Bonterra Energy Corp.
Annual Report 2021

Plain-text annual report

Bonterra Energy Corp. CONTENTS Report to Shareholders 4 Commitment to Responsibility 6 Annual Highlights Quarterly Highlights Statistical Review Management’s Discussion and Analysis Financial Statements Notes to the Financial Statements Corporate Information 8 9 10 14 33 41 IBC 2021 12,747 BOE PER DAY 2021 average annual volumes 2022 13,300-13,700 BOE PER DAY 2022 forecast volumes 2021 $38 MILLION Free Funds Flow generated in 2021(1,2) 2021 $67 MILLION Capex in 2021 2021 221 NET WELLS Successfully abandoned in 2021 2022 $90 MILLION Forecast Free Funds Flow in 2022(1,2,3) 2022 $55-65 MILLION Forecast Capex in 2022 2022 131 NET WELLS Forecast to be abandoned in 2022 A Path 1 Bonterra Energy Corp. (“Bonterra” or the “Company”) is a conventional oil and gas company offering investors exposure to a high-quality and Cardium- focused asset base, a strategy of sustainable growth and commitment to value creation. Bonterra’s Cardium assets are concentrated in Alberta’s Pembina and Willesden Green fields, which are among Canada’s largest conventional oilfields, offering long-term stable production with attractive netbacks. Through 2021, Bonterra substantially improved our financial flexibility and we remain focused on balance sheet strength. With an experienced management team, low-risk and low-decline asset base, and strong torque to rising oil prices, we are well positioned to realize meaningful growth in average daily production, reserves, and free funds flow per share in 2022. Achieving this growth will support continued net debt reduction and position Bonterra to consider future potential capital returns for our shareholders. (1) Non-IFRS financial measure. See advisories later in this report. (2) Free funds flow calculated as funds flow after capital expenditures. (3) Assuming US$70 WTI in 2022. Forward. 2 A Path Forward: Bonterra’s Advantage Bonterra exited 2021 in a substantially stronger position to forge an exciting path forward. The Company’s improved financial position and track record of operational execution support our commitment to long‐term sustainability for shareholders. Having successfully navigated through 2020 and 2021 despite numerous internal and external challenges, today Bonterra benefits from stable and high-quality production, robust oil prices and enhanced netbacks. These strategic advantages are expected to drive further reserves increases, the generation of free funds flow and ongoing strengthening of the balance sheet. Oil-weighted assets Operational execution Long-term inventory Reduced debt Visibility to return of capital Funds Flow and Realized Light Oil Pricing Bonterra took advantage of a stronger commodity price environment through the latter half of 2021, which in combination with higher production volumes, contributed to the generation of robust funds flow and free funds flow. Strong Leverage to Improving Commodity Prices $160 $140 $120 $100 $80 $60 $40 $20 $0 ) C $ M M ( s r a l l o D $150.0 $104.8 $90.0 $27.8 $37.6 $90 $80 $70 $60 $50 $40 $30 ) l b b / D A C $ ( e c i r P d e z i l a e R e g a r e v A 2020 2021 2022 EST ■ Funds Flow ■ Free Funds Flow Average Realized Light Oil Price ($CAD/bbl) 3 Strong Capital Management Bonterra has strategically managed production levels to optimize value through cyclical pricing environments. The Company preserved capital during market volatility caused by the COVID-19 pandemic, and elected to grow our production volumes into a strong pricing environment through the second half of 2021. Production Growth 14,000 13,500 13,000 12,500 12,000 11,500 11,000 10,500 10,000 9,500 9,000 ) d / e o B ( n o i t c u d o r P e g a r e v A 10,575 2020 ■ Production Capital Expenditures 13,500 12,747 2021 2022 EST $70 $65 $60 $55 $50 $45 $40 $35 ) C $ M M ( s e r u t i d n e p x E l a t i p a C Balance Sheet Improvements Through 2021, Bonterra successfully drove down key leverage metrics, increased free funds flow and improved our debt structure. A key achievement during the year was the successful restructuring of our outstanding credit facilities, which served to enhance long-term sustainability and reduce overall bank debt. By the end of 2022, we are targeting a ~33% reduction in net debt (assuming $70 WTI). Net Debt ) C $ M M ( t b e D t e N 350 300 250 200 150 100 50 0 $63.3 $252.3 $104.2 $162.9 2020 2021 ■ Bank Debt ■ Sub-Debt $104.0 $78.0 2022 EST 4 Report to Shareholders Bonterra is pleased to present our fourth quarter and year-end 2021 financial and operating results, selected highlights from which are provided below. Readers are encouraged to review in conjunction with the Company’s full Q4 2021 report which has been filed on SEDAR and is available on Bonterra’s website. Although COVID-19 and its variants continued to present challenges during 2021, Bonterra posted numerous key achievements during the year. With a sound and consistent strategy, strong operational execution and a commitment to financial prudence, we successfully returned production to pre- COVID-19 levels, abandoned more than 221 net wells, renegotiated our bank credit facilities, substantially reduced outstanding bank debt year-over-year, and garnered clear support for Bonterra’s strategy from shareholders. With the combination of these efforts, and the continued strengthening of commodity prices, the Company has established a strong position from which to pursue the ongoing profitable development of our high-quality, light oil weighted asset base. Financial & Operating Highlights ■ Averaged 12,747 BOE per day(1) of production in 2021, representing a 21 percent increase over 2020. Volumes in the fourth quarter averaged 13,810 BOE per day(2), an increase of 37 percent relative to the same period in 2020. ■ Realized oil and gas sales increased 107 percent over 2020 to total $251.6 million in 2021, and increased 149 percent in Q4 2021 over the same period in 2020 with increases primarily driven by significantly higher realized prices and growing production volumes. ■ Generated funds flow(3) of $104.8 million ($3.02 per fully diluted share) in 2021, a 277 percent increase over the $27.8 million ($0.83 per fully diluted share) generated in 2020, while funds flow(3) in Q4 2021 totaled $36.5 million ($1.03 per fully diluted share) or 1,252 percent higher than the same period in 2020. ■ Generated funds flow(3) in excess of capital expenditures (“free funds flow”(3)) of $37.6 million in 2021, which is budgeted to grow to approximately $90 million in 2022 based on increased budgeted production, lower capital spending and an improved pricing environment compared to the previous year. ■ Realized average field netbacks(3) of $29.62 per BOE in 2021 and $34.46 per BOE in Q4 2021, representing increases of 106 percent and 142 percent over the comparative periods of 2020, respectively, with the increases primarily reflecting significantly higher per unit revenue offset by realized losses on risk management contracts and increased per unit royalty expenses. ■ Invested $67.3 million in capital during 2021, $17.6 million of which was invested in the fourth quarter. Approximately $51.1 million was directed to drilling 37 gross (35.4 net) operated wells, with 35 gross (33.2 net) operated wells tied-in and placed on production during the year. Bonterra’s operational performance drove a six percent improvement in per well drilling, completion, and equipping costs compared to 2020. ■ Achieved a 35 percent reduction in bank debt at year end 2021 to $163 million, largely as a result of the Company’s increased funds flow and improved and recapitalized debt structure, while net debt(3) at year end totaled $267 million, reflecting a 15 percent year-over-year decrease. ■ Demonstrated the Company’s ongoing focus on responsible environmental initiatives in 2021 by directing $4.5 million to the successful abandonment of 221 net wells, supported by the Alberta Site Rehabilitation Program, and issuing Bonterra’s inaugural environmental, social and governance (“ESG”) report. For 2022, an additional 131 net wells with no further potential are targeted for abandonment. 5 The Company deployed $67.3 million in capital during 2021, including $17.6 million in the fourth quarter, a portion of which was directed to drill six gross (6.0 net) operated wells. Those six wells were completed, equipped and brought on production during the first quarter of 2022, and during this period, Bonterra has also drilled six gross operated (5.8 net) wells and completed 11 gross operated (10.8 net) wells. In total during the year, Bonterra invested $67.3 million in capital expenditures, coming in at the lower end of our annual capital expenditure budget, partially due to achieving a six percent reduction per well drilling, completion, and equipping costs compared to the prior year and deferring the completion of the six wells outlined above. Of the total capital invested by the Company, 76 percent was allocated to drill 37 gross (35.4 net) operated wells along with the completion, equip, tie-in and placing on production of 35 gross (33.2 net) operated wells, four of which were drilled late in 2020. Approximately 24 percent was directed to related infrastructure, recompletions and non-operated capital programs. With these capital expenditures, Bonterra successfully returned levels, which averaged 2021 production to pre-COVID-19 12,747 BOE per day, an increase of 21 percent over 2020, and averaged 13,810 BOE per day in the fourth quarter. Bonterra intends to continue investing capital for incremental growth initiatives to support increased free funds flow(4) generation that can be allocated to further reductions in outstanding bank debt and balance sheet improvements. As prices improved through the latter half of 2021, Bonterra was able to take advantage of a stronger price environment, which in combination with the higher production volumes, contributed to the generation of $104.8 million of funds flow(3), and $37.6 million of free funds flow during the year. In Q4 2021, Bonterra realized average oil prices of $85.04 per bbl, average NGL prices of $54.54 per bbl, and average natural gas prices of $4.93 per mcf. With stronger prices and higher revenues, the Company’s Q4 2021 field and cash netbacks averaged $34.46 per BOE and $28.72 per BOE, respectively, increases of 142 percent and 901 percent, respectively, compared to the same period in the prior year. Bonterra’s commitment to responsibility was evident throughout 2021, and with support from the Alberta Site Rehabilitation Program, we successfully abandoned 221 net wells, 203 net pipeline segments and decommissioned 3 net battery sites. Bonterra plans to allocate between $4 million and $5 million in 2022 to abandon an additional 131 net wells, and by the end of the year, we expect that our abandonment and reclamation activity will represent approximately 60 percent of all wells that have no further economic potential identified. Bonterra will continue to review our inactive well inventory to identify additional well bores that should be reactivated, repurposed, or abandoned. Outlook As the Company’s production volumes are above pre-COVID-19 levels, Bonterra is pleased to reaffirm our 2022 production guidance of 13,300 to 13,700 BOE per day based on a capital expenditure budget range of $55 million to $65 million. This would represent year-over-year production growth in 2022 of 4 to 7 percent, and would be expected to generate an estimated $90 million of free funds flow(3) (assuming US$70 WTI price) and contribute to significantly improved leverage metrics by year end 2022. To further support stability while facing continued market volatility, and as part of our ongoing efforts to diversify commodity pricing and to protect future cash flows, the Company has executed physical delivery sales and risk management contracts to the end of 2022 on approximately 30 percent of our expected crude oil and natural gas production. For 2022, Bonterra has secured a WTI price between $48.00 USD to $92.10 USD per bbl on 2,460 bbls per day, with a WTI to Edmonton par differential average of approximately $6.00 on 1,663 bbls per day. In addition, we have secured a natural gas price between $2.00 to $4.15 on 11,301 GJ per day for the next twelve months. Bonterra exited 2021 in a substantially stronger position to forge an exciting path forward. The Company’s improved financial position and track record of operational execution support our commitment to long‐term sustainability for shareholders. Having successfully navigated through 2020 and 2021 despite numerous external challenges, today Bonterra benefits from stable and high-quality production, robust oil prices and enhanced netbacks. These strategic advantages are expected to drive further reserves increases, continued generation of free funds flow, ongoing balance sheet strengthening in 2022 and an eventual return of capital to shareholders. In addition, the Company is integrating further ESG initiatives across the organization and looks forward to reporting on progress to shareholders going forward. Bonterra remains committed to employing local services, being a key economic contributor to rural and surrounding communities located within central Alberta, upholding a responsible abandonment and reclamation program, and maintaining rigorous safety measures. George F. Fink Chief Executive Officer (1) 2021 volumes comprised of 7,204 bbl/d light and medium crude oil, 1,013 bbl/d NGLs and 27,176 mcf/d of conventional natural gas. (2) Q4 2021 volumes comprised of 7,659 bbl/d light and medium crude oil, 1,105 bbl/d NGLs and 30,276 mcf/d of conventional natural gas. (3) Non-IFRS measure. See advisories later in this report. 6 Commitment to Responsibility Bonterra is proud to have released our inaugural environmental, social, and governance (“ESG”) report in 2021, which aligns with the Task Force on Climate-related Financial Disclosures (“TCFD”) framework and outlines specific steps the Company is taking to enhance our standing as a corporate citizen. We prioritize the health and safety of our workers, foster positive relationships with local communities, and responsibly maintain environments that may be impacted by Bonterra’s operations. Although we strive to generate positive returns for our shareholders, we carefully balance this goal with responsible operations and upholding integrity. Environment Bonterra strives to minimize our environmental impact while driving economic growth for shareholders, employees, and partnering communities. We seek to minimize waste and reduce energy usage. Bonterra is proud to consistently meet or exceed all applicable environmental regulations, statutes, and industry standards while mitigating risk and liability. Commitments in Action: ■ Use minimal disturbance drilling techniques; ■ Eliminate venting and flaring through facility consolidation, improvements and decommissioning older technological infrastructure; ■ Monitor and protect animals around well sites to minimize impact on surrounding flora and fauna; and ■ Leverage Alberta’s Site Rehabilitation Program ("SRP") for continued abandonment and reclamation efforts. Social The health and safety of our employees and others working with or near Bonterra’s operations is paramount. In addition, we seek to establish positive and constructive relationships with our partnering communities. Bonterra strives to engage and hire local businesses and community members wherever possible. Contributing to the general well-being and improvement of towns, cities, and regions in the vicinity of our operations is a priority of implemented extensive policies, Bonterra. Bonterra has procedures, equipment and emergency response plans designed to ensure the health and well-being of our staff, contractors and the general public. Commitments in Action: ■ Strive for constant safety improvements by deploying an education-based program; ■ Adhere closely to the Alberta, Saskatchewan and British Columbia Occupational Health and Safety Acts and WorkSafeBC; and ■ Support Canada’s conventional energy producers by maintaining membership in, and involvement with, Explorers and Producers Association of Canada (EPAC). Corporate Governance Bonterra has a robust governance framework to ensure corporate responsibility, integrity and transparency. Our board refresh continued in 2021 with the appointment of two new members, Mr. D. Michael Stewart and Ms. Stacey McDonald, reducing our board tenure to 6.1 years while ensuring an optimal balance of corporate history with new ideas and valuable perspectives. Currently, Bonterra’s board includes 33 percent female members, and 100 percent independent board committees. Commitments in Action: ■ Board meets regularly with at least four meetings scheduled per year; ■ All members are invited to attend committee meetings as observers, to hold in-camera sessions with only independent members, and establish a separate Board committee to oversee ESG and Health, Safety & Environment; and ■ Establish strong governance policies including Code of Conduct, Insider Trading and Disclosure Policy, Whistleblower Policy, Majority Voting Policy and a Diversity Policy. Bonterra's Responsible Approach 7 Alleviating abandonment obligations Applications to Alberta’s SRP resulted in $5.9 million of abandonment obligation relief for Bonterra. Incorporating reclamation spending into budgets Abandonment of wells far outpacing well count growth rate Bonterra’s 2021 budget included $4.5 million directed to abandoning 221 wells with no further economic potential throughout the year. Exponential increases in Bonterra’s well abandonment relative to total well count further emphasizes commitment to ESG initiatives. Bonterra is committed to transparency, accountability and providing a safe work environment while employing practices and procedures that meet or exceed all regulatory requirements. 