Bonterra Energy Corp.
Annual Report 2022

Plain-text annual report

2022 ANNUAL REPORT Bonterra Energy Corp. December 31, 2022 ABOUT BONTERRA Bonterra Energy Corp. (“Bonterra” or the “Company”) is a future-focused energy company offering investors exposure to a high-quality, oil-weighted asset base primarily targeting Alberta’s Cardium play. Bonterra’s established track record has been built on assets that are concentrated in the Pembina and Willesden Green fields, which are among Canada’s largest conventional oilfields, offering long-term, lower-decline oil production with attractive netbacks. The Company's shares are listed on The Toronto Stock Exchange under the symbol "BNE". TABLE OF CONTENTS About Bonterra Report To Shareholders Highlight Tables Statistical Review Management’s Discussion and Analysis Financial Statements Notes to the Financial Statements Corporate Information 2 3 6 8 12 33 42 IBC CONTACT INFORMATION OFFICERS Patrick G. Oliver, President & CEO Robb D. Thompson, CFO & Corporate Secretary Adrian Neumann, Chief Operating Officer Brad A. Curtis, Senior VP, Business Development HEAD OFFICE Suite 901, 1015-4th Street SW Calgary, AB T2R 1J4 T: (403) 262-5307 F: (403) 265-7488 2 REPORT TO SHAREHOLDERS I am pleased to share Bonterra Energy Corp’s. (“Bonterra” or the “Company”) operating and financial results for the three and twelve month period ended December 31, 2022. Since I joined Bonterra as President and CEO in September of 2022, I have been working alongside our talented and passionate management team and Board to map out a bold new path forward for the Company. Bonterra realized a landmark year in 2022, and we made significant progress on a multitude of financial, operational and corporate objectives. As a result of our active capital program, we successfully brought new production volumes on-stream into a strong commodity price environment, generating robust netbacks, funds flow1, and free funds flow1. In keeping with our goal of strengthening the balance sheet and enhancing our financial flexibility, Bonterra successfully redirected free funds flow1 to meaningful debt reduction, augmenting our long-term sustainability. With free funds flow1 of $105.8 million generated in 2022, Bonterra exceeded our original free funds flow1 2022 Guidance by 18 percent, demonstrating a commitment to financial discipline and value creation, supported by our expansive Cardium asset base. Our drilling program was executed safely and successfully, and in response to the stronger commodity price environment, we elected to reactivate wells that had been taken off-line during weaker price periods, which also supported production volumes. Further support was gained following the commissioning of a wholly- owned gas plant in the latter half of the year designed to alleviate processing capacity limitations. These efforts, combined with our moderate annual production decline rate, collectively enabled the Company to achieve an average daily production of 13,407 BOE while also paving the way for a strategic bank credit facility restructuring that affords Bonterra financial flexibility, a stable capital base and greatly enhanced liquidity. Our success through 2022 represents a significant step forward in our goal of implementing a shareholder returns-based business model that could be comprised of a combination of debt repayment, sustainable dividends and modest production growth. FINANCIAL & OPERATING HIGHLIGHTS • Production in 2022 averaged 13,407 BOE per day, five percent higher than in 2021, while fourth quarter volumes averaged 12,989 BOE per day, six percent lower than the same period last year. • Realized oil and gas sales in 2022 increased 53 percent over 2021 to total $384.2 million, and rose ten percent in Q4 2022 over the same period in 2021, primarily driven by significantly higher realized prices and stronger production volumes for the full year. • • • Funds flow1 totaled $185.6 million ($4.98 per fully diluted share) in 2022, a 77 percent increase over $104.8 million ($3.02 per fully diluted share) generated in 2021, while funds flow1 in Q4 2022 totaled $41.1 million ($1.10 per fully diluted share) or 13 percent higher than Q4 2021. Free funds flow1 increased 182 percent over 2021 to total $105.8 million in 2022, and $28.5 million in Q4 2022, and was directed primarily to debt repayment. Field netbacks1 averaged $44.93 per BOE in 2022 and $42.99 per BOE in Q4 2022, representing increases of 52 percent and 25 percent over the same respective periods in 2021; cash netbacks averaged $37.92 per BOE in 2022 and $34.43 per BOE in Q4 2022, reflecting increases of 68 percent and 20 percent, over the same respective periods in 2021, due primarily to significantly higher commodity prices. 1 Non-IFRS measure. 3 • Production costs declined in Q4 2022 by 21 percent to average approximately $16.11 per BOE compared to $20.33 per BOE in Q3 2022, further reducing the annual average production costs to $17.45 per BOE. • Capital expenditures totaled $79.8 million during 2022 and $12.6 million in Q4 2022. Of the full year capital, 71 percent was directed to drilling 25 gross (24.7 net) operated wells and having 31 gross (30.7 net) operated wells tied-in and placed on production, six of which were drilled late in 2021. • Bank debt totaled $17.6 million at year-end, 89 percent lower than year-end 2021, while net debt2 declined 44 percent to $149.8 million exiting 2022, improving Bonterra’s net debt to twelve-month trailing cash flow ratio1 to 0.8 times compared to 2.8 times at December 31, 2021. Bonterra’s improved debt profile and increased cash flow helps set the stage to reintroduce a shareholder returns-based business model by the end of 2023. • Strategic debt restructuring was completed in Q4 2022 as Bonterra closed on two new credit facilities, comprised of a $110 million first lien secured bank credit facility and a $95 million second lien secured term debt facility, while simultaneously repaying the $47 million Business Development Bank of Canada (“BDC”) Term Facility. • Significant reduction in ARO liability and inactive well count. Over the past three years, the Company has successfully abandoned 487.8 net wells, 234 pipelines and five facilities, of which 123.5 net wells, 53 pipelines and two facilities were abandoned in 2022. • Responsible operations remained a top priority through 2022 and Bonterra is pleased to confirm the completion of our second environmental, social and governance (“ESG”) report, which is now available on the Company’s website. The report highlights Bonterra’s recent ESG highlights and initiatives, profiling the Company’s progress in our sustainability journey.. OUTLOOK While 2022 represents a year of building and gaining momentum to continue expanding our capabilities, we believe 2023 and beyond offers a bold and bright future for Bonterra to emerge anew and forge ahead with a refreshed vision, team and growth plan. Our intent is to identify and pursue accretive and strategic acquisitions that can enhance production, expand our drilling inventory and further deleverage the balance sheet, supported by our solid production and reserves base. We believe our previously communicated 2023 guidance sets the stage for this evolution: • A capital expenditure budget ranging from $120 to $125 million, allocated approximately 75 percent to drilling and completing new Cardium wells in Pembina and Willesden Green, with the balance directed to facilities, pipelines and a continued commitment to ongoing abandonment and reclamation activities; • Average 2023 production volumes between 13,500 and 13,700 BOE per day3, weighted approximately 60 percent to oil and liquids; • A year-over-year exit rate growth exceeding 10 percent, reflecting planned 2023 exit volumes between 14,100 and 14,400 BOE per day4; and 2 Non-IFRS measure. 3 2023 volumes are anticipated to be comprised of 7,000 bbl/d light and medium crude oil, 1,200 bbl/d NGLs and 32,400 mcf/d of conventional natural gas based on a midpoint of 13,600 BOE/d. 4 Exit 2023 volumes are anticipated to be comprised of 7,428 bbl/d light and medium crude oil, 1,223 bbl/d NGLs and 33,593 mcf/d of conventional natural gas based on a midpoint of 14,250 BOE/d. 4 • • The generation of approximately $170 to $175 million in corporate funds flow5,2 for the year, resulting in meaningful free funds flow2 of approximately $45 to $50 million which is expected to drive a year-end net debt to EBITDA6 ratio of 0.7 times, based on pricing (assuming US$74.80 WTI) and production assumptions as outlined fully in our December 15, 2022 press release. Forecast funds flow1 per fully diluted share of $4.55 to $4.70 positions Bonterra as a low-risk value investment based on the current public market value of the Company’s common shares. We appreciate the support, loyalty and commitment all of our stakeholders have shown to Bonterra over the past few years, and we are excited about unveiling our longer-term growth plans, identity and culture that we believe will support our return to a sustainable dividend paying business model before the end of 2023. Patrick Oliver President & Chief Executive Officer 5 Funds Flow is estimated using a Canadian realized oil price of $94.83/bbl, a realized natural gas price of $4.07/mcf; and a realized NGL price of CAD $65.02/bbl. 6 Non-IFRS measure. 5 ANNUAL HIGHLIGHTS As at and for the year ended ($000s except $ per share) FINANCIAL Revenue - realized oil and gas sales Funds flow(1) Per share - basic Per share - diluted Cash flow from operations Per share - basic Per share - diluted Net earnings (loss)(2) Per share - basic Per share - diluted Capital expenditures Total assets Net debt(3) Bank debt Shareholders' equity OPERATIONS Light oil -bbl per day -average price ($ per bbl) NGLs -bbl per day -average price ($ per bbl) Conventional natural gas -MCF per day Total barrels of oil equivalent per day (BOE)(4) -average price ($ per MCF) December 31, 2022 December 31, 2021 December 31, 2020 384,197 185,583 5.16 4.98 251,616 104,843 3.11 3.02 121,642 27,789 0.83 0.83 183,553 96,103 32,073 5.10 4.92 2.85 2.76 0.96 0.96 79,023 179,299 (306,889) 2.20 2.12 5.32 5.16 79,769 67,282 919,682 945,721 149,831 17,601 479,839 7,095 113.93 1,141 66.00 31,023 5.44 13,407 267,179 162,945 392,019 7,204 74.53 1,013 43.86 27,176 3.97 12,747 (9.19) (9.19) 43,728 731,859 315,573 252,255 196,633 5,832 44.31 1,032 18.65 22,268 2.46 10,575 1 Funds flow is not a recognized measure under IFRS. For these purposes, the Company defines funds flow as funds provided by operations including proceeds from sale of investments and investment income received excluding the effects of changes in non - cash working capital items and decommissioning expenditures settled. 2 In the first quarter of 2020 the Company recorded a $331,678,000 impairment provision less a $54,107,000 deferred income tax recovery related to its Alberta CGU’s oil and gas assets due to the impact of COVID-19 effect on the forward benchmark prices for crude oil. With stronger forward prices in Q2 2021, the Company recorded a $203,197,000 impairment reversal on its Alberta CGU’s oil and gas assets less $47,149,000 deferred income tax expense. 3 Net debt is not a recognized measure under IFRS. The Company defines net debt as current liabilities less current assets plus long- term subordinated debt and subordinated debentures. 4 BOE may be misleading, particularly if used in isolation. A BOE conversion ratio of 6 MCF: 1 bbl is based on an energy conversion method primarily applicable at the burner tip and does not represent a value equivalency at the wellhead. 6 QUARTERLY HIGHLIGHTS As at and for the periods ended ($ 000s except $ per share) FINANCIAL Revenue - oil and gas sales Funds flow (1) Per share - basic and diluted Per share - diluted 2022 Q4 Q3 Q2 Q1 87,154 41,145 1.13 1.10 88,827 35,454 0.98 0.95 116,674 61,892 1.72 1.62 91,542 47,092 1.34 1.28 Cash flow from operations 35,494 48,810 58,307 40,942 Per share - basic Per share - diluted Net earnings Per share - basic Per share - diluted Capital expenditures Total assets Bank debt Net debt(2) Shareholders' equity OPERATIONS Light oil (barrels per day) Average price ($ per bbl) NGLs (barrels per day) Average price ($ per bbl) Conventional natural gas (MCF per day) Average price ($ per MCF) Total BOE per day(3) 0.97 0.95 1.35 1.30 1.62 1.53 1.16 1.11 17,264 17,696 33,544 10,519 0.47 0.46 0.49 0.47 0.93 0.88 0.30 0.29 12,642 20,452 14,506 32,169 919,682 17,601 149,831 479,839 6,764 105.59 1,209 59.38 30,101 5.36 12,989 948,259 74,524 187,128 461,199 6,649 111.44 1,206 64.45 31,052 4.73 13,031 934,303 111,476 211,284 442,653 7,623 126.97 1,151 77.23 33,323 6.76 14,328 965,969 138,384 260,670 405,148 7,356 110.41 996 63.02 29,609 4.80 13,287 1 Funds flow is not a recognized measure under IFRS. For these purposes, the Company defines funds flow as funds provided by operations including proceeds from sale of investments and investment income received excluding the effects of changes in non - cash working capital items and decommissioning expenditures settled. 2 Net debt is not a recognized measure under IFRS. The Company defines net debt as current liabilities less current assets plus long- term subordinated debt and subordinated debentures. 3 BOE may be misleading, particularly if used in isolation. A BOE conversion ratio of 6 MCF: 1 bbl is based on an energy conversion method primarily applicable at the burner tip and does not represent a value equivalency at the wellhead. 7 STATISTICAL REVIEW Summary of Gross Oil and Gas Reserves as of December 31, 2022 Reserves Category: PROVED Developed Producing Developed Non-Producing Undeveloped TOTAL PROVED PROBABLE TOTAL PROVED PLUS PROBABLE(1)(2)(3) Light & Medium Crude Oil Conventional Natural Gas Natural Gas Liquids Oil equivalent(4) Future development Capital (Mbbl) (MMCF) (Mbbl) (MBOE) (000s) 18,072 2,403 22,699 43,174 10,400 53,574 77,590 6,971 99,792 184,352 46,168 230,520 2,699 234 3,869 6,802 1,694 8,496 33,702 - 3,799 43,201 80,702 3,984 656,112 660,097 19,788 - 100,490 660,097 (1) Reserves have been presented on gross basis which are the Company’s total working interest share before the deduction of any royalties and without including any royalty interests of the Company. (2) Totals may not add due to rounding. (3) Based on average forecasted product prices between independent reserve evaluators Sproule, GLJ Petroleum Consultants and McDaniels & Associates Consultants Ltd. (4) Oil equivalent amounts have been calculated using a conversion rate of six thousand cubic feet of natural gas to one barrel of oil. Reconciliation of Company Gross Reserves by Principle Product Type as of December 31, 2022(1) Light & Medium Crude Oil Total Proved (Mbbl) Proved + Probable (Mbbl) Conventional Natural Gas(4) Total Proved (MMCF) Proved + Probable (MMCF) Natural Gas Liquids Total Total Proved (Mbbl) Proved + Probable (Mbbl) Total Proved (MBOE) Proved + Probable (MBOE) 43,470 54,231 166,795 207,273 6,962 8,655 78,231 97,431 Opening Balance December 31, 2021 Extensions & Improved Recovery(2) 4,347 5,390 12,741 15,813 Technical Revisions (4,701) (6,249) 7,797 10,137 573 (618) 712 7,043 8,738 (772) (4,020) (5,332) Discoveries Acquisitions Dispositions Economic Factors Production Closing Balance, December 31, 2022(3) - - - - - - - - - - - - - - - - - - - - - - - - 2,648 2,792 8,342 8,620 303 318 4,341 4,546 (2,590) (2,590) (11,323) (11,323) (417) (417) (4,894) (4,894) 43,174 53,574 184,352 230,520 6,802 8,496 80,702 100,490 (1) Gross Reserves means the Company’s working interest reserves before calculation of royalties, and before consideration of the Company’s (2) royalty interests. Increases to Extensions & Improved Recovery include infill drilling and are the result of step-out locations drilled by Bonterra and other operators on and near Company-owned lands. (3) Totals may not add due to rounding. (4) Conventional natural gas amounts shown include solution gas. 8 Summary of Net Present Values of Future Net Revenue as of December 31, 2022 Reserves Category: PROVED Developed Producing Developed Non-Producing Undeveloped TOTAL PROVED PROBABLE TOTAL PROVED PLUS PROBABLE(1)(2)(3)(4) Net Present Value Before Income Taxes Discounted at (% per Year) 0% 5% 10% 15% 921,555 133,157 1,094,449 2,149,161 782,693 2,931,854 768,088 79,415 692,709 1,540,212 469,041 2,009,253 632,115 55,799 468,029 1,155,943 325,745 1,481,688 537,751 42,666 331,955 912,371 247,388 1,159,759 (1) Evaluated by Sproule as at December 31, 2022. Net present value of future net revenue does not represent fair value of the reserves. (2) Net present values equals net present value before income taxes based on Sproule’s forecast prices and costs as of December 31, 2022. There is no assurance that the forecast price and cost assumptions will be attained and variances could be material. Includes abandonment and reclamation costs as defined in NI 51-101. (3) (4) Totals may not add due to rounding. Finding, Development & Acquisition (FD&A) and Finding & Development (F&D) Costs Proved Reserves Net Additions Proved + Probable Reserves Net Additions 2022 2021 2020 3 Yr Avg(4) 2022 2021 2020 3 Yr Avg(4) FD&A COSTS PER BOE (1)(2)(3) Including FDC Excluding FDC $24.85 $6.90 $ 12.46 $10.47 $8.68 ($18.21) F&D COSTS PER BOE (1)(2)(3) Including FDC Excluding FDC $24.85 $6.90 $12.46 $10.47 $8.68 ($18.21) $16.37 $14.75 $16.37 $14.75 $23.34 $5.64 $9.87 $15.52 $10.02 $8.23 ($13.26) $14.86 $23.34 $5.64 $9.87 $15.52 $10.02 $8.23 ($13.26) $14.86 (1) Barrels of Oil Equivalent may be misleading, particularly if used in isolation. A BOE conversion ratio of 6 MCF: 1 bbl is based on an energy equivalency conversion method primarily applicable at the burner tip and does not represent a value equivalency at the wellhead. (2) The aggregate of the exploration and development costs incurred in the most recent financial year and the change during that year in estimated future development costs generally will not reflect total finding and development costs related to reserve additions for that year. (3) FD&A and F&D costs are net of proceeds of disposal and the FD&A costs per BOE are based on reserves acquired net of reserves disposed of. (4) Three year average is calculated using three year total capital costs and reserve additions on both a Proved and Proved + Probable reserves on a weighted average basis. 9 Commodity Prices Used in the Above Calculations of Reserves are as Follows Edmonton Par Price 40° API ($Cdn per bbl) Natural Gas AECO-C Spot ($Cdn per mmbtu) NGL Butanes Edmonton ($Cdn per bbl) NGL Pentanes Edmonton ($Cdn per bbl) Operating Cost Inflation Rate (% per Year) Exchange Rate ($US/$Cdn) 103.76 97.74 95.27 95.58 97.07 99.01 100.99 103.01 105.07 106.69 108.83 4.23 4.40 4.21 4.27 4.34 4.43 4.51 4.60 4.69 4.79 4.88 53.88 52.67 51.42 51.61 52.39 53.44 54.51 55.60 56.71 57.56 58.71 106.22 101.35 98.94 100.19 101.74 103.78 105.85 107.97 110.13 112.33 114.58 0.0 2.3 2.0 2.0 2.0 2.0 2.0 2.0 2.0 2.0 2.0 0.75 0.77 0.77 0.77 0.78 0.78 0.78 0.78 0.78 0.78 0.78 Year FORECAST 2023 2024 2025 2026 2027 2028 2029 2030 2031 2032 2033 Crude oil, natural gas and liquid prices escalate at 2.0 percent thereafter. Production Alberta Saskatchewan British Columbia Total Land Holdings Alberta Saskatchewan British Columbia Total Oil & NGLs (Bbl Per Day) 2022 Conventional Natural Gas (MCF Per Day) Total (BOE Per Day) 8,151 30,823 13,288 81 4 34 166 87 32 8,236 31,023 13,407 2022 2021 Gross Acres Net Acres Gross Acres Net Acres 345,924 218,640 331,252 204,134 586 3,677 7,806 5,595 65,913 28,297 65,913 28,260 412,423 250,614 404,970 237,989 10 Petroleum and Natural Gas Expenditures ($ 000s) Land Exploration and development costs 2022 2021 2,569 1,621 77,200 65,661 Net petroleum and natural gas capital expenditures 79,769 67,282 Drilling History Crude oil Natural gas Total Success rate Crude oil Natural gas Total Success rate Development 2022 Exploratory Total Gross Net Gross Net Gross Net 34 25.8 - - 34 25.8 - - - - - - 34 25.8 - - 34 25.8 100% 100% - - 100% 100% Development 2021 Exploratory Total Gross Net Gross Net Gross Net 39 35.8 - - 39 35.8 - - - - - - 39 35.8 - - 39 35.8 96% 96% - - 100% 100% 11 YEAR END 2022 Management’s Discussion and Analysis & Financial Statements 12 MANAGEMENT’S DISCUSSION AND ANALYSIS The following report dated March 9, 2023 is a review of the operations and current financial position for the year ended December 31, 2022 for Bonterra Energy Corp. (“Bonterra” or “the Company”) and should be read in conjunction with the audited financial statements presented under International Financial Reporting Standards (IFRS), including the notes related thereto. Use of Non-IFRS Financial Measures Throughout this Management’s Discussion and Analysis (MD&A) the Company uses the terms “field netback”, “cash netback” and “net debt” to analyze operating performance, which are not standardized measures recognized under IFRS and do not have a standardized meaning prescribed by IFRS. These measures are commonly used in the oil and gas industry and are considered informative by management, shareholders and analysts. These measures may differ from those made by other companies and accordingly may not be comparable to such measures as reported by other entities. The Company calculates cash and field netback by dividing various financial statement items as determined by IFRS by total production for the period on a barrel of oil equivalent basis. The Company calculates net debt as long-term debt plus working capital deficiency (current liabilities less current assets). Frequently Recurring Terms Bonterra uses the following frequently recurring terms in this MD&A: “WTI” refers to West Texas Intermediate, a grade of light sweet crude oil used as benchmark pricing in the United States; “MSW Stream Index” or “Edmonton Par” refers to the mixed sweet blend that is the benchmark price for conventionally produced light sweet crude oil in Western Canada; “AECO” is the benchmark price for natural gas in Alberta, Canada; “bbl” refers to barrel; “NGL” refers to natural gas liquids; “MCF” refers to thousand cubic feet; “MMBTU” refers to million British Thermal Units; “GJ” refers to gigajoule; “LNG” refers to liquefied natural gas; and “BOE” refers to barrels of oil equivalent. Disclosure provided herein in respect of a BOE may be misleading, particularly if used in isolation. A BOE conversion ratio of 6 MCF: 1 bbl is based on an energy conversion method primarily applicable at the burner tip and does not represent a value equivalency at the wellhead. Numerical Amounts The reporting and the functional currency of the Company is the Canadian dollar. 