Bonterra Energy Corp.
Annual Report 2023

Plain-text annual report

2023 Annual Report Bonterra Energy Corp. December 31, 2023 ABOUT BONTERRA forward land position Bonterra Energy Corp. is a conventional oil and gas for corporation forging a grounded path large, Canadian energy. Operations concentrated in Alberta's Pembina Cardium, one of Canada's largest oil plays. Bonterra's liquids-weighted Cardium production provides a foundation for implementing a return of capital strategy over time, which is focused on generating long-term, sustainable growth and value creation for shareholders. include a An emerging Charlie Lake light oil asset and a Montney exploration opportunity are both expected to provide enhanced optionality and an expanded potential development runway for the future. TABLE OF CONTENTS About Bonterra Report to Shareholders Highlight Tables Statistical Review Management's Discussion and Analysis Financial Statements Notes to Financial Statements Corporate Information CONTACT INFORMATION HEAD OFFICE Suite 901, 1015-4th Street SW Calgary, AB T2R 1J4 T: (403) 262-5307 F: (403) 265-7488 OFFICERS Patrick G. Oliver, President & CEO Robb D. Thompson, CFO & Corporate Secretary Brad A. Curtis, Senior VP, Business Development Steve Ewens, VP Engineering 2 3 6 8 12 32 39 IBC 2 | Page REPORT TO SHAREHOLDERS As we look back on the Company’s performance and achievements of the past year, I am very proud to share highlights of the operating and financial results generated by Bonterra Energy Corp. (“Bonterra” or the “Company”), through both the full year and the fourth quarter of 2023. This represents another period of continued progress and operational success for Bonterra, as our team truly delivered in the execution of our refreshed corporate strategy that saw the Company meet or exceed guidance across all key metrics. Above all, we achieved corporate milestones while navigating market volatility and uncertainty in commodity prices and remained committed to shareholder value creation. In addition to production increases, including record volumes in the fourth quarter that averaged 15,128 BOE per day, Bonterra continued to transform the organization during 2023. We underwent a rebrand that aligned with our refreshed corporate strategy; added a new independent director; bolstered our internal technical team and expanded our asset base to include two new prolific light oil plays in the Montney and Charlie Lake, advancing the Company’s long term sustainability. The recently announced Charlie Lake acquisition was acquired for $24.1 million adding economic multi- year drilling inventory,330 BOE per day of oil weighted production while improving the Company’s free funds flow profile. 2023 Financial and Operating Snapshot • Production in 2023 averaged 14,204 BOE per day exceeding the top end of our guidance of 13,500 to 13,700 BOE per day; • We invested $126.5 million of capital during the year, including drilling and completing our first Montney well for $9.0 million, which was not budgeted; • Funds flow1 totaled $147.3 million ($3.95 per fully diluted share) in 2023, while free funds flow was $12.5 million in 2023, which we primarily allocated to debt reduction; • Net earnings were $44.9 million ($1.20 per diluted share) in the year; • Net debt1 decrease six percent over 2022, totaling $140.4 million at year-end 2023, with bank debt decreasing 16 percent over the same period; • Production costs of $16.02 per BOE were at the low end of our $16.00 to 16.50 per BOE guidance in 2023, demonstrating our team’s ability to control costs and operate efficiently; and • We exceeded guidance for investing in abandonment and reclamation, which totaled $9.1 million (gross), compared to expectations of $5.0 to $6.0 million. 3 | Page Efficient Capital Allocation Our team executed another safe, efficient and successful capital program in 2023 that centred on the development of our high-quality, light oil weighted Cardium assets. This culminated in the successful drilling of 41 gross (39.2 net) operated wells along with the completion, equip, tie-in and placing on production of 37 gross (35.6 net) operated wells. The remaining four gross (3.6 net) operated wells were brought onstream in the first quarter of 2024. We also invested in strategic infrastructure, recompletions and non-operated capital development, including the successful expansion of a wholly owned gas plant to alleviate processing capacity limitations along with the upgrading of equipment to drive down per unit production costs, as well as the drilling of our first exploration Montney well. Commodity price fluctuations that occurred through 2023 served as an important reminder that maintaining an optimal commodity weighting can be highly strategic. As demonstrated, we saw WTI prices remain relatively stable in the mid $70/bbl through the year, while AECO natural gas prices retreated from $5.09/mcf in the final quarter of 2022, to $2.29/mcf in the fourth quarter of 2023. Bonterra’s revenue in 2023 was derived 88% from oil and liquids, which is positive given the current weak spot and future price outlook for natural gas. Expanding Our Runway Testing of First Montney Well As part of our strategy to position Bonterra for long-term sustainability, expand the Company’s potential drilling inventory and enhance optionality for shareholders, during 2023, we took the first steps to creating a new core area in the Montney, which is regarded as one of the most economic and expansive plays in North America. We drilled our first exploratory Montney well on Bonterra’s 45 section land position without increasing capital, and the results from this well could support drilling of a second well from the same pad in 2024 to further derisk and delineate the area while also holding the acreage. We have since negotiated a processing agreement and secured natural gas egress through third party infrastructure with expectations of flowing the Montney well in the second quarter of 2024. The results of our first Montney well support continued testing and delineation in the area, though we intend to take a measured approach to align the pace of development with available egress. Charlie Lake Acquisition Bonterra’s new core area in the Charlie Lake, which is also deemed one of the top five trending oil plays in the Western Canadian Sedimentary Basin, is highly complementary to our existing Cardium assets and we can directly leverage our team’s operational experience. We built on a previously assembled 37 net sections in the area with the addition of 79 new net sections of land in Bonanza, Alberta, resulting in a total of 116 net sections of contiguous land in the light oil prone Charlie Lake, providing Bonterra with a longer development runway that is prospective for light oil. Based on modeling, our full-field development plan for the Charlie Lake anticipates production reaching 6,000 BOE per day by 2026 that can be maintained over the long-term, while also maintaining our leverage metrics that support efforts to implement a return of capital framework. 4 | Page Where We Go From Here The volatility in commodity prices experienced during 2023 served as a reminder that maintaining an optimal commodity mix is highly strategic, and our oil and liquids weighted asset base has positioned the Company well to navigate future uncertainty. We are excited by the development opportunities identified under the emerging Charlie Lake and Montney assets, which offer considerable value creation potential while expanding Bonterra’s longer-term drilling inventory. Given the recent additions to our asset portfolio, the Company can now pivot from ongoing acquisition evaluation to place a greater focus on the execution of an efficient capital program and profitable development of our three core areas. We are pleased to supplement this operational focus by the recent addition of a senior geologist with extensive Charlie Lake experience, and the appointment of Mr. Steve Ewens, VP Engineering, to head our talented engineering group. Bonterra will remain committed to prioritizing responsible free funds flow generation in 2024 which can be directed to further balance sheet strengthening, achieving modest production growth, or the implementation of a return of capital model. Reflecting on another successful year in 2023, I want to extend my appreciation to the Bonterra team, and to all of our stakeholders for your trust in the Company. Under the invaluable oversight and guidance of our Board of Directors, we look forward to building on our current momentum to propel us on our journey towards responsible, long-term value creation. Patrick Oliver President & Chief Executive Officer 5 | Page ANNUAL HIGHLIGHTS FINANCIAL AND OPERATIONAL HIGHLIGHTS December 31, 2023 December 31, 2022 December 31, 2021 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(2) Per share - basic Per share - diluted Capital expenditures Total assets Net debt(3) Bank debt Shareholders' equity OPERATIONS Light oil NGLs -bbl per day -average price ($ per bbl) -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) 319,517 147,305 3.96 3.95 140,183 3.77 3.76 44,943 1.21 1.20 126,478 967,870 140,400 14,822 528,258 7,209 97.58 1,359 48.80 33,814 3.12 14,204 384,197 185,583 5.16 4.98 183,553 5.10 4.92 79,023 2.20 2.12 79,769 919,682 149,831 17,601 479,839 7,095 113.93 1,141 66.00 31,023 5.44 13,407 251,616 104,843 3.11 3.02 96,103 2.85 2.76 179,299 5.32 5.16 67,282 945,721 267,179 162,945 392,019 7,204 74.53 1,013 43.86 27,176 3.97 12,747 (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) The Company recorded a $203,197,000 impairment reversal on its Alberta CGU’s oil and gas assets less $47,149,000 deferred income tax expense in Q2 2021, due to the recovery of crude oil forward benchmark prices from the impact of COVID-19 in 2020. (3) Net debt is not a recognized measure under IFRS. The Company defines net debt as current liabilities less current assets plus long-term bank debt, subordinated debentures and subordinated term debt. (4) BOE may be misleading, particularly if used in isolation. A BOE conversion ratio of 6 MCF: 1 bbl is based on an energy conversion method primarily applicable at the burner tip and does not represent a value equivalency at the wellhead. 