8 Annual Highlights As at and for the year ended ($000s except $ per share) FINANCIAL Revenue – realized oil and gas sales Funds flow(1) Per share – basic Per share – diluted Dividend payout ratio Cash flow from operations Per share – basic Per share – diluted Dividend payout ratio Cash dividends per share Net earnings (loss)(2) Per share – basic Per share – diluted Capital expenditures Total assets Net debt(3) Bank debt Shareholders' equity OPERATIONS Light oil ‒ bbl per day ‒ average price ($ per bbl) NGLs ‒ bbl per day ‒ average price ($ per bbl) Conventional natural gas ‒ MCF per day Total barrels of oil equivalent per day (BOE)(4) ‒ average price ($ per MCF) December 31, 2021 December 31, 2020 December 31, 2019 251,616 104,843 3.11 3.02 0% 96,103 2.85 2.76 0% 0.00 121,642 27,789 0.83 0.83 4% 32,073 0.96 0.96 3% 0.03 179,299 (306,889) 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 (9.19) (9.19) 43,728 731,859 315,573 252,255 196,633 5,832 44.31 1,032 18.65 22,268 2.46 10,575 202,749 96,261 2.88 2.88 4% 81,132 2.43 2.43 5% 0.12 21,923 0.66 0.66 53,627 1,087,817 292,810 273,065 503,949 7,310 66.34 986 25.83 24,053 1.87 12,305 (1) Funds flow is not a recognized measure under IFRS. For these purposes, the Company defines funds flow as funds provided by operations including proceeds from sale of investments and investment income received excluding the effects of changes in non-cash working capital items and decommissioning expenditures settled. (2) In the first quarter of 2020 the Company recorded a $331,678,000 impairment provision less a $54,107,000 deferred income tax recovery related to its Alberta CGU’s oil and gas assets due to the impact of COVID-19 effect on the forward benchmark prices for crude oil. With stronger forward prices in Q2 2021, the Company recorded a $203,197,000 impairment reversal on its Alberta CGU’s oil and gas assets less $47,149,000 deferred income tax expense. (3) Net debt is not a recognized measure under IFRS. The Company defines net debt as current liabilities less current assets plus long-term subordinated debt and subordinated debentures. (4) BOE may be misleading, particularly if used in isolation. A BOE conversion ratio of 6 MCF: 1 bbl is based on an energy conversion method primarily applicable at the burner tip and does not represent a value equivalency at the wellhead. Quarterly Highlights As at and for the periods ended ($ 000s except $ per share) Q4 2021 Q3 FINANCIAL Revenue – oil and gas sales Funds flow(1) Per share – basic and diluted Per share – diluted Cash flow from operations Per share – basic Per share – diluted Net earnings (loss) Per share – basic Per share – diluted Capital expenditures Total assets Net debt(3) Shareholders' equity OPERATIONS Light oil (barrels per day) Average price ($ per bbl) NGLs (barrels per day) Average price ($ per bbl) Conventional natural gas (MCF per day) Average price ($ per MCF) Total BOE per day(4) 79,202 36,488 1.07 1.03 37,868 1.11 1.07 16,333 0.48 0.46 17,636 945,721 267,179 392,019 7,659 85.04 1,105 54.54 30,276 4.93 13,810 64,457 28,658 0.85 0.83 24,616 0.73 0.71 7,296 0.22 0.21 18,578 939,835 307,729 361,590 6,948 78.42 928 48.86 27,995 3.94 12,542 9 Q2 59,163 23,105 0.69 0.67 18,874 0.56 0.55 157,354(2) 4.68 4.55 7,607 948,260 319,310 353,431 7,370 71.49 996 35.59 26,057 3.37 12,709 Q1 48,794 16,592 0.50 0.49 14,745 0.44 0.43 (1,684) (0.05) (0.05) 23,461 748,543 328,506 195,393 6,834 61.76 1,025 35.60 24,301 3.44 11,909 (1) Funds flow is not a recognized measure under IFRS. For these purposes, the Company defines funds flow as funds provided by operations including proceeds from sale of investments and investment income received excluding the effects of changes in non-cash working capital items and decommissioning expenditures settled. (2) In Q2 2021, with stronger forward benchmark prices since the impact of COVID-19 beginning in March 2020, the Company recorded a $203,197,000 impairment reversal on its Alberta CGU’s oil and gas assets less $47,149,000 deferred income tax expense. (3) Net debt is not a recognized measure under IFRS. The Company defines net debt as current liabilities less current assets plus long-term subordinated debt and subordinated debentures. (4) BOE may be misleading, particularly if used in isolation. A BOE conversion ratio of 6 MCF: 1 bbl is based on an energy conversion method primarily applicable at the burner tip and does not represent a value equivalency at the wellhead. 10 Statistical Review Summary of Gross Oil and Gas Reserves as of December 31, 2021 Reserves Category PROVED Developed Producing Developed Non-Producing Undeveloped TOTAL PROVED PROBABLE TOTAL PROVED PLUS PROBABLE(1)(2)(3) Light & Medium Crude Oil Conventional Natural Gas Natural Gas Liquids Oil Equivalent(4) (Mbbl) (MMCF) (Mbbl) (MBOE) Future Development Capital ($ 000s) 18,522 2,335 22,613 43,470 10,760 54,231 67,490 5,990 93,315 166,795 40,478 207,273 2,725 229 4,008 6,962 1,694 8,655 32,495 3,562 42,174 78,231 19,200 97,431 - 6,793 547,378 554,171 - 554,171 (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, 2021 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, 2021(1)(2) Light and Medium Crude Oil Conventional Natural Gas Natural Gas Liquids Total Proved Proved + Probable Proved Proved + Probable (Mbbl) (Mbbl) (MMCF) (MMCF) Proved (Mbbl) Proved + Probable Proved Proved + Probable (Mbbl) (MBOE) (MBOE) 43,067 53,729 150,476 187,462 7,172 8,938 75,319 93,910 Opening Balance December 31, 2020 Extensions & Improved Recovery(2) Technical Revisions (2,858) (3,833) 3,856 4,823 15,621 3,945 19,510 3,736 731 (848) 914 7,191 (1,100) (3,048) 8,989 (4,310) Discoveries Acquisitions Dispositions(3) Economic Factors Production CLOSING BALANCE, DECEMBER 31, 2021(4) - - - - - - - - - - - - - - - - - - - - - - - - 2,034 (2,630) 2,141 (2,630) 6,673 (9,919) 6,484 (9,919) 276 (370) 273 (370) 3,423 (4,653) 3,495 (4,653) 43,470 54,231 166,795 207,273 6,962 8,655 78,231 97,431 (1) Gross Reserves means the Company’s working interest reserves before calculation of royalties, and before consideration of the Company’s royalty interests. (2) Increases to Extensions & Improved Recovery include infill drilling and are the result of step-out locations drilled by Bonterra and other operators on and near Company-owned lands. (3) Includes volumes associated with Farm outs. (4) Totals may not add due to rounding. 11 Summary of Net Present Values of Future Net Revenue as of December 31, 2021 ($ 000s) Reserve Category PROVED Developed Producing Developed Non-Producing Undeveloped TOTAL PROVED PROBABLE TOTAL PROVED + PROBABLE(1)(2)(3)(4) Net Present Value Before Income Taxes Discounted at (% per Year) 0% 5% 10% 15% 742,567 102,439 941,525 1,786,531 678,326 2,464,857 651,462 71,406 583,748 1,306,616 404,334 1,710,950 542,915 55,012 388,505 986,432 279,419 1,265,851 463,927 45,066 272,631 781,624 212,060 993,685 (1) Evaluated by Sproule as at December 31, 2021. 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, 2021. There is no assurance that the forecast price and cost assumptions will be attained and variances could be material. (3) Includes abandonment and reclamation costs as defined in NI 51-101. (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 2021 2020 2019 3 Yr Avg(4) 2021 2020 2019 3 Yr Avg(4) FD&A COSTS PER BOE(1)(2)(3) Including FDC Excluding FDC F&D COSTS PER BOE(1)(2)(3) Including FDC Excluding FDC $6.90 $8.68 $6.90 $8.68 $12.46 ($18.21) $12.46 ($18.21) $14.32 $9.94 $14.32 $9.94 $9.44 $15.27 $9.44 $15.27 $5.64 $8.23 $5.64 $8.23 $9.87 ($13.26) $9.87 ($13.26) $18.24 $12.35 $18.24 $12.35 $10.06 $17.86 $10.06 $17.86 (1) Barrels of Oil Equivalent may be misleading, particularly if used in isolation. A BOE conversion ratio of 6 MCF: 1 bbl is based on an energy equivalency conversion method primarily applicable at the burner tip and does not represent a value equivalency at the wellhead. (2) The aggregate of the exploration and development costs incurred in the most recent financial year and the change during that year in estimated future development costs generally will not reflect total finding and development costs related to reserve additions for that year. (3) FD&A and F&D costs are net of proceeds of disposal and the FD&A costs per BOE are based on reserves acquired net of reserves disposed of. (4) Three year average is calculated using three year total capital costs and reserve additions on both a Proved and Proved + Probable reserves on a weighted average basis. 12 Commodity Prices Used in the Above Calculations of Reserves are as Follows Year FORECAST 2022 2023 2024 2025 2026 2027 2028 2029 2030 2031 2032 Edmonton Par Price ($Cdn per bbl) Natural Gas AECO-C Spot ($Cdn per mmbtu) Butanes Edmonton ($Cdn per bbl) Pentanes Edmonton ($Cdn per bbl) Operating Cost Inflation Rate (% per Year) Exchange Rate ($US/$Cdn) 86.82 80.73 78.01 79.57 81.16 82.78 84.44 86.13 87.85 89.61 91.40 3.56 3.21 3.05 3.11 3.17 3.23 3.30 3.36 3.43 3.50 3.57 57.49 50.17 48.53 49.50 50.49 51.50 52.53 53.58 54.65 55.74 56.86 91.85 85.53 82.98 84.63 86.33 88.05 89.82 91.61 93.44 95.32 97.22 0.0 2.3 2.0 2.0 2.0 2.0 2.0 2.0 2.0 2.0 2.0 0.80 0.80 0.80 0.80 0.80 0.80 0.80 0.80 0.80 0.80 0.80 Crude oil, natural gas and liquid prices escalate at 2.0 percent thereafter. Production Alberta Saskatchewan British Columbia Land Holdings Alberta Saskatchewan British Columbia 2021 Conventional Natural Gas (Mcf Per Day) Oil & NGLS (bbl Per Day) Total (BOE Per Day) 8,105 107 6 8,218 26,786 36 354 27,176 12,568 113 66 12,747 2021 2020 Gross Acres Net Acres Gross Acres Net Acres 331,252 7,806 65,913 404,970 204,134 5,595 28,260 237,989 344,052 8,157 62,045 414,254 216,076 5,680 23,690 245,446 13 Petroleum and Natural Gas Expenditures The following table summarized petroleum and natural gas capital expenditures incurred by Bonterra on acquisitions, land, and exploration and development costs for the years ended December 31: ($ 000s) Land Exploration and development costs Net petroleum and natural gas capital expenditures 2021 1,621 65,661 67,282 2020 959 42,769 43,728 Drilling History The following tables summarize Bonterra's gross and net drilling activity and success: Crude oil Natural gas Total Success rate Crude oil Natural gas Total Success rate Development Gross 39.0 - 39.0 100% Development Gross 27.0 - 27.0 96% Net 35.8 - 35.8 100% Net 23.9 - 23.9 96% 2021 Exploratory Gross Net - - - - - - - - 2020 Exploratory Gross Net - - - - - - - - Total Gross 39.0 - 39.0 96% Total Gross 27.0 - 27.0 96% Net 35.8 - 35.8 96% Net 23.9 - 23.9 96% 14 Management’s Discussion and Analysis The following report dated March 9, 2022 is a review of the operations and current financial position for the year ended December 31, 2021 for Bonterra Energy Corp. (“Bonterra” or “the Company”) and should be read in conjunction with the audited financial statements presented under International Financial Reporting Standards (IFRS), including the notes related thereto. Use of Non-IFRS Financial Measures Throughout this Management’s Discussion and Analysis (MD&A) the Company uses the terms “field netback”, “cash netback” and “net debt” to analyze operating performance, which are not standardized measures recognized under IFRS and do not have a standardized meaning prescribed by IFRS. These measures are commonly used in the oil and gas industry and are considered informative by management, shareholders and analysts. These measures may differ from those made by other companies and accordingly may not be comparable to such measures as reported by other companies. 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; 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. Annual Comparisons As at and for the year ended ($000s except $ per share) FINANCIAL Revenue – realized oil and gas sales Cash flow from operations Per share – basic Per share – diluted Dividend payout ratio Cash dividends per share Net earnings (loss)(1) Per share – basic Per share – diluted Capital expenditures Total assets Net debt Shareholders' equity OPERATIONS Light oil – bbl per day – average price ($ per bbl) NGLs – bbl per day Conventional natural gas – MCF per day – average price ($ per bbl) – average price ($ per MCF) Total BOE per day 15 December 31, 2021 December 31, 2020 December 31, 2019 251,616 96,103 2.85 2.76 0% 0.00 121,642 32,073 0.96 0.96 3% 0.03 179,299 (306,889) 5.32 5.16 67,282 945,721 267,179 392,019 7,204 74.53 1,013 43.86 27,176 3.97 12,747 (9.19) (9.19) 43,728 731,859 315,573 196,633 5,832 44.31 1,032 18.65 22,268 2.46 10,575 202,749 81,132 2.43 2.43 5% 0.12 21,923 0.66 0.66 53,627 1,087,817 292,810 503,949 7,310 66.34 986 25.83 24,053 1.87 12,305 (1) In the first quarter of 2020 the Company recorded a $331,678,000 impairment provision less a $54,107,000 deferred income tax recovery related to its Alberta CGU’s oil and gas assets due to the impact of COVID-19 effect on the forward benchmark prices for crude oil. With stronger forward prices in Q2 2021, the Company recorded a $203,197,000 impairment reversal on its Alberta CGU’s oil and gas assets less $47,149,000 deferred income tax expense. 16 Quarterly Comparisons As at and for the periods ended ($ 000s except $ per share) Q4 2021 Q3 Q2 Q1 FINANCIAL Revenue – oil and gas sales Cash flow from operations Per share – basic Per share – diluted Net earnings (loss)(1) Per share – basic Per share – diluted Capital expenditures Total assets Net debt Shareholders' equity OPERATIONS Light oil (barrels per day) NGLs (barrels per day) Conventional natural gas (MCF per day) Total BOE per day 79,202 37,868 1.11 1.07 16,333 0.48 0.46 17,636 945,721 267,179 392,019 7,659 1,105 30,276 13,810 64,457 24,616 0.73 0.71 7,296 0.22 0.21 18,578 939,835 307,729 361,590 6,948 928 27,995 12,542 59,163 18,874 0.56 0.55 157,354 4.68 4.55 7,607 948,260 319,310 353,431 7,370 996 26,057 12,709 48,794 14,745 0.44 0.43 (1,684) (0.05) (0.05) 23,461 748,543 328,506 195,393 6,834 1,025 24,301 11,909 (1) In Q2 2021, with stronger forward benchmark prices since the impact of COVID-19 beginning in March 2020, the Company recorded a $203,197,000 impairment reversal on its Alberta CGU’s oil and gas assets less $47,149,000 deferred income tax expense. As at and for the periods ended ($ 000s except $ per share) Q4 FINANCIAL Revenue – oil and gas sales Cash flow from (used in) operations Per share – basic Per share – diluted Net loss(1) Per share – basic Per share – diluted Capital expenditures Total assets Net debt Shareholders' equity OPERATIONS Light oil (barrels per day) NGLs (barrels per day) Conventional natural gas (MCF per day) Total BOE per day 31,761 (1,199) (0.04) (0.04) (11,071) (0.33) (0.33) 19,064 731,859 315,573 196,633 5,371 960 22,560 10,091 2020 Q3 29,155 6,370 0.19 0.19 (5,211) (0.16) (0.16) 2,819 722,910 295,168 207,325 5,355 1,064 21,510 10,004 Q2 22,171 4,429 0.13 0.13 Q1 38,555 22,473 0.67 0.67 (5,954) (284,653) (0.18) (0.18) 104 732,462 299,445 212,342 5,553 1,104 21,142 10,181 (8.53) (8.53) 21,741 743,533 300,688 218,211 7,058 999 23,864 12,034 (1) In the first quarter of 2020 the Company recorded a $331,678,000 impairment provision less a $54,107,000 deferred income tax recovery related to its Alberta CGU’s oil and gas assets due to the impact of COVID-19 on forward benchmark prices for crude oil. 17 Business Environment and Sensitivities Bonterra’s financial results are significantly influenced by fluctuations in commodity prices, including price differentials, as well as production volumes and foreign exchange rates. The following table depicts selective market benchmark commodity prices, differentials and foreign exchange rates in the last eight quarters to assist in understanding how past volatility has impacted Bonterra’s financial and operating performance. The increases or decreases in Bonterra’s realized average price for oil and natural gas for each of the eight quarters is also outlined in detail in the following table. Crude oil WTI (U.S.$/bbl) WTI to MSW Stream Index Differential (U.S.$/bbl)(1) Foreign exchange U.S.$ to Cdn$ Bonterra average realized oil price (Cdn$/bbl) Natural gas AECO (Cdn$/mcf) Bonterra average realized gas price (Cdn$/mcf) Q4-2021 Q3-2021 Q2-2021 Q1-2021 Q4-2020 Q3-2020 Q2-2020 Q1-2020 77.19 70.56 66.07 57.84 42.66 40.93 27.85 46.17 (3.10) (4.08) (3.11) (5.24) (4.07) (3.51) (6.14) (7.58) 1.2601 1.2602 1.2280 1.2663 1.3031 1.3316 1.3860 1.3445 85.04 78.42 71.49 61.76 4.63 4.93 3.58 3.94 3.08 3.37 3.14 3.44 47.16 2.63 3.02 45.73 33.31 49.67 2.23 2.40 1.98 2.14 2.02 2.26 (1) This differential accounts for the majority of the difference between WTI and Bonterra’s average realized price (before quality adjustments and foreign exchange). Bonterra’s average realized commodity prices can be impacted by numerous events or factors. Most impactful has been the ongoing effects of the COVID-19 pandemic. Volatility in WTI benchmark pricing has been significant since the onset of COVID-19 in early 2020, though commodity pricing and industry activity has begun to strengthen in the second half of 2021 and into 2022. WTI benchmark prices for the fourth quarter of 2021 increased by nearly $7 USD per barrel compared to the third quarter of 2021. The increase was driven by continuing improvements in real demand, coupled with ongoing supply discipline from both OPEC+ and US shale producers. These factors have continued to result in significant destocking of global crude and product inventories, which continues to support a higher price environment. However, uncertainty still remains around prolonged COVID-19 related market impacts and supply and demand levels through 2022, and as such, it is likely that pricing volatility will continue. In addition to the above supply and demand issues, geopolitical concerns have played a significant role recently in crude oil price volatility. Tension between Russia, the Ukraine and western countries that support NATO are at the forefront currently, and headlines from this conflict are influencing crude oil prices on a daily basis. In addition to crude prices, Canadian crude oil differentials can also impact Bonterra’s financial performance. Differentials narrowed in the fourth quarter of 2021 compared to the previous quarter. Strong North American refining demand and the startup of the long- anticipated Enbridge Line 3 expansion project both contributed to improved Canadian differentials in the fourth quarter. Longer term, the Trans Mountain Expansion is expected to increase Canada’s export capabilities, and similar to Line 3, is anticipated to have a positive effect on the movement and pricing of Canadian barrels. Ongoing concerns around the outcome of Enbridge’s Line 5 crossing into Michigan is a factor that could have a negative effect on the pricing differential between WTI and MSW or Edmonton Par pricing. Low natural gas inventories around the globe have driven many natural gas commodity benchmark prices to multi-year highs, including the AECO benchmark price which increased nearly 30 percent in the fourth quarter of 2021 relative to the previous quarter. Forecast natural gas pricing in 2022 continues to reflect an improved AECO market. Planned facility additions for the NGTL system in the near term and progress by LNG Canada for the Kitimat liquefied natural gas export facility over the longer term may continue to support and improve market sentiment towards western Canadian-based natural gas producers. 18 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. Annualized sensitivity analysis on cash flow, as estimated for 2022(1) Impact on cash flow Realized crude oil price ($/bbl) Realized natural gas price ($/mcf) U.S.