Calgary, Alberta--(Newsfile Corp. - October 31, 2024) - Baytex Energy Corp. (TSX:BTE) (NYSE:BTE) ("Baytex") reports its operating and financial results for the three and nine months ended September 30, 2024 (all amounts are in Canadian dollars unless otherwise noted).
"During the third quarter we generated $220 million of free cash flow, returned $101 million to shareholders through our share buyback program and quarterly dividend, and reduced net debt by 5%. Over the last fifteen months we have repurchased 9% of our shares outstanding. Our third quarter results demonstrate continued solid operational performance as well as our commitment to generating meaningful free cash flow and the delivery of strong shareholder returns. We expect to release our 2025 budget in early December. We are committed to prioritizing free cash flow and in the current commodity price environment this means moderating our growth profile and delivering stable crude oil production," commented Eric T. Greager, President and Chief Executive Officer.
Highlights
- Generated production of 154,468 boe/d (86% oil and NGL) in Q3/2024, up 3% from Q3/2023. Crude oil production (light oil, condensate, and heavy oil) increased 2% from Q3/2023 to average 112,602 bbl/d.
- Increased production per basic share by 10% in Q3/2024, compared to Q3/2023.
- Executed a $306 million exploration and development program in Q3/2024, consistent with our full-year plan.
- Reported cash flows from operating activities of $550 million ($0.69 per basic share) in Q3/2024.
- Delivered adjusted funds flow(1) of $538 million ($0.68 per basic share) in Q3/2024.
- Generated net income of $185 million ($0.23 per basic share) in Q3/2024.
- Generated free cash flow(2) of $220 million ($0.28 per basic share) in Q3/2024 and returned $101 million to shareholders.
- Repurchased 17.6 million common shares in Q3/2024 for $83 million, at an average price of $4.68 per share.
- Paid a quarterly cash dividend of $18 million ($0.0225 per share) on October 1, 2024.
- Reduced net debt(1) by 5% in Q3/2024 and 12% over the last four quarters, to $2.5 billion. Maintained balance sheet strength with a total debt(3) to Bank EBITDA(3) ratio of 1.0x.
2024 Outlook
We continue to execute our 2024 plan and anticipate full-year 2024 production of approximately 153,000 boe/d (previous guidance range of 152,000 to 154,000 boe/d). We anticipate full-year 2024 exploration and development expenditures of approximately $1.25 billion, consistent with our previous guidance range of $1.2 to $1.3 billion. Based on year-to-date actual results and the forward strip for the balance of 2024(4), we expect to generate free cash flow(2) of approximately $570 million ($0.71 per basic share) in 2024.
(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) Calculated in accordance with our amended credit facilities agreement which is available on SEDAR+ at www.sedarplus.ca.
(4) Q4/2024 commodity prices: WTI - US$69/bbl; WCS differential - US$14/bbl; NYMEX Gas - US$2.90/MMbtu; and Exchange Rate (CAD/USD) - 1.35.
| Three Months Ended | Nine Months Ended | ||||||||||||||
| September 30, 2024 | June 30, 2024 | September 30, 2023 | September 30, 2024 | September 30, 2023 | |||||||||||
| FINANCIAL (thousands of Canadian dollars, except per common share amounts) | |||||||||||||||
| Petroleum and natural gas sales | $ | 1,074,623 | $ | 1,133,123 | $ | 1,163,010 | $ | 3,191,938 | $ | 2,317,106 | |||||
| Adjusted funds flow (1) | 537,947 | 532,839 | 581,623 | 1,494,632 | 1,092,202 | ||||||||||
| Per share - basic | 0.68 | 0.65 | 0.68 | 1.84 | 1.65 | ||||||||||
| Per share - diluted | 0.67 | 0.65 | 0.68 | 1.84 | 1.64 | ||||||||||
| Free cash flow (2) | 220,159 | 180,673 | 158,440 | 400,744 | 252,835 | ||||||||||
| Per share - basic | 0.28 | 0.22 | 0.19 | 0.49 | 0.38 | ||||||||||
| Per share - diluted | 0.28 | 0.22 | 0.18 | 0.49 | 0.38 | ||||||||||
| Cash flows from operating activities | 550,042 | 505,584 | 444,033 | 1,439,399 | 821,279 | ||||||||||
| Per share - basic | 0.69 | 0.62 | 0.52 | 1.78 | 1.24 | ||||||||||
| Per share - diluted | 0.69 | 0.62 | 0.52 | 1.77 | 1.23 | ||||||||||
| Net income | 185,219 | 103,898 | 127,430 | 275,074 | 392,474 | ||||||||||
| Per share - basic | 0.23 | 0.13 | 0.15 | 0.34 | 0.59 | ||||||||||
| Per share - diluted | 0.23 | 0.13 | 0.15 | 0.34 | 0.59 | ||||||||||
| Dividends declared | 17,732 | 18,161 | 19,138 | 54,387 | 19,138 | ||||||||||
| Per share | 0.0225 | 0.0225 | 0.0225 | 0.0675 | 0.0225 | ||||||||||
| Capital Expenditures | |||||||||||||||
| Exploration and development expenditures | $ | 306,332 | $ | 339,573 | $ | 409,191 | $ | 1,058,456 | $ | 813,521 | |||||
| Acquisitions and divestitures | (394 | ) | 654 | 4,051 | 35,638 | 4,210 | |||||||||
| Total oil and natural gas capital expenditures | $ | 305,938 | $ | 340,227 | $ | 413,242 | $ | 1,094,094 | $ | 817,731 | |||||
