Calgary, Alberta--(Newsfile Corp. - July 27, 2022) - Baytex Energy Corp. (TSX: BTE) ("Baytex") reports its operating and financial results for the three and six months ended June 30, 2022 (all amounts are in Canadian dollars unless otherwise noted).
"During the second quarter, we delivered strong operating results which included significant production growth from our Clearwater assets and record quarterly free cash flow of $245 million. Given the strength of our balance sheet and consistent with our desire to offer direct shareholder returns, we launched our share buyback program in May and repurchased 9.1 million shares during the quarter. I am also excited to announce that upon hitting our $800 million net debt target in late 2022 or early 2023, we anticipate increasing direct shareholder returns to 50% of our free cash flow and accelerating our share buyback program. We continue to view our shares as undervalued in relation to our current operations," commented Ed LaFehr, President and Chief Executive Officer.
Q2 2022 Highlights
- Generated production of 83,090 boe/d (83% oil and NGL) in Q2/2022, a 2% increase over Q2/2021.
- Delivered adjusted funds flow(1) of $346 million ($0.61 per basic share) in Q2/2022, a 97% increase compared to $176 million ($0.31 per basic share) in Q2/2021.
- Generated free cash flow(2) of $245 million ($0.43 per basic share) in Q2/2022, a 118% increase compared to $112 million ($0.20 per basic share) in Q2/2021.
- Cash flows from operating activities of $360 million ($0.63 per basic share) in Q2/2022, a 109% increase compared to $172 million ($0.30 per basic share) in Q2/2021.
- Reduced net debt(1) by 20% to $1.12 billion, from $1.41 billion at year-end 2021.
- Redeemed the remaining US$200 million principal amount of 5.625% long-term notes at par on June 1, 2022.
- Repurchased 9.1 million common shares, representing 1.6% of our shares outstanding, at an average price of $6.88 per share.
- Generated production from our Clearwater play at Peavine of 7,319 bbl/d in Q2/2022, up from 3,154 bbl/d in Q1/2022. Production during the month of June averaged 9,088 bbl/d from 18 producing wells and we have 14 Clearwater wells to drill during the second half of 2022.
2022 Outlook
We remain intensely focused on maintaining capital discipline and driving meaningful free cash flow in our business. We continue to execute our 2022 plan with production guidance unchanged at 83,000 to 85,000 boe/d and expect to exit 2022 producing approximately 87,000 to 88,000 boe/d.
Our 2022 exploration and development expenditures guidance is unchanged at $450 to $500 million. We continue to experience inflationary pressures in our business, particularly the Eagle Ford, and anticipate full-year capital expenditures toward the high end of our guidance range. Based on the forward strip(3), we expect to generate approximately $700 million ($1.25 per basic share) of free cash flow this year.
(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) 2022 full-year pricing assumptions: WTI - US$98/bbl; WCS differential - US$17/bbl; MSW differential - US$3/bbl, NYMEX Gas - US$6.60/mcf; AECO Gas - $5.80/mcf and Exchange Rate (CAD/USD) - 1.28.
2022 Outlook (continued)
We have fine-tuned several of our cost assumptions to reflect increased royalties due to higher commodity prices and further inflationary pressures on operating and transportation expenses, related to labor, fuel, electricity and hauling. We are now forecasting approximately 15% inflation on a combined basis for operating and transportation expenses, as compared to 2021.
The following table highlights our 2022 annual guidance.
| 2022 Guidance (1) | 2022 Revised Guidance | ||
| Exploration and development expenditures | $450 - $500 million | no change | |
| Production (boe/d) | 83,000 - 85,000 | no change | |
| Expenses: | |||
| Average royalty rate (2) | 20.0% - 20.5% | 21.0% - 22.0% | |
| Operating (3) | $13.00 - $13.50/boe | $13.75 - $14.25/boe | |
| Transportation (3) | $1.30 - $1.40/boe | $1.50 - $1.60/boe | |
| General and administrative (3) | $43 million ($1.40/boe) | no change | |
| Interest (3) | $75 million ($2.45/boe) | no change | |
| Leasing expenditures | $3 million | no change | |
| Asset retirement obligations | $20 million | no change |
Update to Shareholder Return Framework
With continued operating momentum and strong commodity prices, we reached our initial $1.2 billion net debt(4) target during Q2/2022.