13 ANNUAL COMPARISONS (1) In the first quarter of 2020 the Company recorded a $331,678,000 impairment provision less a $54,107,000 deferred income tax recovery related to its Alberta cash generating unit’s (“CGU”) oil and gas assets due to the impact of COVID-19 on forward benchmark prices for crude oil. With stronger forward benchmark prices in Q2 2021, the Company recorded a $203,197,000 impairment reversal on its Alberta CGU oil and gas assets less $47,149,000 deferred income tax expense 14 As at and for the year ended($000s except $ per share)FINANCIALRevenue - realized oil and gas sales384,197251,616121,642Cash flow from operations183,55396,10332,073Per share - basic5.102.85 0.96 Per share - diluted4.922.76 0.96 Net earnings (loss)(1)79,023179,299 (306,889)Per share - basic2.205.32(9.19)Per share - diluted2.125.16(9.19)Capital expenditures 79,769 67,282 43,728Total assets919,682945,721731,859Net debt149,831267,179315,573Shareholders' equity479,839392,019196,633OPERATIONSLight oil-bbl per day7,0957,2045,832-average price ($ per bbl)113.9374.53 44.31 NGLs-bbl per day1,1411,0131,032-average price ($ per bbl)66.0043.86 18.65 Conventional natural gas-MCF per day31,02327,17622,268-average price ($ per MCF)5.443.97 2.46 Total BOE per day13,40712,74710,575December 31, 2022December 31, 2021December 31, 2020 QUARTERLY COMPARISONS (1) In Q2 2021, with stronger forward benchmark prices since the impact of COVID-19 beginning in March 2020, the Company recorded a $203,197,000 impairment reversal on its Alberta cash generating unit’s (“CGU”) oil and gas assets less $47,149,000 deferred income tax expense. 15 As at and for the periods ended($ 000s except $ per share)Q4Q3Q2Q1Financial Revenue - oil and gas sales 87,15488,827116,67491,542Cash flow from operations35,49448,81058,30740,942Per share - basic0.971.351.621.16Per share - diluted0.951.301.531.11Net earnings17,26417,69633,54410,519Per share - basic0.470.490.930.30Per share - diluted0.460.470.880.29Capital expenditures 12,642 20,452 14,506 32,169 Total assets919,682948,259934,303965,969Net debt149,831187,128211,284260,670Shareholders' equity479,839461,199442,653405,148OperationsLight oil (barrels per day)6,7646,6497,6237,356NGLs (barrels per day)1,2091,2061,151996Conventional natural gas (MCF per day)30,10131,05233,32329,609Total BOE per day12,98913,03114,32813,2872022As at and for the periods ended($ 000s except $ per share)Q4Q3Q2Q1Financial Revenue - oil and gas sales 79,20264,45759,16348,794Cash flow from operations37,86824,61618,87414,745Per share - basic1.110.730.560.44Per share - diluted1.070.710.550.43Net earnings (loss) (1)16,3337,296157,354(1,684)Per share - basic0.480.224.68(0.05)Per share - diluted0.460.214.55(0.05)Capital expenditures 17,636 18,578 7,607 23,461 Total assets945,721939,835948,260748,543Net debt267,179307,729319,310328,506Shareholders' equity392,019361,590353,431195,393OperationsLight oil (barrels per day)7,6596,9487,3706,834NGLs (barrels per day)1,1059289961,025Conventional natural gas (MCF per day)30,27627,99526,05724,301Total BOE per day13,81012,54212,70911,9092021 Business Environment and Sensitivities Bonterra’s financial results may be influenced by fluctuations in commodity prices, including price differentials, as well as production volumes and foreign exchange rates. The following table depicts selective market benchmark commodity prices, differentials, and foreign exchange rates in the last eight quarters to assist in understanding how past volatility has impacted Bonterra’s financial and operating performance. The increases or decreases in Bonterra’s realized average price for oil and natural gas for each of the eight quarters is also outlined in detail in the following table. (1) This differential accounts for the majority of the difference between WTI and Bonterra’s average realized price (before quality adjustments and foreign exchange). WTI prices averaged $82.64 USD per barrel in Q4 2022, an increase of seven percent compared to the fourth quarter of 2021. Increased pricing through 2022 has been driven by continuous improvements in demand, ongoing supply discipline and reduced capital investment from both OPEC+ and US shale producers, along with geopolitical risk factors. The combination of these factors has led to lower global crude and crude product inventories, which have supported a higher price environment. In addition to the WTI benchmark price, the Company’s realized crude oil price is impacted by the MSW Stream Index or Edmonton Par differential (the “Differential”). The Differential averaged ($1.61) USD per barrel in Q4 2022, an improvement of 48 percent compared to Q4 2021. Strong North American refining demand for sweet crude, and limited pipeline apportionment contributed to the improvement in the Differential in the fourth quarter of 2022. Longer term, the Trans Mountain Expansion is expected to increase Canada’s export capabilities and is anticipated to have a positive effect on the movement and pricing of Canadian barrels. AECO daily spot prices averaged $5.09 per mcf in the fourth quarter of 2022, an increase of 10 percent over the fourth quarter of 2021. The increase is mainly due to increased global demand for North American produced gas via LNG exports, which contributed to lower natural gas inventories in North America, including Western Canada through 2022. 16 Q4-2022Q3-2022Q2-2022Q1-2022Q4-2021Q3-2021Q2-2021Q1-2021Crude oil WTI (U.S.$/bbl)82.6491.56108.4194.2977.1970.5666.0757.84WTI to MSW Stream Index Differential (U.S.$/bbl)(1)(1.61)(2.05)(0.50)(2.96)(3.10)(4.08)(3.11)(5.24)Foreign exchange U.S.$ to Cdn$1.35781.30591.27661.26621.26011.26021.22801.2663Bonterra average realized oil price (Cdn$/bbl)105.59111.44126.97110.4185.0478.4271.4961.76Natural gas AECO (Cdn$/mcf)5.094.147.204.724.633.583.083.14Bonterra average realized gas price (Cdn$/mcf)5.364.736.764.804.933.943.373.44 The following chart shows the Company’s sensitivity to key commodity price variables. The sensitivity calculations are performed independently and show the effect of changing one variable while holding all other variables constant. (1) This analysis uses current royalty rates, annualized estimated average production of 13,600 BOE per day and no changes in working capital. (2) Based on annualized basic weighted average shares outstanding of 37,004,070. Business Overview, Strategy and Key Performance Drivers Bonterra is an upstream oil and gas company that is primarily focused on the development of its Cardium land within the Pembina and Willesden Green areas located in central Alberta. The Pembina Cardium reservoir is the largest conventional oil reservoir in western Canada that features large original oil in place with very low recoveries to date. Bonterra operates approximately 93 percent of its production and the majority of its related oil and gas processing facilities, which require minimal additional capital to support an increase of production. Bonterra is committed to employing local services in Drayton Valley and to being a key economic contributor to rural and surrounding communities located within central Alberta. On November 25, 2022, Bonterra completed the restructuring of the Company’s debt capitalization through the closing of two new credit facilities (the “New Credit Facilities”). The New Credit Facilities are comprised of (i) a $110 million first lien secured credit facility (the “Bank Facility”); and (ii) a $95 million second lien secured term debt facility (the “Subordinated Term Debt”). Simultaneously with the closing of the New Credit Facilities, the Company fully repaid its $47 million Business Development Bank of Canada (“BDC”) Term Facility. The new Bank Facility totaling $110 million, of which $17.6 million has been drawn as of December 31, 2022, has been syndicated among three supportive banks. The Bank Facility is restructured as a normal course, reserve-based credit facility available on a revolving basis through October 31, 2023, with bi-annual borrowing base redeterminations and a term maturity of October 31, 2024. The new Subordinated Term Debt amortizes over four years, is non-revolving and is second lien to the Bank Facility. Fixed interest of 11.70 percent will be applied to 25 percent of the Subordinated Term Debt and floating interest of Canadian Prime Rate plus 6.25 percent applies to the remaining amount. The Subordinated Term Debt was used to facilitate the formation of the new Bank Facility through the repayment of the previous bank facility, which was set to mature on November 30, 2022, and the full repayment of the existing $47 million BDC term. The Subordinated Term Debt was arranged through a private institutional lender and provides the Company with defined term, stable capital to facilitate the continued development of Bonterra’s high-quality, conventional, light oil asset base. Furthermore, the Subordinated Term Debt facility represents a significant step forward toward the Company’s goal of implementing a shareholder returns-based business model focused on a combination of debt repayment, sustainable dividends and modest production growth. 17 Annualized sensitivity analysis on before tax cash flow, as estimated for 2023(1)Impact on cash flowChange ($)$000s$ per share(2)Realized crude oil price ($/bbl)1.002,2000.06Realized natural gas price ($/mcf)0.101,0300.03U.S.$ to Canadian $ exchange rate0.011,6940.05 The Company averaged 13,407 BOE per day of production in 2022, compared to 12,747 BOE per day in 2021, an increase of 660 BOE per day, or five percent. Quarter-over-quarter, Bonterra’s production decreased by 42 BOE per day, primarily driven by shut-in production of 245 BOE per day due to freeze-offs and equipment repairs from extremely cold weather in December. The Company is pleased to reiterate its previously announced 2023 annual guidance with average production between 13,500 to 13,700 BOE per day based on a fully funded 2023 capital expenditure budget between $120 million to $125 million. Bonterra invested capital expenditures of $79.8 million in 2022. Of the total capital invested, $56.7 million was directed to the drilling of 25 gross (24.7 net) operated wells and completing, equipping, tying-in and placing on production 31 gross (30.7 net) operated wells, with six of the completed and equipped wells having been drilled late in 2021. The Company also directed $6.1 million of the capital program to the construction of a wholly owned gas plant to resolve gas handling issues, and an additional $17.0 million was directed to related infrastructure, recompletions and non-operated capital programs. The Company has continued to focus on responsible environmental initiatives, including a targeted abandonment and reclamation program with support from the Alberta Site Rehabilitation Program (“SRP”). Throughout 2022, Bonterra successfully abandoned 123.5 net wells, 53 pipelines and two facilities, and plans to abandon an additional 55.0 net wells and 153 pipelines in 2023. By the end of 2023, Bonterra expects to have abandoned approximately 82 percent of all wells identified as having no further economic potential. As part of the Company’s ongoing efforts to diversify commodity pricing and to protect future cash flows, Bonterra has executed physical delivery sales and risk management contracts to the end of Q3 2023 on approximately 30 percent of its expected crude oil and natural gas production. For the next nine months, Bonterra has secured a WTI price between $50.00 USD to $103.30 USD per bbl on 2,282 bbls per day, with a WTI to Edmonton par differential at prices ranging from approximately $3.50 USD to $4.95 USD per barrel on 1,161 bbls per day. In addition, the Company has secured natural gas prices between $3.85 to $5.00 per GJ on 9,333 GJ per day to the end of Q3 2023. Bonterra’s successful operations are dependent upon several factors including, but not limited to: commodity prices, efficient management of capital spending, the ability to maintain desired production levels, control over infrastructure, efficiency in developing and operating properties, and the ability to control costs. The Company’s key measures of performance with respect to these drivers include, but are not limited to, average daily production volumes, average realized prices, and average production costs per unit of production. Disclosure of these key performance measures can be found within this MD&A and/or previous interim or annual MD&A disclosures. 18 Drilling (1) “Gross” wells are the number of wells in which Bonterra has a working interest. (2) “Net” wells are the aggregate number of wells obtained by multiplying each gross well by Bonterra’s percentage of working interest. During 2022, the Company drilled 25 gross (24.7 net) operated wells and completed, tied-in and placed on production 31 gross (30.7 net) operated wells, of which six gross (6.0 net) operated wells were drilled in the fourth quarter of 2021. In the first two months of 2023, the Company drilled twelve gross (11.0 net) operated wells of which four gross (4.0 net) were placed on production by the end of February. Production The Company averaged 13,407 BOE per day of production in 2022, compared to 12,747 BOE per day for 2021, an increase of 660 BOE per day or five percent. The increase in production is largely due to the Company’s increased drilling program and the reactivation of off-line wells given higher commodity prices. Cash Netback The following table illustrates the calculation of the Company’s cash netback from operations for the periods ended: Cash netbacks increased in 2022 compared to 2021 primarily due to higher realized commodity prices and lower interest expense from reduced debt. This was partially offset by increased royalties and production costs. Quarter-over-quarter cash netbacks increased primarily due to decreased royalties and production costs, which was partially offset by decreased commodity prices and an increase in current income tax. 19 Gross(1)Net(2)Gross(1)Net(2)Gross(1)Net(2)Gross(1)Net(2)Gross(1)Net(2)Crude oil horizontal-operated 2 2.0 8 8.0 8 8.02524.73735.4Crude oil horizontal-non-operated - - 3 0.4 2 0.4 9 1.1 2 0.4 Total 2 2.0 11 8.4108.43425.83935.8Success rate100%100%100%100%100% Three months endedYear endedDecember 31, 2022September 30, 2022December 31, 2021December 31, 2022December 31, 2021December 31, 2022September 30, 2022December 31, 2021December 31, 2022December 31, 2021Crude oil (barrels per day)6,764 6,649 7,659 7,095 7,204 NGLs (barrels per day)1,209 1,206 1,105 1,141 1,013 Natural gas (MCF per day)30,101 31,052 30,276 31,023 27,176 Average BOE per day12,989 13,031 13,810 13,407 12,747 Three months endedYear ended$ per BOEDecember 31, 2022September 30, 2022December 31, 2021December 31, 2022December 31, 2021Production volumes (BOE)1,195,0301,198,8351,270,4884,893,5604,652,719Gross production revenue72.93 74.09 62.34 78.51 54.08 Realized loss on risk management (1.04)(2.59)(5.24)(3.45)(3.74)Royalties(12.79)(15.16)(6.94)(12.68)(5.53)Production costs(16.11)(20.33)(15.70)(17.45)(15.19)Field netback 42.9936.0134.46 44.93 29.62 General and administrative(1.78)(2.47)(2.64)(2.43)(2.20)Interest and other (3.19)(2.87)(3.10)(2.98)(4.89)Current income tax(3.59)(1.10) - (1.60) - Cash netback 34.43 29.57 28.72 37.92 22.53 Three months endedYear ended Oil and Gas Sales Revenue from oil and gas sales in 2022 increased by $132.6 million, or 53 percent, compared to 2021. This increase was primarily driven by a 53 percent increase in Bonterra’s realized crude oil prices and a five percent increase in average annual production volumes. Bonterra’s product split on a revenue basis was weighted approximately 84 percent to crude oil and NGLs during 2022. Royalties Royalties paid by the Company consist of both Crown royalties to the Provinces of Alberta, Saskatchewan and British Columbia and other royalties. Total royalties for 2022 increased by $7.15 per BOE compared to the same period of 2021. The increase was primarily the result of commodity price increases. Quarter-over-quarter royalties decreased by $2.37 per BOE, primarily due to a 17 percent decrease in the Alberta Crown reference price for light sweet oil, which decreased the Alberta Crown royalty rates for crude oil in the fourth quarter of 2022 compared to the third quarter of 2022. 20 December 31, 2022September 30, 2022December 31, 2021December 31, 2022December 31, 2021Revenue - oil and gas sales ($ 000s)Light oil65,70468,16659,924295,046195,985NGL6,6047,1555,54327,49716,225Conventional natural gas14,84613,50613,73561,65439,40687,15488,82779,202384,197251,616Average realized prices:Light oil ($ per barrel)105.59111.4485.04113.9374.53NGL ($ per barrel)59.3864.4554.5466.0043.86Conventional natural gas ($ per MCF)5.364.734.935.443.97Average ($ per BOE)72.9374.0962.3478.5154.08Average BOE per day12,98913,03113,81013,40712,747 Three months endedYear ended($ 000s)December 31, 2022September 30, 2022December 31, 2021December 31, 2022December 31, 2021Crown royalties11,23914,2405,71644,84215,241Freehold, gross overriding and other royalties4,0423,9343,09917,23310,509Total royalties15,28118,1748,81562,07525,750Crown royalties - percentage of revenue12.916.07.211.76.1Freehold, gross overriding and other royalties - percentage of revenue4.64.43.94.54.2Royalties - percentage of revenue17.520.411.116.210.3Royalties $ per BOE12.7915.166.9412.685.53 Three months endedYear ended Production Costs Production costs for 2022 increased compared to 2021 primarily due to increased production and maintenance costs along with increased well reactivations as the Company expanded the number of service rigs to four in the current year compared to two in the prior year. Bonterra also invested additional funds in the Company’s pipeline integrity program in 2022 compared to 2021. The Company will continue to invest in pipeline consolidation which is expected to lead to reduced pipeline maintenance costs in 2023. On a per BOE basis, production costs also increased due to maintaining the same level of activity while having shut-in production from gas handling operations, combined with general inflationary pressures and escalating fuel and power prices. Production costs decreased quarter-over-quarter primarily due to less well and facility maintenance that tends to occur in the third quarter. Other Income Deferred consideration relates to a deferred gain on the sale of a two percent overriding royalty interest, which is recognized into revenue using the same unit-of-production method as the encumbered property, plant, and equipment assets. The market value and carrying value of the investments held by the Company on December 31, 2022 totaled $2,028,000 (December 31, 2021 - $891,000). There were no dispositions during the period ended December 31, 2022 or December 31, 2021. Dispositions that result in a gain or loss on sale are recorded as an equity transfer between accumulated other comprehensive income and retained earnings. The Company receives administrative income for various oil and gas administrative services provided and production equipment rentals to other companies. The Government of Alberta’s SRP provides grant funding through service providers to abandon or remediate oil and gas sites. The Company derecognized approximately $3.7 million of asset retirement obligations as an in-kind grant in 2022 (December 31, 2021 - $5.9 million). The benefit of the in-kind grant is recognized through other income. 