Calgary, Alberta–(Newsfile Corp. – February 23, 2023) – Baytex Energy Corp. (TSX: BTE) (NYSE: BTE) (“Baytex”) reports its operating and financial results for the three months and year ended December 31, 2022 (all amounts are in Canadian dollars unless otherwise noted).
“2022 was an exciting year for Baytex as we delivered strong operating results, generated record free cash flow, further strengthened our balance sheet and initiated direct shareholder returns. We generated a 4% year-over-year increase in production, repurchased 4.3% of our shares outstanding and reduced net debt by 30%. We expect another strong year in 2023 as we advance development across our high-quality oil weighted portfolio, further delineate our Peavine Clearwater acreage and progress our Duvernay light oil resource play. At current commodity prices, we anticipate hitting our next debt target during the third quarter at which point we intend to increase direct shareholder returns to 50% of our free cash flow,” commented Eric T. Greager, President and Chief Executive Officer.
2022 Highlights
- Generated production of 86,864 boe/d (84% oil and NGL) in Q4/2022, an 8% increase over Q4/2021. Production for the full-year 2022 averaged 83,519 boe/d (84% oil and NGL), a 4% increase over 2021.
- Delivered adjusted funds flow(1) of $256 million ($0.47 per basic share) in Q4/2022 and $1,165 million ($2.09 per basic share) for 2022.
- Generated free cash flow(2) of $143 million ($0.26 per basic share) in Q4/2022 and $622 million ($1.11 per basic share) for 2022.
- Cash flows from operating activities was $303 million ($0.56 per basic share) in Q4/2022 and $1,173 million ($2.10 per basic share) for 2022.
- Exploration and development expenditures totaled $104 million in Q4/2022, bringing aggregate spending for 2022 to $522 million.
- Reduced net debt(1) by 30% in 2022 to $987 million, from $1.4 billion at year-end 2021.
- Repurchased 24.3 million common shares in 2022, representing 4.3% of our shares outstanding, at an average price of $6.54 per share.
- Reduced our GHG emissions intensity in 2022 by 15% from 2021 levels and have now achieved a 59% reduction, relative to our 2018 baseline.
- At year-end 2022, proved developed producing (“PDP”) reserves total 124 MMboe, proved reserves (“1P”) total 264 MMboe and proved plus probable reserves (“2P”) total 438 MMboe(3). We generated a PDP recycle ratio of 2.8x and a 1P recycle ratio of 1.4x based on a 2022 operating netback(2) of $54.64/boe.
- The present value of our reserves, discounted at 10% before tax, is estimated to be $5.9 billion ($5.1 billion at year-end 2021). The increase is largely attributable to a higher commodity price forecast being utilized by our reserves evaluator (consultant average of approximately US$81/bbl WTI).
- Our net asset value at year-end 2022, discounted at 10% before tax, is $9.28 per share. This is based on the estimated reserves value plus a value for undeveloped acreage, net of long-term debt and working capital.
(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) Baytex’s year-end 2022 reserves were evaluated by McDaniel & Associates Consultants Ltd. (“McDaniel”), an independent qualified reserves evaluator, in accordance with National Instrument 51-101 “Standards of Disclosure for Oil and Gas Activities” (“NI 51-101”).
| Three Months Ended | Twelve Months Ended | |||||||||||||
| December 31, 2022 | September 30, 2022 | December 31, 2021 | December 31, 2022 | December 31, 2021 | ||||||||||
| FINANCIAL (thousands of Canadian dollars, except per common share amounts) | ||||||||||||||
| Petroleum and natural gas sales | $ | 648,986 | $ | 712,065 | $ | 552,403 | $ | 2,889,045 | $ | 1,868,195 | ||||
| Adjusted funds flow (1) | 255,552 | 284,288 | 214,766 | 1,165,151 | 745,628 | |||||||||
| Per share – basic | 0.47 | 0.51 | 0.38 | 2.09 | 1.32 | |||||||||
| Per share – diluted | 0.46 | 0.51 | 0.37 | 2.07 | 1.30 | |||||||||
| Free cash flow (2) | 143,324 | 111,568 | 137,133 | 621,526 | 421,329 | |||||||||
| Per share – basic | 0.26 | 0.20 | 0.24 | 1.11 | 0.75 | |||||||||
| Per share – diluted | 0.26 | 0.20 | 0.24 | 1.10 | 0.74 | |||||||||
| Cash flows from operating activities | 303,441 | 310,423 | 240,567 | 1,172,872 | 712,384 | |||||||||
| Per share – basic | 0.56 | 0.56 | 0.43 | 2.10 | 1.26 | |||||||||
| Per share – diluted | 0.55 | 0.56 | 0.42 | 2.08 | 1.25 | |||||||||
| Net income (loss) | 352,807 | 264,968 | 563,239 | 855,605 | 1,613,600 | |||||||||
| Per share – basic | 0.65 | 0.48 | 1.00 | 1.53 | 2.86 | |||||||||
| Per share – diluted | 0.64 | 0.47 | 0.98 | 1.52 | 2.82 | |||||||||
| Capital Expenditures | ||||||||||||||
| Exploration and development expenditures | $ | 103,634 | $ | 167,453 | $ | 73,995 | $ | 521,542 | $ | 313,303 | ||||
| Acquisitions and divestitures | 937 | (25,460) | (5,414) | (24,297) | (6,247) | |||||||||
