Calgary, Alberta--(Newsfile Corp. - December 7, 2022) - Baytex Energy Corp. (TSX: BTE) ("Baytex") announces that its Board of Directors has approved 2023 exploration and development expenditures of $575 to $650 million, which are designed to generate average annual production of 86,000 to 89,000 boe/d.
"We expect to generate record free cash flow in 2022 and our priorities for 2023 remain the same. We will advance development across our high-quality oil weighted portfolio, further delineate our Peavine Clearwater acreage and progress our Duvernay light oil resource play. We are committed to allocating capital efficiently to generate meaningful free cash flow and, as we achieve our debt targets, increasing direct shareholder returns. In a US$80/bbl WTI pricing environment, we expect to generate approximately $3.1 billion of cumulative free cash flow through our 2022-2026 five-year outlook," commented Eric Greager, President and Chief Executive Officer.
Highlights of the 2023 Budget
Funding of Capital Program. Based on the forward strip(1) our exploration and development expenditures represent approximately 55% of adjusted funds flow.
Free Cash Flow. Based on the forward strip(1) we expect to generate approximately $450 million of free cash flow(2) in 2023. For every US$5/bbl change in WTI, our adjusted funds flow(3) changes by approximately $139 million on an unhedged basis ($128 million including 2023 WTI hedges).
Production Growth. Our 2023 production guidance (at the mid-point) represents a 4% increase from forecast 2022 production guidance (8% increase on a per-share basis(4)).
Capital Efficiency. Our capital program is expected to generate capital efficiencies of approximately $19,500 per boe/d across the portfolio.
Capital Allocation. We plan to direct approximately 65% of our exploration and development expenditures to our light oil assets and approximately 35% to our heavy oil assets, which includes approximately 15% of our 2023 capital program being directed to our Peavine Clearwater assets.
Shareholder Returns. We are currently allocating 25% of free cash flow to share buybacks and 75% of free cash flow to debt reduction. We expect to reach a net debt(3) level of $800 million by mid-2023 at which point we anticipate increasing direct shareholder returns to 50% of free cash flow and accelerating our share buyback program.
Risk Management. Approximately 18% of our net crude oil exposure has been hedged for 2023 utilizing a 3-way structure that provides price protection at US$78/bbl with upside participation to US$96/bbl.
The 2023 capital program is expected to be equally weighted to the first and second half of the year. Based on the mid-point of our production guidance of 87,500 boe/d, approximately 70% of our production is in Canada with the remaining 30% in the Eagle Ford. Our production mix is forecast to be 85% liquids (36% light oil and condensate, 41% heavy oil and 8% natural gas liquids) and 15% natural gas, based on a 6:1 natural gas-to-oil equivalency.
(1) 2023 pricing assumptions: WTI - US$76/bbl; WCS differential - US$25/bbl; MSW differential - US$3/bbl, NYMEX Gas - US$5.70/mmbtu; AECO Gas - $4.75/mcf and Exchange Rate (CAD/USD) - 1.34.
(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) Capital management measure. Refer to the Specified Financial Measures section in this press release for further information.
(4) Includes impact of share buyback program.
Shareholder Returns
In 2022, we benefited from our diversified oil weighted portfolio and our commitment to allocate capital effectively. We are forecasting record 2022 free cash flow(1) of approximately $650 million and expect to exit the year with net debt(2) of approximately $950 million, a 33% reduction from year-end 2021. We are in a strong financial position with a year-end 2022 net debt to forecast 2023 EBITDA(3) ratio of 0.8x.
Our improved financial position enabled us to implement the second phase of our enhanced shareholder return framework in May, allocating 25% of annual free cash flow to a share buyback program with 75% of free cash flow allocated to debt reduction. Year-to-date, we repurchased 23.5 million common shares for $154 million, representing 4.1% of our shares outstanding, at an average price of $6.53 per share.
Based on the forward strip for 2023, we expect to generate approximately $450 million of free cash flow and reach a net debt level of $800 million by mid-2023. Upon achieving this target debt level, we expect to increase direct shareholder returns to 50% of our free cash flow and accelerate our share buyback program.
We have also established an ultimate net debt target for the company of $400 million, which represents an expected net debt to EBITDA ratio of 1.0x at a US$45/bbl WTI price. We feel this level of net debt provides us with flexibility to run our business through the commodity price cycles and generate meaningful returns for our shareholders. At current commodity prices, we expect to achieve this net debt level in 2024, at which point we intend to increase direct shareholder returns to 75% of our free cash flow.
Five-Year Plan
We introduced a five-year plan in April 2021 to highlight our financial and operational sustainability and ability to generate meaningful free cash flow. We continue to benchmark our results to this five-year plan and intend to update as warranted based on the macro-environment (commodity prices, cost inflation), drilling results and activity across our land base.