21 ($ 000s except $ per BOE)December 31, 2022September 30, 2022December 31, 2021December 31, 2022December 31, 2021Production costs19,25124,36619,95185,38570,670$ per BOE16.1120.3315.7017.4515.19 Three months endedYear ended($ 000s)December 31, 2022September 30, 2022December 31, 2021December 31, 2022December 31, 2021Investment income 115 50 38 221 67Administrative income 207 174195 706 487Gain on sale of property - - 225 - 225 Government grant in-kind 1,272 791 1,009 3,675 5,901 Deferred consideration 293 261 364 1,158 1,292 Realized loss on risk management contracts (1,245)(3,103)(6,657) (16,878)(17,389)Unrealized gain (loss) on risk management contracts (246) 11,046 7,190 5,365 (968) 396 9,219 2,364 (5,753) (10,385) Three months endedYear ended To minimize commodity price risk on crude oil and natural gas sales, Bonterra has entered into financial derivatives. The financial derivatives outstanding are for the period from January 1, 2023 to September 30, 2023 and are for a total of 487,450 barrels of light crude oil (approximately 1,786 barrels of oil per day for the next nine months) at fixed WTI prices ranging from $50.00 USD to $103.30 USD per barrel, with a fixed differential from WTI to Edmonton Par prices for 272,000 barrels of oil (approximately 996 barrels of oil per day) at prices ranging from approximately $3.50 to $4.95 USD per barrel. In addition, the Company has entered into financial derivatives on natural gas prices between $4.00 and $5.00 on 4,670 GJ per day for the first nine months of 2023. These contracts are not considered normal sales contracts and are recorded at fair value. General and Administrative (“G&A”) Expense Employee compensation expense increased by $1.6 million for 2022 compared to 2021. The increase is primarily due to a greater bonus accrual. Recurring office and administrative expense increased in 2022 compared to 2021 due to an increase in technical and advisory consulting fees, insurance premiums and bank renewal fees. Nonrecurring office and administrative costs reflect expenditures related to successfully defending an unsolicited hostile bid for the Company that expired March 29, 2021. Finance Costs Interest on bank debt decreased in 2022 compared to 2021 due to a decrease of approximately 60 percent in the average bank debt outstanding as well as a decrease in interest rates stemming from a reduction in the Company’s net debt to earnings before income taxes and depletion and amortization (or “EBITDA” as defined by the Company’s Bank Facility) ratio. With increased cash flow, the Company was able to eliminate the term portion of the facility on its bank debt which had a less favourable interest rate grid. Bank debt interest rates for the current quarter are determined based on the trailing twelve month period and 22 ($ 000s except $ per BOE)December 31, 2022September 30, 2022December 31, 2021December 31, 2022December 31, 2021Employee compensation1,1871,9972,4617,4895,924Office and administrative - recurring9429608914,4183,379Total G&A recurring2,1292,9573,35211,9079,303Office and administrative - nonrecurring - - - - 946 Total G&A2,1292,9573,35211,90710,249$ per BOE recurring1.782.472.642.432.00$ per BOE nonrecurring - - - - 0.20 $ per BOE total1.782.472.642.432.20 Three months endedYear ended($ 000s except $ per BOE)December 31, 2022September 30, 2022December 31, 2021December 31, 2022December 31, 2021Interest on bank debt and subordinated debt 1,612 2,3483,0638,97421,332Subordinated debentures 1,327 1,328 1,047 5,310 1,047 Subordinated term debt 1,193 - 1,193 - Other interest - - 62 - 890 Interest expense4,1323,6764,17215,47723,269$ per BOE3.463.073.283.165.00Accretion of decommissioning liabilities9701,1798293,5673,230Accretion on subordinated debentures681 603 410 2,411 410 Accretion on subordinated term debt192 - - 192 - Total finance costs5,9755,4585,41121,64726,909 Three months endedYear ended calculated by taking the ratio of total debt (excluding accounts payable and accrued liabilities) to EBITDA (defined as net income excluding finance costs, provision for current and deferred taxes, depletion and depreciation, share-option compensation, gain or loss on sale of assets and impairment of assets). Subordinated debt interest relates to the Business Development Bank of Canada (“BDC”) $47 million second lien non-revolving four-year term loan (the “BDC Loan”). Interest on the BDC Loan was $2.6 million (December 31, 2021 - $2.2 million). The BDC loan was repaid on November 25, 2022. Subordinated Term Debt is senior, unsecured and at December 31, 2022 was $95 million. The Subordinated Term Debt has a fixed interest rate of 11.70 percent on 25 percent of the principal balance and a floating interest rate of Canadian Prime plus 6.25 percent on the remaining amount. Based on the calculated fair value of the Subordinated Term Debt as at December 31, 2022, the effective interest rate was determined to be 15.8 percent using the effective interest rate method. The value of the debt will accrete up to the principal balance at maturity. For more information on Subordinated Term Debt, refer to Note 11 of the December 31, 2022, audited annual financial statements. Subordinated Debentures are unsecured and were determined to be a compound instrument with a debt and equity component. The fair value of the $59 million debt component was reduced by the residual value of the issuance 3,304,000 warrants and issue costs. The debentures have a fixed interest rate of nine percent, payable semi-annually. Based on the calculated fair value of the Subordinated Debentures as at December 31, 2022, the effective interest rate was determined to be 15.6 percent using the effective interest rate method. The value of the Subordinated Debentures will accrete up to the principal balance at maturity. For more information on Subordinated debentures, refer to Note 10 of the December 31, 2022, audited annual financial statements. A one percent increase (decrease) in the Canadian prime rate would decrease (increase) both annual net earnings and comprehensive income by approximately $691,000. For more information on bank debt and subordinated term debt, see the Liquidity and Capital Resources section herein. Share-Option Compensation Share-option compensation is a statistically calculated value representing the estimated expense of issuing employee stock options. The Company records a compensation expense over the vesting period based on the fair value of options granted to directors, officers and employees. Based on the outstanding options as of December 31, 2022, the Company has an unamortized expense of $4,180,000, of which $2,554,000 will be recognized in 2023; $1,248,000 in 2024 and $378,000 thereafter. For more information about options issued and outstanding, refer to Note 14 of the December 31, 2022, audited annual financial statements. 23 ($ 000s)December 31, 2022September 30, 2022December 31, 2021December 31, 2022December 31, 2021Share-option compensation6325252591,9101,095 Three months endedYear ended Depletion and Depreciation, Exploration and Evaluation (“E&E”) and Impairment The provision for depletion and depreciation (“D&D”) increased in 2022 compared to 2021 primarily due to increased capital spending, higher production volumes and a greater carrying value to deplete from a $203.2 million impairment reversal on Bonterra’s Alberta cash generating unit (“CGU”) property, plant and equipment (“PP&E”) in the second quarter of 2021. Taxes The Company recorded a deferred income tax expense of $17.7 million (2021 – $53.7 million). The decrease in deferred income tax expense for 2022 compared to 2021 was primarily due to a decrease in earnings before income taxes, as in Q2 2021 the Company recorded a $203 million impairment reversal. The Company recorded $7.8 million of current income tax expense, of which $4.7 million is payable to the province of Alberta. The Company used $3.1 million in investment tax credits to offset the federal income tax owing. For additional information regarding income taxes, see Note 13 of the December 31, 2022 audited annual financial statements. Net Earnings Net earnings for 2022 decreased by $100.3 million compared to 2021. The decrease in net earnings was primarily attributed to an impairment reversal less the deferred income tax on the impairment reversal recorded in Q2 2021. Adjusting net earnings for the impairment reversal and corresponding deferred tax, net earnings increased by $56.0 million, primarily due to an increase in oil and gas sales and a decrease in finance costs and loss on risk management contracts. This increase in adjusted net earnings was partially offset by an increase in royalties, production costs and an increased income tax provision. 24 ($ 000s)December 31, 2022September 30, 2022December 31, 2021December 31, 2022December 31, 2021Depletion and depreciation 21,929 23,69722,56790,95176,791Impairment (reversal of impairment) - - - - (203,197) Three months endedYear ended($ 000s except $ per share)December 31, 2022September 30, 2022December 31, 2021December 31, 2022December 31, 2021Net earnings17,26417,69616,33379,023179,299Adjust for:Reversal of impairment - - - - (203,197)Deferred tax on reversal of impairment - - - - 46,796Adjusted net earnings17,26417,69616,33379,02322,898$ net earnings per share - basic0.470.490.482.205.32$ net earnings per share - diluted0.460.470.462.125.16$ adjusted net earnings per share - basic0.470.490.482.200.68$ adjusted net earnings per share - diluted0.460.470.462.120.66 Three months endedYear ended Other Comprehensive Income Other comprehensive income for 2022 consists of an unrealized gain before tax on investments (including investment in a related party) of $1,137,000 relating to an increase in the investments’ fair value (December 31, 2021 –$598,000). Realized gains result in decreases to accumulated other comprehensive income as these gains are transferred to retained earnings. Other comprehensive income varies from net earnings by unrealized changes in the fair value of Bonterra’s holdings of investments, including the investment in a related party, net of tax. Cash Flow From Operations In 2022, cash flow from operations increased by $87.5 million compared to 2021. This was primarily due to an increase in commodity prices and production volumes and a decrease in interest expense, which was partially offset by an increase in royalties and production costs. Quarter-over-quarter, cash flow from operations decreased due to a decrease in non-cash working capital, which was partially offset by lower production costs. Liquidity and Capital Resources Net Debt to Cash Flow from Operations Bonterra continues to focus on reducing overall debt while managing its cash flow and capital expenditures. The Company’s net debt to twelve month trailing cash flow ratio as of December 31, 2022 was 0.8 to 1 times (versus 2.8 to 1 times at December 31, 2021). The decreased net debt to cash flow ratio is the result of an increase in the Company’s twelve month trailing cash flow, which was primarily driven by rising commodity prices and production volumes. Average net debt for 2022 decreased by $103 million compared to the same period of 2021, related to a 91 percent increase in cash flow due to higher commodity prices and production volumes. Working Capital Deficiency and Net Debt Net debt is a combination of Bank Debt, Subordinated Debentures, Subordinated Term Debt and working capital. As of December 31, 2022, the Company’s Bank Facility has a maturity date of October 31, 2024 and is recorded as a long-term liability. Included in working capital deficiency is $20.2 million of principal payments and accrued interest on the Subordinated Term Debt loan. Bonterra actively monitors its credit availability and working capital to ensure that it has sufficient available funds to meet its financial 25 ($ 000s except $ per share)December 31, 2022September 30, 2022December 31, 2021December 31, 2022December 31, 2021Cash flow from operations35,49448,81037,868183,55396,103$ per share - basic0.971.351.115.102.85$ per share - diluted0.951.301.074.922.76 Three months endedYear ended($ 000s)December 31, 2022December 31, 2021Working capital deficiency12,578172,552Bank Debt 17,601 - Subordinated Debt - 47,268 Subordinated Debentures 49,770 47,359 Subordinated Term Debt (long-term portion) 69,882 - Net Debt149,831267,179 requirements as they come due. Any of these events present risks that could affect Bonterra’s ability to fund ongoing operations. If required, Bonterra will also consider short-term or long-term financing alternatives in order to meet its future liabilities. Net debt at December 31, 2022 decreased by $117.3 million to $149.8 million compared to $267.2 million at December 31, 2021, primarily due to increased cash flow resulting from rising commodity prices and higher production volumes. The Company intends to continue its focus on net debt reduction. Working capital is calculated as current assets less current liabilities. Financial Risk Management Bonterra is exposed to market risk for the oil and gas produced by the Company. External factors beyond the Company’s control may affect the marketability of oil and gas produced. Oil prices are affected by worldwide supply and demand fundamentals and access to market, while natural gas prices are largely affected by North American supply and demand fundamentals. In order to manage commodity risk, the Company executed physical delivery sales contracts which are considered normal sales contracts and are not recorded at fair value in the financial statements, and also executed risk management contracts which are not considered normal sales contracts and are recorded at fair value. The Company has contracts in place on approximately 30 percent of its estimated oil and gas production to the end of Q3 2023. The Company relies on its cash flow, access to equity markets and bank financing to support its operations and capital program. Bonterra uses these futures contracts to hedge its exposure to the potential adverse impact of commodity price volatility and provide a measure of stability to Bonterra’s capital development program. For more information on physical delivery and risk management contracts in place, see Note 18 of the December 31, 2022, audited annual financial statements. Capital Expenditures During the year ended December 31, 2022, the Company incurred capital expenditures of $79.8 million (December 31, 2021 - $67.3 million). Of the total capital invested, $56.7 million was directed to the drilling of 25 gross (24.7 net) operated wells and the completion, equip and tie-in of 31 gross (30.7 net) operated wells, of which six of the completed and equipped wells were drilled in 2021. All of the wells drilled were placed on production in 2022. The Company also spent $6.1 million on the construction of a wholly owned gas plant and an additional $17.0 million was spent primarily on related infrastructure, recompletions and non-operated capital programs. Decommissioning Liabilities The Company spent $5.9 million on decommissioning activities in 2022 excluding any Alberta SRP funding. Over the past three years, Bonterra successfully abandoned 487.8 net wells, 234 pipelines and five facilities. With Bonterra’s extensive targeted abandonment and reclamation program, the Company revised its abandonment costs with regards to older vintage wells and increased the total uninflated and undiscounted decommissioning liability to $178.1 million (December 31, 2021 - $153.1 million). The change in the Company’s decommissioning liability for these wells was due to a change in the estimated scope of work to abandon these wells and the significant cost increases due to recent inflation. Offsetting the increase in the decommissioning liability from the beginning of the year, was a 0.97 percent increase in the risk-free discount rate. As a result, the decommissioning liability went from $135.8 million for December 31, 2021 to $109.2 million for December 31, 2022, primarily due to the effect of increase in the discount rate exceeding the additional uninflated and undiscounted changes in estimated costs. 26 Bonterra also paid $2.4 million in abandonment deposits primarily in its non-core area in British Columbia. These deposits are refundable upon abandonment and reclamation of the area or further development. For more information see Note 12 of the December 31, 2022 audited annual financial statements. Bank Debt and Subordinated Term Debt Bank debt represents the outstanding amounts drawn on the Company’s Bank Facility. As at December 31, 2022, the Company has a total Bank Facility of $110.0 million, comprised of a $85.0 million syndicated revolving credit facility and a $25.0 million non-syndicated revolving facility. The amount drawn under the total Bank Facility at December 31, 2022 was $17.6 million (December 31, 2021 - $162.9 million). The amounts borrowed under the total Bank Facility bear interest at a floating rate based on the applicable Canadian prime rate or Banker’s Acceptance rate, plus between 2.00 percent and 7.00 percent, depending on the type of borrowing and the Company’s consolidated debt to EBITDA ratio. EBITDA is defined as net income for the period excluding finance costs, provision for current and deferred taxes, depletion and depreciation, share-option compensation, gain or loss on sale of assets and impairment of assets. The terms of the total revolving Bank Facility provide that the loan facility is revolving to October 31, 2023, with a maturity date of October 31, 2024. The credit facility has no set terms of repayment. As at December 31, 2022, Bonterra classified its bank debt as a long-term liability. The Company was in compliance with all financial covenants on its total Bank Facility as at December 31, 2022. The amount available for borrowing under the Bank Facility is reduced by outstanding letters of credit. Letters of credit totaling $2.1 million were issued as at December 31, 2022 (December 31, 2021 - $1.4 million). Security for the Bank Facility consists of various floating demand debentures totaling $750 million (December 31, 2021 - $750 million) over all of the Company’s assets and a general security agreement with first ranking over all personal and real property. Subordinated Term Debt represents a four-year second lien, non-revolving subordinated term debt facility. The amounts borrowed under the Subordinated Term Debt bear interest at a fixed rate of 11.70 percent to be applied to 25 percent of the term facility principle and a floating interest rate of Canadian Prime Rate plus 6.25 percent on the remaining 75 percent of the principal amount. The Company is required to make mandatory principal repayments equal to $4.75 million, payable on the last banking day of February, May, August and November of each calendar year, commencing on February 28, 2023. The term debt has a maturity date of November 30, 2026 on which the remaining outstanding principle balance is to be paid. The amount drawn under the Subordinated Term Debt at December 31, 2022 was $95 million (December 31, 2021 - $Nil). Based on the calculated fair value of the debt as at December 31, 2022, the effective interest rate was determined to be 15.8 percent, by discounting future payments of interest and principal with the residual value allocated to issue costs of $6.3 million. The value of the debt will accrete up to the principal balance at maturity. Interest accrued in 2022 was $1.2 million (December 31, 2021 - $Nil). The funds received were used to completely repay the Subordinated debt, a portion of the Company’s outstanding bank debt and general corporate purposes. Security for the Subordinated Term Debt consists of various floating demand debentures totaling $150 million (December 31, 2021 - $Nil) over all of the Company’s assets and a general security agreement with second ranking over all personal and real property. 27 Financial Covenants The Company is subject to certain financial covenants under its Bank Facility and Subordinated Term Debt facility as follows: • Consolidated debt to forecasted EBITDA Ratio shall not exceed 2.50:1.00; and • Asset Coverage Ratio of not less that 1.50:1. Asset Coverage ratio is defined as the proved developed producing reserves of the Company (before income tax; discounted at 10 percent), as evaluated by an independent third-party engineering report and evaluated on strip commodity pricing, divided by the consolidated debt of the Company. The ratio is calculated and revaluated for strip pricing on June 30 and December 31 period ends. As at December 31, 2022, Bonterra was in compliance with all financial covenants on its first and second lien facilities. For more information about bank debt and Subordinated Term Debt, please see Note 8 and 11, respectively, of the December 31, 2022 audited annual financial statements. Shareholders’ Equity The Company is authorized to issue an unlimited number of common shares without nominal or par value. The Company is also authorized to issue an unlimited number of Class “A” redeemable Preferred Shares and an unlimited number of Class “B” Preferred Shares. There are currently no outstanding Class “A” redeemable Preferred Shares or Class “B” Preferred Shares. Total of 2,753,000 Warrants are outstanding as at December 31, 2022, entitling the holder to purchase one Common Share of Bonterra for each Warrant at a price of $7.75, until October 20, 2025. The Company provides a stock option plan for its directors, officers and employees. Under the plan, the Company may grant options for up to 3,691,289 (December 31, 2021 – 3,500,095) common shares. The exercise price of each option granted will not be lower than the market price of the common shares on the date of grant and the option’s maximum term is five years. For additional information regarding warrants and options outstanding, see Note 14 of the December 31, 2022, audited annual financial statements. 