Baytex Announces Fourth Quarter and Year-End 2021 Results, RCALGARY, Alberta, Feb. 24, 2022 (GLOBE NEWSWIRE) -- Baytex Energy Corp. ("Baytex")(TSX: BTE) reports its operating and financial results for the three months and year ended December 31, 2021 (all amounts are in Canadian dollars unless otherwise noted).
"In 2021, we made a commitment to maintain capital discipline, maximize free cash flow and reduce our net debt. I am very pleased to say we delivered on all fronts with strong operational execution, record free cash flow and a significantly improved balance sheet. With continued operating momentum and current commodity prices, we expect to generate over $550 million of free cash flow in 2022 and reach our initial $1.2 billion net debt target during the second quarter. As a result, we are announcing the next phase of our return of capital framework, which includes allocating approximately 25% of our free cash flow to share buybacks commencing in the second quarter. We are also following up our success in the Clearwater where we now have four of the top five initial rate wells drilled to date in the play," commented Ed LaFehr, President and Chief Executive Officer.
2021 Highlights - Production exceeded the high end of guidance at 80,789 boe/d (82% oil and NGL) in Q4/2021 and 80,156 boe/d (82% oil and NGL) for the full-year 2021.
- Exploration and development expenditures totaled $74 million in Q4/2021, bringing aggregate spending for 2021 to $313 million, in line with guidance.
- Delivered adjusted funds flow(1) of $215 million ($0.38 per basic share) in Q4/2021 and $746 million ($1.32 per basic share) for 2021.
- Generated a record level of free cash flow(2) of $137 million ($0.24 per basic share) in Q4/2021 and $421 million ($0.75 per basic share) for 2021.
- Cash flows from operating activities was $241 million ($0.43 per basic share) in Q4/2021 and $712 million ($1.26 per basic share) for 2021.
- Reduced net debt(1) by 24% to $1.4 billion at year-end 2021, from $1.8 billion at year-end 2020.
- Drilled four of the top five wells to-date in the Clearwater play, with our two most recent wells at Peavine generating 30-day initial production rates of 921 bbl/d and 815 bbl/d, respectively.
- Reduced our GHG emissions intensity (tonnes of CO2e per boe) in 2021 by 11% over 2020 levels and have now achieved a 52% reduction, relative to our 2018 baseline.
Reserves Highlights - Proved developed producing reserves increased by 7%, from 120 mmboe to 129 mmboe. Proved reserves total 278 mmboe (271 mmboe at year-end 2020) and proved plus probable reserves total 451 mmboe (462 mmboe at year-end 2020).
- Finding and development ("F&D") costs, including changes in future development costs ("FDC"), were $8.20/boe for PDP reserves, $17.67/boe for 1P reserves and $24.55/boe for 2P reserves.
- Generated a PDP recycle ratio of 4.5x and a 1P recycle ratio of 2.1x based on 2021 operating netback(1) of $36.52/boe.
- At year-end 2021, the present value of our reserves, discounted at 10% before tax, is estimated to be $5.1 billion ($3.3 billion at year-end 2020). The increase is largely attributable to a higher commodity price forecast being utilized by our reserves evaluator (consultant average of approximately US$70/bbl WTI).
- Our net asset value at year-end 2021, discounted at 10% before tax, is estimated to be $6.67 per share. This is based on the estimated reserves value plus a value for undeveloped acreage, net of long-term debt and working capital.
(1) Capital management measure. Refer to the Specified Financial Measures section in this press release for further information.
(2) Specified financial measure that does not have any standardized meaning prescribed by IFRS and may not be comparable with the calculation of similar measures presented by other entities. Refer to the Specified Financial Measures section in this press release for further information.
2022 Outlook In 2022, we expect to benefit from our diversified oil weighted portfolio and our commitment to allocate capital effectively. Our capital program is designed to generate stable production from our light and heavy oil assets in Canada and the Eagle Ford in the United States, while scaling up development in the Clearwater.
Our 2022 guidance remains unchanged as we target production of 80,000 to 83,000 boe/d with exploration and development expenditures of $400 to $450 million. Based on the forward strip
(1), we expect to generate over $550 million of free cash flow
(2) in 2022.
| | 2022 Guidance |
| Exploration and development expenditures | $400 - $450 million |
| Production (boe/d) | 80,000 - 83,000 |
| | |
| Expenses: | |
| Average royalty rate (2) | 18.5% - 19.0% |
| Operating (3) | $12.25 - $13.00/boe |
| Transportation (3) | $1.20 - $1.30/boe |
| General and administrative (3) | $43 million ($1.45/boe) |
| Interest (3) | $80 million ($2.70/boe) |
| | |
| Leasing expenditures | $3 million |
| Asset retirement obligations | $20 million |
Return of Capital Framework With continued operating momentum and strong commodity prices, we expect to reach our initial $1.2 billion net debt
(4) target during the second quarter of 2022. As we reach this debt level, we will have reduced our net debt by approximately $1.1 billion over the past three and a half years. As a result of our significantly improved financial position, we are introducing the next phase of our enhanced return to shareholders framework.
For 2022, we expect to allocate approximately 25% of our annual free cash flow to direct shareholder returns and intend to implement a share buyback program commencing in Q2/2022.
The remainder of our free cash flow will continue to be allocated to debt reduction until we achieve a net debt level of $800 million, which represents an expected net debt
(4) to EBITDA
(5) ratio of 1.0x at a US$55 WTI price. We feel this level of net debt will provide us with ultimate flexibility to run our business through the commodity price cycles and generate meaningful returns for all stakeholders. At current prices, we expect to achieve this net debt level by mid-2023, at which point we will consider steps to further enhance shareholder returns.
(1) 2022 pricing assumptions: WTI - US$82/bbl; WCS differential - US$13/bbl; MSW differential - US$3/bbl, NYMEX Gas - US$4.80/mcf; AECO Gas - $4.50/mcf and Exchange Rate (CAD/USD) - 1.27.
(2) Specified financial measure that does not have any standardized meaning prescribed by IFRS and may not be comparable with the calculation of similar measures presented by other entities. Refer to the Specified Financial Measures section in this press release for further information.
(3) Calculated as operating, transportation, general and administrative or interest expense divided by barrels of oil equivalent production volume for the applicable period.
(4) Capital management measure. Refer to the Specified Financial Measures section in this press release for further information.
