Rok Resources Inc. press release
Baytex Announces Third Quarter 2023 Results
TSXV - TSX Venture Exchange · Oil · Natural Gas · Natural Gas Liquids · Lithium · Canada
Calgary, Alberta--(Newsfile Corp. - November 2, 2023) - Baytex Energy Corp. (TSX: BTE) (NYSE: BTE) ("Baytex") reports its operating and financial results for the three and nine months ended September 30, 2023 (all amounts are in Canadian dollars unless otherwise noted).
"Our third quarter results represent the first full quarter of combined operations following the Ranger acquisition and demonstrate the strength of our diversified North American oil-weighted portfolio. The integration has progressed extremely well and we have delivered strong results from Western Canada and the Eagle Ford in Texas. We are building momentum with current production exceeding 155,000 boe/d (84% oil and NGLs). Currently, we expect to generate free cash flow of approximately $400 million in Q4/2023 and $650 million for this year. As a result of this strong free cash flow, we have increased the pace of our share buyback program during the fourth quarter. We are also excited to announce two new land extensions at Peavine and Cold Lake as we continue to leverage our heavy oil expertise and recent exploration successes," commented Eric T. Greager, President and Chief Executive Officer.
Highlights
Generated production of 150,600 boe/d (85% oil and NGLs) in Q3/2023. Reported cash flows from operating activities of $444 million ($0.52 per basic share) in Q3/2023. Delivered adjusted funds flow(1) of $582 million ($0.68 per basic share) in Q3/2023. Generated free cash flow(2)of $158 million ($0.19 per basic share) in Q3/2023. Exploration and development expenditures totaled $409 million in Q3/2023, consistent with our full-year plan. Repurchased 16.8 million common shares in Q3/2023, representing 2.0% of our shares outstanding, at an average price of $5.29 per share. Paid a quarterly cash dividend of $0.0225 per share ($0.09 per share annualized) on October 2, 2023. Brought 13 operated Eagle Ford wells onstream in Q3/2023, of which seven wells from three pads generated average 30-day initial production rates of approximately 2,000 boe/d (65% oil and NGLs) per well. Executed a two-rig drilling program at Peavine and brought 14 Clearwater wells onstream. Production at Peavine averaged 13,821 bbl/d in Q3/2023, up 69% from Q3/2022. Production during September averaged 16,400 bbl/d. Continued commercialization program in our Pembina Duvernay with six-well program delivering strong results. Expanded our heavy oil development fairway through two land extensions, including a 10-section agreement with the Peavine Métis settlement adjacent to our existing 80 section land position and a farm-in on 17.75 sections of land prospective for Mannville development near Cold Lake in northeast Alberta.
Quarterly Dividend
The Board of Directors declared a quarterly cash dividend of $0.0225 per share to be paid on January 2, 2024 for shareholders of record on December 15, 2023.
(1) Capital management measure. Refer to the Specified Financial Measures 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.
2023 Outlook
We continue to execute our 2023 plan and anticipate full-year 2023 production of 121,500 to 122,000 boe/d (previous guidance range of 120,500 to 122,500 boe/d). Production during the fourth quarter is expected to average 158,000 to 160,000 boe/d, 84% weighted to oil and NGLs (47% light oil, 24% heavy oil and 13% NGLs) and 16% natural gas. We anticipate full-year 2023 exploration and development expenditures of approximately $1,035 million, consistent with our previous guidance range of $1,005 to $1,045 million. Based on the forward strip for the balance of 2023(1), we expect to generate free cash flow(2) of approximately $400 million ($0.48 per basic share) in Q4/2023 and $650 million ($0.92 per basic share) for the full-year 2023.
The following table summarizes our 2023 guidance for production and exploration and development expenditures.
| | H1/2023 Actual | Q3/2023 Actual | Q4/2023 Estimate | 2023 Guidance | | Production (boe/d) | 88,269 (3) | 150,600(4) | 158,000 - 160,000 | 121,500 - 122,000 | | Exploration and development expenditures ($ millions) | $404 | $409 | ~$222 | ~$1,035 |
The following table summarizes our 2023 guidance for expenses, leasing expenditures and asset retirement obligations.