28 Issued and fully paid - common sharesNumberAmount($ 000s)NumberAmount($ 000s)Balance, beginning of year35,000,952772,78133,511,316765,415Shares issued for interest on subordinated promissory note - - 118,896414Issued pursuant to the Company's share option plan1,360,9401,612 183,740 378 Transfer from contributed surplus to share capital1,804 168 Issued pursuant to the exercise of warrants 551,000 4,270 - - Transfer from warrants to share capital 1,212 - Issuance of flow through shares - - 1,187,000 7,003 Premium on flow through shares - (356)Share issue costs, net of tax - (241)Balance, end of year36,912,892781,67935,000,952772,781December 31, 2022December 31, 2021 Quarterly Financial Information The fluctuations in the Company’s revenue and net earnings from quarter-to-quarter are caused by variations in production volumes, realized commodity pricing and the related impact on royalties, production, G&A and finance costs. Net earnings in Q2 2021 were significantly higher than other quarters due to an impairment reversal on the Company’s Alberta CGU from a previous impairment provision taken during the COVID-19 pandemic. More recent quarters’ results have also been positively affected by the rise in oil and natural gas prices primarily due to current geopolitical events and lack of global supply. Contractual Obligations and Commitments At December 31, 2022 the Company has the following contractual obligations and commitments: (1) Principal amount. Off-Balance Sheet Financing Bonterra does not have any guarantees or off-balance sheet arrangements that have been excluded from the annual statement of financial position or balance sheet other than commitments disclosed in Note 18 of the December 31, 2022 audit annual financial statements. 29 For the periods ended($ 000s except $ per share)Q4Q3Q2Q1Revenue - oil and gas sales87,15488,827116,67491,542Cash flow from operations35,49448,81058,30740,942Net earnings (loss)17,26417,69633,54410,519Per share - basic0.470.490.930.30Per share - diluted0.460.470.880.292022For the periods ended($ 000s except $ per share)Q4Q3Q2Q1Revenue - oil and gas sales79,20264,45759,16348,794Cash flow from operations37,86824,61618,87414,745Net earnings (loss)16,3337,296157,354(1,684)Per share - basic0.480.224.68(0.05)Per share - diluted0.460.214.55(0.05)2021($ 000s)Less than 1 yearOver 1 year to 3 yearsOver 3 years to 5 yearsOver 5 years to 7 yearsTotalAccounts payable and accrued liabilities35,573 - - - 35,573 Bank debt- 17,601 - - 17,601 Subordinated debentures(1)- - 59,000 - 59,000 Subordinated term debt(1)19,000 38,000 38,000 - 95,000 Future interest16,047 28,439 3,761 - 48,247 Firm service commitments1,045 1,201 611 103 2,960 Office lease commitments486 1,010 499 - 1,995 Total72,151 86,251 101,871 103 260,376 Critical Accounting Estimates There have been no changes to the Company’s critical accounting policies and estimates as of the period ended in the financial statements. Assessment of Business Risk Bonterra’s exploration and production activities are concentrated in the Western Canadian Sedimentary Basin, where activity is highly competitive and includes a variety of different sized companies. Bonterra is subject to a number of risks that are also common to other organizations involved in the oil and gas industry. Such risks include finding and developing oil and gas reserves at economic costs, estimating amounts of recoverable reserves, production of oil and gas in commercial quantities, marketability of oil and gas produced, fluctuations in commodity prices, stock market volatility, debt servicing which may limit the market price of shares, financial and liquidity risks and environmental and safety risks. The Company mitigates its risk related to producing hydrocarbons through the utilization of hedging a portion or product sales, current technology and information systems. In addition, Bonterra strives to operate the majority of its properties, thereby maintaining operational control where possible. The Company’s business, operations and financial condition has been significantly adversely affected by COVID-19. Actions taken to reduce the spread of COVID-19 resulted in volatility and disruptions in regular business operations, supply chains and financial markets. COVID-19 also posed a risk on the financial capacity of Bonterra’s contract counterparties and potentially their ability to perform contractual obligations. These difficulties have been exacerbated in Canada by political and other actions resulting in uncertainty surrounding regulatory, tax, royalty changes and environmental regulation. Additional information regarding risk factors including, but not limited to, business risks is available in the Company’s Annual Information Form for the year ended December 31, 2022, which can be accessed on its website www.bonterraenergy.com or on SEDAR at www.sedar.com. Environmental Risk General Risks Oil and gas exploration and production can involve environmental risks such as litigation, physical and regulatory risks. Physical risks include the pollution of the environment, climate change and destruction of natural habitats, as well as safety risks such as personal injury. The Company conducts its operations while ensuring it protects the environment, various stakeholders, and the general public. Bonterra maintains current insurance coverage for comprehensive and general liability as well as limited pollution liability. The amount and terms of this insurance are reviewed on an ongoing basis and adjusted as necessary to reflect current corporate requirements, availability, as well as industry standards and government regulations. Without such insurance, and if the Company becomes subject to environmental liabilities, the payment of such liabilities could reduce or eliminate its available funds or could exceed the funds the Company has available and result in financial distress. Climate Change Risks Bonterra’s exploration and production facilities and other operations and activities emit greenhouse gasses ("GHG") which require the Company to comply with federal and/or provincial GHG emissions legislation. Climate change policy is evolving at regional, national and international levels, and political and economic events may significantly affect the scope and timing of climate change measures that are ultimately put in 30 place to prevent climate change or mitigate Bonterra’s effects. The direct or indirect costs of compliance with GHG-related regulations may have a material adverse effect on the Company’s business, financial condition, results of operations and prospects. Some of its significant facilities may ultimately be subject to future regional, provincial and/or federal climate change regulations to manage GHG emissions. In addition, climate change has been linked to long-term shifts in climate patterns and extreme weather conditions, both of which pose the risk of causing operational difficulties. Additional information regarding risk factors including, but not limited to, environmental risks is available in the Company’s Annual Information Form for the year ended December 31, 2022, which can be accessed on its website at www.bonterraenergy.com or on SEDAR at www.sedar.com. Forward-Looking Information Certain statements contained in this MD&A include statements which contain words such as “anticipate”, “could”, “should”, “expect”, “seek”, “may”, “intend”, “likely”, “will”, “believe” and similar expressions, relating to matters that are not historical facts, and such statements of our beliefs, intentions and expectations about development, results and events which will or may occur in the future, constitute “forward-looking information” within the meaning of applicable Canadian securities legislation and are based on certain assumptions and analysis made by us derived from our experience and perceptions. Forward-looking information in this MD&A includes, but is not limited to: estimated production; cash flow sensitivity to commodity price variables; abandonment and reclamation activities and targets; expected cash provided by continuing operations; cash dividends; future capital expenditures, including the amount and nature thereof; oil and natural gas prices and demand; expansion and other development trends of the oil and gas industry; business strategy and outlook; expansion and growth of our business and operations; maintenance of existing customer, supplier and partner relationships; supply channels; accounting policies; and other such matters. All such forward-looking information is based on certain assumptions and analyses made by us in light of our experience and perception of historical trends, current conditions and expected future developments, as well as other factors we believe are appropriate in the circumstances. The risks, uncertainties, and assumptions are difficult to predict and may affect operations, and may include, without limitation: foreign exchange fluctuations; equipment and labour shortages and inflationary costs; general economic conditions; industry conditions; changes in applicable environmental, taxation and other laws and regulations as well as how such laws and regulations may limit growth or operations within the oil and gas industry; the impact of climate-related financial disclosures on financial results; the ability of the Company to raise capital, maintain its syndicated bank facility and refinance indebtedness upon maturity; the effect of weather conditions on operations and facilities; the existence of operating risks; volatility of oil and natural gas prices; oil and gas product supply and demand; risks inherent in the ability to generate sufficient cash flow from operations to meet current and future obligations; increased competition; stock market volatility; credit risks; climate change risks; cyber security; opportunities available to or pursued by us; and other factors, many of which are beyond our control. The foregoing factors are not exhaustive. Actual results, performance or achievements could differ materially from those expressed in, or implied by, this forward-looking information and, accordingly, no assurance can be given that any of the events anticipated by the forward-looking information will transpire or occur, or if any of them do, what benefits will be derived therefrom. Except as required by law, Bonterra disclaims any intention or obligation to update or revise any forward-looking information, whether as a result of new information, future events or otherwise. The forward-looking information contained herein is expressly qualified by this cautionary statement. 31 Disclosure Controls and Procedures Disclosure controls and procedures (“DC&P”), as defined in National Instrument 52-109 Certification of Disclosure in Issuers’ Annual and Interim Filings, are designed to provide reasonable assurance that information required to be disclosed in the Company’s annual filings, interim fillings or other reports filed, or submitted by the Company under securities legislation is recorded, processed, summarized and reported within the time periods specified under securities legislation and include controls and procedures designed to ensure that information required to be disclosed is accumulated and communicated to management, including the Chief Executive Officer and Chief Financial Officer, as appropriate, to allow timely decisions regarding required disclosure. The Chief Executive Officer and Chief financial Officer of Bonterra evaluated the effectiveness of the design and operation of the Company’s DC&P. Based on that evaluation, the Chief Executive Officer and the Chief Financial Officer concluded that Bonterra’s DC&P were effective at December 31, 2022. Internal Controls Over Financial Reporting Internal control over financial reporting (“ICFR”), as defined in National Instrument 52-109, includes those policies and procedures that: 1. Pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect transactions and dispositions of Bonterra; 2. Are designed to provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles and that receipts and expenditures of Bonterra are being made in accordance with authorizations of management and Directors of Bonterra; and 3. Are designed to provide reasonable assurance regarding prevention or timely detection of authorized acquisition, use, or disposition of the Company’s assets that could have a material effect on the financial statements. The CEO and CFO have designed, or caused to be designed under their supervision, ICFR as defined in National Instrument 52-109 of the Canadian Securities Administrators, in order to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with IFRS. The control framework the Company used to design its ICFR was in accordance with the Committee of Sponsoring Organizations of the Treadway Commission (COSO 2013). The Company’s CEO and CFO have evaluated, or caused to be evaluated under their supervision, the effectiveness of the Company’s internal controls over financial reporting at the financial period end of the Company and concluded that such internal controls over financial reporting are effective as of December 31, 2022. It should be noted that while Bonterra’s CEO and CFO believe that the Company’s internal controls and procedures provide a reasonable level of assurance and are effective, they do not expect that these controls will prevent all errors and fraud. 32 MANAGEMENT’S RESPONSIBILITY FOR FINANCIAL STATEMENTS The information provided in this report, including the financial statements, is the responsibility of management. The timely preparation of the financial statements requires that management make estimates and use judgment regarding the reported amounts of assets and liabilities and disclosures of contingent assets and liabilities as at the date of the financial statements and the reported amounts of revenues and expenses during the period. Such estimates primarily relate to unsettled transactions and events as at the date of the financial statements. Accordingly, actual results may differ from estimated amounts as future confirming events occur. Management believes such estimates have been based on careful judgments and have been properly reflected in the accompanying financial statements. Management maintains a system of internal controls to provide reasonable assurance that the Company’s assets are safeguarded and to facilitate the preparation of relevant and timely information. Deloitte LLP has been appointed by the Shareholders to serve as the Company’s external auditors. They have examined the financial statements and provided their auditor’s report. The audit committee has reviewed these financial statements with management and the auditors, and has reported to the Board of Directors. The Board of Directors has approved the financial statements as presented in this annual report. “Signed Patrick G. Oliver” “Signed Robb D. Thompson” Patrick G. Oliver Chief Executive Officer March 9, 2023 Robb D. Thompson Chief Financial Officer March 9, 2023 33 INDEPENDENT AUDITOR’S REPORT To the Shareholders of Bonterra Energy Corp. Opinion We have audited the financial statements of Bonterra Energy Corp. (the “Company”), which comprise the statements of financial position as at December 31, 2022 and 2021, and the statements comprehensive income, cash flow and changes in equity for the years then ended, and notes to the financial statements, including a summary of significant accounting policies (collectively referred to as the “financial statements”). In our opinion, the accompanying financial statements present fairly, in all material respects, the financial position of the Company as at December 31, 2022 and 2021, and its financial performance and its cash flows for the years then ended in accordance with International Financial Reporting Standards (“IFRS”). Basis for Opinion We conducted our audit in accordance with Canadian generally accepted auditing standards (“Canadian GAAS”). Our responsibilities under those standards are further described in the Auditor’s Responsibilities for the Audit of the Financial Statements section of our report. We are independent of the Company in accordance with the ethical requirements that are relevant to our audit of the financial statements in Canada, and we have fulfilled our other ethical responsibilities in accordance with these requirements. We believe that the audit evidence we have obtained is sufficient and appropriate to provide a basis for our opinion. Key Audit Matters Key audit matters are those matters that, in our professional judgment, were of most significance in our audit of the financial statements for the year ended December 31, 2022. These matters were addressed in the context of our audit of the financial statements as a whole, and in forming our opinion thereon, and we do not provide a separate opinion on these matters. Property, Plant and Equipment - Oil and gas properties - Refer to Notes 4 and 6 to the financial statements Key Audit Matter Description The Company’s property, plant and equipment includes oil and gas properties. Oil and gas properties are measured by depleting the assets on a unit-of-production basis (“depletion”) and are evaluated for impairment and impairment reversal using the future net cash flows of the underlying proved plus probable crude oil and natural gas reserves. The Company engages an independent reserve evaluator to estimate crude oil and natural gas reserves using estimates, assumptions and engineering data. The development of the Company’s reserves and the related future net cash flows used to evaluate any impairment or impairment reversal requires management to make significant estimates and assumptions related to crude oil and natural gas prices, discount rates, reserves, and future costs. Given the significant judgments made by management related to future crude oil and natural gas prices, discount rates, reserves, and future operating and development costs, these estimates and assumptions are subject to a high degree of estimation uncertainty. Auditing these estimates and assumptions required auditor judgement in applying audit procedures and in evaluating the results of those procedures. This resulted in an increased extent of audit effort. 34 How the Key Audit Matter Was Addressed in the Audit Our audit procedures related to future crude oil and natural gas prices, discount rates, reserves, and future operating and development costs used to measure oil and gas properties included the following, among others: • • • • • • Evaluated future crude oil and natural gas prices by independently developing a reasonable range of forecasts based on reputable third-party forecasts and market data and comparing those to the future crude oil and natural gas prices selected by management. Evaluated the reasonableness of the discount rates by testing the source information underlying the determination of the discount rates and developing a range of independent estimates and comparing those to the discount rates selected by management. Evaluated the Company’s independent reserve evaluator by examining reports and assessed their scope of work and findings; and assessing the competence, capability and objectivity by evaluating their relevant professional qualifications and experience. Evaluated the reasonableness of reserves by testing the source financial information underlying the reserves and comparing the reserve volumes to historical production volumes. Evaluated the reasonableness of future operating and development costs by testing the source financial information underlying the estimate, comparing future operating and development costs to historical results, and evaluating whether they are consistent with evidence obtained in other areas of the audit. Performed a retrospective review to evaluate management’s ability to accurately forecast and to assess for indications of estimation bias over time. Other Information Management is responsible for the other information. The other information comprises: • Management’s Discussion and Analysis • The information, other than the financial statements and our auditor’s report thereon, in the Annual Report. Our opinion on the financial statements does not cover the other information and we do not and will not express any form of assurance conclusion thereon. In connection with our audit of the financial statements, our responsibility is to read the other information identified above and, in doing so, consider whether the other information is materially inconsistent with the financial statements or our knowledge obtained in the audit, or otherwise appears to be materially misstated. We obtained Management’s Discussion and Analysis prior to the date of this auditor’s report. If, based on the work we have performed on this other information, we conclude that there is a material misstatement of this other information, we are required to report that fact in this auditor’s report. We have nothing to report in this regard. The Annual Report is expected to be made available to us after the date of the auditor’s report. If, based on the work we will perform on this other information, we conclude that there is a material misstatement of this other information, we are required to report that fact to those charged with governance. 