Baytex Announces First Quarter 2024 Results
Calgary, Alberta--(Newsfile Corp. - May 9, 2024) - Baytex Energy Corp. (TSX: BTE) (NYSE: BTE) ("Baytex") reports its operating and financial results for the three months ended March 31, 2024 (all amounts are in Canadian dollars unless otherwise noted).
"In the first quarter we safely and efficiently executed the largest exploration and development ("E&D") program in company history and delivered operating and financial results consistent with our full-year guidance. We expect to deliver substantial free cash flow and meaningful shareholder returns over the next three quarters. Our strong free cash flow profile reflects the efficiency of our E&D program, higher forecast production volumes for the remainder of the year and improved crude oil price realizations in Canada and the Eagle Ford. We are in a strong financial position supported by significant liquidity and a balanced debt maturity profile," commented Eric T. Greager, President and Chief Executive Officer.
Highlights
- Reported cash flows from operating activities of $384 million ($0.47 per basic share) in Q1/2024.
- Increased adjusted funds flow(1) per share by 21% to $424 million ($0.52 per basic share) in Q1/2024 compared to Q1/2023.
- Increased production per share by 15% in Q1/2024, compared to Q1/2023. Production in Q1/2024 averaged 150,620 boe/d (84% oil and NGL), consistent with our full-year plan.
- Executed a $413 million E&D program, the largest in company history which, at its peak, had 13 rigs running.
- Brought 19 operated Eagle Ford wells onstream in Q1/2024, including three Upper Eagle Ford wells and a successful Lower Eagle Ford refrac.
- Generated production from our Clearwater play at Peavine of 17,599 bbl/d in Q1/2024. Brought 12 wells onstream in Q1/2024 that generated an average 30-day initial production rate of 915 bbl/d per well.
- Completed the drilling of our seven-well Duvernay program with a 21% improvement in drilling days (spud to rig release) and a 10% improvement in drilling costs, compared to 2023.
- Continued development success at Morinville, Alberta (Clearwater equivalent) and the greater Cold Lake region (Waseca).
- Maintained balance sheet strength and with a total debt(2) to Bank EBITDA(2) ratio of 1.1x.
- Subsequent to quarter-end, completed a US$575 million private placement offering of senior unsecured notes due 2032 that bear interest at a rate of 7.375% per annum and extended the maturity of our credit facilities by two years to May 2028.
2024 Guidance
Our 2024 guidance remains unchanged with E&D expenditures of $1.2 to $1.3 billion and production of 150,000 to 156,000 boe/d.
Based on the forward strip(3), we expect to generate approximately $700 million of free cash flow(4) in 2024. We intend to 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.
(1) Capital management measure. Refer to the Specified Financial Measures section in this press release for further information.
(2) Calculated in accordance with our amended credit facilities agreement which is available on SEDAR+ at www.sedarplus.ca.
(3) 2024 pricing assumptions: WTI - US$77.50/bbl; WCS differential - US$14.50/bbl; NYMEX Gas - US$2.40/MMbtu; and Exchange Rate (CAD/USD) - 1.36.
(4) 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.