(5) Calculated in accordance with the Credit Facilities Agreement.
| | Three Months Ended | Twelve Months Ended |
| | December 31, 2021 | September 30, 2021 | December 31, 2020 | December 31, 2021 | December 31, 2020 |
FINANCIAL
(thousands of Canadian dollars, except per common share amounts) | | | | | |
| Petroleum and natural gas sales | $ | 552,403 | | $ | 488,736 | | $ | 233,636 | | $ | 1,868,195 | | $ | 975,477 | |
| Adjusted funds flow (1) | | 214,766 | | | 198,397 | | | 82,176 | | | 745,628 | | | 311,506 | |
| Per share - basic | | 0.38 | | | 0.35 | | | 0.15 | | | 1.32 | | | 0.56 | |
| Per share - diluted | | 0.37 | | | 0.35 | | | 0.15 | | | 1.30 | | | 0.56 | |
| Free cash flow (2) | | 137,133 | | | 101,215 | | | 1,794 | | | 421,329 | | | 18,073 | |
| Per share - basic | | 0.24 | | | 0.18 | | | - | | | 0.75 | | | 0.03 | |
| Per share - diluted | | 0.24 | | | 0.18 | | | - | | | 0.74 | | | 0.03 | |
| Cash flows from operating activities | | 240,567 | | | 178,961 | | | 51,017 | | | 712,384 | | | 353,096 | |
| Per share - basic | | 0.43 | | | 0.32 | | | 0.09 | | | 1.26 | | | 0.63 | |
| Per share - diluted | | 0.42 | | | 0.31 | | | 0.09 | | | 1.25 | | | 0.63 | |
| Net income (loss) | | 563,239 | | | 32,714 | | | 221,160 | | | 1,613,600 | | | (2,438,964 | ) |
| Per share - basic | | 1.00 | | | 0.06 | | | 0.39 | | | 2.86 | | | (4.35 | ) |
| Per share - diluted | | 0.98 | | | 0.06 | | | 0.39 | | | 2.82 | | | (4.35 | ) |
| | | | | | |
| Capital Expenditures | | | | | |
| Exploration and development expenditures | $ | 73,995 | | $ | 94,235 | | $ | 77,809 | | $ | 313,303 | | $ | 280,340 | |
| Acquisitions and divestitures | | (5,414 | ) | | (612 | ) | | (33 | ) | | (6,247 | ) | | (182 | ) |
| Total oil and natural gas capital expenditures | $ | 68,581 | | $ | 93,623 | | $ | 77,776 | | $ | 307,056 | | $ | 280,158 | |
| | | | | | |
| Net Debt | | | | | |
| Credit facilities | $ | 506,514 | | $ | 546,803 | | $ | 651,173 | | $ | 506,514 | | $ | 651,173 | |
| Long-term notes | | 885,920 | | | 1,000,171 | | | 1,147,950 | | | 885,920 | | | 1,147,950 | |
| Long-term debt | | 1,392,434 | | | 1,546,974 | | | 1,799,123 | | | 1,392,434 | | | 1,799,123 | |
| Working capital deficiency | | 17,283 | | | 17,684 | | | 48,478 | | | 17,283 | | | 48,478 | |
| Net debt (1) | $ | 1,409,717 | | $ | 1,564,658 | | $ | 1,847,601 | | $ | 1,409,717 | | $ | 1,847,601 | |
| | | | | | |
| Shares Outstanding - basic (thousands) | | | | | |
| Weighted average | | 564,213 | | | 564,211 | | | 561,173 | | | 563,674 | | | 560,657 | |
| End of period | | 564,213 | | | 564,213 | | | 561,227 | | | 564,213 | | | 561,227 | |
| | | | | | |
| BENCHMARK PRICES | | | | | |
| Crude oil | | | | | |
| WTI (US$/bbl) | $ | 77.19 | | $ | 70.56 | | $ | 42.66 | | $ | 67.92 | | $ | 39.40 | |
| MEH oil (US$/bbl) | | 78.89 | | | 71.64 | | | 43.05 | | | 69.26 | | | 40.15 | |
| MEH oil differential to WTI (US$/bbl) | | 1.70 | | | 1.08 | | | 0.39 | | | 1.34 | | | 0.75 | |
| Edmonton par ($/bbl) | | 93.29 | | | 83.78 | | | 50.24 | | | 80.23 | | | 45.34 | |
| Edmonton par differential to WTI (US$/bbl) | | (3.15 | ) | | (4.07 | ) | | (4.11 | ) | | (3.92 | ) | | (5.60 | ) |
| WCS heavy oil ($/bbl) | | 78.82 | | | 71.81 | | | 43.46 | | | 68.79 | | | 35.95 | |
| WCS differential to WTI (US$/bbl) | | (14.63 | ) | | (13.57 | ) | | (9.31 | ) | | (13.05 | ) | | (12.60 | ) |
| Natural gas | | | | | |
| NYMEX (US$/mmbtu) | $ | 5.83 | | $ | 4.01 | | $ | 2.66 | | $ | 3.84 | | $ | 2.08 | |
| AECO ($/mcf) | | 4.94 | | | 3.54 | | | 2.77 | | | 3.56 | | | 2.24 | |
| | | | | | |
| CAD/USD average exchange rate | | 1.2600 | | | 1.2601 | | | 1.3031 | | | 1.2536 | | | 1.3413 | |
| | Three Months Ended | Twelve Months Ended |
| | December 31, 2021 | September 30, 2021 | December 31, 2020 | December 31, 2021 | December 31, 2020 |
| OPERATING | | | | | |
| Daily Production | | | | | |
| Light oil and condensate (bbl/d) | | 34,986 | | | 35,614 | | | 29,568 | | | 35,789 | | | 37,056 | |
| Heavy oil (bbl/d) | | 23,482 | | | 21,996 | | | 21,725 | | | 22,188 | | | 21,142 | |
| NGL (bbl/d) | | 7,984 | | | 7,174 | | | 6,495 | | | 7,244 | | | 7,340 | |
| Total liquids (bbl/d) | | 66,452 | | | 64,784 | | | 57,788 | | | 65,221 | | | 65,538 | |
| Natural gas (mcf/d) | | 86,029 | | | 90,528 | | | 76,116 | | | 89,606 | | | 85,464 | |
| Oil equivalent (boe/d @ 6:1) (3) | | 80,789 | | | 79,872 | | | 70,475 | | | 80,156 | | | 79,781 | |
| | | | | | |
| Netback (thousands of Canadian dollars) | | | | | |
| Total sales, net of blending and other expense (2) | $ | 523,382 | | $ | 469,155 | | $ | 222,745 | | $ | 1,782,506 | | $ | 927,096 | |
| Royalties | | (100,152 | ) | | (90,523 | ) | | (37,807 | ) | | (339,156 | ) | | (163,735 | ) |
| Operating expense | | (95,357 | ) | | (84,196 | ) | | (79,748 | ) | | (343,002 | ) | | (331,345 | ) |
| Transportation expense | | (8,169 | ) | | (7,818 | ) | | (6,692 | ) | | (32,261 | ) | | (28,437 | ) |