35 Responsibilities of Management and Those Charged with Governance for the Financial Statements Management is responsible for the preparation and fair presentation of the financial statements in accordance with IFRS, and for such internal control as management determines is necessary to enable the preparation of financial statements that are free from material misstatement, whether due to fraud or error. In preparing the financial statements, management is responsible for assessing the Company’s ability to continue as a going concern, disclosing, as applicable, matters related to going concern and using the going concern basis of accounting unless management either intends to liquidate the Company or to cease operations, or has no realistic alternative but to do so. Those charged with governance are responsible for overseeing the Company’s financial reporting process. Auditor’s Responsibilities for the Audit of the Financial Statements Our objectives are to obtain reasonable assurance about whether the financial statements as a whole are free from material misstatement, whether due to fraud or error, and to issue an auditor’s report that includes our opinion. Reasonable assurance is a high level of assurance, but is not a guarantee that an audit conducted in accordance with Canadian GAAS will always detect a material misstatement when it exists. Misstatements can arise from fraud or error and are considered material if, individually or in the aggregate, they could reasonably be expected to influence the economic decisions of users taken on the basis of these financial statements. As part of an audit in accordance with Canadian GAAS, we exercise professional judgment and maintain professional skepticism throughout the audit. We also: • Identify and assess the risks of material misstatement of the financial statements, whether due to fraud or error, design and perform audit procedures responsive to those risks, and obtain audit evidence that is sufficient and appropriate to provide a basis for our opinion. The risk of not detecting a material misstatement resulting from fraud is higher than for one resulting from error, as fraud may involve collusion, forgery, intentional omissions, misrepresentations, or the override of internal control. • Obtain an understanding of internal control relevant to the audit in order to design audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of the Company’s internal control. • Evaluate the appropriateness of accounting policies used and the reasonableness of accounting estimates and related disclosures made by management. • Conclude on the appropriateness of management’s use of the going concern basis of accounting and, based on the audit evidence obtained, whether a material uncertainty exists related to events or conditions that may cast significant doubt on the Company’s ability to continue as a going concern. If we conclude that a material uncertainty exists, we are required to draw attention in our auditor’s report to the related disclosures in the financial statements or, if such disclosures are inadequate, to modify our opinion. Our conclusions are based on the audit evidence obtained up to the date of our auditor’s report. However, future events or conditions may cause the Company to cease to continue as a going concern. • Evaluate the overall presentation, structure and content of the financial statements, including the disclosures, and whether the financial statements represent the underlying transactions and events in a manner that achieves fair presentation. 36 We communicate with those charged with governance regarding, among other matters, the planned scope and timing of the audit and significant audit findings, including any significant deficiencies in internal control that we identify during our audit. We also provide those charged with governance with a statement that we have complied with relevant ethical requirements regarding independence, and to communicate with them all relationships and other matters that may reasonably be thought to bear on our independence, and where applicable, related safeguards. From the matters communicated with those charged with governance, we determine those matters that were of most significance in the audit of the financial statements of the current period and are therefore the key audit matters. We describe these matters in our auditor's report unless law or regulation precludes public disclosure about the matter or when, in extremely rare circumstances, we determine that a matter should not be communicated in our report because the adverse consequences of doing so would reasonably be expected to outweigh the public interest benefits of such communication. The engagement partner on the audit resulting in this independent auditor’s report is Christopher Gill. “Signed Deloitte LLP” Chartered Professional Accountants Calgary, Alberta March 9, 2023 37 STATEMENT OF FINANCIAL POSITION See accompanying notes to these financial statements. On behalf of the Board: “Signed Patrick G. Oliver” Patrick G. Oliver Director “Signed Rodger A. Tourigny” Rodger A. Tourigny Director 38 As at($ 000s)NoteAssetsCurrentAccounts receivable27,326 24,215 Crude oil inventory1,106 988 Prepaid expenses7,208 5,922 Investment tax credit receivable5,761 - Risk management contract18798 - Investments 2,028 188 44,227 31,313 Investments- 703 Exploration and evaluation assets54,563 1,994 Property, plant and equipment6870,892 902,850 Investment tax credit receivable- 8,861 919,682 945,721 LiabilitiesCurrentAccounts payable and accrued liabilities735,573 35,194 Risk management contract18- 4,567 Subordinated term debt11 20,193 - Bank debt8- 162,945 Deferred consideration1,039 1,159 56,805 203,865 Bank debt817,601 - Subordinated debt9- 47,268 Subordinated debentures1049,770 47,359 Subordinated term debt1169,882 - Deferred consideration9,051 10,089 Decommissioning liabilities12109,215 135,815 Deferred tax liability13 127,519 109,306 439,843 553,702 Shareholders' equityShare capital14781,679 772,781 Contributed surplus31,705 31,599 Warrants146,053 7,265 Accumulated other comprehensive income (loss)784 (221) Deficit(340,382) (419,405) 479,839 392,019 919,682 945,721 Commitments and contingencies19Subsequent events18December 31,2022December 31,2021 STATEMENT OF COMPREHENSIVE INCOME See accompanying notes to these financial statements. 39 For the years ended December 31($ 000s, except $ per share)Note20222021RevenueOil and gas sales, net of royalties15322,122 225,866 Other income164,602 6,680 Deferred consideration1,158 1,292 Loss on risk management contracts18(11,513) (18,357) 316,369 215,481 ExpensesProduction85,385 70,670 Office and administration4,418 4,325 Employee compensation7,489 5,924 Finance costs1721,647 26,909 Share-option compensation1,910 1,095 Depletion and depreciation690,951 76,791 Impairment (reversal of impairment)6- (203,197) 211,800 (17,483) Earnings before income taxes104,569 232,964 Taxes Current income tax expense 137,819 - Deferred income tax expense1317,727 53,665 25,546 53,665 Net earnings for the year79,023 179,299 Other comprehensive incomeUnrealized gain on investments1,137 598 Deferred taxes on unrealized gain on investments(132) (69) Other comprehensive income for the year1,005 529 Total comprehensive income for the year80,028 179,828 Net earnings per share - basic142.20 5.32 Net earnings per share - diluted142.12 5.16 Comprehensive income per share - basic142.22 5.33 Comprehensive income per share - diluted142.15 5.17 STATEMENT OF CASH FLOW See accompanying notes to these financial statements. 40 For the years ended December 31($ 000s)Note20222021Operating activitiesNet earnings79,023 179,299 Items not affecting cashDeferred income taxes expense17,727 53,665 Share-option compensation1,910 1,095 Investment income(221) (67) Finance costs21,647 26,909 Unrealized (gain) loss on risk management contracts18(5,365) 968 Deferred consideration(1,158) (1,292) Depletion and depreciation690,951 76,791 Government grant in-kind20(3,675) (5,901) Impairment (reversal of impairment)- (203,197) Gain on sale of property and equipment- (225) Decommissioning expenditures(5,930) (4,496) Interest paid17(14,284) (21,217) Changes in non-cash working capital accounts172,928 (6,229) Cash provided by operating activities183,553 96,103 Financing activitiesDecrease of bank debt(145,344) (89,310) Subordinated debt 9(47,268) 17,000 Subordinated debentures, net of issuance costs- 36,887 Subordinated term debt, net of issuance costs1188,690 - Proceeds from warrants exercised104,270 6,690 Stock option proceeds1,612 378 Cash used in financing activities(98,040) (28,355) Investing activitiesInvestment income received221 67 Exploration and evaluation expenditures(2,569) (1,621) Property, plant and equipment expenditures6(77,200) (65,661) Proceeds on sale of property120 225 Changes in non-cash working capital accounts17(6,085) (758) Cash used in investing activities(85,513) (67,748) Net change in cash in the year- - Cash beginning of year- - Cash, end of year- -  STATEMENT OF CHANGES IN EQUITY (1) All amounts reported in Contributed Surplus relate to share-option compensation. (2) Accumulated other comprehensive income is comprised of unrealized gains and losses on investments fair value through other comprehensive income. See accompanying notes to these financial statements. 41 For the years ended($ 000's, except number of shares outstanding)Numbers of common shares outstanding (Note 14)Share capital (Note 14)Contributed surplus (1)WarrantsAccumulated other comprehensive income (loss)(2)DeficitTotal shareholders' equityJanuary 1, 202133,511,316 765,415 30,672 - (750) (598,704) 196,633 Share-option compensation1,095 1,095 Shares issued for subordinated promissory note interest118,896 414 414 Exercise of options183,740 378 378 Transfer to share capital on exercise of options168 (168) - Issuance of warrants9,810 9,810 Deferred tax on issuance of warrants(2,259) (2,259) Share issue costs net of tax(241) (286) (527) Issuance of flow through shares1,187,000 7,003 7,003 Premium on flow through shares(356) (356) Comprehensive income529 179,299 179,828 December 31, 202135,000,952 772,781 31,599 7,265 (221) (419,405) 392,019 Share-option compensation1,910 1,910 Exercise of options1,360,940 1,612 1,612 Transfer to share capital on exercise of options1,804 (1,804) - Exercise of warrants551,000 4,270 4,270 Transfer to share capital on exercise of warrants1,212 (1,212) - Comprehensive income1,005 79,023 80,028 December 31, 202236,912,892 781,679 31,705 6,053 784 (340,382) 479,839 NOTES TO THE FINANCIAL STATEMENTS As at and for the years ended December 31, 2022, and December 31, 2021. 1. NATURE OF BUSINESS AND SEGMENT INFORMATION Bonterra Energy Corp. (“Bonterra” or the “Company”) is a public company listed on the Toronto Stock Exchange (the “TSX”) and incorporated under the Business Corporations Act (Alberta). The address of the Company’s registered office is Suite 901, 1015-4th Street SW, Calgary, Alberta, Canada, T2R 1J4. Common shares of the Company (“Common Shares”) are listed for trading on the Toronto Stock Exchange (“TSX”) under the symbol “BNE”. Bonterra operates in one industry and has only one reportable segment which is the development and production of oil and natural gas in the Western Canadian Sedimentary Basin. 2. BASIS OF PREPARATION AND FUTURE OPERATIONS a) Statement of Compliance These financial statements have been prepared by management in accordance with International Financial Reporting Standards (IFRS). The financial statements were authorized for issue by the Company’s Board of Directors on March 9, 2023. b) Basis of Measurement These financial statements have been prepared on a historical cost basis, except for certain financial instruments and share-based payment transactions which are measured at fair value. c) Functional and Presentation Currency The Company’s functional and presentation currency is the Canadian dollar. Foreign currency denominated monetary assets and liabilities are translated into Canadian dollars at the rates prevailing on the reporting date. Non-monetary assets and liabilities are translated into Canadian dollars at the rates prevailing on the transaction dates. Exchange gains and losses are recorded as income or expense in the period in which they occur. d) Significant Accounting Estimates and Judgments The timely preparation of financial statements requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities as at the date of the statement of financial position as well as the reported amounts of revenues, expenses and cash flows during the periods presented. Such estimates relate primarily to unsettled transactions and events as of the date of the financial statements. Actual results could differ materially from estimated amounts. See Note 4 for more information. 42 e) Adopted Accounting Pronouncements Amendments to IAS 16 Property, Plant and Equipment On January 1, 2022, Bonterra adopted Property, Plant and Equipment - Proceeds before Intended Use issued by the IASB which made amendments to IAS 16 Property, Plant and Equipment. The amendments prohibit a company from deducting from the cost of property, plant, and equipment ("PP&E") amounts received from selling items produced while the company is preparing the asset for its intended use. Instead, a company will recognize such sales proceeds and related cost in profit or loss. There was not a material impact to Bonterra's financial statements. Amendments to IAS 37 Provisions, Contingent Liabilities and Contingent Assets On January 1, 2022, Bonterra adopted “Onerous Contracts - Cost of Fulfilling a Contract,” as issued by the IASB which made amendments to IAS 37 – “Provisions, Contingent Liabilities” and “Contingent Assets.” The amendments specify which costs an entity includes in determining the cost of fulfilling a contract for the purpose of assessing whether the contract is onerous. There was not a material impact to Bonterra's financial statements. f) Future Accounting Pronouncements Amendments to IAS 1 - Classification of liabilities as current or non-current In January 2020, the IASB issued amendments to IAS 1 – “Presentation of Financial Statements” to clarify that liabilities are classified as either current or non-current, depending on the existence of the substantive right at the end of the reporting period for an entity to defer settlement of the liability for at least twelve months after the reporting period. The amendments are effective January 1, 2023, with early adoption permitted. The amendments are required to be adopted retrospectively. Bonterra does not expect a material impact from these amendments on its financial statements as a result of the initial application. Amendments to IAS 1 and IAS 8 - Accounting Policies and Accounting Estimates In February 2021, narrow scope amendments were introduced to IAS 1 – “Presentation of Financial Statements” and IAS 8 – “Accounting Policies, Changes in Accounting Estimates and Errors” to improve accounting policy disclosures and to distinguish changes in accounting estimates from changes in accounting policies. The amendments are effective January 1, 2023. Bonterra does not expect a material impact from these amendments on its financial statements as a result of the application. Amendments to IAS 12 and IFRS 1 – Deferred taxes related to assets and liabilities arising from a single transaction In May 2021, the IASB issued amendments to IAS 12 – “Income Taxes,” which requires companies to recognize deferred tax on particular transactions that, on initial recognition, give rise to equal amounts of taxable and deductible temporary differences. The amendments are effective for annual reporting periods beginning on or after January 1, 2023 and are to be applied retrospectively. Bonterra does not expect a material impact from these amendments on its financial statements as a result of the initial application. 43 Amendments to IFRS 16 – Leases – Lease Liability in a Sale and Leaseback In September 2022, IASB issued amendments to IFRS 16 – Leases “Lease Liability in a Sale and Leaseback” transactions, that specify the requirement that a seller-lessee uses in its subsequent measurement of the lease liability in a sale and leaseback transaction to ensure the seller-lessee does not recognize any amount of the gain or loss that relates to the right of use it retains. The amendments are effective for annual reporting periods beginning on or after January 1, 2024 with early adoption permitted. The amendments are to be applied retrospectively. Bonterra does not anticipate a material impact from these amendments in its financial statements as a result of the initial application. 3. SIGNIFICANT ACCOUNTING POLICIES a) Revenue Recognition Revenue associated with the sale of crude oil, natural gas and natural gas liquids is measured based on the consideration specified in contracts with customers. Revenue from contracts with customers is recognized when or as Bonterra satisfies a performance obligation by transferring a promised good or service to a customer. A good or service is transferred when the customer obtains control of that good or service. The transfer of control of oil, natural gas, and natural gas liquids usually coincides with title passing to the customer and the customer taking physical possession. The Company principally satisfies its performance obligations at a point in time and the amounts of revenue recognized relating to performance obligations satisfied over time are not significant. Collection of revenue associated with the sale of crude oil, natural gas and natural gas liquids occurs on or about the 25th of the month following production. Items such as royalties for crown, freehold, gross overriding (GORR) and Saskatchewan surcharge are netted against revenue. These items are netted to reflect the deduction for other parties’ proportionate share of the revenue. Administration fee income is recorded when services are provided. b) Joint Arrangements Certain exploration, development and production activities are conducted jointly with others. These financial statements reflect only the Company’s interests in such activities. A jointly controlled operation involves the use of assets and other resources of the Company and those of other joint venture participants through contractual arrangements rather than through the establishment of a corporation, partnership or other entity. The Company has no interests in jointly controlled entities. The Company recognizes in its financial statements its interest in assets that it owns, the liabilities and expenses that it incurs, and its share of income earned by the joint arrangement. c) Inventories Inventories consist of crude oil. Crude oil stored in the Company’s tanks is valued on a first-in, first-out basis at the lower of cost or net realizable value. The inventory cost for crude oil is determined based on the combined average per barrel operating costs, and depletion and depreciation for the period, while net realizable value is determined based on estimated sales price less transportation costs. 44 d) Investments Investments consist of equity securities. The Company’s investments are measured as fair value through other comprehensive income (“FVTOCI”), with gains or losses arising from changes in fair value recognized in other comprehensive income and accumulated in the fair value instrument. The cumulative gain or loss will not be reclassified to profit or loss on disposal of the investments. Fair value is determined by multiplying the period end trading price of the investments by the number of common shares held as at period end. e) Exploration and Evaluation Assets General exploration and evaluation (“E&E”) expenditures incurred prior to acquiring the legal right to explore are charged to expense as incurred. E&E expenditures represent undeveloped land costs, licenses and exploration well costs. Undeveloped land costs, licenses and exploration well costs are initially capitalized and, if subsequently determined to have not found sufficient reserves to justify commercial production, are charged to expense. E&E assets continue to be capitalized as long as sufficient progress is being made to assess the reserves and economic viability of the asset. Once technical feasibility and commercial viability has been established, E&E assets are transferred to property, plant and equipment (“PP&E”). E&E assets are assessed for impairment annually, upon transfer to PP&E assets or whenever indications of impairment exist to ensure they are not at amounts above their recoverable amounts. f) Property, Plant and Equipment PP&E assets include transferred-in E&E costs, development drilling and other subsurface expenditures. PP&E assets are carried at cost less depletion and depreciation of all development expenditures and include all other expenditures associated with PP&E assets. Oil and Gas Properties The initial cost of an asset is comprised of its purchase price or construction cost, including expenditures such as drilling costs; the present value of the initial and changes in the estimate of any decommissioning obligation associated with the asset; and finance charges on qualifying assets that are directly attributable to bringing the asset into operation and to its present location. Production Facilities Production facilities are comprised of costs related to petroleum and natural gas plant and production equipment. 