We are committed to a disciplined, returns-based capital allocation philosophy, targeting exploration and development expenditures at approximately 50% of our adjusted funds flow at a US$80/bbl WTI price. We expect to generate annual production growth of 2% to 4% during the plan period, with production reaching approximately 95,000 boe/d in 2026.
Under our current five-year plan and based on a constant US$80/bbl WTI price, we expect to generate approximately $3.1 billion of cumulative free cash flow. Through this plan period, we have incorporated inflation of 30% on exploration and development expenditures, as compared to 2021.
2023 Budget Details
Our 2023 exploration and development expenditures will see us advance development across our high-quality oil weighted portfolio, further delineate our Peavine Clearwater acreage and progress our Duvernay light oil resource play.
Light Oil
Approximately 65% of our exploration and development expenditures are expected to be directed to our high netback light oil assets in the Viking, Eagle Ford and Duvernay where we forecast relatively stable production and strong asset level free cash flow. We expect to bring approximately 144 net wells onstream in the Viking, 15 net wells onstream in the Eagle Ford, and six net wells onstream in the Duvernay.
In the Duvernay, we drilled a three-well pad in 2022 on the northern edge of of our land base and results have tracked to type well forecast for the region, increasing confidence in capital execution and well performance. Our 2023 Duvernay program is expected to include two three-well pads as we continue to progress our understanding of the reservoir. Across our Pembina acreage, we hold 200 sections of contiguous 100% working interest lands.
Heavy Oil
Approximately 20% of our exploration and development expenditures are expected to be directed to our heavy oil assets at Peace River and Lloydminster. Our 2023 activity reflects a capital efficient drilling program that will see approximately 40 net wells drilled at Lloydminster and 10 net Bluesky wells drilled at Peace River. At our Kerrobert steam-assisted gravity drainage ("SAGD") project, we expect to drill three well pairs to maximize resource capture and optimize steam utilization.
(1) Specified financial measure that does not have any standardized meaning prescribed by IFRS and may not be comparable with the calculation of similar measures presented by other entities. Refer to the Specified Financial Measures section in this press release for further information.
(2) Capital management measure. Refer to the Specified Financial Measures section in this press release for further information.
(3) Calculated in accordance with the Credit Facilities Agreement.
Clearwater
We expect to allocate approximately 15% of our exploration and development expenditures to our Peavine Clearwater development as successful drilling results in 2022 have led to scaled up development. We expect to bring approximately 31 net Peavine Clearwater wells onstream in 2023, up from 23 net wells in 2022. In addition, we expect to drill two Clearwater wells on our Seal acreage. Our 2023 program also includes nine stratigraphic test wells across our greater Peace River acreage to further delineate our lands for potential Clearwater development and to support multi-lateral drilling in future years.
Our Peavine Clearwater acreage has emerged as one of the most highly economic plays in North America and has grown organically while enhancing our free cash flow profile. We expect production to increase approximately 60% in 2023 to average approximately 12,000 bbl/d (up from approximately 7,500 bbl/d in 2022).
Environmental Stewardship
As part of our commitment to enhancing our culture of sustainability, we expect to invest $40 million in 2023 to progress our plans to decarbonize and shrink the environmental footprint of our operations. We plan to invest approximately $15 million as part of our GHG mitigation program and expect to reduce our GHG emissions intensity by 7% from 2022 levels. In addition, we will continue our abandonment and reclamation program with approximately $25 million being directed to pipeline, wellbore and facility decommissioning along with well site reclamations.
2023 Guidance
The following table summarizes our 2023 annual guidance.
| Exploration and development expenditures | $575 - $650 million |
| Production (boe/d) | 86,000 - 89,000 |
| Expenses: | |
| Average royalty rate (1) | 20.0 - 22.0% |
| Operating (2) | $14.00 - $14.75/boe |
| Transportation (2) | $1.90 - $2.10/boe |
| General and administrative (2) | $52 million ($1.63/boe) |
| Interest (2) | $65 million ($2.04/boe) |
| Leasing expenditures | $4 million |
| Asset retirement obligations | $25 million |
2023 Adjusted Funds Flow (3) Sensitivities
| Excluding Hedges ($ millions) | Including Hedges ($ millions) | |
| Change of US$1.00/bbl WTI crude oil | $27.8 | $25.5 |
| Change of US$1.00/bbl WCS heavy oil differential | $13.4 | $13.4 |
| Change of US$1.00/bbl MSW light oil differential | $7.2 | $7.2 |
| Change of US$0.25/mmbtu NYMEX natural gas | $7.0 | $7.0 |
| Change of $0.01 in the C$/US$ exchange rate | $12.5 | $12.5 |
(1) Specified financial measure that does not have any standardized meaning prescribed by IFRS and may not be comparable with the calculation of similar measures presented by other entities. Refer to the Specified Financial Measures section in this press release for further information.
(2) Calculated as operating, transportation, general and administrative or cash interest expense divided by barrels of oil equivalent production volume for the applicable period.