6 | Page QUARTERLY HIGHLIGHTS (1) Funds flow is not a recognized measure under IFRS. For these purposes, the Company defines funds flow as funds provided by operations including proceeds from sale of investments and investment income received excluding the effects of changes in non- cash working capital items and decommissioning expenditures settled. (2) Net debt is not a recognized measure under IFRS. The Company defines net debt as current liabilities less current assets plus long-term subordinated term debt and subordinated debentures. (3) BOE may be misleading, particularly if used in isolation. A BOE conversion ratio of 6 MCF: 1 bbl is based on an energy conversion method primarily applicable at the burner tip and does not represent a value equivalency at the wellhead. 7 | Page As at and for the periods ended($ 000s except $ per share)Q4Q3Q2Q1Financial Revenue - oil and gas sales 81,73984,90975,60677,263Funds flow (1)40,44242,72234,79929,342Per share - basic1.091.150.940.79Per share - diluted1.081.140.930.79Cash flow from operations44,59637,71533,85424,018Per share - basic1.201.010.910.65Per share - diluted1.191.010.910.64Net earnings 14,97313,4868,8447,640Per share - basic0.400.360.240.21Per share - diluted0.400.360.240.20Capital expenditures 14,009 36,130 16,116 60,223 Total assets967,870955,484962,021963,890Bank debt14,82226,61335,50612,388Net debt(2)140,400167,449168,344183,674Shareholders' equity528,258512,479498,449488,762OperationsLight oil (barrels per day)7,3067,1777,2827,068Average price ($ per bbl)97.01104.3293.2195.71NGLs (barrels per day)1,6191,4101,2481,155Average price ($ per bbl)48.1249.1943.9754.54Conventional natural gas (MCF per day)37,21434,24132,28631,448Average price ($ per MCF)2.733.063.013.78Total BOE per day(3)15,12814,29413,91113,4642023 STATISTICAL REVIEW Summary of Gross Oil and Gas Reserves as of December 31, 202 3 Reserves Category: PROVED Developed Producing Developed Non-Producing Undeveloped TOTAL PROVED PROBABLE TOTAL PROVED PLUS PROBABLE(1)(2)(3) Light & Medium Crude Oil (Mbbl) 16,475 2,485 23,245 42,205 10,950 53,155 Conventional Natural Gas Natural Gas Liquids (MMCF) (Mbbl) Oil equivalent(4) (MBOE) Future development Capital (000s) 79,677 13,626 91,458 184,761 46,976 231,737 3,008 501 3,633 7,142 1,827 8,969 32,763 - 5,257 42,121 80,141 8,525 707,017 715,542 20,606 3,951.00 100,747 719,493 (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 Sproule’s December 31, 2023 escalated price deck. (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, 2023(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) Opening Balance December 31, 2022 Extensions & Improved Recovery(2) 43,174 4,469 53,574 184,352 230,520 5,829 16,768 21,477 6,802 756 8,496 967 80,702 100,490 8,019 10,376 Technical Revisions Dispositions Economic Factors Production Closing Balance, December 31, 2023(3) (3,053) (3,908) (4,113) (7,975) 79 2 (3,658) (5,234) - - (203) (256) (11) (13) 246 290 299 313 12 13 (44) 307 (56) 356 (2,631) (2,631) (12,342) (12,342) (496) (496) (5,185) (5,185) 42,205 53,154 184,761 231,737 7,142 8,969 80,141 100,747 (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. Includes volumes associated with Farm outs. (3) (4) Totals may not add due to rounding. 8 | Page Summary of Net Present Values of Future Net Revenue as of December 31, 2023 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% 899,090 141,106 1,018,596 2,058,792 799,896 2,858,688 692,144 99,918 629,647 1,421,710 483,731 1,905,441 557,339 76,585 411,865 1,045,789 337,012 1,382,801 468,130 61,736 280,415 810,282 256,000 1,066,282 (1) Evaluated by Sproule as at December 31, 2023. 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, 2023. 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 2023 2022 2021 3 Yr Avg(4) 2023 2022 2021 3 Yr Avg(4) FD&A COSTS PER BOE (1)(2)(3)(5) Including FDC Excluding FDC F&D COSTS PER BOE (1)(2)(3)(5) Including FDC Excluding FDC $39.08 $24.85 $27.09 $10.47 $6.90 $8.68 $21.27 $34.16 $23.34 $5.64 $19.36 $13.71 $23.24 $10.02 $8.23 $12.68 $39.08 $24.85 $27.09 $10.47 $6.90 $8.68 $21.27 $34.16 $23.34 $5.64 $19.36 $13.71 $23.24 $10.02 $8.23 $12.68 (1) Barrels of Oil Equivalent may be misleading, particularly if used in isolation. A BOE conversion ratio of 6 MCF: 1 bbl is based on an energy equivalency conversion method primarily applicable at the burner tip and does not represent a value equivalency at the wellhead. (2) The aggregate of the exploration and development costs incurred in the most recent financial year and the change during that year in estimated future development costs generally will not reflect total finding and development costs related to reserve additions for that year. (3) The calculation of F&D and FD&A costs both includes or excludes, as labelled, the change in FDC required to bring proved undeveloped and developed reserves into production. The F&D or FD&A number is calculated by dividing the identified capital expenditures by applicable reserve additions including extensions, infills. Revisions, acquisitions and disposals, and economic factors, after or before changes in FDC costs (as labelled)."FD&A Cost", "F&D Cost", and "Recycle Ratio" do not have standardized meanings and therefore may not be comparable with the calculation of similar measures for other entities. See "Information Regarding Disclosure on Oil and Gas Reserves and Operational Information" in the Bonterra Energy Announces 2023 Reserves and Provides Operational Update news release. (4) Three-year average is calculated using three-year total capital costs and reserve additions on both a TP and TPP reserves on a weighted (5) average basis. "FD&A Cost", "F&D Cost", and "Recycle Ratio" do not have standardized meanings and therefore may not be comparable with the calculation of similar measures for other entities. See "Information Regarding Disclosure on Oil and Gas Reserves and Operational Information" in the Bonterra Energy Announces 2023 Reserves and Provides Operational Update news release. 9 | Page Commodity Prices Used in the Above Calculations of Reserves are as Follows Edmonton Par Price 40° API ($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/$Cdn) 92.91 95.04 96.07 97.99 99.95 101.94 103.98 106.06 108.18 110.35 2.20 3.37 4.05 4.13 4.21 4.30 4.38 4.47 4.56 4.65 47.69 48.83 49.36 50.35 51.35 52.38 53.43 54.50 55.58 56.70 96.79 98.75 100.71 102.72 104.78 106.87 109.01 111.19 113.41 115.67 0.0 2.0 2.0 2.0 2.0 2.0 2.0 2.0 2.0 2.0 0.75 0.75 0.76 0.76 0.76 0.76 0.76 0.76 0.76 0.76 Year FORECAST(1)(2) 2024 2025 2026 2027 2028 2029 2030 2031 2032 2033 (1) Crude oil, natural gas and liquid prices escalate at 2.0 percent thereafter. (2) The forecast of product prices is an average of independent reserve evaluators Sproule, GLJ Petroleum Consultants and McDaniels & Associates Consultants Ltd. Production Alberta Saskatchewan British Columbia Total Land Holdings Alberta Saskatchewan British Columbia Total Oil & NGLs (Bbl Per Day) 8,491 73 5 2023 Conventional Natural Gas (MCF Per Day) 33,615 32 167 Total (BOE Per Day) 14,093 78 33 8,569 33,814 14,204 2023 2022 Gross Acres Net Acres Gross Acres Net Acres 354,928 227,663 345,924 218,640 5,886 3,677 5,886 3,677 65,913 28,297 65,913 28,297 426,727 259,636 417,723 250,613 10 | Page Petroleum and Natural Gas Expenditures ($ 000s) Land Exploration and development costs Net petroleum and natural gas capital expenditures Drilling History 2023 1,222 125,255 126,477 2022 2,569 77,200 79,769 Crude oil Natural gas Total Success rate Crude oil Natural gas Total Success rate 2023 Development Exploratory Total Gross 52 - 52 100% Net 41.2 - 41.2 100% Gross Net Gross - 1 1 - 1.0 1.0 52 1 53 Net 41.2 1.0 42.2 100% 100% 100% 100% 2022 Development Exploratory Total Gross Net Gross Net Gross Net 34 25.8 - - 34 25.8 - - - - - - 34 25.8 - - 34 25.8 100% 100% - - 100% 100% 11 | Page YEAR END 2023 Management’s Discussion and Analysis & Financial Statements 12 | Page MANAGEMENT’S DISCUSSION AND ANALYSIS The following report dated March 7, 2024 is a review of the operations and current financial position for the year ended December 31, 2023 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 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 | Page ANNUAL COMPARISONS (1) 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 in Q2 2021, due to the recovery of crude oil forward benchmark prices from the impact of COVID-19 in 2020. 