45 Leases Leases or contractual obligations are capitalized as right of use assets (“ROUs”) with a corresponding right of use lease obligation using the present value of future lease payments on the statement of financial position. The discount rate used to determine the ROU is the stated rate in the lease contract. If no discount rate is provided, the Company’s incremental borrowing rate is used. Certain lease payments will continue to be expensed in the statement of comprehensive income. These leases are contractual obligations that contain any of the following: are equal to or less than twelve months; are for oil and gas extraction; are variable payments; the Company does not control the asset; or no asset is identified in the lease. Depletion and Depreciation Depletion and depreciation is recognized in the statement of comprehensive income (loss). PP&E properties, excluding surface costs are depleted using the unit-of-production method over their proved plus probable developed reserve life, when commercial production in an area has commenced. Proved plus probable developed reserves are determined annually by qualified independent reserve engineers. Changes in factors such as estimates of proved plus probable developed reserves that affect unit-of-production calculations are accounted for on a prospective basis. Surface costs such as production facilities and furniture, fixtures and other equipment are depreciated over their estimated useful lives. Production facilities, furniture, fixtures and other equipment are depreciated over the individual assets estimated economic lives, less estimated salvage value of the assets at the end of their useful lives. These assets are depreciated as follows: Production facilities Furniture, fixtures and other equipment Right of use assets Declining balance method at 10 percent per year Declining balance method at 10 to 20 percent per year Straight line method over the term of the associated lease g) Business Combinations and Goodwill The purchase price used in a business combination is based on the fair value at the date of acquisition. The business combination is accounted for based on the fair value of the assets acquired and liabilities assumed. All acquisition costs are expensed as incurred. Contingent liabilities are recognized at fair value at the date of the acquisition, and subsequently re-measured at each reporting period until settled. The excess of cost over fair value of the net assets and liabilities acquired is recorded as goodwill. h) Impairment of Assets Impairment of Financial Assets A financial asset is considered to be impaired if objective evidence indicates that one or more events have had a negative effect on the estimated future cash flow of that asset. An impairment loss in respect of a financial asset measured at amortized cost is calculated as the difference between its carrying amount and the present value of the estimated future cash flow discounted at the original effective interest rate. Significant financial assets are tested for impairment on an individual basis. The remaining financial assets are assessed collectively in groups that share similar credit risk characteristics. 46 All impairment losses are recognized in net earnings. An impairment loss is reversed if there is an indicator that the impairment reversal can be related objectively to an event occurring after the impairment loss was recognized. Any subsequent recovery of an impairment loss in respect of an investment in an equity instrument classified as FVTOCI is reversed through other comprehensive income instead of net earnings. For financial assets measured at amortized cost, the reversal is recognized in net earnings. Impairment of Non-Financial Assets The carrying amounts of the Company's non-financial assets are reviewed at the end of each reporting period to determine whether there is any indication of impairment. If such indication exists, then the assets’ carrying amounts are assessed for impairment. For the purpose of impairment testing, assets (which include E&E, PP&E and goodwill) are grouped together into the smallest group of assets that generate cash flows from continuing use which are largely independent of the cash flow of other assets or groups of assets (the cash-generating unit or “CGU”). Goodwill is allocated to the CGU expected to benefit from the synergies of the combination. The recoverable amount of an asset or a CGU is the greater of its value-in-use (“VIU”) and its fair value less costs to sell (“FVLCS”). The Company has a core CGU composed of its Alberta properties and secondary CGUs for its British Columbia (BC) and Saskatchewan properties. An impairment loss is recognized if the carrying amount of an asset or its CGU exceeds its recoverable amount. Impairment losses are recognized in the statement of comprehensive income (loss). Impairment losses recognized in respect of a CGU are allocated first to reduce the carrying amount of any goodwill allocated to the CGU and then to reduce the carrying amount of the other assets of the CGU on a pro-rata basis. In respect of assets other than goodwill, impairment losses recognized in prior periods are assessed at each reporting date for any indications that the impairment loss has reversed. If the amount of the impairment loss reverses in a subsequent period and the reversal can be objectively related to an event occurring after the impairment was recognized, the impairment loss is reversed only to the extent that the asset's carrying amount does not exceed the carrying amount that would have been determined, net of depletion and depreciation, if no impairment loss had been recognized and recorded in the statement of comprehensive income (loss). An impairment loss in respect of goodwill cannot be reversed. i) Deferred Consideration Deferred consideration is generated when a sale of a royalty interest linked to production at a specific property occurs. Consideration is given to the specific terms of each arrangement to determine whether a disposal of an interest in the reserves of the respective property has occurred and whether the counterparty is entitled to the associated risks and rewards attributable to the property over its estimated life. These include the contractual terms and implicit obligations related to production, such as the holder of the royalty having the option of either being paid in cash or in kind and the associated commitments, if any, to develop future expansions or projects at the property. Proceeds for sale of a royalty interest on petroleum properties are then attributed to two components: a payment for partial disposal of an interest in PP&E; and an upfront payment received for future extraction services that will generate future royalties. Discounted future cash flows of future development and operating costs multiplied by the royalty rate are used to derive the upfront payment received for future extraction services, which is accounted for as deferred consideration and recognized as revenue over the reserve life of the encumbered properties (as this represents the efforts incurred towards the extraction 47 performance obligation). Upon commencement of the royalty interest the deferred consideration is depleted (recognized into revenue) using the same unit-of-production method as the depletion of the encumbered PP&E asset’s carrying value. j) Decommissioning Liabilities The fair value of the statutory, contractual, constructive or legal liabilities associated with the retirement and reclamation of oil and gas properties is recorded when incurred, with a corresponding increase to the carrying amount of the related PP&E. The amount recognized is the estimated cost of decommissioning, discounted to its present value using the Company’s risk-free rate. Changes in the estimated timing of decommissioning or decommissioning cost estimates and changes to the risk-free rates are dealt with prospectively by recording an adjustment to the decommissioning liabilities, and a corresponding adjustment to PP&E. The unwinding of the discount on the decommissioning provision is charged to net earnings as a finance cost. The Company recognizes a decommissioning liability in the period in which it is incurred when a reasonable estimate of the liability can be made. On a periodic basis, management will review these estimates and changes and if there are any, they will be applied prospectively. The fair value of the estimated provision is recorded as a long-term liability, with a corresponding increase in the carrying amount of the related asset. The capitalized amount is depleted on a unit-of-production basis over the life of the proved plus probable developed reserves. The liability amount is increased each reporting period due to the passage of time and this amount is charged to earnings in the period. Actual costs incurred upon settlement of the obligations are charged against the provision to the extent of the liability recorded and any remaining balance of actual costs is recorded in the statement of comprehensive income (loss). k) Income Taxes Tax expense comprises current and deferred taxes. Tax is recognized in the statement of comprehensive income (loss) or directly in equity. Current tax expense is based on the results for the period as adjusted for items that are not taxable or not deductible. Current tax is calculated using tax rates and laws that are substantively enacted at the end of the reporting period. Management periodically evaluates positions taken in tax returns with respect to situations in which applicable tax regulation is subject to interpretation. Provisions are established where appropriate on the basis of amounts expected to be paid to the tax authorities. Deferred tax is recognized using the liability method, providing for unused tax losses, unused tax credits and temporary differences between the carrying amounts of assets and liabilities for financial reporting purposes and the amounts used for taxation purposes. Deferred tax is not recognized for the following temporary differences: the initial recognition of assets and liabilities in a transaction that is not a business combination and that affects neither accounting nor taxable profit, and differences relating to investments in subsidiaries to the extent that they are unlikely to be reversed in the foreseeable future. Deferred tax is measured at the tax rates that are expected to be applied to the temporary differences when they reverse, based on the laws that have been enacted or substantively enacted by the reporting date. A deferred tax asset is recognized to the extent that it is probable that future taxable profits will be available against which unused tax losses, unused tax credits and temporary differences can be utilized. Deferred tax assets are reviewed at each period end and are reduced to the extent that it is no longer probable that the related tax benefit will be realized. 48 The amount and timing of reversals of temporary differences will also depend on the Company’s future operating results, and acquisitions and dispositions of assets and liabilities. A significant change in any of the preceding assumptions could materially affect the Company’s estimate of the deferred income tax asset or liability. l) Share-option Compensation The Company accounts for share-option compensation using the fair-value method of accounting for stock options granted to directors, officers, employees and other service providers using the Black-Scholes option pricing model. Share-option payments are recognized through the statement of comprehensive income (loss) over the vesting period with a corresponding amount reflected in contributed surplus in equity. For awards issued in tranches that vest at different times, the fair value of each tranche is recognized over its respective vesting period. At the grant date and at the end of each reporting period, the Company assesses and re-assesses for subsequent periods its estimates of the number of awards that are expected to vest and recognizes the impact of the revisions in the statement of comprehensive income (loss). Upon exercise of share-based options, the proceeds received net of any transaction costs and the fair value of the exercised share-based options is credited to share capital. Employees may elect to have the Company settle any or all options vested and exercisable using a cashless equity settlement. In connection with any such exercise, an employee shall be entitled to receive, without any cash payment (other than the taxes required to be paid in connection with the exercise), whole shares of the Company. The number of shares under option multiplied by the difference of the fair value at the time of exercise less the option exercise price, divided by the fair value at the time of exercise, determines the number of whole shares issued. m) Financial Instruments The Company classifies its financial instruments into one of the following categories: financial assets at amortized cost, financial liabilities at amortized costs; and fair value through profit or loss. All financial instruments are measured at fair value on initial recognition. Measurement in subsequent periods is dependent on the classification of the respective financial instrument. Fair value through profit or loss financial instruments are subsequently measured at fair value with changes in fair value recognized in net earnings. All other categories of financial instruments are measured at amortized cost using the effective interest rate method. Cash, account receivables and certain other long-term assets are classified as financial assets at amortized cost since it is the Company’s intention to hold these assets to maturity and the related cash flows are mainly payments of principle and interest. The Company’s investments are measured at FVTOCI, with gains or losses arising from changes in fair value recognized in other comprehensive income and accumulated in the fair value instrument. The cumulative gain or loss will not be reclassified to profit or loss on disposal of the investments. Accounts payable, accrued liabilities, and certain other long-term liabilities and long-term debt are classified as financial liabilities at amortized cost. Risk management assets and liabilities are classified as fair value through profit or loss. 49 n) Fair Value Measurement Financial instruments consisting of accounts receivable, accounts payable and accrued liabilities, due to related party, subordinated promissory note and bank debt on the statement of financial position are carried at amortized cost. Investments and investment in related party are carried at fair value. All of the investments are transacted in active markets. Bonterra determines the fair value of these transactions according to the following hierarchy based on the amount of observable inputs used to value the instrument. Level 1 – Quoted prices are available in active markets for identical assets or liabilities as of the reporting date. Active markets are those in which transactions occur in sufficient frequency and volume to provide pricing information on an ongoing basis. Level 2 – Pricing inputs are other than quoted prices in active markets included in Level 1. Prices in Level 2 are either directly or indirectly observable as of the reporting date. Level 2 valuations are based on inputs, including quoted forward prices for commodities, time value and volatility factors, which can be substantially observed or corroborated in the marketplace. Level 3 – Valuations in this level are those with inputs for the asset or liability that are not based on observable market data. Bonterra’s investments and investments in related party have been assessed on the fair value hierarchy described above and are all considered Level 1. o) Risk Management Contracts The Company is exposed to market risks resulting from fluctuations in commodity prices, foreign currency exchange rates and interest rates in the normal course of its business. The Company may use a variety of instruments to manage these exposures. For transactions where hedge accounting is not applied, the Company accounts for such instruments using the fair value method by initially recording an asset or liability and recognizing changes in the fair value of the instruments in earnings as unrealized gains or losses on risk management contracts. Fair values of financial instruments are based on third party quotes or valuations provided by independent third parties. Any realized gains or losses on risk management contracts are recognized in net earnings in the period they occur. Bonterra’s risk management contracts have been assessed on the fair value hierarchy described above and are all considered Level 2. p) Net Earnings and Comprehensive Income Per Share Per share amounts are calculated by dividing the net earnings or comprehensive income (loss) attributable to common shareholders of the Company by the weighted average number of common shares outstanding during the reporting period. Diluted per share amounts are calculated similar to basic per share amounts except that the weighted average common shares outstanding are increased to include additional common shares from the assumed exercise of dilutive share-options. The number of additional outstanding common shares is calculated by assuming that the outstanding in-the-money share-options were exercised and that the proceeds from such exercises were used to acquire common shares at the average market price during the reporting period. 50 q) Government Grants The Company may receive government grants which provide financial assistance as compensation for costs or expenditures to be incurred. Government grants are accounted for when there is reasonable assurance that conditions attached to the grants are met and that the grants will be received. The Company recognizes government grants in net earnings on a systematic basis and in line with recognition of the expenses that the grants are intended to compensate. 4. SIGNIFICANT ACCOUNTING ESTIMATES AND JUDGMENTS Estimates and underlying assumptions are reviewed on an ongoing basis. Revisions to accounting estimates are recognized in the year in which the estimates are revised and in any future years affected. The following are the estimates and judgments applied by management that most significantly affect the Company’s financial statements. Exploration and Evaluation Expenditures E&E costs are initially capitalized with the intent to establish commercially viable reserves. E&E assets include undeveloped land and costs related to exploratory wells. The Company is required to make estimates and judgments about future events and circumstances regarding the future economic viability of extracting the underlying resources. Changes to project economics, resource quantities, expected production techniques, unsuccessful drilling, expired mineral leases, production costs and required capital expenditures are important factors when making this determination. To the extent a judgment is made that the underlying reserves are not viable, the E&E costs will be impaired and charged to net earnings. Impairment of Non-Financial Assets PP&E and goodwill are aggregated into CGUs based on their ability to generate largely independent cash flows and are assessed for impairment or in the case of PP&E impairment reversals. CGUs have been determined based on similar geological structure, shared infrastructure, geographical proximity, commodity type, and similar market risks. Oil and gas prices and other assumptions will change in the future, which may impact the Company’s recoverable amounts and may therefore require a material adjustment to the carrying value of PP&E. The determination of the Company's CGUs is subject to management's judgment. The Company has a core CGU composed of its Alberta properties and secondary CGUs for its BC and Saskatchewan properties. The recoverable amount of E&E and PP&E, is determined based on the fair value less costs of disposal using a discounted cash flow model and is assessed at the CGU level. The period the Company used to project cash flows is approximately 50 years or the CGUs reserve life. Growth in cash flow from a single well would be determined based on the extent of total reserves assigned, which is produced at declining rates over the estimated reserve life. The fair value measurement of the Company’s E&E and PP&E, is designated Level 3 on the fair value hierarchy. 