| Net Debt | |||||||||||||||
| Credit facilities | $ | 466,108 | $ | 625,976 | $ | 1,046,756 | $ | 466,108 | $ | 1,046,756 | |||||
| Long-term notes | 1,856,869 | 1,881,894 | 1,637,640 | 1,856,869 | 1,637,640 | ||||||||||
| Total debt (3) | 2,322,977 | 2,507,870 | 2,684,396 | 2,322,977 | 2,684,396 | ||||||||||
| Working capital deficiency (2) | 170,292 | 131,144 | 139,952 | 170,292 | 139,952 | ||||||||||
| Net debt (1) | $ | 2,493,269 | $ | 2,639,014 | $ | 2,824,348 | $ | 2,493,269 | $ | 2,824,348 | |||||
| Shares Outstanding - basic (thousands) | |||||||||||||||
| Weighted average | 796,064 | 814,151 | 855,300 | 810,589 | 662,379 | ||||||||||
| End of period | 787,328 | 804,977 | 845,360 | 787,328 | 845,360 | ||||||||||
| BENCHMARK PRICES | |||||||||||||||
| Crude oil | |||||||||||||||
| WTI (US$/bbl) | $ | 75.10 | $ | 80.57 | $ | 82.26 | $ | 77.54 | $ | 77.39 | |||||
| MEH oil (US$/bbl) | 77.50 | 83.10 | 84.10 | 79.85 | 78.84 | ||||||||||
| MEH oil differential to WTI (US$/bbl) | 2.40 | 2.53 | 1.84 | 2.31 | 1.45 | ||||||||||
| Edmonton par ($/bbl) | 97.91 | 105.30 | 107.93 | 98.46 | 100.70 | ||||||||||
| Edmonton par differential to WTI (US$/bbl) | (3.30 | ) | (3.62 | ) | (1.78 | ) | (5.16 | ) | (2.54 | ) | |||||
| WCS heavy oil ($/bbl) | 83.98 | 91.72 | 93.02 | 84.45 | 80.47 | ||||||||||
| WCS differential to WTI (US$/bbl) | (13.51 | ) | (13.55 | ) | (12.89 | ) | (15.46 | ) | (17.57 | ) | |||||
| Natural gas | |||||||||||||||
| NYMEX (US$/MMbtu) | $ | 2.16 | $ | 1.89 | $ | 2.55 | $ | 2.10 | $ | 2.69 | |||||
| AECO ($/Mcf) | 0.81 | 1.44 | 2.39 | 1.43 | 3.03 | ||||||||||
| CAD/USD average exchange rate | 1.3636 | 1.3684 | 1.3410 | 1.3603 | 1.3453 | ||||||||||
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) Calculated in accordance with our amended credit facilities agreement which is available on SEDAR+ at www.sedarplus.ca.
| Three Months Ended | Nine Months Ended | ||||||||||||||
| September 30, 2024 | June 30, 2024 | September 30, 2023 | September 30, 2024 | September 30, 2023 | |||||||||||
| OPERATING | |||||||||||||||
| Daily Production | |||||||||||||||
| Light oil and condensate (bbl/d) | 69,843 | 67,031 | 75,763 | 67,645 | 47,750 | ||||||||||
| Heavy oil (bbl/d) | 42,759 | 43,703 | 35,204 | 42,342 | 34,076 | ||||||||||
| NGL (bbl/d) | 19,836 | 20,167 | 18,004 | 19,767 | 11,318 | ||||||||||
| Total liquids (bbl/d) | 132,438 | 130,901 | 128,971 | 129,754 | 93,144 | ||||||||||
| Natural gas (Mcf/d) | 132,175 | 139,764 | 129,780 | 140,069 | 96,787 | ||||||||||
| Oil equivalent (boe/d @ 6:1) (1) | 154,468 | 154,194 | 150,600 | 153,099 | 109,275 | ||||||||||
| Netback (thousands of Canadian dollars) | |||||||||||||||
| Total sales, net of blending and other expense (2) | $ | 1,022,721 | $ | 1,065,438 | $ | 1,113,180 | $ | 3,008,143 | $ | 2,154,600 | |||||
| Royalties | (223,800 | ) | (240,440 | ) | (240,049 | ) | (673,411 | ) | (441,222 | ) | |||||
| Operating expense | (167,119 | ) | (167,705 | ) | (174,119 | ) | (508,259 | ) | (405,965 | ) | |||||
| Transportation expense | (36,883 | ) | (33,314 | ) | (27,983 | ) | (100,032 | ) | (59,562 | ) | |||||
| Operating netback (2) | $ | 594,919 | $ | 623,979 | $ | 671,029 | $ | 1,726,441 | $ | 1,247,851 | |||||
| General and administrative | (17,895 | ) | (21,006 | ) | (20,536 | ) | (61,313 | ) | (47,510 | ) | |||||
| Cash financing and interest | (50,109 | ) | (53,946 | ) | (56,495 | ) | (157,335 | ) | (103,125 | ) | |||||
| Realized financial derivatives gain (loss) | 331 | (2,257 | ) | 2,055 | 3,562 | 23,835 | |||||||||
| Other (3) | 10,701 | (13,931 | ) | (14,430 | ) | (16,723 | ) | (28,849 | ) | ||||||
| Adjusted funds flow (4) | $ | 537,947 | $ | 532,839 | $ | 581,623 | $ | 1,494,632 | $ | 1,092,202 | |||||
| Netback (per boe) (2) | |||||||||||||||
| Total sales, net of blending and other expense (2) | $ | 71.97 | $ | 75.93 | $ | 80.34 | $ | 71.71 | $ | 72.22 | |||||
| Royalties (5) | (15.75 | ) | (17.14 | ) | (17.33 | ) | (16.05 | ) | (14.79 | ) | |||||
| Operating expense (5) | (11.76 | ) | (11.95 | ) | (12.57 | ) | (12.12 | ) | (13.61 | ) | |||||
| Transportation expense (5) | (2.60 | ) | (2.37 | ) | (2.02 | ) | (2.38 | ) | (2.00 | ) | |||||
| Operating netback (2) | $ | 41.86 | $ | 44.47 | $ | 48.42 | $ | 41.16 | $ | 41.82 | |||||
| General and administrative (5) | (1.26 | ) | (1.50 | ) | (1.48 | ) | (1.46 | ) | (1.59 | ) | |||||
| Cash financing and interest (5) | (3.53 | ) | (3.84 | ) | (4.08 | ) | (3.75 | ) | (3.46 | ) | |||||
| Realized financial derivatives (loss) gain (5) | 0.02 | (0.16 | ) | 0.15 | 0.08 | 0.80 | |||||||||
| Other (3) | 0.76 | (1.00 | ) | (1.03 | ) | (0.40 | ) | (0.96 | ) | ||||||
| Adjusted funds flow (4) | $ | 37.85 | $ | 37.97 | $ | 41.98 | $ | 35.63 | $ | 36.61 | |||||
Notes:
(1) 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.