14 | Page As at and for the year ended($000s except $ per share)FINANCIALRevenue - realized oil and gas sales319,517384,197251,616Cash flow from operations140,183183,55396,103Per share - basic3.775.10 2.85 Per share - diluted3.764.92 2.76 Net earnings(1)44,94379,023 179,299 Per share - basic1.212.205.32Per share - diluted1.202.125.16Capital expenditures 126,478 79,769 67,282Total assets967,870919,682945,721Net debt140,400149,831267,179Shareholders' equity528,258479,839392,019OPERATIONSLight oil-bbl per day7,2097,0957,204-average price ($ per bbl)97.58113.93 74.53 NGLs-bbl per day1,3591,1411,013-average price ($ per bbl)48.8066.00 43.86 Conventional natural gas-MCF per day33,81431,02327,176-average price ($ per MCF)3.125.44 3.97 Total BOE per day14,20413,40712,747December 31, 2023December 31, 2022December 31, 2021 QUARTERLY COMPARISONS 15 | Page As at and for the periods ended($ 000s except $ per share)Q4Q3Q2Q1Financial Revenue - oil and gas sales 81,73984,90975,60677,263Cash flow from operations44,59637,71533,85424,018Per share - basic1.201.010.910.65Per share - diluted1.191.010.910.64Net earnings14,97313,4868,8447,640Per share - basic0.400.360.240.21Per share - diluted0.400.360.240.20Capital expenditures 14,009 36,130 16,116 60,223 Total assets967,870955,484962,021963,890Net debt140,400167,449168,344183,674Shareholders' equity528,258512,479498,449488,762OperationsLight oil (barrels per day)7,3067,1777,2827,068NGLs (barrels per day)1,6191,4101,2481,155Conventional natural gas (MCF per day)37,21434,24132,28631,448Total BOE per day15,12814,29413,91113,4642023As 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 day12,98913,03114,32813,2872022 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 $78.32 USD per barrel in Q4 2023, a decrease of five percent compared to Q4 2022. The pricing decline for WTI throughout 2023 has been driven by supply and demand volatility due to a variety of macroeconomic and geopolitical factors. These factors include, but are not limited to, persistent crude oil supply growth outside of OPEC+, and a slower than expected ramp up in demand from China as their economy struggles to regain growth rates similar to those realized prior to COVID-19 related restrictions. 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 ($5.16) USD per barrel in Q4 2023, a decrease of $3.55 USD per barrel from Q4 2022. Replenished inventories at the Cushing storage hub in Oklahoma and apportionment on downstream Canadian pipelines have been the largest contributing factor in moving the differential wider compared to recent quarters. The anticipated commissioning of the Trans Mountain Pipeline Expansion in 2024 is expected to increase Canada’s export capabilities and to have a positive effect on the movement and pricing of all Canadian barrels. AECO daily spot prices averaged $2.73 per mcf in Q4 2023, a decrease of 49 percent over Q4 2022. The decrease is mainly due to looser supply and demand balances and elevated storage levels that have been exacerbated by an unseasonably mild winter across much of North America and continued strong supply. The following chart shows the Company’s sensitivity to key commodity price variables. The sensitivity calculations are performed independently and show the effect of changing one variable while holding all other variables constant. 16 | Page Q4-2023Q3-2023Q2-2023Q1-2023Q4-2022Q3-2022Q2-2022Q1-2022Crude oil WTI (U.S.$/bbl)78.3282.2673.7876.1382.6491.56108.4194.29WTI to MSW Stream Index Differential (U.S.$/bbl)(1)(5.16)(1.83)(2.96)(2.86)(1.61)(2.05)(0.50)(2.96)Foreign exchange U.S.$ to Cdn$1.36191.34101.34311.35201.35781.30591.27661.2662Bonterra average realized oil price (Cdn$/bbl)97.01104.3293.2195.71105.59111.44126.97110.41Natural gas AECO (Cdn$/mcf)2.292.582.443.205.094.147.204.72Bonterra average realized gas price (Cdn$/mcf)2.733.063.013.785.364.736.764.80 (1) This analysis uses current royalty rates, annualized estimated average production of 14,000 BOE per day and no changes in working capital. (2) Based on annualized basic weighted average shares outstanding of 37,253,252. 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 in 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 March 1, 2024, Bonterra closed an acquisition to purchase producing petroleum and natural gas assets in northern Alberta, for cash consideration of approximately $24.1 million before estimated closing adjustments. The assets acquired currently produce 330 BOE per day and provide a portfolio of high-quality future drilling locations and reserves, establishing a new core operating area for the Company. The Company averaged 14,204 BOE per day of production in 2023, compared to 13,407 BOE per day in 2022, an increase of 797 BOE per day, or six percent. Quarter-over-quarter, Bonterra’s average production increased by 834 BOE per day, primarily driven by realizing a full quarter of production from 12 gross (11.8 net) operated wells that were drilled in Q3 2023. The Company is pleased to reiterate its previously announced 2024 annual guidance with average production between 13,800 to 14,200 BOE per day based on a fully funded 2024 capital expenditure budget between $90 million to $100 million. Bonterra invested capital expenditures of $126.5 million in 2023. Of the capital invested, $91.6 million was directed to the drilling of 41 gross (39.2 net) operated wells and completing, equipping, tying-in and placing on production 37 gross (35.6 net) operated wells. The remaining four gross (3.6 net) operated wells were placed on production in the first quarter of 2024. In addition to the drilling program, the Company allocated $3.7 million of the 2023 capital program to the expansion of a wholly owned gas plant to alleviate processing capacity limitations, with an additional $31.2 million directed to related infrastructure, recompletions, non- operated capital as well as the drilling of the Company’s first exploration Montney well. The Montney well was completed in the fourth quarter of 2023 and is currently in the early stages of flow back with an extended flow test planned in the second quarter of 2024 through third-party processing facilities. 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 2023, Bonterra successfully abandoned 84.1 net wells and 155 pipelines for a total length of 135.7 kilometers of pipe. By the end of 2024, Bonterra expects to have abandoned approximately 75 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 2024 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 $93.75 USD per bbl on 2,133 bbls per day. In addition, the Company has secured natural gas prices between $1.81 to $3.56 per GJ on 13,662 GJ per day to the end of Q3 2024. 17 | Page Annualized sensitivity analysis on before tax cash flow, as estimated for 2024(1)Impact on cash flowChange ($)$000s$ per share(2)Realized crude oil price ($/bbl)1.002,1940.06Realized natural gas price ($/mcf)0.101,1910.03U.S.$ to Canadian $ exchange rate0.011,6230.04 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. 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 2023, the Company drilled 41 gross (39.2 net) operated wells and completed, tied in, and placed on production 37 gross (35.6 net) operated wells. The remaining four wells are expected to be completed and placed on production early in the first quarter of 2024. In addition to the 41 gross operated development wells, Bonterra drilled an exploration Montney well which the Company completed in Q4 2023 and plans to flow test through third party processing facilities in the second quarter of 2024. Production The Company averaged 14,204 BOE per day of production in 2023, compared to 13,407 BOE per day in 2022, an increase of 797 BOE per day or six percent. The increase was primarily due to Bonterra’s successful capital program, which was partially offset by 333 BOE per day of shut-in volumes in Q2 2023 as a result of the wildfires that occurred in central Alberta during the period. Quarter-over-quarter, Bonterra increased its production by 834 BOE per day, primarily due to a full quarter of production from 12 gross (11.8 net) operated wells that were drilled in Q3 2023. 18 | Page Gross(1)Net(2)Gross(1)Net(2)Gross(1)Net(2)Gross(1)Net(2)Gross(1)Net(2)Crude oil horizontal-operated 3 2.8 12 11.8 2 2.04139.22524.7Crude oil horizontal-non-operated 5 1.0 - - - - 11 2.0 9 1.1 Total 8 3.8 1211.822.05241.23425.8Success rate100%100%100%100%100% Three months endedYear endedDecember 31, 2023September 30, 2023December 31, 2022December 31, 2023December 31, 2022December 31, 2023September 30, 2023December 31, 2022December 31, 2023December 31, 2022Crude oil (barrels per day)7,306 7,177 6,764 7,209 7,095 NGLs (barrels per day)1,619 1,410 1,209 1,359 1,141 Natural gas (MCF per day)37,214 34,241 30,101 33,814 31,023 Average BOE per day15,128 14,294 12,989 14,204 13,407 Three months endedYear ended Cash Netback Cash netbacks decreased in 2023 on a BOE basis compared to 2022 primarily due to lower per BOE realized commodity prices, and increased current income tax costs. This was partially offset by gains on realized risk management contracts, and lower production and royalty costs. Oil and Gas Sales Revenue from oil and gas sales in 2023 decreased by $64.7 million, or 17 percent, compared to 2022. This decrease was primarily driven by a 22 percent reduction in Bonterra’s average realized commodity prices over the same period. Quarter-over-quarter, revenue from oil and gas sales decreased due to lower realized crude oil and natural gas prices, partially offset by an increase in production. Bonterra’s product split on a revenue basis was weighted approximately 88 percent to crude oil and NGLs during 2023. 