| Total oil and natural gas capital expenditures | $ | 104,571 | $ | 141,993 | $ | 68,581 | $ | 497,245 | $ | 307,056 | ||||
| Net Debt | ||||||||||||||
| Credit facilities | $ | 385,394 | $ | 450,051 | $ | 506,514 | $ | 385,394 | $ | 506,514 | ||||
| Long-term notes | 554,597 | 648,207 | 885,920 | 554,597 | 885,920 | |||||||||
| Long-term debt | 939,991 | 1,098,258 | 1,392,434 | 939,991 | 1,392,434 | |||||||||
| Working capital deficiency | 47,455 | 15,301 | 17,283 | 47,455 | 17,283 | |||||||||
| Net debt (1) | $ | 987,446 | $ | 1,113,559 | $ | 1,409,717 | $ | 987,446 | $ | 1,409,717 | ||||
| Shares Outstanding – basic (thousands) | ||||||||||||||
| Weighted average | 546,279 | 553,409 | 564,213 | 557,986 | 563,674 | |||||||||
| End of period | 544,930 | 547,615 | 564,213 | 544,930 | 564,213 | |||||||||
| BENCHMARK PRICES | ||||||||||||||
| Crude oil | ||||||||||||||
| WTI (US$/bbl) | $ | 82.64 | $ | 91.56 | $ | 77.19 | $ | 94.23 | $ | 67.92 | ||||
| MEH oil (US$/bbl) | 85.88 | 96.15 | 78.89 | 97.79 | 69.26 | |||||||||
| MEH oil differential to WTI (US$/bbl) | 3.24 | 4.59 | 1.70 | 3.57 | 1.34 | |||||||||
| Edmonton par ($/bbl) | 109.57 | 116.79 | 93.29 | 119.95 | 80.23 | |||||||||
| Edmonton par differential to WTI (US$/bbl) | (1.94) | (2.13) | (3.15) | (2.07) | (3.92) | |||||||||
| WCS heavy oil ($/bbl) | 77.37 | 93.62 | 78.82 | 98.94 | 68.79 | |||||||||
| WCS differential to WTI (US$/bbl) | (25.65) | (19.87) | (14.63) | (18.21) | (13.05) | |||||||||
| Natural gas | ||||||||||||||
| NYMEX (US$/mmbtu) | $ | 6.26 | $ | 8.20 | $ | 5.83 | $ | 6.64 | $ | 3.84 | ||||
| AECO ($/mcf) | 5.58 | 5.81 | 4.94 | 5.56 | 3.56 | |||||||||
| CAD/USD average exchange rate | 1.3577 | 1.3059 | 1.2600 | 1.3016 | 1.2536 | |||||||||
| Three Months Ended | Twelve Months Ended | |||||||||||||
| December 31, 2022 | September 30, 2022 | December 31, 2021 | December 31, 2022 | December 31, 2021 | ||||||||||
| OPERATING | ||||||||||||||
| Daily Production | ||||||||||||||
| Light oil and condensate (bbl/d) | 32,105 | 33,247 | 34,986 | 33,101 | 35,789 | |||||||||
| Heavy oil (bbl/d) | 32,819 | 29,244 | 23,482 | 28,993 | 22,188 | |||||||||
| NGL (bbl/d) | 7,661 | 7,536 | 7,984 | 7,575 | 7,244 | |||||||||
| Total liquids (bbl/d) | 72,585 | 70,027 | 66,452 | 69,669 | 65,221 | |||||||||
| Natural gas (mcf/d) | 85,679 | 79,003 | 86,029 | 83,101 | 89,606 | |||||||||
| Oil equivalent (boe/d @ 6:1) (1) | 86,864 | 83,194 | 80,789 | 83,519 | 80,156 | |||||||||
| Netback (thousands of Canadian dollars) | ||||||||||||||
| Total sales, net of blending and other expense (2) | $ | 598,812 | $ | 671,120 | $ | 523,382 | $ | 2,699,591 | $ | 1,782,506 | ||||
| Royalties | (121,691) | (146,994) | (100,152) | (562,964) | (339,156) | |||||||||
| Operating expense | (104,335) | (110,139) | (95,357) | (422,666) | (343,002) | |||||||||
| Transportation expense | (14,817) | (12,771) | (8,169) | (48,561) | (32,261) | |||||||||
| Operating netback (2) | $ | 357,969 | $ | 401,216 | $ | 319,704 | $ | 1,665,400 | $ | 1,068,087 | ||||
| General and administrative | (14,945) | (12,003) | (11,481) | (50,270) | (40,804) | |||||||||
| Cash financing and interest | (19,711) | (19,774) | (21,319) | (80,386) | (92,069) | |||||||||
| Realized financial derivatives loss | (49,665) | (76,408) | (70,544) | (334,481) | (184,241) | |||||||||
| Other (3) | (18,096) | (8,743) | (1,594) | (35,112) | (5,345) | |||||||||
| Adjusted funds flow (4) | $ | 255,552 | $ | 284,288 | $ | 214,766 | $ | 1,165,151 | $ | 745,628 | ||||
| Netback per boe (5) | ||||||||||||||
| Total sales, net of blending and other expense (2) | $ | 74.93 | $ | 87.68 | $ | 70.42 | $ | 88.56 | $ | 60.93 | ||||
| Royalties | (15.23) | (19.21) | (13.47) | (18.47) | (11.59) | |||||||||
| Operating expense | (13.06) | (14.39) | (12.83) | (13.86) | (11.72) | |||||||||
| Transportation expense | (1.85) | (1.67) | (1.10) | (1.59) | (1.10) | |||||||||
| Operating netback (2) | $ | 44.79 | $ | 52.41 | $ | 43.02 | $ | 54.64 | $ | 36.52 | ||||
| General and administrative | (1.87) | (1.57) | (1.54) | (1.65) | (1.39) | |||||||||
| Cash financing and interest | (2.47) | (2.58) | (2.87) | (2.64) | (3.15) | |||||||||
| Realized financial derivatives loss | (6.21) | (9.98) | (9.49) | (10.97) | (6.30) | |||||||||
| Other (3) | (2.26) | (1.14) | (0.23) | (1.16) | (0.19) | |||||||||
| Adjusted funds flow (4) | $ | 31.98 | $ | 37.14 | $ | 28.89 | $ | 38.22 | $ | 25.49 | ||||
Notes:
(1) Barrel of oil equivalent (“boe”) amounts have been calculated using a conversion rate of six thousand cubic feet of natural gas to one barrel of oil. The use of boe amounts may be misleading, particularly if used in isolation. A boe conversion ratio of six thousand cubic feet of natural gas to one barrel of oil is based on an energy equivalency conversion method primarily applicable at the burner tip and does not represent a value equivalency at the wellhead.