| Three Months Ended | |||||||||||
| March 31, 2024 | December 31, 2023 | March 31, 2023 | |||||||||
| FINANCIAL (thousands of Canadian dollars, except per common share amounts) | |||||||||||
| Petroleum and natural gas sales | $ | 984,192 | $ | 1,065,515 | $ | 555,336 | |||||
| Adjusted funds flow (1) | 423,846 | 502,148 | 236,989 | ||||||||
| Per share - basic | 0.52 | 0.60 | 0.43 | ||||||||
| Per share - diluted | 0.52 | 0.60 | 0.43 | ||||||||
| Free cash flow (2) | (88 | ) | 290,785 | (1,918 | ) | ||||||
| Per share - basic | - | 0.35 | - | ||||||||
| Per share - diluted | - | 0.35 | - | ||||||||
| Cash flows from operating activities | 383,773 | 474,452 | 184,938 | ||||||||
| Per share - basic | 0.47 | 0.57 | 0.34 | ||||||||
| Per share - diluted | 0.47 | 0.57 | 0.34 | ||||||||
| Net (loss) income | (14,043 | ) | (625,830 | ) | 51,441 | ||||||
| Per share - basic | (0.02 | ) | (0.75 | ) | 0.09 | ||||||
| Per share - diluted | (0.02 | ) | (0.75 | ) | 0.09 | ||||||
| Dividends declared | 18,494 | 18,381 | - | ||||||||
| Per share | 0.0225 | 0.0225 | - | ||||||||
| Capital Expenditures | |||||||||||
| Exploration and development expenditures | $ | 412,551 | $ | 199,214 | $ | 233,626 | |||||
| Acquisitions and divestitures | 35,378 | (125,822 | ) | 271 | |||||||
| Total oil and natural gas capital expenditures | $ | 447,929 | $ | 73,392 | $ | 233,897 | |||||
| Net Debt | |||||||||||
| Credit facilities | $ | 849,926 | $ | 864,736 | $ | 409,653 | |||||
| Long-term notes | 1,637,155 | 1,597,475 | 554,351 | ||||||||
| Total debt (3) | 2,487,081 | 2,462,211 | 964,004 | ||||||||
| Working capital deficiency (2) | 152,760 | 72,076 | 31,166 | ||||||||
| Net debt(1) | $ | 2,639,841 | $ | 2,534,287 | $ | 995,170 | |||||
| Shares Outstanding - basic (thousands) | |||||||||||
| Weighted average | 821,710 | 831,063 | 545,062 | ||||||||
| End of period | 821,322 | 821,681 | 545,553 | ||||||||
| BENCHMARK PRICES | |||||||||||
| Crude oil | |||||||||||
| WTI (US$/bbl) | $ | 76.96 | $ | 78.32 | $ | 76.13 | |||||
| MEH oil (US$/bbl) | 78.95 | 80.62 | 77.42 | ||||||||
| MEH oil differential to WTI (US$/bbl) | 1.99 | 2.30 | 1.29 | ||||||||
| Edmonton par ($/bbl) | 92.16 | 99.72 | 99.04 | ||||||||
| Edmonton par differential to WTI (US$/bbl) | (8.63 | ) | (5.10 | ) | (2.88 | ) | |||||
| WCS heavy oil ($/bbl) | 77.73 | 76.86 | 69.44 | ||||||||
| WCS differential to WTI (US$/bbl) | (19.33 | ) | (21.88 | ) | (24.77 | ) | |||||
| Natural gas | |||||||||||
| NYMEX (US$/mmbtu) | $ | 2.24 | $ | 2.88 | $ | 3.42 | |||||
| AECO ($/mcf) | 2.05 | 2.66 | 4.34 | ||||||||
| CAD/USD average exchange rate | 1.3488 | 1.3619 | 1.3520 | ||||||||
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 | |||||||||
| March 31, 2024 | December 31, 2023 | March 31, 2023 | |||||||
| OPERATING | |||||||||
| Daily Production | |||||||||
| Light oil and condensate (bbl/d) | 66,036 | 70,124 | 31,678 | ||||||
| Heavy oil (bbl/d) | 40,560 | 39,569 | 34,191 | ||||||
| NGL (bbl/d) | 19,299 | 23,160 | 7,213 | ||||||
| Total liquids (bbl/d) | 125,895 | 132,853 | 73,082 | ||||||
| Natural gas (mcf/d) | 148,353 | 165,121 | 82,066 | ||||||
| Oil equivalent (boe/d @ 6:1) (1) | 150,620 | 160,373 | 86,760 | ||||||
| Netback (thousands of Canadian dollars) | |||||||||
| Total sales, net of blending and other expense (2) | $ | 919,984 | $ | 1,003,219 | $ | 495,655 | |||
| Royalties | (209,171 | ) | (228,570 | ) | (93,253 | ) | |||
| Operating expense | (173,435 | ) | (164,873 | ) | (112,408 | ) | |||
| Transportation expense | (29,835 | ) | (29,744 | ) | (17,005 | ) | |||
| Operating netback (2) | $ | 507,543 | $ | 580,032 | $ | 272,989 | |||
| General and administrative | (22,412 | ) | (22,280 | ) | (11,734 | ) | |||
| Cash financing and interest | (53,280 | ) | (56,698 | ) | (18,375 | ) | |||
| Realized financial derivatives gain | 5,488 | 12,377 | 5,415 | ||||||