51 The Company performs an impairment test on all of its CGUs for any potential impairment or related recovery at least annually or when impairment or recovery indicators arise. In making these evaluations, the Company uses the following information: 1) The net present value of the pre-tax cash flows from oil and gas reserves of each CGU based on total proved plus probable reserves estimated by the Company’s independent reserve evaluator; and 2) Key input estimates used in the determination of cash flows from oil and gas reserves include the following: a) Reserves - Assumptions that are valid at the time of reserve estimation may change significantly when new information becomes available. Changes in forward price estimates, production costs or recovery rates may change the economic status of reserves and may ultimately result in reserves being revised. b) Crude oil and natural gas prices - Forward price estimates of the crude oil and natural gas prices are used in the discounted cash flow model. These prices are adjusted for quality differentials, heat content and distance to market. Commodity prices have fluctuated widely in recent years due to global and regional factors including supply and demand fundamentals, inventory levels, exchange rates, weather, economic and geopolitical factors. c) Discount rate - The Company uses a pre-tax discount rate of fifteen percent that reflects risks specific to the assets for which the future cash flow estimates have not been adjusted. The discount rate was determined based on the Company’s assessment of risk based on past experience. Changes in the general economic environment could result in material changes to this estimate. No indicators of impairment or impairment reversal were identified at December 31, 2022. Reserves Estimation The capitalized costs of oil and gas properties and deferred consideration are depleted on a unit-of- production basis at a rate calculated by reference to proved plus probable developed reserves determined in accordance with National Instrument 51-101 and the Canadian Oil and Gas Evaluation handbook. Commercial reserves are determined using best estimates of oil and gas in place, recovery factors and future oil and gas prices. Amounts used for impairment calculations are also based on estimates of crude oil and natural gas reserves and future costs required to develop those reserves. Risk Management Contract The Company accounts for such instruments using the fair value method by initially recording an asset or liability, and recognizing changes in the fair value of the instruments in net earnings as unrealized gains or losses on risk management contracts. Fair values of financial instruments are based on third party futures quotes for commodities. Any realized or unrealized gains or losses on risk management contracts are recognized in net earnings in the period they occur. 52 Share-option Compensation The Company measures the cost of equity-settled transactions with employees by reference to the fair value of the equity instruments at the date they are granted. Estimating the fair value requires the determination of the most appropriate valuation model for a grant, which is dependent on the terms and conditions of the grant. This also requires the determination of the most appropriate inputs to the valuation model including the expected life of the option, risk-free interest rates, volatility and dividend yield. Deferred Consideration Deferred consideration is incurred when the sale of a royalty interest occurs that has contractual terms or implicit obligations that requires future performance such future development costs and operating costs. Management uses judgments in determining those cash flows such as cost, inflation and the discount rate to determine the portion of proceeds that is deferred. Decommissioning and Restoration Costs Decommissioning and restoration costs will be incurred by the Company at the end of the operating lives of the Company’s oil and gas properties. Provisions for decommissioning liabilities are based on cost estimates which can vary in response to many factors including timing of abandonment, inflation, changes in legal requirements, new restoration techniques and interest rates. Income Taxes The Company recognizes the net deferred tax benefit or expense related to deferred income tax assets or liabilities to the extent that it is probable that the deductible temporary differences will reverse in the foreseeable future. Assessing the recoverability of investment tax credit receivable requires the Company to make significant estimates related to expectations of future taxable income. The provision for income taxes is based on judgments in applying income tax law and estimates of the timing, likelihood and reversal of temporary differences between the accounting and tax basis of assets and liabilities. The ability to realize on the deferred tax assets and investment tax credit receivable that are recorded on the balance sheet may be compromised to the extent that any interpretation of tax law is challenged or taxable income differs significantly from estimates. Further details regarding accounting estimates and judgments are disclosed in Note 3. 5. EXPLORATION AND EVALUATION ASSETS 53 ($ 000s)Cost and carrying amountBalance at January 1, 2021 373 Additions 1,621 Balance at December 31, 2021 1,994 Additions 2,569 Balance at December 31, 2022 4,563 6. PROPERTY, PLANT AND EQUIPMENT Impairment There were no impairment losses or reversals recorded in the statement of comprehensive income for the year ended December 31, 2022. At June 30, 2021 the Company identified indicators of an impairment reversal due to increased forward commodity prices and an increase in the Company’s market capitalization since the impairment loss recognized as at March 31, 2020. As a result, recovery testing was performed by preparing estimates of future cash flows to determine the recoverable amount of the respective assets. The Company determined that the recoverable amount of the Company’s Alberta CGU exceeded its carrying value. A total impairment recovery of $203,197,000 was recognized in the Company’s PP&E. 7. ACCOUNTS PAYABLE AND ACCRUED LIABILITIES 54 Cost($ 000s)Oil and gas propertiesProduction facilitiesFurniture fixtures & other equipmentTotal property plant & equipmentBalance at January 31, 20211,457,565 369,585 2,297 1,829,447 Additions44,505 21,140 16 65,661 Adjustment to decommissioning liabilities (Note 12)5,980 - - 5,980 Disposal- - (3) (3) Balance at December 31, 20211,508,050 390,725 2,310 1,901,085 Additions52,589 24,458 153 77,200 Disposal(120) - - (120) Adjustment to decommissioning liabilities(18,125) - - (18,125) Disposal- - (2) (2) Balance at December 31, 20221,542,394 415,183 2,461 1,960,038 Accumulated depletion and depreciation($ 000s)Oil and gas propertiesProduction facilitiesFurniture fixtures & other equipmentTotal property plant & equipmentBalance at January 1, 2021(910,638) (212,032) (1,856) (1,124,526) Depletion and depreciation(64,331) (12,404) (56) (76,791) Disposal and other(115) - - (115) Impairment reversal159,673 43,524 - 203,197 Balance at December 31, 2021(815,411) (180,912) (1,912) (998,235) Depletion and depreciation(74,455) (16,406) (90) (90,951) Disposal and other40 - - 40 Balance at December 31, 2022(889,826) (197,318) (2,002) (1,089,146) Carrying amounts as at:($ 000s)December 31, 2021692,639 209,813 398 902,850 December 31, 2022652,568 217,865 459 870,892 ($ 000s)December 31, 2022December 31, 2021Accounts payable27,701 25,420 Accrued liabilities7,872 9,774 35,573 35,194 8. BANK DEBT As at December 31, 2022, the Company had a total Bank Facility of $110,000,000 (December 31, 2021 - $210,000,000), comprised of a $85,000,000 syndicated revolving credit facility, and a $25,000,000 non- syndicated revolving credit facility. The amount drawn under the total Bank Facility at December 31, 2022 was $17,601,000 (December 31, 2021 - $162,945,000). The amounts borrowed under the total Bank Facility bear interest at a floating rate based on the applicable Canadian prime rate or Banker’s Acceptance rate, plus between 2.00 percent and 7.00 percent, depending on the type of borrowing and the Company’s consolidated debt to EBITDA ratio. EBITDA is defined as net income for the twelve month trailing period excluding finance costs, provision for current and deferred taxes, depletion and depreciation, share-option compensation, gain or loss on sale of assets and impairment of assets. The terms of the total revolving Bank Facility provide that the loan facility is revolving to October 31, 2023, with a maturity date of October 31, 2024. The credit facility has no set terms of repayment. The amount available for borrowing under the Bank Facility is reduced by outstanding letters of credit. Letters of credit totaling $2,095,000 were issued as at December 31, 2022 (December 31, 2021 - $1,445,000). Security for the Bank Facility consists of various floating demand debentures totaling $750,000,000 (December 31, 2021 - $750,000,000) over all of the Company’s assets and a general security agreement with first ranking over all personal and real property. Financial Covenants The Company is subject to certain financial covenants under its Bank Facility and Subordinated Term Debt facility as follows: • Consolidated debt to forecasted EBITDA Ratio shall not exceed 2.50:1.00; and • Asset Coverage Ratio of not less that 1.50:1. Asset Coverage ratio is defined as the proved developed producing reserves of the Company (before income tax; discounted at 10 percent), as evaluated by an independent third-party engineering report and evaluated on strip commodity pricing, divided by the consolidated debt of the Company. The ratio is calculated and revaluated for strip pricing on June 30 and December 31 period ends. As at December 31, 2022, Bonterra was in compliance with all financial covenants on its Bank Facility. 9. SUBORDINATED DEBT As at December 31, 2022, Bonterra had $nil (December 31, 2021 - $47,268,000) outstanding on a second lien non-revolving term facility from the Business Development Bank of Canada (the “BDC”), through the Business Credit Availability Program (the “BCAP”). Interest accrued on the BCAP facility during 2022 was $nil (December 31, 2021 - $2,108,000). Interest paid in 2022 was $2,110,000 (December 31, 2021 - $139,000). On November 25, 2022 the Company completed a restructuring of the Company’s outstanding debt with two new credit facilities, one of the credit facilities was a renewal of the Company’s bank debt with a syndicate of lenders as described in Note 8. The second credit facility was subordinated term debt disclosed in Note 11. The Company fully repayed the BDC term facility on November 25, 2022. 55 10. SUBORDINATED DEBENTURES As at December 31, 2022 the Company has a total of 59,000 senior unsecured subordinated debenture units outstanding. Each Unit is comprised of: (i) one senior unsecured debenture with a par value of $1,000 per note and bearing interest at 9.0 percent per annum, payable semi-annually; and (ii) 56 common share purchase warrants of Bonterra (“Warrants”). The debentures mature on October 20, 2025 and all or a portion of the principal amount outstanding can be repaid without penalty after October 20, 2024, however, all interest due to the maturity date must be paid. A total of 3,304,000 Warrants were issued, entitling the holder to purchase one common share of Bonterra for each Warrant at a price of $7.75, until October 20, 2025. Interest paid in 2022 was $5,310,000 (December 31, 2021 - $1,047,000). The unsecured subordinated debentures were determined to be a compound instrument with a debt and equity component. Based on the calculated fair value of the debentures, the effective interest rate was determined on issuance to be 15.6 percent using the effective interest rate method, by discounting future payments of interest and principal with the residual value allocated to Warrants and issue costs. The value of the debt will accrete up to the principal balance at maturity. For more information about Warrants please see Note 14. 11. SUBORDINATED TERM DEBT On November 25, 2022 the Company entered into a four year second lien, non-revolving subordinated term debt facility (“Subordinated Term Debt”). The amounts borrowed under the Subordinated Term Debt bear interest at a fixed rate of 11.70 percent to be applied to 25 percent of the term facility principle and a floating interest rate of Canadian Prime Rate plus 6.25 percent on the remaining 75 percent of the principal amount. The Company is required to make mandatory principal repayments equal to $4.75 million, payable on the last banking day of February, May, August and November of each calendar year, commencing on February 28, 2023. The term debt has a maturity date of November 30, 2026 on which the remaining outstanding principle balance is to be paid. The amount drawn under the Subordinated Term Debt at December 31, 2022 was $95,000,000 (December 31, 2021 - $Nil). Based on the calculated fair value of the Subordinated Term Debt as at December 31, 2022, the effective interest rate was determined to be 15.8 percent using the effective interest rate method. The effective interest rate was calculated by discounting future payments of interest and principal with the residual value allocated to issue costs of $6,310,000. The value of the debt will accrete up to the principal balance at maturity. Interest accrued in 2022 was $1,193,000 (December 31, 2021 - $Nil). The funds received were used to completely repay the subordinated debt, a portion of the Company’s outstanding bank debt and general corporate purposes. Security for the Subordinated Term Debt consists of various floating demand debentures totaling $150,000,000 (December 31, 2021 - $Nil) over all of the Company’s assets and a general security agreement with second ranking over all personal and real property. As at December 31, 2022, Bonterra was in compliance with all financial covenants on its second lien Subordinated Term Debt facility (as described in Note 8). 56 12. DECOMMISIONING LIABLITIES At December 31, 2022, the estimated total uninflated and undiscounted amount required to settle the decommissioning liabilities was $178,183,000 (December 31, 2021- $153,061,000). The provision has been calculated assuming a 2.0 percent inflation rate (December 31, 2021 – 2.0 percent inflation rate). These obligations will be settled at the end of the useful lives of the underlying assets, which extend up to 50 years into the future. This amount has been discounted using a risk-free interest rate of 3.27 percent (December 31, 2021 – 2.30 percent). (1) The change is estimate was primarily due to an increase in estimated costs less an increase in the discount rate. (2) Included in liabilities settled is $2,437,000 of abandonment deposits (December 31, 2021 - $Nil). 13. INCOME TAXES Income tax expense varies from the amounts that would be computed by applying Canadian federal and provincial tax rates as follows: 57 ($ 000s)December 31, 2022December 31, 2021Decommissioning liabilities, January 1135,815 137,002 Changes in estimate(1)(18,125) 5,980 Liabilities settled during the year(2)(8,367) (4,496) Government grant in-kind (Note 20)(3,675) (5,901) Accretion on decommissioning liabilities3,567 3,230 Decommissioning liabilities, end of year109,215 135,815 ($ 000s)December 31, 2022December 31, 2021Deferred tax asset (liability) related to:Investments(120) 11 (145,019) (149,656) Investment tax credits(2,040) (2,041) Decommissioning liabilities25,700 31,276 Corporate tax losses carried forward- 16,284 Share issue costs1,566 539 Financial derivative(184) 1,052 Subordinated debenture(2,125) (2,681) Subordinated term debt(1,408) - Corporate capital tax losses carried forward7,449 7,453 Unrecorded benefits of capital tax losses carried forward(7,329) (7,453) Unrecorded benefits of successored resource related pools(4,009) (4,090) Deferred tax asset (liability)(127,519) (109,306) Exploration and evaluation assets and property, plant and equipment($ 000s)December 31, 2022December 31, 2021Earnings before taxes104,569 232,964 Combined federal and provincial income tax rates23.03%23.03%Income tax provision calculated using statutory tax rates24,082 53,652 Increase (decrease) in taxes resulting from:Share-option compensation440 252 Change in unrecorded benefits of tax pools(205) (95) Change in estimates and other1,229 (144) 25,546 53,665 The Company has the following tax pools, which may be used to reduce taxable income in future years, limited to the applicable rates of utilization: The Company has $5,761,000 (December 31, 2021 - $8,861,000) of investment tax credits that expire in the following years: 2025 - $477,000; 2026 - $2,405,000; 2027- $2,009,000; 2028 - $745,000; 2034 - $99,000; and 2037 - $26,000. The Company has $64,725,000 (December 31, 2021 - $64,725,000) of capital losses carried forward which can only be claimed against taxable capital gains. 14. SHAREHOLDERS’ EQUITY Authorized The Company is authorized to issue an unlimited number of common shares without nominal or par value. The Company is authorized to issue an unlimited number of Class “A” redeemable Preferred Shares and an unlimited number of Class “B” Preferred Shares. There are currently no outstanding Class “A” redeemable Preferred Shares or Class “B” Preferred Shares. The weighted average common shares used to calculate basic and diluted net earnings per share for the year ended December 31, 2022, are as follows: (1) The Company did not include 1,756,844 share-options and warrants (December 31, 2021 – 3,574,500) in the dilutive effect of share-options and warrants calculations as these were anti-dilutive. 58 ($ 000s)Rate of Utilization (%)AmountUndepreciated capital costs7-10060,770 Share issue costs206,804 Canadian oil and gas property expenditures1066,255 Canadian development expenditures3097,113 Canadian exploration expenditures1008,587 239,529 Issued and fully paid - common sharesNumberAmount ($ 000s)NumberAmount ($ 000s)Balance, beginning of year35,000,952 772,781 33,511,316 765,415 Shares issued for interest on subordinated promissory note- - 118,896 414 Issued pursuant to the Company's share option plan1,360,940 1,612 183,740 378 Transfer from contributed surplus to share capital1,804 168 Issued pursuant to the exercise of warrants551,000 4,270 1,187,000 7,003 Transfer from warrants to share capital1,212 (356) Share issue costs, net of tax- (241) Balance, end of year36,912,892 781,679 35,000,952 772,781 December 31, 2022December 31, 202120222021Basic shares outstanding 35,968,921 33,729,730 Dilutive effect of share options and warrants(1)1,314,945 1,031,445 Diluted shares outstanding37,283,866 34,761,175 Warrants A summary of the status of warrants issued by the Company as of December 31, 2022 and changes during the period are presented below: The Warrants issued entitle the holder to purchase one Common Share of Bonterra for each Warrant at a price of $7.75, until October 20, 2025. Options The Company provides an equity settled option plan for its directors, officers and employees. Under the plan, the Company may grant options for up to 3,691,289 (December 31, 2021 – 3,500,095 common shares). The exercise price of each option granted cannot be lower than the market price of the common shares on the date of grant and the option’s maximum term is five years. A summary of the status of the Company’s stock options as of December 31, 2022 and changes during the period are presented below: (1) 720,250 options were exercised under the cashless option method, which resulted in 536,340 shares being issued in which the Company received no proceeds. Under the cashless option method, the remaining options between the number of options exercised and shares issued are cancelled. 59 Number of warrantsWeighted exercise priceAt January 1, 2021 - $ - Warrants granted 3,304,000 7.75At December 31, 2021 3,304,000 $7.75Warrants exercised (551,000)7.75At December 31, 20222,753,000 $7.75Number of optionsWeighted average exercise priceAt January 1, 2021 2,426,700 $2.63Options granted 235,500 4.39Options exercised(1) (266,600)3.02Options forfeited (87,000)1.96Options expired (47,000)13.55At December 31, 2021 2,261,600 $2.56Options granted 2,051,500 8.10Options exercised(1) (1,544,850)2.12Options forfeited (2,500)3.14Options expired (14,000)17.76At December 31, 20222,751,750 $6.86 The following table summarizes information about options outstanding and exercisable as at December 31, 2022: The Company records compensation expense over the vesting period, which ranges between one and three years, based on the fair value of options granted to directors, officers and employees. In 2022, the Company granted 2,051,500 options with an estimated fair value of $6,544,000 or $3.19 per option using the Black- Scholes option pricing model with the following key assumptions: (1) Risk-free interest rate is based on the weighted average Government of Canada benchmark bond yields for one, two, and three year terms to match corresponding vesting periods. (2) The expected volatility is measured as the standard deviation of expected share price returns based on statistical analysis of historical weekly share prices for a representative period. 