| Operating netback (2) | $ | 319,704 | | $ | 286,618 | | $ | 98,498 | | $ | 1,068,087 | | $ | 403,579 | |
| General and administrative | | (11,481 | ) | | (9,980 | ) | | (9,314 | ) | | (40,804 | ) | | (34,268 | ) |
| Cash financing and interest | | (21,319 | ) | | (22,793 | ) | | (25,194 | ) | | (92,069 | ) | | (106,534 | ) |
| Realized financial derivatives (loss) gain | | (70,544 | ) | | (53,905 | ) | | 17,105 | | | (184,241 | ) | | 47,836 | |
| Other (4) | | (1,594 | ) | | (1,543 | ) | | 1,081 | | | (5,345 | ) | | 893 | |
| Adjusted funds flow (1) | $ | 214,766 | | $ | 198,397 | | $ | 82,176 | | $ | 745,628 | | $ | 311,506 | |
| | | | | | |
| Netback per boe (5) | | | | | |
| Total sales, net of blending and other expense (2) | $ | 70.42 | | $ | 63.85 | | $ | 34.35 | | $ | 60.93 | | $ | 31.75 | |
| Royalties | | (13.47 | ) | | (12.32 | ) | | (5.83 | ) | | (11.59 | ) | | (5.61 | ) |
| Operating expense | | (12.83 | ) | | (11.46 | ) | | (12.30 | ) | | (11.72 | ) | | (11.35 | ) |
| Transportation expense | | (1.10 | ) | | (1.06 | ) | | (1.03 | ) | | (1.10 | ) | | (0.97 | ) |
| Operating netback (2) | $ | 43.02 | | $ | 39.01 | | $ | 15.19 | | $ | 36.52 | | $ | 13.82 | |
| General and administrative | | (1.54 | ) | | (1.36 | ) | | (1.44 | ) | | (1.39 | ) | | (1.17 | ) |
| Cash financing and interest | | (2.87 | ) | | (3.10 | ) | | (3.89 | ) | | (3.15 | ) | | (3.65 | ) |
| Realized financial derivatives (loss) gain | | (9.49 | ) | | (7.34 | ) | | 2.64 | | | (6.30 | ) | | 1.64 | |
| Other (4) | | (0.23 | ) | | (0.21 | ) | | 0.17 | | | (0.19 | ) | | 0.03 | |
| Adjusted funds flow (1) | $ | 28.89 | | $ | 27.00 | | $ | 12.67 | | $ | 25.49 | | $ | 10.67 | |
Notes:
(1) Capital management measure. Refer to the Specified Financial Measures section in this press release for further information.
(2) Specified financial measure that does not have any standardized meaning prescribed by IFRS and may not be comparable with the calculation of similar measures presented by other entities. Refer to the Specified Financial Measures section in this press release for further information.
(3) Barrel of oil equivalent ("boe") amounts have been calculated using a conversion rate of six thousand cubic feet of natural gas to one barrel of oil. The use of boe amounts may be misleading, particularly if used in isolation. A boe conversion ratio of six thousand cubic feet of natural gas to one barrel of oil is based on an energy equivalency conversion method primarily applicable at the burner tip and does not represent a value equivalency at the wellhead.
(4) Other is comprised of realized foreign exchange gain or loss, other income or expense, current income tax expense or recovery and share-based compensation. Refer to the 2021 MD&A for further information on these amounts.
(5) Calculated as royalties, operating or transportation expense divided by barrels of oil equivalent production volume for the applicable period.
2021 Results In 2021, we delivered strong operating and financial results and continued to advance our exciting new Clearwater play in northwest Alberta with four of the highest initial rate wells drilled to date in the play. We also delivered on our commitment to maintain capital discipline, maximize free cash flow and reduce our net debt. Production exceeded the high end of our annual guidance and we generated record free cash flow
(1) of $421 million, which meaningfully accelerated our debt reduction efforts.
Production during the fourth quarter averaged 80,789 boe/d (82% oil and NGL), as compared to 79,872 boe/d (82% oil and NGL) in Q3/2021. The higher volumes largely reflect a resumption of activity during the second half of the year. Production in 2021 averaged 80,156 boe/d as compared to 79,781 boe/d in 2020. Exploration and development expenditures totaled $74 million in Q4/2021 and $313 million for full-year 2021. We participated in the drilling of 231 (174.2 net) wells with a 100% success rate during the year.
We delivered adjusted funds flow
(2) of $215 million ($0.38 per basic share) in Q4/2021 and $746 million ($1.32 per basic share) in 2021. This resulted in a record level of free cash flow of $137 million ($0.24 per basic share) in Q4/2021 and $421 million ($0.75 per basic share) in 2021. We allocated 100% of our free cash flow to debt repayment, reducing net debt
(2) by 24% to $1.4 billion at year-end 2021, from $1.8 billion at year-end 2020.
We recorded net income of $563 million ($1.00 per basic share) in Q4/2021 and $1.6 billion ($2.86 per basic share) in 2021. During 2021, we identified indicators of impairment reversal for our oil and gas properties due to the increase in forecasted commodity prices. As a result, we recorded an impairment reversal of $0.4 billion in Q4/2021 and $1.5 billion for the full-year 2021 as the estimated recoverable amounts exceeded the carrying value of our oil and gas properties.