| Other (3) | (13,493 | ) | (11,283 | ) | (11,306 | ) | |||
| Adjusted funds flow (4) | $ | 423,846 | $ | 502,148 | $ | 236,989 | |||
| Netback (per boe) (2) | |||||||||
| Total sales, net of blending and other expense (2) | $ | 67.12 | $ | 68.00 | $ | 63.48 | |||
| Royalties (5) | (15.26 | ) | (15.49 | ) | (11.94 | ) | |||
| Operating expense (5) | (12.65 | ) | (11.17 | ) | (14.40 | ) | |||
| Transportation expense (5) | (2.18 | ) | (2.02 | ) | (2.18 | ) | |||
| Operating netback (2) | $ | 37.03 | $ | 39.32 | $ | 34.96 | |||
| General and administrative (5) | (1.64 | ) | (1.51 | ) | (1.50 | ) | |||
| Cash financing and interest (5) | (3.89 | ) | (3.84 | ) | (2.35 | ) | |||
| Realized financial derivatives gain (5) | 0.40 | 0.84 | 0.69 | ||||||
| Other (3) | (0.98 | ) | (0.78 | ) | (1.45 | ) | |||
| Adjusted funds flow (4) | $ | 30.92 | $ | 34.03 | $ | 30.35 | |||
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, other income or expense, current income tax expense or recovery and cash share-based compensation. Refer to the Q1/2024 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 (loss) divided by barrels of oil equivalent production volume for the applicable period.
During the first quarter, we delivered operating and financial results consistent with our full-year guidance. We increased production per basic share by 15% in Q1/2024, compared to Q1/2023, with production averaging 150,620 boe/d (84% oil and NGLs). We increased adjusted funds flow(1) per basic share by 21% to $424 million ($0.52 per basic share) and realized a net loss of $14 million ($0.02 per basic share).
Our first quarter drilling program delivered strong results as we safely and efficiently executed the largest E&D program in company history. We drilled 92 (82.7 net) wells with 13 rigs running at the peak and E&D expenditures totaled $413 million (33% of budgeted full-year expenditures).
We remain committed to a disciplined, returns-based capital allocation philosophy to drive increased per-share returns. Our 2024 guidance remains unchanged with E&D expenditures of $1.2 to $1.3 billion and production of 150,000 to 156,000 boe/d. Based on the forward strip(2), we expect to generate approximately $700 million of free cash flow(3) in 2024, all of which is expected to be generated in the next three quarters. We intend to 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.
Our strong free cash flow profile for 2024 reflects the efficiency of our exploration and development program, higher forecast production volumes for the remainder of the year and improved crude oil price realizations in Canada and the Eagle Ford. In Canada, we are benefiting from the completion of the Trans Mountain Pipeline Expansion and increased oil export capacity which is contributing to a narrowing of the WTI-WCS spread. In the Eagle Ford, we benefit from our exposure to premium U.S. Gulf Coast pricing for our light oil and condensate production.
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 and we restarted our share buyback program in late March. For the period June 29, 2023 to May 8, 2024, we repurchased 47.0 million common shares for $255 million, representing 5.5% of our shares outstanding, at an average price of $5.42 per share.
Subsequent to quarter-end, we undertook steps to extend our debt maturities. On April 1, 2024, we closed a private placement offering of US$575 million aggregate principal amount of senior unsecured notes. The notes bear interest at a rate of 7.375% per annum and mature on March 15, 2032. Net proceeds from the offering were used to redeem US$409.8 million aggregate principal amount of outstanding 8.75% notes and repay a portion of the debt outstanding on our credit facilities. On May 9, 2024, we extended the maturity of our credit facilities by two years to May 2028.