Our improved financial position enabled us to implement the first phase of our enhanced shareholder return framework in May, allocating 25% of our annual free cash flow to a share buyback program. During the second quarter, we repurchased 9.1 million common shares, representing 1.6% of our shares outstanding, at an average price of $6.88 per share. The remainder of our free cash flow continues to be allocated to debt reduction.
As our deleveraging continues at a rapid pace, we are pleased to announce the second phase of our shareholder return framework. Upon hitting a net debt level of $800 million in late 2022 or early 2023, we anticipate increasing direct shareholder returns to 50% of our free cash flow and accelerating our share buyback program. We continue to view our shares as undervalued in relation to our current operations.
We have also established an ultimate net debt target for the company of $400 million, which represents an expected net debt(4) to EBITDA(5) ratio of 1.0x at a US$45 WTI price. We feel this level of net debt will provide us with full flexibility to run our business through the commodity price cycles and generate meaningful returns for our shareholders. At current prices, we expect to achieve this net debt level by the end of 2023 or early 2024, at which point we will consider steps to further enhance shareholder returns.
President and CEO Retirement
Mr. LaFehr has provided the company notice of his intent to retire in January 2023. Mr. LaFehr has had a long and successful career as an oil and gas executive. Over the last six years at Baytex he has stewarded the company through a challenging commodity price environment and positioned the company to deliver meaningful returns to shareholders.
(1) As announced on April 28, 2022.
(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 as operating, transportation, general and administrative or cash interest expense divided by barrels of oil equivalent production volume for the applicable period.
(4) Capital management measure. Refer to the Specified Financial Measures section in this press release for further information.
(5) Calculated in accordance with the Credit Facilities Agreement.
"With a strong and improving balance sheet, our exciting Clearwater play and the initiation of share buybacks, Mr. LaFehr's planned retirement comes at a time when Baytex has a solid foundation and is well positioned for the future. Mr. LaFehr will continue to lead the team in the execution of the 2022 plan and 2023 budget preparation, which will include advancing our shareholder return framework. In addition, we will benefit from Mr. LaFehr's input as we progress through the CEO transition process," commented Mark Bly, Chair of the Board.
"I am pleased that Baytex is extremely well positioned for the future and, at the same time, I am ready to move to the next stage of my career. I look forward to guiding the company through a smooth transition as we continue to build operational momentum and drive shareholder returns," commented Ed LaFehr, President and Chief Executive Officer.
Executive development and succession planning are an ongoing process at Baytex and are critical responsibilities of the Board. To help facilitate this process, Baytex's Board has established a succession committee and engaged an executive search firm to identify and evaluate both internal and external candidates for the role.