The following table compares our 2021 results to our 2021 guidance.
| | 2021 Guidance | |
| | Original (3) | Revised (4) | 2021 Results |
| Exploration and development expenditures | $225 - $275 million | $285 - $315 million | $313 million |
| Production (boe/d) | 73,000 - 77,000 | 77,000 - 79,000 | 80,156 |
| | | | |
| Expenses: | | | |
| Average royalty rate (1) | 18.0% - 18.5% | 18.0% - 18.5% | 19.0% |
| Operating (5) | $11.50 - $12.25/boe | $11.25 - $12.00/boe | $11.72/boe |
| Transportation (5) | $1.00 - $1.10/boe | $1.15 - $1.25/boe | $1.10/boe |
| General and administrative (5) | $42 million ($1.53/boe) | $42 million ($1.48/boe) | $41 million ($1.39/boe) |
| Interest (5) | $105 million ($3.84/boe) | $98 million ($3.46/boe) | $92 million ($3.15/boe) |
| | | | |
| Leasing expenditures | $4 million | $4 million | $4 million |
| Asset retirement obligations (6) | $6 million | $6 million | $7 million |
Operating Results Eagle Ford and Viking Light Oil Production in the Eagle Ford averaged 30,428 boe/d (82% oil and NGL) during Q4/2021 and 30,731 boe/d for the full-year 2021. In 2021, we invested $105 million on exploration and development in the Eagle Ford and generated an operating netback
(1) of $437 million. During 2021, we participated in the drilling of 67 (15.5 net) wells and brought 93 (23.1 net) wells onstream. We expect to bring approximately 14 net wells onstream in 2022.
(1) Specified financial measure that does not have any standardized meaning prescribed by IFRS and may not be comparable with the calculation of similar measures presented by other entities. Refer to the Specified Financial Measures section in this press release for further information.
(2) Capital management measure. Refer to the Specified Financial Measures section in this press release for further information.
(3) As announced on December 2, 2020.
(4) As announced on April 29, 2021. This guidance reference date included the introduction of a five-year outlook. 2021 guidance was subsequently tightened on November 4, 2021 reflecting year-to-date results to $300 to $315 million for exploration and development expenditures, 79,500 to 80,000 boe/d for production, 18.5% to 19.0% for average royalty rates, $11.25/boe to $11.75/boe for operating expenses, $1.10/boe to $1.15/boe for transportation expenses and $92 million ($3.16/boe) for interest expense.
(5) Calculated as operating, transportation, general and administrative or interest expense divided by barrels of oil equivalent production volume for the applicable period.
(6) Government grants reduced asset retirement obligations by $3 million in 2021.
Production in the Viking averaged 16,313 boe/d (88% oil and NGL) during Q4/2021 and 17,278 boe/d for the full-year 2021. In 2021, we invested $116 million on exploration and development in the Viking and generated an operating netback
(1) of $327 million. During 2021, we participated in the drilling of 123 (121.2 net) wells and brought 116 (114.2 net) wells onstream. We expect to bring approximately 145 net wells onstream in 2022.
Heavy Oil Our heavy oil assets at Peace River and Lloydminster (excluding our Clearwater development) produced a combined 24,217 boe/d (91% oil and NGL) during Q4/2021 and 23,579 boe/d for the full-year 2021. Our 2021 drilling program was heavily weighted to H2/2021 and included three net Bluesky wells at Peace River and 21.5 net wells at Lloydminster. In 2021, we invested $38 million on exploration and development in Peace River and Lloydminster and generated an operating netback
(1) of $231 million. In 2022, we will drill approximately nine net Bluesky wells at Peace River and 37 net wells at Lloydminster.
Peace River Clearwater We are committed to building and maintaining respectful relationships with Indigenous communities and creating opportunities for meaningful economic participation and inclusion. We have executed two strategic agreements with the Peavine Metis Settlement in the Peace River area that cover 80 sections of land directly to the south of our existing Seal operations. At the time, we identified potential for an early stage exploratory play targeting the Spirit River formation, a Clearwater formation equivalent. When combined with our legacy acreage position in northwest Alberta, we estimate that over 125 sections are highly prospective for Clearwater development.
Our 2021 appraisal program yielded exceptional results with production increasing from zero at the beginning of 2021 to over 3,000 bbl/d in January 2022. Our two eight-lateral wells (6-31 and 14-31) drilled during the fourth quarter and offsetting our highest initial rate well (11-31) generated 30-day initial production rates of 921 bbl/d and 815 bbl/d, respectively. With the performance of these two wells, our Peavine development has now yielded four of the top five initial rate Clearwater wells drilled-to date across the entire play. In addition, our eight lateral appraisal well (14-11) drilled on our northern acreage generated a very economic initial production rate (through its first twenty-five days of production) of approximately 120 bbl/d, consistent with our expectations. On our Seal legacy lands, we drilled a successful exploration well in late 2021 with a 30-day initial production rate of 147 bbl/d and we have a follow-up well scheduled for H2/2022.
The following table summarizes the results of our 2021 appraisal program.
| Area | Well | Spud | Rig Release | # of Laterals | 30-Day Initial Production Rate
(bbl/d) (2) |
| Peavine | 100/04-34 | January 7 | January 15 | 2 | 175 |
| Peavine | 102/04-34 | June 15 | June 21 | 2 | 175 |
| Peavine | 100/13-27 | June 22 | July 6 | 8 | 695 |
| Peavine | 100/05-34 | July 8 | July 18 | 8 | 412 |
| Peavine | 102/11-31 | July 20 | August 4 | 8 | 930 |
| Peavine | 100/06-31 | November 4 | November 15 | 8 | 921 |
| Peavine | 100/14-31 | November 17 | November 27 | 8 | 815 |
| Peavine | 100/14-11 | November 29 | December 11 | 8 | 120 |
| Seal | 100/12-34 | October 21 | November 2 | 6 | 147 |
Our first quarter 2022 drilling program is underway with two rigs that will see ten wells drilled on our Peavine lands. Importantly, we have successfully executed our first three extended reach horizontal multi-lateral wells at Peavine, which are utilized to provide appropriate set-backs to residents and environmentally sensitive areas. In aggregate, we expect to bring 18 wells onstream this year. To-date, we have de-risked 20 sections of land and pending further success, the play holds the potential for greater than 200 locations. The Clearwater generates strong economics with the ability to grow organically while enhancing our free cash flow profile.
Pembina Area Duvernay Light Oil Production in the Pembina Duvernay averaged 2,668 boe/d (83% oil and NGL) during Q4/2021 and 2,008 boe/d for the full-year 2021. The increased volumes during the fourth quarter reflect two wells brought onstream in October 2021. As a follow-up to our 2021 program, we are currently drilling a three-well pad which is expected to be onstream in Q3/2022.
(1) Specified financial measure that does not have any standardized meaning prescribed by IFRS and may not be comparable with the calculation of similar measures presented by other entities. Refer to the Specified Financial Measures section in this press release for further information.
