Rok Resources Inc. press release
Baytex Announces Second Quarter 2023 Results
TSXV - TSX Venture Exchange · Oil · Natural Gas · Natural Gas Liquids · Lithium · Canada
Calgary, Alberta--(Newsfile Corp. - July 27, 2023) - Baytex Energy Corp. (TSX: BTE) (NYSE: BTE) ("Baytex") reports its operating and financial results for the three and six months ended June 30, 2023 (all amounts are in Canadian dollars unless otherwise noted).
"We continue to execute on our base business, and following the Ranger transaction, have emerged as a well-capitalized and diversified North American exploration and production company. We have a strong portfolio of high-quality oil weighted assets in Western Canada and the Eagle Ford shale in Texas and we are poised to deliver a powerful combination of free cash flow and increased shareholder returns on a per-share basis. We have initiated our share buyback program (repurchased 4.7 million shares to-date in July) and declared a quarterly dividend of $0.0225 per share ($0.09 per share annualized). We are committed to operational excellence and delivering long-term value and enhanced shareholder returns," commented Eric T. Greager, President and Chief Executive Officer.
Highlights
Completed the acquisition of Ranger Oil Corporation ("Ranger") on June 20, 2023. Generated production of 89,71 boe/d (86% oil and NGLs) in Q2/2023. Reported cash flows from operating activities of $192 million ($0.33 per basic share) in Q2/2023. Delivered adjusted funds flow(1) of $274 million ($0.47 per basic share) in Q2/2023. Generated free cash flow(2)of $96 million ($0.17 per basic share) in Q2/2023. Exploration and development expenditures totaled $171 million in Q2/2023, consistent with our full-year plan. Completed six-well Duvernay program with wells onstream in Q3/2023. New heavy oil exploration success in Waseca near Cold Lake, Alberta.
On June 20, 2023, we closed the acquisition of Ranger, adding quality scale in the Eagle Ford and reinforcing a resilient and sustainable business. The total consideration paid by Baytex, including assumption of net debt(1), was US$2.4 billion (C$3.2 billion). Under the terms of the agreement, Ranger shareholders received 7.49 Baytex shares plus US$13.31 cash for each share of Ranger common stock. Our second quarter results include 11 days of operations from Ranger.
In conjunction with closing of the acquisition, we increased our direct shareholder returns to 50% of free cash flow(2)which will allow 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 debt reduction.
On June 23, 2023, we renewed our Normal Course Issuer Bid with the Toronto Stock Exchange for a share buyback program for up to 10% of our public float. Through July 26, 2023, we have repurchased 4.7 million common shares at an average price of $4.59 per share.
The Board of Directors has declared a quarterly cash dividend of $0.0225 per share to be paid on October 2, 2023 for shareholders of record on September 15, 2023(3).
(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. (3) Refer to the dividend advisory section in this press release for further information.
2023 Outlook
Following the Ranger transaction, Baytex has emerged as a well-capitalized, diversified oil-weighted North American E&P company with a strong free cash flow profile. Based on the forward strip(1), we expect to generate over $400 million of free cash flow(2)in the second half of 2023, and approximately $500 million of free cash flow for the full-year 2023.
For 2023, we continue to forecast exploration and development expenditures of $1,005 to $1,045 million, which are expected to generate an average production rate of 120,500 to 122,500 boe/d. For the second half of 2023, we expect production to average 153,000 to 157,000 boe/d. Our production mix for the second half of 2023 is forecast to be 84% oil and NGLs (50% light oil, 22% heavy oil and 12% NGLs) and 16% natural gas.
The following table summarizes our 2023 guidance for production and exploration and development expenditures.
| | | H1/2023 Actual | | | H2/2023 Guidance | | | 2023 Guidance | | Production (boe/d) | | 88,269 (3) | | | 153,000-157,000 | | | 120,500-122,500 | | Exploration and development expenditures ($ millions) | $ | 404 | | $ | 601-$641 | | $ | 1,005-$1,045 |
We have updated our full-year 2023 cost assumptions to reflect the Ranger acquisition. Guidance for unit operating expenses decreased by 13% to reflect the lower cost structure of the Ranger asset base, while unit general and administrative expenses increased by 10% to reflect costs associated with Ranger personnel, and interest expense is higher due to the incremental debt associated with the Ranger acquisition as well as higher interest rates on the credit facility due to the rising interest rate environment.