(2) Specified financial measure that does not have any standardized meaning prescribed by IFRS and may not be comparable with the calculation of similar measures presented by other entities. Refer to the Specified Financial Measures section in this press release for further information.
(3) Other is comprised of realized foreign exchange gain or loss, other income or expense, current income tax expense or recovery and share-based compensation. Refer to the 2022 MD&A for further information on these amounts.
(4) Capital management measure. Refer to the Specified Financial Measures section in this press release for further information.
(5) Calculated as royalties, operating or transportation expense divided by barrels of oil equivalent production volume for the applicable period.
2023 Outlook
In 2023, 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 increasing direct shareholder returns. Our 2023 guidance remains unchanged as we target production of 86,000 to 89,000 boe/d with exploration and development expenditures of $575 to $650 million.
Based on the forward strip(1), we expect to generate approximately $450 million of free cash flow(2) in 2023. We expect to reach a net debt(3) level of $800 million during Q3/2023, at which time, we anticipate increasing direct shareholder returns to 50% of our free cash flow and accelerating our share buyback program.
The following table highlights our 2023 annual guidance.
| 2023 Guidance | |
| Exploration and development expenditures | $575 – $650 million |
| Production (boe/d) | 86,000 – 89,000 |
| Expenses: | |
| Average royalty rate (2) | 20.0% – 22.0% |
| Operating (4) | $14.00 – $14.75/boe |
| Transportation (4) | $1.90 – $2.10/boe |
| General and administrative (4) | $52 million ($1.63/boe) |
| Interest (4) | $65 million ($2.04/boe) |
| Leasing expenditures | $4 million |
| Asset retirement obligations | $25 million |
2022 Results
In 2022, we delivered strong strong operating results and further strengthened our business. We generated record free cash flow of $622 million ($1.11 per basic share), up from $421 million ($0.75 per basic share) in 2021.
During 2022, we initiated direct shareholder returns, allocating 25% of annual free cash flow to a share buyback program with 75% of free cash flow allocated to debt reduction. We repurchased 24.3 million common shares for $159 million, representing 4.3% of our shares outstanding, at an average price of $6.54 per share. In addition, we significantly strengthened our balance sheet, reducing net debt by 30% to $987 million, representing a net debt to EBITDA(5) ratio (trailing twelve months) of 0.8x.
Production for the full-year 2022 averaged 83,519 boe/d, a 4% increase compared to 80,156 boe/d in 2021, and consistent with our annual guidance. Production in Q4/2022 averaged 86,864 boe/d (84% oil and NGL), an 8% increase compared to 80,789 boe/d (82% oil and NGL) in Q4/2021. During the fourth quarter, production was reduced by approximately 1,500 boe/d due to extreme cold weather conditions during the month of December.
We maintained capital discipline despite inflationary pressures across our portfolio that was consistent with the industry and broader economy. Exploration and development expenditures totaled $104 million in Q4/2022 and $522 million for full-year 2022. We participated in the drilling of 269 (212.2 net) wells.
We delivered adjusted funds flow(3) of $256 million ($0.47 per basic share) in Q4/2022 and $1,165 million ($2.09 per basic share) in 2022. We recorded net income of $353 million ($0.65 per basic share) in Q4/2022 and $855.6 million ($1.53 per basic share) in 2022. During Q4/2022, we reversed $268 million of previously recorded impairments on our assets primarily as a result of higher forecasted commodity prices.
(1) 2023 pricing assumptions: WTI – US$75/bbl; WCS differential – US$19/bbl; MSW differential – US$2/bbl, NYMEX Gas – US$3.05/MMbtu; AECO Gas – $2.95/mcf and Exchange Rate (CAD/USD) – 1.35.
(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) Calculated as operating, transportation, general and administrative or interest expense divided by barrels of oil equivalent production volume for the applicable period.
(5) Calculated in accordance with the Credit Facilities Agreement.