| Three Months Ended | Six Months Ended | ||||||||||||||
| June 30, 2022 | March 31, 2022 | June 30, 2021 | June 30, 2022 | June 30, 2021 | |||||||||||
| FINANCIAL (thousands of Canadian dollars, except per common share amounts) | |||||||||||||||
| Petroleum and natural gas sales | $ | 854,169 | $ | 673,825 | $ | 442,354 | $ | 1,527,994 | $ | 827,056 | |||||
| Adjusted funds flow (1) | 345,704 | 279,607 | 175,883 | 625,311 | 332,465 | ||||||||||
| Per share - basic | 0.61 | 0.49 | 0.31 | 1.10 | 0.59 | ||||||||||
| Per share - diluted | 0.60 | 0.49 | 0.31 | 1.10 | 0.59 | ||||||||||
| Free cash flow (2) | 245,316 | 121,318 | 112,486 | 366,634 | 182,981 | ||||||||||
| Per share - basic | 0.43 | 0.21 | 0.20 | 0.65 | 0.32 | ||||||||||
| Per share - diluted | 0.43 | 0.21 | 0.20 | 0.64 | 0.32 | ||||||||||
| Cash flows from operating activities | 360,034 | 198,974 | 171,876 | 559,008 | 292,856 | ||||||||||
| Per share - basic | 0.63 | 0.35 | 0.30 | 0.99 | 0.52 | ||||||||||
| Per share - diluted | 0.63 | 0.35 | 0.30 | 0.98 | 0.52 | ||||||||||
| Net income | 180,972 | 56,858 | 1,052,999 | 237,830 | 1,017,647 | ||||||||||
| Per share - basic | 0.32 | 0.10 | 1.87 | 0.42 | 1.81 | ||||||||||
| Per share - diluted | 0.32 | 0.10 | 1.85 | 0.42 | 1.79 | ||||||||||
| Capital Expenditures | |||||||||||||||
| Exploration and development expenditures | $ | 96,633 | $ | 153,822 | $ | 61,485 | $ | 250,455 | $ | 145,073 | |||||
| Acquisitions and divestitures | 194 | 32 | (18 | ) | 226 | (221 | ) | ||||||||
| Total oil and natural gas capital expenditures | $ | 96,827 | $ | 153,854 | $ | 61,467 | $ | 250,681 | $ | 144,852 | |||||
| Net Debt | |||||||||||||||
| Credit facilities | $ | 496,917 | $ | 426,858 | $ | 486,623 | $ | 496,917 | $ | 486,623 | |||||
| Long-term notes | 643,600 | 873,880 | 1,109,211 | 643,600 | 1,109,211 | ||||||||||
| Long-term debt | 1,140,517 | 1,300,738 | 1,595,834 | 1,140,517 | 1,595,834 | ||||||||||
| Working capital | (17,220 | ) | (25,058 | ) | 33,795 | (17,220 | ) | 33,795 | |||||||
| Net debt (1) | $ | 1,123,297 | $ | 1,275,680 | $ | 1,629,629 | $ | 1,123,297 | $ | 1,629,629 | |||||
| Shares Outstanding - basic (thousands) | |||||||||||||||
| Weighted average | 566,997 | 565,518 | 564,156 | 566,262 | 563,126 | ||||||||||
| End of period | 560,139 | 569,214 | 564,182 | 560,139 | 564,182 | ||||||||||
| BENCHMARK PRICES | |||||||||||||||
| Crude oil | |||||||||||||||
| WTI (US$/bbl) | $ | 108.41 | $ | 94.29 | $ | 66.07 | $ | 101.35 | $ | 61.96 | |||||
| MEH oil (US$/bbl) | 112.41 | 96.72 | 67.15 | 104.56 | 63.26 | ||||||||||
| MEH oil differential to WTI (US$/bbl) | 4.00 | 2.43 | 1.08 | 3.21 | 1.30 | ||||||||||
| Edmonton par ($/bbl) | 137.79 | 115.66 | 77.28 | 126.72 | 71.93 | ||||||||||
| Edmonton par differential to WTI (US$/bbl) | (0.47 | ) | (2.94 | ) | (3.13 | ) | (1.68 | ) | (4.28 | ) | |||||
| WCS heavy oil ($/bbl) | 122.05 | 100.99 | 67.03 | 111.48 | 62.33 | ||||||||||
| WCS differential to WTI (US$/bbl) | (12.80 | ) | (14.53 | ) | (11.48 | ) | (13.67 | ) | (11.98 | ) | |||||
| Natural gas | |||||||||||||||
| NYMEX (US$/mmbtu) | $ | 7.17 | $ | 4.95 | $ | 2.83 | $ | 6.06 | $ | 2.76 | |||||