The following table summarizes our 2023 guidance for expenses, leasing expenditures and asset retirement obligations.
| | 2023 Original Guidance(4) | 2023 Revised Guidance (5) | | Expenses: | | | | Average royalty rate (2) | 20.0 - 22.0% | 21.0 - 22.0% | | Operating (6) | $14.00 - $14.75/boe | $12.25 - $12.75/boe | | Transportation (6) | $1.90 - $2.10/boe | $2.00 - $2.10/boe | | General and administrative (6) | $52 million ($1.63/boe) | $80 million ($1.80/boe) | | Interest (6) | $65 million ($2.04/boe) | $150 million ($3.38/boe) | | | | | | Leasing expenditures | $4 million | $13 million | | Asset retirement obligations | $25 million | $25 million |
(1) H2/2023 commodity prices: WTI - US$75/bbl, WCS differential to WTI - US$14/bbl, NYMEX Gas - US$2.85/MMbtu; Exchange Rate (CAD/USD) - 1.32. (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) As announced on December 7, 2022. (5) 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.
| | | Three Months Ended | | | Six Months Ended | | | | | | | | | | | | | June 30, 2023 | | | March 31, 2023 | | | June 30, 2022 | | | June 30, 2023 | | | June 30, 2022 | | FINANCIAL (thousands of Canadian dollars, except per common share amounts) | | | | | | | | | | | | | | | | Petroleum and natural gas sales | $ | 598,760 | | $ | 555,336 | | $ | 854,169 | | $ | 1,154,096 | | $ | 1,527,994 | | Adjusted funds flow(1) | | 273,590 | | | 236,989 | | | 345,704 | | | 510,579 | | | 625,311 | | Per share - basic | | 0.47 | | | 0.43 | | | 0.61 | | | 0.90 | | | 1.10 | | Per share - diluted | | 0.47 | | | 0.43 | | | 0.60 | | | 0.90 | | | 1.10 | | Free cash flow (2) | | 96,313 | | | (1,918) | | | 245,316 | | | 94,395 | | | 366,634 | | Per share - basic | | 0.17 | | | - | | | 0.43 | | | 0.17 | | | 0.65 | | Per share - diluted | | 0.16 | | | - | | | 0.43 | | | 0.17 | | | 0.64 | | Cash flows from operating activities | | 192,308 | | | 184,938 | | | 360,034 | | | 377,246 | | | 559,008 | | Per share - basic | | 0.33 | | | 0.34 | | | 0.63 | | | 0.67 | | | 0.99 | | Per share - diluted | | 0.33 | | | 0.34 | | | 0.63 | | | 0.66 | | | 0.98 | | Net income | | 213,603 | | | 51,441 | | | 180,972 | | | 265,044 | | | 237,830 | | Per share - basic | | 0.37 | | | 0.09 | | | 0.32 | | | 0.47 | | | 0.42 | | Per share - diluted | | 0.36 | | | 0.09 | | | 0.32 | | | 0.47 | | | 0.42 | | | | | | | | | | | | | | | | | | Capital Expenditures | | | | | | | | | | | | | | | | Exploration and development expenditures | $ | 170,704 | | $ | 233,626 | | $ | 96,633 | | $ | 404,330 | | $ | 250,455 | | Acquisitions and divestitures | | (112) | | | 271 | | | 194 | | | 159 | | | 226 | | Total oil and natural gas capital expenditures | $ | 170,592 | | $ | 233,897 | | $ | 96,827 | | $ | 404,489 | | $ | 250,681 | | | | | | | | | | | | | | | | | | Net Debt | | | | | | | | | | | | | | | | Credit facilities | $ | 986,903 | | $ | 409,653 | | $ | 496,917 | | $ | 986,903 | | $ | 496,917 | | Long-term notes | | 1,601,468 | | | 554,351 | | | 643,600 | | | 1,601,468 | | | 643,600 | | Long-term debt | | 2,588,371 | | | 964,004 | | | 1,140,517 | | | 2,588,371 | | | 1,140,517 | | Working capital | | 226,473 | | | 31,166 | | | (17,220) | | | 226,473 | | | (17,220) | | Net debt(1) | $ | 2,814,844 | | $ | 995,170 | | $ | 1,123,297 | | $ | 2,814,844 | | $ | 1,123,297 | | | | | | | | | | | | | | | | | | Shares Outstanding - basic(thousands) | | | | | | | | | | | | | | | | Weighted average | | 583,365 | | | 545,062 | | | 566,997 | | | 564,319 | | | 566,262 | | End of period | | 862,192 | | | 545,553 | | | 560,139 | | | 862,192 | | | 560,139 | | | | | | | | | | | | | | | | | | BENCHMARK PRICES | | | | | | | | | | | | | | | | Crude oil | | | | | | | | | | | | | | | | WTI (US$/bbl) | $ | 73.78 | | $ | 76.13 | | $ | 108.41 | | $ | 74.96 | | $ | 101.35 | | MEH oil (US$/bbl) | | 75.01 | | | 77.42 | | | 112.41 | | | 76.22 | | | 104.56 | | MEH oil differential to WTI (US$/bbl) | | 1.23 | | | 1.29 | | | 4.00 | | | 1.26 | | | 3.21 | | Edmonton par ($/bbl) | | 95.13 | | | 99.04 | | | 137.79 | | | 97.09 | | | 126.72 | | Edmonton par differential to WTI (US$/bbl) | | (2.95) | | | (2.88) | | | (0.47) | | | (2.91) | | | (1.68) | | WCS heavy oil ($/bbl) | | 78.85 | | | 69.44 | | | 122.05 | | | 74.16 | | | 111.48 | | WCS differential to WTI (US$/bbl) | | (15.07) | | | (24.77) | | | (12.80) | | | (19.92) | | | (13.67) | | Natural gas | | | | | | | | | | | | | | | | NYMEX (US$/mmbtu) | $ | 2.10 | | $ | 3.42 | | $ | 7.17 | | $ | 2.76 | | $ | 6.06 | | AECO ($/mcf) | | 2.35 | | | 4.34 | | | 6.27 | | | 3.34 | | | 5.43 | | | | | | | | | | | | | | | | | | CAD/USD average exchange rate | | 1.3431 | | | 1.3520 | | | 1.2766 | | | 1.3475 | | | 1.2714 |
| | | Three Months Ended | | | Six Months Ended | | | | | | | | | | | | | June 30, 2023 | | | March 31, 2023 | | | June 30, 2022 | | | June 30, 2023 | | | June 30, 2022 | | OPERATING | | | | | | | | | | | | | | | | Daily Production | | | | | | | | | | | | | | | | Light oil and condensate (bbl/d) | | 35,322 | | | 31,678 | | | 33,007 | | | 33,510 | | | 33,533 | | Heavy oil (bbl/d) | | 32,821 | | | 34,191 | | | 28,586 | | | 33,502 | | | 26,921 | | NGL (bbl/d) | | 8,620 | | | 7,213 | | | 7,468 | | | 7,920 | | | 7,552 | | Total liquids (bbl/d) | | 76,763 | | | 73,082 | | | 69,061 | | | 74,932 | | | 68,006 | | Natural gas (mcf/d) | | 77,989 | | | 82,066 | | | 84,169 | | | 80,017 | | | 83,873 | | Oil equivalent (boe/d @ 6:1) (3) | | 89,761 | | | 86,760 | | | 83,090 | | | 88,269 | | | 81,985 | | | | | | | | | | | | | | | | | | Netback (thousands of Canadian dollars) | | | | | | | | | | | | | | | | Total sales, net of blending and other expense (2) | $ | 545,765 | | $ | 495,655 | | $ | 797,274 | | $ | 1,041,420 | | $ | 1,429,659 | | Royalties | | (107,920) | | | (93,253) | | | (171,559) | | | (201,173) | | | (294,279) | | Operating expense | | (119,438) | | | (112,408) | | | (107,426) | | | (231,846) | | | (208,192) | | Transportation expense | | (14,574) | | | (17,005) | | | (11,758) | | | (31,579) | | | (20,973) | | Operating netback(2) | $ | 303,833 | | $ | 272,989 | | $ | 506,531 | | $ | 576,822 | | $ | 906,215 | | General and administrative | | (15,240) | | | (11,734) | | | (11,640) | | | (26,974) | | | (23,322) | | Cash financing and interest | | (28,255) | | | (18,375) | | | (20,474) | | | (46,630) | | | (40,901) | | Realized financial derivatives gain (loss) | | 16,365 | | | 5,415 | | | (124,042) | | | 21,780 | | | (208,408) | | Other (4) | | (3,113) | | | (11,306) | | | (4,671) | | | (14,419) | | | (8,273) | | Adjusted funds flow (1) | $ | 273,590 | | $ | 236,989 | | $ | 345,704 | | $ | 510,579 | | $ | 625,311 | | | | | | | | | | | | | | | | | | Netback (per boe) (5) | | | | | | | | | | | | | | | | Total sales, net of blending and other expense (2) | $ | 66.82 | | $ | 63.48 | | $ | 105.44 | | $ | 65.18 | | $ | 96.34 | | Royalties | | (13.21) | | | (11.94) | | | (22.69) | | | (12.59) | | | (19.83) | | Operating expense | | (14.62) | | | (14.40) | | | (14.21) | | | (14.51) | | | (14.03) | | Transportation expense | | (1.78) | | | (2.18) | | | (1.56) | | | (1.98) | | | (1.41) | | Operating netback (2) | $ | 37.21 | | $ | 34.96 | | $ | 66.98 | | $ | 36.10 | | $ | 61.07 | | General and administrative | | (1.87) | | | (1.50) | | | (1.54) | | | (1.69) | | | (1.57) | | Cash financing and interest | | (3.46) | | | (2.35) | | | (2.71) | | | (2.92) | | | (2.76) | | Realized financial derivatives gain (loss) | | 2.00 | | | 0.69 | | | (16.41) | | | 1.36 | | | (14.04) | | Other (4) | | (0.39) | | | (1.45) | | | (0.60) | | | (0.89) | | | (0.56) | | Adjusted funds flow (1) | $ | 33.49 | | $ | 30.35 | | $ | 45.72 | | $ | 31.96 | | $ | 42.14 |
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 cash share-based compensation. Refer to the Q2/2023 MD&A for further information on these amounts. (5) 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.