Operating Results
Light Oil
Production in the Eagle Ford averaged 29,918 boe/d (78% oil and NGL) during Q4/2022 and 28,245 boe/d for the full-year 2022. In 2022, we invested $141 million on exploration and development in the Eagle Ford and generated an operating netback(1) of $582 million. During 2022, we participated in the drilling of 64 (15.8 net) wells and brought 68 (16.8 net) wells onstream. We expect to bring approximately 15 net wells onstream in 2023.
Production in the Viking averaged 14,625 boe/d (87% oil and NGL) during Q4/2022 and 16,239 boe/d for the full-year 2022. In 2022, we invested $168 million on exploration and development in the Viking and generated an operating netback of $479 million. During 2022, we drilled 137 (131.3 net) wells and brought 132 (126.9 net) wells onstream. We expect to bring approximately 144 net wells onstream in 2023.
Production in the Pembina Duvernay averaged 3,058 boe/d (81% oil and NGL) during Q4/2022 and 2,603 boe/d for the full-year 2022. In the Duvernay, we drilled a three-well pad in 2022 that provided increased 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.
Heavy Oil
Our heavy oil assets at Peace River and Lloydminster (excluding our Clearwater development) produced a combined 23,999 boe/d (91% oil and NGL) during Q4/2022 and 23,834 boe/d for the full-year 2022. Our 2022 drilling program included 9 net Bluesky wells at Peace River and 28.1 net wells at Lloydminster. In 2022, we invested $113 million on exploration and development in Peace River and Lloydminster and generated an operating netback of $361 million. In 2023, we will drill approximately 10 net Bluesky wells at Peace River and 40 net wells at Lloydminster.
Clearwater
Production from our Peavine Clearwater development averaged 11,009 boe/d (100% oil) during Q4/2022 and 7,442 boe/d for the full-year 2022. In 2022, we invested $55 million on exploration and development on our Peavine Clearwater acreage and generated an operating netback of $142 million. During 2022, we drilled 22 (22.0 net) wells at Peavine and brought 23 (23.0 net) wells onstream. Initial well performance continues to outperform type curve assumptions and we now hold the top 15 initial rate wells (based on peak 30-day calendar rate) drilled across the play. We expect to bring approximately 31 net wells onstream at Peavine in 2023.
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. 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 250 locations with production increasing to approximately 15,000 bbl/d. When combined with our legacy acreage position in northwest Alberta, we estimate that over 125 sections of our lands are prospective for Clearwater development.
Financial Liquidity
Our credit facilities total US$850 million and have a maturity date of April 1, 2026. These are not borrowing base facilities and do not require annual or semi-annual reviews. As of December 31, 2022, we had $765 million of undrawn capacity on our credit facilities, resulting in liquidity, net of working capital, of $717 million.
Our net debt(2), which includes our credit facilities, long-term notes and working capital, totaled $987 million at December 31, 2022, down from $1.1 billion at September 30, 2022 and $1.4 billion at December 31, 2021.
On June 1, 2022, we redeemed the remaining US$200 million principal amount of 5.625% long-term notes due 2024 at par. In addition, we repurchased and cancelled US$90 million principal amount of 8.75% long-term notes due 2027 during 2022.
(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.
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 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$78.36/bbl with upside participation to US$96.11/bbl.
A complete listing of our financial derivative contracts can be found in Note 17 to our 2022 financial statements.
Environmental Stewardship
The energy industry and society are undergoing an evolution toward lower carbon intensity, and we believe that oil and gas will be instrumental in this energy evolution. As a responsible energy producer, we are committed to monitoring greenhouse gas (“GHG”) emissions from our operations, setting targets to reduce our GHG emissions intensity, and pursuing cost-effective strategies to produce energy for society with a lower carbon intensity.
Our objective is to reduce our corporate GHG emissions intensity (kg of CO2e per boe) by 65% by 2025, relative to our 2018 baseline. Our emissions reduction strategy includes increased gas conservation and destruction, reusing associated gas as fuel for field activities, capturing and reducing emissions from storage tanks, along with monitoring and preventing fugitive emissions.
In 2022, we reduced our GHG emissions intensity by 15% from 2021 levels. This equates to a 59% reduction from our 2018 baseline and represents an annual reduction of 1.7 million tonnes of CO2e, which is equivalent to taking 340,000 cars off the road annually. In 2023, we will invest approximately $15 million as part of our GHG mitigation program and expect to reduce our GHG emissions intensity by another 7% below 2022 levels.
GHG Emissions Intensity (Scope 1 and Scope 2)
| 2018 Baseline | 2019 | 2020 | 2021 | 2022(1) | 2025 Target | |
| kg CO2e/boe | 112 | 95 | 61 | 54 | 46 | 39 |
Our commitment to responsible resource development also extends to the retirement of our assets when they’ve reached the end of their economic life. We plan for full lifecycle development of our properties, which includes the abandonment, reclamation, and full restoration at the end of asset life. At December 31, 2020, we had an end of life well inventory of approximately 4,500 wells. We have committed to reducing this well inventory to zero by 2040, which represents proactive management of future financial obligations as well as regulatory compliance.
In 2022, we invested $34 million (including $16 million of government grants) to complete 379 well abandonments. In 2023, we will continue our abandonment and reclamation program with approximately $25 million being directed to pipeline, wellbore and facility decommissioning along with well site reclamations.
