,802) |
Acquisitions | – | – | – | 24 | 6 | 30 | – | – | – |
Dispositions | (1,943) | (3,393) | (5,336) | (23,463) | (14,422) | (37,885) | – | – | – |
Economic Factors | 5,575 | 1,530 | 7,104 | 4,107 | 1,744 | 5,851 | 911 | 167 | 1,078 |
Production | (22,810) | – | (22,810) | (6,519) | – | (6,519) | (1,534) | – | (1,534) |
December 31, 2021 | 181,545 | 107,868 | 289,413 | 61,122 | 40,574 | 101,696 | 24,259 | 7,255 | 31,514 |
Natural Gas Liquids
(Mbbls) |
Shale Gas
(MMcf) |
Natural Gas
(MMcf) |
|||||||
Factors | Proved | Probable | Proved plus Probable |
Proved | Probable | Proved plus Probable |
Proved | Probable | Proved plus Probable |
December 31, 2020 | 58,082 | 33,832 | 91,914 | 176,738 | 110,880 | 287,618 | 52,042 | 29,381 | 81,423 |
Extensions and Improved Recovery | 31,404 | 6,241 | 37,645 | 113,922 | 20,659 | 134,581 | 1,581 | 820 | 2,402 |
Technical Revisions | (4,385) | (4,344) | (8,729) | (14,641) | (17,625) | (32,266) | (1,970) | (1,940) | (3,910) |
Acquisitions | 54,314 | 12,327 | 66,641 | 203,901 | 48,064 | 251,966 | – | – | – |
Dispositions | (1,396) | (1,159) | (2,554) | (3,188) | (5,272) | (8,460) | (7,728) | (4,712) | (12,440) |
Economic Factors | 2,615 | 845 | 3,460 | 5,793 | 1,786 | 7,579 | 3,822 | 1,527 | 5,350 |
Production | (10,605) | – | (10,605) | (37,640) | – | (37,640) | (4,135) | – | (4,135) |
December 31, 2021 | 130,029 | 47,742 | 177,772 | 444,884 | 158,493 | 603,377 | 43,612 | 25,077 | 68,690 |
Total Oil Equivalent
(Mboe) |
|||
Factors | Proved | Probable | Proved
plus Probable |
December 31, 2020 | 410,862 | 254,476 | 665,338 |
Extensions and Improved Recovery | 71,389 | 13,151 | 84,541 |
Technical Revisions | (29,961) | (38,135) | (68,096) |
Acquisitions | 88,322 | 20,343 | 108,665 |
Dispositions | (28,621) | (20,638) | (49,259) |
Economic Factors | 14,810 | 4,838 | 19,648 |
Production | (48,429) | – | (48,429) |
December 31, 2021 | 478,371 | 234,035 | 712,406 |
(1) | Based on three evaluator’s average (McDaniel, GLJ Ltd. and Sproule Associates Ltd.) December 31, 2021, escalated price forecast. |
(2) | “Gross Reserves” are the total Company’s working-interest share before the deduction of any royalties and without including any royalty interest of the Company. |
(3) | Numbers may not add due to rounding |
Finding, Development and Acquisition Costs for 2021
The Company’s F&D costs, FD&A costs and recycle ratios may not be meaningful or comparable year-over-year given significant portfolio changes executed over the last three years.