$ to Canadian $ exchange rate Change ($) 1.00 0.10 0.01 $000s 2,517 979 2,013 $ per share(2) 0.07 0.03 0.06 (1) This analysis uses current royalty rates, annualized estimated average production of 13,500 BOE per day and no changes in working capital. (2) Based on annualized basic weighted average shares outstanding of 35,000,952. Business Overview, Strategy and Key Performance Drivers Bonterra is an upstream oil and gas company that is primarily focused on the development of its Cardium land within the Pembina and Willesden Green areas located in central Alberta. The Pembina Cardium reservoir is the largest conventional oil reservoir in western Canada that features large original oil in place with very low recoveries to date. Bonterra operates approximately 93 percent of its production and the majority of its related oil and gas processing facilities, which require minimal additional capital to support an increase of production. Bonterra is committed to employing local services in Drayton Valley and to being a key economic contributor to rural and surrounding communities located within central Alberta. On October 20, 2021, the Company successfully closed a private placement debt financing, thereby achieving its goal of restructuring all bank debt to a fully conforming revolving credit facility and converting $19.5 million of its current subordinated promissory note and due- to-related party debt under the same terms and conditions as the private placement. Bonterra’s current debt restructuring and move to a fully conforming $210 million borrowing base facility together represent the complete removal of the existing $65 million non-revolving term loan, leading to significantly improved financial flexibility. With these balance sheet improvements combined with strengthening commodity prices, the Company has established a stronger position from which to execute on its business plan through 2022. Bonterra intends to continue investing capital for incremental growth initiatives to support increased free cash flow generation that can be allocated to further enhancing its capital structure, balance sheet and leverage metric improvements. Bonterra successfully returned to pre-COVID-19 production levels in 2021, taking advantage of rising commodity prices to maximize cash flow. The Company averaged 12,747 BOE per day of production in 2021, an increase of 2,172 BOE per day, or twenty-one percent compared to 2020, and averaged 13,810 BOE per day through the fourth quarter. With production volumes now in excess of pre- COVID-19 levels, the Company’s 2022 production guidance has been reaffirmed between 13,300 to 13,700 BOE per day. Bonterra believes the Company has established a strong position to continue pursuing profitable development of its high-quality, light oil weighted asset base and remains focused to maximizing the Company’s financial position. In 2021, the Company achieved a six percent reduction per well drilling, completion, and equipping costs compared to the prior year. Bonterra invested total capital expenditures of $67.3 million in 2021, which was at the lower end of its annual capital budget. Of the total capital invested, $51.1 million was directed to the drilling of 37 gross (35.4 net) operated wells and the completing, equipping, tying-in and placing on production of 35 gross (33.2 net) operated wells, with four of the completed and equipped wells having been drilled late in 2020. Approximately $16.2 million of the capital program was directed to related infrastructure, recompletions and non- operated capital programs. The six gross (6.0 net) operated wells drilled in the fourth quarter of 2021 were completed, equipped and tied-in in the first quarter of 2022. The Company’s previously announced 2022 capital expenditure budget is expected to total between $55 million to $65 million. Bonterra successfully abandoned 220.7 net wells, 203.0 net pipeline segments and decommissioned 3.0 net battery sites during 2021 with support from the Alberta Site Rehabilitation Program (“SRP”). As the Company continues to execute its abandonment program through 2022, a further 131 net wells and associate pipelines that have no deemed future economic potential are forecast to be abandoned. Bonterra continuously reviews its inactive well inventory for future potential to determine if a well bore should be reactivated, repurposed, or abandoned. 19 To further support stability while facing continued market volatility, and as part of Bonterra’s ongoing efforts to diversify commodity pricing and to protect future cash flows, the Company has executed physical delivery sales and risk management contracts to the end of 2022 on approximately 30 percent of its expected crude oil and natural gas production. For 2022, Bonterra has secured a WTI price between $48.00 USD to $92.10 USD per bbl on 2,460 bbls per day, with a WTI to Edmonton par differential average of approximately $6.00 on 1,663 bbls per day. In addition, the Company has secured a natural gas price between $2.00 to $4.15 on 11,301 GJ per day for the next twelve months. 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 levels of production, 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 in this MD&A and/or previous interim or annual MD&A disclosures. Drilling Three months ended Year ended December 31, 2021 September 30, 2021 December 31, 2020 December 31, 2021 December 31, 2020 Gross(1) Net(2) Gross(1) Net(2) Gross(1) Net(2) Gross(1) Net(2) Gross(1) Net(2) Crude oil horizontal-operated Crude oil horizontal-non-operated Total Success rate 8 2 10 8.0 0.4 8.4 100% 13 - 13 11.5 - 11.5 100% 13 3 16 12.8 0.1 12.9 100% 37 2 39 35.4 0.4 35.8 100% 24 3 27 23.8 0.1 23.9 96% (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 2021, the Company drilled 37 gross (35.4 net) operated wells and completed, tied-in and placed on production 35 gross (33.2 net) operated wells. Four of the wells that were completed and tied-in during Q1 2021 were drilled in late 2020. The six gross (6.0 net) operated wells drilled in the fourth quarter of 2021 were completed, equipped and tied-in in the first quarter of 2022. Production Crude oil (barrels per day) NGLs (barrels per day) Natural gas (MCF per day) Average BOE per day Three months ended Year ended December 31, 2021 September 30, 2021 December 31, 2020 December 31, 2021 December 31, 2020 7,659 1,105 30,276 13,810 6,948 928 27,995 12,542 5,371 960 22,560 10,091 7,204 1,013 27,176 12,747 5,832 1,032 22,268 10,575 The Company averaged 12,747 BOE per day of production in 2021, compared to 10,575 BOE per day for 2020, an increase of 2,172 BOE per day or 21 percent. The increase in production is largely due to the Company’s drilling program re-commencing in the fourth quarter of 2020 after being suspended since April 2020, along with the reactivation of down wells that were voluntarily shut-in due to low commodity prices from the onset of the COVID-19 pandemic. With the support of the BDC subordinated debt, Bonterra has since exceeded Q1 2020 (pre COVID-19) production levels. The Company’s 2021 average production was slightly below with its previously stated annual production guidance of 12,800 to 13,200 BOE per day, despite experiencing an average of approximately 375 BOE per day of downtime during the year due to third-party pipeline and facility issues and pipeline freeze offs in December 2021 due to extremely cold weather. Quarter-over-quarter production increased primarily due to the Company realizing the full benefit of bringing on production from fifteen wells during the third and fourth quarter of 2021. 20 Cash Netback The following table illustrates the calculation of the Company's cash netback from operations for the periods ended: $ per BOE Production volumes (BOE) Gross production revenue Risk management contracts realized gain (loss) Royalties Production costs Field netback General and administrative Interest and other Cash netback Three months ended Year ended December 31, 2021 September 30, 2021 December 31, 2020 December 31, 2021 December 31, 2020 1,270,488 62.34 1,153,874 55.86 928,332 34.21 4,652,719 54.08 3,870,369 31.43 (5.24) (6.94) (15.70) 34.46 (2.64) (3.10) 28.72 (4.21) (6.17) (14.45) 31.03 (1.74) (4.45) 24.84 (0.58) (2.11) (17.30) 14.22 (4.07) (7.28) 2.87 (3.74) (5.53) (15.19) 29.62 (2.20) (4.89) 22.53 0.10 (2.02) (15.12) 14.39 (2.54) (4.67) 7.18 Cash netbacks increased in 2021 compared to 2020 primarily due to higher realized commodity prices. This was partially offset by increased royalties and realized losses on risk management contracts. Quarter-over-quarter cash netbacks increased primarily due to further increases in commodity prices and a decrease in interest expense offset by an increase in royalties and risk management contract losses. Oil and Gas Sales Three months ended Year ended December 31, 2021 September 30, 2021 December 31, 2020 December 31, 2021 December 31, 2020 Revenue – oil and gas sales ($ 000s) Light oil NGL Conventional natural gas Average realized prices: Light oil ($ per barrel) NGL ($ per barrel) Conventional natural gas ($ per MCF) Average ($ per BOE) Average BOE per day 59,924 5,543 13,735 79,202 85.04 54.54 4.93 62.34 13,810 50,127 4,172 10,158 64,457 78.42 48.86 3.94 55.86 12,542 23,301 2,188 6,272 31,761 47.16 24.78 3.02 34.21 10,091 195,985 16,225 39,406 251,616 74.53 43.86 3.97 54.08 12,747 94,567 7,044 20,031 121,642 44.31 18.65 2.46 31.43 10,575 Revenue from oil and gas sales in 2021 increased by $129.9 million, or 107 percent, compared to the same period in 2020. This increase was primarily driven by a 68 percent increase in Bonterra’s realized crude oil prices paired with a twenty percent increase in production. Quarter-over-quarter, oil and gas sales increased as the Company benefited from further increases in crude oil and NGL prices while natural gas prices also increased by twenty-five percent quarter-over-quarter. Bonterra’s product split on a revenue basis was weighted approximately 84 percent to crude oil and NGLs during 2021. 21 Royalties ($ 000s) Crown royalties Freehold, gross overriding and other royalties Total royalties Crown royalties – percentage of revenue Freehold, gross overriding and other royalties – percentage of revenue Royalties – percentage of revenue Royalties $ per BOE Three months ended Year ended December 31, 2021 September 30, 2021 December 31, 2020 December 31, 2021 December 31, 2020 5,716 3,099 8,815 7.2 3.9 11.1 6.94 4,193 2,926 7,119 6.5 4.5 11.0 6.17 913 1,044 1,957 2.9 3.3 6.2 2.11 15,241 10,509 25,750 6.1 4.2 10.3 5.53 4,104 3,717 7,821 3.4 3.1 6.5 2.02 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 2021 increased by $3.51 per BOE and quarter-over-quarter increased by $0.77 per BOE. The increase in both periods was primarily the result of commodity price improvements. Production Costs ($ 000s except $ per BOE) Production costs $ per BOE Three months ended Year ended December 31, 2021 September 30, 2021 December 31, 2020 December 31, 2021 December 31, 2020 19,951 15.70 16,676 14.45 16,064 17.30 70,670 15.19 58,525 15.12 Production costs for 2021 increased compared to 2020 primarily due to increased production, maintenance costs with more well reactivations from the prior year, an increase in power costs from higher energy rates and increased Alberta government levies as some amounts were waived during 2020. Production costs for Q4 2021 increased from Q3 2021 on per BOE basis. The increase was primarily due to increased maintenance costs as the Company continued to reactivate down wells and more third-party facility maintenance costs. Also, the Company had increased trucking costs on flush production in new areas with limited facility capacity. Other Income ($ 000s) Investment income Administrative income Gain on sale of property Deferred consideration Government grant in-kind Realized gain (loss) on risk management contracts Unrealized gain (loss) on risk management contracts Three months ended Year ended December 31, 2021 September 30, 2021 December 31, 2020 December 31, 2021 December 31, 2020 38 195 225 364 1,009 5 124 - 321 1,470 12 71 - 214 1,689 67 487 225 1,292 5,901 (6,657) (4,856) (540) (17,389) 7,189 2,363 1,763 (1,173) (3,451) (2,005) (968) (10,385) 50 211 - 889 1,689 401 (3,464) (224) 22 Deferred consideration relates to a deferred gain on the sale of a two percent overriding royalty interest, which is recognized into revenue using the same unit-of-production method as the encumbered property, plant, and equipment assets. The market value and carrying value of the investments held by the Company on December 31, 2021 was $891,000 (December 31, 2020 – $295,000). There were no dispositions during the period ended December 31, 2021 or December 31, 2020. Dispositions that result in a gain or loss on sale are recorded as an equity transfer between accumulated other comprehensive income and retained earnings. The Company receives administrative income for various oil and gas administrative services provided and production equipment rentals to other companies. The Government of Alberta’s SRP provides grant funding through service providers to abandon or remediate oil and gas sites. The Company derecognized approximately $5.9 million of asset retirement obligations as an in-kind grant in 2021 (December 31, 2020 – $1.7 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 for the period from January 1, 2022 to December 31, 2022 and are for a total of 601,900 barrels of light crude oil (approximately 1,649 barrels of oil per day for the next twelve months) at fixed WTI prices ranging from $48.00 USD to $81.60 USD per barrel, with a fixed differential from WTI to Edmonton Par prices for 447,500 barrels of oil (approximately 1,226 barrels of oil per day) at prices ranging from approximately $5.80 to $6.55 per barrel. These contracts are not considered normal sales contracts and are recorded at fair value. General and Administrative (“G&A”) Expense ($ 000s except $ per BOE) Employee compensation Office and administrative – recurring Total G&A recurring Office and administrative – nonrecurring Total G&A $ per BOE recurring $ per BOE nonrecurring $ per BOE total Three months ended Year ended December 31, 2021 September 30, 2021 December 31, 2020 December 31, 2021 December 31, 2020 2,461 891 3,352 - 3,352 2.64 - 2.64 1,341 670 2,011 - 2,011 1.74 - 1.74 1,412 1,077 2,489 1,287 3,776 2.68 1.39 4.07 5,924 3,379 9,303 946 10,249 2.00 0.20 2.20 3,903 3,093 6,996 2,818 9,814 1.81 0.73 2.54 Employee compensation expense increased by $2.0 million in 2021 compared to 2020. In 2020, as a result of COVID-19, the Company cutback staffing costs and utilized the Canadian Emergency Wage Subsidy (“CEWS”) government program. The Company did not receive any CEWS payments in Q2, Q3 and Q4 2021. Non-recurring office and administrative costs are expenditures related to successfully defending an unsolicited hostile bid for the Company that expired March 29, 2021. 23 Finance Costs ($ 000s except $ per BOE) Interest on bank debt and subordinated debt Other interest Interest expense $ per BOE Accretion of decommissioning liabilities Accretion on subordinated debentures Total finance costs Three months ended Year ended December 31, 2021 September 30, 2021 December 31, 2020 December 31, 2021 December 31, 2020 3,063 1,109 4,172 3.28 829 410 5,411 4,985 281 5,266 4.56 822 - 6,088 6,566 274 6,840 7.37 800 - 7,640 21,332 1,937 23,269 5.00 3,230 410 26,909 17,353 1,003 18,356 4.74 3,134 - 21,490 Interest on bank debt increased in 2021 compared to 2020 due to an increase in interest rates stemming from the negative effects of COVID-19 on the Company’s net debt to earnings before income taxes and depletion and amortization (or “EBITDA” as defined by the Company’s bank facility) ratio and the interest rate grid for the term portion of the facility. Interest costs were partially offset by a $42.9 million reduction in the average bank debt balance outstanding. Interest rates for the current quarter are determined based on the trailing quarter and calculated by taking the ratio of total debt (excluding accounts payable and accrued liabilities) to EBITDA (defined as net income excluding finance costs, provision for current and deferred taxes, depletion and depreciation, share-option compensation, gain or loss on sale of assets and impairment of assets) multiplied by four. Subordinated debt interest relates to the BDC second lien non-revolving four-year term loan. The Company drew $28 million in Q4 2020 and $17 million in Q1 2021. The loan bears interest at five percent in the first year and increases by one percent per year thereafter. For more information about the subordinated debt, refer to Note 12 of the December 31, 2021 audited annual financial statements. Prior to October 20, 2021, other interest primarily related to amounts paid to a related party and a subordinated promissory note from a private investor (“Subordinated Loans”). For more information about the Subordinated Loans, refer to Note 9 and 10 of the December 31, 2021 audited annual financial statements. On October 20, 2021, the Company issued 32,000 units of senior unsecured debentures (the “Initial Offering”) at a face value of $1,000 per unit. Each unit bears interest at 9 percent per annum and has a four-year term, and includes 56 common share purchase warrants of Bonterra. Each warrant is exercisable to acquire one common share of Bonterra at a price of $7.75 per common share for a period of four years from October 20, 2021 and is subject to customary anti-dilution adjustment until October 20, 2025. In conjunction with the Initial Offering, the Company has also entered into agreements with the holders of its existing Subordinated Loans to convert their principal amounts of an aggregate of $19.5 million into units under the same terms and conditions as the subscribers under the Initial Offering. Concurrent with the closing of the Initial Offering, Bonterra entered into an agreement with the Agents providing for a separate offering of up to $5 million of Units (the “Follow On Offering”), under the same terms and conditions as the Initial Offering. As part of the Follow On Offering, insiders of the Company were given the option to subscribe for up to $1 million in Units. On October 21, 2021, The Company announced an increase to the Follow On Offering to $7.5 million of Units. The Follow On Offering closed on November 10, 2021, and 7,500 units were issued. A total of 59,000 units were issued. For more information on unsecured subordinated debentures see Note 13 of the December 31, 2021 audited annual financial statements. The unsecured subordinated debentures were determined to be a compound instrument with a debt and equity component. The fair value of the debt component of the $59 million in debentures 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 of $9.8 million and issue costs of $2.2 million. The value of the debt will accrete up to the principal balance at maturity. The Company estimated the fair value of $9.8 million or $2.97 per Warrant using the Black-Scholes option pricing model. The Warrants have been recorded net of $2.3 million of deferred taxes in shareholders’ equity. A one percent increase (decrease) in the Canadian prime rate would decrease (increase) both annual net earnings and comprehensive income by approximately $1,618,000. 