19 | Page $ per BOEDecember 31, 2023September 30, 2023December 31, 2022December 31, 2023December 31, 2022Production volumes (BOE)1,391,7541,315,0791,195,0305,184,4554,893,560Gross production revenue58.73 64.57 72.93 61.63 78.51 Realized gain (loss) on risk management contracts0.020.52(1.04)0.35(3.45)Royalties(9.53)(8.10)(12.79)(8.95)(12.68)Production costs(13.37)(16.61)(16.11)(16.02)(17.45)Field netback 35.8540.3842.99 37.01 44.93 General and administrative(3.72)(2.30)(1.78)(2.79)(2.43)Interest and other (3.09)(3.64)(3.19)(3.65)(2.98)Current income tax0.02(1.96)(3.59)(2.15)(1.60)Cash netback 29.06 32.48 34.43 28.42 37.92 Three months endedYear endedDecember 31, 2023September 30, 2023December 31, 2022December 31, 2023December 31, 2022Revenue - oil and gas sales ($ 000s)Light oil65,20968,88365,704256,745295,046NGL7,1686,3836,60424,21227,497Conventional natural gas9,3629,64314,84638,56061,65481,73984,90987,154319,517384,197Average realized prices:Light oil ($ per barrel)97.01104.32105.5997.58113.93NGL ($ per barrel)48.1249.1959.3848.8066.00Conventional natural gas ($ per MCF)2.733.065.363.125.44Average ($ per BOE)58.7364.5772.9361.6378.51Average BOE per day15,12814,29412,98914,20413,407 Three months endedYear ended 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 2023 decreased by $3.73 per BOE compared to 2022 primarily due to a decrease in commodity prices. Quarter-over-quarter, royalties increased on a BOE basis due to a 16 percent increase in the Alberta Light Oil Crown Reference price used to calculate Alberta Oil Crown royalties. Production Costs Production costs for 2023 decreased compared to 2022, primarily due to less well and facility maintenance as the Company replaced old infrastructure with new upgrades that require less maintenance. The Company also incurred less service rig costs due to fewer wells being worked over in Q4 2023. This was partially offset by general cost increases due to inflation and an increase in government levies. Quarter-over-quarter, production costs decreased on a BOE basis due to less service rig costs and a decrease in power costs. Other Income Deferred consideration relates to a deferred gain on the sale of a two percent overriding royalty interest, which is recognized into revenue using the same unit-of-production method as the encumbered property, plant, and equipment assets. 20 | Page ($ 000s)December 31, 2023September 30, 2023December 31, 2022December 31, 2023December 31, 2022Crown royalties9,4487,38211,23932,95344,842Freehold, gross overriding and other royalties3,8123,2674,04213,45117,233Total royalties13,26010,64915,28146,40462,075Crown royalties - percentage of revenue11.68.712.910.311.7Freehold, gross overriding and other royalties - percentage of revenue4.73.84.64.24.5Royalties - percentage of revenue16.312.517.514.516.2Royalties $ per BOE9.538.1012.798.9512.68 Three months endedYear ended($ 000s except $ per BOE)December 31, 2023September 30, 2023December 31, 2022December 31, 2023December 31, 2022Production costs18,60321,84419,25183,06485,385$ per BOE13.3716.6116.1116.0217.45 Three months endedYear ended($ 000s)December 31, 2023September 30, 2023December 31, 2022December 31, 2023December 31, 2022Investment income 120 104 115 440 221Administrative income 120 74207 321 706Gain on sale of property - 17 - 17 - Government grant in-kind - - 1,272 782 3,675 Deferred consideration 274 232 293 1,009 1,158 Realized gain (loss) on risk management contracts 28 680 (1,245) 1,801 (16,878)Unrealized gain (loss) on risk management contracts 4,617 (3,266)(246) 1,559 5,365 5,159 (2,159) 396 5,929 (5,753) Three months endedYear ended The market value and carrying value of the investments held by the Company on December 31, 2023 totaled $1,634,000 (December 31, 2022 - $2,028,000). There were no dispositions during the period ended December 31, 2023 or December 31, 2022. 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, which concluded in Q2 2023. The Company derecognized approximately $0.8 million of asset retirement obligations as an in-kind grant in 2023 (December 31, 2022 - $3.7 million). The benefit of the in-kind grant is recognized through other income. To minimize commodity price risk on crude oil and natural gas sales, Bonterra has entered into financial derivatives. The financial derivatives outstanding are primarily for the period from January 1, 2024 to December 31, 2024 and are for a total of 704,200 barrels of light crude oil (approximately 1,924 barrels of oil per day for the next twelve months) at fixed WTI prices ranging from $50.00 USD to $93.75 USD per barrel. In addition, the Company has entered into financial derivatives on natural gas prices between $1.81 and $2.04 on 3,360 GJ per day for the period from January 1, 2024 to December 31, 2024. 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 $1.7 million for 2023 compared to 2022. The increase is primarily due to a bonus accrual and severance paid in fourth quarter of 2023. Office and administrative expense increased in 2023 compared to the same period in 2022 primarily due to an increase in continuous disclosure costs and an increase in the provision for the allowance for doubtful accounts. Finance Costs 21 | Page ($ 000s except $ per BOE)December 31, 2023September 30, 2023December 31, 2022December 31, 2023December 31, 2022Employee compensation3,9371,8291,1879,2127,489Office and administrative1,2341,2019425,2454,418Total G&A5,1713,0302,12914,45711,907$ per BOE3.722.301.782.792.43 Three months endedYear ended($ 000s except $ per BOE)December 31, 2023September 30, 2023December 31, 2022December 31, 2023December 31, 2022Interest on bank debt and subordinated debt 641 8671,6123,3598,974Subordinated debentures 1,327 1,328 1,327 5,310 5,310 Subordinated term debt 2,596 2,748 1,193 11,046 1,193 Interest expense4,5644,9434,13219,71515,477$ per BOE3.283.763.463.803.16Accretion of decommissioning liabilities9439569703,7703,567Accretion on subordinated debentures790 706 681 2,816 2,411 Accretion on subordinated term debt496 522 192 2,136 192 Total finance costs6,7937,1275,97528,43721,647 Three months endedYear ended Interest on bank debt was lower in 2023 compared to 2022 due to a decrease of approximately 79 percent in average bank debt outstanding. 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 for the year ended December 31, 2023 was $nil (December 31, 2022 - $2.6 million). The BDC Loan was fully repaid on November 25, 2022. Subordinated unsecured term debt on December 31, 2023 was $76.0 million (December 31, 2022 - $95 million) (the “Subordinated Term Debt”). 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, 2023, the effective interest rate was determined to be 16.4 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 10 of the December 31, 2023, 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, 2023, 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 9 of the December 31, 2023, 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 $580,000. 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, 2023, the Company has an unamortized expense of $3,207,000, of which $2,132,000 will be recognized in 2024; $877,000 in 2025 and $198,000 thereafter. For more information about options issued and outstanding, refer to Note 13 of the December 31, 2023, audited annual financial statements. Depletion and Depreciation, Exploration and Evaluation (“E&E”) and Impairment 22 | Page ($ 000s)December 31, 2023September 30, 2023December 31, 2022December 31, 2023December 31, 2022Share-option compensation9464716323,2281,910 Three months endedYear ended($ 000s)December 31, 2023September 30, 2023December 31, 2022December 31, 2023December 31, 2022Depletion and depreciation 24,071 21,98421,92990,47990,951 Three months endedYear ended The provision for depletion and depreciation (“D&D”) remained relatively the same as the increase in production was offset by an increase in proved plus probable developed reserves. Taxes The Company recorded a total income tax expense of $14.4 million in 2023 (2022 – $25.5 million). The income tax expense decrease compared to the prior period is due to reduced earnings before income taxes. The 2023 current income tax portion of the provision of $11.1 million, is comprised of $3.8 million payable to the province of Alberta and the remainder to the Federal government. The Company used $5.3 million of investment tax credits to offset the cash owing for Federal income tax. For additional information regarding income taxes, see Note 12 of the December 31, 2023 audited annual financial statements. Net Earnings Net earnings for 2023 decreased by $34.1 million compared to 2022. The decrease in net earnings was primarily attributed to lower commodity prices realized and increased finance costs during the period. This was partially offset by a gain on risk management contracts in the current year compared to a loss on risk management contracts in the prior year and a decrease in the tax provision. Other Comprehensive Income Other comprehensive income for 2023 consists of an unrealized loss before tax on investments of $394,000 relating to a decrease in the investments’ fair value (December 31, 2022 – $1,137,000 gain). 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, net of tax. Cash Flow From Operations In 2023, cash flow from operations decreased by $43.4 million compared to 2022. This was primarily due to a decrease in realized commodity prices. Quarter-over-quarter, cash flow from operations increased primarily due to an increase in non-cash working capital. 23 | Page ($ 000s except $ per share)December 31, 2023September 30, 2023December 31, 2022December 31, 2023December 31, 2022Net earnings14,97313,48617,26444,94379,023$ net earnings per share - basic0.400.360.471.212.20$ net earnings per share - diluted0.400.360.461.202.12 Three months endedYear ended($ 000s except $ per share)December 31, 2023September 30, 2023December 31, 2022December 31, 2023December 31, 2022Cash flow from operations44,59637,71535,494140,183183,553$ per share - basic1.201.010.973.775.10$ per share - diluted1.191.010.953.764.92 Three months endedYear ended Liquidity and Capital Resources Net Debt to EBITDA 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 EBITDA ratio as of December 31, 2023 was 0.8 (versus 0.7 at December 31, 2022). 