(2) 30-Day Initial Production Rate (bbl/d) is defined as the average oil rate over the first 720 hours of production following drilling fluid recovery.
Financial Liquidity Our credit facilities total approximately $1.0 billion and have a maturity date of April 2, 2024. These are not borrowing base facilities and do not require annual or semi-annual reviews. As of December 31, 2021, we had $506 million of undrawn capacity on our credit facilities, resulting in liquidity, net of working capital, of $489 million.
Our net debt
(1), which includes our credit facilities, long-term notes and working capital, totaled $1.4 billion at December 31, 2021, down from $1.6 billion at September 30, 2021.
During 2021, we repurchased and cancelled US$200 million of the 5.625% long term notes due June 2024. This represents 50% of the original US$400 million outstanding.
Risk Management To manage commodity price movements, we utilize various financial derivative contracts and crude-by-rail to reduce the volatility of our adjusted funds flow.
For 2022, we have entered into hedges on approximately 41% of our net crude oil exposure utilizing a combination of a 3-way option structure that provides price protection at US$57.76/bbl with upside participation to US$67.51/bbl and swaptions at US$53.50/bbl. We also have WTI-MSW differential hedges on approximately 25% of our expected net Canadian light oil exposure at US$4.43/bbl and WCS differential hedges on approximately 70% of our expected net heavy oil exposure at a WTI-WCS differential of approximately US$12.28/bbl.
For 2023, we have entered into hedges on approximately 9% of our net crude oil exposure utilizing a 3-way option structure that provides price protection at US$71.00/bbl with upside participation to US$88.18/bbl
A complete listing of our financial derivative contracts can be found in Note 17 to our 2021 financial statements.
Environmental Stewardship The energy industry and society are undergoing a transition to a low-carbon economy. We believe oil and gas will be instrumental in this energy transition. As a responsible energy producer, we are committed to monitoring greenhouse gas (GHG) emissions from our operations, setting targets to reduce our GHG emissions intensity, and pursuing cost-effective decarbonization strategies.
In 2019, we established a GHG emissions reduction target. Our objective was to reduce our corporate GHG emission intensity (tonnes of CO2e per boe) by 30% by 2021, relative to our 2018 baseline. We exceeded this target in scope and timing, achieving a 46% reduction in our GHG emissions intensity through year-end 2020. This represented an annual reduction of 1.6 million tonnes of CO2e and was equivalent to taking 340,000 cars off the road annually.
Continual improvement is an important element of our corporate culture and we have set the bar higher. Our target is to now reduce our corporate GHG emission intensity by a further 33% from 2020 levels by 2025. This equates to an approximate 65% reduction by 2025, relative to our 2018 baseline. Our emissions reduction strategy includes increased gas conservation and combustion, reusing associated gas as fuel for field activities, reducing emissions from storage tanks, along with monitoring and preventing fugitive emissions.
In 2021, we reduced our GHG emissions intensity by 11% over 2020 levels. In 2022, we will invest approximately $10 million as part of our GHG mitigation program and expect to reduce our GHG emissions intensity by approximately 7.5% over 2021 levels.
GHG Emissions Intensity (Scope 1 and Scope 2) | | 2018 Baseline | 2019 | 2020 | 2021 | 2025 Target |
| Tonnes CO2e/boe | 0.112 | 0.095 | 0.061 | 0.054 | 0.041 |
(1) Capital management measure. Refer to the Specified Financial Measures section in this press release for further information.
Our commitment to responsible development also extends to the retirement of our assets. We plan for full lifecycle development of our properties which includes the restoration, abandonment and reclamation of assets that have reached the end of their productive life. At December 31, 2020, we had an end of life well inventory of approximately 4,500 wells. We have committed to reducing this well inventory to zero by 2040 which represents a proactive stance to managing future financial obligations and regulatory compliance. In 2022, we will embark on an active abandonment and reclamation program with approximately $35 million being directed to pipeline, wellbore and facility decommissioning along with well site reclamations.
Abandonment and Reclamation | | | 2018 | | 2019 | | 2020 | | 2021 | 2022 Plan |
| Number of wells abandoned (gross) | | 110 | | 113 | | 99 | | 237 | | 320 |
| Spending in abandonment/reclamation ($ million) (1) | $ | 14 | $ | 15 | $ | 9 | $ | 10 | $ | 35 |
Year-end 2021 Reserves Baytex's year-end 2021 proved and probable reserves were evaluated by McDaniel & Associates Consultants Ltd. ("McDaniel"), an independent qualified reserves evaluator. All of our oil and gas properties were evaluated in accordance with National Instrument 51-101 "Standards of Disclosure for Oil and Gas Activities" ("NI 51-101") and the Canadian Oil and Gas Evaluation Handbook (the "COGE Handbook") using the average commodity price forecasts and inflation rates of McDaniel, GLJ Petroleum Consultants ("GLJ") and Sproule Associates Limited ("Sproule") as of January 1, 2022. Complete reserves disclosure will be included in our Annual Information Form for the year ended December 31, 2021, which will be filed on or before March 31, 2022.
Reserves Highlights - Proved developed producing ("PDP") reserves increased by 7%, from 120 mmboe to 129 mmboe. Proved reserves ("1P") total 278 mmboe (271 mmboe at year-end 2020) and proved plus probable reserves ("2P") total 451 mmboe (462 mmboe at year-end 2020).
- Finding and development ("F&D") costs, including changes in future development costs ("FDC"), were $8.20/boe for PDP reserves, $17.67/boe for 1P reserves and $24.55/boe for 2P reserves.
- Generated a PDP recycle ratio of 4.5x and a 1P recycle ratio of 2.1x based on 2021 operating netback(2) of $36.52/boe.
- Reserves on a 1P basis are comprised of 80% oil and NGL (36% light oil, 26% NGL's, 17% heavy oil and 2% bitumen) and 20% natural gas. PDP reserves represent 46% of 1P reserves (44% at year-end 2020) and 1P reserves represent 62% of 2P reserves (59% at year-end 2020).
- Baytex maintains a strong reserves life index of 4.4 years based on PDP reserves, 9.4 years based on 1P reserves and 15.3 years based on 2P reserves.
- At year-end, 2021, the present value of our reserves, discounted at 10% before tax, is estimated to be $5.1 billion ($3.3 billion at year-end 2020). The increase is largely attributable to a higher commodity price forecast being utilized by our reserves evaluator (consultant average of approximately US$70/bbl WTI).
