Baytex Announces Fourth Quarter and Full Year 2024 Financial and Operating Results and Year End Reserves

2025-03-04

NYSE - New York Stock Exchange · Oil · Natural Gas · Natural Gas Liquids · Canada

Calgary, Alberta--(Newsfile Corp. - March 4, 2025) - Baytex Energy Corp. (TSX: BTE) (NYSE: BTE) ("Baytex") reports its operating and financial results for the three months and year ended December 31, 2024 (all amounts are in Canadian dollars unless otherwise noted).

"Our strong 2024 results speak to our disciplined, returns-based capital allocation philosophy that delivers increased per-share returns. In 2024, we generated 10% production per share growth and grew reserves per-share across all reserves categories. We executed our capital program on budget, generated meaningful free cash flow and returned $290 million to shareholders through our buyback program and quarterly dividend. For 2025, we will continue to prioritize free cash flow and shareholder returns," commented Eric T. Greager, President and Chief Executive Officer.

2024 Highlights

Reported cash flows from operating activities of $469 million ($0.60 per basic share) in Q4/2024 and $1,908 million ($2.38 per basic share) for 2024.

Increased production per basic share by 10% in 2024, compared to 2023. Production for the full-year 2024 averaged 153,048 boe/d (85% oil and NGL), compared to 122,154 boe/d in 2023 (85% oil and NGL). Production in Q4/2024 averaged 152,894 boe/d (84% oil and NGL).

Delivered adjusted funds flow(1) of $462 million ($0.59 per basic share) in Q4/2024 and $1,957 million ($2.44 per basic share) for 2024.

Generated free cash flow(2)of $255 million ($0.33 per basic share) in Q4/2024 and $656 million ($0.82 per basic share) for 2024.

Returned $290 million to shareholders in 2024 through our share buyback program and dividend. We repurchased 48.4 million common shares for $218 million, representing 6% of our shares outstanding. In addition, we declared four quarterly dividends of $0.0225 per share, totaling $72 million.

Improved our cash cost structure (operating, transportation, and general & administrative expenses) in 2024 by 5% on a boe basis, as compared to 2023.

Reduced net debt(1)by 5% in 2024 (13% in U.S. dollars) and maintained balance sheet strength with a total debt to EBITDA ratio(3)of 1.1x.

Reserves Highlights (4)

Achieved strong per-share growth and reserves replacement across all three reserves categories, proved developed producing ("PDP"), proved ("1P") and proved plus probable ("2P").

Increased PDP reserves per share by 8% and 1P and 2P reserves per share by 6%. PDP reserves total 187 MMboe, 1P reserves total 408 MMboe and 2P reserves total 660 MMboe.

Replaced 102% of production on a 1P basis and 101% of production on a 2P basis, excluding acquisition and divestiture activity.

Generated a strong PDP recycle ratio of 1.9x and a 1P and 2P recycle ratio of 2.7x based on a 2024 operating netback(2)of $40.67/boe, reflective of the efficiency of our capital program and high netback oil-weighted portfolio.

Increased our net asset value at year-end 2024, discounted at 10% before tax, 13% to $7.27 per share ($6.41 per share at year-end 2023). This is based on the estimated 2P reserves value, 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. (3)Ratio is calculated as total debt at December 31, 2024 divided by EBITDA for the twelve months ended December 31, 2024. Total debt and EBITDA are calculated in accordance with our amended credit facilities agreement which is available on SEDAR+ at www.sedarplus.ca. (4)Baytex's year-end 2024 reserves were evaluated by McDaniel & Associates Consultants Ltd. ("McDaniel"), an independent qualified reserves evaluator, in accordance with National Instrument 51-101 "Standards of Disclosure for Oil and Gas Activities" ("NI 51-101").

