Petrus Resources Ltd.
Annual Report 2021

Plain-text annual report

ANNUAL REPORT December 31, 2021 Petrus Resources Ltd. (“Petrus” or the “Company”) (TSX: PRQ) is pleased to report financial and operating results as at and for the three and twelve months ended December 31, 2021 and to provide 2021 year end reserves information as evaluated by Insite Petroleum Consultants Ltd. ("Insite"). The Company's Management's Discussion and Analysis ("MD&A") and audited consolidated financial statements are available on SEDAR (the System for Electronic Document Analysis and Retrieval) at www.sedar.com. Q4 2021 HIGHLIGHTS • • • • Commodity price improvement – Realized price per boe increased by 92% in the fourth quarter of 2021 compared to the fourth quarter of 2020 due to strengthened oil, natural gas and NGL pricing, which increased by 81%, 78% and 140%, respectively. Operating netback up 112% – Operating netback(1) increased by 122% to $33.12/boe in the fourth quarter of 2021 up from $14.95/boe in the fourth quarter of 2020. Total funds flow up 62% – Petrus generated funds flow and corporate netback(2) of $10.4 million and $19.26/boe in the fourth quarter of 2021, 62% and 75% higher, respectively, than the fourth quarter of the prior year Increased capital activity – Petrus incurred capital expenditures of $12.2 million in the fourth quarter of 2021 compared to $2.8 million in the fourth quarter of 2020. Petrus began execution of its fourth quarter 2021 drilling program in November, which included the Company’s first operated well in North Ferrier. In December, the Company drilled two net wells in its core Ferrier area. ANNUAL 2021 HIGHLIGHTS • • • Transformative debt reduction – During 2021, Petrus executed transactions that transformed its debt position, as follows: ◦ ◦ ◦ ◦ Reduced net debt(1) by 46% from $114.4 million to $61.8 million; Debt to fourth quarter 2021 annualized funds flow (excluding realized hedge settlements) is now 1.5x; Second lien term loan settled in full; and First lien debt is now fully conforming at $57.7 million drawn. Funds flow per boe up 41% – Petrus generated funds flow and corporate netback of $33.4 million and $15.19/boe in 2021, 26% and 40% higher, respectively, than funds flow of $26.4 million and $10.93/boe in 2020. Capital expenditures doubled – Petrus incurred $26.9 million of capital expenditures in 2021, compared to $14.3 million in 2020; drilling ten gross (6.4 net) wells in Ferrier and North Ferrier. • Maintained production – Petrus held production relatively flat at 6,009 boe/d through 2021 as it focused on debt repayment, which limited capital reinvestment during the first nine months of the year. 2022 OUTLOOK(3) The completion of the debt restructuring transactions during the third quarter of 2021 transformed Petrus from a company with limited capital resources to one with the ability to create meaningful shareholder value. The substantial debt reduction associated with the second lien debt settlement and equity financing has bolstered the Company’s financial position and provides the flexibility required to invest in the development of its land base and unlock proven value. On March 1, 2022, the Company entered into a definitive agreement to acquire producing oil and gas properties that are held by a privately owned limited partnership and its general partner (the "Acquired Entities") for total consideration of approximately $14.4 million, consisting of 10 million common shares of the Company issued at a deemed price of $1.44 per share based on the volume weighted average trading price of the common shares of the Company on the TSX for the five trading days prior to the date of the Agreement (the "Acquisition"). The Acquisition is expected to close in March 2022 and is subject to customary closing conditions. For more information, please refer to the related press release dated March 1, 2022. Petrus' Board of Directors has approved a 2022 capital budget of $50 to $55 million. Capital will be largely focused on the drilling, completion and tie-in of 14 net wells in Ferrier. The 2022 budget was constructed using a price forecast of WTI at US$69.00/bbl, AECO at $3.20/GJ and a foreign exchange rate of US$0.79. Through the successful execution of this capital plan, Petrus is expecting to: • Achieve a 2022 exit production rate of 9,000 to 9,500 boe per day (62% conventional natural gas, 25% light crude oil and 13% natural gas liquids), a projected increase of 40 to 50% compared to 2021 average annual production. • • Generate in excess of $60 million in annual funds flow, an anticipated 65 to 80% improvement compared to 2021 results. Continue to reduce debt and further strengthen the Company’s balance sheet. (1)Non-GAAP measure or non-GAAP ratio. Refer to "Non-GAAP and Other Financial Measures" in the Management's Discussion & Analysis attached hereto. (2)Corporate netback is equal to funds flow, which is a comparable additional GAAP measure. Petrus analyzes these measures on an absolute value and per unit basis. Refer to "Non-GAAP and Other Financial Measures". (3)Refer to "Advisories - Forward-Looking Statements" in the Management's Discussion & Analysis attached hereto. PRESIDENT’S MESSAGE This past year was a transformational one for Petrus and, as a result of the strategic changes we made, the Company is well positioned to take advantage of the improved macro-outlook for the Canadian oil and gas industry. It was my pleasure to join the Petrus team in April 2021 and, with the support of our shareholders and Board of Directors, continue to repair Petrus’ balance sheet and put an end to declining production and cash flow. We successfully reduced the company’s net debt by nearly half, substantially improving Petrus’ financial position and providing the much needed flexibility to begin deploying more of our cash flow to generate production growth and leverage our existing infrastructure. After drilling only 3.2 net wells in 2020, we doubled our drilling activity with 6.4 net wells drilled in 2021 including five operated wells: four in our core Ferrier area and one in our emerging North Ferrier area. Production was held relatively flat throughout the year. However, with the three net wells that we drilled at the end of 2021 and the fourteen net wells planned for 2022, we are forecasting significant production and cash flow growth in the year ahead. Cash flow was up in 2021, mostly because of higher commodity prices though hedging losses moderated the gains. These lower-priced hedge contracts, put in place in 2020 during the tumultuous COVID-19 pandemic, extend only to the end of the first quarter of 2022, after which we will start to see the full effect of the improved commodity prices in our cash flow. Net debt was reduced significantly last year and is now forecast to be less than one times cash flow by the end of the year. Shareholder equity value increased almost 8 fold over the year from a combination of share price increase (4x) and new equity issued, and equity accounted for 58% of the enterprise value of the company at year end, up from 9% in 2020, and this will continue to improve as we create value while reducing debt. Petrus has been sitting on a strong asset base with a fantastic team in place to execute the development of those assets. With the improved macro environment and the debt issues largely behind us, 2022 will be the year to show what the Company is capable of. We appreciate the support of our shareholders and Board of Directors and we will continue to develop and work hard to generate the return on investment our shareholders expect. Ken Gray President, Chief Executive Officer and Director RESERVES Petrus’ 2021 year end reserves were evaluated by independent reserves evaluator, InSite Petroleum Consultants Ltd. ("Insite"), in accordance with the definitions, standards and procedures contained in the Canadian Oil and Gas Evaluation Handbook (“COGE Handbook”) and National instrument 51-101 - Standards of Disclosure for Oil and Gas Activities (“NI 51-101”) as of December 31, 2021 ("2021 Insite Report"). Additional reserve information as required under NI 51-101 will be included in our Annual Information Form for the year ended December 31, 2021, which will be available under the Company's profile on SEDAR (the System for Electronic Document Analysis and Retrieval) at www.sedar.com. Petrus has a reserves committee, comprised of a majority of independent board members, that reviews the qualifications and appointment of the independent reserves evaluator. The committee also reviews the procedures for providing information to the evaluators. All booked reserves are based upon annual evaluations by the independent qualified reserve evaluator conducted in accordance with the COGE Handbook and NI 51-101. The evaluations are conducted using all available geological and engineering data. The reserves committee has reviewed the reserves information and approved the 2021 Insite Report. The following table provides a summary of the Company’s before tax reserves as evaluated by Insite: As at December 31, 2021 Total Company Interest (1)(3) Reserve Category Proved Producing Proved Non-Producing Proved Undeveloped Total Proved Proved + Probable Producing Total Probable Total Proved Plus Probable Conventional Natural Gas (mmcf) Light and Medium Crude Oil (mbbl) NGL (mbbl) Total (mboe) NPV 0%(2) ($000s) NPV 5%(2) ($000s) NPV 10%(2) ($000s) 49,580 1,066 82,065 132,711 59,462 67,070 199,781 885 2 1,725 2,612 1,057 2,300 4,912 2,550 24 5,797 8,371 3,049 3,812 12,183 11,698 204 21,200 33,101 14,017 17,291 50,392 119,994 1,756 302,220 423,970 163,359 321,029 744,999 136,554 128,517 1,509 193,014 331,078 162,738 193,091 524,168 1,329 130,575 260,421 146,541 130,210 390,631 (1Tables may not add due to rounding. (2NPV 0%, NPV 5% and NPV 10% refer to the risked net present value of the future net revenue of the Company's reserves, discounted by 0%, 5% and 10%, respectively and is presented before tax and based on Insite's pricing assumptions. (3)Total company interest reserve volumes presented above and in the remainder of this Annual Report are presented as the Company's total working interest before the deduction of royalties (but after including any royalty interests of Petrus). In 2021, Petrus’ development program generated proved developed producing ("PDP") reserve volume additions of 3.0 mmboe. The Company produced 2.2 mmboe and had dispositions of 1.3 mmboe of PDP reserves. The Company ended the year with 11.7 mmboe of PDP reserves (29% crude oil and liquids). Petrus ended 2021 with $129.9 million, $260.4 million and $390.6 million of Proved Developed ("PD"), Total Proved ("TP"), and Proved plus Probable (“P+P”), respectively, reserve value before-tax, discounted at 10%, based on the 2021 Insite Report. In 2021, the Company realized Finding, Development and Acquisition (“FD&A”) costs of $15.64/boe for PDP reserves. Based on the 2021 Insite Report, the Company’s PDP reserve value before-tax, discounted at 10% is $1.33 per share (96,707,912 basic common shares outstanding at December 31, 2021). On the same basis, the P+P reserve value before tax, discounted at 10%, is $4.04 per share. Page |4 FUTURE DEVELOPMENT COST Future Development Cost ("FDC") reflects Insite's best estimate of what it will cost to bring the P+P undeveloped reserves on production. The following table provides a summary of the Company's FDC as set forth in the 2021 Insite Report: Future Development Cost ($000s) 2022 2023 2024 2025 2026 Total FDC, Undiscounted Total FDC, Discounted at 10% Total Proved Total Proved + Probable 49,560 68,890 68,752 40,854 5,629 233,684 194,687 49,560 76,030 68,752 82,203 66,942 343,489 270,860 PERFORMANCE RATIOS The following table highlights annual performance ratios for the Company from 2017 to 2021(3): December 31, 2021 December 31, 2020 December 31, 2019 December 31, 2018 December 31, 2017 Proved Producing FD&A ($/boe) (1)(2) F&D ($/boe) (1)(2) Reserve Life Index (yr) (1) Reserve Replacement Ratio (1) FD&A Recycle Ratio (1) Proved Developed FD&A ($/boe) (1)(2) F&D ($/boe) (1)(2) Reserve Life Index (yr) (1) Reserve Replacement Ratio (1) FD&A Recycle Ratio (1) Total Proved FD&A ($/boe) (1)(2) F&D ($/boe) (1)(2) Reserve Life Index (yr) (1) Reserve Replacement Ratio (1) FD&A Recycle Ratio (1) Future Development Cost ($000s) Total Proved + Probable FD&A ($/boe) (1)(2) F&D ($/boe) (1)(2) Reserve Life Index (yr) (1) Reserve Replacement Ratio (1) FD&A Recycle Ratio (1) Future Development Cost ($000s) 15.64 8.90 5.4 1.4 1.6 14.54 8.53 5.5 1.4 1.7 10.51 9.24 15.3 5.1 2.3 4.83 4.83 5.2 1.2 2.6 4.71 4.71 5.2 1.2 2.7 1.29 1.29 10.9 (1) 9.8 13.31 12.81 3.8 0.4 1.2 12.49 12.03 4.8 0.5 1.3 1.09 (6.83) 9.9 0.3 14.4 37.76 42.27 4.6 0.2 0.4 11.34 11.55 5.6 0.6 1.4 8.73 8.16 11.1 1.3 1.8 13.05 11.57 4.1 1.6 1.1 16.74 14.62 4.5 1.2 0.9 14.33 12.03 8 1.1 1 233,684 156,815 174,027 194,757 182,086 10.57 8.36 23.3 6.4 2.3 0.37 0.37 17.7 (1.3) 33.7 (7.32) 190.21 15.4 — (2.1) 6.49 5.15 17.1 1.5 2.4 14.87 17.28 12.3 1.7 1.0 343,489 252,335 267,652 290,876 283,030 (1)Refer to "Oil and Gas Disclosures" in the Management's Discussion & Analysis attached hereto. (2)Certain changes in FD&A costs and F&D costs produce non-meaningful figures as discussed in "Oil and Gas Disclosures" in the Management's Discussion & Analysis attached hereto. While FD&A costs and F&D costs, reserve life index, reserve replacement ratio and FD&A recycle ratio are commonly used in the oil and nature gas industry and have been prepared by management, these terms do not have a standardized meaning and may not be comparable to similar measures presented by other companies and, therefore, should not be used to make such comparisons. Page |5 NET ASSET VALUE The following table shows the Company's Net Asset Value ("NAV"), calculated using the 2021 Insite Report and Insite's December 31, 2021 price forecast: As at December 31, 2021 ($000s except per share) Present Value Reserves, before tax (discounted at 10%) (1) Undeveloped Land Value (2) Net Debt (3) Net Asset Value Fully Diluted Shares Outstanding Estimated Net Asset Value per Share Proved Developed Producing Total Proved Proved + Probable 128,517 35,634 (61,779) 102,372 103,889 $0.99 260,421 35,634 (61,779) 234,276 103,889 $2.26 390,631 35,634 (61,779) 364,486 103,889 $3.51 (1)Based on the 2021 Insite Report, using the forecast future prices and costs. (2)Based on the exploration and evaluation assets as per the Company's December 31, 2021 audited consolidated financial statements. (3)See "Non-GAAP and Other Financial Measures" in the Management's Discussion & Analysis attached hereto. Page |6 MANAGEMENT'S DISCUSSION & ANALYSIS December 31, 2021 MANAGEMENT’S DISCUSSION & ANALYSIS The following is Management’s Discussion and Analysis ("MD&A") of the financial and operating results of Petrus Resources Ltd. ("Petrus" or the "Company") as at and for the year ended December 31, 2021. This MD&A is dated March 2, 2022 and should be read in conjunction with the Company's audited consolidated financial statements for the years ended December 31, 2021 and 2020. The Company’s consolidated financial statements are prepared in accordance with Canadian generally accepted accounting principles ("GAAP") which require publicly accountable enterprises to prepare their financial statements using International Financial Reporting Standards ("IFRS"). Readers are directed to the "Advisories" section at the end of this MD&A regarding forward-looking statements and boe presentation and to the section "Non-GAAP and Other Financial Measures" herein. The principal undertaking of Petrus is the investment in energy assets. The operations of the Company consist of the acquisition, development, exploration and exploitation of these assets. The Company’s head office is