- Our net asset value at year-end 2021, discounted at 10% before tax, is $6.67 per share. This is based on the estimated reserves value plus a value for undeveloped acreage, net of long-term debt and working capital.
(1) Spending includes government grants received for abandonment and reclamations of $2 million in 2020, $3 million in 2021 and $15 million in 2022.
(2) Specified financial measure that does not have any standardized meaning prescribed by IFRS and may not be comparable with the calculation of similar measures presented by other entities. Refer to the Specified Financial Measures section in this press release for further information.
The following table sets forth our gross and net reserves volumes at December 31, 2021 by product type and reserves category. Please note that the data in the table may not add due to rounding.
Reserves Summary | | Light and Medium Oil | Tight Oil | Heavy Oil | Bitumen | Total Oil | Natural Gas Liquids (3) | Conventional Natural Gas (4) | Shale Gas | Total (5) |
| Reserves Summary | (mbbls) | (mbbls) | (mbbls) | (mbbls) | (mbbls) | (mbbls) | (mmcf) | (mmcf) | (mboe) |
| Gross (1) | | | | | | | | | |
| Proved producing | 18,564 | 26,623 | 23,735 | 641 | 69,564 | 31,853 | 65,234 | 99,778 | 128,919 |
| Proved developed non-producing | 664 | 314 | 765 | - | 1,743 | 852 | 1,973 | 2,448 | 3,333 |
| Proved undeveloped | 26,781 | 26,278 | 21,503 | 4,197 | 78,759 | 39,431 | 37,216 | 129,213 | 145,929 |
| Total proved | 46,009 | 53,216 | 46,003 | 4,838 | 150,067 | 72,137 | 104,423 | 231,439 | 278,181 |
| Total probable | 23,296 | 21,485 | 29,705 | 45,874 | 120,360 | 27,751 | 62,394 | 84,928 | 172,665 |
| Proved plus probable | 69,305 | 74,701 | 75,709 | 50,713 | 270,427 | 99,888 | 166,817 | 316,367 | 450,846 |
| Net (2) | | | | | | | | | |
| Proved producing | 17,436 | 19,797 | 20,775 | 575 | 58,583 | 23,735 | 58,749 | 74,461 | 104,519 |
| Proved developed non-producing | 617 | 232 | 689 | - | 1,538 | 630 | 1,687 | 1,812 | 2,751 |
| Proved undeveloped | 24,891 | 19,882 | 19,139 | 3,857 | 67,769 | 29,521 | 34,310 | 96,601 | 119,108 |
| Total proved | 42,944 | 39,911 | 40,602 | 4,432 | 127,890 | 53,885 | 94,745 | 172,874 | 226,378 |
| Total probable | 21,399 | 16,404 | 25,547 | 37,186 | 100,535 | 20,970 | 56,747 | 64,506 | 141,715 |
| Proved plus probable | 64,343 | 56,315 | 66,149 | 41,618 | 228,425 | 74,856 | 151,492 | 237,381 | 368,093 |
Notes:
(1) "Gross" reserves means the total working interest share of remaining recoverable reserves owned by Baytex before deductions of royalties payable to others.
(2) "Net" reserves means Baytex's gross reserves less all royalties payable to others plus royalty interest reserves.
(3) Natural Gas Liquids includes condensate.
(4) Conventional Natural Gas includes associated, non-associated and solution gas.
(5) Oil equivalent amounts have been calculated using a conversion rate of six thousand cubic feet of natural gas to one barrel of oil. BOEs may be misleading, particularly if used in isolation. A boe conversion ratio of six thousand cubic feet of natural gas to one barrel of oil is based on an energy equivalency conversion method primarily applicable at the burner tip and does not represent a value equivalency at the wellhead.
Reserves Reconciliation The following table reconciles the year-over-year changes in our gross reserves volumes by product type and reserves category. Please note that the data in the table may not add due to rounding.
Proved Reserves - Gross Volumes (1) (Forecast Prices) | | Light and Medium Oil | Tight Oil | Heavy Oil | Bitumen | Total Oil | Natural Gas Liquids (3) | Conventional Natural Gas (4) | Shale Gas | Total (5) |
| | (mbbls) | (mbbls) | (mbbls) | (mbbls) | (mbbls) | (mbbls) | (mmcf) | (mmcf) | (mboe) |
| December 31, 2020 | 52,067 | 53,316 | 35,412 | 5,737 | 146,532 | 72,475 | 87,894 | 226,334 | 271,378 |
| Extensions | 3,227 | 4,370 | 8,977 | - | 16,574 | 4,294 | 16,032 | 16,165 | 26,234 |
| Technical Revisions (2) | (6,059) | 520 | 2,949 | (394) | (2,984) | (1,379) | (1,649) | 1,599 | (4,372) |
| Acquisitions | 3 | - | 1,228 | - | 1,231 | - | - | - | 1,231 |
| Dispositions | (2) | (20) | (260) | - | (282) | (19) | (313) | (35) | (360) |
| Economic Factors | 2,509 | 612 | 5,160 | 130 | 8,411 | 1,159 | 20,547 | 1,995 | 13,326 |
| Production | (5,734) | (5,581) | (7,464) | (635) | (19,414) | (4,392) | (18,088) | (14,619) | (29,257) |
| December 31, 2021 | 46,009 | 53,216 | 46,003 | 4,838 | 150,067 | 72,137 | 104,423 | 231,439 | 278,181 |
Probable Reserves - Gross Volumes (1) (Forecast Prices) | | Light and Medium Oil | Tight Oil | Heavy Oil | Bitumen | Total Oil | Natural Gas Liquids (3) | Conventional Natural Gas (4) | Shale Gas | Total (5) |
| | (mbbls) | (mbbls) | (mbbls) | (mbbls) | (mbbls) | (mbbls) | (mmcf) | (mmcf) | (mboe) |
| December 31, 2020 | 25,688 | 24,642 | 30,544 | 46,093 | 126,967 | 32,760 | 86,778 | 96,852 | 190,332 |
| Extensions | 2,413 | (2,315) | (760) | - | (663) | (2,989) | (9,810) | (10,055) | (6,963) |
| Technical Revisions (2) | (5,357) | (1,018) | (1,721) | (216) | (8,312) | (1,634) | (70) | (2,403) | (10,359) |
| Acquisitions | - | - | 458 | - | 458 | - | - | - | 458 |
| Dispositions | (5) | (5) | (225) | - | (235) | (258) | (7,224) | (9) | (1,699) |
| Economic Factors | 556 | 182 | 1,409 | (2) | 2,145 | (127) | (7,280) | 543 | 895 |
| Production | - | - | - | - | - | - | - | - | - |
| December 31, 2021 | 23,296 | 21,485 | 29,705 | 45,874 | 120,360 | 27,751 | 62,394 | 84,928 | 172,665 |