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 increase in Bonterra’s net debt to EBITDA flow ratio is primarily due to a decrease in EBITDA from lower commodity prices. The net debt to EBITDA ratio is expected to improve in subsequent quarters due to the Company’s focus on debt reduction paired with 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 nine months. For more information about net debt to EBITDA, please see Note 17 of the December 31, 2023 audited annual financial statements. Working Capital Deficiency and Net Debt Net debt is a combination of bank debt, subordinated debentures, subordinated term debt and working capital. The Company’s Bank Facility has a maturity date of April 30, 2025 and is recorded as a long-term liability at December 31, 2023 and December 31, 2022. Included in working capital deficiency is $19.0 million of principal payments due in the next twelve months 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 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 to meet its future liabilities. Net debt at December 31, 2023 decreased by $9.4 million compared to December 31, 2022, primarily due to Bonterra’s continued focus on balance sheet strengthening, which was partially offset by the Company’s front loaded 2023 capital program. Working capital is calculated as current assets less current liabilities. Financial Risk Management Bonterra is exposed to market risk for the oil and gas produced by the Company. External factors beyond the Company’s control may affect the marketability of oil and gas produced. Oil prices are affected by worldwide supply and demand fundamentals and access to market, while natural gas prices are largely affected by North American supply and demand fundamentals. To manage commodity risk, the Company executed physical delivery sales contracts which are considered normal sales contracts and are not recorded at fair value in the financial statements, and also executed risk management contracts which are not considered normal sales contracts and are recorded at fair value. The Company has contracts in place on approximately 30 percent of its estimated oil and gas production to the end of Q3 2024. The Company relies on its cash flow, access to equity markets and bank financing to support its operations and capital program. Bonterra uses these futures contracts to hedge its exposure to the potential adverse impact of commodity 24 | Page ($ 000s)December 31, 2023December 31, 2022Working capital deficiency19,97512,578Bank debt 14,822 17,601Subordinated debentures 52,585 49,770Subordinated term debt (long-term portion) 53,018 69,882 Net debt140,400149,831 price volatility and provide a measure of stability to the Company’s capital development program. For more information on physical delivery and risk management contracts in place, see Note 17 of the December 31, 2023 audited annual financial statements. Capital Expenditures During 2023, the Company incurred capital expenditures of $126.5 million (December 31, 2022 - $79.8 million). Of the total capital invested, $91.6 million was directed to the drilling of 41 gross (39.2 net) operated wells and the completion, equip and tie-in of gross 37 (35.6 net) operated wells. The remaining four gross (3.6 net) operated wells were placed on production in the first quarter of 2024. In addition to the development drilling program, Bonterra also directed $3.7 million to expanding a wholly owned gas plant, with an additional $31.2 million spent primarily on related infrastructure, recompletions, non-operated capital programs and the drilling as well as completion of the Company’s first exploration Montney well. The Montney well was completed in the fourth quarter and is currently in the early stages of flow back with an extended flow test planned in the second quarter of 2024 through third party processing facilities. Decommissioning Liabilities Including the Alberta SRP funding that was received in the first quarter, the Company spent $9.1 million on decommissioning activities during the year ended December 31, 2023. Since the beginning of 2020, Bonterra has successfully abandoned 573.5 net wells, 423 pipelines and six facilities. Bank Debt and Subordinated Term Debt Bank debt represents the outstanding amounts drawn on the Company’s Bank Facility. As at December 31, 2023, 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, 2023 was $14.8 million (December 31, 2022 - $17.6 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. As at December 31, 2023, the terms of the total revolving Bank Facility provided that the loan facility was revolving to April 30, 2024, with a maturity date of April 30, 2025, with no set terms of repayment on the credit facility. The terms of the revolving Bank Facility were confirmed on October 25, 2023. The Company is subject to the next semi- annual determination by April 30, 2024. As at December 31, 2023, Bonterra classified its bank debt as a long-term liability and was in compliance with all financial covenants on its total Bank Facility. 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, 2023 (December 31, 2022 - $2.1 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 principal balance is to be paid. 25 | Page The amount drawn under the Subordinated Term Debt at December 31, 2023 was $76.0 million (December 31, 2022 - $95.0 million). Based on the calculated fair value of the debt as at December 31, 2023, the effective interest rate was determined to be 16.4 percent, by discounting future payments of interest and principal with the residual value allocated to issue costs. The value of the debt will accrete up to the principal balance at maturity. Security for the Subordinated Term Debt consists of various floating demand debentures totaling $150 million (December 31, 2022 - $150 million) over all of the Company’s assets and a general security agreement with second 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 trailing twelve months 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 as at December 31 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, 2023, 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 10, respectively, of the December 31, 2023 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. A total of 2,753,000 Warrants are outstanding as at December 31, 2023, entitling the holder to purchase one Common Share of Bonterra for each Warrant at a price of $7.75, until October 20, 2025. The Company provides a stock option plan for its directors, officers and employees. Under the plan, the Company may grant options for up to 3,725,325 (December 31, 2022 – 3,691,289) common shares. The 26 | Page Issued and fully paid - common sharesNumberAmount($ 000s)NumberAmount($ 000s)Balance, beginning of year36,912,892781,67935,000,952772,781Issued pursuant to the Company's share option plan340,360596 1,360,940 1,612 Transfer from contributed surplus to share capital9101,804Issued pursuant to the exercise of warrants - - 551,000 4,270 Transfer from warrants to share capital - 1,212 Balance, end of year37,253,252783,18536,912,892781,679December 31, 2023December 31, 2022 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 13 of the December 31, 2023, audited annual financial statements. 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. Contractual Obligations and Commitments At December 31, 2023, the Company has the following contractual obligations and commitments: (1) Principal amount. 27 | Page For the periods ended($ 000s except $ per share)Q4Q3Q2Q1Revenue - oil and gas sales81,73984,90975,60677,263Cash flow from operations44,59637,71533,85424,018Net earnings14,97313,4868,8447,640Per share - basic0.400.360.240.21Per share - diluted0.400.360.240.202023For the periods ended($ 000s except $ per share)Q4Q3Q2Q1Revenue - oil and gas sales87,15488,827116,67491,542Cash flow from operations35,49448,81058,30740,942Net earnings17,26417,69633,54410,519Per share - basic0.470.490.930.30Per share - diluted0.460.470.880.292022($ 000s)Less than 1 yearOver 1 year to 3 yearsOver 3 years to 5 yearsOver 5 years to 7 yearsTotalAccounts payable and accrued liabilities37,226 - - - 37,226 Bank debt- 14,822 - - 14,822 Subordinated debentures(1)- 59,000 - - 59,000 Subordinated term debt(1)19,000 57,000 - - 76,000 Future interest14,063 14,297 - - 28,360 Firm service commitments1,140 1,824 909 189 4,062 Office lease commitments472 961 - - 1,433 Total71,901 147,904 909 189 220,903 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, 2023 annual audited financial statements. 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; environmental and safety risks; failure to realize benefits of acquisitions and dispositions; reliance on third party gathering, processing and pipeline systems; changes to applicable royalty regimes and environmental legislation and regulations; cyber security risks; and reliance on key personnel. The Company mitigates its risk related to producing hydrocarbons through the utilization of hedging a portion of product sales, current technology and information systems. In addition, Bonterra strives to operate the majority of its properties, thereby maintaining operational control where possible. 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, 2023, which can be accessed on its website www.bonterraenergy.com or on SEDAR at www.sedarplus.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 or damage to production facilities and equipment. 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 28 | Page events may significantly affect the scope and timing of climate change measures that are ultimately put in 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, 2023, which can be accessed on its website at www.bonterraenergy.com or on SEDAR at www.sedarplus.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; earnings sensitivity to interest rates; 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. 29 | Page 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, 2023. 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, 2023. 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. 30 | Page 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 7, 2024 Robb D. Thompson Chief Financial Officer March 7, 2024 31 | Page 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, 2023 and 2022, 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, 2023 and 2022, 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, 2023. 