Abandonment and Reclamation
| 2018 | 2019 | 2020 | 2021 | 2022 | 2023 Plan | ||||||||||||
| Number of wells abandoned (gross) | 110 | 113 | 99 | 237 | 379 | 270 | |||||||||||
| Spending in abandonment/reclamation ($ million) (2) | $ | 14 | $ | 15 | $ | 9 | $ | 10 | $ | 34 | $ | 25 |
(1) Corporate emissions are reported based on the operating control method of the GHG Protocol. 2022 data is not yet third party verified.
(2) Spending includes government grants received for abandonment and reclamations of $2 million in 2020, $3 million in 2021 and $16 million in 2022.
Year-end 2022 Reserves
Baytex’s year-end 2022 proved and probable reserves were evaluated by McDaniel & Associates Consultants Ltd. (“McDaniel”), an independent qualified reserves evaluator. All of our oil and gas properties were evaluated in accordance with National Instrument 51-101 “Standards of Disclosure for Oil and Gas Activities” (“NI 51-101”) and the Canadian Oil and Gas Evaluation Handbook (the “COGE Handbook”) using the average commodity price forecasts and inflation rates of McDaniel, GLJ Petroleum Consultants (“GLJ”) and Sproule Associates Limited (“Sproule”) as of January 1, 2023. Complete reserves disclosure will be included in our Annual Information Form for the year ended December 31, 2022, which will be filed on or before March 31, 2023.
Reserves Highlights
- Proved developed producing (“PDP”) reserves total 124 MMboe (129 MMboe at year-end 2021), proved reserves (“1P”) total 264 MMboe (278 MMboe at year-end 2021) and proved plus probable reserves (“2P”) total 438 MMboe (451 MMboe at year-end 2021).
- In Canada, 1P and 2P reserves increased 1% and 2%, respectively. We invested $381 million on exploration and development expenditures in Canada and replaced 131% of production on a 2P basis with significant reserves additions coming from our Peavine heavy oil development. The divestiture of non-core natural gas assets during the fourth quarter reduced 1P and 2P reserves by 5 MMboe and 9 MMboe, respectively.
- In the Eagle Ford, 1P and 2P reserves declined 10%. The reduction in Eagle Ford reserves is largely attributable to adjustments in development plans and technical revisions associated with shale gas.
- Future development costs (“FDC”) on a 1P basis increased to $2.7 billion ($2.4 billion at year-end 2021) and on a 2P basis, increased to $4.3 billion ($3.8 billion at year-end 2021). The increase in FDC is mainly attributable to inflationary pressures across our portfolio, consistent with inflationary pressures across the industry and the broader economy.
- Finding and development (“F&D”) costs, including changes in FDC, were $19.20/boe for PDP reserves, $39.40/boe for 1P reserves and $42.34/boe for 2P reserves.
- Generated a PDP recycle ratio of 2.8x and a 1P recycle ratio of 1.4x based on a 2022 operating netback(1) of $54.64/boe.
- Reserves on a 1P basis are comprised of 82% oil and NGLs (34% light oil, 26% NGLs, 19% heavy oil and 2% bitumen) and 18% natural gas. PDP reserves represent 47% of 1P reserves (46% at year-end 2021) and 1P reserves represent 60% of 2P reserves (62% at year-end 2021).
- Baytex maintains a strong reserves life index of 8.3 years based on 1P reserves and 13.8 years based on 2P reserves.
- At year-end, 2022, the present value of our reserves, discounted at 10% before tax, is estimated to be $5.9 billion ($5.1 billion at year-end 2021). The increase is largely attributable to a higher commodity price forecast being utilized by our reserves evaluator (consultant average of approximately US$81/bbl WTI).
- Our net asset value at year-end 2022, discounted at 10% before tax, is $9.28 per share. This is based on the estimated reserves value plus a value for undeveloped acreage, net of long-term debt and working capital.
(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.
The following table sets forth our gross and net reserves volumes at December 31, 2022 by product type and reserves category. Please note that the data in the table may not add due to rounding.
Reserves Summary
| Light and Medium Oil | Tight Oil | Heavy Oil | Bitumen | Total Oil | Natural Gas Liquids (3) | Conventional Natural Gas (4) | Shale Gas | Total (5) | ||||
| Reserves Summary | (Mbbls) | (Mbbls) | (Mbbls) | (Mbbls) | (Mbbls) | (Mbbls) | (MMcf) | (MMcf) | (Mboe) | |||
| Gross (1) | ||||||||||||
| Proved producing | 16,144 | 25,913 | 29,187 | 939 | 72,183 | 28,796 | 59,803 | 80,928 | 124,434 | |||
| Proved developed non-producing | 993 | 1,894 | 1,624 | – | 4,510 | 1,734 | 1,239 | 4,686 | 7,231 | |||
| Proved undeveloped | 24,814 | 20,757 | 20,247 | 3,668 | 69,487 | 39,235 | 25,831 | 117,354 | 132,586 | |||
| Total proved | 41,951 | 48,563 | 51,058 | 4,608 | 146,180 | 69,765 | 86,872 | 202,967 | 264,251 | |||
| Total probable | 21,881 | 20,719 | 34,526 | 45,751 | 122,878 | 28,728 | 45,786 | 84,633 | 173,342 | |||
| Proved plus probable | 63,832 | 69,283 | 85,584 | 50,359 | 269,057 | 98,493 | 132,658 | 287,600 | 437,593 | |||
| Net (2) | ||||||||||||
| Proved producing | 15,049 | 19,250 | 24,694 | 879 | 59,872 | 21,502 | 53,606 | 60,467 | 100,386 | |||
| Proved developed non-producing | 883 | 1,395 | 1,444 | – | 3,723 | 1,279 | 1,105 | 3,453 | 5,761 | |||
| Proved undeveloped | 23,098 | 15,844 | 17,584 | 3,354 | 59,880 | 29,453 | 22,315 | 88,536 | 107,808 | |||
| Total proved | 39,030 | 36,490 | 43,722 | 4,233 | 123,474 | 52,234 | 77,026 | 152,456 | 213,955 | |||
| Total probable | 19,989 | 15,789 | 28,960 | 37,202 | 101,940 | 21,795 | 40,387 | 64,878 | 141,279 | |||
| Proved plus probable | 59,018 | 52,278 | 72,681 | 41,436 | 225,414 | 74,029 | 117,413 | 217,335 | 355,234 |
Notes:
(1) “Gross” reserves means the total working interest share of remaining recoverable reserves owned by Baytex before deductions of royalties payable to others.