Guidance for unit operating expenses moves to the high end of our previous range to reflect incremental base optimization and workover activity in the Eagle Ford. Guidance for interest expense is higher due largely to the impact of a strengthening U.S. dollar, relative to the Canadian dollar, on our U.S. dollar denominated debt.
| | | 2023 Guidance(5) | | 2023 Revised Guidance | | Expenses: | | | | | | Average royalty rate (2) | | 21.0 - 22.0% | | no change | | Operating (6) | | $12.25 - $12.75/boe | | ~ $12.75/boe | | Transportation (6) | | $2.00 - $2.10/boe | | ~ $2.10/boe | | General and administrative (6) | | $80 million ($1.80/boe) | | no change | | Interest (6) | | $150 million ($3.38/boe) | | $156 million ($3.50/boe) | | Leasing expenditures | | $13 million | | no change | | Asset retirement obligations | | $25 million | | no change |
Our 2024 capital budget is expected to be released in early December following approval by our Board of Directors.
Shareholder Returns
In conjunction with closing the Ranger Oil Corporation ("Ranger") transaction, we increased direct shareholder returns to 50% of free cash flow(2) which has allowed us to increase the value of our share buyback program and introduce a dividend. The remainder of our free cash flow continues to be allocated to the balance sheet.
Our normal course issuer bid allows for the purchase of up to 68.4 million common shares during the 12-month period ending June 28, 2024. During the third quarter, we repurchased 16.8 million common shares for $89 million, representing 2.0% of our shares outstanding, at an average price of $5.29 per share. Through October 31, 2023, we repurchased 28.1 million common shares for $155.0 million, representing 3.3% of our shares outstanding, at an average price of $5.51 per share. In addition, we paid an initial quarterly cash dividend of $0.0225 per share ($0.09 per share annualized) on October 2, 2023.
As of September 30, 2023, our total debt(7)was $2.7 billion, representing a total debt to EBITDA(7)ratio (Q3/2023 annualized) of 1.1x. Our total debt at quarter-end increased relative to Q2/2023 due to the impact of a strengthening U.S. dollar, relative to the Canadian dollar, on our U.S. dollar denominated debt, and working capital adjustments. Based on current commodity prices and forecast free cash flow for the fourth quarter, we expect to exit 2023 with total debt of approximately $2.5 billion.
(1) Q4/2023 commodity prices: WTI - US$84/bbl, WCS differential to WTI - US$21/bbl, NYMEX Gas - US$3.00/MMbtu; Exchange Rate (CAD/USD) - 1.38. (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) H1/2023 actual production is comprised of 33,510 bbl/d of light crude oil and medium crude oil (including condensate), 33,502 bbl/d of heavy crude oil, 7,920 bbl/d of natural gas liquids and 80,017 mcf/d of conventional natural gas. (4) Q3/2023 actual production is comprised of 75,763 bbl/d of light crude oil and medium crude oil (including condensate), 35,204 bbl/d of heavy crude oil, 18,004 bbl/d of natural gas liquids and 129,780 mcf/d of conventional natural gas. (5) As announced on July 27, 2023. Includes Ranger from the closing date of the transaction (June 20, 2023). (6) Calculated as operating, transportation, general and administrative or cash interest expense divided by barrels of oil equivalent production volume for the applicable period. (7) Calculated in accordance with the amended credit facilities agreement which is available on SEDAR+ at www.sedarplus.com.