| | | Three Months Ended | | | Twelve Months Ended | | | | | | | | | | | | | | December 31, 2024 | | | September 30, 2024 | | | December 31, 2023 | | | December 31, 2024 | | | December 31, 2023 | | | FINANCIAL (thousands of Canadian dollars, except per common share amounts) | | | | | | | | | | | | | | | | | Petroleum and natural gas sales | $ | 1,017,017 | | $ | 1,074,623 | | $ | 1,065,515 | | $ | 4,208,955 | | $ | 3,382,621 | | | Adjusted funds flow (1) | | 461,886 | | | 537,947 | | | 502,148 | | | 1,956,518 | | | 1,594,350 | | | Per share - basic | | 0.59 | | | 0.68 | | | 0.60 | | | 2.44 | | | 2.26 | | | Per share - diluted | | 0.59 | | | 0.67 | | | 0.60 | | | 2.42 | | | 2.26 | | | Free cash flow (2) | | 254,838 | | | 220,159 | | | 290,785 | | | 655,582 | | | 543,620 | | | Per share - basic | | 0.33 | | | 0.28 | | | 0.35 | | | 0.82 | | | 0.77 | | | Per share - diluted | | 0.33 | | | 0.28 | | | 0.35 | | | 0.81 | | | 0.77 | | | Cash flows from operating activities | | 468,865 | | | 550,042 | | | 474,452 | | | 1,908,264 | | | 1,295,731 | | | Per share - basic | | 0.60 | | | 0.69 | | | 0.57 | | | 2.38 | | | 1.84 | | | Per share - diluted | | 0.60 | | | 0.69 | | | 0.57 | | | 2.36 | | | 1.84 | | | Net income (loss) | | (38,477 | ) | | 185,219 | | | (625,830 | ) | | 236,597 | | | (233,356 | ) | | Per share - basic | | (0.05 | ) | | 0.23 | | | (0.75 | ) | | 0.29 | | | (0.33 | ) | | Per share - diluted | | (0.05 | ) | | 0.23 | | | (0.75 | ) | | 0.29 | | | (0.33 | ) | | Dividends declared | | 17,598 | | | 17,732 | | | 18,381 | | | 71,985 | | | 37,519 | | | Per share | | 0.0225 | | | 0.0225 | | | 0.0225 | | | 0.090 | | | 0.045 | | | | | | | | | | | | | | | | | | | | Capital Expenditures | | | | | | | | | | | | | | | | | Exploration and development expenditures | $ | 198,177 | | $ | 306,332 | | $ | 199,214 | | $ | 1,256,633 | | $ | 1,012,787 | | | Acquisitions and (divestitures) | | (29,718 | ) | | (394 | ) | | (125,822 | ) | | 5,920 | | | (121,342 | ) | | Total oil and natural gas capital expenditures | $ | 168,459 | | $ | 305,938 | | $ | 73,392 | | $ | 1,262,553 | | $ | 891,445 | | | | | | | | | | | | | | | | | | | | Net Debt | | | | | | | | | | | | | | | | | Credit facilities | $ | 341,207 | | $ | 466,108 | | $ | 864,736 | | $ | 341,207 | | $ | 864,736 | | | Long-term notes | | 1,980,619 | | | 1,856,869 | | | 1,597,475 | | | 1,980,619 | | | 1,597,475 | | | Total debt (3) | | 2,321,826 | | | 2,322,977 | | | 2,462,211 | | | 2,321,826 | | | 2,462,211 | | | Working capital deficiency (2) | | 95,346 | | | 170,292 | | | 72,076 | | | 95,346 | | | 72,076 | | | Net debt(1) | $ | 2,417,172 | | $ | 2,493,269 | | $ | 2,534,287 | | $ | 2,417,172 | | $ | 2,534,287 | | | | | | | | | | | | | | | | | | | | Shares Outstanding - basic(thousands) | | | | | | | | | | | | | | | | | Weighted average | | 782,131 | | | 796,064 | | | 831,063 | | | 803,435 | | | 704,896 | | | End of period | | 773,590 | | | 787,328 | | | 821,681 | | | 773,590 | | | 821,681 | | | | | | | | | | | | | | | | | | | | BENCHMARK PRICES | | | | | | | | | | | | | | | | | Crude oil | | | | | | | | | | | | | | | | | WTI (US$/bbl) | $ | 70.27 | | $ | 75.10 | | $ | 78.32 | | $ | 75.72 | | $ | 77.62 | | | MEH oil (US$/bbl) | | 72.40 | | | 77.50 | | | 80.62 | | | 77.99 | | | 79.29 | | | MEH oil differential to WTI (US$/bbl) | | 2.13 | | | 2.40 | | | 2.30 | | | 2.27 | | | 1.67 | | | Edmonton par ($/bbl) | | 94.98 | | | 97.91 | | | 99.72 | | | 97.59 | | | 100.46 | | | Edmonton par differential to WTI (US$/bbl) | | (2.39 | ) | | (3.30 | ) | | (5.10 | ) | | (4.49 | ) | | (3.18 | ) | | WCS heavy oil ($/bbl) | | 80.77 | | | 83.98 | | | 76.86 | | | 83.56 | | | 79.58 | | | WCS differential to WTI (US$/bbl) | | (12.54 | ) | | (13.51 | ) | | (21.88 | ) | | (14.73 | ) | | (18.65 | ) | | Natural gas | | | | | | | | | | | | | | | | | NYMEX (US$/mmbtu) | $ | 2.79 | | $ | 2.16 | | $ | 2.88 | | $ | 2.27 | | $ | 2.74 | | | AECO ($/mcf) | | 1.46 | | | 0.81 | | | 2.66 | | | 1.44 | | | 2.93 | | | | | | | | | | | | | | | | | | | | CAD/USD average exchange rate | | 1.3992 | | | 1.3636 | | | 1.3619 | | | 1.3700 | | | 1.3495 | |