located at 2400, 240 - 4th Avenue SW, Calgary, Alberta, Canada. Additional information on Petrus, including the most recently filed Annual Information Form ("AIF"), are available under the Company's profile on SEDAR (the System for Electronic Document Analysis and Retrieval) at www.sedar.com. Page |8 SELECTED FINANCIAL INFORMATION OPERATIONS Average production Natural gas (mcf/d) Oil (bbl/d) NGLs (bbl/d) Total (boe/d) Total (boe) Light oil weighting Realized Prices Natural gas ($/mcf) Oil ($/bbl) NGLs ($/bbl) Total realized price ($/boe) Royalty income Royalty expense Net oil and natural gas revenue ($/boe) Operating expense Transportation expense Operating netback(1) ($/boe) Realized gain (loss) on derivatives ($/boe) Other income (cash) General & administrative expense Cash finance expense Decommissioning expenditures Funds flow & corporate netback(2) ($/boe) FINANCIAL (000s except $ per share) Oil and natural gas revenue Net income (loss) Net income (loss) per share Basic Fully diluted Funds flow Funds flow per share Basic Fully diluted Capital expenditures Weighted average shares outstanding Basic Fully diluted As at period end Common shares outstanding Basic Fully diluted Total assets Non-current liabilities Net debt(1) Twelve months ended Twelve months ended Three months ended Three months ended Three months ended Three months ended Dec. 31, 2021 Dec. 31, 2020 Dec. 31, 2021 Sept. 30, 2021 Jun. 30, 2021 Mar. 31, 2021 23,680 1,019 1,043 6,009 27,640 1,021 980 6,608 23,494 1,002 962 5,880 23,942 937 1,010 5,937 24,291 1,214 1,046 6,309 22,985 923 1,158 5,912 2,193,432 2,418,259 540,924 546,227 574,084 532,099 17 % 15 % 20 % 21 % 19 % 15 % 4.03 78.82 44.09 36.90 0.14 (4.72) 32.32 (5.89) (1.79) 24.64 (5.34) 0.49 (1.95) (2.34) (0.31) 15.19 2.57 44.14 20.84 20.67 0.16 (2.15) 18.68 (4.64) (1.43) 12.61 2.70 0.15 (1.41) (2.75) (0.37) 10.93 5.45 89.71 56.35 46.29 0.06 (6.34) 40.01 (5.02) (1.87) 33.12 (9.52) 0.04 (2.24) (1.58) (0.56) 19.26 4.04 82.56 45.10 37.00 0.18 (3.94) 33.24 (5.57) (1.81) 25.86 (6.41) 0.02 (1.47) (3.30) (0.27) 14.43 3.28 75.99 39.76 33.87 0.19 (4.87) 29.19 (6.80) (1.84) 20.55 (3.21) 1.77 (2.41) (2.52) (0.14) 14.04 3.33 66.61 36.79 30.55 0.15 (3.74) 26.96 (6.12) (1.62) 19.22 (2.28) 0.04 (1.65) (1.93) (0.27) 13.13 Twelve months ended Twelve months ended Three months ended Three months ended Three months ended Three months ended Dec. 31, 2021 Dec. 31, 2020 Dec. 31, 2021 Sept. 30, 2021 Jun. 30, 2021 Mar. 31, 2021 81,268 114,556 1.83 1.76 33,354 0.53 0.51 26,916 62,557 65,207 96,708 103,889 290,492 42,172 61,779 50,368 (97,554) (1.97) (1.97) 26,397 0.53 0.53 14,298 49,469 49,469 49,469 49,469 177,914 45,321 114,361 25,070 114,633 1.19 1.11 10,418 0.11 0.10 12,235 96,660 102,868 96,708 103,889 290,492 42,172 61,779 20,306 7,343 0.04 0.03 7,874 0.15 0.14 6,101 54,167 57,638 96,603 100,074 173,101 40,200 60,071 19,553 (4,265) (0.09) (0.09) 8,070 0.16 0.16 663 49,513 49,513 49,559 49,559 176,629 40,838 110,346 16,339 (3,155) (0.06) (0.06) 6,993 0.14 0.14 7,917 49,469 49,469 49,469 49,469 177,587 42,028 116,634 (1) Non-GAAP ratio. Refer to "Non-GAAP and Other Financial Measures". (2)Corporate netback is equal to funds flow, which is a comparable additional GAAP measure. Petrus analyzes these measures on an absolute value and per unit basis. Refer to "Non-GAAP and Other Financial Measures". Page |9 OPERATIONS UPDATE Fourth quarter average production by area was as follows: For the three months ended December 31, 2021 Natural gas (mcf/d) Oil (bbl/d) NGLs (bbl/d) Total (boe/d) Ferrier North Ferrier Foothills Central Alberta Kakwa Total 16,288 560 799 4,073 1,194 40 26 265 1,405 109 5 347 4,415 257 132 1,126 163 37 4 69 23,465 1,003 966 5,880 Fourth quarter 2021 production averaged 5,880 boe/d compared to 5,937 boe/d in the previous quarter. Three gross (3.0 net) wells were drilled with one well brought on production late in the quarter adding 114 boe/d to the fourth quarter average, which offset natural declines. Production was relatively consistent quarter over quarter. CAPITAL EXPENDITURES Capital expenditures (net of dispositions) totaled $12.2 million in the fourth quarter of 2021, compared to $2.8 million in the prior year comparative period. Fourth quarter 2021 capital spending was largely directed toward the drilling, completion and tie-in of three gross (3.0 net) wells in the Ferrier and North Ferrier areas. Capital expenditures (net of dispositions) totaled $26.9 million in the year ended December 31, 2021, compared to $14.3 million in 2020. The increase from the prior year is attributed to the Company's increased drilling as commodity prices continued to rise. The following table shows capital expenditures for the reporting periods indicated. All capital is presented before decommissioning obligations. Capital Expenditures ($000s) Drill and complete Oil and gas equipment and facilities Geological Land and lease Dispositions Capitalized general and administrative expense Total capital expenditures Gross (net) wells spud Three months ended Three months ended Twelve months ended Twelve months ended December 31, 2021 December 31, 2020 December 31, 2021 December 31, 2020 10,769 1,104 — 25 — 337 12,235 3 (3.0) 1,585 777 — 57 — 378 2,797 1 (1.0) 21,882 3,918 — 274 (99) 941 26,916 10 (6.4) 11,477 1,612 — 92 — 1,117 14,298 4 (3.2) Page |10 RESULTS OF OPERATIONS FINANCIAL AND OPERATIONAL RESULTS OF OIL AND NATURAL GAS ACTIVITIES Average production Natural gas (mcf/d) Oil (bbl/d) NGLs (bbl/d) Total (boe/d) Total (boe) Revenue ($000s) Natural gas Oil NGLs Royalty revenue Oil and natural gas revenue Average realized prices Natural gas ($/mcf) Oil ($/bbl) NGLs ($/bbl) Total realized price ($/boe) Hedging gain (loss) ($/boe) Total price including hedging ($/boe) Average benchmark prices Natural gas AECO 5A (C$/GJ) AECO 7A (C$/GJ) Crude oil Mixed Sweet Blend Edm (C$/bbl) Natural gas liquids Propane Conway (US$/bbl) Butane Edmonton (C$/bbl) Foreign exchange US$/C$ Twelve months ended Twelve months ended Three months ended Three months ended Three months ended Three months ended Dec. 31, 2021 Dec. 31, 2020 Dec. 31, 2021 Sept. 30, 2021 Jun. 30, 2021 Mar. 31, 2021 23,680 1,019 1,043 6,009 27,640 1,021 980 6,608 23,494 1,002 962 5,880 23,942 937 1,010 5,937 24,291 1,214 1,046 6,309 22,985 923 1,158 5,912 2,193,432 2,418,259 540,924 546,227 574,084 532,099 34,833 29,322 16,793 320 81,268 4.03 78.82 44.09 36.90 (5.34) 31.56 26,023 16,493 7,472 380 50,368 2.57 44.14 20.84 20.67 2.70 23.37 11,781 8,273 4,985 31 25,070 5.45 89.71 56.35 46.29 8,902 7,120 4,188 96 20,306 4.04 82.56 45.10 37.00 7,261 8,397 3,784 111 19,553 3.28 75.99 39.76 33.87 (9.52) (6.41) (3.21) 36.77 30.59 30.66 6,889 5,532 3,836 82 16,339 3.33 66.61 36.79 30.55 (2.28) 28.27 Twelve months ended Twelve months ended Three months ended Three months ended Three months ended Three months ended Dec. 31, 2021 Dec. 31, 2020 Dec. 31, 2021 Sept. 30, 2021 Jun. 30, 2021 Mar. 31, 2021 3.43 3.38 2.09 2.12 4.41 4.68 3.41 3.36 2.93 2.70 2.98 2.77 80.48 45.69 92.97 84.17 76.16 68.62 43.10 49.39 0.79 17.94 23.23 0.75 54.81 81.90 0.79 47.04 55.58 0.79 34.86 34.02 0.81 35.74 26.04 0.79 Page |11 FUNDS FLOW AND NET INCOME (LOSS) Petrus generated funds flow of $10.4 million in the fourth quarter of 2021 compared to $6.4 million in the fourth quarter of 2020. The 62% increase is due to higher commodity prices. In the fourth quarter of 2021 Petrus' total realized price was $46.29/boe compared to $24.05/ boe in the fourth quarter of 2020. For the year ended December 31, 2021, Petrus generated funds flow of $33.4 million compared to $26.4 million in the prior year. The 27% increase is due to higher commodity prices partially offset by realized hedging losses. Petrus reported net income of $114.6 million in the fourth quarter of 2021, compared to a net loss of $0.2 million in the fourth quarter of 2020. The net income in the fourth quarter of 2021 compared to the net loss in the fourth quarter of 2020 is primarily due to the net impairment reversal of $103.2 million recorded in the fourth quarter of 2021 as well as improved commodity prices after depressed pricing in 2020 due to the ongoing COVID-19 pandemic. On a twelve month basis, the Company generated net income of $114.6 million for the year ended December 31, 2021 compared to a net loss of $97.6 million for the year ended December 31, 2020. The year over year change is due to the $98.0 million impairment loss booked during the first quarter of 2020 and the net impairment reversal of $103.2 million recorded in 2021. ($000s except per share) Funds flow Funds flow per share - basic Funds flow per share - fully diluted Net income (loss) Net income (loss) per share - basic Net income (loss) per share - fully diluted Common shares outstanding (000s) Basic Fully diluted Weighted average shares outstanding (000s) Basic Fully diluted Three months ended Three months ended Twelve months ended Twelve months ended December 31, 2021 December 31, 2020 December 31, 2021 December 31, 2020 10,418 0.11 0.10 114,633 1.19 1.11 96,708 103,889 96,660 102,868 6,424 0.13 0.13 (151) — — 49,469 49,469 49,469 49,469 33,354 0.53 0.51 114,556 1.83 1.76 96,708 103,889 62,557 65,207 26,397 0.53 0.53 (97,554) (1.97) (1.97) 49,469 49,469 49,469 49,469 OIL AND NATURAL GAS REVENUE Fourth quarter average production in 2021 was 5,880 boe/d (67% natural gas), 8% lower than the fourth quarter of 2020 (6,357 boe/d; 69% natural gas). Fourth quarter oil and natural gas revenue in 2021 was $25.1 million compared to $14.1 million in 2020. The 77% increase is due to significantly higher commodity prices. Average production for the year ended December 31, 2021 was 6,009 boe/d (66% natural gas), 9% lower than 2020 (6,608 boe/d; 70% natural gas). Total oil and natural gas revenue increased from $50.4 million in 2020 to $81.3 million in 2021 due to the higher commodity prices. The following table presents oil and natural gas revenue by product and the change from the prior comparative periods: Oil and Natural Gas Revenue ($000s) Natural gas Crude oil and condensate Natural gas liquids Royalty income Total oil and natural gas revenue Three months ended Three months ended Twelve months ended Twelve months ended December 31, 2021 December 31, 2020 % Change December 31, 2021 December 31, 2020 % Change 11,781 8,273 4,985 31 25,070 7,395 4,475 2,195 78 14,143 59 % 85 % 127 % (60) % 77 % 34,833 29,322 16,793 320 81,268 26,023 16,493 7,472 380 50,368 34 % 78 % 125 % (16) % 61 % Page |12 The following table provides the average benchmark and the Company's average realized commodity prices: Three months ended Three months ended Twelve months ended Twelve months ended December 31, 2021 December 31, 2020 % Change December 31, 2021 December 31, 2020 % Change Average benchmark prices Natural gas AECO 5A (C$/GJ) AECO 7A (C$/GJ) Crude oil Mixed Sweet Blend Edm (C$/bbl) Natural gas liquids Propane Conway (US$/bbl) Butane Edmonton (C$/bbl) Average realized prices Natural gas ($/mcf) Oil ($/bbl) NGLs ($/bbl) Total average realized price 4.41 4.68 92.97 43.10 49.39 5.45 89.71 56.35 46.29 2.50 2.62 76 % 79 % 49.34 88 % 25.50 19.32 3.07 49.64 23.52 24.05 69 % 156 % 78 % 81 % 140 % 92 % 3.43 3.38 80.48 35.28 30.03 4.03 78.82 44.09 36.90 2.09 2.12 64 % 59 % 45.69 76 % 17.94 23.23 2.57 44.14 20.84 20.67 97 % 29 % 57 % 79 % 112 % 79 % The following table provides a breakdown of composition of the Company's production volume by product: Production Volume by Product (%) Natural gas Crude oil and condensate Natural gas liquids Total commodity sales from production Three months ended Three months ended Twelve months ended Twelve months ended December 31, 2021 December 31, 2020 December 31, 2021 December 31, 2020 67 % 17 % 16 % 100 % 69 % 15 % 16 % 100 % 66 % 17 % 17 % 100 % 70 % 15 % 15 % 100 % Natural gas Natural gas revenue for the year ended December 31, 2021 was $34.8 million, which increased 34% from the prior year ($26.0 million), despite lower natural gas production. The average realized natural gas price for the year ended December 31, 2021 increased 57% to $4.03/mcf from the prior year ($2.57/mcf). Natural gas revenue accounted for 43% of oil and natural gas revenue in 2021, compared to 52% in the prior year. Fourth quarter 2021 natural gas revenue was $11.8 million, which increased 59% from the prior year comparative period ($7.4 million). The average realized natural gas price in the fourth quarter of 2021 was $5.45/mcf, compared to $3.07/mcf in the fourth quarter of 2020 (78% increase). Natural gas revenue accounted for 47% of oil and natural gas revenue in the fourth quarter of 2021, compared to 53% in the prior year comparative period. The increase in natural gas revenue for the fourth quarter and the year ended December 31, 2021, compared to the same periods in 2020, was due to the increase in natural gas pricing (AECO 5A) of 76% and 64%, respectively. Crude oil and condensate Oil and condensate revenue for the year ended December 31, 2021 was $29.3 million, which increased 78% from the prior year ($16.5 million). The average realized oil and condensate price for the year ended December 31, 2021 increased 79% to $78.82/bbl from the prior year ($44.14/bbl). Oil and condensate revenue accounted for 36% of oil and natural gas revenue in 2021, compared to 33% in the prior year. Fourth quarter 2021 oil and condensate revenue was $8.3 million, which increased 85% from the prior year comparative period ($4.5 million). The average realized oil and condensate price was $89.71/bbl for the fourth quarter of 2021 compared to $49.64/bbl in the fourth quarter of 2020 (81% increase). Oil and condensate revenue accounted for 33% of oil and natural gas revenue in the fourth quarter of 2021, compared to 32% in the prior year comparative period. The increase in oil and condensate revenue is attributed to the rising oil prices in the current quarter and twelve month period as prices continue to recover from the low pricing seen during 2020 due to the effects of the COVID-19 global pandemic. Page |13 Natural gas liquids (NGLs) NGL revenue for the year ended December 31, 2021 was $16.8 million, which increased 125% from the prior year ($7.5 million). The average realized NGL price for the year ended December 31, 2021 increased 112% to $44.09/bbl from the prior year ($20.84/bbl). NGL revenue accounted for 21% of oil and natural gas revenue, compared to 15% in the prior year. Fourth quarter 2021 NGL revenue was $5.0 million, which increased 127% from the prior year comparative period ($2.2 million). The average realized NGL price was $56.35/bbl for the fourth quarter of 2021 compared to $23.52/bbl in the fourth quarter of 2020. The 140% increase is attributed to higher contract prices for NGL products, especially butane and propane. Fourth quarter market pricing for propane at Conway increased 69% from the prior year. Petrus' butane production is priced as a function of WTI (oil) which also increased in the fourth quarter compared to the prior year. NGL revenue accounted for 20% of oil and natural gas revenue in the fourth quarter of 2021, compared to 16% in the prior year comparative period. The Company’s NGL production mix consists of ethane, propane, butane and pentane. The pricing received for NGL production is based on annual contracts effective the first of April each year. The contract prices are based on the product mix, the fractionation process required and the demand for fractionation facilities. ROYALTY EXPENSE Royalties are paid to the Government of Alberta and to gross overriding royalty owners. The following table shows the Company’s royalty expense (net of royalty allowances and incentives) for the periods shown: Royalty Expense ($000s) Crown Percent of production revenue Gross overriding Total Three months ended Three months ended Twelve months ended