Q2/2023 Results
We continue to execute on our base business. Production In Q2/2023 was 89,761 boe/d (86% oil and NGLs), which includes production from Ranger for the 11 days following closing of the acquisition. Production exceeded the high end of our Q2/2023 guidance range of 88,500 to 89,000 boe/d due to the timing of operated Eagle Ford wells brought onstream late in the second quarter.
Production in Q2/2023 was reduced by approximately 4,500 boe/d due to the temporary curtailment of production caused by wildfires in Alberta. For the month of July, we expect production to be curtailed by approximately 2,000 boe/d. Wildfires continue to burn in northwest Alberta and we could see further interruptions through the summer and into the fall. We are incredibly proud of how our personnel have responded with sound, safety-focused decision making.
We delivered adjusted funds flow(1)of $274 million ($0.47 per basic share) and net income of $214 million ($0.37 per basic share) in Q2/2023. Exploration and development expenditures totaled $171 million in Q2/2023 and we brought 43 (34.9 net) wells onstream. During the second quarter, we generated free cash flow(2)of $96 million ($0.17 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 net acres in the crude oil window and on-trend with our non-operated position in the Karnes Trough. The transaction increased our exposure to premium U.S. Gulf Coast pricing and included substantial infrastructure in place with low operating and transportation costs.
Production in the Eagle Ford averaged 33,887 boe/d (82% oil and NGLs) during Q2/2023, and includes 11 days of production from the Ranger assets. During the second quarter, we brought 13 (4.9 net) wells onstream, including 2 (2.0 net) operated wells. We expect to bring approximately 24 net operated wells and 8 net non-operated wells to sales in H2/2023.
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 the potential for strong economics and organic growth.
Our light oil production in Canada averaged 17,029 boe/d (86% oil and NGLs) during Q2/2023. In the Viking, we brought 28 (28.0 net) wells onstream in Q2/2023 and expect to bring another 46 net wells onstream in H2/2023. In the Pembina Duvernay, we commenced completion activities for the six wells (two-three well pads) drilled this year. Our completions and facility execution tracked ahead of plan, which allowed for an acceleration of the on-streaming of wells. Four of the six wells are in the early stages of flow back and are tracking to type curve initial rate expectations. The remaining two wells are expected to be onstream by mid-August.
Heavy Oil - Canada
Our heavy oil production and development in Canada occurs within the Bluesky and Spirit River (Clearwater) formations in the Peace River area of northwest Alberta and the Mannville group of formations in the greater Lloydminster region of east central Alberta and west central Saskatchewan. Our heavy oil business includes the use of innovative multi-lateral horizontal drilling with strong capital efficiencies. The core of our Clearwater play is located on the Peavine Métis settlement.
Our heavy oil assets produced a combined 34,955 boe/d (94% oil and NGLs) during Q2/2023. We brought onstream two net wells during the second quarter, which typically has lower activity due to spring breakup. Our heavy oil development program has ramped up in the third quarter with four rigs running, two at Peavine, one at Peace River and one at Lloydminster. In H2/2023, we expect to bring 40 net heavy oil wells onstream, 19 at Peavine, 18 at Lloydminster and 3 at Peace River.
In Q1/2023 we successfully drilled a six-leg Upper Waseca multi-lateral horizontal exploration well at Cold Lake, Alberta. The well was brought onstream in April and achieved a 30-day initial production rate of 165 bbl/d of 12.5° API crude oil. The Waseca formation is analogous to Clearwater reservoirs across the fairway and is highly amenable to open-hole development which drives strong returns and capital efficiencies. We are encouraged by this initial test result and are planning 3 follow-up wells in the second half of 2023, including a Lower Waseca test. We hold 20 prospective sections across the play. In addition, we will follow up our successful Q4/2022 Clearwater test well at Morinville, Alberta with two additional wells in the second half of 2023.
(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.