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 | | | Twelve Months Ended | | | | | | | | | | | | | | December 31, 2024 | | | September 30, 2024 | | | December 31, 2023 | | | December 31, 2024 | | | December 31, 2023 | | | OPERATING | | | | | | | | | | | | | | | | | Daily Production | | | | | | | | | | | | | | | | | Light oil and condensate (bbl/d) | | 64,661 | | | 69,843 | | | 70,124 | | | 66,894 | | | 53,389 | | | Heavy oil (bbl/d) | | 42,227 | | | 42,759 | | | 39,569 | | | 42,313 | | | 35,460 | | | NGL (bbl/d) | | 21,208 | | | 19,836 | | | 23,160 | | | 20,129 | | | 14,304 | | | Total liquids (bbl/d) | | 128,096 | | | 132,438 | | | 132,853 | | | 129,336 | | | 103,153 | | | Natural gas (mcf/d) | | 148,792 | | | 132,175 | | | 165,121 | | | 142,262 | | | 114,010 | | | Oil equivalent (boe/d @ 6:1) (1) | | 152,894 | | | 154,468 | | | 160,373 | | | 153,048 | | | 122,154 | | | | | | | | | | | | | | | | | | | | Netback (thousands of Canadian dollars) | | | | | | | | | | | | | | | | | Total sales, net of blending and other expense (2) | $ | 936,869 | | $ | 1,022,721 | | $ | 1,003,219 | | $ | 3,945,012 | | $ | 3,157,819 | | | Royalties | | (206,675 | ) | | (223,800 | ) | | (228,570 | ) | | (880,086 | ) | | (669,792 | ) | | Operating expense | | (145,690 | ) | | (167,119 | ) | | (164,873 | ) | | (653,949 | ) | | (570,839 | ) | | Transportation expense | | (33,110 | ) | | (36,883 | ) | | (29,744 | ) | | (133,142 | ) | | (89,306 | ) | | Operating netback(2) | $ | 551,394 | | $ | 594,919 | | $ | 580,032 | | $ | 2,277,835 | | $ | 1,827,882 | | | General and administrative | | (20,433 | ) | | (17,895 | ) | | (22,280 | ) | | (81,746 | ) | | (69,789 | ) | | Cash interest | | (48,769 | ) | | (50,109 | ) | | (56,698 | ) | | (206,104 | ) | | (159,823 | ) | | Realized financial derivatives (loss) gain | | (2,115 | ) | | 331 | | | 12,377 | | | 1,447 | | | 36,212 | | | Other (3) | | (18,191 | ) | | 10,701 | | | (11,283 | ) | | (34,914 | ) | | (40,132 | ) | | Adjusted funds flow (4) | $ | 461,886 | | $ | 537,947 | | $ | 502,148 | | $ | 1,956,518 | | $ | 1,594,350 | | | | | | | | | | | | | | | | | | | | Netback per boe(2) | | | | | | | | | | | | | | | | | Total sales, net of blending and other expense (2) | $ | 66.60 | | $ | 71.97 | | $ | 68.00 | | $ | 70.43 | | $ | 70.82 | | | Royalties (5) | | (14.69 | ) | | (15.75 | ) | | (15.49 | ) | | (15.71 | ) | | (15.02 | ) | | Operating expense (5) | | (10.36 | ) | | (11.76 | ) | | (11.17 | ) | | (11.67 | ) | | (12.80 | ) | | Transportation expense (5) | | (2.35 | ) | | (2.60 | ) | | (2.02 | ) | | (2.38 | ) | | (2.00 | ) | | Operating netback (2) | $ | 39.20 | | $ | 41.86 | | $ | 39.32 | | $ | 40.67 | | $ | 41.00 | | | General and administrative (5) | | (1.45 | ) | | (1.26 | ) | | (1.51 | ) | | (1.46 | ) | | (1.57 | ) | | Cash interest (5) | | (3.47 | ) | | (3.53 | ) | | (3.84 | ) | | (3.68 | ) | | (3.58 | ) | | Realized financial derivatives (loss) gain (5) | | (0.15 | ) | | 0.02 | | | 0.84 | | | 0.03 | | | 0.81 | | | Other (3) | | (1.29 | ) | | 0.76 | | | (0.78 | ) | | (0.63 | ) | | (0.90 | ) | | Adjusted funds flow (4) | $ | 32.84 | | $ | 37.85 | | $ | 34.03 | | $ | 34.93 | | $ | 35.76 | |