Twelve months ended December 31, 2021 December 31, 2020 December 31, 2021 December 31, 2020 1,941 8 % 1,487 3,428 443 3 % 738 1,181 5,797 7 % 4,564 10,361 1,785 4 % 3,409 5,194 Fourth quarter royalty expense increased from $1.2 million in 2020 to $3.4 million in 2021. On a twelve month basis, total royalty expense (net of royalty allowances and incentives) increased from $5.2 million in 2020 to $10.4 million in 2021. The increase in royalties for the fourth quarter and the year ended December 31, 2021 is due to higher revenue (as a result of increased commodity prices). Gross overriding royalties increased from $0.7 million in the fourth quarter of 2020 to $1.5 million in the fourth quarter of 2021, due to higher revenue and commodity prices. Gross overriding royalties increased from $3.4 million for the year ended December 31, 2020 to $4.6 million for the year ended December 31, 2021 due to higher revenue (as a result of increased commodity prices). OTHER INCOME During the year ended December 31, 2021 the Company recorded $1.4 million as other income. $1.0 million was recorded in the second quarter of 2021 and related to the settlement of an outstanding dispute associated with the transportation and marketing of the Company's Ferrier area condensate volume. The remaining $0.4 million is related to a government grant for decommissioning activities provided to Petrus during the second quarter of 2021. RISK MANAGEMENT The Company utilizes financial derivative contracts to mitigate commodity price risk and provide stability and sustainability to the Company's economic returns, funds flow and capital development plan. Petrus’ risk management program is governed by guidelines approved by its Board of Directors. The impact of the contracts that were settled during the reporting periods are actual cash settlements and are recorded as realized hedging gains (losses). The unrealized gain (loss) is recorded to demonstrate the change in fair value of the outstanding contracts at the end of the financial reporting period for financial statement purposes. Petrus does not follow hedge accounting for any of its risk management contracts in place. Petrus considers all of its risk management contracts to be effective economic hedges of its underlying business transactions. Page |14 The table below shows the realized and unrealized gain or loss on risk management contracts for the periods shown: Net Gain (Loss) on Financial Derivatives ($000s) Three months ended Three months ended Twelve months ended Twelve months ended December 31, 2021 December 31, 2020 December 31, 2021 December 31, 2020 Realized hedging gain (loss) Unrealized hedging gain (loss) Net gain (loss) on derivatives (5,148) 6,064 916 381 491 872 (11,713) (2,408) (14,121) 6,518 1,661 8,179 In the fourth quarter of 2021, the Company recognized a realized hedging loss of $5.1 million compared to a gain of $0.4 million in the fourth quarter of 2020. The realized loss in the fourth quarter of 2021 decreased the Company’s corporate netback by $9.52/boe, compared to an increase of $0.65/boe in 2020. The Company recognized a realized hedging loss of $11.7 million during the year ended December 31, 2021, in comparison to the $6.5 million gain realized in 2020. The realized loss for the three and twelve months ended December 31, 2021 was due to higher commodity prices (relative to the respective contracts settled). During the fourth quarter of 2021, the Company recognized an unrealized gain of $6.1 million compared to an unrealized gain of $0.5 million in the fourth quarter of 2020. The Company recognized an unrealized hedging loss of $2.4 million for the year ended December 31, 2021 compared to an unrealized gain of $1.7 million for the year ended December 31, 2020. The loss represents the change in the unrealized risk management net liability position during the year ended December 31, 2021. This change is a result of changes related to contracts entered into and contracts settled during the period as well as changes in value of existing contracts due to changes in commodity prices. The Company’s risk management contracts provide protection from significant changes in crude oil and natural gas commodity prices for 2022 and 2023. The Company endeavors to hedge approximately half of its forecast production for the following year, and approximately 30% of its forecast production for the subsequent year. The Company's hedging strategy is intended to provide stability and sustainability to the Company's economic returns, funds flow and capital development plan. A summary of Petrus’ risk management contracts is included in note 10 of the Company’s annual consolidated financial statements as at and for the year ended December 31, 2021. The table below summarizes Petrus’ average crude oil and natural gas hedged volumes. The 12,333 GJ/day of average natural gas hedged for the remainder of 2021 represents 55% of fourth quarter 2021 average natural gas production. The following table summarizes the average and minimum and maximum cap and floor prices for the 2022 to 2023 oil and natural gas contracts outstanding as at the date of this report: Q4 Avg.(1) Q1 Q2 2023 Q3 Q4 Avg.(1) Oil hedged (bbl/d) Avg. WTI cap price ($C/bbl) Avg. WTI floor price ($C/bbl) Q1 Q2 800 70.95 70.95 2022 Q3 — — — — — — — — — 200 70.95 70.95 — — — Natural gas hedged (GJ/d) 12,000 13,000 13,000 11,000 12,250 10,000 Avg. AECO 7A cap price ($C/GJ) Avg. AECO 7A floor price ($C/GJ) 2.96 2.96 3.44 3.44 3.44 3.44 3.67 3.67 3.37 3.37 3.78 3.78 (1)The volumes and prices reported are the weighted average volumes and prices for the period. OPERATING EXPENSE The following table shows the Company’s operating expense for the reporting periods shown: — — — — — — — — — — — — — — — — — — — — — 2,500 3.78 3.78 Operating Expense ($000s) Fixed and variable operating expense Processing, gathering and compression charges Total gross operating expense Overhead recoveries Total net operating expense Operating expense, net ($/boe) Three months ended Three months ended Twelve months ended Twelve months ended December 31, 2021 December 31, 2020 December 31, 2021 December 31, 2020 2,853 631 3,484 (247) 3,237 5.53 11,134 2,719 13,853 (939) 12,914 5.89 9,673 2,463 12,136 (913) 11,223 4.64 2,182 745 2,927 (212) 2,715 5.02 Page |15 For the three months ended December 31, 2021, net operating expense totaled $2.7 million, a 16% decrease from $3.2 million during the prior year comparative period. On a per boe basis, net operating expense was 9% lower at $5.02/boe in the fourth quarter of 2021 compared to $5.53/boe in 2020 which is due to increased fixed and variable cost efficiencies. For the year ended December 31, 2021, net operating expense totaled $12.9 million, a 15% increase from the $11.2 million incurred in the prior year comparative period. The increase in operating expense for the year ended December 31, 2021 is due to a number of factors, the most significant, in order of value, are: lower cost recoveries (on a percentage to total gross operating expense basis); higher power prices; a one-time billing adjustment for prior year non-operated gas processing fees; and higher property tax and regulatory fees that were deferred or reduced in 2020 as a result of the COVID-19 pandemic relief. TRANSPORTATION EXPENSE The following table shows transportation expense paid in the reporting periods: Transportation Expense ($000s) Transportation expense Transportation expense ($/boe) Three months ended Three months ended Twelve months ended Twelve months ended December 31, 2021 December 31, 2020 December 31, 2021 December 31, 2020 1,010 1.87 983 1.68 3,920 1.79 3,452 1.43 Petrus pays commodity and demand charges for transporting its gas on pipeline systems. The Company also incurs trucking costs on the portion of its oil and natural gas liquids production that is not pipeline connected. For the three months ended December 31, 2021 transportation expense was $1.0 million or $1.87/boe compared to $1.0 million or $1.68/boe in the prior year comparative period. On a twelve month basis, transportation expense totaled $3.9 million, or $1.79/boe for 2021, which is 11% and 25% higher, respectively, than the $3.5 million of costs incurred (or $1.43/boe) in the prior year. The increase in transportation expense is attributed to the pipeline firm transportation contract that began at the end of the second quarter of 2020. GENERAL AND ADMINISTRATIVE EXPENSE The following table illustrates the Company’s general and administrative ("G&A") expense which is shown net of capitalized costs directly related to exploration and development activities: General and Administrative Expense ($000s) Personnel, consultants and directors Administrative expenses Regulatory and professional expenses Gross general and administrative expenses Capitalized general and administrative expenses Overhead recoveries General and administrative expenses General and administrative expense ($/boe) Three months ended Three months ended Twelve months ended Twelve months ended December 31, 2021 December 31, 2020 December 31, 2021 December 31, 2020 1,070 491 112 1,673 (289) (171) 1,213 2.24 1,039 300 326 1,665 (378) (228) 1,059 1.81 3,529 1,613 688 5,830 (878) (678) 4,274 1.95 3,028 1,102 1,118 5,248 (1,117) (722) 3,409 1.41 G&A expense (net of capitalized G&A expense and overhead recoveries) for the fourth quarter of 2021 totaled $1.2 million or $2.24/boe, compared to $1.1 million or $1.81/boe in the fourth quarter of 2020. Gross G&A expense (before capitalized G&A expense and overhead recoveries) was consistent with the the prior year ($1.7 million in the fourth quarter of 2021 compared to $1.7 million in the fourth quarter of 2020) due to lower staffing costs and regulatory expenses. For the year ended December 31, 2021, gross G&A expense was $5.8 million compared to $5.2 million in the prior year, which represents a 6% increase. Net G&A expense for the year ended December 31, 2021, was $4.3 million or $1.95/boe which is higher than the $3.4 million or $1.41/boe for the prior year comparative period (38% increase on a per boe basis). The net and gross increases in G&A are attributed to one-time expenses related to management changes and lower wage subsidy from the federal government during 2021. Page |16 SHARE-BASED COMPENSATION EXPENSE The following table illustrates the Company’s share-based compensation expense which is shown net of capitalized costs directly related to exploration and development activities: Share-Based Compensation Expense ($000s) Gross share-based compensation expense Capitalized share-based compensation expense Share-based compensation expense Three months ended Three months ended Twelve months ended Twelve months ended December 31, 2021 December 31, 2020 December 31, 2021 December 31, 2020 164 (48) 116 163 (20) 143 355 (96) 259 483 (102) 381 Share-based compensation expense (net of capitalized portion) was $0.12 million for the fourth quarter of 2021, which is 20% lower than the $0.14 million recognized in the fourth quarter of the prior year. For the year ended December 31, 2021, net share-based compensation expense was $0.26 million, which is 32% lower than the $0.38 million in the prior year comparative period. The decrease in stock based compensation expense for the current period and year-end compared to the prior year comparative periods is due to options fully vesting during 2020 and the deferral of new option grants until late 2021. FINANCE EXPENSE The following table illustrates the Company’s finance expense which includes cash and non-cash expenses: Finance Expense ($000s) Interest expense Finance fees Deferred financing costs Non-cash term loan interest payment-in-kind Accretion on decommissioning obligations Total finance expense Three months ended Three months ended Twelve months ended Twelve months ended December 31, 2021 December 31, 2020 December 31, 2021 December 31, 2020 811 45 61 — 198 1,115 1,081 375 145 936 107 2,644 4,108 1,025 365 2,573 707 8,778 5,738 923 625 1,813 494 9,593 Fourth quarter total finance expense was $1.1 million in 2021, comprised of $0.2 million of non-cash accretion of its decommissioning obligations, $0.8 million of cash interest expense and $0.05 million of finance fees. In the fourth quarter of 2020, the Company incurred total finance expense of $2.6 million, comprised of $0.1 million in non-cash accretion of its decommissioning obligation, $1.1 million cash interest expense, $0.4 million of finance fees, $0.9 million of non-cash term loan interest payment-in-kind related to the second lien term loan and $0.1 million of deferred financing fee amortization. The Company incurred total finance expense of $8.8 million for the year ended December 31, 2021, which is lower than the $9.6 million for the prior year. The decreases in total finance expense are due to a lower first lien loan balance and elimination of the second lien term loan during the year. DEPLETION AND DEPRECIATION The following table compares depletion and depreciation expense recorded in the reporting periods shown: Depletion and Depreciation Expense ($000s) Depletion and depreciation expense Depletion and depreciation expense ($/boe) Three months ended Three months ended Twelve months ended Twelve months ended December 31, 2021 December 31, 2020 December 31, 2021 December 31, 2020 5,508 10.18 6,121 10.47 22,992 10.48 25,231 10.43 Depletion and depreciation expense is calculated on a unit-of-production (boe) basis. This fluctuates period to period primarily as a result of changes in the underlying proved plus probable reserve base and in the amount of costs subject to depletion and depreciation, including future development cost. Such costs are segregated and depleted on an area by area basis relative to the respective underlying proved plus probable reserve base. Petrus recorded depletion and depreciation expense in the fourth quarter of 2021 of $5.5 million or $10.18/boe, compared to the fourth quarter of 2020, when $6.1 million or $10.47/boe was recorded. The decrease in the depletion expense for the fourth quarter of 2021 compared to the fourth quarter of 2020 was primarily due to lower production in 2021. Page |17 For the year ended December 31, 2021, the Company recorded $23.0 million or $10.48/boe, compared to $25.2 million or $10.43 per boe for the prior year comparative period. The decrease in total depletion and depreciation expense is attributed to lower production during 2021. IMPAIRMENT (REVERSAL) The following table illustrates impairment losses and reversals recorded in the reporting periods shown: Impairment (Reversal) ($000s) Impairment (reversal) Total Three months ended Three months ended Twelve months ended Twelve months ended December 31, 2021 December 31, 2020 December 31, 2021 December 31, 2020 (103,220) (103,220) — — (103,220) (103,220) 98,000 98,000 During 2021, Petrus recorded an impairment reversal of $106.9 million in its Ferrier CGU due to the significant increase in forward benchmark commodity prices at December 31, 2021 compared to December 31, 2020. In addition, Petrus also recognized an impairment loss of $3.7 million in its Kakwa CGU. The impairment reversal was allocated to PP&E ($80.6 million) and E&E ($22.6 million). The $103.2 million net amount of the impairment reversal was recorded in the Consolidated Statements of Net Income (Loss) and Comprehensive Income (Loss). For more information, refer to notes 5 and 6 of the December 31, 2021 audited consolidated financial statements. Petrus recognized an impairment loss of $98.0 million in the Ferrier CGU during the year ended December 31, 2020, due to the significant decrease in forward benchmark commodity prices at March 31, 2020 compared to December 31, 2019. For more information, refer to notes 5 and 6 of the December 31, 