F&D | Change in FDC on F&D |
F&D Total (incl. change in FDC) |
FD&A | Change in FDC |
FD&A Total (incl. change in FDC) |
|
Capital ($ millions) | ||||||
Total Proved plus Probable | 629 | 319 | 948 | 1,472 | 407 | 1,879 |
Total Proved | 629 | 190 | 819 | 1,472 | 458 | 1,931 |
Proved Developed Producing | 629 | (38) | 591 | 1,472 | (6) | 1,467 |
Reserves Additions (Mboe) | ||||||
Total Proved plus Probable | 36,092 | – | 36,092 | 95,498 | – | 95,498 |
Total Proved | 56,238 | – | 56,238 | 115,939 | – | 115,939 |
Proved Developed Producing | 48,338 | – | 48,338 | 92,066 | – | 92,066 |
Costs ($/boe) (1) | ||||||
Total Proved plus Probable | $17.43 | – | $26.27 | $15.42 | – | $19.68 |
Total Proved | $11.19 | – | $14.56 | $12.70 | – | $16.65 |
Proved Developed Producing | $13.01 | – | $12.22 | $15.99 | – | $15.93 |
Recycle Ratio (2) | ||||||
Total Proved plus Probable | 2.4 | – | 1.6 | 2.7 | – | 2.2 |
Total Proved | 3.8 | – | 2.9 | 3.3 | – | 2.5 |
Proved Developed Producing | 3.3 | – | 3.5 | 2.6 | – | 2.7 |
(1) | Numbers may not add due to rounding. |
(2) | F&D and FD&A are calculated by dividing the identified capital expenditures by the applicable reserves additions. These can include or exclude changes in future development capital costs. |
(3) | Recycle ratio is calculated as operating netback before hedging divided by F&D or FD&A costs. Based on a 2021 operating netback of $42.43 per boe. |
Future Development Capital
At year-end 2021, FDC for 2P reserves totaled $4.6 billion, compared to $4.2 billion at year-end 2020. The Company’s FDC increased by approximately $400 million, primarily driven by location additions from its Kaybob Duvernay play.
Company Annual Capital Expenditures ($ millions) | ||||||
Canada | U.S. | Total | ||||
Year | Total Proved |
Total Proved + Probable |
Total Proved |
Total Proved + Probable |
Total Proved |
Total Proved + Probable |
2022 | 608 | 612 | 130 | 130 | 738 | 742 |
2023 | 551 | 607 | 51 | 128 | 602 | 736 |
2024 | 606 | 742 | 121 | 141 | 727 | 883 |
2025 | 550 | 727 | 81 | 137 | 631 | 864 |
2026 | 284 | 505 | 6 | 138 | 290 | 643 |
2027 | 6 | 399 | – | 24 | 6 | 424 |
2028 | 4 | 265 | – | – | 4 | 265 |
2029 | 3 | 3 | – | – | 3 | 3 |
2030 | 3 | 3 | – | – | 3 | 3 |
2031 | 5 | 3 | – | – | 5 | 3 |
2032 | 3 | 2 | – | – | 3 | 2 |
2033 | 1 | 1 | – | – | 1 | 1 |
Subtotal (1) | 2,624 | 3,870 | 390 | 699 | 3,014 | 4,568 |
Remainder | 3 | 9 | – | – | 3 | 9 |
Total (1) | 2,627 | 3,878 | 390 | 699 | 3,017 | 4,577 |
10% Discounted | 2,134 | 2,941 | 331 | 558 | 2,465 | 3,499 |
(1) | Numbers may not add due to rounding. |
CONFERENCE CALL DETAILS
Crescent Point management will host a conference call on Thursday, March 3, 2022 at 10:00 a.m. MT (12:00 p.m. ET) to discuss the Company’s results and outlook. A slide deck will accompany the conference call and can be found on Crescent Point’s website.
Participants can listen to this event online via webcast. Alternatively, the conference call can be accessed by dialing 1–888–390–0605.
The webcast will be archived for replay and can be accessed on Crescent Point’s conference calls and webcasts webpage under the invest tab. The replay will be available approximately one hour following completion of the call.
Shareholders and investors can also find the Company’s most recent investor presentation on Crescent Point’s website.