(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) Other is comprised of realized foreign exchange gain or loss, other income or expense, current income tax expense or recovery and cash share-based compensation. Refer to the Q3/2024 MD&A for further information on these amounts.
(4) Capital management measure. Refer to the Specified Financial Measures section in this press release for further information.
(5) Calculated as royalties, operating, transportation expense, general and administrative expense, cash interest expense or realized financial derivatives gain or loss divided by barrels of oil equivalent production volume for the applicable period.
Baytex is a well-capitalized, North American oil-weighted producer with 60% of our production in the Eagle Ford and the balance in western Canada. We are focused on disciplined capital allocation to prioritize free cash flow generation while maintaining a strong balance sheet. We currently allocate 50% of free cash flow to the balance sheet and 50% to shareholder returns, which includes a combination of share buybacks and a quarterly dividend.
The following table summarizes our updated 2024 guidance which reflects year-to-date results and our expectations for the fourth quarter.
| Previous Annual Guidance(1) | Revised Annual Guidance | |||
| Production (boe/d) | 152,000 - 154,000 | ~ 153,000 | ||
| Exploration and development expenditures | $1.2 - $1.3 billion | ~ $1.25 billion | ||
| Expenses: | ||||
| Average royalty rate (2) | ~ 23.0% | ~ 22.5% | ||
| Operating (3) | $11.25 - $12.00/boe | ~ $12.00/boe | ||
| Transportation (3) | $2.35 - $2.55/boe | ~ $2.45/boe | ||
| General and administrative (3) | $92 million ($1.65/boe) | $85 million ($1.52/boe) | ||
| Interest (3) | $200 million ($3.58/boe) | no change | ||
| Current income tax (3) | $40 million ($0.72/boe) | $25 million ($0.45/boe) | ||
| Leasing expenditures | $12 million | $15 million | ||
| Asset retirement obligations | $30 million | no change | ||
Our 2025 capital budget is expected to be released in early December following approval by our Board of Directors. We are committed to prioritizing free cash flow and in the current commodity price environment this means moderating our growth profile and delivering stable crude oil production.
Financial Highlights
During the third quarter, we delivered operating and financial results consistent with our full-year plan. We increased production per basic share by 10% in Q3/2024, compared to Q3/2023, with production averaging 154,468 boe/d (86% oil and NGL). Exploration and development expenditures totaled $306 million and we brought 82 (69.2 net) wells onstream.
Adjusted funds flow(4) was $538 million or $0.68 per basic share and we generated net income of $185 million ($0.23 per basic share). During the third quarter we recorded approximately $22 million in insurance claim proceeds related to the 2023 Alberta wild fires and prior-period adjustments with respect to previously paid royalties.
During the third quarter we generated free cash flow(2) of $220 million ($0.28 per basic share) and returned $101 million to shareholders. We repurchased 17.6 million common shares for $83 million, at an average price of $4.68 per share, and paid a quarterly cash dividend of $18 million ($0.0225 per share).
Over the last five quarters, we returned $479 million to shareholders. We repurchased 75 million common shares for $387 million, representing 8.7% of our shares outstanding, at an average price of $5.14 per share, and paid total dividends of $92 million ($0.1125 per share).
Continuing to strengthen our balance sheet remains a priority. Our net debt(4) at September 30, 2024 was $2.5 billion, down 5% from June 30, 2024. Over the last four quarters, we reduced our net debt by 12%. Our total debt(5) (excluding working capital) at September 30, 2024 was $2.3 billion.
Operating Results
In the Eagle Ford, production averaged 89,800 boe/d (82% oil and NGL) in Q3/2024, up from 87,311 boe/d (85% oil and NGL) in Q3/2023. We are executing our 2024 development program consistent with our full-year plan. During the third quarter we brought onstream 21 net wells, including 17 net operated wells. Through the first nine months of 2024, we brought onstream 58 net wells, including 46 net operated wells.
(1) As announced on July 25, 2024.