We employ a disciplined commodity hedging program to help mitigate the volatility in revenue due to changes in commodity prices. In Q1/2024, our hedging program generated realized financial derivatives gains of $5 million. For the balance of 2024, we have entered into hedges on approximately 40% of our net crude oil exposure utilizing two-way collars with an average floor price of US$60/bbl and an average ceiling price of US$96/bbl. For H1/2025, we have entered into hedges on approximately 20% of our net crude oil exposure utilizing two-way collars with an average floor price of US$60/bbl and an average ceiling price of US$91/bbl. A complete listing of our financial derivative contracts can be found in Note 17 to our Q1/2024 financial statements.
Operations
In the Eagle Ford, we continue to deliver strong results across the black oil, volatile oil, and condensate thermal maturity windows. In Q1/2024, we brought 19 (18.5 net) operated wells onstream, including 15 Lower Eagle Ford wells, three Upper Eagle Ford wells, and one refrac.
During the first quarter, 10 of the 15 Lower Eagle Ford wells were on production for a sufficient amount of time to establish 30-day peak production rates. These wells generated an average 30-day initial peak production rate of 1,298 boe/d (85% oil and NGLs) per well. For 2024, we are targeting an 8% improvement in our operated drilling and completion costs per completed lateral foot over 2023. On our non-operated Eagle Ford acreage, we brought 18 (3.9 net) wells onstream.
We are focused on optimizing our acreage and have identified Upper Eagle Ford development areas. Our 2024 E&D program includes four Upper Eagle Ford wells, three of which were brought onstream during the first quarter and generated an average 30-day initial peak production rate of 1,214 boe/d per well (72% oil and NGLs). We completed a successful refrac (Medina Unit 3H) on our operated acreage during the first quarter that is expected to generate an internal rate of return of over 100%. Additional refrac opportunities have been identified to supplement to our capital program.
(1) Capital management measure. Refer to the Specified Financial Measures section in this press release for further information.
(2) 2024 pricing assumptions: WTI - US$77.50/bbl; WCS differential - US$14.50/bbl; NYMEX Gas - US$2.40/MMbtu; and Exchange Rate (CAD/USD) - 1.36.
(3) 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.
(4) Calculated in accordance with our amended credit facilities agreement which is available on SEDAR+ at www.sedarplus.ca.
In our light oil business unit, we completed our 2024 drilling program in the Pembina Duvernay, expanded our land base and continued development in the Viking. We were pleased with the efficiency of our two-pad, seven-well drilling program in the Duvernay which saw a 21% improvement in drilling days (spud to rig release) and a 10% improvement in drilling costs, compared to 2023. Completion of the three-well pad commenced in April, and completion of the four-well pad is expected to commence in June. In the Viking, we brought 46 net wells onstream in Q1/2024.
In addition, we acquired 30.75 net sections of high-quality Duvernay lands adjacent to our existing acreage. This brings our core Duvernay acreage to 142 net sections. We believe the asset offers significant economic inventory and growth potential.
In our heavy oil business unit, Peavine continued to outperform expectations and we have followed up early exploration success in Morinville and the greater Cold Lake area. Our Clearwater production averaged 17,599 bbl/d during the first quarter, up 8% from Q4/2023. We brought 12 (12.0 net) wells onstream during Q1/2024 and initial well performance exceeded our internal type curve expectations. The 12 wells generated an average 30-day initial peak production rate of 915 bbl/d per well.
During the first quarter, we followed up our recent heavy oil exploration success at Morinville, Alberta. We brought four multi-lateral horizontal wells onstream that targeted the Rex formation (a Clearwater equivalent). At Morinville, we have aggregated approximately 30 sections of prospective lands and production has increased to over 1,000 bbl/d.
In the greater Cold Lake area, we recently brought five Waseca horizontal multi-lateral wells onstream, increasing production from the Waseca to over 1,000 bbl/d. At Angling Lake, we drilled two successful step-out wells targeting the Upper Waseca and a successful Lower Waseca follow-up. At Ethel Lake, we drilled our first two wells targeting the Upper Waseca and are encouraged by early-time productivity. We are planning five additional Waseca follow-up wells in H2/2024.
In addition, we completed a 13 well stratigraphic test program across our heavy oil acreage. The results will guide future exploration and development activity.