| AECO ($/mcf) | 6.27 | 4.59 | 2.85 | 5.43 | 2.89 | ||||||||||
| CAD/USD average exchange rate | 1.2766 | 1.2661 | 1.2279 | 1.2714 | 1.2471 | ||||||||||
| Three Months Ended | Six Months Ended | ||||||||||||||
| June 30, 2022 | March 31, 2022 | June 30, 2021 | June 30, 2022 | June 30, 2021 | |||||||||||
| OPERATING | |||||||||||||||
| Daily Production | |||||||||||||||
| Light oil and condensate (bbl/d) | 33,007 | 34,065 | 37,134 | 33,533 | 36,286 | ||||||||||
| Heavy oil (bbl/d) | 28,586 | 25,236 | 21,269 | 26,921 | 21,627 | ||||||||||
| NGL (bbl/d) | 7,468 | 7,636 | 7,563 | 7,552 | 6,904 | ||||||||||
| Total liquids (bbl/d) | 69,061 | 66,937 | 65,966 | 68,006 | 64,817 | ||||||||||
| Natural gas (mcf/d) | 84,169 | 83,574 | 91,172 | 83,873 | 90,957 | ||||||||||
| Oil equivalent (boe/d @ 6:1) (3) | 83,090 | 80,867 | 81,162 | 81,985 | 79,978 | ||||||||||
| Netback (thousands of Canadian dollars) | |||||||||||||||
| Total sales, net of blending and other expense (2) | $ | 797,274 | $ | 632,385 | $ | 422,387 | $ | 1,429,659 | $ | 789,969 | |||||
| Royalties | (171,559 | ) | (122,720 | ) | (81,531 | ) | (294,279 | ) | (148,481 | ) | |||||
| Operating expense | (107,426 | ) | (100,766 | ) | (82,901 | ) | (208,192 | ) | (163,449 | ) | |||||
| Transportation expense | (11,758 | ) | (9,215 | ) | (7,486 | ) | (20,973 | ) | (16,274 | ) | |||||
| Operating netback (2) | $ | 506,531 | $ | 399,684 | $ | 250,469 | $ | 906,215 | $ | 461,765 | |||||
| General and administrative | (11,640 | ) | (11,682 | ) | (10,610 | ) | (23,322 | ) | (19,343 | ) | |||||
| Cash financing and interest | (20,474 | ) | (20,427 | ) | (23,554 | ) | (40,901 | ) | (47,957 | ) | |||||
| Realized financial derivatives loss | (124,042 | ) | (84,366 | ) | (39,024 | ) | (208,408 | ) | (59,792 | ) | |||||
| Other (4) | (4,671 | ) | (3,602 | ) | (1,398 | ) | (8,273 | ) | (2,208 | ) | |||||
| Adjusted funds flow (1) | $ | 345,704 | $ | 279,607 | $ | 175,883 | $ | 625,311 | $ | 332,465 | |||||
| Netback (per boe) (5) | |||||||||||||||
| Total sales, net of blending and other expense (2) | $ | 105.44 | $ | 86.89 | $ | 57.19 | $ | 96.34 | $ | 54.57 | |||||
| Royalties | (22.69 | ) | (16.86 | ) | (11.04 | ) | (19.83 | ) | (10.26 | ) | |||||
| Operating expense | (14.21 | ) | (13.85 | ) | (11.22 | ) | (14.03 | ) | (11.29 | ) | |||||
| Transportation expense | (1.56 | ) | (1.27 | ) | (1.01 | ) | (1.41 | ) | (1.12 | ) | |||||
| Operating netback (2) | $ | 66.98 | $ | 54.91 | $ | 33.92 | $ | 61.07 | $ | 31.90 | |||||
| General and administrative | (1.54 | ) | (1.61 | ) | (1.44 | ) | (1.57 | ) | (1.34 | ) | |||||
| Cash financing and interest | (2.71 | ) | (2.81 | ) | (3.19 | ) | (2.76 | ) | (3.31 | ) | |||||
| Realized financial derivatives loss | (16.41 | ) | (11.59 | ) | (5.28 | ) | (14.04 | ) | (4.13 | ) | |||||
| Other (4) | (0.60 | ) | (0.48 | ) | (0.20 | ) | (0.56 | ) | (0.15 | ) | |||||
| Adjusted funds flow (1) | $ | 45.72 | $ | 38.42 | $ | 23.81 | $ | 42.14 | $ | 22.97 | |||||
Notes:
(1) Capital management measure. Refer to the Specified Financial Measures section in this press release for further information.