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. 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 32 | Page 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. 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 33 | Page 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. 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 7, 2024 34 | Page STATEMENT OF FINANCIAL POSITION See accompanying notes to these financial statements. On behalf of the Board: “Signed Patrick G. Oliver” “Signed Rodger A. Tourigny” Patrick G. Oliver Director Rodger A. Tourigny Director 35 | Page As at($ 000s)NoteAssetsCurrentAccounts receivable25,364 27,326 Crude oil inventory893 1,106 Prepaid expenses6,912 7,208 Investment tax credit receivable- 5,761 Risk management contract172,357 798 Investments 1,634 2,028 37,160 44,227 Exploration and evaluation assets55,785 4,563 Property, plant and equipment6924,925 870,892 967,870 919,682 LiabilitiesCurrentAccounts payable and accrued liabilities737,226 35,573 Subordinated term debt1019,000 20,193 Deferred consideration909 1,039 57,135 56,805 Bank debt814,822 17,601 Subordinated debentures952,585 49,770 Subordinated term debt1053,018 69,882 Deferred consideration8,170 9,051 Decommissioning liabilities11123,108 109,215 Deferred tax liability12 130,774 127,519 439,612 439,843 Shareholders' equityShare capital13783,185 781,679 Contributed surplus34,023 31,705 Warrants136,053 6,053 Accumulated other comprehensive income436 784 Deficit(295,439) (340,382) 528,258 479,839 967,870 919,682 Commitments and contingencies18Subsequent events17, 20December 31,2023December 31,2022 STATEMENT OF COMPREHENSIVE INCOME See accompanying notes to these financial statements. 36 | Page For the years ended December 31($ 000s, except $ per share)Note20232022RevenueOil and gas sales, net of royalties14273,113 322,122 Other income151,560 4,602 Deferred consideration1,009 1,158 Gain (Loss) on risk management contracts173,360 (11,513) 279,042 316,369 ExpensesProduction83,064 85,385 Office and administration5,245 4,418 Employee compensation9,212 7,489 Finance costs1628,437 21,647 Share-option compensation3,228 1,910 Depletion and depreciation690,479 90,951 219,665 211,800 Earnings before income taxes59,377 104,569 Taxes Current income tax expense 1211,134 7,819 Deferred income tax expense123,300 17,727 14,434 25,546 Net earnings for the year44,943 79,023 Other comprehensive income (loss)Unrealized (loss) gain on investments(394) 1,137 Deferred taxes on unrealized loss (gain) on investments46 (132) Other comprehensive income (loss) for the year(348) 1,005 Total comprehensive income for the year44,595 80,028 Net earnings per share - basic131.21 2.20 Net earnings per share - diluted131.20 2.12 Comprehensive income per share - basic131.20 2.22 Comprehensive income per share - diluted131.19 2.15 STATEMENT OF CASH FLOW See accompanying notes to these financial statements. 37 | Page For the years ended December 31 ($ 000s)Note20232022Operating activitiesNet earnings44,943 79,023 Items not affecting cashDeferred income tax expense3,300 17,727 Share-option compensation3,228 1,910 Investment income(440) (221) Finance costs1628,437 21,647 Unrealized gain on risk management contracts17(1,559) (5,365) Deferred consideration(1,009) (1,158) Depletion and depreciation690,479 90,951 Gain on sale of property(17) - Government grant in-kind19(782) (3,675) Decommissioning expenditures(8,291) (5,930) Interest paid16(19,715) (14,284) Changes in non-cash working capital accounts161,609 2,928 Cash provided by operating activities140,183 183,553 Financing activitiesDecrease of bank debt(2,779) (145,344) Subordinated debt - (47,268) Subordinated term debt10(20,193) 88,690 Proceeds from warrants exercised13- 4,270 Stock option proceeds596 1,612 Cash used in financing activities(22,376) (98,040) Investing activitiesInvestment income received440 221 Exploration and evaluation expenditures(1,222) (2,569) Property, plant and equipment expenditures6(125,256) (77,200) Proceeds on sale of property28 120 Changes in non-cash working capital accounts168,203 (6,085) Cash used in investing activities(117,807) (85,513) Net change in cash in the year- - Cash, beginning of year- - Cash, end of year- - The following are included in cash flow from operating activities:Income taxes paid9,625 - 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. 38 | Page For the years ended($ 000's, except number of shares outstanding)Numbers of common shares outstanding (Note 13)Share capital (Note 13)Contributed surplus (1)WarrantsAccumulated other comprehensive income (loss)(2)DeficitTotal shareholders' equityJanuary 1, 202235,000,952 772,781 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 Share-option compensation3,228 3,228 Exercise of options340,360 596 596 Transfer to share capital on exercise of options910 (910) - Comprehensive income (loss)(348) 44,943 44,595 December 31, 202337,253,252 783,185 34,023 6,053 436 (295,439) 528,258 NOTES TO THE FINANCIAL STATEMENTS As at and for the years ended December 31, 2023 and December 31, 2022 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 7, 2024. 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) Material 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. e) Adopted Accounting Pronouncements Amendments to IAS 1 and IAS 8 - Accounting Policies and Accounting Estimates On January 1, 2023, the Company adopted the narrow scope amendments 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. There was no material impact to Bonterra’s financial statements. 39 | Page Amendments to IAS 12 – Deferred taxes related to assets and liabilities arising from a single transaction On January 1, 2023, the Company adopted 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. There was no 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, 2024, 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 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. MATERIAL 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 40 | Page 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. 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. 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 41 | Page 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. 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 42 | Page 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 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 43 | Page 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. 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. 44 | Page 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. 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. 45 | Page 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. 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. 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: 46 | Page 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, 2023. 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. 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. 47 | Page 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 48 | Page ($ 000s)Cost and carrying amountBalance at January 1, 2022 1,994 Additions 2,569 Balance at December 31, 2022 4,563 Additions 1,222 Balance at December 31, 2023 5,785 6. PROPERTY, PLANT AND EQUIPMENT Impairment There were no indicators of impairment losses or reversals identified for the year ended December 31, 2023 and December 31, 2022. 7. ACCOUNTS PAYABLE AND ACCRUED LIABILITIES 49 | Page Cost($ 000s)Oil and gas propertiesProduction facilitiesFurniture fixtures & other equipmentTotal property plant & equipmentBalance at January 1, 20221,508,050 390,725 2,310 1,901,085 Additions52,589 24,458 153 77,200 Disposal(120) - (2) (122) Adjustment to decommissioning liabilities(18,125) - - (18,125) Balance at December 31, 20221,542,394 415,183 2,461 1,960,038 Additions93,907 30,948 401 125,256 Disposal- - (51) (51) Adjustment to decommissioning liabilities19,212 - - 19,212 Balance at December 31, 20231,655,513 446,131 2,811 2,104,455 Accumulated depletion and depreciation($ 000s)Oil and gas propertiesProduction facilitiesFurniture fixtures & other equipmentTotal property plant & equipmentBalance at January 1, 2022(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) Depletion and depreciation(72,615) (17,728) (136) (90,479) Disposal and other54 - 41 95 Balance at December 31, 2023(962,387) (215,046) (2,097) (1,179,530) Carrying amounts as at:($ 000s)December 31, 2022652,568 217,865 459 870,892 December 31, 2023693,126 231,085 714 924,925 ($ 000s)December 31, 2023December 31, 2022Accounts payable30,625 27,701 Accrued liabilities6,601 7,872 37,226 35,573 8. BANK DEBT As at December 31, 2023, the Company had a total Bank Facility of $110,000,000 (December 31, 2022 - $110,000,000), 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, 2023 was $14,822,000 (December 31, 2022 - $17,601,000). 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. As at December 31, 2023, the terms of the total revolving Bank Facility provided that the loan facility was revolving to April 30, 2024, with a maturity date of April 30, 2025, with no set terms of repayment on the credit facility. The terms of the revolving Bank Facility were confirmed on October 25, 2023. The Company is subject to the next semi-annual determination by April 30, 2024. The amount available for borrowing under the Bank Facility is reduced by outstanding letters of credit. Letters of credit totaling $2,130,000 were issued as at December 31, 2023 (December 31, 2022 - $2,095,000). Security for the Bank Facility consists of various floating demand debentures totaling $750,000,000 (December 31, 2022 - $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 trailing twelve months 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 as at December 31, 2023 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, 2023, Bonterra was in compliance with all financial covenants on its Bank Facility. 