2021 audited consolidated financial statements. SHARE CAPITAL The Company's authorized share capital consists of an unlimited number of common shares and an unlimited number of preferred shares. The Company has not issued any preferred shares. The following table details the number of issued and outstanding securities for the periods shown: Share Capital (000s) Weighted average common shares outstanding Basic Fully diluted Common shares outstanding Basic Fully diluted Stock options outstanding Three months ended Three months ended Twelve months ended Twelve months ended December 31, 2021 December 31, 2020 December 31, 2021 December 31, 2020 96,660 102,868 96,708 103,889 5,563 49,469 49,469 49,469 49,469 2,277 62,557 65,207 96,708 103,889 5,563 49,469 49,469 49,469 49,469 2,277 At December 31, 2021, the Company had 96,707,912 common shares and 5,562,549 stock options outstanding. During the third quarter of 2021, the Company completed a private placement financing of an aggregate of $10 million of common shares at an issue price of $0.55 per share. All proceeds from the equity financing were applied to outstanding indebtedness under the Company's first lien loan. Prior to September 30, 2021, Petrus had a second debt instrument, a subordinated secured term loan (the "Term Loan"). During the third quarter of 2021, the Company settled the Term Loan with a principal amount (carrying value) of $39.4 million in consideration for the issuance of $15.8 million (the settlement amount) of common shares of Petrus to the holders of the Term Loan at an issue price of $0.55 per share. The difference between the loan amount and the value of the shares was recorded as contributed surplus. The Company has a deferred share unit plan in place whereby it may issue deferred share units ("DSUs") to directors of the Company. At December 31, 2021, 1,618,702 DSUs were issued and outstanding (December 31, 2020 – 2,158,270). Each DSU entitles the participants to receive, at the Company's discretion, either common shares or a cash equivalent to the number of DSUs multiplied by the current trading price of the equivalent number of common shares. All DSUs vest and become payable upon retirement of the director. The DSUs are included as equity as the company does not intend to settle the DSUs for cash. Page |18 LIQUIDITY AND CAPITAL RESOURCES Petrus has one debt instrument outstanding; a reserve-based, senior secured revolving credit facility with a syndicate of lenders, which is comprised of an operating facility and a syndicated facility (together, the “Revolving Credit Facility” or “RCF”). Revolving Credit Facility At December 31, 2021 the RCF was comprised of a $18.6 million operating facility and a $43.4 million syndicated facility with a maturity date of May 31, 2022. The Company has provided collateral by way of a debenture over all of the present and after acquired property of the Company. At December 31, 2021, the Company had a $0.6 million letter of credit outstanding against the RCF (December 31, 2020 – $0.6 million) and had drawn $57.7 million against the RCF (December 31, 2020 – $77.5 million). The amount of the RCF is subject to a borrowing base review performed on a semi-annual basis by the lenders, based primarily on reserves and commodity prices estimated by the lenders as well as other factors. In addition, asset dispositions require unanimous lender consent. A decrease in the borrowing base could result in a reduction to the available credit under the RCF. During the fourth quarter of 2021, the syndicate of lenders reconfirmed the Company's borrowing base of $64.8 million, which was reduced by $2.75 million on December 31, 2021 and will be reduced by a further $5.0 million on March 31, 2022. In addition, Petrus and the lenders under the RCF have agreed to a cash sweep provision under which 75% of excess cash flow will be used to accelerate repayment of the Company's RCF. The next scheduled borrowing base redetermination date for the RCF is on or before May 31, 2022. Debt Settlement - Term Loan During 2021, Petrus had a second debt instrument, a subordinated the "Term Loan". During the third quarter of 2021, the Company settled the Term Loan with a principal amount of $39.4 million in consideration for the issuance of $15.8 million of common shares of Petrus to the holders of the Term Loan at an issue price of $0.55 per share. Liquidity At December 31, 2021, the Company had a working capital deficiency (excluding non-cash risk management assets and liabilities) of $62.0 million due to the classification of the Company's borrowings under its RCF as a current liability. The Company's RCF's maturity date is May 31, 2022. The Company requires an extension or refinancing of its RCF. The borrowings under the RCF are classified as current liabilities in the December 31, 2021 audited consolidated financial statements, which has no impact on the debt covenants and the Company remains in compliance with each of its covenants. However, the reclassification of the debt instruments resulted in a working capital deficit of $62.0 million as of December 31, 2021. For the year ended December 31, 2021 the Company generated funds flow of $33.4 million and reduced its debt $56.3 million from December 31, 2020. Management is actively seeking alternative debt or equity financing to refinance the RCF prior to May 31, 2022. Based on current available information relating to future production volumes, forward commodity pricing, future costs including capital, operating and general and administrative, forward exchange rates, interest rates and taxes, all of which are subject to measurement uncertainty, management expects to comply with all financial covenants under its RCF during the subsequent 12 month period. Financial Covenants The Company's RCF is subject to certain financial covenants. The following definitions are used in the covenant calculations for the RCF: Working Capital Working Capital means Current Assets to Current Liabilities whereby Current Assets means on any date of determination, the current assets of Petrus that would, in accordance with IFRS, be classified as of that date as current assets plus any undrawn availability under the RCF, less any non-cash amount required to be included in current assets as the result of the application of IFRS including non-cash commodity and interest rate hedges assets and liabilities and whereby Current Liabilities means, on any date of determination, the liabilities of Petrus that would, in accordance with IFRS, be classified as of that date as current liabilities, excluding (a) non-cash obligations under IFRS including non-cash commodity and interest rate hedges assets and liabilities, and (b) the current portion of long-term debt. Working Capital Ratio means the ratio of Current Assets to Current Liabilities as defined above. The RCF carries the following covenants: i. ii. The Company is unable to borrow amounts greater than the RCF limit; and the Working Capital ratio shall not be less than 0.6:1.0. Page |19 Contractual Maturities The following are the contractual maturities of financial liabilities as at December 31, 2021: $000s Accounts payable and accrued liabilities Risk management liability Current portion of long term debt Lease obligations Total Total 19,690 2,488 57,700 820 80,698 < 1 year 19,690 2,488 57,700 217 80,095 Commitments The commitments for which the Company is responsible are as follows: $000s Firm service transportation Total 13,197 < 1 year 2,465 1-5 years 10,392 1-5 years — — — 603 603 > 5 years 340 Risk Management Petrus is engaged in the acquisition, development, exploration and exploitation of oil and natural gas in western Canada. The Company is exposed to a number of risks, both financial and operational, through the pursuit of its strategic objectives. Actively managing these risks improves the ability to effectively execute Petrus' business strategy. Financial risks associated with the oil and natural gas industry include fluctuations in commodity prices, interest rates, currency exchange rates and the cost of goods and services. Financial risks also include third party credit risk and liquidity risk. Operational risks include reservoir performance uncertainties, competition, regulatory, environment and safety concerns. For a more in-depth discussion of risk management, see notes 10 and 15 of the Company’s December 31, 2021 audited consolidated financial statements. Page |20 SUMMARY OF QUARTERLY RESULTS ($000s unless otherwise noted) Dec. 31, 2021 Sept. 30, 2021 Jun. 30, 2021 Mar. 31, 2021 Dec. 31, 2020 Sept. 30, 2020 Jun. 30, 2020 Mar. 31, 2020 Average Production Natural gas (mcf/d) Oil (bbl/d) NGLs (bbl/d) Total (boe/d) Total (boe) Financial Results Oil and natural gas revenue Royalty expense Net oil and natural gas revenue Transportation expense Operating expense Operating netback(1) Realized gain (loss) on derivatives Other income (cash) General and administrative expense Cash finance expense Decommissioning expenditures Corporate netback and funds flow(2) Oil and natural gas revenue Per share - basic Per share - fully diluted Net income (loss) Per share - basic Per share - fully diluted Common shares outstanding (000s) Basic Fully diluted Weighted average shares outstanding (000s) Basic Fully diluted Total assets Net debt(1) 23,494 23,942 24,291 22,985 26,177 26,181 27,630 30,604 1,002 962 5,880 937 1,010 5,937 1,214 1,046 6,309 923 1,158 5,912 980 1,014 6,357 1,103 997 867 819 6,463 6,291 1,134 1,088 7,323 540,924 546,227 574,084 532,099 584,860 594,599 572,440 666,361 25,070 20,306 19,553 16,339 14,143 12,840 9,041 14,344 (3,429) (2,150) (2,794) (1,989) (1,183) (1,245) (867) (1,899) 21,641 18,156 16,759 14,350 12,960 11,595 8,174 12,445 (1,010) (991) (1,057) (863) (983) (967) (799) (703) (2,715) (3,042) (3,903) (3,254) (3,237) (2,408) (2,543) (3,035) 17,916 14,123 11,799 10,233 8,740 8,220 4,832 (5,148) (3,504) (1,843) (1,215) 21 12 1,018 23 381 184 1,308 3,656 23 99 8,707 1,174 48 (1,213) (804) (1,381) (876) (1,059) (635) (817) (898) (856) (1,803) (1,444) (1,029) (1,456) (1,286) (1,831) (2,089) (302) (150) (79) (143) (366) (79) (84) (376) 10,418 7,874 8,070 6,993 6,424 7,551 5,855 6,566 25,070 20,306 19,553 16,339 14,143 12,840 9,041 14,344 0.26 0.24 0.37 0.35 0.39 0.39 0.33 0.33 0.29 0.29 0.26 0.26 0.18 0.18 0.29 0.29 114,633 7,343 (4,265) (3,155) (151) (3,678) (6,281) (87,444) 1.19 1.11 0.14 0.13 (0.09) (0.06) (0.09) (0.06) — — (0.07) (0.13) (0.07) (0.13) (1.77) (1.77) 96,708 96,603 49,559 49,469 49,469 49,469 49,469 49,469 103,889 100,074 49,559 49,469 49,469 49,469 49,469 49,469 96,660 54,167 49,513 49,469 49,469 49,469 49,469 49,469 102,868 57,638 49,513 49,469 49,469 49,469 49,469 49,469 290,492 173,101 176,629 177,587 177,914 179,895 184,532 193,679 (61,779) (60,071) (110,346) (116,634) (114,361) (116,717) (120,570) (125,974) (1)Non-GAAP measure. Refer to "Non-GAAP and Other Financial Measures". (2)Corporate netback is equal to funds flow, which is a comparable additional GAAP measure. Petrus analyzes these measures on an absolute value and per unit basis. Refer to "Non-GAAP and Other Financial Measures". The oil and natural gas exploration and production industry is cyclical in nature. Petrus' financial position, results of operations and corporate netback are affected by commodity prices, exchange rates, Canadian commodity price differentials and production levels. Petrus’ average quarterly production has decreased from 7,323 boe/d in the first quarter of 2020 to 5,880 boe/d in the fourth quarter of 2021. The 20% production decrease is attributable to Petrus' disciplined capital program prioritizing debt repayment as well as non-operated and third party downtime. Page |21 SELECTED ANNUAL INFORMATION ($000s unless otherwise noted) For the year ended, Oil and natural gas revenue Per share - basic Per share - fully diluted Net income (loss) Per share - basic Per share - fully diluted Common shares outstanding (000s) Basic Fully diluted Weighted avg. shares outstanding (000s) Basic Fully diluted Total assets Non-current liabilities CRITICAL ACCOUNTING ESTIMATES December 31, 2021 December 31, 2020 December 31, 2019 81,268 1.30 1.30 114,556 1.18 1.10 96,708 103,889 62,557 65,207 290,492 42,172 50,368 1.02 1.02 (97,554) (1.97) (1.97) 49,469 49,469 49,469 49,469 177,914 45,321 71,398 1.44 1.44 (42,176) (0.85) (0.85) 49,469 49,469 49,469 49,469 289,225 42,346 The timely preparation of financial statements in conformity with IFRS requires management to make judgments, estimates and assumptions that affect the application of accounting policies and reported amounts of assets and liabilities and income and expenses. Accordingly, actual results may differ from these estimates. Estimates and underlying assumptions are reviewed on an ongoing basis. Revisions to accounting estimates are recognized in the period in which the estimates are revised and in any future periods affected. Significant estimates and judgments made by management in the preparation of the financial statements are outlined below. The Company’s critical accounting estimates can be read in note 2 to the Company’s audited consolidated financial statements as at and for the year ended December 31, 2021. In March 2020, the World Health Organization declared the COVID-19 outbreak a global pandemic. The rapid outbreak and subsequent measures intended to limit the spread of COVID-19 have contributed to a significant increase in economic uncertainty, with more volatile commodity prices, currency exchange rates and interest rates. The duration and severity of the business disruptions and reduction in consumer activity nationally and internationally and the resulting financial effect is difficult to reliably estimate. The results of the potential economic downturn and any potential resulting direct or indirect effect on the Company has been considered in management’s estimates at period end; however, there could be a further prospective material effect in future periods. OTHER FINANCIAL INFORMATION Significant accounting policies The Company’s significant accounting policies can be read in note 3 of the Company’s audited consolidated financial statements as at and for the year ended December 31, 2021. New standards and interpretations The Company has not adopted any new standards and interpretations for the year ended December 31, 2021. Disclosure Controls and Procedures Petrus’ Chief Executive Officer and Chief Financial Officer have designed, or caused to be designed under their supervision, disclosure controls and procedures ("DC&P"), as defined by National Instrument 52-109 – Certification of Disclosure in Issuers’ Annual and Interim Filings (“NI 52-109”), to provide reasonable assurance that: (i) material information relating to the Company is made known to the Company's Chief Executive Officer and Chief Financial Officer by others, particularly during the period in which the annual filings are being prepared; and (ii) information required to be disclosed by the Company in its annual filings, interim filings or other reports filed or submitted by it under securities legislation is recorded, processed, summarized and reported within the time period specified in securities Page |22 legislation. The Chief Executive Officer and Chief Financial Officer of Petrus have evaluated, or caused to be evaluated under their supervision, the effectiveness of the Company's DC&P as at December 31, 2021 and have concluded that the Company's DC&P are effective at December 31, 2021 for the foregoing purposes. Internal Control over Financial Reporting Internal control over financial reporting (“ICFR”), as defined in NI 52-109, includes those policies and procedures that: (i) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of assets of Petrus; (ii) are designed to