| | | Three Months Ended | | | Nine Months Ended | | | | | | | | | | | | | September 30, 2023 | | | June 30, 2023 | | | September 30, 2022 | | | September 30, 2023 | | | September 30, 2022 | | FINANCIAL (thousands of Canadian dollars, except per common share amounts) | | | | | | | | | | | | | | | | Petroleum and natural gas sales | $ | 1,163,010 | | $ | 598,760 | | $ | 712,065 | | $ | 2,317,106 | | $ | 2,240,059 | | Adjusted funds flow(1) | | 581,623 | | | 273,590 | | | 284,288 | | | 1,092,202 | | | 909,599 | | Per share - basic | | 0.68 | | | 0.47 | | | 0.51 | | | 1.65 | | | 1.62 | | Per share - diluted | | 0.68 | | | 0.47 | | | 0.51 | | | 1.64 | | | 1.60 | | Free cash flow (2) | | 158,440 | | | 96,313 | | | 111,568 | | | 252,835 | | | 478,202 | | Per share - basic | | 0.19 | | | 0.17 | | | 0.20 | | | 0.38 | | | 0.85 | | Per share - diluted | | 0.18 | | | 0.16 | | | 0.20 | | | 0.38 | | | 0.84 | | Cash flows from operating activities | | 444,033 | | | 192,308 | | | 310,423 | | | 821,279 | | | 869,431 | | Per share - basic | | 0.52 | | | 0.33 | | | 0.56 | | | 1.24 | | | 1.55 | | Per share - diluted | | 0.52 | | | 0.33 | | | 0.56 | | | 1.23 | | | 1.53 | | Net income | | 127,430 | | | 213,603 | | | 264,968 | | | 392,474 | | | 502,798 | | Per share - basic | | 0.15 | | | 0.37 | | | 0.48 | | | 0.59 | | | 0.89 | | Per share - diluted | | 0.15 | | | 0.36 | | | 0.47 | | | 0.59 | | | 0.89 | | Dividends declared | | 19,138 | | | - | | | - | | | 19,138 | | | - | | Per share | | 0.0225 | | | - | | | - | | | 0.0225 | | | - | | | | | | | | | | | | | | | | | | Capital Expenditures | | | | | | | | | | | | | | | | Exploration and development expenditures | $ | 409,191 | | $ | 170,704 | | $ | 167,453 | | $ | 813,521 | | $ | 417,908 | | Acquisitions and divestitures | | 4,051 | | | (112) | | | (25,460) | | | 4,210 | | | (25,234) | | Net oil and natural gas capital expenditures | $ | 413,242 | | $ | 170,592 | | $ | 141,993 | | $ | 817,731 | | $ | 392,674 | | | | | | | | | | | | | | | | | | Net Debt | | | | | | | | | | | | | | | | Credit facilities | $ | 1,046,756 | | $ | 986,903 | | $ | 450,051 | | $ | 1,046,756 | | $ | 450,051 | | Long-term notes | | 1,637,640 | | | 1,601,468 | | | 648,207 | | | 1,637,640 | | | 648,207 | | Total debt (3) | | 2,684,396 | | | 2,588,371 | | | 1,098,258 | | | 2,684,396 | | | 1,098,258 | | Working capital | | 139,952 | | | 226,473 | | | 15,301 | | | 139,952 | | | 15,301 | | Net debt (1) | $ | 2,824,348 | | $ | 2,814,844 | | $ | 1,113,559 | | $ | 2,824,348 | | $ | 1,113,559 | | | | | | | | | | | | | | | | | | Shares Outstanding - basic(thousands) | | | | | | | | | | | | | | | | Weighted average | | 855,300 | | | 583,365 | | | 553,409 | | | 662,379 | | | 561,931 | | End of period | | 845,360 | | | 862,192 | | | 547,615 | | | 845,360 | | | 547,615 | | | | | | | | | | | | | | | | | | BENCHMARK PRICES | | | | | | | | | | | | | | | | Crude oil | | | | | | | | | | | | | | | | WTI (US$/bbl) | $ | 82.26 | | $ | 73.78 | | $ | 91.56 | | $ | 77.39 | | $ | 98.09 | | MEH oil (US$/bbl) | | 84.10 | | | 75.01 | | | 96.15 | | | 78.84 | | | 101.76 | | MEH oil differential to WTI (US$/bbl) | | 1.84 | | | 1.23 | | | 4.59 | | | 1.45 | | | 3.67 | | Edmonton par ($/bbl) | | 107.93 | | | 95.13 | | | 116.79 | | | 100.70 | | | 123.41 | | Edmonton par differential to WTI (US$/bbl) | | (1.78) | | | (2.95) | | | (2.13) | | | (2.54) | | | (1.89) | | WCS heavy oil ($/bbl) | | 93.02 | | | 78.85 | | | 93.62 | | | 80.47 | | | 105.65 | | WCS differential to WTI (US$/bbl) | | (12.89) | | | (15.07) | | | (19.87) | | | (17.57) | | | (15.74) | | Natural gas | | | | | | | | | | | | | | | | NYMEX (US$/mmbtu) | $ | 2.55 | | $ | 2.10 | | $ | 8.20 | | $ | 2.69 | | $ | 6.77 | | AECO ($/mcf) | | 2.39 | | | 2.35 | | | 5.81 | | | 3.03 | | | 5.56 | | | | | | | | | | | | | | | | | | CAD/USD average exchange rate | | 1.3410 | | | 1.3431 | | | 1.3059 | | | 1.3453 | | | 1.2829 |