9. SUBORDINATED DEBENTURES As at December 31, 2023 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 2023 was $5,310,000 (December 31, 2022 - $5,310,000). 50 | Page 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 13. 10. SUBORDINATED TERM DEBT As at December 31, 2023 the Company has a second lien, non-revolving subordinated term debt facility (“Subordinated Term Debt”). The amount drawn under the Subordinated Term Debt at December 31, 2023 was $76,000,000 (December 31, 2022 - $95,000,000). 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. Based on the calculated fair value of the Subordinated Term Debt as at December 31, 2023, the effective interest rate was determined to be 16.4 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 paid in 2023 was $11,046,000 (December 31, 2022 - $Nil). Security for the Subordinated Term Debt consists of various floating demand debentures totaling $150,000,000 (December 31, 2022 - $150,000,000) over all the Company’s assets and a general security agreement with second ranking over all personal and real property. As at December 31, 2023, Bonterra was in compliance with all financial covenants on its second lien Subordinated Term Debt facility (as described in Note 8). 11. DECOMMISSIONING LIABILITIES At December 31, 2023, the estimated total uninflated and undiscounted amount required to settle the decommissioning liabilities was $176,425,000 (December 31, 2022- $178,183,000). The provision has been calculated assuming a 2.0 percent inflation rate (December 31, 2022 – 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 2.87 percent (December 31, 2022 – 3.27 percent). (1) The change is estimate was primarily due to an increase in estimated costs less a decrease in the discount rate. (2) Included in liabilities settled is $2,455,000 of abandonment deposits (December 31, 2022 - $2,437,000). 51 | Page ($ 000s)December 31, 2023December 31, 2022Decommissioning liabilities, January 1109,215 135,815 Changes in estimate(1)19,212 (18,125) Liabilities settled during the year(2)(8,307) (8,367) Government grant in-kind (Note 19)(782) (3,675) Accretion on decommissioning liabilities3,770 3,567 Decommissioning liabilities, end of year123,108 109,215 12. INCOME TAXES Income tax expense varies from the amounts that would be computed by applying Canadian federal and provincial tax rates as follows: Earnings before taxes Combined federal and provincial income tax rates Income tax provision calculated using statutory tax rates Increase (decrease) in taxes resulting from: Share-option compensation Renouncement of tax pool on flow through share issuance Change in unrecorded benefits of tax pools Change in estimates and other December 31, December 31, 2022 104,569 23.03% 24,082 59,377 23.02% 13,666 743 - 45 (20) 14,434 440 1,257 (205) (28) 25,546 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 $nil (December 31, 2022 - $5,761,000) of investment tax credits. The Company has $64,725,000 (December 31, 2022 - $64,725,000) of capital losses carried forward which can only be claimed against taxable capital gains. 52 | Page ($ 000s)December 31, 2023December 31, 2022Deferred tax asset (liability) related to:Investments(75) (120) (152,653) (145,019) Investment tax credits(1,216) (2,040) Decommissioning liabilities28,899 25,700 Share issue costs1,141 1,566 Financial derivative(543) (184) Subordinated debenture(1,476) (2,125) Subordinated term debt(916) (1,408) Corporate capital tax losses carried forward7,448 7,449 Unrecorded benefits of capital tax losses carried forward(7,374) (7,329) Unrecorded benefits of successored resource related pools(4,009) (4,009) Deferred tax liability(130,774) (127,519) Exploration and evaluation assets and property, plant and equipment($ 000s) 2023 ($ 000s)Rate of Utilization (%)AmountUndepreciated capital costs7-10065,792 Share issue and financing costs204,957 Canadian oil and gas property expenditures1060,998 Canadian development expenditures30121,141 Canadian exploration expenditures1008,587 261,475 13. 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 periods ended, are as follows: (1) The Company did not include 5,496,849 share-options and warrants (December 31, 2022 – 1,756,844) in the dilutive effect of share- options and warrants calculations as these were anti-dilutive. Warrants A summary of the status of warrants issued by the Company as of December 31, 2023 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 $7.75, until October 20, 2025. Options The Company provides an equity settled option plan for its directors, officers, and employees. Under the plan, the Company may grant options for up to 3,725,325 (December 31, 2022 – 3,691,289 common shares). The exercise price of each option granted cannot be lower than the market price of the common shares on the date of grant and the option’s maximum term is five years. 53 | Page Issued and fully paid - common sharesNumberAmount ($ 000s)NumberAmount ($ 000s)Balance, beginning of year36,912,892 781,679 35,000,952 772,781 Issued pursuant to the Company's share option plan340,360 596 1,360,940 1,612 Transfer from contributed surplus to share capital910 1,804 Issued pursuant to the exercise of warrants551,000 4,270 Transfer from warrants to share capital1,212 Balance, end of year37,253,252 783,185 36,912,892 781,679 December 31, 2023December 31, 202220232022Basic shares outstanding 37,197,337 35,968,921 Dilutive effect of share options and warrants(1)134,317 1,314,945 Diluted shares outstanding37,331,654 37,283,866 Number of warrantsWeighted exercise priceAt January 1, 2022 3,304,000 $7.75Warrants exercised (551,000)7.75As at December 31, 2022 and December 31, 2023 2,753,000 $7.75 A summary of the status of the Company’s stock options as of December 31, 2023 and changes during the period are presented below: (1) 247,000 options (December 31, 2022 - 720,250) were exercised under the cashless option method, which resulted in 140,610 (December 31, 2022 – 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. The following table summarizes information about options outstanding and exercisable as at December 31, 2023: 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 2023, the Company granted 1,171,000 options with an estimated fair value of $2,084,000 or $1.78 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. 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. 54 | Page Number of optionsWeighted average exercise priceAt January 1, 2022 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, 2022 2,751,750 $6.86Options granted 1,171,000 5.47Options exercised(1) (446,750)2.92Options forfeited (171,000)7.81Options expired (45,000)5.18At December 31, 20233,260,000 $6.87Range of exercise pricesNumber outstandingWeighted-average remaining contractual lifeWeighted-average exercise priceNumber exercisableWeighted-average exercise price$ 1.00 - $ 5.00198,500 0.8 years $ 3.38 125,000 $ 2.83 5.01 - 10.003,016,500 4.0 years7.02615,807 8.0010.01 - 15.0045,000 1.4 years12.3215,000 12.32$ 1.00 - $ 15.003,260,000 3.8 years $ 6.87 755,807 $ 7.23 Options outstandingOptions exercisableDecember 31, 2023December 31, 2022Weighted-average risk free interest rate (%)(1)3.852.59Weighted-average expected life (years)2.02.0Weighted-average volatility (%)(2)55.7875.06Forfeiture rate (%)6.407.20Weighted average dividend yield (%)0.371.52 14. OIL AND GAS SALES, NET OF ROYALTIES 15. OTHER INCOME 55 | Page ($ 000s)December 31, 2023December 31, 2022Oil and gas salesCrude oil 256,745 295,046 Natural gas liquids 24,212 27,497 Natural gas 38,560 61,654 319,517 384,197 Less royalties:Crown (32,953) (44,842)Freehold, gross overriding royalties and other (13,451) (17,233) (46,404) (62,075)Oil and gas sales, net of royalties 273,113 322,122 ($ 000s)December 31, 2023December 31, 2022Investment income 440 221 Administrative income 321 706 Gain on sale of property and equipment 17 - Government grant in-kind (Note 19) 782 3,675 Other income 1,560 4,602 16. SUPPLEMENTAL CASH FLOW INFORMATION 17. 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 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. 56 | Page ($ 000s)December 31, 2023Decmber 31, 2022Change in non-cash working capital:Accounts receivable 1,962 (3,111)Crude oil inventory 159 (158)Prepaid expenses 296 (1,286)Investment tax credit receivable 5,761 3,100 Abandonment deposit (19) (2,437)Accounts payable and accrued liabilities 1,653 735 9,812 (3,157)Changes related to:Operating activities 1,609 2,928 Investing activities 8,203 (6,085) 9,812 (3,157)Finance expense ($ 000s)December 31, 2023Decmber 31, 2022Interest expense:Bank and subordinated debt3,359 8,974 Subordinated debenture5,310 5,310 Subordinated term debt11,046 1,193 19,715 15,477 Accretion:Decommissioning liabilities3,770 3,567 Subordinated debentures2,816 2,411 Subordinated term debt2,136 192 8,722 6,170 Total finance costs28,437 21,647 Interest expense19,715 15,477 Interest accrued- (1,193) Interest paid19,715 14,284 The Company’s overall risk management program seeks to mitigate these risks and reduce the volatility on Bonterra’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 of Bonterra’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 Bonterra 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 Bonterra 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 $25,364,000 accounts receivable balance at December 31, 2023 (December 31, 2022 - $27,326,000) over 83 percent (December 31, 2022 – 93 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, 2023, 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, 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. 