2022 GUIDANCE
The Company’s guidance for 2022 is as follows:
Total Annual Average Production (boe/d) (1) | 133,000 – 137,000 |
Capital Expenditures | |
Development capital expenditures ($ millions) | $825 – $900 |
Capitalized G&A ($ millions) | $40 |
Total ($ million) (2) | $865 – $940 |
Other Information for 2022 Guidance | |
Reclamation activities ($ millions) (3) | $20 |
Capital lease payments ($ millions) | $20 |
Annual operating expenses ($/boe) | $13.25 – $13.75 |
Royalties | 12.5% – 13.5% |
1) | Total annual average production (boe/d) is comprised of approximately 80% Oil & NGLs and 20% Natural Gas |
2) | Land expenditures and net property acquisitions and dispositions are not included. Development capital expenditures spend is allocated on an approximate basis as follows: 85% drilling & development and 15% facilities & seismic |
3) | Reflects Crescent Point’s portion of its expected total budget |
The Company’s audited financial statements and management’s discussion and analysis for the year ended December 31, 2021, will be available on the System for Electronic Document Analysis and Retrieval (“SEDAR”) at www.sedar.com, on EDGAR at www.sec.gov/edgar.shtml and on Crescent Point’s website at www.crescentpointenergy.com.
FINANCIAL AND OPERATING HIGHLIGHTS
Three months ended December 31 | Year ended December 31 | |||
(Cdn$ millions except per share and per boe amounts) | 2021 | 2020 | 2021 | 2020 |
Financial | ||||
Cash flow from operating activities | 492.4 | 245.1 | 1,495.8 | 860.5 |
Adjusted funds flow from operations | 432.5 | 220.2 | 1,476.9 | 874.4 |
Per share (2) | 0.74 | 0.41 | 2.57 | 1.64 |
Net income (loss) | 121.6 | (51.2) | 2,364.1 | (2,519.9) |
Per share (2) | 0.21 | (0.10) | 4.11 | (4.76) |
Adjusted net earnings from operations (1) | 160.0 | 85.6 | 515.3 | 177.4 |
Per share (1) (2) | 0.27 | 0.16 | 0.90 | 0.33 |
Dividends declared | 26.0 | 1.4 | 47.8 | 9.4 |
Per share (2) | 0.0450 | 0.0025 | 0.0825 | 0.0175 |
Net debt | 2,005.0 | 2,149.2 | 2,005.0 | 2,149.2 |
Net debt to adjusted funds flow from operations (3) | 1.4 | 2.5 | 1.4 | 2.5 |
Weighted average shares outstanding | ||||
Basic | 582.1 | 530.0 | 569.2 | 529.3 |
Diluted | 587.7 | 534.4 | 575.1 | 531.8 |
Operating | ||||
Average daily production | ||||
Crude oil and condensate (bbls/d) | 88,544 | 87,512 | 95,839 | 95,859 |
NGLs (bbls/d) | 20,884 | 13,033 | 17,769 | 14,542 |
Natural gas (mcf/d) | 125,871 | 64,033 | 114,452 | 67,447 |
Total (boe/d) | 130,407 | 111,217 | 132,683 | 121,642 |
Average selling prices (4) | ||||
Crude oil and condensate ($/bbl) | 91.27 | 49.40 | 78.43 | 43.50 |
NGLs ($/bbl) | 47.59 | 24.96 | 42.33 | 17.19 |
Natural gas ($/mcf) | 5.66 | 3.42 | 4.51 | 3.02 |
Total ($/boe) | 75.05 | 43.76 | 66.21 | 38.01 |
Netback ($/boe) | ||||
Oil and gas sales | 75.05 | 43.76 | 66.21 | 38.01 |
Royalties | (9.57) | (5.65) | (8.44) | (4.88) |
Operating expenses | (12.85) | (13.30) | (12.91) | (12.62) |
Transportation expenses | (2.48) | (2.29) | (2.43) | (2.27) |
Operating netback | 50.15 | 22.52 | 42.43 | 18.24 |
Realized gain (loss) on commodity derivatives | (9.60) | 4.03 | (7.45) | 5.52 |