provide reasonable assurance that transactions are recorded as necessary to permit preparation of the consolidated financial statements in accordance with generally accepted accounting principles and that receipts and expenditures of Petrus are being made in accordance with authorizations of management and Directors of Petrus; and (iii) are designed to provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the Company’s assets that could have a material effect on the consolidated financial statements. The Chief Executive Officer and the Chief Financial Officer are responsible for establishing and maintaining ICFR for Petrus. For the year ended December 31, 2021, they have designed ICFR, or caused it to be designed under their supervision, 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 used to design the Company’s ICFR is the framework in Internal Control – Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission. There has not been any change in Petrus' ICFR that occurred during the period beginning on October 1, 2021 and ended on December 31, 2021 that has materially affected, or is reasonably likely to materially affect, Petrus' ICFR. Under the supervision of the Chief Executive Officer and the Chief Financial Officer, Petrus conducted an evaluation of the effectiveness of the Company’s ICFR as at December 31, 2021. Based on this evaluation, the Chief Executive Officer and Chief Financial Officer concluded that as at December 31, 2021, Petrus maintained effective ICFR. It should be noted that while the Chief Executive Officer and Chief Financial Officer believe that the Company’s controls provide a reasonable level of assurance with regard to their effectiveness, a control system, no matter how well conceived or operated, can provide only reasonable, not absolute, assurance that the objectives of the control system will be met and it should not be expected that the control system will prevent all errors or fraud. NON-GAAP AND OTHER FINANCIAL MEASURES This MD&A makes reference to the terms "operating netback", "corporate netback" and "net debt". These non-GAAP and other financial measures are not recognized measures under GAAP (IFRS) and do not have a standardized meaning prescribed by GAAP (IFRS). Accordingly, the Company's use of these terms may not be comparable to similarly defined measures presented by other companies. These non-GAAP and other financial measures should not be considered to be more meaningful than GAAP measures which are determined in accordance with IFRS as indicators of our performance. Management uses these non-GAAP and other financial measures for the reasons set forth below. Operating Netback Operating netback is a common non-GAAP financial measure used in the oil and natural gas industry which is a useful supplemental measure to evaluate the specific operating performance by product type at the oil and natural gas lease level. The most directly comparable GAAP measure to operating netback is funds flow/oil and natural gas revenue. Operating netback is calculated as oil and natural gas revenue less royalties and operating and transportation expenses. It is presented on an absolute value and on a per unit (boe) basis as a non-GAAP ratio. See below and under "Summary of Quarterly Results" for a reconciliation of operating netback to oil and natural gas revenue. Corporate Netback Corporate netback is a common non-GAAP financial measure used in the oil and natural gas industry which evaluates the Company’s profitability at the corporate level. Corporate netback is equal to funds flow, which is a directly comparable GAAP measure. Petrus analyzes these measures on an absolute value and on a per unit (boe) basis as a non-GAAP ratio. Management believes that funds flow and corporate netback provide information to assist a reader in understanding the Company's profitability relative to current commodity prices. They are calculated as the operating netback less general and administrative expense, finance expense, decommissioning expenditures, plus other income and the net realized gain (loss) on financial derivatives. See below and under "Summary of Quarterly Results" for a reconciliation of funds flow and corporate netback to oil and natural gas revenue. Page |23 Oil and natural gas revenue Royalty expense Net oil and natural gas revenue Transportation expense Operating expense Operating netback Realized gain (loss) on financial derivatives Other income General & administrative expense Cash finance expense(1) Decommissioning expenditures Funds flow and corporate netback (1)Excludes non-cash Term Loan interest payment-in-kind. Three months ended Three months ended Twelve months ended Twelve months ended December 31, 2021 December 31, 2020 December 31, 2021 December 31, 2020 $000s $/boe $000s $/boe $000s $/boe $000s $/boe 25,070 (3,429) 21,641 (1,010) (2,715) 17,916 (5,148) 21 (1,213) (856) (302) 10,418 46.35 (6.34) 40.01 (1.87) (5.02) 33.12 (9.52) 0.04 (2.24) (1.58) (0.56) 19.26 14,143 (1,183) 12,960 (983) (3,237) 8,740 381 184 (1,059) (1,456) (366) 6,424 24.18 81,268 (2.02) (10,361) 22.16 (1.68) (5.53) 14.95 0.65 0.31 (1.81) (2.49) (0.63) 70,907 (3,920) (12,914) 54,073 (11,713) 1,075 (4,274) (5,133) (674) 37.04 (4.72) 32.32 (1.79) (5.89) 24.64 (5.34) 0.49 (1.95) (2.34) (0.31) 50,368 (5,194) 45,174 (3,452) (11,223) 30,499 6,518 354 (3,409) (6,661) (904) 20.83 (2.15) 18.68 (1.43) (4.64) 12.61 2.70 0.15 (1.41) (2.75) (0.37) 10.98 33,354 15.19 26,397 10.93 Net Debt Net debt is a non-GAAP financial measure and is calculated as current assets (excluding unrealized financial derivative assets) less current liabilities (excluding unrealized financial derivative liabilities, lease obligations, and deferred share unit liabilities) and long term debt. Petrus uses net debt as a key indicator of its leverage and strength of its balance sheet. See below for a reconciliation of net debt to long term debt, being our nearest measure prescribed by GAAP (IFRS). ($000s) Adjusted current assets(1) Less: adjusted current liabilities(1) Net debt As at December 31, 2021 As at December 31, 2020 15,611 (77,390) (61,779) 7,428 (121,789) (114,361) (1)Adjusted for unrealized risk management assets, liabilities, lease obligations and unrealized deferred share unit liabilities. OIL AND GAS DISCLOSURES Our oil and gas reserves statement for the year ended December 31, 2021, which includes disclosure of our oil and natural gas reserves and other oil and natural gas information in accordance with NI 51-101, is contained in the AIF. The recovery and reserve estimates contained herein are estimates only and there is no guarantee that the estimated reserves will be recovered. Management uses oil and gas metrics for its own performance measurements and to provide shareholders with measures to compare Petrus' operations over time. Readers are cautioned that the information provided by these metrics, or that can be derived from the metrics presented in this MD&A, should not be relied upon for investment or other purposes. F&D Costs and FD&A Costs FD&A cost is defined as capital costs for the time period including change in FDC divided by change in reserves including revisions and production for that same time period. F&D cost is defined as capital costs for the time period including change in FDC divided by change in reserves including revisions and production for that same time period, excluding acquisitions and dispositions. Both F&D costs and FD&A costs take into account reserves revisions during the year on a per boe basis. The methodology used to calculate F&D costs includes disclosure required to bring the proved undeveloped and probable reserves to production. Annually, changes in forecast FDC occur as a result of Petrus' development, acquisition and disposition activities, undeveloped reserve revision and capital cost estimates. These values reflect the independent evaluator's best estimate of the cost to bring the proved and probable undeveloped reserves to production. Reserve Life Index Reserve life index is defined as total reserves by category divided by the annualized fourth quarter production. Reserve Replacement Ratio The reserve replacement ratio is calculated by dividing the yearly change in reserves net of production by the actual annual production for the year. Page |24 FD&A Recycle Ratio The FD&A recycle ratio is calculated by dividing operating netback by FD&A. ADVISORIES Basis of Presentation Financial data presented above has largely been derived from the Company’s financial statements, prepared in accordance with GAAP which require publicly accountable enterprises to prepare their financial statements using IFRS. Accounting policies adopted by the Company are set out in the notes to the consolidated financial statements as at and for the twelve months ended December 31, 2021. The reporting and the measurement currency is the Canadian dollar. All financial information is expressed in Canadian dollars, unless otherwise stated. Forward-Looking Statements Certain information regarding Petrus set forth in this MD&A contains forward-looking statements within the meaning of applicable securities law, that involve substantial known and unknown risks and uncertainties. The use of any of the words “anticipate”, “continue”, “estimate”, “expect”, “may”, “will”, “project”, “should”, “believe” and similar expressions are intended to identify forward-looking statements. Such statements represent Petrus’ internal projections, estimates or beliefs concerning, among other things, an outlook on the estimated amounts and timing of capital investment, anticipated future debt, production, revenues or other expectations, beliefs, plans, objectives, assumptions, intentions or statements about future events or performance. These statements are only predictions and actual events or results may differ materially. Although Petrus believes that the expectations reflected in the forward-looking statements are reasonable, it cannot guarantee future results, levels of activity, performance or achievement since such expectations are inherently subject to significant business, economic, competitive, political and social uncertainties and contingencies. Many factors could cause Petrus’ actual results to differ materially from those expressed or implied in any forward-looking statements made by, or on behalf of, Petrus. In particular, forward-looking statements included in this MD&A include, but are not limited to, statements with respect to: prospective changes to the terms of the RCF and Term Loan; Petrus' capital program, flexibility and utilization of free cash flow; Petrus' utilization of Federal and Provincial programs; Petrus' expectations regarding 2022 production volumes; Petrus' ability to modify its operations, including its ability to adjust liquid volumes and the results thereof; expectations regarding the adequacy of Petrus' liquidity and the funding of its financial liabilities; the impact of the current economic environment on Petrus; the performance characteristics of the Company's crude oil, NGL and natural gas properties; future prospects; the focus of and timing of capital expenditures; access to debt and equity markets; Petrus' future operating and financial results; capital investment programs; supply and demand for crude oil, NGL and natural gas; future royalty rates; drilling, development and completion plans and the results therefrom; and treatment under governmental regulatory regimes and tax laws. In addition, statements relating to “reserves” are deemed to be forward-looking statements, as they involve the implied assessment, based on certain estimates and assumptions, that the reserves described can be profitably produced in the future. These forward-looking statements are subject to numerous risks and uncertainties, most of which are beyond the Company’s control, including the impact of general economic conditions; volatility in market prices for crude oil, NGL and natural gas; impact of the economic crisis on the Company's lenders; willingness of the Company's lenders to negotiate; industry conditions; currency fluctuation; imprecision of reserve estimates; liabilities inherent in crude oil and natural gas operations; environmental risks; incorrect assessments of the value of acquisitions and exploration and development programs; competition; the lack of availability of qualified personnel or management; changes in income tax laws or changes in tax laws and incentive programs relating to the oil and gas industry; hazards such as fire, explosion, blowouts, cratering, and spills, each of which could result in substantial damage to wells, production facilities, other property and the environment or in personal injury; stock market volatility; ability to access sufficient capital from internal and external sources; completion of the financing on the timing planned and the receipt of applicable approvals; and the other risks. With respect to forward- looking statements contained in this MD&A, Petrus has made assumptions regarding: future commodity prices and royalty regimes; availability of skilled labour; timing and amount of capital expenditures; willingness of its lenders to negotiate; the impact of the current financial crisis; future exchange rates; the impact of increasing competition; conditions in general economic and financial markets; availability of drilling and related equipment and services; effects of regulation by governmental agencies; and future operating costs. Management has included the above summary of assumptions and risks related to forward-looking information provided in this MD&A in order to provide shareholders with a more complete perspective on Petrus’ future operations and such information may not be appropriate for other purposes. Petrus’ actual results, performance or achievement could differ materially from those expressed in, or implied by, these forward-looking statements and, accordingly, no assurance can be given that any of the events anticipated by the forward-looking statements will transpire or occur, or if any of them do so, what benefits that the Company will derive therefrom. Readers are cautioned that the foregoing lists of factors are not exhaustive. This MD&A contains future-oriented financial information and financial outlook information (collectively, "FOFI") about Petrus' prospective results of operations including, without limitation, its ability to repay debt, which are subject to the same assumptions, risk factors, limitations, and qualifications as set forth above. Readers are cautioned that the assumptions used in the preparation of such information, Page |25 although considered reasonable at the time of preparation, may prove to be imprecise and, as such, undue reliance should not be placed on FOFI. Petrus' actual results, performance or achievement could differ materially from those expressed in, or implied by, these FOFI, or if any of them do so, what benefits Petrus will derive therefrom. Petrus has included the FOFI in order to provide readers with a more complete perspective on Petrus' future operations and such information may not be appropriate for other purposes. These forward-looking statements and FOFI are made as of the date of this MD&A and the Company disclaims any intent or obligation to update any forward-looking statements and FOFI, whether as a result of new information, future events or results or otherwise, other than as required by applicable securities laws. BOE Presentation The oil and natural gas industry commonly expresses production volumes and reserves on a barrel of oil equivalent (“boe”) basis whereby natural gas volumes are converted at the ratio of six thousand cubic feet to one barrel of oil. The intention is to sum oil and natural gas measurement units into one basis for improved