Baytex Announces First Quarter 2023 Results
Calgary, Alberta--(Newsfile Corp. - May 4, 2023) - Baytex Energy Corp. (TSX: BTE) (NYSE: BTE) ("Baytex") reports its operating and financial results for the three months ended March 31, 2023 (all amounts are in Canadian dollars unless otherwise noted).
"We continued to deliver on our operating and financial targets in the first quarter, which included strong results from our Peavine Clearwater development. We continue to make significant progress on the Ranger acquisition, which materially increases Eagle Ford scale in Texas, while building a quality operating capability in a premier basin. The combined company will deliver a powerful combination of substantial free cash flow and increased shareholder returns on a per-share basis. We are in a strong financial position that is supported by significant liquidity and a balanced note maturity profile and we are excited to increase direct shareholder returns to
Highlights
- Entered into an agreement to acquire Ranger Oil Corporation ("Ranger") for approximately US
$2.5 billion . - Generated production of 86,760 boe/d (
84% oil and NGL) in Q1/2023, a7% increase over Q1/2022. - Delivered adjusted funds flow(1) of
$237 million ($0.43 per basic share) in Q1/2023. - Reported cash flows from operating activities of
$185 million ($0.34 per basic share) in Q1/2023. - Exploration and development expenditures totaled
$234 million in Q1/2023, consistent with our full-year plan. - Generated production from our Clearwater play at Peavine of 11,760 bbl/d in Q1/2023. The first 12 wells from our 2023 drilling program at Peavine generated an average 30-day initial production rate of 661 bbl/d per well.
- Subsequent to quarter-end, completed a US
$800 million private offering of senior unsecured notes due 2030 that bear interest at a rate of8.5% per annum.
Ranger Acquisition
On February 28, 2023, Baytex announced the acquisition of Ranger (the "Merger"), a pure play Eagle Ford operator. With this transaction, we are building a quality, scaled North American oil-weighted exploration and production company with a portfolio across the Western Canadian Sedimentary Basin and the Eagle Ford. The transaction enhances our inventory and creates a more resilient and sustainable business.
A key consideration of the Merger was our ability to accelerate the planned next phase of our shareholder return framework. On closing, we intend to increase direct shareholder returns to
2023 Guidance
Our 2023 production guidance range is unchanged at 86,000 to 89,000 boe/d with budgeted exploration and development expenditures of
(1) Capital management measure. Refer to the Specified Financial Measures section in this press release for further information.
(2) 2023 pricing assumptions: WTI - US
| Three Months Ended | ||||||||
| March 31, 2023 | December 31, 2022 | March 31, 2022 | ||||||
| FINANCIAL (thousands of Canadian dollars, except per common share amounts) | ||||||||
| Petroleum and natural gas sales | $ | 555,336 | $ | 648,986 | $ | 673,825 | ||
| Adjusted funds flow (1) | 236,989 | 255,552 | 279,607 | |||||
| Per share - basic | 0.43 | 0.47 | 0.49 | |||||
| Per share - diluted | 0.43 | 0.46 | 0.49 | |||||
| Free cash flow (2) | (1,918) | 143,324 | 121,318 | |||||
| Per share - basic | - | 0.26 | 0.21 | |||||
| Per share - diluted | - | 0.26 | 0.21 | |||||
| Cash flows from operating activities | 184,938 | 303,441 | 198,974 | |||||
| Per share - basic | 0.34 | 0.56 | 0.35 | |||||
| Per share - diluted | 0.34 | 0.55 | 0.35 | |||||
| Net income | 51,441 | 352,807 | 56,858 | |||||
| Per share - basic | 0.09 | 0.65 | 0.10 | |||||