24 Share-Option Compensation ($ 000s) December 31, 2021 September 30, 2021 December 31, 2020 December 31, 2021 December 31, 2020 Share-option compensation 259 292 194 1,095 438 Three months ended Year ended 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. Share-option compensation increased by $657,000 in 2021 compared to 2020. The increase is primarily due to the 1,200,000 options issued in the fourth quarter of 2020 (which will be fully amortized in 2021). Based on the outstanding options as of December 31, 2021, the Company has an unamortized expense of $287,000, of which $191,000 is in 2022 and $96,000 thereafter. For more information about options issued and outstanding, refer to Note 16 of the December 31, 2021 audited annual financial statements. Depletion and Depreciation, Exploration and Evaluation (“E&E”) and Impairment ($ 000s) December 31, 2021 September 30, 2021 December 31, 2020 December 31, 2021 December 31, 2020 Depletion and depreciation Impairment (reversal of impairment) 22,567 - 21,579 - 14,439 - 76,791 (203,197) 59,225 331,678 Three months ended Year ended The provision for depletion and depreciation (“D&D”) increased in 2021 compared to 2020 primarily due to increased capital spending, higher production volumes and a greater carrying value to deplete from an impairment reversal in 2021. At March 31, 2020 the Company determined that the carrying value of the Company’s Alberta cash generating unit (“CGU”) exceeded its recoverable amount. A total impairment loss of $331.7 million was recognized, with $234.3 million recognized on the Company’s property, plant and equipment ("PP&E"), $92.8 million was applied to the Company’s goodwill and an additional $4.6 million was applied to the Company’s E&E assets. The impairment loss was the result of the COVID-19 pandemic's effect on the forward commodity benchmark prices used in impairment testing at March 31, 2020. On June 30, 2021, the Company performed an impairment test due to higher commodity prices and an increase in the Company’s market capitalization since the impairment loss recognized as at March 31, 2020. A total impairment reversal of $203.2 million was recognized on Bonterra’s Alberta CGU PP&E. The impairment reversal was up to the original carrying value less associated D&D. The impairment charge or reversal does not impact the Company’s cash flow or the amount of credit available under our bank credit facilities. For more information about PP&E, refer to Note 7 of the December 31, 2021 audited annual financial statements. Taxes The Company recorded a deferred income tax expense of $53.7 million (2020 – $60.7 million recovery). The increase in deferred income tax expense for 2021 was primarily due to the impairment reversal recorded at the end of the second quarter of 2021 compared to an impairment provision recorded in the first quarter of 2020. For additional information regarding income taxes, see Note 15 of the December 31, 2021 audited annual financial statements. 25 Net Earnings (Loss) ($ 000s except $ per share) Net earnings (loss) $ per share – basic $ per share – diluted Three months ended Year ended December 31, 2021 September 30, 2021 December 31, 2020 December 31, 2021 December 31, 2020 16,333 0.48 0.46 7,296 0.22 0.21 (11,071) (0.33) (0.33) 179,299 (306,889) 5.32 5.16 (9.19) (9.19) Net earnings for the 2021 increased by $486.2 million compared to 2020. The increase in net earnings was primarily attributed to an impairment reversal recorded in Q2 2021, compared to an impairment provision taken in Q1 2020 due to a recovery of forward commodity benchmark prices since the COVID-19 pandemic in 2020. The impairment provision and reversal was reduced by deferred income taxes. Net earnings also increased from higher oil and gas sales due to improved commodity prices and higher production volumes. Other Comprehensive Income (loss) Other comprehensive income for 2021 consists of an unrealized gain before tax on investments (including investment in a related party) of $598,000 relating to an increase in the investments’ fair value (December 31, 2020 – $7,000). Realized gains result in decreases to accumulated other comprehensive income as these gains are transferred to retained earnings. Other comprehensive income varies from net earnings by unrealized changes in the fair value of Bonterra’s holdings of investments, including the investment in a related party, net of tax. Cash Flow from Operations ($ 000s except $ per share) Cash flow from operations $ per share – basic $ per share – diluted Three months ended Year ended December 31, 2021 September 30, 2021 December 31, 2020 December 31, 2021 December 31, 2020 37,868 1.11 1.07 24,616 0.73 0.71 (1,199) (0.04) (0.04) 96,103 2.85 2.76 32,073 0.96 0.96 In 2021, cash flow from operations increased by $64.0 million compared to the same period in 2020. This was primarily due to an increase in commodity prices and production volumes, which was partially offset by an increase in royalties and an increase in realized risk management contract losses. Quarter-over-quarter, cash flow from operations increased due to an increase in commodity prices and production volumes. Related Party Transaction Bonterra holds 1,034,523 (December 31, 2020 – 1,034,523) common shares in Pine Cliff Energy Ltd. (“Pine Cliff”) which represents less than one percent ownership in Pine Cliff’s outstanding common shares. Pine Cliff’s common shares had a fair market value as of December 31, 2021 of $703,000 (December 31, 2020 – $233,000). 26 Liquidity and Capital Resources Net Debt to Cash Flow from Operations Bonterra continues to focus on reducing overall debt while managing its cash flow and capital expenditures. The Company’s net debt to twelve-month trailing cash flow ratio as of December 31, 2021 was 2.8 to 1 times (versus 9.8 to 1 times at December 31, 2020). The decreased net debt to cash flow ratio is the result of an increase in the Company’s twelve-month trailing cash flow that is primarily due to the economic recovery since the effect of the COVID-19 pandemic on crude oil prices and higher production volumes. Compared to the first twelve months of 2020, net debt at December 31, 2021 decreased by $48.4 million due to a 200 percent increase in cash flow from increased commodity prices and production volumes and a $7 million flow through share issuance. In addition, the fair value of the warrants of $9.8 million and $2.2 million of issuance costs reduced the carrying value of the subordinated debentures issued which reduced net debt. Bonterra will continue to assess its capital expenditures compared to cash flow from operations on a quarterly basis. Working Capital Deficiency and Net debt ($ 000s) Working capital deficiency Subordinated debt Net Debt December 31, 2021 December 31, 2020 172,552 94,627 267,179 287,412 28,161 315,573 Net debt is a combination of subordinated debt and working capital. As of December 31, 2021, the Company’s bank facility has a maturity date of May 31, 2022 and is recorded as a current liability. 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 in order to meet its future liabilities. Net debt for December 31, 2021 decreased by $48.4 million compared to December 31, 2020 primarily due to increased cash flow with rising commodity prices and higher production volumes. The Company also raised $46.5 million of new debt and equity financing from the issuance of $39.5 million of unsecured subordinated debentures (excluding $19.5 million of subordinated debentures issued to extinguish Subordinated Loans) and $7 million flow through share issuance. With commodity prices remaining strong to date in 2022, the Company intends to continue its focus on reducing net debt. The fair value of the warrants of $9.8 million and $2.2 million of issuance costs reduced the carrying value of the subordinated debentures which reduced net debt. The difference between the carrying value and face value of the subordinated debentures will be accreted to face value over the life of the debenture. For additional information on subordinated debentures, see Note 13 of the December 31, 2021 audited annual financial statements. Working capital is calculated as current assets less current liabilities. Included in the working capital deficiency as at December 31, 2021 is $162.9 million of bank debt. On October 20, 2021 (the “Conversion Date”), $7.5 million of the current subordinated promissory note and $12.0 million of the due to related party loan were exchanged for long-term unsecured subordinated debentures plus warrants (for more information on the Subordinated Loans see Note 10 and 11 of the December 31, 2021 audited annual financial statements). 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 affected by North American supply and demand fundamentals. In order to manage commodity risk, in 2021 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 in addition 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 for the next twelve months. The Company relies on its cash flow, access to equity markets and bank financing to support its operations and capital program. Bonterra uses these futures contracts to hedge its exposure to the potential adverse impact of commodity price volatility and provide a measure of stability to Bonterra’s capital development program. For more information on physical delivery and risk management contracts in place see Note 20 of the December 31, 2021 audited annual financial statements. 27 Capital Expenditures During the year ended December 31, 2021, the Company incurred capital expenditures of $67.3 million (December 31, 2020 – $43.7 million). Of the total capital invested, $52.5 million was directed to the drilling of 39 gross (35.8 net) wells and the completion, equip and tie-in of 37 gross (33.6 net) wells, of which four of the completed and equipped wells were drilled in 2020. Of the wells drilled in 2021, 33 (29.9 net) have been placed on production as of December 31, 2021. An additional $14.7 million was spent primarily on related infrastructure and recompletions. Decommissioning Liabilities Bonterra participates in the province of Alberta’s Voluntary Closure Target program (“VCT”) (formerly the Area-Based Closure program) to reduce abandonment and reclamation costs and liabilities. This program provides numerous incentives to efficiently manage decommissioning liabilities that reduce overall cost. In 2021, the Company exceeded its annual commitment under the VCT program of approximately $3.3 million by $1.2 million or $4.5 million in total on its inactive wells, pipelines and facilities excluding any Alberta SRP funding. The Company’s mandatory target under the VCT program for 2022 is $3.7 million. The VCT program also sets an upper limit voluntary spend target that comes with additional incentives. The voluntary target under the VCT is set at $3.9 million for 2022 and Bonterra expects to meet or exceed this amount. Bank Debt Bank debt represents the outstanding amounts drawn on the Company’s bank facility. On October 20, 2021 the Company entered into its Fourth Amended and Restated Credit Agreement (“ARCA”). As at December 31, 2021, the ARCA represents a total bank facility of $210.0 million, comprised of a $185.0 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, 2021 was $162.9 million (December 31, 2020 – $252.3 million). The amounts borrowed under the total bank facility bear interest at a floating rate based on the applicable Canadian prime rate or Banker’s Acceptance rate, plus between 2.00 percent and 7.00 percent, depending on the type of borrowing and the Company’s consolidated debt to EBITDA ratio. EBITDA is defined as net income for the period excluding finance costs, provision for current and deferred taxes, depletion and depreciation, share-option compensation, gain or loss on sale of assets and impairment of assets. The terms of the total revolving bank facility provide that the loan facility is revolving to May 31, 2022, with a maturity date of November 30, 2022. The available lending limit of the bank facility is scheduled to be reviewed before May 31, 2022. The syndicated revolving credit facility has a $10.0 million reduction on March 31, 2022. Under the ARCA, the Company is restricted from making any payment of dividend distributions. In addition, the Company is also limited to expenditures on an annual basis which cannot: ■ exceed 110 percent or be less than 90 percent of the forecasted decommissioning expenditures settled; and ■ exceed 110 percent of the forecasted capital expenses. As at December 31, 2021, Bonterra classified its bank debt as a current liability and had a working capital deficiency. The Company was in compliance with all financial covenants on its total bank facility as at December 31, 2021. After examining the economic factors that are causing the liquidity risk facing the Company, the judgment applied to these factors, and the various initiatives that the Company has and will undertake to strengthen its financial position, the Company believes it will have sufficient liquidity to support its ongoing operations and meet its current financial obligations as they come due for at least the next twelve months. There can be no assurance that the next bank review will not result in a material reduction in the borrowing base, and that the necessary funds will be available to meet its obligations as they become due, subject to other alternative sources of financing. Advances drawn under the bank facility are secured by a fixed and floating charge debenture over the assets of the Company. In the event the bank facility is not extended or renewed, amounts drawn under the facility would be due and payable on the maturity date. The size of the committed credit facilities is based primarily on the value of the Company’s producing petroleum and natural gas assets and related tangible assets as determined by the lenders. For more information see Note 11 of the December 31, 2021 audited annual financial statements. The amount available for borrowing under the bank facility is reduced by outstanding letters of credit. Letters of credit totaling $1.4 million were issued as at December 31, 2021 (December 31, 2020 – $1.3 million). Security for the bank facility consists of various floating demand debentures totaling $750 million (December 31, 2020 – $750 million) over all of the Company’s assets and a general security agreement with first ranking over all personal and real property. 28 Shareholders’ Equity The Company is authorized to issue an unlimited number of common shares without nominal or par value. The Company is also authorized to issue an unlimited number of Class “A” redeemable Preferred Shares and an unlimited number of Class “B” Preferred Shares. There are currently no outstanding Class “A” redeemable Preferred Shares or Class “B” Preferred Shares. Issued and fully paid – common shares Balance, beginning of year Shares issued for interest on subordinated promissory note Issued pursuant to the Company's share option plan Transfer from contributed surplus to share capital Issuance of flow through shares Premium on flow through shares Share issue costs, net of tax Balance, end of year December 31, 2021 December 31, 2020 Number 33,511,316 118,896 183,740 1,187,000 Amount ($ 000s) 765,415 414 378 168 7,003 (356) (241) Number 33,388,796 122,520 - - Amount ($ 000s) 765,276 139 - - - - - 35,000,952 772,781 33,511,316 765,415 On December 9, 2021, the Company raised $7.0 million by issuing 1,187,000 common shares on a flow through basis through a private placement financing. Proceeds of the offering are to be used for qualifying development expenditures during the first quarter of 2022. At December 31, 2021, Bonterra had not incurred the required expenditures. The Company has filed the renouncement documents subsequent to year-end. The premium component of the flow-through shares is calculated as $356,000 and is set up as a current liability in accounts payable and accrued liabilities. This amount will be netted against the Company’s deferred tax liability in the first quarter of 2022. The Company provides a stock option plan for its directors, officers and employees. Under the plan, the Company may grant options for up to 3,500,095 (December 31, 2020 – 3,351,131) common shares. The exercise price of each option granted will not be lower than the market price of the common shares on the date of grant and the option’s maximum term is five years. On February 18, 2022, the Company granted 965,000 share options to employees and directors with an exercise price of $9.00, based on the market price immediately preceding the date of grant. The share options vests between one and three years from the grant date and expire on February 18, 2027. For additional information regarding options outstanding, see Note 16 of the December 31, 2021 audited annual financial statements. On October 20, 2021, unsecured subordinated debentures were issued with the Initial Offering and Follow On Offering, that resulted in a total of 3,304,000 warrants being issued and outstanding over the next four years. Each warrant can be exercised to acquire one common share of Bonterra at a price of $7.75 per common share and is subject to customary anti-dilution adjustment until October 20, 2025. For more information on unsecured subordinated debentures see Note 13 of the December 31, 2021 audited annual financial statements. Dividend Policy For the year ended December 31, 2021, the Company did not declare or pay any dividends (December 31, 2020 – $1,002,000) ($0.03 per share). On March 10, 2020, the Company’s Board of Directors elected to suspend its monthly dividend, commencing on April 1, 2020. 