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 share-based compensation. Refer to the 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 expense, 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.

2025 Outlook

Baytex is a well-capitalized, North American oil-weighted producer with 60% of our production in the Eagle Ford in Texas and the balance in western Canada.

In 2025, the government of the United States of America announced tariffs on goods imported from Canada, including a 10% tariff on Canadian energy imports, effective March 4, 2025. We continue to monitor the impact of these tariffs and expect that our geographic diversification will provide a measure of insulation.

We are focused on disciplined capital allocation to prioritize free cash flow generation while maintaining a strong balance sheet. In the current commodity price environment this means moderating our growth profile and delivering stable crude oil production. We currently allocate approximately 50% of free cash flow(1)to the balance sheet and approximately 50% to shareholder returns, which includes a combination of share buybacks and quarterly dividend payments.

In 2025, we are targeting continued strong performance in the Eagle Ford, further progression of the Pembina Duvernay and capital efficient heavy oil development. We anticipate first quarter production of approximately 144,000 boe/d with volumes increasing over the balance of the year. During the first quarter, extremely cold temperatures across North America resulted in modest production disruptions across our operations. Our full year 2025 guidance is unchanged with exploration and development expenditures of $1.2 to $1.3 billion and production of 148,000 to 152,000 boe/d.

We expect to generate approximately $400 million of free cash flow in 2025 at US$70/bbl WTI. Based on our production profile and timing of capital expenditures, the majority of our free cash flow is expected to be generated in the second half of the year.