| Per share - diluted | 0.09 | 0.64 | 0.10 | |||||
| | ||||||||
| Capital Expenditures | ||||||||
| Exploration and development expenditures | $ | 233,626 | $ | 103,634 | $ | 153,822 | ||
| Acquisitions and divestitures | 271 | 937 | 32 | |||||
| Total oil and natural gas capital expenditures | $ | 233,897 | $ | 104,571 | $ | 153,854 | ||
| | ||||||||
| Net Debt | ||||||||
| Credit facilities | $ | 409,653 | $ | 385,394 | $ | 426,858 | ||
| Long-term notes | 554,351 | 554,597 | 873,880 | |||||
| Total debt (1) | 964,004 | 939,991 | 1,300,738 | |||||
| Working capital | 31,166 | 47,455 | (25,058) | |||||
| Net debt (1) | $ | 995,170 | $ | 987,446 | $ | 1,275,680 | ||
| | ||||||||
| Shares Outstanding - basic (thousands) | ||||||||
| Weighted average | 545,062 | 546,279 | 565,518 | |||||
| End of period | 545,553 | 544,930 | 569,214 | |||||
| | ||||||||
| BENCHMARK PRICES | ||||||||
| Crude oil | ||||||||
| WTI (US$/bbl) | $ | 76.13 | $ | 82.64 | $ | 94.29 | ||
| MEH oil (US$/bbl) | 77.42 | 85.88 | 96.72 | |||||
| MEH oil differential to WTI (US$/bbl) | 1.29 | 3.24 | 2.43 | |||||
| Edmonton par ($/bbl) | 99.04 | 109.57 | 115.66 | |||||
| Edmonton par differential to WTI (US$/bbl) | (2.88) | (1.94) | (2.94) | |||||
| WCS heavy oil ($/bbl) | 69.44 | 77.37 | 100.99 | |||||
| WCS differential to WTI (US$/bbl) | (24.77) | (25.65) | (14.53) | |||||
| Natural gas | ||||||||
| NYMEX (US$/mmbtu) | $ | 3.42 | $ | 6.26 | $ | 4.95 | ||
| AECO ($/mcf) | 4.34 | 5.58 | 4.59 | |||||
| | ||||||||
| CAD/USD average exchange rate | 1.3520 | 1.3577 | 1.2661 | |||||
| Three Months Ended | ||||||||
| March 31, 2023 | December 31, 2022 | March 31, 2022 | ||||||
| OPERATING | ||||||||
| Daily Production | ||||||||
| Light oil and condensate (bbl/d) | 31,678 | 32,105 | 34,065 | |||||
| Heavy oil (bbl/d) | 34,191 | 32,819 | 25,236 | |||||
| NGL (bbl/d) | 7,213 | 7,661 | 7,636 | |||||
| Total liquids (bbl/d) | 73,082 | 72,585 | 66,937 | |||||
| Natural gas (mcf/d) | 82,066 | 85,679 | 83,574 | |||||
| Oil equivalent (boe/d @ 6:1) (3) | 86,760 | 86,864 | 80,867 | |||||
| | ||||||||
| Netback (thousands of Canadian dollars) | ||||||||
| Total sales, net of blending and other expense (2) | $ | 495,655 | $ | 598,812 | $ | 632,385 | ||
| Royalties | (93,253) | (121,691) | (122,720) | |||||
| Operating expense | (112,408) | (104,335) | (100,766) | |||||
| Transportation expense | (17,005) | (14,817) | (9,215) | |||||
| Operating netback (2) | $ | 272,989 | $ | 357,969 | $ | 399,684 | ||
| General and administrative | (11,734) | (14,945) | (11,682) | |||||
| Cash financing and interest | (18,375) | (19,711) | (20,427) | |||||
| Realized financial derivatives gain (loss) | 5,415 | (49,665) | (84,366) | |||||
| Other (4) | (11,306) | (18,096) | (3,602) | |||||
| Adjusted funds flow (1) | $ | 236,989 | $ | 255,552 | $ | 279,607 | ||
| | ||||||||
| Netback (per boe) (5) | ||||||||
| Total sales, net of blending and other expense (2) | $ | 63.48 | $ | 74.93 | $ | 86.89 | ||
| Royalties | (11.94) | (15.23) | (16.86) | |||||
| Operating expense | (14.40) | (13.06) | (13.85) | |||||
| Transportation expense | (2.18) | (1.85) | (1.27) | |||||
| Operating netback (2) | $ | 34.96 | $ | 44.79 | $ | 54.91 | ||
| General and administrative | (1.50) | (1.87) | (1.61) | |||||
| Cash financing and interest | (2.35) | (2.47) | (2.81) | |||||
| Realized financial derivatives gain (loss) | 0.69 | (6.21) | (11.59) | |||||
| Other (4) | (1.45) | (2.26) | (0.48) | |||||
| Adjusted funds flow (1) | $ | 30.35 | $ | 31.98 | $ | 38.42 | ||
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 Q1/2023 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.