15. OIL AND GAS SALES, NET OF ROYALTIES 16. OTHER INCOME 60 Range of exercise pricesNumber outstandingWeighted-average remaining contractual lifeWeighted-average exercise priceNumber exercisableWeighted-average exercise price$ 1.00 - $ 5.00665,250 0.7 years $ 3.10 458,250 $ 2.97 5.01 - 10.002,041,500 4.5 years7.9625,000 5.7210.01 - 15.0045,000 2.4 years12.32- - $ 1.00 - $ 15.002,751,750 3.5 years $ 6.86 483,250 $ 3.11 Options outstandingOptions exercisableDecember 31, 2022December 31, 2021Weighted-average risk free interest rate (%)(1)2.590.40Weighted-average expected life (years)2.02.0Weighted-average volatility (%)(2)75.0684.61Forfeiture rate (%)7.207.69Weighted average dividend yield (%)1.522.71($ 000s)December 31, 2022December 31, 2021Oil and gas salesCrude oil 295,046 195,985 Natural gas liquids 27,497 16,225 Natural gas 61,654 39,406 384,197 251,616 Less royalties:Crown (44,842) (15,241)Freehold, gross overriding royalties and other (17,233) (10,509) (62,075) (25,750)Oil and gas sales, net of royalties 322,122 225,866 ($ 000s)December 31, 2022December 31, 2021Investment income 221 67 Administrative income 706 487 Gain on sale of property and equipment - 225 Government grant in-kind (Note 20) 3,675 5,901 Other income 4,602 6,680 17. SUPPLEMENTAL CASH FLOW INFORMATION 18. FINANCIAL RISK MANAGEMENT Financial Risk Factors The Company undertakes transactions in a range of financial instruments including: • Accounts receivable • Accounts payable and accrued liabilities • Common share investments • Bank debt • Subordinated debentures • Subordinated term debt 61 ($ 000s)December 31, 2022December 31, 2021Change in non-cash working capital:Accounts receivable (3,111) (11,324)Crude oil inventory (158) (270)Prepaid expenses (1,286) (2,002)Investment tax credit receivable 3,100 - Abandonment deposit (2,437) - Accounts payable and accrued liabilities 735 6,609 (3,157) (6,987)Changes related to:Operating activities 2,928 (6,229)Investing activities (6,085) (758) (3,157) (6,987)Finance expense ($ 000s)December 31, 2022December 31, 2021Interest expense:Bank and subordinated debt8,974 21,332 Due to related party- 557 Subordinated debenture5,310 1,047 Subordinated term debt1,193 - Subordinated promissory note- 333 15,477 23,269 Accretion:Decommissioning liabilities3,567 3,230 Subordinated debentures2,411 410 Subordinated term debt192 - 6,170 3,640 Total finance costs21,647 26,909 Interest expense15,477 23,269 Interest accrued(1,193) (2,052)Interest paid14,284 21,217 The Company’s activities result in exposure to a number of financial risks including market risk (commodity price risk, interest rate risk, and foreign exchange risk), credit risk, liquidity risk and equity price risk. The Company’s overall risk management program seeks to mitigate these risks and reduce the volatility on the Company’s financial performance. Financial risk is managed by senior management under the direction of the Board of Directors. The Company is exposed to credit risk, liquidity risk and market risk as part of its normal course of business. The Company’s overall risk management program seeks to mitigate these risks and reduce the volatility on the Company’s financial performance. Financial risk is managed by senior management under the direction of the Board of Directors. The Company does not speculatively trade in risk management contracts. The Company’s risk management contracts are entered into in order to manage the risks relating to commodity prices from its business activities. Liquidity Risk Management Liquidity risk is the risk that the Company will encounter difficulty in meeting obligations associated with its financial liabilities. The Company’s financial performance and position are largely dependent on the commodity prices received for its oil and natural gas production. Commodity prices have fluctuated widely in recent years due to the COVID-19 pandemic, crude oil inventory levels, domestic infrastructure constraints, global economic and geopolitical factors. The Company continues to retain available committed borrowing capacity that provides the Company with financial flexibility and the ability to meet ongoing obligations as they become due. After examining the economic factors that are causing the liquidity risk facing the Company, the judgment applied to these factors, and the various initiatives that the Company has and will undertake to strengthen its financial position, the Company believes it will have sufficient liquidity to support its ongoing operations and meet its financial obligations as they come due for at least the next twelve months. There can be no assurance that the next borrowing base redetermination will not result in a borrowing base shortfall, and that the necessary funds or additional security will be available to eliminate the shortfall. Upon receipt of notice from the lenders, the shortfall would have to be remedied within 30 days or by such other means as acceptable to the lenders. Credit Risk Credit risk is the risk that a contracting party will not complete its obligations under a financial instrument and cause the Company to incur a financial loss. The Company is exposed to credit risk on all financial assets included on the statement of financial position. To help mitigate this risk: • The Company only enters into material agreements with credit worthy counterparties. These include major oil and gas companies or major Canadian chartered banks; and • Agreements for product sales are primarily on 30-day renewal terms. Of the $27,327,000 accounts receivable balance at December 31, 2022 (December 31, 2021 - $24,215,000) over 93 percent (December 31, 2021 – 89 percent) relate to product sales or risk management contracts with national and international banks and oil and gas companies. On a quarterly basis, Bonterra assesses if there has been any impairment of the financial assets of the Company. During the year ended December 31, 2022, there was no material impairment provision required on any of the financial assets of the Company. Bonterra does have credit risk exposure, as the majority of the Company’s accounts receivable are with counterparties having similar characteristics. However, 62 payments from the Company’s largest accounts receivable counterparties have consistently been received within 30 days and the sales agreements with these parties are cancellable with 30 days’ notice if payments are not received. At December 31, 2022, approximately $262,000 or 1.1 percent of the Company’s total accounts receivable are aged over 90 days and considered past due (December 31, 2021 - $459,000 or 1.9 percent). The majority of these accounts are due from various joint venture partners. The Company actively monitors past due accounts and takes the necessary actions to expedite collection, which can include withholding production or netting payables when the accounts are with joint venture partners. Should the Company determine that the ultimate collection of a receivable is in doubt, it will provide the necessary provision in its allowance for doubtful accounts with a corresponding charge to earnings. If the Company subsequently determines an account is uncollectable, the account is written off with a corresponding charge to the allowance account. The Company’s allowance for doubtful accounts balance at December 31, 2022 is $1,248,000 (December 31, 2021 - $1,287,000) with the expense being included in general and administrative expenses. There were no material accounts written off during the period. The maximum exposure to credit risk is represented by the carrying amounts of accounts receivable. There are no material financial assets that the Company considers past due. Capital Risk Management The Company’s objectives when managing capital, which the Company defines to include shareholders’ equity, debt and working capital balances, are to safeguard the Company’s ability to continue as a going concern, so that it can continue to provide returns to its shareholders and benefits for other stakeholders and to maintain a capital structure that provides a low cost of capital. In order to maintain or adjust the capital structure, the Company may adjust the current debt structure and/or issue common shares. The Company monitors capital based on the ratio of net debt (total debt adjusted for working capital) to cash flow from operating activities. This ratio is calculated using each quarter end net debt divided by the preceding twelve months’ cash flow. At December 31, 2022, the Company had a net debt to cash flow level of 0.8:1 compared to 2.8:1 as at December 31, 2021. The improvement in Bonterra’s net debt to cash flow ratio is primarily due to the Company’s repayment of debt and an increase in cash flow from increasing commodity prices and production. The net debt to cash flow ratio is expected to continue to improve in subsequent quarters due to the Company’s focus on debt reduction paired with improved commodity prices, increased production and future cash flow protection from having approximately 30 percent of Bonterra’s forecasted oil and natural gas production hedged over the next 9 months. Section (a) of this note provides the Company’s debt to cash flow from operations. Section (b) addresses in more detail the key financial risk factors that arise from the Company’s activities including its policies for managing these risks. 63 a) Net debt to cash flow ratio The net debt and cash flow amounts are as follows: (1) (2) Bank debt is classified as a current liability for 2021. Included in current liabilities is the current portion of the Subordinated Term Debt of $20,193,000 (December 31, 2021 - $Nil) b) Risks and mitigation Market risk is the risk that the fair value or future cash flow of the Company’s financial instruments will fluctuate because of changes in market prices. Components of market risk to which the Company is exposed are discussed below. Commodity Price Risk The Company’s principal operation is the production and sale of crude oil, natural gas and natural gas liquids. Fluctuations in prices of these commodities directly impact the Company’s performance and ability to continue with its dividends. The Company has used various risk management contracts to set price parameters for a portion of its production. The Company has assumed the risk in respect of commodity prices, except for a small portion of physical delivery sales and risk management contracts to manage commodity risk on the Company’s higher operating cost areas. The Company is exposed to credit risk, liquidity risk and market risk as part of its normal course of business. The Company’s overall risk management program seeks to mitigate these risks and reduce the volatility on the Company’s financial performance. Financial risk is managed by senior management under a risk management program approved by the Board of Directors. 64 ($ 000s)December 31, 2022December 31, 2021Bank debt(1)17,601 162,945 Subordinated debt- 47,268 Subordinated debentures49,770 47,359 Subordinated term debt(2)69,882 - Current liabilities56,805 40,920 Current assets (44,227) (31,313)Net debt149,831 267,179 Cash flow from operations (trailing twelve months)183,553 96,103 Net debt to cash flow ratio0.8 2.8 Physical Delivery Sales Contracts Bonterra enters into physical delivery sales contracts to manage commodity price risk. These contracts are considered normal executory sales contracts and are not recorded at fair value in the financial statements. As of December 31, 2022, the Company has the following physical delivery sales contracts in place. (1) (2) (3) (4) (5) “WTI” refers to West Texas Intermediate, a grade of light sweet crude oil used as benchmark pricing in the United States. "MSW Stream index" or "Edmonton Par" refers to the mixed sweet blend that is the benchmark price for conventionally produced light sweet crude oil in Western Canada. “MSW differential” is the primary difference between WTI and MSW steam index benchmark pricing. “AECO Daily” refers to a grade or heating content of natural gas used as daily index benchmark pricing in Alberta, Canada. “AECO Monthly” refers to a grade or heating content of natural gas used as monthly index benchmark pricing in Alberta, Canada. Subsequent to December 31, 2022, the Company entered into the following physical delivery sales contract. 65 ProductType of contractVolumeOilPhysical collar - WTI(1)500 BBL/dayJan 1, 2023toMar 31, 202365.00 to86.00 USD/BBLOilPhysical collar - WTI(1)500 BBL/dayJan 1, 2023toMar 31, 202370.00 to100.00 USD/BBLOilPhysical collar - WTI(1)500 BBL/dayApr 1, 2023toJun 30, 202380.00 to102.25 USD/BBLOilFixed price - MSW differential(2)(3)500 BBL/dayJan 1, 2023toMar 31, 2023(4.50) USD/BBLGasPhysical collar - AECO Monthly(5)5,000 GJ/dayJan 1, 2023toMar 31, 20234.00 to4.55 CAD/GJGasFixed Price - AECO Daily(4)5,000 GJ/dayApr 1, 2023toJun 30, 20234.28 CAD/GJGasFixed Price - AECO Daily(4)4,000 GJ/dayJul 1, 2023toSep 30, 20233.85 CAD/GJContract price ($)TermProductType of contractVolumeGasFixed Price - AECO Daily2,500 GJ/dayApr 1, 2023toOct 31, 20232.55 CAD/GJTermContract price ($) Risk Management Contracts The Company also enters into financial derivative instruments or risk management contracts to manage commodity price risk. These contracts are not considered normal executory sales contracts and are recorded at fair value in the financial statements. The Company has entered into the following risk management contracts during the period ended December 31, 2022. 66 ($ 000s)December 31, 2022December 31, 2021Risk management contractsRealized loss (16,878) (17,389)Unrealized gain (loss) 5,365 (968) (11,513) (18,357)ProductType of contractVolumeOilFinancial collar - WTI500 BBL/dayJan 1, 2023toMar 31, 202360.00 to88.00 USD/BBLOilFinancial collar - WTI500 BBL/dayJan 1, 2023toMar 31, 202365.00 to89.45 USD/BBLOilFinancial collar - WTI500 BBL/dayJan 1, 2023toMar 31, 202365.00 to100.00 USD/BBLOilFinancial collar - WTI500 BBL/dayApr 1, 2023toJun 30, 202370.00 to100.00 USD/BBLOilFinancial collar - WTI1,000 BBL/dayApr 1, 2023toJun 30, 202375.00 to101.00 USD/BBLOilFinancial collar - WTI250 BBL/dayApr 1, 2023toJun 30, 202375.00 to103.30 USD/BBLOilFinancial collar - WTI500 BBL/dayJul 1, 2023toSep 30, 202370.00 to95.00 USD/BBLOilFinancial collar - WTI500 BBL/dayJul 1, 2023toSep 30, 202370.00 to98.65 USD/BBLOilFinancial collar - WTI500 BBL/dayJul 1, 2023toSep 30, 202350.00 to95.25 USD/BBLOilFinancial collar - WTI600 BBL/dayJul 1, 2023toSep 30, 202350.00 to98.00 USD/BBLOilFixed price - MSW differential500 BBL/dayJan 1, 2023toMar 31, 2023(4.40) USD/BBLOilFixed price - MSW differential500 BBL/dayJan 1, 2023toMar 31, 2023(4.20) USD/BBLOilFixed price - MSW differential500 BBL/dayApr 1, 2023toJun 30, 2023(3.50) USD/BBLOilFixed price - MSW differential500 BBL/dayJul 1, 2023toSep 30, 2023(3.80) USD/BBLGasFinancial collar - AECO Monthly4,000 GJ/dayJan 1, 2023toMar 31, 20234.50 to5.00 CAD/GJGasFixed Price - AECO Monthly5,000 GJ/dayApr 1, 2023toJun 30, 20234.30 CAD/GJGasFinancial collar - AECO Monthly5,000 GJ/dayJul 1, 2023toSep 30, 20234.00 to5.00 CAD/GJTermContract price ($) Subsequent to December 31, 2022, the Company entered into the following risk management contracts. Interest Rate Risk Interest rate risk refers to the risk that the value of a financial instrument or cash flows associated with the instrument will fluctuate due to changes in market interest rates. Interest rate risk arises from interest bearing financial assets and liabilities that the Company uses. The principal exposure of the Company is on its borrowings which have a variable interest rate which gives rise to a cash flow interest rate risk. As of December 31, 2022, the Company’s debt facilities consist of a $85,000,000 syndicated revolving credit facility, and a $25,000,000 non-syndicated revolving credit facility, $95,000,000 second lien Subordinated Term Debt and $59,000,000 in senior unsecured subordinated debentures. The borrowings under the total bank facilities are at bank prime plus or minus various percentages as well as by means of banker’s acceptances (“BAs”) within the Company’s credit facility. The subordinated debt has a fixed interest rate of 11.7 percent for a quarter of the outstanding balance and prime plus 6.25 percent for the remaining outstanding balance. Subordinated debentures are at a fixed interest rate of nine percent. The Company manages its exposure to interest rate risk on its floating interest rate debt through entering into various term lengths on its BAs but in no circumstances do the terms exceed six months. Sensitivity Analysis Based on historic movements and volatilities in the interest rate markets and management’s current assessment of the financial markets, the Company believes that a one percent variation in the Canadian prime interest rate is reasonably possible over a 12-month period. A one percent increase (decrease) in the Canadian prime rate would decrease (increase) both annual net earnings and comprehensive income by $691,000. Equity Price Risk Equity price risk refers to the risk that the fair value of the investments and investment in related party will fluctuate due to changes in equity markets. Equity price risk arises from the realizable value of the investments that the Company holds which are subject to variable equity market prices which on disposition gives rise to a cash flow equity price risk. The Company will assume full risk in respect of equity price fluctuations. Foreign Exchange Risk The Company has no foreign operations and currently sells all of its product sales in Canadian currency. The Company however is exposed to currency risk in that crude oil is priced in US currency, then converted to Canadian currency. The Company currently has no outstanding risk management agreements. The Company will assume full risk in respect of foreign exchange fluctuations. 67 ProductType of contractVolumeOilFinancial collar - WTI500 BBL/dayOct 1, 2023toDec 31, 202360.00 to86.75 USD/BBLOilFinancial collar - WTI500 BBL/dayOct 1, 2023toDec 31, 202360.00 to90.00 USD/BBLTermContract price ($) 19. COMMITMENTS AND FINANCIAL LIABILITIES The Company has the following maturity schedule for its financial liabilities and commitments: (1) Principal amount. The Company has entered into firm service gas transportation agreements in which the Company guarantees certain minimum volumes of natural gas will be shipped on various gas transportation systems. The terms of the various agreements expire in one to seven years. The future minimum payment amounts for the firm service gas transportation agreements are calculated using current tariff rates. The Company also has non-cancellable office lease commitments for building and office equipment. The building and office equipment leases have an average remaining life of 3.9 years. 20. GOVERNMENT GRANTS The Government of Alberta’s Site Rehabilitation Program (“SRP”) provides grant funding through service providers to abandon or remediate oil and gas sites. The Company derecognized approximately $3,675,000 of asset retirement obligations as an in-kind grant (December 31, 2021 - $5,901,000). The benefit of the in- kind grant is recognized through other income. 21. TRANSACTIONS WITH RELATED PARTIES On October 20, 2021, a $12,000,000 loan to Bonterra provided by a major shareholder, director and former CEO of the Company was exchanged for senior unsecured subordinated debentures plus warrants and approximately $923,000 of current and previously accrued interest to the Conversion Date was settled for cash. 68 ($ 000s)Recognized on Financial StatementsLess than 1 yearOver 1 year to 3 yearsOver 3 years to 5 yearsOver 5 years to 7 yearsTotalAccounts payable and accrued liabilitiesYes - Liability35,573 - - - 35,573 Bank debtYes - Liability- 17,601 - - 17,601 Subordinated debentures(1)Yes - Liability- - 59,000 - 59,000 Subordinated term debt(1)Yes - Liability19,000 38,000 38,000 - 95,000 Future interestNo16,047 28,439 3,761 - 48,247 Firm service commitmentsNo1,045 1,201 611 103 2,960 Office lease commitmentsNo486 1,010 499 - 1,995 Total72,151 86,251 101,871 103 260,376 CORPORATE INFORMATION Board of Directors D. Michael G. Stewart - Chair John J. Campbell George F. Fink Stacey E. McDonald Patrick G. Oliver Jacqueline R. Ricci Rodger A. Tourigny Officers Patrick G. Oliver, President and CEO Robb D. Thompson, CFO and Corporate Secretary Adrian Neumann, Chief Operating Officer Brad A. Curtis, Senior VP, Business Development Registrar and Transfer Agent Odyssey Trust Company Auditors Deloitte LLP Solicitors Borden Ladner Gervais LLP Bankers CIBC ATB Financial Business Development Bank of Canada Head Office 901, 1015 – 4th Street SW Calgary, Alberta T2R 1J4 Telephone: 403.262.5307 Fax: 403.265.7488 Email: info@bonterraenergy.com Website www.bonterraenergy.com 69 901, 1015 – 4th Street SW Calgary, Alberta, T2R 1J4 TEL 403.262.5307 FAX 403.265.7488 info@bonterraenergy.com www.bonterraenergy.com 70 

Continue reading text version or see original annual report in PDF format above