measurement of results and comparisons with other industry participants. Petrus uses the 6:1 boe measure which is the approximate energy equivalence of the two commodities at the burner tip. Boe’s do not represent an economic value equivalence at the wellhead and therefore may be a misleading measure if used in isolation. Abbreviations $000’s $/bbl $/boe $/GJ $/mcf bbl bbl/d boe mboe mmboe boe/d GJ GJ/d mcf mcf/d mmcf/d NGLs WTI thousand dollars dollars per barrel dollars per barrel of oil equivalent dollars per gigajoule dollars per thousand cubic feet barrel barrels per day barrel of oil equivalent thousand barrel of oil equivalent million barrel of oil equivalent barrel of oil equivalent per day gigajoule gigajoules per day thousand cubic feet thousand cubic feet per day million cubic feet per day natural gas liquids West Texas Intermediate Page |26 CONSOLIDATED ANNUAL FINANCIAL STATEMENTS As at and for the years ended December 31, 2021 and 2020 INDEPENDENT AUDITOR’S REPORT To the Shareholders of Petrus Resources Ltd. Opinion We have audited the consolidated financial statements of Petrus Resources Ltd. (the Company), which comprise the consolidated balance sheets as at December 31, 2021 and 2020, and the consolidated statements of net income (loss) and comprehensive income (loss), consolidated statements of changes in shareholders’ equity and consolidated statements of cash flows for the years then ended, and notes to the consolidated financial statements, including a summary of significant accounting policies. In our opinion, the accompanying consolidated financial statements present fairly, in all material respects, the consolidated financial position of the Company as at December 31, 2021 and 2020, and its consolidated financial performance and its consolidated 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. Our responsibilities under those standards are further described in the Auditor’s Responsibilities for the Audit of the Consolidated 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 consolidated 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. Material Uncertainty Related to Going Concern We draw attention to Note 2(a) in the consolidated financial statements, which indicates that the Company’s continued successful operations are dependent on its ability to refinance its debt. As stated in Note 2(a), these events or conditions indicate that a material uncertainty exists that may cast significant doubt on the Company’s ability to continue as a going concern. Our opinion is not modified in respect of this matter. Key Audit Matters Key audit matters are those matters that, in our professional judgment, were of most significance in the audit of the consolidated financial statements of the current period. In addition to the matter described in the Material Uncertainty Related to Going Concern section, we have determined the matter described below to be the key audit matter to be communicated in our report. This matter was addressed in the context of the audit of the consolidated financial statements as a whole, and in forming the auditor’s opinion thereon, and we do not provide a separate opinion on this matter. For the matter below, our description of how our audit addressed the matter is provided in that context. We have fulfilled the responsibilities described in the Auditor’s Responsibilities for the Audit of the Consolidated Financial Statements section of our report, including in relation to this matter. Accordingly, our audit included the performance of procedures designed to respond to our assessment of the risks of material misstatement of the consolidated financial statements. The results of our audit procedures, including the procedures performed to address the matter below, provide the basis for our audit opinion on the accompanying consolidated financial statements. Key audit matter How our audit addressed the key audit matter Impairment or Impairment Reversal of Property, Plant and Equipment (“PP&E”) and Exploration and Evaluation (“E&E”) Assets As at December 31, 2021, the carrying values of PP&E and E&E assets were $239.2 million and $35.6 million respectively. For the year ended December 31, 2021, an impairment reversal of $106.9 million was recorded with respect to the Ferrier cash generating unit (“CGU”), allocated $22.6 million to E&E assets and $84.3 million to PP&E; and an impairment charge of $3.8 million was recorded with respect to the Kakwa CGU, allocated entirely to PP&E. PP&E and E&E assets are tested for impairment only when circumstances indicate that the carrying value of a CGU may exceed its recoverable amount and for impairment reversal when there is any indication that previously recognized impairment losses may no longer exist or may have decreased. Impairment and impairment reversal is determined by estimating a CGU’s respective recoverable amount. The recoverable the Ferrier and Kakwa CGUs were amounts of determined based on their fair value less costs of disposal (“FVLCD”), which were estimated using a discounted cash flow approach. The Company discloses significant judgments, estimates and assumptions in respect of impairment in Note 3 to the consolidated financial statements, and the results of their analysis in Notes 5 and 6. the estimated recoverable amount of Auditing the Company’s Ferrier and Kakwa CGUs was complex due to the subjective nature of the various management inputs and assumptions and commodity price volatility. The primary inputs noted in the FVLCD model were production, pricing, royalties, operating costs, capital costs, costs of disposal and discount rate. Other Information To test the Company's estimated recoverable amounts for the Ferrier and Kakwa CGUs, we performed the following procedures, among others: – – – – – – – in against production forecasted the various the discount in determining forecasted prices used Involved our valuation specialists to assess the inputs methodology applied, and utilized rate by industry, economic, and referencing current comparable company information, company and cash-flow specific risk premiums. Compared historically realized production. the Compared impairment test to third-party reserve engineer data. Assessed forecasted royalties, operating costs and capital cost data by comparing it to historical performance. Assessed the competence and objectivity of the Company’s external reserve engineer. Tested the completeness and accuracy of the reserve engineer report by agreeing all current year production, revenue, royalty, operating cost, and capital cost data to management’s accounting records. Evaluated the adequacy of the impairment note disclosure included in Notes 5 and 6 of the accompanying consolidated financial statements in relation to this matter. Management is responsible for the other information. The other information comprises: a. b. Management’s Discussion and Analysis Annual Report Our opinion on the consolidated financial statements does not cover the other information and we do not express any form of assurance conclusion thereon. In connection with our audit of the consolidated financial statements, our responsibility is to read the other information, and in doing so, consider whether the other information is materially inconsistent with the consolidated financial statements or our knowledge obtained in the audit or otherwise appears to be materially misstated. We obtained Management’s Discussion & Analysis and the Annual Report prior to the date of this auditor’s report. If, based on the work we have performed, 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. Responsibilities of Management and Those Charged with Governance for the Consolidated Financial Statements Management is responsible for the preparation and fair presentation of the consolidated financial statements in accordance with IFRS, and for such internal control as management determines is necessary to enable the preparation of consolidated financial statements that are free from material misstatement, whether due to fraud or error. In preparing the consolidated financial statements, management is responsible for assessing the Company’s ability to continue as a going concern, disclosing, as applicable, matters related to going concern and using the going concern basis of accounting unless management either intends to liquidate the Company or to cease operations, or has no realistic alternative but to do so. Those charged with governance are responsible for overseeing the Company’s financial reporting process. Auditor’s Responsibilities for the Audit of the Consolidated Financial Statements Our objectives are to obtain reasonable assurance about whether the consolidated 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 generally accepted auditing standards 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 consolidated financial statements. As part of an audit in accordance with Canadian generally accepted auditing standards, we exercise professional judgment and maintain professional skepticism throughout the audit. We also: a. Identify and assess the risks of material misstatement of the consolidated 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. b. 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. c. Evaluate the appropriateness of accounting policies used and the reasonableness of accounting estimates and related disclosures made by management. d. 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 consolidated 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. e. Evaluate the overall presentation, structure and content of the consolidated financial statements, including the disclosures, and whether the consolidated 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 consolidated 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 Ryan MacDonald. Calgary, Alberta March 2, 2022 CONSOLIDATED BALANCE SHEETS (Presented in 000’s of Canadian dollars) As at December 31, 2021 December 31, 2020 ASSETS Current Cash Deposits and prepaid expenses Accounts receivable (note 15) Risk management asset (note 10) Total current assets Non-current Risk management asset (note 10) Exploration and evaluation assets (note 5) Property, plant and equipment (note 6) Total assets LIABILITIES AND SHAREHOLDERS’ EQUITY Current liabilities Bank indebtedness Bank loan (note 7) Accounts payable and accrued liabilities (note 15) Risk management liability (note 10) Lease obligations (note 8) Total current liabilities Non-current liabilities Lease obligations (note 8) Decommissioning obligation (note 9) Risk management liability (note 10) Total liabilities Shareholders’ equity Share capital (note 11) Contributed surplus Deficit Total shareholders' equity Total liabilities and shareholders' equity Commitments and contingencies (note 19) Related party transactions (note 21) Subsequent event (note 23) See accompanying notes to the consolidated financial statements Approved by the Board of Directors, (signed) “Don T. Gray” Don T. Gray Chairman 4,928 950 9,733 — 15,611 — 35,634 239,247 274,881 290,492 — 57,700 19,690 2,488 217 80,095 603 41,569 — 122,267 455,908 27,846 (315,529) 168,225 290,492 — 1,150 6,278 934 8,362 15 17,568 151,969 169,552 177,914 32 114,049 7,708 986 188 122,963 824 44,456 41 168,284 430,119 9,596 (430,085) 9,630 177,914 (signed) “Donald Cormack” Donald Cormack Director Page |31 CONSOLIDATED STATEMENTS OF NET INCOME (LOSS) AND COMPREHENSIVE INCOME (LOSS) (Presented in 000’s of Canadian dollars, except per share amounts) Year ended Year ended December 31, 2021 December 31, 2020 REVENUE Oil and natural gas revenue (note 20) Royalty expense Net oil and natural gas revenue Other income (note 20) Net gain (loss) on financial derivatives (note 10) EXPENSES Operating (note 13) Transportation General and administrative (note 14) Share-based compensation (note 11) Finance (note 17) Exploration and evaluation (note 5) Depletion and depreciation (note 6) Gain on sale of assets Impairment (reversal) (notes 5 and 6) Total expenses INCOME (LOSS) BEFORE INCOME TAX Income tax recovery (note 22) NET INCOME (LOSS) AND COMPREHENSIVE INCOME (LOSS) Net income (loss) per common share Basic (note 12) Diluted (note 12) See accompanying notes to the consolidated financial statements 81,268 (10,361) 70,907 1,448 (14,122) 58,233 12,914 3,920 4,274 259 8,778 108 22,992 (924) (103,220) (50,899) 109,132 (5,424) 114,556 1.83 1.76 50,368 (5,194) 45,174 354 8,179 53,707 11,223 3,452 3,409 381 9,593 18 25,231 (46) 98,000 151,261 (97,554) — (97,554) (1.97) (1.97) Page |32 CONSOLIDATED STATEMENTS OF CHANGES IN SHAREHOLDERS’ EQUITY (Presented in 000’s of Canadian dollars) Balance, December 31, 2019 Net loss Share-based compensation (note 11) Balance, December 31, 2020 Net income Deferred Share Unit settlement (note 11) Issuance of common shares (note 11) Share issue costs (note 11) Share-based compensation (note 11) Balance, December 31, 2021 See accompanying notes to the consolidated financial statements Share Capital 430,119 — — 430,119 — — 25,900 (111) — 455,908 Contributed Surplus 9,112 — 484 9,596 — (223) 18,119 — 354 27,846 Deficit (332,531) (97,554) — (430,085) 114,556 — — — — (315,529) Total 106,700 (97,554) 484 9,630 114,556 (223) 44,019 (111) 354 168,225 Page |33 CONSOLIDATED STATEMENTS OF CASH FLOWS (Presented in 000’s of Canadian dollars) OPERATING ACTIVITIES Net income (loss) Adjust items not affecting cash: Share-based compensation (note 11) Unrealized (gain) loss on financial derivatives (note 10) Non-cash finance expenses (note 17) Non-cash term loan interest payment-in-kind (note 17) Depletion and depreciation (note 6) Impairment (reversal) (notes 5 and 6) Exploration and evaluation expense (note 5) Gain on sale of assets (note 6) Recovery of income taxes on debt settlement (note 7) Other income (note 20) Decommissioning expenditures (note 9) Funds flow Change in operating non-cash working capital (note 18) Cash flows from operating activities FINANCING ACTIVITIES Deferred Share Unit payment (note 11) Issuance of shares (note 11) Repayment of revolving credit facility Drawing (repayment) of bank indebtedness Repayment of lease liabilities (note 8) Change in financing non-cash working capital (note 18) Cash flows used in financing activities INVESTING ACTIVITIES Property and equipment dispositions (note 6) Exploration and evaluation asset expenditures (note 5) Petroleum and natural gas property expenditures (note 6) Change in investing non-cash working capital (note 18) Cash flows used in investing activities Increase (decrease) in cash Cash, beginning of year Cash, end of year Cash interest paid (note 17) See accompanying notes to the consolidated financial statements Page |34 Year ended Year ended December 31, 2021 December 31, 2020 114,556 259 2,409 1,072 2,573 22,992 (103,220) 108 (924) (5,424) (373) (674) 33,354 (366) 32,988 (30) 10,107 (19,800) (32) (192) (179) (10,126) 148 (621) (26,550) 9,089 (17,934) 4,928 — 4,928 5,133 (97,554) 381 (1,661) 1,119 1,813 25,231 98,000 18 (46) — — (904) 26,397 2,527 28,924 — — (14,750) 32 (137) 162 (14,693) — (4,869) (9,439) (179) (14,487) (256) 256 — 6,661 NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS For the years ended December 31, 2021 and 2020 1. NATURE OF THE ORGANIZATION Petrus Resources Ltd. (the “Company” or "Petrus") was incorporated under the laws of the Province of Alberta on November 25, 2015. The principal undertaking of Petrus is the investment in energy business-related assets. The operations of the Company consist of the acquisition, development, exploration and exploitation of these assets. These consolidated financial statements reflect only the Company’s proportionate interest in such activities and are comprised of the Company and its subsidiaries, Petrus Resources Corp. and Petrus Resources Inc. The Company’s head office is located at 2400, 240 - 4th Avenue SW, Calgary, Alberta, Canada. These consolidated financial statements, for the years ended December 31, 2021 and 2020, were approved by the Company’s Audit Committee and Board of Directors on March 2, 2022. 