29 Quarterly Financial Information For the periods ended ($ 000s except $ per share) Revenue – oil and gas sales Cash flow from operations Net earnings (loss) Per share – basic Per share – diluted For the periods ended ($ 000s except $ per share) Revenue – oil and gas sales Cash flow from operations Net earnings (loss) Per share – basic Per share – diluted Q4 79,202 37,868 16,333 0.48 0.46 Q4 31,761 (1,199) (11,071) (0.33) (0.33) 2021 Q3 64,457 24,616 7,296 0.22 0.21 2020 Q3 29,155 6,370 (5,211) (0.16) (0.16) Q2 59,163 18,874 157,354 4.68 4.55 Q2 22,171 4,429 (5,954) (0.18) (0.18) Q1 48,794 14,745 (1,684) (0.05) (0.05) Q1 38,555 22,473 (284,653) (8.53) (8.53) 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. In 2020, the Company’s net earnings and cash flow significantly decreased mainly due to the effect of the COVID-19 pandemic on crude oil demand. With the utilization of the BDC funding for the Company’s capital program and well reactivation costs in the fourth quarter of 2020, the Company increased production, net earnings and cash flow from operations in the quarters subsequent to December 31, 2020. Net loss for Q1 2020 and net earnings in Q2 2021 were significantly higher than other quarters due to an impairment provision and reversal on the Company’s Alberta cash generating unit. Contractual Obligations and Commitments At December 31, 2021, the Company has the following contractual obligations and commitments: ($ 000s) Accounts payable and accrued liabilities Bank Debt Subordinated debt(1) Subordinated debentures(1) Future interest Firm service commitments Office lease commitments Total (1) Principal amount. Over 1 year to 3 years Over 3 years to 5 years Over 5 years to 7 years Less than 1 year 35,194 162,945 - - 8,191 489 526 - - 47,029 - 17,263 805 463 - - - 59,000 4,204 220 498 207,345 65,560 63,922 - - - - - 15 988 1,003 Total 35,194 162,945 47,029 59,000 29,657 1,529 2,475 337,829 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 21 of the December 31, 2021 audited annual financial statements. 30 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 service which may limit market price of shares, financial and liquidity risks and environmental and safety risks. The Company mitigates its risk related to producing hydrocarbons through the utilization of current technology and information systems. In addition, Bonterra strives to operate the majority of its properties, thereby maintaining operational control where possible. The Company’s business, operations and financial condition has been significantly adversely affected by COVID-19. Actions taken to reduce the spread of COVID-19 have resulted in volatility and disruptions in regular business operations, supply chains and financial markets. COVID-19 also poses a risk on the financial capacity of Bonterra’s contract counterparties and potentially their ability to perform contractual obligations. These difficulties have been exacerbated in Canada by political and other actions resulting in uncertainty surrounding regulatory, tax, royalty changes and environmental regulation. Additional information regarding risk factors including, but not limited to, business risks is available in our Annual Information Form for the year ended December 31, 2021, which can be accessed on our website www.bonterraenergy.com or on SEDAR at www.sedar.com. Environmental Risk General Risks Oil and gas exploration and production can involve environmental risks such as litigation, physical and regulatory risks. Physical risks include the pollution of the environment, climate change and destruction of natural habitat, as well as safety risks such as personal injury. The Company conducts its operations and ensures to protect the environment, its 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 Our exploration and production facilities and other operations and activities emit greenhouse gasses ("GHG") which require us to comply with federal and/or provincial GHG emissions legislation. Climate change policy is evolving at regional, national and international levels, and political and economic events may significantly affect the scope and timing of climate change measures that are ultimately put in place to prevent climate change or mitigate our effects. The direct or indirect costs of compliance with GHG-related regulations may have a material adverse effect on our business, financial condition, results of operations and prospects. Some of our 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 our Annual Information Form for the year ended December 31, 2021, which can be accessed on our website www.bonterraenergy.com or on SEDAR at www.sedar.com. 31 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: 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; and maintenance of existing customer, supplier and partner relationships; supply channels; accounting policies; credit risks; climate change risks; cyber security; impact of COVID-19; 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 are interpreted and enforced; the ability of oil and natural gas companies to raise capital or maintain its syndicated bank facility; 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; 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. 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, 2021. 32 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. 2. 3. Pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect transactions and dispositions of Bonterra; 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 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, 2021. 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. 33 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. George F. Fink Chief Executive Officer March 9, 2022 Robb D. Thompson Chief Financial Officer March 9, 2022 34 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, 2021 and 2020, 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, 2021 and 2020, 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, 2021. 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 7 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. 35 How the Key Audit Matter Was Addressed in the Audit Our audit procedures related to future crude oil and natural gas prices, discount rates, reserves, and future operating and development costs used to measure oil and gas properties included the following, among others: ■ Evaluated future crude oil and natural gas prices by independently developing a reasonable range of forecasts based on reputable third-party forecasts and market data and comparing those to the future crude oil and natural gas prices selected by management. ■ Evaluated the reasonableness of the discount rates by testing the source information underlying the determination of the discount rates and developing a range of independent estimates and comparing those to the discount rates selected by management. ■ Evaluated the Company’s independent reserve evaluator by examining reports and assessed their scope of work and findings; and assessing the competence, capability and objectivity by evaluating their relevant professional qualifications and experience. ■ Evaluated the reasonableness of reserves by testing the source financial information underlying the reserves and comparing the reserve volumes to historical production volumes. ■ Evaluated the reasonableness of future operating and development costs by testing the source financial information underlying the estimate, comparing future operating and development costs to historical results, and evaluating whether they are consistent with evidence obtained in other areas of the audit. ■ Performed a retrospective review to evaluate management’s ability to accurately forecast and to assess for indications of estimation bias over time. Other Information Management is responsible for the other information. The other information comprises : ■ Management’s Discussion and Analysis ■ The information, other than the financial statements and our auditor’s report thereon, in the Annual Report. Our opinion on the financial statements does not cover the other information and we do not and will not express any form of assurance conclusion thereon. In connection with our audit of the financial statements, our responsibility is to read the other information identified above and, in doing so, consider whether the other information is materially inconsistent with the financial statements or our knowledge obtained in the audit, or otherwise appears to be materially misstated. We obtained Management’s Discussion and Analysis prior to the date of this auditor’s report. If, based on the work we have performed on this other information, we conclude that there is a material misstatement of this other information, we are required to report that fact in this auditor’s report. We have nothing to report in this regard. The Annual Report is expected to be made available to us after the date of the auditor’s report. If, based on the work we will perform on this other information, we conclude that there is a material misstatement of this other information, we are required to report that fact to those charged with governance. 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. 36 Auditor’s Responsibilities for the Audit of the Financial Statements Our objectives are to obtain reasonable assurance about whether the financial statements as a whole are free from material misstatement, whether due to fraud or error, and to issue an auditor’s report that includes our opinion. Reasonable assurance is a high level of assurance, but is not a guarantee that an audit conducted in accordance with Canadian GAAS will always detect a material misstatement when it exists. Misstatements can arise from fraud or error and are considered material if, individually or in the aggregate, they could reasonably be expected to influence the economic decisions of users taken on the basis of these financial statements. As part of an audit in accordance with Canadian GAAS, we exercise professional judgment and maintain professional skepticism throughout the audit. We also: ■ Identify and assess the risks of material misstatement of the financial statements, whether due to fraud or error, design and perform audit procedures responsive to those risks, and obtain audit evidence that is sufficient and appropriate to provide a basis for our opinion. The risk of not detecting a material misstatement resulting from fraud is higher than for one resulting from error, as fraud may involve collusion, forgery, intentional omissions, misrepresentations, or the override of internal control. ■ Obtain an understanding of internal control relevant to the audit in order to design audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of the Company’s internal control. ■ Evaluate the appropriateness of accounting policies used and the reasonableness of accounting estimates and related disclosures made by management. ■ Conclude on the appropriateness of management’s use of the going concern basis of accounting and, based on the audit evidence obtained, whether a material uncertainty exists related to events or conditions that may cast significant doubt on the Company’s ability to continue as a going concern. If we conclude that a material uncertainty exists, we are required to draw attention in our auditor’s report to the related disclosures in the financial statements or, if such disclosures are inadequate, to modify our opinion. Our conclusions are based on the audit evidence obtained up to the date of our auditor’s report. However, future events or conditions may cause the Company to cease to continue as a going concern. ■ Evaluate the overall presentation, structure and content of the financial statements, including the disclosures, and whether the financial statements represent the underlying transactions and events in a manner that achieves fair presentation. 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. Chartered Professional Accountants Calgary, Alberta March 9, 2022 Statement of Financial Position 37 As at ($ 000s) ASSETS CURRENT Accounts receivable Crude oil inventory Prepaid expenses Investments Investment in related party Exploration and evaluation assets Property, plant and equipment Investment tax credit receivable LIABILITIES CURRENT Accounts payable and accrued liabilities Risk management contract Due to related party Subordinated promissory note Bank debt Deferred consideration Subordinated debt Subordinated debentures Deferred consideration Decommissioning liabilities Deferred tax liability SHAREHOLDERS' EQUITY Share capital Contributed surplus Warrants Accumulated other comprehensive loss Deficit Note December 31, 2021 December 31, 2020 5 6 7 15 8 20 9 10 11 12 13 14 15 16 13 24,215 988 5,922 188 31,313 703 1,994 902,850 8,861 945,721 35,194 4,567 - - 162,945 1,159 203,865 47,268 47,359 10,089 135,815 109,306 553,702 772,781 31,599 7,265 (221) (419,405) 392,019 945,721 12,891 598 3,920 62 17,471 233 373 704,921 8,861 731,859 28,229 3,599 12,366 7,604 252,255 830 304,883 28,161 - 11,709 137,002 53,471 535,226 765,415 30,672 - (750) (598,704) 196,633 731,859 Commitments and contingencies Subsequent events 21 16, 20 See accompanying notes to these financial statements. On behalf of the Board: George F. Fink Director Rodger A. Tourigny Director 38 Statement of Comprehensive Income FOR THE YEAR ENDED DECEMBER 31 ($ 000s, except $ per share) REVENUE Oil and gas sales, net of royalties Other income Deferred consideration Loss on risk management contracts EXPENSES Production Office and administration Employee compensation Finance costs Share-option compensation Depletion and depreciation Impairment (reversal of impairment) EARNINGS (LOSS) BEFORE INCOME TAXES TAXES Deferred income tax expense (recovery) NET EARNINGS (LOSS) FOR THE YEAR OTHER COMPREHENSIVE INCOME (LOSS) Unrealized gain on investments Deferred taxes on unrealized gain on investments OTHER COMPREHENSIVE INCOME (LOSS) FOR THE YEAR TOTAL COMPREHENSIVE INCOME (LOSS) FOR THE YEAR NET EARNINGS (LOSS) PER SHARE – BASIC NET EARNINGS (LOSS) PER SHARE – DILUTED COMPREHENSIVE INCOME (LOSS) PER SHARE – BASIC COMPREHENSIVE INCOME (LOSS) PER SHARE – DILUTED See accompanying notes to these financial statements. Note 2021 2020 17 18 20 22 19 7 7 15 16 16 16 16 225,866 6,680 1,292 (18,357) 215,481 70,670 4,325 5,924 26,909 1,095 76,791 (203,197) (17,483) 232,964 53,665 53,665 179,299 598 (69) 529 113,821 1,950 889 (3,063) 113,597 58,525 5,911 3,903 21,490 438 59,225 331,678 481,170 (367,573) (60,684) (60,684) (306,889) 7 (9) (2) 179,828 (306,891) 5.32 5.16 5.33 5.17 (9.19) (9.19) (9.19) (9.19) Statement of Cash Flow 39 FOR THE YEARS ENDED DECEMBER 31 ($ 000s) OPERATING ACTIVITIES Net earnings (loss) Items not affecting cash Deferred income taxes expense (recovery) Share-option compensation Investment income Finance costs Unrealized loss on risk management contracts Deferred consideration Depletion and depreciation Government grant in-kind Impairment (reversal of impairment) Gain on sale of property and equipment Decommissioning expenditures Interest paid Changes in non-cash working capital accounts CASH PROVIDED BY OPERATING ACTIVITIES FINANCING ACTIVITIES Increase (decrease) of bank debt Subordinated debt Subordinated debentures, net of issuance costs Flow through shares, net of issuance costs Stock option proceeds Dividends CASH PROVIDED BY (USED IN) FINANCING ACTIVITIES INVESTING ACTIVITIES Investment income received Exploration and evaluation expenditures Property, plant and equipment expenditures Proceeds on sale of property Changes in non-cash working capital accounts CASH USED IN INVESTING ACTIVITIES NET CHANGE IN CASH IN THE YEAR Cash, beginning of year CASH, END OF YEAR See accompanying notes to these financial statements. Note 2021 2020 179,299 (306,889) 19 20 7 22 14 19 19 6 7 19 53,665 1,095 (67) 26,909 968 (1,292) 76,791 (5,901) (203,197) (225) (4,496) (21,217) (6,229) 96,103 (89,310) 17,000 36,887 6,690 378 - (28,355) 67 (1,621) (65,661) 225 (758) (67,748) - - - (60,684) 438 (50) 21,491 3,465 (889) 59,225 (1,689) 331,678 - (2,706) (17,587) 6,270 32,073 (20,810) 28,000 - - - (1,002) 6,188 50 (959) (42,769) - 5,417 (38,261) - - - 40 Statement of Changes in Equity FOR THE YEARS ENDED ($ 000s, except number of shares outstanding) Numbers of Common Shares Outstanding (Note 16) Share Capital (Note 16) Contributed Surplus(1) Warrants Accumulated Other Comprehensive Loss(2) Total Shareholders' Equity Deficit JANUARY 1, 2020 33,388,796 765,276 30,234 - (748) (290,813) 503,949 Share-option compensation Shares issued for subordinated promissory note interest Comprehensive loss Dividends 122,520 139 DECEMBER 31, 2020 33,511,316 765,415 Share-option compensation Shares issued for subordinated promissory note interest Exercise of options Transfer to share capital on exercise of options Comprehensive income Issuance of warrants (Note 13) Deferred tax on issuance of warrants (Note 13) 118,896 183,740 414 378 168 438 30,672 1,095 (168) Issuance of flow through shares 1,187,000 7,003 Premium on flow through shares Share issue costs net of tax (356) (241) DECEMBER 31, 2021 35,000,952 772,781 31,599 (1) All amounts reported in Contributed Surplus relate to share-option compensation. 9,810 (2,259) (286) 7,265 438 139 (2) (306,889) (306,891) - (750) (598,704) (1,002) 529 179,299 (1,002) 196,633 1,095 414 378 - 179,828 9,810 (2,259) 7,003 (356) (527) (221) (419,405) 392,019 (2) Accumulated other comprehensive income is comprised of unrealized gains and losses on investments fair value through other comprehensive income. See accompanying notes to these financial statements. 41 Notes to the Financial Statements As at and for the years ended December 31, 2021 and December 31, 2020. 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. Bonterra operates in one industry and has only one reportable segment which is the development and production of oil and natural gas in the Western Canadian Sedimentary Basin. 2. Basis of Preparation and Future Operations a) Statement of Compliance These financial statements have been prepared by management in accordance with International Financial Reporting Standards (IFRS). The financial statements were authorized for issue by the Company’s Board of Directors on March 9, 2022. b) Basis of Measurement These financial statements have been prepared on a historical cost basis, except for certain financial instruments and share-based payment transactions which are measured at fair value. c) Functional and Presentation Currency The Company’s functional and presentation currency is the Canadian dollar. Foreign currency denominated monetary assets and liabilities are translated into Canadian dollars at the rates prevailing on the reporting date. Non-monetary assets and liabilities are translated into Canadian dollars at the rates prevailing on the transaction dates. Exchange gains and losses are recorded as income or expense in the period in which they occur. d) Significant Accounting Estimates and Judgments The timely preparation of financial statements requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities as at the date of the statement of financial position as well as the reported amounts of revenues, expenses and cash flows during the periods presented. Such estimates relate primarily to unsettled transactions and events as of the date of the financial statements. Actual results could differ materially from estimated amounts. See Note 4 for more information. 