(2) Specified financial measure that does not have any standardized meaning prescribed by IFRS and may not be comparable with the calculation of similar measures presented by other entities. Refer to the Specified Financial Measures section in this press release for further information.
(3) Barrel of oil equivalent ("boe") amounts have been calculated using a conversion rate of six thousand cubic feet of natural gas to one barrel of oil. The use of boe amounts may be misleading, particularly if used in isolation. A boe conversion ratio of six thousand cubic feet of natural gas to one barrel of oil is based on an energy equivalency conversion method primarily applicable at the burner tip and does not represent a value equivalency at the wellhead.
(4) Other is comprised of realized foreign exchange gain or loss, other income or expense, current income tax expense or recovery and cash share-based compensation. Refer to the Q2/2022 MD&A for further information on these amounts.
(5) Calculated as royalties, operating, transportation, general and administrative, cash financing and interest expense or realized financial derivatives loss divided by barrels of oil equivalent production volume for the applicable period.
Q2/2022 Results
In Q2/2022, we delivered strong operating and financial results and continued to advance our exciting new Clearwater play in northwest Alberta.
Production during the second quarter averaged 83,090 boe/d (83% oil and NGL) as compared to 80,867 boe/d (82% oil and NGL) in Q1/2022. The increased production is consistent with our full-year plan and reflects the success of our first quarter drilling program at Peavine, which more than offset the seasonality associated with spring breakup and wet weather conditions across western Canada.
Exploration and development expenditures totaled $97 million in Q2/2022 and we participated in the drilling of 37 (21.4 net) wells with a 100% success rate.
We delivered adjusted funds flow(1) of $346 million ($0.61 per basic share) and net income of $181 million ($0.32 per basic share). We generated a record level of quarterly free cash flow(2) of $245 million ($0.43 per basic share) and reduced net debt(1) by 12% to $1.12 billion, from $1.28 billion at March 31, 2022.
Operating Results
Eagle Ford and Viking Light Oil
Production in the Eagle Ford averaged 28,170 boe/d (82% oil and NGL) during Q2/2022 and generated an operating netback(2) of $168 million. We invested $45 million on exploration and development in the Eagle Ford during the quarter and brought 20 (3.8 net) wells onstream. We expect to bring approximately 18 net wells onstream in 2022.
Production in the Viking averaged 16,487 boe/d (87% oil and NGL) during Q2/2022 and generated an operating netback of $140 million. We invested $15 million on exploration and development in the Viking during the quarter and brought 9 (8.2 net) wells onstream. We expect to bring approximately 130 net wells onstream in 2022.
Heavy Oil
Our heavy oil assets at Peace River and Lloydminster (excluding our Clearwater development program) produced a combined 23,683 boe/d (90% oil and NGL) during Q2/2022 and generated an operating netback of $122 million. We invested $16 million on exploration and development during the quarter and brought onstream 3 net Bluesky wells at Peace River and 5.8 net wells at Lloydminster. In 2022, we will drill approximately 9 net Bluesky wells at Peace River and 31 net wells at Lloydminster.
Peace River Clearwater
Production in the Clearwater averaged 7,319 boe/d (100% oil) during Q2/2022 and generated an operating netback of $48 million. Production during the second quarter was curtailed by approximately 650 bbl/d due to spring break-up and road maintenance that led to the shut-in of our 4-25 pad for two weeks in May. Production during the month of June averaged 9,088 bbl/d from 18 producing wells.
We followed up our 2021 appraisal program on our Peavine acreage with an exceptional Q1/2022 drilling program. During the second quarter, the remaining four wells from our 10-well Q1/2022 drilling program were brought onstream and all ten wells have now established 30-day initial production rates. The average 30-day initial production rate per well for these 10 wells is 772 bbl/d. Initial well performance continues to outperform type curve assumptions and we now hold nine of the top ten initial rate wells drilled to date across the play.