Other (5) | (4.50) | (5.03) | (4.48) | (4.12) |
Adjusted funds flow from operations netback (1) | 36.05 | 21.52 | 30.50 | 19.64 |
Capital Expenditures | ||||
Capital acquisitions (6) | 5.2 | — | 942.4 | 1.4 |
Capital dispositions (6) | (0.1) | 1.1 | (99.0) | (508.2) |
Development capital expenditures | ||||
Drilling and development | 198.9 | 152.3 | 523.7 | 586.5 |
Facilities and seismic | 30.6 | 17.1 | 100.5 | 68.3 |
Total | 229.5 | 169.4 | 624.2 | 654.8 |
Land expenditures | 0.8 | 0.8 | 4.9 | 3.6 |
(1) | Specified financial measure that does not have any standardized meaning prescribed by IFRS and, therefore, may not be comparable with the calculation of similar measures presented by other entities. Refer to the Specified Financial Measures section for further information. |
(2) | The per share amounts (with the exception of dividends per share) are the per share – diluted amounts. |
(3) | Net debt to adjusted funds flow from operations is calculated as the period end net debt divided by the sum of adjusted funds flow from operations for the trailing four quarters. |
(4) | The average selling prices reported are before realized derivatives and transportation. |
(5) | Other includes net purchased products, general and administrative expenses, interest on long-term debt, foreign exchange, cash-settled share-based compensation and certain cash items and excludes transaction costs, foreign exchange on US dollar long-term debt and certain non-cash items. |
(6) | Capital dispositions, net represent total consideration for the transactions, including long-term debt and working capital assumed, and exclude transaction costs. |
Specified Financial Measures
Throughout this press release, the Company uses the terms “adjusted funds flow” (equivalent to “adjusted funds flow from operations”), “adjusted funds flow from operations per share – diluted”, “adjusted net earnings from operations”, “adjusted net earnings from operations per share – diluted”, “excess cash flow”, “net debt”, “net debt to adjusted funds flow” (equivalent to “net debt to adjusted funds flow from operations”), “recycle ratio”, “total operating netback”, “total netback”, “operating netback”, “netback”, “adjusted funds flow from operations netback” and “adjusted working capital deficiency”. These terms do not have any standardized meaning as prescribed by IFRS and, therefore, may not be comparable with the calculation of similar measures presented by other issuers. For information on the composition of these measures and how the Company uses these measures, refer to the Specified Financial Measures section of the Company’s MD&A for the year ended December 31, 2021, which section is incorporated herein by reference, and available on SEDAR at www.sedar.com and on EDGAR at www.sec.gov/edgar.
Adjusted funds flow from operations netback is a non-GAAP financial ratio and is calculated as adjusted funds flow from operations divided by total production. Adjusted funds flow from operations netback is a common metric used in the oil and gas industry and is used to measure operating results on a per boe basis.