42 3. Significant Accounting Policies a) Revenue Recognition Revenue associated with the sale of crude oil, natural gas and natural gas liquids is measured based on the consideration specified in contracts with customers. Revenue from contracts with customers is recognized when or as Bonterra satisfies a performance obligation by transferring a promised good or service to a customer. A good or service is transferred when the customer obtains control of that good or service. The transfer of control of oil, natural gas, and natural gas liquids usually coincides with title passing to the customer and the customer taking physical possession. The Company principally satisfies its performance obligations at a point in time and the amounts of revenue recognized relating to performance obligations satisfied over time are not significant. Collection of revenue associated with the sale of crude oil, natural gas and natural gas liquids occurs on or about the 25th of the month following production. Items such as royalties for crown, freehold, gross overriding (GORR) and Saskatchewan surcharge are netted against revenue. These items are netted to reflect the deduction for other parties’ proportionate share of the revenue. Administration fee income is recorded when services are provided. b) Joint Arrangements Certain exploration, development and production activities are conducted jointly with others. These financial statements reflect only the Company’s interests in such activities. A jointly controlled operation involves the use of assets and other resources of the Company and those of other joint venture participants through contractual arrangements rather than through the establishment of a corporation, partnership or other entity. The Company has no interests in jointly controlled entities. The Company recognizes in its financial statements its interest in assets that it owns, the liabilities and expenses that it incurs, and its share of income earned by the joint arrangement. c) Inventories Inventories consist of crude oil. Crude oil stored in the Company’s tanks is valued on a first-in, first-out basis at the lower of cost or net realizable value. The inventory cost for crude oil is determined based on the combined average per barrel operating costs, and depletion and depreciation for the period, while net realizable value is determined based on estimated sales price less transportation costs. d) Investments and Investment in Related Party Investments and investment in related party 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. 43 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 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 Declining balance method at 10 percent per year Furniture, fixtures and other equipment Declining balance method at 10 to 20 percent per year Right of use assets 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. Impairment of Assets h) 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. 44 Impairment of Non-Financial Assets The carrying amounts of the Company's non-financial assets are reviewed at the end of each reporting period to determine whether there is any indication of impairment. If such indication exists, then the assets’ carrying amounts are assessed for impairment. For the purpose of impairment testing, assets (which include E&E, PP&E and goodwill) are grouped together into the smallest group of assets that generate cash flows from continuing use which are largely independent of the cash flow of other assets or groups of assets (the cash-generating unit or “CGU”). Goodwill is allocated to the CGU expected to benefit from the synergies of the combination. The recoverable amount of an asset or a CGU is the greater of its value-in-use (“VIU”) and its fair value less costs to sell (“FVLCS”). The Company has a core CGU composed of its Alberta properties and secondary CGUs for its British Columbia (BC) and Saskatchewan properties. An impairment loss is recognized if the carrying amount of an asset or its CGU exceeds its recoverable amount. Impairment losses are recognized in the statement of comprehensive income (loss). Impairment losses recognized in respect of a CGU are allocated first to reduce the carrying amount of any goodwill allocated to the CGU and then to reduce the carrying amount of the other assets of the CGU on a pro-rata basis. In respect of assets other than goodwill, impairment losses recognized in prior periods are assessed at each reporting date for any indications that the impairment loss has reversed. If the amount of the impairment loss reverses in a subsequent period and the reversal can be objectively related to an event occurring after the impairment was recognized, the impairment loss is reversed only to the extent that the asset's carrying amount does not exceed the carrying amount that would have been determined, net of depletion and depreciation, if no impairment loss had been recognized and recorded in the statement of comprehensive income (loss). An impairment loss in respect of goodwill cannot be reversed. i) Deferred Consideration Deferred consideration is generated when a sale of a royalty interest linked to production at a specific property occurs. Consideration is given to the specific terms of each arrangement to determine whether a disposal of an interest in the reserves of the respective property has occurred and whether the counterparty is entitled to the associated risks and rewards attributable to the property over its estimated life. These include the contractual terms and implicit obligations related to production, such as the holder of the royalty having the option of either being paid in cash or in kind and the associated commitments, if any, to develop future expansions or projects at the property. Proceeds for sale of a royalty interest on petroleum properties are then attributed to two components: a payment for partial disposal of an interest in PP&E; and an upfront payment received for future extraction services that will generate future royalties. Discounted future cash flows of future development and operating costs multiplied by the royalty rate are used to derive the upfront payment received for future extraction services, which is accounted for as deferred consideration and recognized as revenue over the reserve life of the encumbered properties (as this represents the efforts incurred towards the extraction performance obligation). Upon commencement of the royalty interest the deferred consideration is depleted (recognized into revenue) using the same unit-of-production method as the depletion of the encumbered PP&E asset’s carrying value. j) Decommissioning Liabilities The fair value of the statutory, contractual, constructive or legal liabilities associated with the retirement and reclamation of oil and gas properties is recorded when incurred, with a corresponding increase to the carrying amount of the related PP&E. The amount recognized is the estimated cost of decommissioning, discounted to its present value using the Company’s risk-free rate. Changes in the estimated timing of decommissioning or decommissioning cost estimates and changes to the risk-free rates are dealt with prospectively by recording an adjustment to the decommissioning liabilities, and a corresponding adjustment to PP&E. The unwinding of the discount on the decommissioning provision is charged to net earnings as a finance cost. The Company recognizes a decommissioning liability in the period in which it is incurred when a reasonable estimate of the liability can be made. On a periodic basis, management will review these estimates and changes and if there are any, they will be applied prospectively. The fair value of the estimated provision is recorded as a long-term liability, with a corresponding increase in the carrying amount of the related asset. The capitalized amount is depleted on a unit-of-production basis over the life of the proved plus probable developed reserves. The liability amount is increased each reporting period due to the passage of time and this amount is charged to earnings in the period. Actual costs incurred upon settlement of the obligations are charged against the provision to the extent of the liability recorded and any remaining balance of actual costs is recorded in the statement of comprehensive income (loss). 45 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. 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. 46 n) Fair Value Measurement Financial instruments consisting of accounts receivable, accounts payable and accrued liabilities, due to related party, subordinated promissory note and bank debt on the statement of financial position are carried at amortized cost. Investments and investment in related party are carried at fair value. All of the investments are transacted in active markets. Bonterra determines the fair value of these transactions according to the following hierarchy based on the amount of observable inputs used to value the instrument. Level 1 – Quoted prices are available in active markets for identical assets or liabilities as of the reporting date. Active markets are those in which transactions occur in sufficient frequency and volume to provide pricing information on an ongoing basis. Level 2 – Pricing inputs are other than quoted prices in active markets included in Level 1. Prices in Level 2 are either directly or indirectly observable as of the reporting date. Level 2 valuations are based on inputs, including quoted forward prices for commodities, time value and volatility factors, which can be substantially observed or corroborated in the marketplace. Level 3 – Valuations in this level are those with inputs for the asset or liability that are not based on observable market data. Bonterra’s investments and investments in related party have been assessed on the fair value hierarchy described above and are all considered Level 1. o) Risk Management Contracts The Company is exposed to market risks resulting from fluctuations in commodity prices, foreign currency exchange rates and interest rates in the normal course of its business. The Company may use a variety of instruments to manage these exposures. For transactions where hedge accounting is not applied, the Company accounts for such instruments using the fair value method by initially recording an asset or liability and recognizing changes in the fair value of the instruments in earnings as unrealized gains or losses on risk management contracts. Fair values of financial instruments are based on third party quotes or valuations provided by independent third parties. Any realized gains or losses on risk management contracts are recognized in net earnings in the period they occur. Bonterra’s risk management contracts have been assessed on the fair value hierarchy described above and are all considered Level 2. p) Net Earnings and Comprehensive Income Per Share Per share amounts are calculated by dividing the net earnings or comprehensive income (loss) attributable to common shareholders of the Company by the weighted average number of common shares outstanding during the reporting period. Diluted per share amounts are calculated similar to basic per share amounts except that the weighted average common shares outstanding are increased to include additional common shares from the assumed exercise of dilutive share-options. The number of additional outstanding common shares is calculated by assuming that the outstanding in-the-money share-options were exercised and that the proceeds from such exercises were used to acquire common shares at the average market price during the reporting period. 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. 47 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, PP&E, and goodwill 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, PP&E, and goodwill 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: 1) The net present value of the pre-tax cash flows from oil and gas reserves of each CGU based on 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) b) c) 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. 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. 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. 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. 48 Share-option Compensation The Company measures the cost of equity-settled transactions with employees by reference to the fair value of the equity instruments at the date they are granted. Estimating the fair value requires the determination of the most appropriate valuation model for a grant, which is dependent on the terms and conditions of the grant. This also requires the determination of the most appropriate inputs to the valuation model including the expected life of the option, risk-free interest rates, volatility and dividend yield. Deferred Consideration Deferred consideration is incurred when the sale of a royalty interest occurs that has contractual terms or implicit obligations that requires future performance such future development costs and operating costs. Management uses judgments in determining those cash flows such as cost, inflation and the discount rate to determine the portion of proceeds that is deferred. Decommissioning and Restoration Costs Decommissioning and restoration costs will be incurred by the Company at the end of the operating lives of the Company’s oil and gas properties. Provisions for decommissioning liabilities are based on cost estimates which can vary in response to many factors including timing of abandonment, inflation, changes in legal requirements, new restoration techniques and interest rates. Income Taxes The Company recognizes the net deferred tax benefit or expense related to deferred income tax assets or liabilities to the extent that it is probable that the deductible temporary differences will reverse in the foreseeable future. Assessing the recoverability of investment tax credit receivable requires the Company to make significant estimates related to expectations of future taxable income. The provision for income taxes is based on judgments in applying income tax law and estimates of the timing, likelihood and reversal of temporary differences between the accounting and tax basis of assets and liabilities. The ability to realize on the deferred tax assets and investment tax credit receivable that are recorded on the balance sheet may be compromised to the extent that any interpretation of tax law is challenged or taxable income differs significantly from estimates. Further details regarding accounting estimates and judgments are disclosed in Note 3. 5. Investment in Related Party The investment consists of 1,034,523 (December 31, 2020 – 1,034,523) common shares in Pine Cliff Energy Ltd. (“Pine Cliff”), a company with some common directors with Bonterra. The investment in Pine Cliff represents less than one percent ownership in the outstanding common shares of Pine Cliff and is recorded at fair value through other comprehensive income. The common shares of Pine Cliff trade on the TSX under the symbol PNE. 6. Exploration and Evaluation Assets ($ 000s) COST AND CARRYING AMOUNT Balance at January 1, 2020 Additions Impairment (Note7) BALANCE AT DECEMBER 31, 2020 Additions BALANCE AT DECEMBER 31, 2021 3,980 959 (4,566) 373 1,621 1,994 49 7. Property, Plant and Equipment COST ($ 000s) Balance at January 1, 2020 Additions Adjustment to decommissioning liabilities (Note 14) BALANCE AT DECEMBER 31, 2020 Additions Adjustment to decommissioning liabilities (Note 14) Disposal Oil and Gas Properties Production Facilities Furniture Fixtures & Other Equipment Total Property Plant & Equipment 1,426,923 30,550 92 1,457,565 44,505 5,980 - 357,408 12,177 - 369,585 21,140 - - 2,255 1,786,586 42 - 42,769 92 2,297 1,829,447 16 - (3) 65,661 5,980 (3) BALANCE AT DECEMBER 31, 2021 1,508,050 390,725 2,310 1,901,085 ACCUMULATED DEPLETION AND DEPRECIATION ($ 000s) Oil and Gas Properties Production Facilities Furniture Fixtures & Other Equipment Total Property Plant & Equipment Balance at January 1, 2020 Depletion and depreciation Disposal and other Impairment BALANCE AT DECEMBER 31, 2020 Depletion and depreciation Disposal and other Impairment reversal BALANCE AT DECEMBER 31, 2021 CARRYING AMOUNTS AS AT: ($ 000s) December 31, 2020 DECEMBER 31, 2021 Impairment (678,265) (49,087) 51 (183,337) (910,638) (64,331) (115) 159,673 (815,411) (150,996) (10,071) - (50,965) (212,032) (12,404) - 43,524 (180,912) (1,789) (67) - - (1,856) (56) - - (831,050) (59,225) 51 (234,302) (1,124,526) (76,791) (115) 203,197 (1,912) (998,235) 546,927 692,639 157,553 209,813 441 398 704,921 902,850 At March 31, 2020 an impairment test over all CGUs was conducted in response to the economic impact of the global COVID-19 pandemic, the global oversupply of crude oil, the impact on forecast benchmark commodity prices and a reduction in market capitalization. The Company determined that the carrying value of the Company’s Alberta CGU exceeded its recoverable amount. A total impairment loss of $331,678,000 was recognized, with $234,302,000 recognized on the Company’s PPE, $92,810,000 was applied to the Company’s goodwill and an additional $4,566,000 was applied to the Company’s exploration and evaluation assets (“E&E”). As at December 31, 2020, no further impairment or impairment recovery was recognized as the estimated recoverable amount of each CGU exceeded its respective carrying value, but has not fully recovered as well as the Company’s market capitalization with commodity price uncertainty caused by COVID-19. At June 30, 2021 the Company identified indicators of an impairment reversal due to increased forward commodity prices and an increase in the Company’s market capitalization since the impairment loss recognized as at March 31, 2020. As a result, recovery testing was performed by preparing estimates of future cash flows to determine the recoverable amount of the respective assets. At June 30, 2021 the Company determined that the recoverable amount of the Company’s Alberta CGU exceeded its carrying value. A total impairment recovery of $203,197,000 was recognized in the Company’s PP&E. Impairment can be reversed for PP&E up to the lower of the recoverable amount or the original carrying value less any associated depletion and depreciation that would have been incurred had the impairment not occurred. Goodwill impairment cannot be reversed. 