2024 Results

We delivered operating and financial results consistent with our full-year plan. Production and exploration and development expenditures were in line with full-year guidance and we improved our cash cost structure (operating, transportation, general & administrative expenses) by 5% on a boe basis, compared to 2023. Adjusted funds flow(2)totaled $2.0 billion ($2.44 per basic share) and we generated net income of $237 million ($0.29 per basic share).

We increased production per basic share by 10% in 2024, compared to 2023, with production averaging 153,048 boe/d (84% oil and NGL), up from 122,154 boe/d in 2023. Production in Q4/2024 averaged 152,894 boe/d (84% oil and NGL). Exploration and development expenditures totaled $1.26 billion in 2024 and we participated in the drilling of 290 (246.4 net) wells.

We generated free cash flow of $656 million ($0.82 per basic share) in 2024 and returned $290 million to shareholders through our share buyback program and dividend. We repurchased 48.4 million common shares for $218 million, representing 6% of our shares outstanding, at an average price of $4.50 per share. In addition, we declared four quarterly dividends of $0.0225 per share, totaling $72 million.

Over the last six quarters, we generated free cash flow of $1.1 billion and returned $550 million to shareholders through our share buyback program and dividend. We repurchased 88.9 million common shares for $440 million, representing 10% of our shares outstanding, at an average price of $4.95 per share. In addition, we declared six quarterly dividends of $0.0225 per share, totaling $110 million.

On December 20, 2024, we completed the divestiture of our Kerrobert thermal asset in southwest Saskatchewan for net proceeds of $41.5 million. Proceeds from the sale were applied against our credit facilities. Production from the assets at the time of the sale was approximately 2,000 bbl/d (100% heavy oil).

We reduced net debt(2)by 5% ($117 million) in 2024. Our strong free cash flow generation was significantly offset by the impact of a strengthening U.S. dollar, relative to the Canadian dollar, on our U.S. dollar denominated debt. In U.S. dollars, we reduced net debt by 13% (US$241 million). On an annual basis, a $0.05 CAD/USD change in the foreign exchange rate impacts our net debt by approximately $70 million.

(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.

Operations

In the Eagle Ford, production averaged 89,100 boe/d (81% oil and NGL) in 2024 and we brought onstream 64 net wells, including 51 net operated wells. Our development program was 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. We realized an 8% improvement in operated drilling and completion costs per completed lateral foot over 2023.

In the Eagle Ford, we expect to bring onstream 54 net wells in 2025, including 41 net operated wells. We intend to run a consistent two rig and one frac crew program for most of the year and are targeting a 7% improvement in operated drilling and completion costs per completed lateral foot compared to 2024.

In our Canadian light oil business unit, production averaged 16,701 boe/d (83% oil and NGL) in 2024. We made substantial strides in advancing our understanding of the Pembina Duvernay with production increasing 64% to 6,112 boe/d (82% oil and NGL) in 2024, compared to 2023. We brought onstream seven net wells in the Pembina Duvernay and 95 net wells in the the Viking. In 2025, we expect to bring onstream nine net wells in the Pembina Duvernay and 90 net wells in the Viking.

In our heavy oil business unit, production averaged 43,704 boe/d (95% oil and NGL) in 2024. Peavine continued to deliver top well results with production increasing 44% to 19,241 bbl/d (100% heavy oil) in 2024, compared to 2023. During 2024, we brought onstream 31 net Clearwater wells at Peavine, 9 net wells at Peace River and 40 net wells across the broader Mannville group in Lloydminster. In 2025, we expect to bring onstream 112 net heavy oil wells, including 33 net Clearwater wells at Peavine.

Subsequent to year-end, we acquired through an asset exchange, 44.5 net sections of land on the Peavine Métis settlement. The lands acquired are immediately adjacent to our existing 90-section acreage position.

Quarterly Dividend

The Board of Directors has declared a quarterly cash dividend of $0.0225 per share to be paid on April 1, 2025 for shareholders of record on March 14, 2025.

Year-end 2024 Reserves

Baytex's year-end 2024 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, 2025.