Proved Plus Probable Reserves - Gross Volumes (1) (Forecast Prices) | | Light and Medium Oil | Tight Oil | Heavy Oil | Bitumen | Total Oil | Natural Gas Liquids (3) | Conventional Natural Gas (4) | Shale Gas | Total (5) |
| | (mbbls) | (mbbls) | (mbbls) | (mbbls) | (mbbls) | (mbbls) | (mmcf) | (mmcf) | (mboe) |
| December 31, 2020 | 77,755 | 77,958 | 65,956 | 51,830 | 273,499 | 105,235 | 174,671 | 323,186 | 461,710 |
| Extensions | 5,640 | 2,054 | 8,217 | - | 15,911 | 1,304 | 6,222 | 6,110 | 19,271 |
| Technical Revisions (2) | (11,416) | (498) | 1,228 | (610) | (11,296) | (3,013) | (1,719) | (804) | (14,730) |
| Acquisitions | 3 | - | 1,686 | - | 1,689 | - | - | - | 1,689 |
| Dispositions | (7) | (26) | (485) | - | (517) | (278) | (7,536) | (45) | (2,058) |
| Economic Factors | 3,065 | 794 | 6,570 | 127 | 10,556 | 1,031 | 13,267 | 2,538 | 14,221 |
| Production | (5,734) | (5,581) | (7,464) | (635) | (19,414) | (4,392) | (18,088) | (14,619) | (29,257) |
| December 31, 2021 | 69,305 | 74,701 | 75,709 | 50,713 | 270,427 | 99,888 | 166,817 | 316,367 | 450,846 |
Notes:
(1) "Gross" reserves means the total working interest share of remaining recoverable reserves owned by Baytex before deductions of royalties payable to others.
(2) Negative revisions in light and medium oil are predominantly associated with our Viking asset and due to variations in performance versus previous forecasts and the removal of inventory locations with higher finding and development costs.
(3) Natural gas liquids include condensate.
(4) Conventional natural gas includes associated, non-associated and solution gas.
(5) Oil equivalent amounts have been calculated using a conversion rate of six thousand cubic feet of natural gas to one barrel of oil. BOEs may be misleading, particularly if used in isolation. A boe conversion ratio of six thousand cubic feet of natural gas to one barrel of oil is based on an energy equivalency conversion method primarily applicable at the burner tip and does not represent a value equivalency at the wellhead.
Future Development Costs The following table sets forth future development costs deducted in the estimation of the future net revenue attributable to the reserves categories noted below.
| Future Development Costs ($ millions) | Proved
Reserves | Proved Plus
Probable Reserves |
| 2022 | 416 | 423 |
| 2023 | 506 | 540 |
| 2024 | 517 | 562 |
| 2025 | 489 | 581 |
| 2026 | 398 | 657 |
| Remainder | 84 | 987 |
| Total FDC undiscounted | 2,410 | 3,750 |
F&D and FD&A Costs - including future development costs Based on the evaluation of our petroleum and natural gas reserves prepared by McDaniel, the efficiency of our capital program is summarized in the following table.
| $ millions except for per boe amounts | | 2021 | | 2020 | | | 2019 | | 3 Year | |
| Proved plus Probable Reserves | | | | |
| Finding & Development Costs | | | | |
| Exploration and development expenditures | $ | 313.3 | $ | 280.3 | | $ | 552.3 | | $ | 1,145.9 | |
| Net change in Future Development Costs | $ | 147.4 | $ | (705.9 | ) | $ | 96.7 | | $ | (461.8 | ) |
| Gross Reserves additions (mmboe) | | 18.8 | | (38.4 | ) | | 39.8 | | | 20.2 | |
| F&D Costs ($/boe) | $ | 24.55 | $ | 11.08 | | $ | 16.30 | | $ | 33.92 | |
| | | | | |
| Finding, Development & Acquisition ("FD&A") Costs | | | | |
| Exploration and development expenditures and net acquisitions | $ | 307.1 | $ | 280.2 | | $ | 554.5 | | $ | 1,141.7 | |
| Net change in Future Development Costs | $ | 144.4 | $ | (709.3 | ) | $ | 79.9 | | $ | (485.0 | ) |
| Gross Reserves additions (mmboe) | | 18.4 | | (38.6 | ) | | 38.6 | | | 18.5 | |
| FD&A Costs ($/boe) | $ | 24.55 | $ | 11.12 | | $ | 16.42 | | $ | 35.59 | |
| | | | | |
| Proved Reserves | | | | |
| Finding & Development Costs | | | | |
| Exploration and development expenditures | $ | 313.3 | $ | 280.3 | | $ | 552.3 | | $ | 1,145.9 | |
| Net change in Future Development Costs | $ | 308.6 | $ | (464.4 | ) | $ | (90.4 | ) | $ | (246.2 | ) |
| Gross Reserves additions (mmboe) | | 35.2 | | (13.1 | ) | | 35.8 | | | 57.9 | |
| F&D Costs ($/boe) | $ | 17.67 | $ | 14.06 | | $ | 12.92 | | $ | 15.55 | |
| | | | | |
| Finding, Development & Acquisition Costs | | | | |
| Exploration and development expenditures and net acquisitions | $ | 307.1 | $ | 280.2 | | $ | 554.5 | | $ | 1,141.7 | |
| Net change in Future Development Costs | $ | 316.8 | $ | (464.4 | ) | $ | (107.2 | ) | $ | (254.7 | ) |
| Gross Reserves additions (mmboe) | | 36.1 | | (13.1 | ) | | 34.7 | | | 57.7 | |
| FD&A Costs ($/boe) | $ | 17.30 | $ | 14.07 | | $ | 12.88 | | $ | 15.38 | |
| | | | | |
| Proved Developed Producing Reserves | | | | |
| Finding & Development Costs | | | | |
| Exploration and development expenditures | $ | 313.3 | $ | 280.3 | | $ | 552.3 | | $ | 1,145.9 | |
| Gross Reserves additions (mmboe) | | 38.2 | | 7.7 | | | 42.5 | | | 88.2 | |
| F&D Costs ($/boe) | $ | 8.20 | $ | 36.63 | | $ | 13.04 | | $ | 12.99 | |
| | | | | |
| Finding, Development & Acquisition Costs | | | | |
| Exploration and development expenditures and net acquisitions | $ | 307.1 | $ | 280.2 | | $ | 554.5 | | $ | 1,141.7 | |
| Gross Reserves additions (mmboe) | | 38.1 | | 7.6 | | | 42.5 | | | 88.3 | |
| FD&A Costs ($/boe) | $ | 8.06 | $ | 36.64 | | $ | 13.04 | | $ | 12.93 | |
Reserves Life Index The following table sets forth our reserves life index, which is calculated by dividing our proved and proved plus probable reserves at year-end 2021 by annualized Q4/2021 production.