Return of Capital Framework
In 2022, we made a commitment to return
On closing of the Merger, we intend to increase direct shareholder returns to
Our existing normal course issuer bid ("NCIB") is set to expire on May 8, 2023. Following closing of the Merger, we intend to file an updated NCIB application with the TSX for a share buyback program representing approximately
Q1/2023 Results
During the first quarter, we delivered strong operating and financial results, consistent with our full-year plan. Production averaged 86,760 boe/d (
Exploration and development expenditures totaled
Light Oil - United States
Our light oil assets in the United States are located in the core of the liquids-rich Eagle Ford formation, in the Texas Gulf Coast Basin. Our existing Eagle Ford assets include non-operated working interests in four areas of mutual interest with an average working interest of approximately
Production in the Eagle Ford averaged 26,109 boe/d (
Light Oil - Canada
Our light oil production and development in Canada occurs within the Viking formation in west central Saskatchewan and east central Alberta, and the Duvernay formation in the Pembina area of central Alberta. The Viking assets are a shallow, light oil resource play with strong operating netbacks. The Pembina Duvernay development is an early stage, high operating netback light oil resource play.
Production in the Viking averaged 16,770 boe/d (
Production in the Pembina Duvernay averaged 2,444 boe/d (
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 low decline production with innovative multi-lateral (trident and fishbone) horizontal drilling with strong capital efficiencies. The core of our Clearwater play is located on the Peavine Métis settlement.
(1) Refer to the Dividend Advisory section in the press release for further information.
(2) Capital management measure. Refer to the Specified Financial Measures section in this press release for further information.
(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.
Our heavy oil assets at Peace River and Lloydminster (excluding Clearwater development) produced a combined 24,588 boe/d (
Production in the Peavine Clearwater averaged 11,760 boe/d (
Across all of our core assets, inventory enhancement continues to be a priority. In Q4/2022 we successfully drilled a Clearwater equivalent test well at Morinville, Alberta, where we have aggregated approximately 30 sections of prospective land. The well was brought onstream in Q1/2023 and has achieved a 30-day initial production rate of 180 bbl/d of 15.5° API crude oil. Notably, this six leg test well is about half the length of full planned development wells. We are encouraged by these initial results and are planning two additional follow-up wells in the second half of 2023.
Senior Notes Financing
On April 27, 2023, we announced the closing of a US
Risk Management
To manage commodity price movements, we utilize various financial derivative contracts to reduce the volatility of our adjusted funds flow.
For May to December 2023, we have entered into hedges on approximately
We intend to hedge approximately
A complete listing of our financial derivative contracts can be found in Note 17 to our Q1/2023 financial statements.
Board of Directors Update
On closing of the Merger, Baytex intends to appoint two independent directors from the Ranger Board of Directors to the Baytex Board of Directors. At the time of the Merger announcement, Baytex indicated its intent to appoint Jeffrey E. Wojahn to the Baytex Board of Directors. Baytex is pleased to announce that we also intend to appoint Tiffany ("T.J.") Thom Cepak to the Baytex Board of Directors.
Additional Information
Our condensed consolidated interim unaudited financial statements for the three months ended March 31, 2023 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.sedar.com and EDGAR at www.sec.gov/edgar.shtml.
(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.
Conference Call Tomorrow |
Baytex will host a conference call tomorrow, May 5, 2023, starting at 9:00am MT (11:00am ET). To participate, please dial toll free in North America 1-800-319-4610 or international 1-416-915-3239. Alternatively, to listen to the conference call online, please enter https://services.choruscall.ca/links/baytex2023q1.html in your web browser. An archived recording of the conference call will be available shortly after the event by accessing the webcast link above. The conference call will also be archived on the Baytex website at www.baytexenergy.com. |
Advisory Regarding Forward-Looking Statements
In the interest of providing Baytex's shareholders and potential investors with information regarding Baytex, including management's assessment of Baytex's future plans and operations, certain statements in this press release are "forward-looking statements" within the meaning of the United States Private Securities Litigation Reform Act of 1995 and "forward-looking information" within the meaning of applicable Canadian securities legislation (collectively, "forward-looking statements"). In some cases, forward-looking statements can be identified by terminology such as "believe", "continue", "estimate", "expect", "forecast", "intend", "may", "objective", "ongoing", "outlook", "potential", "project", "plan", "should", "target", "would", "will" or similar words suggesting future outcomes, events or performance. The forward-looking statements contained in this press release speak only as of the date thereof and are expressly qualified by this cautionary statement.