50 The following table outlines the forecasted benchmark commodity prices and the exchange rates used in the impairment (reversal) calculation of PP&E at June 30, 2021. WTI Crude oil $US/Bbl(1) AECO C-Spot $Mmbtu(1) Exchange rate US$/$Cdn 2021 71.33 3.28 0.80 2022 67.20 2.97 0.80 2023 63.95 2.58 0.80 2024 63.23 2.57 0.80 2025 64.50 2.62 0.80 2026 65.79 2.67 0.80 2027 67.10 2.73 0.80 2028 68.44 2.78 0.80 2029 69.81 2.84 0.80 2030 71.21 2.90 0.80 2031(2) 72.63 2.95 0.80 (1) The forecast benchmark commodity prices listed above are adjusted for quality differentials, heat content, transportation and marketing costs and other factors specific to the Company’s operations in performing the Company’s impairment tests. (2) Forecast benchmarks commodity prices are assumed to increase by 2.0% in each year after 2030 to end of the reserve life. Discount rate – The Company used a pre-tax discount rate of 15 percent that reflects risks specific to the assets for which the future cash flow estimates have not been adjusted. The discount rate was determined based on the Company’s assessment of risk based on experience. Changes in the general economic environment could result in material changes to this estimate. Changes in any of the key judgments, such as a revision in reserves, changes in forecast benchmark commodity prices, discount rates, foreign exchange rates, capital or operating costs would impact the recoverable amounts of assets and any recoveries or impairment changes would affect net earnings. The most sensitive assumptions to the calculation are the discount rate and forecast benchmark commodity price estimates at June 30, 2021. The Company concluded that no reasonable change in the key assumptions, such as a two percent change in commodity prices or a one percent change in the discount rate, would result in a different impairment reversal being recorded. 8. Accounts Payable and Accrued Liabilities ($ 000s) Accounts payable Accrued liabilities December 31, 2021 December 31, 2020 25,420 9,774 35,194 20,092 8,137 28,229 9. Transactions With Related Parties As at December 31, 2021, a loan to Bonterra provided by the Company’s CEO, director and major shareholder totaled $nil (December 31, 2020 – $12,366,000). The loan did bear interest at five and a half percent and had no set repayment terms. Effective June 1, 2020, principal or interest payments could not be settled for cash but could be settled by the issuance of common shares. No common shares were issued. Security under the debenture was over all of the Company’s assets and it was subordinated to all claims in favour of the syndicate of senior lenders (including subordinated debt) providing credit facilities to the Company. Interest paid on this loan in 2021 was $557,000 (December 31, 2020 – $224,000). In 2021, interest accrued on this loan and added to the loan’s principal totaled $nil (December 31, 2020 – $366,000). On October 20, 2021 (the “Conversion Date”), $12,000,000 of the due to related party loan was exchanged for senior unsecured subordinated debentures plus warrants and approximately $923,000 of current and previously accrued interest to the Conversion Date was settled for cash (for more information see Note 13). 10. Subordinated Promissory Note As at December 31, 2021, Bonterra had $nil (December 31, 2020 – $7,604,000) outstanding on a subordinated promissory note to a private investor. The note did bear interest at five and a half percent. Effective June 1, 2020, principal or interest payments could not be settled for cash but could be settled by the issuance of common shares. Security consists of a floating demand debenture over all of the Company’s assets and it was subordinated to all claims in favor of the syndicate of senior lenders (including subordinated debt) providing credit facilities to the Company. Interest settled in cash on the subordinated promissory note for the year ended 2021 was $23,000 (December 31, 2020 – $171,000). In 2021, the Company issued 118,896 common shares to settle $414,000 of accrued interest for the period of October 1, 2020 to September 30, 2021. 51 On October 20, 2021, $7,500,000 of the subordinated promissory note was exchanged for senior unsecured subordinated debentures plus warrants and approximately $23,000 of current interest to the Conversion Date was settled for cash (for more information see Note 13). 11. Bank Debt As at December 31, 2021, the Company has a total bank facility of $210,000,000 (December 31, 2020 – $300,000,000), comprised of a $185,000,000 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, 2021 was $162,945,000 (December 31, 2020 – $252,255,000). 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 period excluding finance costs, provision for current and deferred taxes, depletion and depreciation, share- option compensation, gain or loss on sale of assets and impairment of assets. The terms of the total revolving bank facility provide that the loan facility is revolving to May 31, 2022, with a maturity date of November 30, 2022. The available lending limit of the bank facility is scheduled to be reviewed before May 31, 2022. The syndicated revolving credit facility has a $10,000,000 reduction on March 31, 2022. The amount available for borrowing under the bank facility is reduced by outstanding letters of credit. Letter of credit totaling $1,445,000 were issued as at December 31, 2021 (December 31, 2020 – $1,245,000). Security for the bank facility consists of various floating demand debentures totaling $750,000,000 (December 31, 2020 – $750,000,000) over all of the Company’s assets and a general security agreement with first ranking over all personal and real property. As at December 31, 2021, Bonterra was in compliance with all financial covenants on its total bank facility. Under the Company’ current credit agreement, it is restricted from making any payment of dividend distributions. In addition, the Company is also limited to expenditures on an annual basis which cannot: ■ exceed 110 percent or be less than 90 percent of the forecasted decommissioning expenditures settled; and ■ exceed 110 percent of forecasted capital expenditures. 12. Subordinated Debt As at December 31, 2021, Bonterra had $47,268,000 (December 31, 2020 – $28,161,000) outstanding on a second lien non-revolving term facility due November 13, 2024 from the Business Development Bank of Canada (the “BDC”), through the Business Credit Availability Program (the “BCAP”). The amount drawn under the BCAP facility as at December 31, 2021 was $45,000,000 (December 31, 2020 – $28,000,000). Interest owing under the BCAP facility is accrued and added to the principal at five percent for the first year from the effective date of November 13, 2020. Thereafter interest will be paid monthly at an interest rate calculated as the greater of the revolving bank facility rate plus 1.00 percent or a fixed interest rate of 6.00 percent, increasing by 1.00 percent in each of the subsequent years. Security consists of a floating demand debenture over all of the Company’s assets and is subordinated to all claims in favor of the syndicate of senior lenders providing credit facilities to the Company. Interest accrued on the BCAP facility during 2021 was $2,108,000 (December 31, 2020 – $161,000) of which $1,868,000 (December 31, 2020 – $161,000) was added to the principal. Interest paid in 2021 was $139,000 (December 31, 2020 – $nil). 13. Subordinated Debentures On October 20, 2021, the Company issued 32,000 units (“Initial Offering”) at a price of $1,000 per unit for aggregate proceeds $32,000,000. In conjunction with the Initial Offering the Company has also entered into agreements with the holders of its existing subordinated promissory note and due to related party loan (the “Subordinated Loans”) to convert their principal amounts outstanding of an aggregate of $19,500,000 into units under the same terms and conditions as the subscribers under the Initial Offering. Concurrent with the closing of the Initial Offering, Bonterra entered into an agreement with the Agents providing for a separate offering of up to $5,000,000 of Units (the “Follow On Offering”), under the same terms and conditions as the Initial Offering. As part of the Follow On Offering, insiders of the Company will be given the option to subscribe for up to $1,000,000 in Units. On October 21, 2021, the Company announced an increase to the Follow On Offering to $7,500,000 of Units. The Follow On Offering closed on November 10, 2021, and 7,500 units were issued. A total of 59,000 units were issued. 52 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, which are 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. 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. The unsecured subordinated debentures were determined to be a compound instrument with a debt and equity component. The fair value of the debt component of the $59,000,000 in debentures were 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 of $9,811,000 and issue costs of $2,240,000. The value of the debt will accrete up to the principal balance at maturity. The Warrants have been recorded net of $2,259,000 of deferred taxes in shareholders’ equity. The Company estimated the fair value of $9,811,000 or $2.97 per Warrant using the Black-Scholes option pricing model with the following key assumptions: Weighted-average risk free interest rate (%)(1) Weighted-average expected life (years) Weighted-average volatility (%)(2) Weighted average dividend yield (%) December 31, 2021 0.80 2.2 91.01 1.73 (1) Risk-free interest rate is based on the weighted average Government of Canada benchmark bond yields for one, two, and three year terms to match corresponding vesting periods. (2) The expected volatility is measured as the standard deviation of expected share price returns based on statistical analysis of historical weekly share prices for a representative period. 14. Decommissioning Liabilities At December 31, 2021, the Company used a 2.0 percent inflation rate (December 31, 2020 – 2.0 percent inflation rate) and a risk-free nominal rate of 2.3 percent (December 31, 2020 – 2.3 percent) to calculate the present value of the decommissioning provision. Due to current global capital markets and its effect on long-term risk-free nominal rates in Canada are below target inflation rates, implying a negative real rate of return. The Company determined that applying these rates to current cost estimates would not provide an accurate measurement of the decommissioning liability as observable stand-alone risk-free real rates of return continue to be positive. To provide a more accurate measurement of the liability, the Company applied a risk-free real return rate of 0.3 percent above inflation to estimate the present value of the decommissioning provision at December 31, 2021, resulting in a change in estimate. The risk-free real return rate represents an observable, market based risk-free rate of return after adjusting for inflation. Changes in the measurement of the decommissioning provision are added to, or deducted from, the cost of the related asset in property, plant and equipment. When a re-measurement of the decommissioning provision relates to a retired asset, the amount is recorded in the statement of comprehensive income (loss). At December 31, 2021, the estimated total uninflated and undiscounted amount required to settle the decommissioning liabilities was $153,061,000 (December 31, 2020 – $156,573,000). These obligations will be settled at the end of the useful lives of the underlying assets, which extend up to 50 years into the future. ($ 000s) DECOMMISSIONING LIABILITIES, JANUARY 1 Changes in estimate Liabilities settled during the period Government grant in-kind (Note 21) Accretion on decommissioning liabilities DECOMMISSIONING LIABILITIES, END OF YEAR December 31, 2021 December 31, 2020 137,002 5,980 (4,496) (5,901) 3,230 135,815 138,171 92 (2,706) (1,689) 3,134 137,002 15. Income Taxes ($ 000s) Deferred tax asset (liability) related to: Investments Exploration and evaluation assets and property, plant and equipment Investment tax credits Decommissioning liabilities Corporate tax losses carried forward Share issue costs Financial derivative Subordinated debenture Corporate capital tax losses carried forward Unrecorded benefits of capital tax losses carried forward Unrecorded benefits of successored resource related pools Deferred tax asset (liability) 53 December 31, 2021 December 31, 2020 11 80 (149,656) (100,243) (2,041) 31,276 16,284 539 1,052 (2,681) 7,453 (7,453) (4,090) (109,306) (2,041) 31,558 20,496 - 829 - 7,488 (7,488) (4,150) (53,471) Income tax expense varies from the amounts that would be computed by applying Canadian federal and provincial income tax rates as follows: ($ 000s) Earnings (loss) 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 Impairment of goodwill Change in unrecorded benefits of tax pools Change in estimates and other December 31, 2021 December 31, 2020 232,964 23.03% 53,652 252 - (95) (144) 53,665 (367,573) 24.03% (88,314) 105 22,299 2,529 2,697 (60,684) (1) Effective July 1, 2020 the combined federal and provincial tax rate for Bonterra is approximately 23.00% due to the provincial tax rate for Alberta, Canada decreasing from 10% to 8%. 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: ($ 000s) Undepreciated capital costs Share issue costs Canadian oil and gas property expenditures Canadian development expenditures Canadian exploration expenditures Federal income tax losses carried forward(1) Provincial income tax losses carried forward(2) Rate of Utilization (%) 7-100 20 10 30 100 100 100 Amount 60,376 2,341 71,257 100,853 9,111 83,951 45,569 373,458 (1) Federal income tax losses carried forward expire in the following years: 2036 – $25,601,000; 2037 – $182,000; 2039 – $2,163,000; 2040 – $56,005,000; (2) Provincial income tax losses carried forward expire in 2040. 54 The Company has $8,861,000 (December 31, 2020 – $8,861,000) of investment tax credits that expire in the following years: 2024 – $1,319,000; 2025 – $2,258,000; 2026 - $2,405,000; 2027 – $2,009,000; 2028 – $745,000; 2034 – $99,000; and 2037 – $26,000. The Company has $64,725,000 (December 31, 2020 – $65,015,000) of capital losses carried forward which can only be claimed against taxable capital gains. 16. Shareholders’ Equity Authorized The Company is authorized to issue an unlimited number of common shares without nominal or par value. Issued and fully paid – common shares Balance, beginning of year Shares issued for interest on subordinated promissory note Issued pursuant to the Company's share option plan Transfer from contributed surplus to share capital Issuance of flow through shares Premium on flow through shares Share issue costs, net of tax Balance, end of year December 31, 2021 December 31, 2020 Number 33,511,316 118,896 183,740 1,187,000 Amount ($ 000s) 765,415 414 378 168 7,003 (356) (241) Number 33,388,796 122,520 - - Amount ($ 000s) 765,276 139 - - - - - 35,000,952 772,781 33,511,316 765,415 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. On December 9, 2021, the Company raised $7,003,000 by issuing 1,187,000 common shares on a flow through basis through a private placement financing. Proceeds of the offering are to be used for qualifying development expenditures during the first quarter of 2022. At December 31, 2021, Bonterra had not incurred the required expenditures. The Company has filed the renouncement documents subsequent to year-end. The premium component of the flow-through shares is calculated as $356,000 and is set up as a current liability in accounts payable and accrued liabilities. This amount will be netted against the Company’s deferred tax liability in the first quarter of 2022. The weighted average common shares used to calculate basic and diluted net earnings per share for the year ended December 31, 2021, are as follows: Basic shares outstanding Dilutive effect of share options(1) Diluted shares outstanding December 31, 2021 December 31, 2020 33,729,730 1,031,445 34,761,175 33,403,860 16,784 33,420,644 (1) The Company did not include 3,574,500 share-options and warrants (December 30, 2020 – 2,246,700) in the dilutive effect of share-options and warrants calculations as these were anti-dilutive. For the year ended December 31, 2021, the Company did not declare or pay dividends (December 31, 2020 – $1,002,000 ($0.03 per share)). The dividend was suspended effective April 1, 2020. 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 3,500,095 (December 31, 2020 – 3,351,131 common shares). The exercise price of each option granted cannot be lower than the market price of the common shares on the date of grant and the option’s maximum term is five years. A summary of the status of the Company’s stock options as of December 31, 2021 and changes during the year are presented below: 55 At January 1, 2020 Options granted Options forfeited Options expired At December 31, 2020 Options granted Options exercised(1) Options forfeited Options expired AT DECEMBER 31, 2021 Number of Options Weighted Average Exercise Price 1,945,000 $ 2,373,200 (348,500) (1,543,000) 2,426,700 $ 235,500 (266,600) (87,000) (47,000) 2,261,600 $ 10.13 2.25 7.94 10.3 2.63 4.39 3.02 1.96 13.55 2.56 (1) 127,500 options were exercised under the cashless option method, which resulted in 44,640 shares being issued in which the Company received no proceeds. The following table summarizes information about options outstanding and exercisable as at December 31, 2021: Range of Exercise Prices Number Outstanding Options Outstanding Weighted-average Remaining Contractual Life Options Exercisable Weighted-average Exercise Price Number Exercisable Weighted-average Exercise Price $ 1.00 – $ 5.00 2,176,600 1.1 years $ 5.01 – 10.00 10.01 – 20.00 71,000 14,000 1.1 years 0.5 years $ 1.00 – $ 20.00 2,261,600 1.1 years $ 2.36 5.76 17.76 2.56 1,380,750 $ 36,000 14,000 1,430,750 $ 1.91 5.87 17.76 2.16 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 2021, the Company granted 235,500 options with an estimated fair value of $417,000 or $1.77 per option using the Black-Scholes option pricing model with the following key assumptions: Weighted-average risk free interest rate (%)(1) Weighted-average expected life (years) Weighted-average volatility (%)(2) Forfeiture rate (%) Weighted average dividend yield (%) December 31, 2021 December 31, 2020 0.40 2.0 84.61 7.69 2.71 0.78 1.3 88.02 7.50 5.96 (1) Risk-free interest rate is based on the weighted average Government of Canada benchmark bond yields for one, two, and three year terms to match corresponding vesting periods. (2) The expected volatility is measured as the standard deviation of expected share price returns based on statistical analysis of historical weekly share prices for a representative period. On February 18, 2022 the Company granted 965,000 share options to employees and directors with an exercise price of $9.00, based on the market price immediately preceding the date of grant. The share options vests between one and three years from the grant date and expire on February 18, 2027. 