The following table reconciles oil and gas sales to total operating netback, total netback and adjusted funds flow from operations netback:
Three months ended December 31 | Year ended December 31 | |||||||||||
($ millions) | 2021 | 2020 | % Change | 2021 | 2020 | % Change | ||||||
Oil and gas sales | 900.4 | 447.8 | 101 | 3,206.5 | 1,692.2 | 89 | ||||||
Royalties | (114.8) | (57.8) | 99 | (408.8) | (217.1) | 88 | ||||||
Operating expenses | (154.2) | (136.1) | 13 | (625.3) | (561.8) | 11 | ||||||
Transportation expenses | (29.8) | (23.4) | 27 | (117.7) | (101.1) | 16 | ||||||
Total operating netback | 601.6 | 230.5 | 161 | 2,054.7 | 812.2 | 153 | ||||||
Realized gain (loss) on commodity derivatives | (115.2) | 41.2 | (380) | (360.8) | 245.7 | (247) | ||||||
Total netback | 486.4 | 271.7 | 79 | 1,693.9 | 1,057.9 | 60 | ||||||
Other (1) | (53.9) | (51.5) | 5 | (217.0) | (183.5) | 18 | ||||||
Total adjusted funds flow from operations netback | 432.5 | 220.2 | 96 | 1,476.9 | 874.4 | 69 |
(1) | Other includes net purchased products, general and administrative expenses, interest on long-term debt, foreign exchange, cash-settled share-based compensation and certain cash items and excludes transaction costs, foreign exchange on US dollar long-term debt and certain non-cash items. |
The following table reconciles cash flow from operating activities to adjusted funds flow from operations and excess cash flow:
Three months ended December 31 | Year ended December 31 | |||||||||||
($ millions) | 2021 | 2020 (1) | % Change | 2021 | 2020 (1) | % Change | ||||||
Cash flow from operating activities | 492.4 | 245.1 | 101 | 1,495.8 | 860.5 | 74 | ||||||
Changes in non-cash working capital | (69.1) | (29.0) | 138 | (51.6) | (6.2) | 732 | ||||||
Transaction costs | 0.3 | — | 100 | 12.5 | 5.4 | 131 | ||||||
Decommissioning expenditures (2) | 8.9 | 4.1 | 117 | 20.2 | 14.7 | 37 | ||||||
Adjusted funds flow from operations | 432.5 | 220.2 | 96 | 1,476.9 | 874.4 | 69 | ||||||
Capital expenditures | (242.9) | (181.6) | 34 | (676.1) | (698.8) | (3) | ||||||
Payments on lease liability | (5.6) | (5.2) | 8 | (21.2) | (30.0) | (29) | ||||||
Decommissioning expenditures | (8.9) | (4.1) | 117 | (20.2) | (14.7) | 37 | ||||||
Other items (3) | 7.3 | 13.1 | (44) | 29.0 | 0.5 | 5,700 | ||||||
Excess cash flow | 182.4 | 42.4 | 330 | 788.4 | 131.4 | 500 |
(1) | Comparative period revised to reflect current year presentation. |
(2) | Excludes amounts received from government subsidy programs. |
(3) | Other items include, but are not limited to, unrealized gains on equity derivative contracts, sale of long-term investments and transaction costs. Other items exclude net acquisitions and dispositions. |
Adjusted funds flow from operations per share – diluted is a supplementary financial measure and is calculated as adjusted funds flow from operations divided by the number of weighted average diluted shares outstanding. It is used as a key measure to assess the ability of the Company to finance dividends, operating activities, capital expenditures and debt repayments.
The following table reconciles adjusted working capital deficiency:
($ millions) | 2021 | 2020 | % Change | |||
Accounts payable and accrued liabilities | 450.7 | 310.3 | 45 | |||
Dividends payable | 43.5 | 1.3 | 3,246 | |||
Long-term compensation liability (1) | 42.6 | 16.3 | 161 | |||
Cash | (13.5) | (8.8) | 53 | |||
Accounts receivable | (314.3) | (200.5) | 57 | |||
Prepaids and deposits | (7.4) | (22.7) | (67) | |||
Long-term investments | — | (2.5) | (100) | |||
Adjusted working capital deficiency | 201.6 | 93.4 | 116 |
(1) | Includes current portion of long-term compensation liability and is net of equity derivative contracts. |
The following table reconciles long-term debt to net debt:
($ millions) | 2021 | 2020 | % Change | |||
Long-term debt (1) | 1,970.2 | 2,259.6 | (13) | |||
Adjusted working capital deficiency | 201.6 | 93.4 | 116 | |||
Unrealized foreign exchange on translation of US dollar long-term debt | (166.8) | (203.8) | (18) | |||
Net debt | 2,005.0 | 2,149.2 | (7) |
(1) | Includes current portion of long-term debt. |
The following table reconciles net income (loss) to adjusted net earnings from operations:
Three months ended December 31 | Year ended December 31 | |||||||||||
($ millions) | 2021 | 2020 | % Change | 2021 | 2020 | % Change | ||||||