| | | Three Months Ended | | | Nine Months Ended | | | | | | | | | | | | | September 30, 2023 | | | June 30, 2023 | | | September 30, 2022 | | | September 30, 2023 | | | September 30, 2022 | | OPERATING | | | | | | | | | | | | | | | | Daily Production | | | | | | | | | | | | | | | | Light oil and condensate (bbl/d) | | 75,763 | | | 35,322 | | | 33,247 | | | 47,750 | | | 33,437 | | Heavy oil (bbl/d) | | 35,204 | | | 32,821 | | | 29,244 | | | 34,076 | | | 27,703 | | NGL (bbl/d) | | 18,004 | | | 8,620 | | | 7,536 | | | 11,318 | | | 7,547 | | Total liquids (bbl/d) | | 128,971 | | | 76,763 | | | 70,027 | | | 93,144 | | | 68,686 | | Natural gas (mcf/d) | | 129,780 | | | 77,989 | | | 79,003 | | | 96,787 | | | 82,232 | | Oil equivalent (boe/d @ 6:1) (4) | | 150,600 | | | 89,761 | | | 83,194 | | | 109,275 | | | 82,392 | | | | | | | | | | | | | | | | | | Netback (thousands of Canadian dollars) | | | | | | | | | | | | | | | | Total sales, net of blending and other expense (2) | $ | 1,113,180 | | $ | 545,765 | | $ | 671,120 | | $ | 2,154,600 | | $ | 2,100,779 | | Royalties | | (240,049) | | | (107,920) | | | (146,994) | | | (441,222) | | | (441,273) | | Operating expense | | (174,119) | | | (119,438) | | | (110,139) | | | (405,965) | | | (318,331) | | Transportation expense | | (27,983) | | | (14,574) | | | (12,771) | | | (59,562) | | | (33,744) | | Operating netback(2) | $ | 671,029 | | $ | 303,833 | | $ | 401,216 | | $ | 1,247,851 | | $ | 1,307,431 | | General and administrative | | (20,536) | | | (15,240) | | | (12,003) | | | (47,510) | | | (35,325) | | Cash financing and interest | | (56,495) | | | (28,255) | | | (19,774) | | | (103,125) | | | (60,675) | | Realized financial derivatives gain (loss) | | 2,055 | | | 16,365 | | | (76,408) | | | 23,835 | | | (284,816) | | Other (5) | | (14,430) | | | (3,113) | | | (8,743) | | | (28,849) | | | (17,016) | | Adjusted funds flow (1) | $ | 581,623 | | $ | 273,590 | | $ | 284,288 | | $ | 1,092,202 | | $ | 909,599 | | | | | | | | | | | | | | | | | | Netback (per boe) (6) | | | | | | | | | | | | | | | | Total sales, net of blending and other expense (2) | $ | 80.34 | | $ | 66.82 | | $ | 87.68 | | $ | 72.22 | | $ | 93.40 | | Royalties | | (17.33) | | | (13.21) | | | (19.21) | | | (14.79) | | | (19.62) | | Operating expense | | (12.57) | | | (14.62) | | | (14.39) | | | (13.61) | | | (14.15) | | Transportation expense | | (2.02) | | | (1.78) | | | (1.67) | | | (2.00) | | | (1.50) | | Operating netback (2) | $ | 48.42 | | $ | 37.21 | | $ | 52.41 | | $ | 41.82 | | $ | 58.13 | | General and administrative | | (1.48) | | | (1.87) | | | (1.57) | | | (1.59) | | | (1.57) | | Cash financing and interest | | (4.08) | | | (3.46) | | | (2.58) | | | (3.46) | | | (2.70) | | Realized financial derivatives gain (loss) | | 0.15 | | | 2.00 | | | (9.98) | | | 0.80 | | | (12.66) | | Other (4) | | (1.03) | | | (0.39) | | | (1.14) | | | (0.96) | | | (0.76) | | Adjusted funds flow (1) | $ | 41.98 | | $ | 33.49 | | $ | 37.14 | | $ | 36.61 | | $ | 40.44 |
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 the amended credit facilities agreement which is available on SEDAR+ at www.sedarplus.com. (4) 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. (5) 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 Q3/2023 MD&A for further information on these amounts. (6) Calculated as royalties, operating, transportation, general and administrative, cash financing and interest expense or realized financial derivatives loss divided by barrels of oil equivalent production volume for the applicable period.