56 17. Oil and Gas Sales, Net of Royalties ($ 000s) Oil and gas sales Crude oil Natural gas liquids Natural gas Less royalties: Crown Freehold, gross overriding royalties and other Oil and gas sales, net of royalties 18. Other Income ($ 000s) Investment income Administrative income Gain on sale of property and equipment Government grant in-kind (Note 21) Other income 19. Supplemental Cash Flow Information ($ 000s) Change in non-cash working capital: Accounts receivable Crude oil inventory Prepaid expenses Accounts payable and accrued liabilities Changes related to: Operating activities Investing activities December 31, 2021 December 31, 2020 195,985 16,225 39,406 251,616 (15,241) (10,509) (25,750) 225,866 94,567 7,044 20,031 121,642 (4,104) (3,717) (7,821) 113,821 December 31, 2021 December 31, 2020 67 487 225 5,901 6,680 50 211 - 1,689 1,950 December 31, 2021 December 31, 2020 (11,324) (270) (2,002) 6,609 (6,987) (6,229) (758) (6,987) 8,873 20 (12) 2,806 11,687 6,270 5,417 11,687 FINANCE EXPENSE ($ 000s) Interest expense: Bank and subordinated debt Due to related party Subordinated debenture Subordinated promissory note Accretion: Decommissioning liabilities Subordinated debentures Total finance costs Interest expense Interest accrued Interest paid 57 December 31, 2021 December 31, 2020 21,332 557 1,047 333 23,269 3,230 410 3,640 26,909 23,269 (2,052) 21,217 17,353 590 - 413 18,356 3,134 - 3,134 21,490 18,356 (769) 17,587 20. 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 ■ Due to related party ■ Subordinated promissory note ■ Bank debt ■ Subordinated 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. The Company’s overall risk management program seeks to mitigate these risks and reduce the volatility on the Company’s financial performance. Financial risk is managed by senior management under the direction of the Board of Directors. The Company is exposed to credit risk, liquidity risk and market risk as part of its normal course of business. The Company’s overall risk management program seeks to mitigate these risks and reduce the volatility on the Company’s financial performance. Financial risk is managed by senior management under the direction of the Board of Directors. The Company does not speculatively trade in risk management contracts. The Company’s risk management contracts are entered into to manage the risks relating to commodity prices from its business activities. Certain financial risks have been increased due to the COVID-19 outbreak and have created abnormal volatility in spot prices and decreased demand for oil. Liquidity Risk Management Liquidity risk is the risk that the Company will encounter difficulty in meeting obligations associated with its financial liabilities. While commodity prices have stabilized since the outbreak of the COVID-19 pandemic there is still economic uncertainty as a result of new COVID-19 variants and varying levels of progress each country around the globe can administer vaccines will have impact the Company’s financial performance and position, the Company continues to retain available committed borrowing capacity that provides the Company with financial flexibility and the ability to meet ongoing obligations as they become due. 58 After examining the economic factors that are causing the liquidity risk facing the Company, the judgment applied to these factors, and the various initiatives that the Company has and will undertake to strengthen its financial position, the Company believes it will have sufficient liquidity to support its ongoing operations and meet its financial obligations as they come due for at least the next twelve months. There can be no assurance that the next borrowing base redetermination will not result in a borrowing base shortfall, and that the necessary funds or additional security will be available to eliminate the short fall. 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 $24,215,000 accounts receivable balance at December 31, 2021 (December 31, 2020 – $12,891,000) over 89 percent (2020 – 91 percent) relates to product sales or risk management contracts with national and international banks and oil and gas companies. On a quarterly basis, the Company assesses if there has been any impairment of the financial assets of the Company. During the year ended December 31, 2021, there was no material impairment provision required on any of the financial assets of the Company. The Company does have a 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. At December 31, 2021, approximately $459,000 or 1.9 percent of the Company’s total accounts receivable are aged over 90 days and considered past due (December 31, 2020 – $709,000 or 5.5 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, 2021 is $1,287,000 (December 31, 2020 – $1,186,000) with the expense being included in general and administrative expenses. There were no material accounts written off during the period. The maximum exposure to credit risk is represented by the carrying amounts of accounts receivable. There are no material financial assets that the Company considers past due. Capital Risk Management The Company’s objectives when managing capital, which the Company defines to include shareholders’ equity, debt and working capital balances, are to safeguard the Company’s ability to continue as a going concern, so that it can continue to provide returns to its shareholders and benefits for other stakeholders and to maintain a capital structure that provides a low cost of capital. In order to maintain or adjust the capital structure, the Company may adjust the current debt structure and/or issue common shares. The Company monitors capital based on the ratio of net debt (total debt adjusted for working capital) to cash flow from operating activities. This ratio is calculated using each quarter end net debt divided by the preceding twelve months’ cash flow. At December 31, 2021, the Company had a net debt to cash flow level of 2.8:1 compared to 9.8:1 as at December 31, 2020. The decrease in net debt to cash flow ratio is primarily due to an increase in commodity prices in 2021. Net debt to cash flow ratio should improve in subsequent quarters with commodity prices increasing, increased production from the Company’s capital program and having approximately thirty percent of the Company’s forecasted oil and natural gas production hedged over the next twelve months. Bonterra has also optimized cash flow using any government assistance programs where applicable. 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. a) Net Debt to Cash Flow Ratio The net debt and cash flow amounts are as follows: ($ 000s) Bank debt(1) Subordinated debt Subordinated debentures Current liabilities Current assets Net debt Cash flow from operations Net debt to cash flow ratio (1) Bank debt is classified as a current liability. b) Risks and Mitigation 59 December 31, 2021 December 31, 2020 162,945 47,268 47,359 40,920 (31,313) 267,179 96,103 2.8 252,255 28,161 - 52,628 (17,471) 315,573 32,073 9.8 Market risk is the risk that the fair value or future cash flow of the Company’s financial instruments will fluctuate because of changes in market prices. Components of market risk to which the Company is exposed are discussed below. Commodity Price Risk The Company’s principal operation is the production and sale of crude oil, natural gas and natural gas liquids. Fluctuations in prices of these commodities directly impact the Company’s performance and ability to continue with its dividends. The Company has used various risk management contracts to set price parameters for a portion of its production. The Company has assumed the risk in respect of commodity prices, except for a small portion of physical delivery sales and risk management contracts to manage commodity risk on the Company’s higher operating cost areas. The Company is exposed to credit risk, liquidity risk and market risk as part of its normal course of business. The Company’s overall risk management program seeks to mitigate these risks and reduce the volatility on the Company’s financial performance. Financial risk is managed by senior management under a risk management program approved by the Board of Directors. 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, 2021, the Company has the following physical delivery sales contracts in place. 60 Product Type of Contract Physical collar – WTI(1) Physical collar – WTI(1) Physical collar – WTI(1) Volume 250 BBL/day 500 BBL/day 500 BBL/day Term Contract Price ($) Jan 1, 2022 to Mar 31, 2022 48.00 to 63.90 USD/BBL Apr 1, 2022 to Jun 30, 2022 48.00 to 75.50 USD/BBL Apr 1, 2022 to Jun 30, 2022 48.00 to 77.00 USD/BBL Fixed price – MSW Stream Index(2) 500 BBL/day Jan 1, 2022 to Mar 31, 2022 91.00 CAD/BBL Physical collar – WTI(1) Physical collar – WTI(1) Fixed price – MSW differential(2)(3) Fixed price – MSW differential(2)(3) Fixed price – MSW differential(2)(3) Fixed Price – AECO Daily(4) Fixed Price – AECO Daily(4) Fixed Price – AECO Daily(4) Physical collar – AECO Monthly(5) Fixed Price – AECO Daily(4) Physical collar – AECO Monthly(5) Physical collar – AECO Monthly(5) Fixed Price – AECO Daily(4) Fixed Price – AECO Daily(4) Fixed Price – AECO Daily(4) 500 BBL/day 500 BBL/day 250 BBL/day 500 BBL/day 500 BBL/day 3,000 GJ/day 2,500 GJ/day 2,000 GJ/day 5,000 GJ/day 2,000 GJ/day 5,000 GJ/day 4,000 GJ/day 2,500 GJ/day 2,500 GJ/day 5,000 GJ/day Jul 1, 2022 to Sept 30, 2022 48.00 to 77.20 USD/BBL Oct 1, 2022 to Dec 31, 2022 48.00 to 77.00 USD/BBL Jan 1, 2022 to Mar 31, 2022 Apr 1, 2022 to Jun 30, 2022 Jul 1, 2022 to Sept 30, 2022 Jan 1, 2022 to Mar 31, 2022 Jan 1, 2022 to Mar 31, 2022 Jan 1, 2022 to Mar 31, 2022 Apr 1, 2022 to Jun 30, 2022 Apr 1, 2022 to Jun 30, 2022 Jul 1, 2022 to Sep 30, 2022 Oct 1, 2022 to Dec 31, 2022 Jul 1, 2022 to Sep 30, 2022 Nov 1, 2021 to Oct 31, 2022 Oct 1, 2022 to Dec 31, 2022 (5.00) USD/BBL (5.25) USD/BBL (4.65) USD/BBL 3.10 GJ/ day 2.65 GJ/ day 2.70 GJ/ day 2.00 to 2.60 GJ/ day 2.40 GJ/ day 2.50 to 3.15 GJ/ day 3.00 to 3.63 GJ/ day 3.18 GJ/ day 4.10 GJ/ day 3.32 GJ/ day Oil Oil Oil Oil Oil Oil Oil Oil Oil Gas Gas Gas Gas Gas Gas Gas Gas Gas Gas (1) “WTI” refers to West Texas Intermediate, a grade of light sweet crude oil used as benchmark pricing in the United States. (2) "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. (3) “MSW differential” is the primary difference between WTI and MSW steam index benchmark pricing. (4) “AECO Daily” refers to a grade or heating content of natural gas used as daily index benchmark pricing in Alberta, Canada. (5) “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, 2021, the Company entered into the following physical delivery sales contracts. Product Type of Contract Oil Oil Oil Oil Gas Gas Physical collar – WTI Physical collar – WTI Fixed price – MSW differential Fixed price – MSW differential Physical collar – AECO Monthly Physical collar – AECO Monthly Risk Management Contracts ($ 000s) Risk management contracts Realized gain (loss) Unrealized gain (loss) Volume 500 BBL/day 500 BBL/day 500 BBL/day 500 BBL/day 2,500 GJ/day 5,000 GJ/day Term Contract Price ($) Apr 1, 2022 to Jun 30, 2022 75.00 to 92.10 USD/BBL Jan 1, 2023 to Mar 31, 2023 65.00 to 86.00 USD/BBL Apr 1, 2022 to Jun 30, 2022 Jan 1, 2023 to Mar 31, 2023 Apr 1, 2022 to Oct 31, 2022 Oct 1, 2022 to Dec 31, 2022 (2.75) USD/BBL (4.50) USD/BBL 3.50 to 4.15 GJ/ day 4.00 to 4.55 GJ/ day December 31, 2021 December 31, 2020 (17,389) (968) (18,357) 402 (3,465) (3,063) The Company also enters into financial derivative instruments or risk management contracts to manage commodity price risk. These contracts are not considered normal executory sales contracts and are recorded at fair value in the financial statements. The Company has entered into the following risk management contracts during the period ended December 31, 2021. Product Type of Contract Volume Term Contract Price ($) 61 Oil Oil Oil Oil Oil Oil Oil Oil Oil Oil Oil Oil Oil Oil Oil Oil Oil Financial collar – WTI Financial collar – WTI Financial collar – WTI Financial collar – WTI Financial collar – WTI Financial collar – WTI Financial collar – WTI Financial collar – WTI Financial collar – WTI Financial collar – WTI Financial collar – WTI Fixed price – MSW differential Fixed price – MSW differential Fixed price – MSW differential 1,000 BBL/day Jan 1, 2022 to Mar 31, 2022 48.00 to 64.60 USD/BBL 500 BBL/day 500 BBL/day 500 BBL/day 500 BBL/day 300 BBL/day Jan 1, 2022 to Mar 31, 2022 48.00 to 68.00 USD/BBL Jan 1, 2022 to Mar 31, 2022 48.00 to 68.50 USD/BBL Apr 1, 2022 to Jun 30, 2022 48.00 to 68.90 USD/BBL Apr 1, 2022 to Jun 30, 2022 48.00 to 73.10 USD/BBL Apr 1, 2022 to Jun 30, 2022 48.00 to 79.75 USD/BBL 1,000 BBL/day Jul 1, 2022 to Sept 30, 2022 48.00 to 75.75 USD/BBL 600 BBL/day Jul 1, 2022 to Sept 30, 2022 48.00 to 81.60 USD/BBL 1,000 BBL/day Oct 1, 2022 to Dec 31, 2022 60.00 to 81.25 USD/BBL Oct 1, 2022 to Dec 31, 2022 48.00 to 81.25 USD/BBL Oct 1, 2022 to Dec 31, 2022 55.00 to 78.45 USD/BBL 500 BBL/day 200 BBL/day 1,000 BBL/day 1,000 BBL/day 300 BBL/day Jan 1, 2022 to Mar 31, 2022 Apr 1, 2022 to Jun 30, 2022 Apr 1, 2022 to Jun 30, 2022 Fixed price – MSW differential 1,000 BBL/day Jul 1, 2022 to Sept 30, 2022 Fixed price – MSW differential 600 BBL/day Jul 1, 2022 to Sept 30, 2022 Fixed price – MSW differential 1,000 BBL/day Oct 1, 2022 to Dec 31, 2022 (6.60) CAD/BBL (6.55) CAD/BBL (4.75) USD/BBL (5.90) CAD/BBL (4.65) USD/BBL (6.05) CAD/BBL Subsequent to December 31, 2021, the Company entered into the following risk management contracts. Product Type of Contract Oil Oil Oil Oil Oil Financial collar – WTI Financial collar – WTI Financial collar – WTI Fixed price – MSW differential Fixed price – MSW differential Interest Rate Risk Volume 500 BBL/day 500 BBL/day 500 BBL/day 500 BBL/day 500 BBL/day Term Contract Price ($) Jan 1, 2023 to Mar 31, 2023 60.00 to 88.00 USD/BBL Jan 1, 2023 to Mar 31, 2023 60.00 to 89.45 USD/BBL Jan 1, 2023 to Mar 31, 2023 65.00 to 100.00 USD/BBL Jan 1, 2023 to Mar 31, 2023 Jan 1, 2023 to Mar 31, 2023 (4.40) USD/BBL (4.20) USD/BBL 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, 2021, the Company’s debt facilities consist of a $185,000,000 syndicated revolving credit facility, and a $25,000,000 non-syndicated revolving credit facility, $45,000,000 subordinated 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. Subordinated debt is at the greater of six percent and increases by one percent in subsequent years or the revolving bank facility rate plus one percent. The subordinated debentures are at a fixed interest rate of nine percent. The Company manages its exposure to interest rate risk on its floating interest rate debt through entering into various term lengths on its BAs but in no circumstances do the terms exceed six months. Sensitivity Analysis Based on historic movements and volatilities in the interest rate markets and management’s current assessment of the financial markets, the Company believes that a one percent variation in the Canadian prime interest rate is reasonably possible over a 12 month period. A one percent increase (decrease) in the Canadian prime rate would decrease (increase) both annual net earnings and comprehensive income by $1,618,000. 62 Equity Price Risk Equity price risk refers to the risk that the fair value of the investments and investment in related party will fluctuate due to changes in equity markets. Equity price risk arises from the realizable value of the investments that the Company holds which are subject to variable equity market prices which on disposition gives rise to a cash flow equity price risk. The Company will assume full risk in respect of equity price fluctuations. Foreign Exchange Risk The Company has no foreign operations and currently sells all of its product sales in Canadian currency. The Company however is exposed to currency risk in that crude oil is priced in US currency, then converted to Canadian currency. The Company currently has no outstanding risk management agreements. The Company will assume full risk in respect of foreign exchange fluctuations. 21. Commitments and Financial Liabilities The Company has the following maturity schedule for its financial liabilities and commitments: Recognized on Financial Statements Yes – Liability Yes – Liability Yes – Liability Yes – Liability No No No ($ 000s) Accounts payable and accrued liabilities Bank Debt Subordinated debt(1) Subordinated debentures(1) Future interest Firm service commitments Office lease commitments Total (1) Principal amount. Less than 1 year Over 1 year to 3 years Over 3 years to 5 years Over 5 years to 7 years 35,194 162,945 - - 8,191 489 526 - - 47,029 - 17,263 805 463 - - - 59,000 4,204 220 498 207,345 65,560 63,922 - - - - - 15 988 1,003 Total 35,194 162,945 47,029 59,000 29,657 1,529 2,475 337,829 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 4.9 years. 22. 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 $5,901,000 of asset retirement obligations as an in-kind grant (December 31, 2020 – $1,689,000). The benefit of the in-kind grant is recognized through other income. Canadian Emergency Wage Subsidy (“CEWS”) is a federal program that allows eligible companies to receive a subsidy of employee wages, subject to a maximum per employee. During the year ended December 31, 2021, the Company received $159,000 (2020 – $895,000), which resulted in a reduction of employee compensation. Notes 63 64 Notes 65 Corporate Information Bankers CIBC National Bank of Canada The Toronto-Dominion Bank ATB Financial Business Development Bank of Canada Export Development Bank 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 Board of Directors D. Michael G. Stewart – Chair John J. Campbell George F. Fink Stacey E. McDonald Jacqueline R. Ricci Rodger A. Tourigny Officers George F. Fink, CEO Robb D. Thompson, CFO and Corporate Secretary Adrian Neumann, Chief Operating Officer Brad A. Curtis, Senior VP, Business Development Registrar and Transfer Agent Odyssey Trust Company Auditors Deloitte LLP Solicitors Borden Ladner Gervais LLP 901, 1015 – 4th Street SW Calgary, Alberta, T2R 1J4 TEL 403.262.5307 FAX 403.265.7488 info@bonterraenergy.com www.bonterraenergy.com 

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