(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, cash interest expense, or current income tax expense (recovery) divided by barrels of oil equivalent 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 our amended credit facilities agreement which is available on SEDAR+ at www.sedarplus.ca.
Our development program is largely focused on the black oil and volatile oil windows of our acreage where we typically generate 30-day peak crude oil rates of 700 to 800 bbl/d (900 to 1,100 boe/d) per well with average lateral lengths of 9,000 to 9,500 feet. Year-to-date, we have realized an 8% improvement in operated drilling and completion costs per completed lateral foot over 2023.
In our Canadian light oil business unit, production averaged 20,428 boe/d (84% oil and NGL) in Q3/2024. We have made substantial strides in advancing our understanding of the Pembina Duvernay and production averaged 7,550 boe/d (83% oil and NGL) in Q3/2024, up from 4,758 boe/d (86% oil and NGL) in Q3/2023. In the Viking, we brought onstream 35 (34.9 net) wells and the asset continues to perform in line with expectations.
In the Pembina Duvernay, we were pleased with the efficiency of our two-pad, seven-well drilling program which saw a 21% improvement in drilling days (spud to rig release) and a 10% improvement in drilling costs. Through a combination of facility and completion design optimization, our average 30-day peak production rates improved by 40%, as compared to 2023 well results, with only a 4% increase in lateral length.
The first pad (3-wells) was brought onstream in May with an average completed lateral length of 11,000 feet and generated an average 30-day peak production rate of 1,354 boe/d per well (890 bbl/d of crude oil, 326 bbl/d of NGLs, 826 Mcf/d of natural gas). The second pad (4-wells) was brought onstream in August with an average completed lateral length of 9,250 feet and generated an average 30-day peak production rate of 968 boe/d per well (725 bbl/d of crude oil, 171 bbl/d of NGLs, 434 Mcf/d of natural gas).
In our heavy oil business unit, production averaged 44,240 boe/d (95% oil and NGL) in Q3/2024, up from 37,506 boe/d (94% oil and NGL) in Q3/2023. Peavine continued to outperform expectations with production averaging 20,085 bbl/d (100% heavy oil) in Q3/2024, up from 13,821 bbl/d (100% heavy oil) in Q3/2023. During the third quarter, we brought onstream 7 (7.0 net) wells. At Peace River, we brought onstream 5 multi-lateral horizontal wells, including one successful Bluesky exploration well on a recently acquired 66-section land block contiguous to our existing acreage position. At Lloydminster, we brought onstream 11 (10.2 net) multi-lateral horizontal wells across the broader Mannville group.
Management Change
Baytex is pleased to announce that Taylor Young has been promoted to Vice President and General Manager, U.S. Eagle Ford Operations. Mr. Young has over 14 years industry experience and holds a Bachelor of Science in Mechanical Engineering from the Colorado School of Mines. He has been with Baytex and its predecessor companies for the last four years, most recently as Director, Subsurface for our U.S. Eagle Ford Operations.
Julia Gwaltney, Senior Vice President and General Manager, U.S. Eagle Ford Operations, has stepped down to pursue another opportunity. Baytex would like to thank Ms. Gwaltney for her contributions and wish her success in her future endeavors.
Quarterly Dividend
The Board of Directors has declared a quarterly cash dividend of $0.0225 per share, to be paid on January 2, 2025 to shareholders of record on December 13, 2024.
Additional Information
Our condensed consolidated interim unaudited financial statements for the three and nine months ended September 30, 2024 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.sedarplus.ca and EDGAR at www.sec.gov/edgar.shtml.
| Conference Call Tomorrow 9:00 a.m. MT (11:00 a.m. ET) |
| Baytex will host a conference call tomorrow, November 1, 2024, starting at 9:00am MT (11:00am ET). To participate, please dial toll free in North America 1-844-763-8274 or international 1-647-484-8814. Alternatively, to listen to the conference call online, please enter https://event.choruscall.com/mediaframe/webcast.html?webcastid=OkApicVw in your web browser. To register, visit our website at https://www.baytexenergy.com/investors/events-presentations. 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. |
Advisory Regarding Forward-Looking Statements
In the interest of providing Baytex's shareholders and potential investors with information regarding Baytex, including management's assessment of Baytex's future plans and operations, certain statements in this press release are "forward-looking statements" within the meaning of the United States Private Securities Litigation Reform Act of 1995 and "forward-looking information" within the meaning of applicable Canadian securities legislation (collectively, "forward-looking statements"). In some cases, forward-looking statements can be identified by terminology such as "believe", "continue", "estimate", "expect", "forecast", "intend", "may", "objective", "ongoing", "outlook", "potential", "project", "plan", "should", "target", "would", "will" or similar words suggesting future outcomes, events or performance. The forward-looking statements contained in this press release speak only as of the date thereof and are expressly qualified by this cautionary statement.
Specifically, this press release contains forward-looking statements relating to but not limited to: that we expect to release our 2025 budget in December 2024; that we are committed to prioritizing free cash flow, maintaining a strong balance sheet and in the current commodity price environment we will moderate our growth profile and deliver stable crude oil production; for 2024: our guidance for exploration and development expenditures and production and the amount of free cash flow we expect to generate; our expected allocation of free cash flow as between the balance sheet and shareholder returns (including share buybacks and quarterly dividends); and our 2024 guidance for expense items, leasing expenditures and asset retirement obligations. In addition, information and statements relating to reserves are deemed to be forward-looking statements, as they involve implied assessment, based on certain estimates and assumptions, that the reserves described exist in quantities predicted or estimated, and that they can be profitably produced in the future.