(2) “Net” reserves means Baytex’s gross reserves less all royalties payable to others plus royalty interest reserves.
(3) Natural Gas Liquids includes condensate.
(4) Conventional Natural Gas includes associated, non-associated and solution gas.
(5) 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.
Reserves Reconciliation
The following table reconciles the year-over-year changes in our gross reserves volumes by product type and reserves category. Please note that the data in the table may not add due to rounding.
Proved Reserves – Gross Volumes (1) (Forecast Prices)
| Light and Medium Oil | Tight Oil | Heavy Oil | Bitumen | Total Oil | Natural Gas Liquids (3) | Conventional Natural Gas (4) | Shale Gas | Total (5) | ||||
| (Mbbls) | (Mbbls) | (Mbbls) | (Mbbls) | (Mbbls) | (Mbbls) | (MMcf) | (MMcf) | (Mboe) | ||||
| December 31, 2021 | 46,009 | 53,216 | 46,003 | 4,838 | 150,067 | 72,137 | 104,423 | 231,439 | 278,181 | |||
| Extensions | 2,456 | 1,673 | 11,275 | – | 15,404 | 1,946 | 15,912 | 4,201 | 20,702 | |||
| Technical Revisions (2) | (2,504) | (1,164) | 3,034 | 344 | (290) | (152) | 4,658 | (20,846) | (3,140) | |||
| Acquisitions | – | – | – | – | – | – | – | – | – | |||
| Dispositions | – | – | (1) | – | (1) | (743) | (24,363) | – | (4,804) | |||
| Economic Factors | 1,320 | 395 | 686 | 69 | 2,470 | 536 | 3,450 | 1,298 | 3,797 | |||
| Production | (5,331) | (5,556) | (9,939) | (644) | (21,470) | (3,960) | (17,207) | (13,125) | (30,485) | |||
| December 31, 2022 | 41,951 | 48,563 | 51,058 | 4,608 | 146,180 | 69,765 | 86,872 | 202,967 | 264,251 |
Probable Reserves – Gross Volumes (1) (Forecast Prices)
| Light and Medium Oil | Tight Oil | Heavy Oil | Bitumen | Total Oil | Natural Gas Liquids (3) | Conventional Natural Gas (4) | Shale Gas | Total (5) | ||||
| (Mbbls) | (Mbbls) | (Mbbls) | (Mbbls) | (Mbbls) | (Mbbls) | (MMcf) | (MMcf) | (Mboe) | ||||
| December 31, 2021 | 23,296 | 21,485 | 29,705 | 45,874 | 120,360 | 27,751 | 62,394 | 84,928 | 172,665 | |||
| Extensions | 636 | 904 | 3,744 | – | 5,285 | 602 | 4,183 | 1,883 | 6,898 | |||
| Technical Revisions (2) | (2,414) | (1,796) | (866) | (136) | (5,211) | 844 | (1,880) | (2,647) | (5,121) | |||
| Acquisitions | – | – | – | – | – | – | – | – | – | |||
| Dispositions | – | – | – | – | – | (655) | (21,175) | – | (4,184) | |||
| Economic Factors | 363 | 126 | 1,942 | 12 | 2,443 | 186 | 2,263 | 468 | 3,084 | |||
| Production | – | – | – | – | – | – | – | – | – | |||
| December 31, 2022 | 21,881 | 20,719 | 34,526 | 45,751 | 122,877 | 28,728 | 45,786 | 84,633 | 173,342 |
Proved Plus Probable Reserves – Gross Volumes (1) (Forecast Prices)
| Light and Medium Oil | Tight Oil | Heavy Oil | Bitumen | Total Oil | Natural Gas Liquids (3) | Conventional Natural Gas (4) | Shale Gas | Total (5) | ||||
| (Mbbls) | (Mbbls) | (Mbbls) | (Mbbls) | (Mbbls) | (Mbbls) | (MMcf) | (MMcf) | (Mboe) | ||||
| December 31, 2021 | 69,305 | 74,701 | 75,709 | 50,713 | 270,427 | 99,888 | 166,817 | 316,367 | 450,846 | |||
| Extensions | 3,093 | 2,577 | 15,019 | – | 20,689 | 2,549 | 20,095 | 6,085 | 27,601 | |||
| Technical Revisions (2) | (4,917) | (2,960) | 2,168 | 208 | (5,500) | 692 | 2,778 | (23,492) | (8,261) | |||
| Acquisitions | – | – | – | – | – | – | – | – | – | |||
| Dispositions | – | – | (1) | – | (2) | (1,397) | (45,537) | – | (8,989) | |||
| Economic Factors | 1,683 | 521 | 2,628 | 81 | 4,913 | 722 | 5,713 | 1,765 | 6,881 | |||
| Production | (5,331) | (5,556) | (9,939) | (644) | (21,470) | (3,960) | (17,207) | (13,125) | (30,485) | |||
| December 31, 2022 | 63,832 | 69,283 | 85,584 | 50,359 | 269,058 | 98,493 | 132,658 | 287,600 | 437,593 |
Notes:
(1) “Gross” reserves means the total working interest share of remaining recoverable reserves owned by Baytex before deductions of royalties payable to others.