Quarterly Dividend
The Board of Directors declared a quarterly cash dividend of $0.0225 per share to be paid on July 2, 2024 to shareholders of record on June 14, 2024.
Additional Information
Our condensed consolidated interim unaudited financial statements for the three months ended March 31, 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, May 10, 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://services.choruscall.ca/links/baytex2024q1.html 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: our expectation that we will deliver substantial free cash flow and meaningful shareholder returns over the next three quarters; for 2024: our guidance for exploration and development expenditures and production, the amount of free cash flow we expect to generate based on the forward strip and our expected allocation of that free cash flow as between the balance sheet and shareholder returns (including share buybacks and quarterly dividends); that we are committed to a disciplined, returns-based capital allocation philosophy to drive increased per-share returns; our expected reduction in total debt during 2024; our commodity hedging program, the percentage of our 2024 net crude exposure that is hedged, and the ability of such program to mitigate revenue volatility due to changes in commodity prices; in the Eagle Ford: our targeted improvement in operated drilling and completion costs per lateral foot in the Eagle Ford and the expected internal rate of return for the Medina Unit 3H refrac; our belief that the Duvernay asset offers significant economic inventory growth potential; drilling and completion plans for the Duvernay and Viking; and that stratigraphic test results on our heavy oil acreage will guide future exploration and development activity. 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 Corporation 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 Corporation'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 Corporation 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 Corporation 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 Corporation'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 Corporation'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 Corporation has incurred or may incur in the future, including the terms of the Credit Facilities) and satisfaction of the solvency tests imposed on the Corporation under applicable corporate law. There can be no assurance of the number of Common Shares that the Corporation 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 | |||||||||
| ($ thousands) | March 31, 2024 | December 31, 2023 | March 31, 2023 | ||||||
| Petroleum and natural gas sales | $ | 984,192 | $ | 1,065,515 | $ | 555,336 | |||
| Blending and other expense | (64,208) | (62,296) | (59,681) | ||||||
| Total sales, net of blending and other expense | $ | 919,984 | $ | 1,003,219 | $ | 495,655 | |||
| Royalties | (209,171) | (228,570) | (93,253) | ||||||
| Operating expense | (173,435) | (164,873) | (112,408) | ||||||
| Transportation expense | (29,835) | (29,744) | (17,005) | ||||||
| Operating netback | $ | 507,543 | $ | 580,032 | $ | 272,989 | |||
| Realized financial derivatives gain (1) | 5,488 | 12,377 | 5,415 | ||||||
| Operating netback after realized financial derivatives | $ | 513,031 | $ | 592,409 | $ | 278,404 | |||
(1)Realized financial derivatives gain 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 months ended March 31, 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, and transaction costs.
Free cash flow is reconciled to cash flows from operating activities in the following table.
| Three Months Ended | |||||||||
| ($ thousands) | March 31, 2024 | December 31, 2023 | March 31, 2023 | ||||||
| Cash flows from operating activities | $ | 383,773 | $ | 474,452 | $ | 184,938 | |||
| Change in non-cash working capital | 32,023 | 14,971 | 39,054 | ||||||
| Additions to exploration and evaluation assets | - | 5,079 | (490 | ) | |||||
| Additions to oil and gas properties | (412,551 | ) | 1,271 | (233,136 | ) | ||||
| Payments on lease obligations | (4,872 | ) | (200,537 | ) | (1,155 | ) | |||
| Transaction costs | 1,539 | (4,451 | ) | 8,871 | |||||
| Free cash flow | $ | (88 | ) | $ | 290,785 | $ | (1,918 | ) | |
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 March 31, 2024, the Company had $638.6 million of available credit facility capacity to cover any working capital deficiencies.