These forward-looking statements are based on certain key assumptions regarding, among other things: oil and natural gas prices and differentials between light, medium and heavy crude oil prices; well production rates and reserve volumes; success obtained in drilling new wells; our ability to add production and reserves through our exploration and development activities; capital expenditure levels; operating costs; our ability to borrow under our credit agreements; the receipt, in a timely manner, of regulatory and other required approvals for our operating activities; the availability and cost of labour and other industry services; interest and foreign exchange rates; the continuance of existing and, in certain circumstances, proposed tax and royalty regimes; our ability to develop our crude oil and natural gas properties in the manner currently contemplated; our ability to market oil and natural gas successfully; that we will have sufficient financial resources in the future to provide shareholder returns; and current industry conditions, laws and regulations continuing in effect (or, where changes are proposed, such changes being adopted as anticipated). Readers are cautioned that such assumptions, although considered reasonable by Baytex at the time of preparation, may prove to be incorrect.
Actual results achieved will vary from the information provided herein as a result of numerous known and unknown risks and uncertainties and other factors. Such factors include, but are not limited to: the risk of an extended period of low oil and natural gas prices; risks associated with our ability to develop our properties and add reserves; that we may not achieve the expected benefits of acquisitions and we may sell assets below their carrying value; the availability and cost of capital or borrowing; restrictions or costs imposed by climate change initiatives and the physical risks of climate change; the impact of an energy transition on demand for petroleum productions; availability and cost of gathering, processing and pipeline systems; retaining or replacing our leadership and key personnel; changes in income tax or other laws or government incentive programs; risks associated with large projects; risks associated with higher a higher concentration of activity and tighter drilling spacing; costs to develop and operate our properties; risks associated with achieving our total debt target, production guidance, exploration and development expenditures guidance; the amount of free cash flow we expect to generate; risk that the board of directors determines to allocate capital other than as set forth herein; current or future controls, legislation or regulations; restrictions on or access to water or other fluids; public perception and its influence on the regulatory regime; new regulations on hydraulic fracturing; regulations regarding the disposal of fluids; risks associated with our hedging activities; variations in interest rates and foreign exchange rates; uncertainties associated with estimating oil and natural gas reserves; our inability to fully insure against all risks; risks associated with a third-party operating our Eagle Ford properties; additional risks associated with our thermal heavy crude oil projects; our ability to compete with other organizations in the oil and gas industry; risk that we do not achieve our GHG emissions intensity reduction target; risks associated with our use of information technology systems; adverse results of litigation; that our Credit Facilities may not provide sufficient liquidity or may not be renewed; failure to comply with the covenants in our debt agreements; risks associated with expansion into new activities; the impact of Indigenous claims; risks of counterparty default; impact of geopolitical risk and conflicts; loss of foreign private issuer status; conflicts of interest between the Company and its directors and officers; variability of share buybacks and dividends; risks associated with the ownership of our securities, including changes in market-based factors; risks for United States and other non-resident shareholders, including the ability to enforce civil remedies, differing practices for reporting reserves and production, additional taxation applicable to non-residents and foreign exchange risk; and other factors, many of which are beyond our control. Readers are cautioned that the foregoing list of risk factors is not exhaustive. New risk factors emerge from time to time, and it is not possible for management to predict all of such factors and to assess in advance the impact of each such factor on our business or the extent to which any factor, or combination of factors, may cause actual results to differ materially from those contained in any forward-looking statements.
These and additional risk factors are discussed in our Annual Information Form, Annual Report on Form 40-F and Management's Discussion and Analysis for the year ended December 31, 2023 filed with Canadian securities regulatory authorities and the U.S. Securities and Exchange Commission and in our other public filings. The above summary of assumptions and risks related to forward-looking statements has been provided in order to provide shareholders and potential investors with a more complete perspective on Baytex's current and future operations and such information may not be appropriate for other purposes.
This press release contains information that may be considered a financial outlook under applicable securities laws about the Company's potential financial position, including, but not limited to, our 2024 guidance for development expenditures; our expected 2024 free cash flow; and our intentions regarding the allocating our annual free cash flow; all of which are subject to numerous assumptions, risk factors, limitations and qualifications, including those set forth in the above paragraphs. The actual results of operations of the Company and the resulting financial results will vary from the amounts set forth in this press release and such variations may be material. This information has been provided for illustration only and with respect to future periods are based on budgets and forecasts that are speculative and are subject to a variety of contingencies and may not be appropriate for other purposes. Accordingly, these estimates are not to be relied upon as indicative of future results. Except as required by applicable securities laws, the Company undertakes no obligation to update such financial outlook, whether as a result of new information, future events or otherwise. The financial outlook contained in this press release was made as of the date of this press release and was provided for the purpose of providing further information about the Company's potential future business operations. Readers are cautioned that the financial outlook contained in this press release is not conclusive and is subject to change.
The future acquisition of our common shares pursuant to a share buyback (including through its NCIB), if any, and the level thereof is uncertain. Any decision to acquire Common Shares pursuant to a share buyback will be subject to the discretion of the Board and may depend on a variety of factors, including, without limitation, the Company's business performance, financial condition, financial requirements, growth plans, expected capital requirements and other conditions existing at such future time including, without limitation, contractual restrictions (including covenants contained in the agreements governing any indebtedness that the Company has incurred or may incur in the future, including the terms of the Credit Facilities) and satisfaction of the solvency tests imposed on the Company under applicable corporate law. There can be no assurance of the number of Common Shares that the Company will acquire pursuant to a share buyback, if any, in the future.