(2) Negative technical revisions in light and medium oil are predominantly associated with higher field operating costs in our Viking asset due to inflationary impacts truncating end of life forecasts and natural variation in actual performance vs forecast. Negative technical revisions in tight oil are predominantly associated with higher field operating costs in our Eagle Ford asset due to inflationary impacts truncating end of life forecasts and natural variation in actual performance vs forecast. Negative technical revisions in shale gas are predominantly associated with natural variation in actual performance vs forecast in our Eagle Ford asset.
(3) Natural gas liquids include condensate.
(4) Conventional natural gas includes associated, non-associated and solution gas.
(5) 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.
Future Development Costs
The following table sets forth future development costs deducted in the estimation of the future net revenue attributable to the reserves categories noted below.
| Future Development Costs ($ millions) | Proved Reserves | Proved Plus Probable Reserves |
| 2023 | 490 | 516 |
| 2024 | 602 | 643 |
| 2025 | 510 | 625 |
| 2026 | 505 | 707 |
| 2027 | 494 | 569 |
| Remainder | 95 | 1,228 |
| Total FDC undiscounted | 2,695 | 4,288 |
F&D and FD&A Costs – including future development costs
Based on the evaluation of our petroleum and natural gas reserves prepared by McDaniel, the efficiency of our capital program is summarized in the following table.
| $ millions except for per boe amounts | 2022 | 2021 | 2020 | 3 Year | |||||||
| Proved plus Probable Reserves | |||||||||||
| Finding & Development Costs | |||||||||||
| Exploration and development expenditures | $ | 521.5 | $ | 313.3 | $ | 280.3 | $ | 1,115.2 | |||
| Net change in Future Development Costs | $ | 588.6 | $ | 147.4 | $ | (705.9) | $ | 30.1 | |||
| Gross Reserves additions (MMboe) | 26.2 | 18.8 | (38.4) | 6.6 | |||||||
| F&D Costs ($/boe) | $ | 42.34 | $ | 24.55 | $ | 11.08 | n.m.(1) | ||||
| Finding, Development & Acquisition (“FD&A”) Costs | |||||||||||
| Exploration and development expenditures and net acquisitions | $ | 497.2 | $ | 307.1 | $ | 280.2 | $ | 1,084.5 | |||
| Net change in Future Development Costs | $ | 537.6 | $ | 144.4 | $ | (709.3) | $ | (27.3) | |||
| Gross Reserves additions (MMboe) | 17.2 | 18.4 | (38.6) | (3.0) | |||||||
| FD&A Costs ($/boe) | $ | 60.05 | $ | 24.55 | $ | 11.12 | n.m.(1) | ||||
| Proved Reserves | |||||||||||
| Finding & Development Costs | |||||||||||
| Exploration and development expenditures | $ | 521.5 | $ | 313.3 | $ | 280.3 | $ | 1,115.2 | |||
| Net change in Future Development Costs | $ | 320.1 | $ | 308.6 | $ | (464.4) | $ | 164.2 | |||
| Gross Reserves additions (MMboe) | 21.4 | 35.2 | (13.1) | 43.5 | |||||||
| F&D Costs ($/boe) | $ | 39.40 | $ | 17.67 | $ | 14.06 | $ | 29.44 | |||
| Finding, Development & Acquisition Costs | |||||||||||
| Exploration and development expenditures and net acquisitions | $ | 497.2 | $ | 307.1 | $ | 280.2 | $ | 1,084.5 | |||
| Net change in Future Development Costs | $ | 285.0 | $ | 316.8 | $ | (464.4) | $ | 137.4 | |||
| Gross Reserves additions (MMboe) | 16.6 | 36.1 | (13.1) | 39.5 | |||||||
| FD&A Costs ($/boe) | $ | 47.25 | $ | 17.30 | $ | 14.07 | $ | 30.92 | |||
| Proved Developed Producing Reserves | |||||||||||
| Finding & Development Costs | |||||||||||
| Exploration and development expenditures | $ | 521.5 | $ | 313.3 | $ | 280.3 | $ | 1,115.2 | |||
| Gross Reserves additions (MMboe) | 27.2 | 38.2 | 7.7 | 73.1 | |||||||
| F&D Costs ($/boe) | $ | 19.20 | $ | 8.20 | $ | 36.63 | $ | 15.27 | |||
| Finding, Development & Acquisition Costs | |||||||||||
| Exploration and development expenditures and net acquisitions | $ | 497.2 | $ | 307.1 | $ | 280.2 | $ | 1,084.5 | |||
| Gross Reserves additions (MMboe) | 26.0 | 38.1 | 7.6 | 71.8 | |||||||
| FD&A Costs ($/boe) | $ | 19.13 | $ | 8.06 | $ | 36.64 | $ | 15.11 |
Note:
(1) Not meaningful.