57 | Page As at December 31, 2023, approximately $591,000 or 2.3 percent of the Company’s total accounts receivable are aged over 90 days and considered past due (December 31, 2022 - $262,000 or 1.1 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, 2023 is $1,878,000 (December 31, 2022 - $1,248,000) 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 EBITDA. This ratio is calculated using each quarter end net debt divided by the preceding twelve months’ EBITDA. At December 31, 2023, the Company had a net debt to EBITDA level of 0.8:1 compared to 0.7:1 as at December 31, 2022. The increase in Bonterra’s net debt to EBITDA ratio is primarily due to a decrease in EBITDA from lower commodity prices. The net debt to EBITDA ratio is expected to improve in subsequent quarters due to the Company’s focus on debt reduction paired with 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 nine 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. 58 | Page a) Net debt to EBITDA ratio The net debt and EBITDA amounts are as follows: (1) Included in current liabilities is the current portion of the Subordinated Term Debt of $19,000,000 (December 31, 2022 - $20,193,000). b) Risks and mitigation Market risk is the risk that the fair value or future cash flow of the Company’s financial instruments will fluctuate because of changes in market prices. Components of market risk to which the Company is exposed are discussed below. Commodity Price Risk The Company’s principal operation is the production and sale of crude oil, natural gas and natural gas liquids. Fluctuations in prices of these commodities directly impact the Company’s performance and ability to continue with its dividends. The Company has used various risk management contracts to set price parameters for a portion of its production. The Company has assumed the risk in respect of commodity prices, except for a small portion of physical delivery sales and risk management contracts to manage commodity risk on the Company’s higher operating cost areas. The Company is exposed to credit risk, liquidity risk and market risk as part of its normal course of business. The Company’s overall risk management program seeks to mitigate these risks and reduce the volatility of Bonterra’s financial performance. Financial risk is managed by senior management under a risk management program approved by the Board of Directors. 59 | Page ($ 000s)December 31, 2023December 31, 2022Bank debt14,822 17,601 Subordinated debentures52,585 49,770 Subordinated term debt(1)53,018 69,882 Current liabilities57,135 56,805 Current assets (37,160) (44,227)Net debt140,400 149,831 Net earnings44,943 79,023 Adjustments to net earnings:Unrealized gain on risk management contracts (1,559) (5,365)Deferred consideration (1,009) (1,158)Finance costs 28,437 21,647 Share-option compensation 3,228 1,910 Depletion and depreciation 90,479 90,951 Current income tax expense 11,134 7,819 Deferred income tax expense 3,300 17,727 EBITDA (trailing twelve months)178,953 212,554 Net debt to EBITDA ratio0.8 0.7 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, 2023, 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, 2023, the Company entered into the following physical delivery sales contract. 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. 60 | Page ProductType of contractVolumeOilPhysical collar - WTI(1)200 BBL/dayApr 1, 2024toJun 30, 202470.00 to90.00 USD/BBLGasPhysical collar - AECO Monthly(5)5,000 GJ/dayJan 1, 2024toMar 31, 20242.75 to3.45 CAD/GJGasPhysical collar - AECO Monthly(5)6,000 GJ/dayApr 1, 2024toJun 30, 20242.15 to2.75 CAD/GJGasFixed Price - AECO Daily(4)5,000 GJ/dayJan 1, 2024toJan 31, 2024- 1.81 CAD/GJGasFixed Price - AECO Daily(4)5,000 GJ/dayFeb 1, 2024toFeb 29, 2024- 1.84 CAD/GJGasFixed Price - AECO Daily(4)5,000 GJ/dayJan 1, 2024toJan 31, 2024- 1.82 CAD/GJContract price ($)TermProductType of contractVolumeGasFixed Price - AECO Daily2,500 GJ/dayApr 1, 2024toOct 31, 20252.39 CAD/GJTermContract price ($)($ 000s)December 31, 2023December 31, 2022Risk management contractsRealized gain (loss) 1,801 (16,878)Unrealized gain 1,559 5,365 3,360 (11,513) As of December 31, 2023, the Company has the following risk management contracts in place. 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, 2023, 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, $76,000,000 second lien Subordinated Term Debt and $59,000,000 in senior unsecured subordinated debentures. The borrowings under the total bank facilities are at bank prime plus or minus various percentages as well as by means of banker’s acceptances (“BAs”) within the Company’s credit facility. The subordinated debt has a fixed interest rate of 11.7 percent for a quarter of the outstanding balance and prime plus 6.25 percent for the remaining outstanding balance. Subordinated debentures are at a fixed interest rate of nine percent. The Company 61 | Page ProductType of contractVolumeOilFinancial collar - WTI500 BBL/dayJan 1, 2024toMar 31, 202450.00 to88.25 USD/BBLOilFinancial collar - WTI500 BBL/dayJan 1, 2024toMar 31, 202450.00 to84.85 USD/BBLOilFinancial collar - WTI500 BBL/dayJan 1, 2024toMar 31, 202450.00 to85.00 USD/BBLOilFinancial collar - WTI300 BBL/dayJan 1, 2024toMar 31, 202450.00 to85.50 USD/BBLOilFinancial collar - WTI500 BBL/dayJan 1, 2024toMar 31, 202450.00 to85.60 USD/BBLOilFinancial collar - WTI500 BBL/dayApr 1, 2024toJun 30, 202460.00 to93.35 USD/BBLOilFinancial collar - WTI500 BBL/dayApr 1, 2024toJun 30, 202460.00 to92.00 USD/BBLOilFinancial collar - WTI500 BBL/dayApr 1, 2024toJun 30, 202465.00 to92.85 USD/BBLOilFinancial collar - WTI400 BBL/dayApr 1, 2024toJun 30, 202465.00 to93.75 USD/BBLOilFinancial collar - WTI500 BBL/dayJul 1, 2024toSep 30, 202470.00 to90.00 USD/BBLOilFinancial collar - WTI500 BBL/dayJul 1, 2024toDec 31, 202465.00 to92.80 USD/BBLOilFinancial collar - WTI500 BBL/dayJul 1, 2024toDec 31, 202465.00 to84.50 USD/BBLOilFinancial collar - WTI500 BBL/dayJul 1, 2024toDec 31, 202465.00 to85.30 USD/BBLGasFinancial collar - AECO Monthly5,000 GJ/dayJan 1, 2024toMar 31, 20242.75 to3.56 CAD/GJGasFinancial collar - AECO Monthly5,000 GJ/dayApr 1, 2024toJun 30, 20242.25 to2.71 CAD/GJGasFixed Price - AECO Monthly5,000 GJ/dayJul 1, 2024toDec 31, 2024- 2.10 CAD/GJGasFixed Price - AECO Daily5,000 GJ/dayJul 1, 2024toDec 31, 2024- 2.04 CAD/GJTermContract price ($) 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 $580,000. Equity Price Risk Equity price risk refers to the risk that the fair value of the investments and investment in related party will fluctuate due to changes in equity markets. Equity price risk arises from the realizable value of the investments that the Company holds which are subject to variable equity market prices which on disposition gives rise to a cash flow equity price risk. The Company will assume full risk in respect of equity price fluctuations. Foreign Exchange Risk The Company has no foreign operations and currently sells all of its product sales in Canadian currency. The Company however is exposed to currency risk in that crude oil is priced in US currency, then converted to Canadian currency. The Company currently has no outstanding risk management agreements. The Company will assume full risk in respect of foreign exchange fluctuations. 18. COMMITMENTS AND FINANCIAL LIABILITIES The Company has the following maturity schedule for its financial liabilities and commitments: (1) Principal amount. The Company has entered into firm service gas transportation agreements in which the Company guarantees certain minimum volumes of natural gas will be shipped on various gas transportation systems. The terms of the various agreements expire in one to seven years. The future minimum payment amounts for the firm service gas transportation agreements are calculated using current tariff rates. The Company also has non-cancellable office lease commitments for building and office equipment. The building and office equipment leases have an average remaining life of 2.9 years. 62 | Page ($ 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 - Liability37,226 - - - 37,226 Bank debtYes - Liability- 14,822 - - 14,822 Subordinated debentures(1)Yes - Liability- 59,000 - - 59,000 Subordinated term debt(1)Yes - Liability19,000 57,000 - 76,000 Future interestNo14,063 14,297 - - 28,360 Firm service commitmentsNo1,140 1,824 909 189 4,062 Office lease commitmentsNo472 961 - - 1,433 Total71,901 147,904 909 189 220,903 19. 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 $782,000 of asset retirement obligations as an in-kind grant (December 31, 2022 - $3,675,000). The benefit of the in- kind grant is recognized through other income. 20. SUBSEQUENT EVENTS Asset Acquisition On March 1, 2024, Bonterra closed an acquisition to purchase producing petroleum and natural gas assets in northern Alberta, for cash consideration of approximately $24.1 million before estimated closing adjustments. The assets acquired currently produce 330 BOE per day and provide a portfolio of high-quality future drilling locations and reserves, establishing a new core operating area for the Company. 63 | Page CORPORATE INFORMATION Board of Directors D. Michael G. Stewart - Chair Solicitors Borden Ladner Gervais LLP John J. Campbell David M. Humphreys Stacey E. McDonald Patrick G. Oliver Jacqueline R. Ricci Rodger A. Tourigny Bankers CIBC ATB Financial Business Development Bank of Canada Officers Patrick G. Oliver, President and CEO Robb D. Thompson, CFO and Corporate Secretary Steve Ewens, VP Engineering Brad A. Curtis, Senior VP, Business Development Registrar and Transfer Agent Odyssey Trust Company 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 Auditors Deloitte LLP 64 | Page  

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