Our second half drilling program kicked off in July and we expect to drill 14 additional Clearwater wells, including 13 wells at Peavine and one well at Seal that follows up a successful exploration well from 2021. The first two wells from the H2/2022 drilling program are scheduled to be onstream mid-August.
At current commodity prices, the Clearwater generates among the strongest economics within our portfolio with payouts of less than three months and has the ability to grow organically while enhancing our free cash flow profile. To-date, we have de-risked 50 sections (of our 80-section Peavine land base) and believe the lands hold the potential for greater than 200 locations. When combined with our legacy acreage position in northwest Alberta, we estimate that over 125 sections of our lands are highly prospective for Clearwater development.
(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.
Pembina Area Duvernay Light Oil
Production in the Pembina Duvernay averaged 1,756 boe/d (81% oil and NGL) during Q2/2022.
We continue to advance the delineation of the Pembina Duvernay Shale, an early stage, high operating netback light oil resource play. During the second quarter, we completed a three-well pad that was drilled during the first quarter. All three wells are now flowing back and initial results are encouraging and tracking to type well forecast. The wells flow to a Baytex operated oil battery with solution gas being processed at a third party deep cut facility. The three wells, each drilled to a vertical depth of 2,400 metres with a horizontal lateral of 1.85 miles, were drilled and completed on budget at approximately $8.1 million per well. Across our Pembina acreage, we hold 200 sections of 100% working interest lands.
Financial Liquidity
On June 1, 2022, we redeemed the remaining US$200 million principal amount of 5.625% long-term notes due 2024 at par. Following this, our net debt(1), which includes our credit facilities, long-term notes and working capital, totaled $1.12 billion at June 30, 2022, down from $1.41 billion at December 31, 2021.
As of June 30, 2022, we had $582 million of undrawn capacity on our credit facilities, resulting in liquidity, net of working capital, of $599 million.
Risk Management
To manage commodity price movements, we utilize various financial derivative contracts and crude-by-rail to reduce the volatility of our adjusted funds flow.
For the second half of 2022, we have entered into hedges on approximately 40% of our net crude oil exposure utilizing a combination of a 3-way option structure that provides price protection at US$57.76/bbl with upside participation to US$67.51/bbl and swaptions at US$53.50/bbl. We also have WTI-MSW differential hedges on approximately 25% of our expected net Canadian light oil exposure at US$4.43/bbl and WCS differential hedges on approximately 70% of our expected net heavy oil exposure at a WTI-WCS differential of approximately US$12.28/bbl.
For 2023, we have entered into hedges on approximately 18% of our net crude oil exposure utilizing a 3-way option structure that provides price protection at US$78.37/bbl with upside participation to US$96.12/bbl
A complete listing of our financial derivative contracts can be found in Note 16 to our Q2/2022 financial statements.
(1) Capital management measure. Refer to the Specified Financial Measures section in this press release for further information.
Additional Information
Our condensed consolidated interim unaudited financial statements for the three and six months ended June 30, 2022 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.