| | | Reserves Life Index (years) |
| | Q4/2021
Production | Proved | Proved Plus Probable |
| Crude Oil and NGL (bbl/d) | 66,452 | 9.2 | 15.3 |
| Natural Gas (mcf/d) | 86,029 | 10.7 | 15.4 |
| Oil Equivalent (boe/d) | 80,789 | 9.4 | 15.3 |
Forecast Prices and Costs The following table summarizes the forecast prices used in preparing the estimated reserves volumes and the net present values of future net revenues at December 31, 2021. The estimated future net revenue to be derived from the production of the reserves is based on the following average of the price forecasts of McDaniel, GLJ and Sproule as of January 1, 2022.
| Year |
WTI Crude Oil
US$/bbl | Edmonton Light
Crude Oil
$/bbl | Western Canadian Select
$/bbl |
Henry Hub
US$/MMbtu |
AECO Spot
$/MMbtu | Inflation Rate
%/Yr | Exchange Rate
$US/$Cdn |
| 2021 act. | 67.95 | 80.25 | 68.80 | 3.90 | 3.55 | 1.4 | 0.800 |
| 2022 | 72.83 | 86.82 | 74.42 | 3.85 | 3.56 | - | 0.797 |
| 2023 | 68.78 | 80.73 | 69.17 | 3.44 | 3.21 | 2.3 | 0.797 |
| 2024 | 66.76 | 78.01 | 66.54 | 3.17 | 3.05 | 2.0 | 0.797 |
| 2025 | 68.09 | 79.57 | 67.87 | 3.24 | 3.11 | 2.0 | 0.797 |
| 2026 | 69.45 | 81.16 | 69.23 | 3.30 | 3.17 | 2.0 | 0.797 |
| 2027 | 70.84 | 82.78 | 70.61 | 3.37 | 3.23 | 2.0 | 0.797 |
| 2028 | 72.26 | 84.44 | 72.02 | 3.44 | 3.30 | 2.0 | 0.797 |
| 2029 | 73.70 | 86.13 | 73.46 | 3.50 | 3.36 | 2.0 | 0.797 |
| 2030 | 75.18 | 87.85 | 74.69 | 3.58 | 3.43 | 2.0 | 0.797 |
| 2031 | 76.68 | 89.61 | 76.19 | 3.65 | 3.50 | 2.0 | 0.797 |
| Thereafter | Escalation rate of 2.0% | 2.0 | 0.797 |
Net Present Value of Reserves (1) (Forecast Prices and Costs) The following table summarizes the McDaniel estimate of the net present value before income taxes of the future net revenue attributable to our reserves.
| Reserves at December 31, 2021 ($ millions, discounted at) | 0% | | 5% | | 10% | | 15% | |
| Proved developed producing | 2,399 | | 2,235 | | 1,988 | | 1,787 | |
| Proved developed non-producing | 94 | | 72 | | 60 | | 52 | |
| Proved undeveloped | 2,852 | | 1,948 | | 1,399 | | 1,040 | |
| Total proved | 5,345 | | 4,255 | | 3,448 | | 2,880 | |
| Probable | 4,596 | | 2,554 | | 1,636 | | 1,149 | |
| Total Proved Plus Probable (before tax) | 9,941 | | 6,809 | | 5,084 | | 4,029 | |
Note:
(1) Includes abandonment, decommissioning and reclamation costs for all producing and non-producing wells and facilities.
Net Asset Value (Forecast Prices and Costs) Our estimated net asset value is based on the estimated net present value of all future net revenue from our reserves, before income taxes, as estimated by McDaniel at year-end, plus the estimated value of our undeveloped land holdings, less net debt. This calculation can vary significantly depending on the oil and natural gas price assumptions. In addition, this calculation does not consider "going concern" value and assumes only the reserves identified in the reserves report with no further acquisitions or incremental development.
The following table sets forth our net asset value as at December 31, 2021.
| ($ millions, except per share amounts, discounted at) | 5% | | 10% | | 15% | |
| Net present value of proved plus probable reserves (1) | 6,809 | | 5,084 | | 4,029 | |
| Undeveloped land holdings (2) | 89 | | 89 | | 89 | |
| Net Debt (4) | (1,410 | ) | (1,410 | ) | (1,410 | ) |
| Net Asset Value | 5,488 | | 3,763 | | 2,708 | |
| Net Asset Value per Share (3) | 9.73 | | 6.67 | | 4.80 | |
Notes:
(1) Includes abandonment, decommissioning and reclamation costs for all producing and non-producing wells and facilities.
(2) The value of undeveloped land holdings generally represents the estimated replacement cost of our undeveloped land.
(3) Based on 564.2 million common shares outstanding as at December 31, 2021.
(4) Capital management measure. Refer to the Specified Financial Measures section in this press release for further information.
Additional Information Our audited consolidated financial statements for the year ended December 31, 2021 and the related Management's Discussion and Analysis of the operating and financial results can be accessed on our website at
www.baytexenergy.com and will be available shortly through SEDAR at
www.sedar.com and EDGAR at
www.sec.gov/edgar.shtml.
Conference Call Tomorrow
9:00 a.m. MST (11:00 a.m. EST) |
Baytex will host a conference call tomorrow, February 25, 2022, starting at 9:00am MST (11:00am EST). To participate, please dial toll free in North America 1-800-319-4610 or international 1-416-915-3239. Alternatively, to listen to the conference call online, please enter https://services.choruscall.ca/links/baytex20220225.html in your web browser.
An archived recording of the conference call will be available shortly after the event by accessing the webcast link above. The conference call will also be archived on the Baytex website at www.baytexenergy.com. |