2. BASIS OF PRESENTATION Going Concern These financial statements have been prepared in accordance with generally accepted accounting principles applicable to a going concern, which assumes that the Company will be able to realize its assets and discharge its liabilities in the normal course of business. As at December 31, 2021, the Company's revolving credit facility ("RCF") was due on May 31, 2022. The borrowing under the RCF is classified as a current liability in the December 31, 2021 consolidated financial statements. The Company intends to refinance the RCF; however, there is no assurance that it will be successful in this regard, which results in material uncertainty that may cast significant doubt on the Company’s ability to continue as a going concern. These financial statements do not include adjustments to the recoverability and classification of recorded asset and liabilities and related expenses that might be necessary should the Company be unable to continue as a going concern and therefore be required to realize its assets and liquidate its liabilities and commitments in other than the normal course of business at amounts different from those in the accompanying consolidated financial statements. Such adjustments could be material. Statement of Compliance These consolidated financial statements have been prepared by management in accordance with International Financial Reporting Standards (“IFRS”) as issued by the International Accounting Standards Board (“IASB”). Measurement Basis These consolidated financial statements were prepared on the basis of historical cost except for financial derivatives which are measured at fair value. This method is consistent with the method used in prior years. These consolidated financial statements are presented in Canadian dollars. Consolidation These audited consolidated financial statements include the accounts of Petrus and its 100% owned subsidiaries, Petrus Resources Corp. and Petrus Resources Inc. Subsidiaries are consolidated from the date control is obtained until the date control ends. Control exists where the Company has power over the investee, exposure or rights to variable returns from the investee and the ability to use its power over the investee to affect returns. All intra-group balances and transactions are eliminated on consolidation. Critical Accounting Estimates The timely preparation of financial statements in conformity with IFRS requires management to make judgments, estimates and assumptions that affect the application of accounting policies and reported amounts of assets and liabilities and income and expenses. Accordingly, actual results may differ from these estimates. Estimates and underlying assumptions are reviewed on an ongoing basis. Revisions to accounting estimates are recognized in the period in which the estimates are revised and in any future periods affected. Significant estimates and judgments made by management in the preparation of the financial statements are outlined below. i. Depletion and reserve estimates Petroleum and natural gas assets are depleted on a unit of production basis at a rate calculated by reference to proved and probable reserves determined in accordance with National Instrument 51-101 - Standards of Disclosure for Oil and Gas Activities (“NI 51-101”). The calculation incorporates the estimated future cost of developing and extracting those reserves. Proved and probable reserves are estimated using independent reservoir engineering reports and represent the estimated quantities of crude oil, natural gas and natural gas liquids which geological, geophysical and engineering data demonstrate with a specified degree of certainty to be recoverable in future years from known reservoirs and which are considered commercially producible. Reserves estimates, although not reported as part of the Company’s financial statements, can have a significant effect on net income (loss), assets and liabilities as a result of their impact on depletion and depreciation, decommissioning liabilities, deferred taxes, asset impairments and business combinations. Independent reservoir engineers perform evaluations of the Company’s petroleum and natural gas reserves on an annual basis. The estimation of reserves is an inherently complex process requiring significant judgment. Estimates of economically recoverable petroleum and natural gas reserves are based upon a number of variables and Page |35 assumptions such as geoscientific interpretation, production forecasts, commodity prices, costs and related future cash flows, all of which may vary considerably from actual results. These estimates are expected to be revised upward or downward over time, as additional information such as reservoir performance becomes available or as economic conditions change. ii. Impairment indicators and cash-generating units For purposes of impairment testing, exploration and evaluation assets and petroleum and natural gas assets are aggregated into cash- generating units (“CGUs”), based on separately identifiable and largely independent cash inflows. The determination of the Company’s CGUs is subject to judgment. The recoverable amounts of CGUs and individual assets have been determined based on the higher of the value-in-use calculations and fair value less costs of disposal. These calculations require the use of estimates and assumptions, including the discount rate, future petroleum and natural gas prices, expected production volumes and anticipated recoverable quantities of proved and probable reserves. These assumptions are subject to change as new information becomes available and changes in economic conditions take place. Changes may impact the estimated life of the field and economical reserves recoverable and may require a material adjustment to the carrying value of exploration and evaluation assets and petroleum and natural gas assets. The Company monitors internal and external indicators of impairment relating to its tangible assets. Technical feasibility and commercial viability of exploration and evaluation assets The determination of technical feasibility and commercial viability, based on the presence of proved and probable reserves, results in the transfer of assets from exploration and evaluation assets to property, plant and equipment. As discussed above, the estimate of proved and probable reserves is inherently complex and requires significant judgment. Thus any material change to reserve estimates could affect the technical feasibility and commercial viability of the underlying assets. Financial instruments Financial instruments are subject to valuations at the end of each reporting period. Generally the valuation is based on active and efficient markets. However, certain financial instruments may not be traded on an efficient market or the market may disappear or be subject to conditions that impede the efficiency of the market. Decommissioning obligation At the end of the operating life of the Company’s facilities and properties and upon retirement of its petroleum and natural gas assets, decommissioning costs will be incurred by the Company. This requires judgment regarding abandonment date, future environmental and regulatory legislation, the extent of reclamation activities, the engineering methodology for estimating cost, future removal technologies in determining the removal cost and discount rates to determine the present value of these cash flows. Income taxes Tax provisions are based on enacted or substantively enacted laws. Changes in those laws could affect amounts recognized in income or loss both in the period of change, which would include any impact on cumulative provisions, and in future periods. Changes in tax laws in the jurisdictions in which the Company operates could limit the ability of the Company to obtain tax deductions in future periods. Income taxes are subject to measurement uncertainty. Significant judgment can be involved in the recognition of deferred tax assets. iii. iv. v. vi. vii. Measurement of share-based compensation Share-based compensation recorded pursuant to share-based compensation plans is subject to estimated fair values, forfeiture rates and the future attainment of performance criteria. viii. Contingencies By their nature, contingencies will only be resolved when one or more future events occur or fail to occur. The assessment of contingencies inherently involves the exercise of significant judgment and estimates of the outcome of future events. 3. SIGNIFICANT ACCOUNTING POLICIES (a) Revenue recognition Revenue from contracts with customers is recognized when or as Petrus satisfies a performance obligation by transferring a promised good or service to a customer. The transfer of control of oil, natural gas, natural gas liquids usually occurs at a point in time and coincides with title passing to the customer and the customer taking physical possession. The transaction price for variable price contracts is based on the commodity price, adjusted for quality, location and other factors. The amount of revenue recognized is based on the agreed transaction price with any variability in transaction price recognized in the same period. (b) Exploration & evaluation assets Capitalization All costs incurred after the rights to explore an area have been obtained, such as geological and geophysical costs, other direct costs of exploration (drilling, testing and evaluating the technical feasibility and commercial viability of extraction) and appraisal and including any directly attributable general and administration costs and share-based payments, are accumulated and capitalized as exploration and evaluation assets. Page |36 Certain costs incurred prior to acquiring the legal rights to explore are charged directly to net income (loss). Depletion & depreciation Exploration and evaluation costs are not amortized prior to the conclusion of appraisal activities. At the completion of appraisal activities, if technical feasibility is demonstrated and commercial reserves are discovered, then the carrying value of the relevant exploration and evaluation asset will be reclassified as a property, plant and equipment asset into the CGU to which it relates, but only after the carrying value of the relevant exploration and evaluation asset has been assessed for impairment and, where appropriate, its carrying value adjusted. Technical feasibility and commercial viability are considered to be demonstrable when proved or probable reserves are determined to exist. If it is determined that technical feasibility and commercial viability have not been achieved in relation to the exploration and evaluation assets appraised, all other associated costs are written down to the recoverable amount in net income (loss). Expired land leases included as undeveloped land in exploration and evaluation assets are recognized in exploration and evaluation cost in net income (loss) upon expiry and are considered prior to expiry. Management considers upcoming land lease expiries and may recognize the costs in advance of expiry. Impairment Indicators of impairment of exploration and evaluation assets are assessed at each reporting date which can include upcoming land lease expiries, third party land valuations and other information. When there are such indications, an impairment test is carried out and any resulting impairment loss is written off to net income (loss). The recoverable amount is the greater of fair value, less costs of disposal, or value-in-use. (c) Property, plant and equipment The Company’s property, plant and equipment is comprised of petroleum and natural gas assets and corporate assets. Capitalization Petroleum and natural gas assets are measured at cost less accumulated depletion and depreciation and accumulated impairment losses, if any. Petroleum and natural gas assets consist of the purchase price and costs directly attributable to bringing the asset to the location and condition necessary for its intended use. Petroleum and natural gas assets include developing and producing interests such as land acquisitions, geological and geophysical costs, facility and production equipment, including any directly attributable general and administration costs and share-based payments and the initial estimate of the costs of dismantling and removing an asset and restoring the site on which it was located. Subsequent costs Costs incurred subsequent to the determination of technical feasibility and commercial viability are recognized as developing and producing petroleum and natural gas interests when they increase the future economic benefits embodied in the specific asset to which they relate. Such capitalized petroleum and natural gas interests generally represent costs incurred in developing proved and/or probable reserves, and are accumulated on a field or geotechnical area basis. The cost of day-to-day servicing of an item of petroleum and natural gas assets is expensed in income or loss as incurred. Petroleum and natural gas assets are derecognized upon disposal or when no future economic benefits are expected to arise from the continued use of the asset. Any gain or loss arising from the disposal of an asset, determined as the difference between the net disposal proceeds and the carrying amount of the asset, is recognized in net income or loss. Depletion and depreciation The costs for petroleum and natural gas properties, including related pipelines and facilities, are depleted using a unit-of-production method based on the commercial proved and probable reserves. Petroleum and natural gas assets are not depleted until production commences. This depletion calculation includes actual production in the period and total estimated proved and probable reserves attributable to the assets being depleted, taking into account total capitalized costs plus estimated future development costs necessary to bring those reserves into production. Relative volumes of reserves and production (before royalties) are converted at the energy equivalent conversion ratio of six thousand cubic feet of natural gas to one barrel of oil. Proved and probable reserves are estimated using independent reservoir engineering reports and represent the estimated quantities of crude oil, natural gas and natural gas liquids which geological, geophysical and engineering data demonstrate with a specified degree of certainty to be recoverable in future years from known reservoirs and which are considered commercially producible. Corporate assets are recorded at cost less accumulated depreciation. Depreciation is calculated on a declining balance method so as to write off the cost of these assets, less estimated residual values, over their estimated useful lives consistent with the treatment used for tax purposes. Impairment The assessment for impairment entails comparing the carrying value of the CGU with its recoverable amount: that is, the higher of fair value, less costs of disposal, and value in use. Petrus’ property, plant and equipment are grouped into CGUs based on separately identifiable and largely independent cash inflows considering geological characteristics, shared infrastructure and exposure to market risks. Estimates of future cash flows used in the calculation of the recoverable amount are based on reserve evaluation reports prepared by independent reservoir engineers. Page |37 The CGUs are reviewed quarterly for indicators of impairment. Indicators are events or changes in circumstances that indicate that the carrying