Net income (loss) | 121.6 | (51.2) | (338) | 2,364.1 | (2,519.9) | (194) | ||||||
Amortization of E&E undeveloped land | 9.6 | 13.9 | (31) | 51.0 | 71.9 | (29) | ||||||
Impairment (impairment reversal) | — | — | 100 | (2,514.4) | 3,557.8 | (171) | ||||||
Unrealized derivative (gains) losses | (87.1) | 185.5 | (147) | 141.4 | 112.5 | 26 | ||||||
Unrealized foreign exchange gain on translation of hedged US dollar long-term debt |
(13.1) | (86.2) | (85) | (37.0) | (62.1) | (40) | ||||||
Unrealized (gain) loss on long-term investments | — | (0.9) | (100) | (3.1) | 4.2 | (174) | ||||||
Gain on sale of long-term investments | — | — | (100) | (7.0) | — | (100) | ||||||
Net gain on capital dispositions | — | (8.5) | (100) | (58.4) | (316.4) | (82) | ||||||
Deferred tax adjustments | 129.0 | 33.0 | 291 | 578.7 | (670.6) | (186) | ||||||
Adjusted net earnings from operations | 160.0 | 85.6 | 87 | 515.3 | 177.4 | 190 |
Recycle ratio is a non-GAAP ratio and is calculated as operating netback before hedging divided by FD&A costs. Recycle ratios may not be comparable year-over-year given significant changes executed over the last three years. Recycle ratio is a common metric used in the oil and gas industry and is used to measure profitability on a per boe basis.
Excess cash flow forecasted for 2022 is a forward-looking non-GAAP measure and is calculated consistently with the measure disclosed in the Company’s MD&A. Refer to the Specified Financial Measures section of the Company’s MD&A for the year ended December 31, 2021.
Management believes the presentation of the specified financial measures above provide useful information to investors and shareholders as the measures provide increased transparency and the ability to better analyze performance against prior periods on a comparable basis.
Notice to US Readers
The oil and natural gas reserves contained in this press release have generally been prepared in accordance with Canadian disclosure standards, which are not comparable in all respects of United States or other foreign disclosure standards. For example, the United States Securities and Exchange Commission (the “SEC”) generally permits oil and gas issuers, in their filings with the SEC, to disclose only proved reserves (as defined in SEC rules), but permits the optional disclosure of “probable reserves” and “possible reserves” (each as defined in SEC rules). Canadian securities laws require oil and gas issuers, in their filings with Canadian securities regulators, to disclose not only proved reserves (which are defined differently from the SEC rules) but also probable reserves and permits optional disclosure of “possible reserves”, each as defined in NI 51-101. Accordingly, “proved reserves”, “probable reserves” and “possible reserves” disclosed in this news release may not be comparable to US standards, and in this news release, Crescent Point has disclosed reserves designated as “proved plus probable reserves”. Probable reserves are higher-risk and are generally believed to be less likely to be accurately estimated or recovered than proved reserves. “Possible reserves” are higher risk than “probable reserves” and are generally believed to be less likely to be accurately estimated or recovered than “probable reserves”. In addition, under Canadian disclosure requirements and industry practice, reserves and production are reported using gross volumes, which are volumes prior to deduction of royalties and similar payments. The SEC rules require reserves and production to be presented using net volumes, after deduction of applicable royalties and similar payments. Moreover, Crescent Point has determined and disclosed estimated future net revenue from its reserves using forecast prices and costs, whereas the SEC rules require that reserves be estimated using a 12-month average price, calculated as the arithmetic average of the first-day-of-the-month price for each month within the 12-month period prior to the end of the reporting period. Consequently, Crescent Point’s reserve estimates and production volumes in this news release may not be comparable to those made by companies using United States reporting and disclosure standards. Further, the SEC rules are based on unescalated costs and forecasts.
All amounts in the news release are stated in Canadian dollars unless otherwise specified.