Baytex's future shareholder distributions, including but not limited to the payment of dividends, if any, and the level thereof is uncertain. Any decision to pay dividends on the common shares (including the actual amount, the declaration date, the record date and the payment date in connection therewith and any special dividends) will be subject to the discretion of the Board of Directors of Baytex and may depend on a variety of factors, including, without limitation, Baytex's business performance, financial condition, financial requirements, growth plans, expected capital requirements and other conditions existing at such future time including, without limitation, contractual restrictions and satisfaction of the solvency tests imposed on Baytex under applicable corporate law. Further, the actual amount, the declaration date, the record date and the payment date of any dividend are subject to the discretion of the Board of Directors of Baytex.
All amounts in this press release are stated in Canadian dollars unless otherwise specified.
Specified Financial Measures
In this press release, we refer to certain financial measures (such as free cash flow, operating netback, working capital deficiency, average royalty rate and total sales, net of blending and other expense) which do not have any standardized meaning prescribed by IFRS. While these measures are commonly used in the oil and gas industry, our determination of these measures may not be comparable with calculations of similar measures presented by other reporting issuers. This press release also contains the terms "adjusted funds flow" and "net debt" which are considered capital management measures. We believe that inclusion of these specified financial measures provides useful information to financial statement users when evaluating the financial results of Baytex.
Non-GAAP Financial Measures
Total sales, net of blending and other expense
Total sales, net of blending and other expense represents the revenues realized from produced volumes during a period. Total sales, net of blending and other expense is comprised of total petroleum and natural gas sales adjusted for blending and other expense. We believe including the blending and other expense associated with purchased volumes is useful when analyzing our realized pricing for produced volumes against benchmark commodity prices.
Operating netback
Operating netback and operating netback after financial derivatives are used to assess our operating performance and our ability to generate cash margin on a unit of production basis. Operating netback is comprised of petroleum and natural gas sales less blending expense, royalties, operating expense and transportation expense.
The following table reconciles total sales, net of blending and other expense and operating netback to petroleum and natural gas sales.
| Three Months Ended | Nine Months Ended | ||||||||||||||
| ($ thousands) | September 30, 2024 | June 30, 2024 | September 30, 2023 | September 30, 2024 | September 30, 2023 | ||||||||||
| Petroleum and natural gas sales | $ | 1,074,623 | $ | 1,133,123 | $ | 1,163,010 | $ | 3,191,938 | $ | 2,317,106 | |||||
| Blending and other expense | (51,902 | ) | (67,685 | ) | (49,830 | ) | (183,795 | ) | (162,506 | ) | |||||
| Total sales, net of blending and other expense | $ | 1,022,721 | $ | 1,065,438 | $ | 1,113,180 | $ | 3,008,143 | $ | 2,154,600 | |||||
| Royalties | (223,800 | ) | (240,440 | ) | (240,049 | ) | (673,411 | ) | (441,222 | ) | |||||
| Operating expense | (167,119 | ) | (167,705 | ) | (174,119 | ) | (508,259 | ) | (405,965 | ) | |||||
| Transportation expense | (36,883 | ) | (33,314 | ) | (27,983 | ) | (100,032 | ) | (59,562 | ) | |||||
| Operating netback | $ | 594,919 | $ | 623,979 | $ | 671,029 | $ | 1,726,441 | $ | 1,247,851 | |||||
| Realized financial derivatives (loss) gain (1) | 331 | (2,257 | ) | 2,055 | 3,562 | 23,835 | |||||||||
| Operating netback after realized financial derivatives | $ | 595,250 | $ | 621,722 | $ | 673,084 | $ | 1,730,003 | $ | 1,271,686 | |||||
(1) Realized financial derivatives gain or loss is a component of financial derivatives gain or loss. See Note 17 - Financial Instruments and Risk Management in the consolidated financial statements for the three and nine months ended September 30, 2024 and the consolidated financial statements for the six months ended June 30, 2024 for further information.
Free cash flow
We use free cash flow to evaluate our financial performance and to assess the cash available for debt repayment, common share repurchases, dividends and acquisition opportunities. Free cash flow is comprised of cash flows from operating activities adjusted for changes in non-cash working capital, additions to exploration and evaluation assets, additions to oil and gas properties, payments on lease obligations, transaction costs and cash premiums on derivatives.
Free cash flow is reconciled to cash flows from operating activities in the following table.
| Three Months Ended | Nine Months Ended | ||||||||||||||
| ($ thousands) | September 30, 2024 | June 30, 2024 | September 30, 2023 | September 30, 2024 | September 30, 2023 | ||||||||||
| Cash flows from operating activities | $ | 550,042 | $ | 505,584 | $ | 444,033 | $ | 1,439,399 | $ | 821,279 | |||||
| Change in non-cash working capital | (20,813 | ) | 20,140 | 126,075 | 31,350 | 205,924 | |||||||||
| Additions to exploration and evaluation assets | - | - | (40 | ) | - | (1,271 | ) | ||||||||
| Additions to oil and gas properties | (306,332 | ) | (339,573 | ) | (409,151 | ) | (1,058,456 | ) | (812,250 | ) | |||||
| Payments on lease obligations | (2,738 | ) | (5,478 | ) | (4,740 | ) | (13,088 | ) | (7,076 | ) | |||||
| Transaction costs | - | - | 2,263 | 1,539 | 43,966 | ||||||||||
| Cash premiums on derivatives | - | - | - | - | 2,263 | ||||||||||
| Free cash flow | $ | 220,159 | $ | 180,673 | $ | 158,440 | $ | 400,744 | $ | 252,835 | |||||
Working capital deficiency
Working capital deficiency is calculated as cash, trade receivables, prepaids and other assets net of trade payables, dividends payable, other long-term liabilities and share-based compensation liability. Working capital deficiency is used by management to measure the Company's liquidity. At September 30, 2024, the Company had $1.0 billion of available credit facility capacity to cover any working capital deficiencies.