| Conference Call Tomorrow 9:00 a.m. MDT (11:00 a.m. EDT) |
| Baytex will host a conference call tomorrow, July 28, 2022, starting at 9:00am MDT (11:00am EDT). 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 http://services.choruscall.ca/links/baytex20220728.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: our plan to increase direct shareholder returns to 50% of free cash flow and accelerate our share buyback program on reaching net debt of $800 million in late 2022 or early 2023; that our shares are undervalued in relation to current operations; our focus on strong capital discipline and generating free cash flow; that we expect exploration and development expenditures toward the high end of our guidance range and to generate $700 million ($1.25 per basic share) of free cash flow in 2022; our revised guidance for 2022 exploration and development expenditures, production, royalty rate, operating, transportation, general and administration and interest expense and leasing expenditures and asset retirement obligations; our expected 1.0x net debt to EBITDA ratio at a US$45 WTI price when we reach our $400 million net debt target; that we will have flexibility to run our business through commodity price cycles and generate meaningful shareholder returns when our net debt target of $400 million is reached; that we expect to reach our $400 million net debt target by the end of 2023 and will consider steps to further enhance shareholder returns once reached; our CEO’s intention to retire in January 2023; that Mr. LaFehr will lead the execution of the 2022 plan and 2023 budget preparation, which includes advancing our shareholder return framework; in 2022 that we expect to: bring on production 18 net wells in the Eagle Ford and 130 in the Viking; that we expect to drill 9 net Bluesky wells at Peace River and 31 net wells at Lloydminster in 2022; we plan to drill 14 additional Clearwater wells in H2/2022, with the first two wells on-stream mid-August; that the Clearwater generates among the strongest economics in our portfolio with payouts of less than three months and has the ability to grow organically while enhancing our free cash flow profile; to date we have de-risked 50 sections of Peavine lands which hold the potential for 200 locations; we have over 125 sections that are highly prospective for Clearwater development; we use financial derivative contracts and crude-by-rail to reduce adjusted funds flow volatility; the percentage of our net exposure to crude oil, the WTI-MSW differential and WCS differential that we have hedged for 2022 and the percentage of our net exposure to crude oil that we have hedged 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; 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 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.
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 free cash flow and operating netback are commonly used in the oil and 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.
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 June 30 | Six Months Ended June 30 | |||||||||||
| ($ thousands) | 2022 | 2021 | 2022 | 2021 | ||||||||
| Petroleum and natural gas sales | $ | 854,169 | $ | 442,354 | $ | 1,527,994 | $ | 827,056 | ||||
| Blending and other expense | (56,895 | ) | (19,967 | ) | (98,335 | ) | (37,087 | ) | ||||
| Total sales, net of blending and other expense | 797,274 | 422,387 | 1,429,659 | 789,969 | ||||||||
| Royalties | (171,559 | ) | (81,531 | ) | (294,279 | ) | (148,481 | ) | ||||
| Operating expense | (107,426 | ) | (82,901 | ) | (208,192 | ) | (163,449 | ) | ||||
| Transportation expense | (11,758 | ) | (7,486 | ) | (20,973 | ) | (16,274 | ) | ||||
| Operating netback | $ | 506,531 | $ | 250,469 | $ | 906,215 | $ | 461,765 | ||||
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 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.
Free cash flow is reconciled to cash flows from operating activities in the following table.
| Three Months Ended June 30 | Six Months Ended June 30 | |||||||||||
| ($ thousands) | 2022 | 2021 | 2022 | 2021 | ||||||||
| Cash flows from operating activities | $ | 360,034 | $ | 171,876 | $ | 559,008 | $ | 292,856 | ||||
| Change in non-cash working capital | (17,046 | ) | 3,014 | 60,294 | 37,199 | |||||||
| Additions to exploration and evaluation assets | (2,338 | ) | (428 | ) | (5,897 | ) | (644 | ) | ||||
| Additions to oil and gas properties | (94,295 | ) | (61,057 | ) | (244,558 | ) | (144,429 | ) | ||||
| Payments on lease obligations | (1,039 | ) | (919 | ) | (2,213 | ) | (2,001 | ) | ||||
| Free cash flow | $ | 245,316 | $ | 112,486 | $ | 366,634 | $ | 182,981 | ||||
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
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.
The following table summarizes our calculation of net debt.
| ($ thousands) | June 30, 2022 | December 31, 2021 | ||||
| Credit facilities | $ | 494,410 | $ | 505,171 | ||
| Unamortized debt issuance costs - Credit facilities (1) | 2,507 | 1,343 | ||||
| Long-term notes | 634,758 | 874,527 | ||||
| Unamortized debt issuance costs - Long-term notes (1) | 8,842 | 11,393 | ||||
| Trade and other payables | 309,163 | 190,692 | ||||
| Trade and other receivables | (326,383 | ) | (173,409 | ) | ||
| Net debt | $ | 1,123,297 | $ | 1,409,717 |
(1) Unamortized debt issuance costs were obtained from Note 6 - Credit Facilities and Note 7 - Long-term Notes from the consolidated financial statements for the three and six months ended June 30, 2022.