The following table summarizes the calculation of working capital deficiency.
| As at | |||||||||
| ($ thousands) | March 31, 2024 | December 31, 2023 | March 31, 2023 | ||||||
| Cash | $ | (29,140) | $ | (55,815) | $ | (6,445) | |||
| Trade receivables | (423,119) | (339,405) | (221,007) | ||||||
| Prepaids and other assets | (77,901) | (83,259) | (12,404) | ||||||
| Trade payables | 626,137 | 477,295 | 250,920 | ||||||
| Share-based compensation liability | 18,667 | 35,732 | 20,102 | ||||||
| Other long-term liabilities | 19,622 | 19,147 | - | ||||||
| Dividends payable | 18,494 | 18,381 | - | ||||||
| Working capital deficiency | $ | 152,760 | $ | 72,076 | $ | 31,166 | |||
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) | March 31, 2024 | December 31, 2023 | March 31, 2023 | ||||||
| Credit facilities | $ | 835,363 | $ | 848,749 | $ | 407,473 | |||
| Unamortized debt issuance costs - Credit facilities (1) | 14,563 | 15,987 | 2,180 | ||||||
| Long-term notes | 1,602,417 | 1,562,361 | 547,698 | ||||||
| Unamortized debt issuance costs - Long-term notes (1) | 34,738 | 35,114 | 6,653 | ||||||
| Trade payables | 626,137 | 477,295 | 250,920 | ||||||
| Share-based compensation liability | 18,667 | 35,732 | 20,102 | ||||||
| Dividends payable | 18,494 | 18,381 | - | ||||||
| Other long-term liabilities | 19,622 | 19,147 | - | ||||||
| Cash | (29,140 | ) | (55,815 | ) | (6,445 | ) | |||
| Trade receivables | (423,119 | ) | (339,405 | ) | (221,007 | ) | |||
| Prepaids and other assets | (77,901 | ) | (83,259 | ) | (12,404 | ) | |||
| Net debt | $ | 2,639,841 | $ | 2,534,287 | $ | 995,170 | |||
(1)Unamortized debt issuance costs were obtained from Note 7 - Credit Facilities and Note 8 - Long-term Notes from the consolidated financial statements for the three months ended March 31, 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, and transaction costs during the applicable period.
Adjusted funds flow is reconciled to amounts disclosed in the primary financial statements in the following table.
| Three Months Ended | ||||||||||
| ($ thousands) | March 31, 2024 | December 31, 2023 | March 31, 2023 | |||||||
| Cash flow from operating activities | $ | 383,773 | $ | 474,452 | $ | 184,938 | ||||
| Change in non-cash working capital | 32,023 | 14,971 | 39,054 | |||||||
| Asset retirement obligations settled | 6,511 | 7,646 | 4,126 | |||||||
| Transaction costs | 1,539 | 5,079 | 8,871 | |||||||
| Adjusted funds flow | $ | 423,846 | $ | 502,148 | $ | 236,989 | ||||
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 initial 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 months ended March 31, 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 March 31, 2024 | Three Months Ended March 31, 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 | 9,481 | 9 | 48 | 10,088 | 11,219 | 10,783 | 13 | 54 | 11,264 | 12,727 | ||||||||||||||||||
| Lloydminster | 13,156 | 12 | - | 1,431 | 13,407 | 11,648 | 10 | - | 1,218 | 11,861 | ||||||||||||||||||
| Peavine | 17,599 | - | - | - | 17,599 | 11,760 | - | - | - | 11,760 | ||||||||||||||||||
| Canada - Light | ||||||||||||||||||||||||||||
| Viking | - | 9,181 | 190 | 11,068 | 11,215 | - | 14,640 | 193 | 11,620 | 16,770 | ||||||||||||||||||
| Duvernay | - | 1,803 | 1,757 | 5,456 | 4,469 | - | 1,063 | 944 | 2,623 | 2,444 | ||||||||||||||||||
| Remaining Properties | 324 | 488 | 636 | 16,337 | 4,171 | - | 672 | 684 | 22,395 | 5,089 | ||||||||||||||||||
| United States | ||||||||||||||||||||||||||||
| Eagle Ford | - | 54,543 | 16,668 | 103,973 | 88,540 | - | 15,280 | 5,338 | 32,946 | 26,109 | ||||||||||||||||||
| Total | 40,560 | 66,036 | 19,299 | 148,353 | 150,620 | 34,191 | 31,678 | 7,213 | 82,066 | 86,760 | ||||||||||||||||||
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: investor@baytexenergy.com
To view the source version of this press release, please visit https://www.newsfilecorp.com/release/208610