The following table summarizes the calculation of working capital deficiency.
| As at | |||||||||
| ($ thousands) | September 30, 2024 | June 30, 2024 | December 31, 2023 | ||||||
| Cash | $ | (21,311 | ) | $ | (35,887 | ) | $ | (55,815 | ) |
| Trade receivables | (375,942 | ) | (429,098 | ) | (339,405 | ) | |||
| Prepaids and other assets | (78,427 | ) | (81,805 | ) | (83,259 | ) | |||
| Trade payables | 584,696 | 617,222 | 477,295 | ||||||
| Share-based compensation liability | 23,962 | 22,706 | 35,732 | ||||||
| Other long-term liabilities | 19,582 | 19,845 | 19,147 | ||||||
| Dividends payable | 17,732 | 18,161 | 18,381 | ||||||
| Working capital deficiency | $ | 170,292 | $ | 131,144 | $ | 72,076 | |||
Non-GAAP Financial Ratios
Total sales, net of blending and other expense per boe
Total sales, net of blending and other per boe is used to compare our realized pricing to applicable benchmark prices and is calculated as total sales, net of blending and other expense divided by barrels of oil equivalent production volume for the applicable period.
Average royalty rate
Average royalty rate is used to evaluate the performance of our operations from period to period and is comprised of royalties divided by total sales, net of blending and other expense (a non-GAAP financial measure). The actual royalty rates can vary for a number of reasons, including the commodity produced, royalty contract terms, commodity price level, royalty incentives and the area or jurisdiction.
Operating netback per boe
Operating netback per boe is equal to operating netback (a non-GAAP financial measure) divided by barrels of oil equivalent sales volume for the applicable period and is used to assess our operating performance on a unit of production basis.
Capital Management Measures
Net debt
We use net debt to monitor our current financial position and to evaluate existing sources of liquidity. We also use net debt projections to estimate future liquidity and whether additional sources of capital are required to fund ongoing operations. Net debt is comprised of our credit facilities and long-term notes outstanding adjusted for unamortized debt issuance costs, trade payables, share-based compensation liability, dividends payable, other long-term liabilities, cash, trade receivables, and prepaids and other assets.
The following table summarizes our calculation of net debt.
| As at | |||||||||
| ($ thousands) | September 30, 2024 | June 30, 2024 | December 31, 2023 | ||||||
| Credit facilities | $ | 449,116 | $ | 607,589 | $ | 848,749 | |||
| Unamortized debt issuance costs - Credit facilities (1) | 16,992 | 18,387 | 15,987 | ||||||
| Long-term notes | 1,810,701 | 1,833,182 | 1,562,361 | ||||||
| Unamortized debt issuance costs - Long-term notes (1) | 46,168 | 48,712 | 35,114 | ||||||
| Trade payables | 584,696 | 617,222 | 477,295 | ||||||
| Share-based compensation liability | 23,962 | 22,706 | 35,732 | ||||||
| Other long-term liabilities | 19,582 | 19,845 | 19,147 | ||||||
| Dividends payable | 17,732 | 18,161 | 18,381 | ||||||
| Cash | (21,311 | ) | (35,887 | ) | (55,815 | ) | |||
| Trade receivables | (375,942 | ) | (429,098 | ) | (339,405 | ) | |||
| Prepaids and other assets | (78,427 | ) | (81,805 | ) | (83,259 | ) | |||
| Net debt | $ | 2,493,269 | $ | 2,639,014 | $ | 2,534,287 | |||
(1) Unamortized debt issuance costs for the respective periods were obtained from Note 7 - Credit Facilities and Note 8 - Long-term Notes from the consolidated financial statements for the three and nine months ended September 30, 2024 and the consolidated financial statements for the six months ended June 30, 2024.
Adjusted funds flow
Adjusted funds flow is used to monitor operating performance and our ability to generate funds for exploration and development expenditures and settlement of abandonment obligations. Adjusted funds flow is comprised of cash flows from operating activities adjusted for changes in non-cash working capital, asset retirement obligations settled, transaction costs and cash premiums on derivatives during the applicable period.
Adjusted funds flow is reconciled to amounts disclosed in the primary financial statements in the following table.
| Three Months Ended | Nine Months Ended | ||||||||||||||
| ($ thousands) | September 30, 2024 | June 30, 2024 | September 30, 2023 | September 30, 2024 | September 30, 2023 | ||||||||||
| Cash flow from operating activities | $ | 550,042 | $ | 505,584 | $ | 444,033 | $ | 1,439,399 | $ | 821,279 | |||||
| Change in non-cash working capital | (20,813 | ) | 20,140 | 126,075 | 31,350 | 205,924 | |||||||||
| Asset retirement obligations settled | 8,718 | 7,115 | 9,252 | 22,344 | 18,770 | ||||||||||
| Transaction costs | - | - | 2,263 | 1,539 | 43,966 | ||||||||||
| Cash premiums on derivatives | - | - | - | - | 2,263 | | |||||||||
| Adjusted funds flow | $ | 537,947 | $ | 532,839 | $ | 581,623 | $ | 1,494,632 | $ | 1,092,202 | |||||
Advisory Regarding Oil and Gas Information
Where applicable, 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.