Specifically, this press release contains forward-looking statements relating to but not limited to: that the Merger will result in a combined company that will deliver a powerful combination of substantial free cash flow and increased shareholder returns on a per-share basis; that following the Merger we intend to increase direct shareholder returns to
These forward-looking statements are based on certain key assumptions regarding, among other things: the consummation and success of the Merger and our ability to successfully integrate the acquired business into our existing operations; the timing of receipt of regulatory and shareholder and stockholder approvals; the ability of the combined business to realize the anticipated benefits of the transaction; petroleum and natural gas prices and differentials between light, medium and heavy oil prices; well production rates and reserve volumes; our ability to add production and reserves through our exploration and development activities; capital expenditure levels; 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; 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 ability to obtain stockholder, shareholder, and regulatory approvals, if any, of the Merger; the ability to complete the Merger on anticipated terms and timetable; the possibility that various closing conditions for the transaction may not be satisfied or waived; risks relating to any unforeseen liabilities of Baytex and Ranger; the volatility of oil and natural gas prices and price differentials (including the impacts of COVID-19); restrictions or costs imposed by climate change initiatives and the physical risks of climate change; risks associated with our ability to develop our properties and add reserves; the impact of an energy transition on demand for petroleum productions; changes in income tax or other laws or government incentive programs; availability and cost of gathering, processing and pipeline systems; retaining or replacing our leadership and key personnel; the availability and cost of capital or borrowing; risks associated with a third-party operating our Eagle Ford properties; risks associated with large projects; costs to develop and operate our properties; public perception and its influence on the regulatory regime; current or future control, legislation or regulations; new regulations on hydraulic fracturing; restrictions on or access to water or other fluids; 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; additional risks associated with our thermal heavy oil projects; our ability to compete with other organizations in the oil and gas industry; risks associated with our use of information technology systems; 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 of counterparty default; the impact of Indigenous claims; risks associated with expansion into new activities; 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.
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, 2022, 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.
There is no representation by Baytex that actual results achieved will be the same in whole or in part as those referenced in the forward-looking statements and Baytex does not undertake any obligation to update publicly or to revise any of the included forward-looking statements, whether as a result of new information, future events or otherwise, except as may be required by applicable securities law.
This press release contains information that may be considered a financial outlook under applicable securities laws about Baytex's pro forma capitalization upon completion of the Merger, which are subject to numerous assumptions, risk factors, limitations and qualifications, including those set forth herein. The actual capitalization of Baytex 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, Baytex undertakes no obligation to update such financial outlook. 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 Baytex's potential future capitalization upon completion of the Merger. Readers are cautioned that the financial outlook contained in this press release is not conclusive and is subject to change.
Dividend Advisory
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. There can be no assurance that Baytex will pay dividends following closing of the Merger.
Specified Financial Measures
In this press release, we refer to certain financial measures (such as free cash flow, operating netback, 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 natural gas industry, our determination of these measures may not be comparable with calculations of similar measures for other issuers. In addition, this press release contains the terms "adjusted funds flow", "total debt", and "net debt" which are considered capital management measures.
Non-GAAP Financial Measures
Total sales, net of blending and other expense
Total sales, net of blending and other expense is not a measurement based on GAAP in Canada and 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 is not a measurement based on GAAP in Canada, but is a financial term commonly used in the oil and gas industry. Operating netback is equal to petroleum and natural gas sales less blending expense, royalties, production and operating expense and transportation expense. Our determination of operating netback may not be comparable with the calculation of similar measures for other entities. We believe that this measure assists in characterizing our ability to generate cash margin on a unit of production basis and is a key measure used to evaluate our operating performance.
The following table reconciles total sales, net of blending and other expense and operating netback to petroleum and natural gas sales.
| Three Months Ended March 31 | |||||
| ($ thousands) | 2023 | 2022 | |||
| Petroleum and natural gas sales | $ | 555,336 | $ | 673,825 | |
| Blending and other expense | (59,681) | (41,440) | |||
| Total sales, net of blending and other expense | $ | 495,655 | $ | 632,385 | |
| Royalties | (93,253) | (122,720) | |||
| Operating expense | (112,408) | (100,766) | |||
| Transportation expense | (17,005) | (9,215) | |||
| Operating netback | $ | 272,989 | $ | 399,684 | |
Free cash flow
Free cash flow is not a measurement based on GAAP in Canada. We define free cash flow as 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. Our determination of free cash flow may not be comparable to other issuers. We use free cash flow to evaluate funds available for debt repayment, common share repurchases, potential future dividends and acquisition and disposition opportunities.