Q3/2023 Results
Our third quarter results represent the first full quarter of operations following the acquisition of Ranger and demonstrate the strength of our diversified North American oil weighted portfolio. We continue to integrate the Ranger assets and execute our development program with strong results in Western Canada and the Eagle Ford.
Production during the third quarter averaged 150,600 boe/d (85% oil and NGLs). We delivered adjusted funds flow(1)of $582 million ($0.68 per basic share), cash flows from operating activities of $444 million ($0.52 per basic share) and net income of $127 million ($0.15 per basic share) in Q3/2023. Exploration and development expenditures totaled $409 million in Q3/2023 and we brought 105 (87.8 net) wells onstream. During the third quarter, we generated free cash flow(2)of $158 million ($0.19 per basic share).
Operating Results
Light Oil - United States
Our light oil assets in the United States are located in the liquids-rich Eagle Ford formation, in the Texas Gulf Coast Basin. The Ranger acquisition materially increased the scale of our Eagle Ford operations, adding 162,000 operated net acres in the crude oil window on-trend with our non-operated position in the Karnes Trough. The transaction increased our exposure to premium U.S. Gulf Coast pricing and includes substantial infrastructure in place with low operating and transportation costs.
Production in the Eagle Ford averaged 87,311 boe/d (85% oil and NGLs) during Q3/2023. During the third quarter, we brought 36 (21.3 net) wells onstream, including 13 (12.9 net) operated wells. The third quarter program reflects strong results across the black oil and condensate thermal maturity windows of the Lower Eagle Ford. The 13 operated wells generated an average 30-day initial production rate of 1,495 boe/d (78% oil and NGLs) per well (ranging from 769 boe/d to 2,355 boe/d). Seven wells from three pads (Bloodstone, Bubinga and Hickory) generated an average 30-day initial production rate of 2,000 boe/d (65% oil and NGLs) per well.
Given the timing of on-streaming wells, production in the Eagle Ford increased to over 92,000 boe/d in September. In addition to delivering strong results, we remain focused on base optimization and continued strong drilling and completion performance.
Light Oil - Canada
Our light oil production and development in Canada occurs from the Viking formation in west-central Saskatchewan and east-central Alberta, and the Duvernay formation in the Pembina area of central Alberta. The Viking is a shallow and highly repeatable light oil resource play with some of the highest operating netbacks in North America. Our Pembina Duvernay light oil assets are in the demonstration stage of commerciality and offer high operating netbacks, with strong economics and the potential for significant organic growth.
Our light oil production in Canada averaged 21,088 boe/d (87% oil and NGLs) during Q3/2023. In the Viking, we brought 38 (35.5 net) wells onstream in Q3/2023. In the Pembina Duvernay, commercialization continued with our six-well program (two-three well pads) delivering strong results with production increasing to over 7,500 boe/d in September (up from 2,000 boe/d in H1/2023). The six wells generated average production rates of approximately 950 boe/d (89% oil and NGLs) in September (ranging from 790 boe/d to 1,080 boe/d) and continue to track to type curve expectations. The 2023 program has advanced our understanding of the reservoir as we continue to progress this light oil resource play.