(3) Capital management measure. Refer to the Specified Financial Measures section in this press release for further information.
2023 Exploration and Development Expenditures and Wells On-Stream by Operating Area
| Operating Area | Amount (1) ($ millions) | Wells On-stream (net) |
| Canada | $485 | 234 |
| United States (2) | $130 | 15 |
| Total | $615 | 249 |
2023 Breakdown of Exploration and Development Expenditures
| Classification | Amount (1) ($ millions) |
| Drill, completion and equipping | $555 |
| Facilities | $35 |
| Land, seismic and other | $10 |
| GHG Mitigation | $15 |
| Total | $615 |
(1) Reflects the mid-point of the exploration and development expenditures guidance range.
(2) Based on a Canadian-U.S. exchange rate of 1.34 CAD/USD.
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 "anticipate", "believe", "continue", "could", "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 2023 exploration and development expenditures budget of $575-$650 million, that the budget is designed to generate average annual production of 86,000 to 89,000; we expect to generate record free cash flow in 2022; we that we will develop our portfolio, further delineate our Peavine Clearwater and progress the Duvernay; our commitment to allocated capital to maximize free cash flow, and increase direct shareholder returns as we achieve debt targets; in an US$80 WTI environment we expect to generate $3.1 billion of cumulative free cash flow through 2022-2026; based on the forward strip, our exploration and development expenditures represents approximately 55% of adjusted funds flow; based on the forward strip we expect to generate $450 million of free cash flow and for each $5/bbl change in WTI our adjusted funds flow changes by ~$139 million ($128 million including WTI hedges); our capital program is expected to generate capital efficiencies of $19,500 per boe/d across the portfolio; the allocation as between certain assets of our exploration and development expenditures; that we expect to reach our debt debt target of $800 million by mid-2023 and will then increase our direct shareholder returns to 50% and accelerate our share buyback program; the percentage of our net crude exposure that is hedged for 2023; the expected timing of our exploration and development expenditures; the geographic breakdown and product type breakdown for 2023 production; forecast 2022 free cash flow of $650 million, our expected 2022 year-end net debt of $950 million and 2022 net debt to EBITDA ratio of 0.8x; that we expect to reach our ultimate net debt target of $400 million in 2024, that $400 million of net debt represents 1.0x at a $45 WTI price, and at this level of net we will have flexibility to run our business through the commodity price cycle and generate meaningful returns for shareholders debt and intend to increase direct shareholder returns to 75% of free cash flow; that we intend to update our 5 year plan as warranted; regarding our five-year plan: it highlights our financial and operational sustainability and ability to generate meaningful free cash flow, it will be updated as warranted, during the plan period we are committed to a disciplined, returns-based capital allocation philosophy, our targeted exploration and development expenditures at ~50% of adjusted funds flow at US$80/bbl WTI, expected production growth of 2-4% reaching ~95,000 boe/d in 2026 and expected cumulative free cash flow of $3.1 billion at US$80/bbl WTI; the percentage of exploration and development expenditures that will be allocated to our heavy and light oil assets; the number of wells we expect to drill and bring onstream by asset; that we expect production in our Peavine Clearwater acreage to average 12,000 bbl/d in 2023; our GHG emissions reduction and abandonment and reclamation plans and spending commitments; our expected exploration and development expenditures, production, royalty rate and operating, transportation, general and administrative, interest costs, leasing expenditures and asset retirement obligations for 2023; the sensitivity of our 2023 adjusted funds flow to changes in WTI, WCS, MSW and NYMEX prices and the C$/US$ exchange rate (with and without hedges); the expected exploration and development expenditures budget and wells on-stream by operating area in 2023 and the exploration and development expenditures budget by spending type for 2023.
These forward-looking statements are based on certain key assumptions regarding, among other things: 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; exploration and development 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 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, 2021, 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.
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 and average royalty rate) 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" and "net debt" which are considered capital management measures.
For additional information and quantitative reconciliations related to the specified financial measures as at September 30, 2022, which have been incorporated by reference into this document, refer to Management's Discussion and Analysis dated November 3, 2022. A copy is available through Baytex's filings on SEDAR at and through the U.S. Securities and Exchange Commission at .
Non-GAAP Financial Measures and Ratios
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 and payments on lease obligations. 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.
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.
Capital Management Measures
Net debt
We define net debt to be the sum of our credit facilities and long-term notes outstanding adjusted for unamortized debt issuance costs, trade and other payables, cash and trade and other receivables. Our definition of net debt may not be comparable to other issuers. We believe that this measure assists in providing a more complete understanding of our cash liabilities and provides 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 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.
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.
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. 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.
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.
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 under the symbol BTE.
For further information about Baytex, please visit our website at or contact:
Brian Ector, Vice President, Capital Markets
Toll Free Number: 1-800-524-5521
Email:
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