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 June 30 | Six Months Ended June 30 | |||||||||||
| ($ thousands) | 2022 | 2021 | 2022 | 2021 | ||||||||
| Cash flow from operating activities | $ | 360,034 | $ | 171,876 | $ | 559,008 | $ | 292,856 | ||||
| Change in non-cash working capital | (17,046 | ) | 3,014 | 60,294 | 37,199 | |||||||
| Asset retirement obligations settled | 2,716 | 993 | 6,009 | 2,410 | ||||||||
| Adjusted funds flow | $ | 345,704 | $ | 175,883 | $ | 625,311 | $ | 332,465 | ||||
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 news release, "oil and NGL" refers to heavy oil, bitumen, light and medium 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 and six months ended June 30, 2022. The NI 51-101 product types are included as follows: "Heavy Oil" - heavy oil and bitumen, "Light and Medium Oil" - light and medium oil, tight oil and condensate, "NGL" - natural gas liquids and "Natural Gas" - shale gas and conventional natural gas. All production from our Peavine asset is 100% Heavy Oil.
| Three Months Ended June 30, 2022 | Six Months Ended June 30, 2022 | |||||||||||||||||||||||||||||||
| Heavy Oil (bbl/d) | Light and Medium Oil (bbl/d) | NGL (bbl/d) | Natural Gas (Mcf/d) | Oil Equivalent (boe/d) | Heavy Oil (bbl/d) | Light and Medium Oil (bbl/d) | NGL (bbl/d) | Natural Gas (Mcf/d) | Oil Equivalent (boe/d) | |||||||||||||||||||||||
| Canada - Heavy | ||||||||||||||||||||||||||||||||
| Peace River | 10,216 | 10 | 31 | 12,471 | 12,336 | 10,898 | 8 | 30 | 11,801 | 12,902 | ||||||||||||||||||||||
| Lloydminster | 11,051 | 8 | - | 1,729 | 11,347 | 10,775 | 11 | - | 1,758 | 11,079 | ||||||||||||||||||||||
| Peavine | 7,319 | - | - | - | 7,319 | 5,248 | - | - | - | 5,248 | ||||||||||||||||||||||
| Canada - Light | ||||||||||||||||||||||||||||||||
| Viking | - | 14,103 | 184 | 13,202 | 16,487 | - | 14,894 | 186 | 12,552 | 17,172 | ||||||||||||||||||||||
| Duvernay | - | 801 | 620 | 2,007 | 1,756 | - | 896 | 705 | 2,174 | 1,963 | ||||||||||||||||||||||
| Remaining Properties | - | 753 | 983 | 23,627 | 5,674 | - | 810 | 956 | 24,158 | 5,792 | ||||||||||||||||||||||
| United States | ||||||||||||||||||||||||||||||||
| Eagle Ford | - | 17,332 | 5,650 | 31,133 | 28,170 | - | 16,914 | 5,675 | 31,430 | 27,828 | ||||||||||||||||||||||
| Total | 28,586 | 33,007 | 7,468 | 84,169 | 83,090 | 26,921 | 33,533 | 7,552 | 83,873 | 81,985 | ||||||||||||||||||||||
This press release discloses drilling inventory and potential drilling locations. Drilling inventory and drilling locations refers to Baytex's proved, probable and unbooked locations. Proved locations and probable locations account for drilling locations in our inventory that have associated proved and/or probable reserves. Unbooked locations are internal estimates based on our prospective acreage and an assumption as to the number of wells that can be drilled per section based on industry practice and internal review. Unbooked locations do not have attributed reserves. Unbooked locations are farther away from existing wells and, therefore, there is more uncertainty whether wells will be drilled in such locations and if drilled there is more uncertainty whether such wells will result in additional oil and gas reserves, resources or production. Of the 200 or more potential drilling locations identified in the Clearwater, as at December 31, 2021, 4 are proved locations, 5 are probable locations and the remainder are unbooked locations.
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 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/132077