Reserves Life Index
The following table sets forth our reserves life index, which is calculated by dividing our proved and proved plus probable reserves at year-end 2022 by annualized Q4/2022 production.
| Reserves Life Index (years) | |||
| Q4/2022 Production | Proved | Proved Plus Probable | |
| Crude Oil and NGL (bbl/d) | 72,585 | 8.2 | 13.9 |
| Natural Gas (Mcf/d) | 85,679 | 9.3 | 13.4 |
| Oil Equivalent (boe/d) | 86,864 | 8.3 | 13.8 |
Forecast Prices and Costs
The following table summarizes the forecast prices used in preparing the estimated reserves volumes and the net present values of future net revenues at December 31, 2022. The estimated future net revenue to be derived from the production of the reserves is based on the following average of the price forecasts of McDaniel, GLJ and Sproule as of January 1, 2023.
| Year | WTI Crude Oil US$/bbl | Edmonton Light Crude Oil $/bbl | Western Canadian Select $/bbl | Henry Hub US$/MMbtu | AECO Spot $/MMbtu | Inflation Rate %/Yr | Exchange Rate $US/$Cdn |
| 2022 act. | 94.65 | 120.55 | 98.85 | 6.40 | 5.55 | 6.9 | 0.770 |
| 2023 | 80.33 | 103.76 | 76.54 | 4.74 | 4.23 | – | 0.745 |
| 2024 | 78.50 | 97.74 | 77.75 | 4.50 | 4.40 | 2.3 | 0.765 |
| 2025 | 76.95 | 95.27 | 77.55 | 4.31 | 4.21 | 2.0 | 0.768 |
| 2026 | 77.61 | 95.58 | 80.07 | 4.40 | 4.27 | 2.0 | 0.772 |
| 2027 | 79.16 | 97.07 | 81.89 | 4.49 | 4.34 | 2.0 | 0.775 |
| 2028 | 80.74 | 99.01 | 84.02 | 4.58 | 4.43 | 2.0 | 0.775 |
| 2029 | 82.36 | 100.99 | 85.73 | 4.67 | 4.51 | 2.0 | 0.775 |
| 2030 | 84.00 | 103.01 | 87.44 | 4.76 | 4.60 | 2.0 | 0.775 |
| 2031 | 85.69 | 105.07 | 89.20 | 4.86 | 4.69 | 2.0 | 0.775 |
| 2032 | 87.40 | 106.69 | 91.11 | 4.95 | 4.79 | 2.0 | 0.775 |
| Thereafter | Escalation rate of 2.0% | 2.0 | 0.775 | ||||
Net Present Value of Reserves (1) (Forecast Prices and Costs)
The following table summarizes the McDaniel estimate of the net present value before income taxes of the future net revenue attributable to our reserves.
| Reserves at December 31, 2022 ($ millions, discounted at) | 0% | 5% | 10% | 15% |
| Proved developed producing | 2,821 | 2,485 | 2,197 | 1,978 |
| Proved developed non-producing | 296 | 225 | 185 | 159 |
| Proved undeveloped | 3,007 | 2,055 | 1,485 | 1,108 |
| Total proved | 6,124 | 4,765 | 3,867 | 3,246 |
| Probable | 5,303 | 3,065 | 2,011 | 1,434 |
| Total Proved Plus Probable (before tax) | 11,427 | 7,830 | 5,878 | 4,680 |
Note:
(1) Includes abandonment, decommissioning and reclamation costs for all producing and non-producing wells and facilities.
Net Asset Value (Forecast Prices and Costs)
Our estimated net asset value is based on the estimated net present value of all future net revenue from our reserves, before income taxes, as estimated by McDaniel at year-end, plus the estimated value of our undeveloped land holdings, less net debt. This calculation can vary significantly depending on the oil and natural gas price assumptions. In addition, this calculation assumes only the reserves identified in the reserves report with no further acquisitions or incremental development.
The following table sets forth our net asset value as at December 31, 2022.
| ($ millions, except per share amounts, discounted at) | 5% | 10% | 15% |
| Net present value of proved plus probable reserves (1) | 7,830 | 5,878 | 4,680 |
| Undeveloped land holdings (2) | 166 | 166 | 166 |
| Net Debt (3) | (987) | (987) | (987) |
| Net Asset Value | 7,009 | 5,057 | 3,859 |
| Net Asset Value per Share (4) | 12.86 | 9.28 | 7.08 |
Notes:
(1) Includes abandonment, decommissioning and reclamation costs for all producing and non-producing wells and facilities.
(2) The value of undeveloped land holdings generally represents the estimated replacement cost of our undeveloped land.
(3) Capital management measure. Refer to the Specified Financial Measures section in this press release for further information.
(4) Based on 544.9 million common shares outstanding as at December 31, 2022.
Additional Information
Our audited consolidated financial statements for the year ended December 31, 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. MST (11:00 a.m. EST) |
| Baytex will host a conference call tomorrow, February 24, 2023, starting at 9:00am MST (11:00am EST). 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/baytex2022ye.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. |
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. Approximately 84% of Baytex’s production is weighted toward crude oil and natural gas liquids. 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: [email protected]
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