Free cash flow is reconciled to cash flows from operating activities in the following table.
| Three Months Ended March 31 | |||||
| ($ thousands) | 2023 | 2022 | |||
| Cash flows from operating activities | $ | 184,938 | $ | 198,974 | |
| Change in non-cash working capital | 39,054 | 77,340 | |||
| Additions to exploration and evaluation assets | (490) | (3,559) | |||
| Additions to oil and gas properties | (233,136) | (150,263) | |||
| Payments on lease obligations | (1,155) | (1,174) | |||
| Transaction costs | 8,871 | - | |||
| Free cash flow | $ | (1,918) | $ | 121,318 | |
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. 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 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
Total debt and Net debt
We use total debt and net debt to monitor our current financial position and to evaluate existing sources of liquidity. We define total debt to be the sum of our credit facilities and long-term notes outstanding adjusted for unamortized debt issuance costs. To arrive at net debt we further adjust for trade and other payables, cash, and trade and other receivables. We believe that these measures assist in providing a more complete understanding of our cash liabilities and provide a key measure to assess our liquidity. We use the principal amounts of the credit facilities and long-term notes outstanding in the calculation of total debt and net debt as these amounts represent our ultimate repayment obligation at maturity. The carrying amount of debt issue costs associated with the credit facilities and long-term notes is excluded on the basis that these amounts have already been paid by Baytex at inception of the contract and do not represent an additional source of capital or repayment obligation.
The following table summarizes our calculation of net debt.
| ($ thousands) | March 31, 2023 | December 31, 2022 | |||
| Credit facilities | $ | 407,473 | $ | 383,031 | |
| Unamortized debt issuance costs - Credit facilities (1) | 2,180 | 2,363 | |||
| Long-term notes | 547,698 | 547,598 | |||
| Unamortized debt issuance costs - Long-term notes (1) | 6,653 | 6,999 | |||
| Total Debt | $ | 964,004 | $ | 987,446 | |
| Trade and other payables | 271,022 | 272,195 | |||
| Cash | (6,445) | (5,464) | |||
| Trade and other receivables | (233,411) | (228,485) | |||
| Net debt | $ | 995,170 | $ | 987,446 |
(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, 2023.
Adjusted funds flow
Adjusted funds flow is a financial term commonly used in the oil and gas industry. We define adjusted funds flow as cash flow from operating activities adjusted for changes in non-cash operating working capital and asset retirement obligations settled. Our determination of adjusted funds flow may not be comparable to other issuers. We consider adjusted funds flow a key measure that provides a more complete understanding of operating performance and our ability to generate funds for exploration and development expenditures, debt repayment, settlement of our abandonment obligations and potential future dividends.
Adjusted funds flow is reconciled to amounts disclosed in the primary financial statements in the following table.
| Three Months Ended March 31 | |||||
| ($ thousands) | 2023 | 2022 | |||
| Cash flow from operating activities | $ | 184,938 | $ | 198,974 | |
| Change in non-cash working capital | 39,054 | 77,340 | |||
| Asset retirement obligations settled | 4,126 | 3,293 | |||
| Transaction costs | 8,871 | - | |||
| Adjusted funds flow | $ | 236,989 | $ | 279,607 | |
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, 2023. 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, 2023 | Three Months Ended March 31, 2022 | ||||||||||
| 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 | 10,783 | 13 | 54 | 11,264 | 12,727 | 11,587 | 5 | 29 | 11,125 | 13,475 | |
| Lloydminster | 11,648 | 10 | - | 1,218 | 11,861 | 10,495 | 15 | - | 1,787 | 10,808 | |
| Peavine | 11,760 | - | - | - | 11,760 | 3,154 | - | - | - | 3,154 | |
| | |||||||||||
| Canada - Light | |||||||||||
| Viking | - | 14,640 | 193 | 11,620 | 16,770 | - | 15,694 | 188 | 11,894 | 17,865 | |
| Duvernay | - | 1,063 | 944 | 2,623 | 2,444 | - | 992 | 789 | 2,343 | 2,172 | |
| Remaining Properties | - | 672 | 684 | 22,395 | 5,089 | - | 867 | 929 | 24,694 | 5,911 | |
| | |||||||||||
| United States | |||||||||||
| Eagle Ford | - | 15,280 | 5,338 | 32,946 | 26,109 | - | 16,492 | 5,701 | 31,731 | 27,482 | |
| | |||||||||||
| Total | 34,191 | 31,678 | 7,213 | 82,066 | 86,760 | 25,236 | 34,065 | 7,636 | 83,574 | 80,867 | |
Baytex Energy Corp.
Baytex Energy Corp. is an energy company based in Calgary, Alberta. 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, Vice President, Capital Markets
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/164878