References herein to average 30-day peak production rates and other short-term production rates are useful in confirming the presence of hydrocarbons, however, such rates are not determinative of the rates at which such wells will commence production and decline thereafter and are not indicative of long term performance or of ultimate recovery. While encouraging, readers are cautioned not to place reliance on such rates in calculating aggregate production for us or the assets for which such rates are provided. A pressure transient analysis or well-test interpretation has not been carried out in respect of all wells. Accordingly, we caution that the test results should be considered to be preliminary.
Throughout this press release, "oil and NGL" refers to heavy crude oil, bitumen, light and medium crude oil, tight oil, condensate and natural gas liquids ("NGL") product types as defined by NI 51-101. The following table shows Baytex's disaggregated production volumes for the three and nine months ended September 30, 2024. The NI 51-101 product types are included as follows: "Heavy Crude Oil" - heavy crude oil and bitumen, "Light and Medium Crude Oil" - light and medium crude oil, tight oil and condensate, "NGL" - natural gas liquids and "Natural Gas" - shale gas and conventional natural gas.
| Three Months Ended September 30, 2024 | Three Months Ended September 30, 2023 | ||||||||||
| Heavy Crude Oil (bbl/d) | Light and Medium Crude Oil (bbl/d) | NGL (bbl/d) | Natural Gas (Mcf/d) | Oil Equivalent (boe/d) | Heavy Crude Oil (bbl/d) | Light and Medium Crude Oil (bbl/d) | NGL (bbl/d) | Natural Gas (Mcf/d) | Oil Equivalent (boe/d) | ||
| Canada - Heavy | |||||||||||
| Peace River | 9,024 | 13 | 36 | 11,959 | 11,067 | 9,766 | 8 | 45 | 12,075 | 11,831 | |
| Lloydminster | 12,792 | 19 | - | 1,659 | 13,088 | 11,617 | 20 | - | 1,300 | 11,854 | |
| Peavine | 20,085 | - | - | - | 20,085 | 13,821 | - | - | - | 13,821 | |
| Canada - Light | |||||||||||
| Viking | - | 9,328 | 183 | 9,152 | 11,036 | - | 14,074 | 253 | 12,015 | 16,330 | |
| Duvernay | - | 4,019 | 2,276 | 7,529 | 7,550 | - | 2,962 | 1,130 | 3,996 | 4,758 | |
| Remaining Properties | 858 | 402 | 38 | 3,267 | 1,842 | - | 577 | 674 | 20,672 | 4,695 | |
| United States | |||||||||||
| Eagle Ford | - | 56,062 | 17,303 | 98,609 | 89,800 | - | 58,122 | 15,902 | 79,722 | 87,311 | |
| Total | 42,759 | 69,843 | 19,836 | 132,175 | 154,468 | 35,204 | 75,763 | 18,004 | 129,780 | 150,600 | |
| Nine Months Ended September 30, 2024 | Nine Months Ended September 30, 2023 | ||||||||||
| Heavy Crude Oil (bbl/d) | Light and Medium Crude Oil (bbl/d) | NGL (bbl/d) | Natural Gas (Mcf/d) | Oil Equivalent (boe/d) | Heavy Crude Oil (bbl/d) | Light and Medium Crude Oil (bbl/d) | NGL (bbl/d) | Natural Gas (Mcf/d) | Oil Equivalent (boe/d) | ||
| Canada - Heavy | |||||||||||
| Peace River | 9,206 | 10 | 41 | 10,931 | 11,079 | 10,113 | 9 | 49 | 11,488 | 12,086 | |
| Lloydminster | 13,211 | 16 | - | 1,566 | 13,488 | 11,554 | 18 | - | 1,249 | 11,780 | |
| Peavine | 19,211 | - | - | - | 19,211 | 12,409 | - | - | - | 12,409 | |
| Canada - Light | |||||||||||
| Viking | - | 8,881 | 185 | 10,264 | 10,776 | - | 13,991 | 210 | 11,915 | 16,186 | |
| Duvernay | - | 2,782 | 1,892 | 6,291 | 5,723 | - | 1,573 | 881 | 2,860 | 2,931 | |
| Remaining Properties | 714 | 434 | 373 | 10,110 | 3,206 | - | 631 | 664 | 19,565 | 4,556 | |
| United States | |||||||||||
| Eagle Ford | - | 55,522 | 17,276 | 100,907 | 89,616 | - | 31,528 | 9,514 | 49,710 | 49,327 | |
| Total | 42,342 | 67,645 | 19,767 | 140,069 | 153,099 | 34,076 | 47,750 | 11,318 | 96,787 | 109,275 | |
Baytex Energy Corp.
Baytex Energy Corp. is an energy company with headquarters based in Calgary, Alberta and offices in Houston, Texas. The Company is engaged in the acquisition, development and production of crude oil and natural gas in the Western Canadian Sedimentary Basin and in the Eagle Ford in the United States. Baytex's common shares trade on the Toronto Stock Exchange and the New York Stock Exchange under the symbol BTE.
For further information about Baytex, please visit our website at www.baytexenergy.com or contact:
Brian Ector, Senior Vice President, Capital Markets & Investor Relations
Toll Free Number: 1-800-524-5521
Email: [email protected]
To view the source version of this press release, please visit https://www.newsfilecorp.com/release/228483