amount may not be recoverable. If indicators of impairment exist, the recoverable amount of the CGU is estimated. If the carrying amount of the CGU exceeds the recoverable amount, the CGU is written down with an impairment recognized in net income (loss). The recoverable amount is the higher of fair value, less costs of disposal, and the value-in-use. Fair value, less costs of disposal, is derived by estimating the discounted after-tax future net cash flows. Discounted future net cash flows are based on forecast commodity prices and costs over the expected economic life of the reserves and discounted using market-based rates to reflect a market participant’s view of the risks associated with the assets. Value-in-use is assessed using the expected future cash flows discounted at a pre-tax rate. Impairments of property, plant and equipment are reversed when there is significant evidence that the impairment has been reversed, but only to the extent of what the carrying amount would have been had no impairment been recognized. (d) Decommissioning obligations The Company’s activities give rise to dismantling, decommissioning and reclamation requirements. Costs related to these abandonment activities are estimated by management in consultation with the Company’s engineers based on risk-adjusted current costs which take into consideration current technology in accordance with existing legislation and industry practices. Decommissioning obligations are measured at the present value of the best estimate of expenditures required to settle the obligations at the reporting date. When the fair value of the liability is initially measured, the estimated cost, discounted using a risk-free rate, is capitalized by increasing the carrying amount of the related petroleum and natural gas assets. The increase in the provision due to the passage of time, or accretion, is recognized as a finance expense. Increases and decreases due to revisions in the estimated future cash flows are recorded as adjustments to the carrying amount of the related petroleum and natural gas assets. Actual costs incurred upon settlement of the liability are charged against the obligation to the extent that the obligation was previously established. The carrying amount capitalized in petroleum and natural gas assets is depleted in accordance with the Company’s depletion policy. The Company reviews the obligation at each reporting date and revisions to the estimated timing of cash flows, discount rates and estimated costs will result in an increase or decrease to the obligations. Any difference between the actual costs incurred upon settlement of the obligation and recorded liability is recognized as an increase or reduction in income. (e) Finance expenses Finance expense may be comprised of interest expense on borrowings, acquisition related (transaction) costs, foreign exchange expenses and accretion of the discount on decommissioning obligations. (f) Financial instruments Financial instruments are recognized initially at fair value plus any directly attributable transaction costs. Subsequent to initial recognition, financial instruments are measured based on their classification as described below: • • Fair value through profit or loss: Financial instruments under this classification include risk management assets and liabilities. Amortized cost: Financial instruments under this classification include cash, accounts receivable, deposits, bank indebtedness, accounts payable and long term debt. (g) Share capital Common shares are classified as equity. Incremental costs directly attributable to the issuance of common shares are recognized as a reduction in share capital, net of any tax effects. (h) Flow-through shares The resources expenditure deductions for income tax purposes related to exploratory activities funded by flow-through shares are renounced to investors in accordance with tax legislation. Upon issuance of a flow-through share, a liability is recognized representing the premium paid on flow- through common shares over regular common shares. This liability is reduced as the expenditures are incurred and tax attributes are renounced. (i) Income taxes The Company’s income tax expense is comprised of current and deferred tax. Income tax expense is recognized through income or loss except to the extent that it relates to items recognized directly in equity, in which case the related income taxes are also recognized in equity. Current tax is the expected tax payable on taxable income for the period, using tax rates enacted or substantively enacted at the reporting date, and any adjustment to tax payable in respect of previous years. Deferred tax is recognized on temporary differences between the carrying amounts of assets and liabilities in the financial statements and the corresponding tax basis used in the computation of taxable income. Deferred tax liabilities are generally recognized for all taxable temporary differences. Deferred tax assets are generally recognized for all deductible temporary differences to the extent that it is probable that taxable income will be available against which those deductible temporary differences can be utilized. Assessing the recoverability of deferred tax assets requires management to make significant estimates related to expectations of future taxable income. Estimates of future taxable income are based on forecast cash flows from operations and the application of existing tax laws in the jurisdictions of Alberta and Canada. The carrying amount of deferred tax assets Page |38 is reviewed at the end of each reporting period and reduced to the extent that it is no longer probable that sufficient taxable income will be available to allow all or part of the asset to be recovered. (j) Joint arrangements A portion of the Company’s exploration, development and production activities are conducted jointly with others through unincorporated joint operations. These financial statements reflect only the Company’s proportionate interest of these joint operations and the proportionate share of the relevant revenue and related costs. (k) Share-based compensation Share-based compensation expense is determined based on the estimated fair value of shares on the date of grant. Forfeitures are estimated at the grant date and are subsequently adjusted to reflect actual forfeitures. The expense is recognized over the service period, with a corresponding increase to contributed surplus. The Company capitalizes the qualifying portion of share-based compensation expense directly attributable to the exploration and development activities of exploration and evaluation assets and petroleum and natural gas assets, with a corresponding decrease to share-based compensation expense. At the time the stock options or performance warrants are exercised, the issuance of common shares is recorded as an increase to shareholders’ capital and a corresponding decrease to contributed surplus. For deferred share units (“DSUs”) that can be settled in cash or equity at the option of the Company, the fair value of the DSUs is recognized as stock- based compensation expense, with a corresponding increase in contributed surplus. (l) Earnings per share Earnings per share are presented for basic and diluted earnings. Basic per share information is computed by dividing the net income (loss) for the period attributable to equity owners of the Company by the weighted average number of common shares outstanding during the period. The weighted average number of shares for diluted earnings per share information is calculated using the treasury stock method whereby it is assumed that proceeds obtained upon exercise of performance warrants and stock options would be used to purchase common shares at the average market price during the period. The treasury stock method also assumes that the deemed proceeds related to unrecognized share-based payments expense are used to repurchase shares at the average market price during the period. Under the treasury stock method, stock options and share warrants have a dilutive effect only when the average market price of the common shares during the period exceeds the exercise price of the options or warrants (they are "in- the-money"). Exercise of in-the-money stock options and share warrants is assumed at the beginning of the year or date of issuance, if later. Should the Company have a loss for the period, stock options and share warrants would be anti-dilutive and therefore will have no effect on the determination of loss per share. (m) Leases At inception of a contract, the Company assesses whether a contract is, or contains a lease. A contract is, or contains a lease if the contract conveys the right to control the use of an identified asset for a period of time in exchange for consideration. To assess whether a contract conveys the right to control the use of an identified asset, the Company assesses whether: • • • the contract involves the use of an identified asset - this may be specified explicitly or implicitly, and should be physically distinct or represent substantially all of the capacity of a physically distinct asset. If the suppler has a substantive substitution right, the asset is not identified; the Company has the right to obtain substantially all of the economic benefits from use of the asset throughout the period of use; and the Company has the right to direct the use of the asset. The Company has this right when it has the decision-making rights that are most relevant to changing how and for what purpose the asset is used is predetermined, the Company has the right to direct the use of the asset if either: ◦ ◦ the Company has the right to operate the asset; or the Company designed the asset in a way that predetermines how and for what purpose it will be used. This policy is applied to contracts entered into, or changed, on or after January 1, 2019. i) As a lessee The Company recognizes a right-of-use ("ROU") asset and a lease liability at the lease commencement date. The ROU asset is initially measured at cost, which comprises the initial amount of the lease liability adjusted for any lease payments made at or before the commencement date, plus any initial direct costs incurred and an estimate of costs to dismantle and remove the underlying asset or to restore the underlying asset or the site on which it is located, less any lease incentives received. The ROU asset is subsequently depreciated using the straight-line method from the commencement date to the earlier of the end of the useful life of the ROU asset or the end of the lease term. The estimated useful lives of ROU assets are determined on the same basis as those of property and equipment. In addition, the ROU asset is periodically reduced by impairment losses, if any, and adjusted for certain remeasurements of the lease liability. The lease liability is initially measured at the present value of the lease payments that are not paid at the commencement date, discounted using the intrest rate implicit in the lease or, if that rate cannot be readily determined, the Company's incremental borrowing rate. Generally, the Company uses its incremental borrowing rate as the discount rate. Page |39 (n) Government grants Government grants are recognized when there is reasonable assurance that the Company will comply with the conditions attaching to it, and that the grant will be received. Grants related to income are presented in the Consolidated Statement of Comprehensive Income (loss) and are deducted in reporting the related expense. Grants related to assets are presented in the Consolidated Balance Sheet by deducting the grant in arriving at the carrying amount of the asset or recognized as other income. (o) New standards and interpretations There are no new standards or interpretations to report. 4. DETERMINATION OF FAIR VALUES A number of the Company’s accounting policies and disclosures require the determination of fair value, for both financial and non-financial assets and liabilities. Fair values have been determined for measurement and/or disclosure purposes based on the following methods. When applicable, further information about the assumptions made in determining fair values is disclosed in the notes specific to that asset or liability. Petroleum and natural gas properties and equipment and exploration and evaluation assets The fair value of petroleum and natural gas properties and equipment recognized in a business combination and for impairment testing, is based on market values. The market value of petroleum and natural gas properties and equipment is the estimated amount for which property, plant and equipment could be exchanged on the acquisition date between a willing buyer and a willing seller in an arm’s length transaction after proper marketing wherein the parties had each acted knowledgeably, prudently and without compulsion. The market value of oil and natural gas interests (included in petroleum and natural gas properties and equipment) and intangible exploration and evaluation assets is estimated with reference to the discounted cash flow expected to be derived from oil and natural gas production based on externally prepared reserve reports. The risk-adjusted discount rate is specific to the asset with reference to general market conditions. The fair value less costs of disposal value used to determine the recoverable amount of the impaired petroleum and natural gas properties are classified as Level 3 fair value measurements. Refer to “Financial Instruments” section below for fair value hierarchy classifications. Derivatives The fair value of commodity price risk management contracts is determined by discounting the difference between the contracted prices and published forward price curves as at the balance sheet date, using the remaining contracted oil and natural gas volumes and a risk-free interest rate (based on published government rates). The fair value of options is based on option models that use published information with respect to volatility, prices, interest rates and counter-party credit risks. Share-based payments The fair value of employee share-based payments is measured using a Black-Scholes option-pricing model. Measurement inputs include share price on measurement date, exercise price of the instrument, expected volatility in share price (based on weighted average historic volatility adjusted for changes expected due to publicly available information), weighted average expected life of the instruments (based on historical experience and general option holder behavior), expected dividend yield, risk-free interest rate (based on government bonds) and estimated forfeiture rate at each reporting date. Financial Instruments The Company’s fair value measurements require disclosure about how the fair value was determined based on significant levels of inputs described in the following hierarchy: • • • 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. Assessment of the significance of a particular input to the fair value measurement requires judgment and may affect the placement within the fair value hierarchy level. The Company’s risk management contracts are considered Level 2. Page |40 5. EXPLORATION AND EVALUATION ASSETS The components of the Company’s exploration and evaluation ("E&E") assets are as follows: $000s Balance, December 31, 2019 Additions Disposition Exploration and evaluation expense Capitalized G&A Capitalized share-based compensation Transfers to property, plant and equipment (note 6) Impairment loss Balance, December 31, 2020 Additions Disposition Exploration and evaluation expense Capitalized G&A Capitalized share-based compensation (note 11) Impairment reversal Transfers to property, plant and equipment (note 6) Balance, December 31, 2021 36,116 4,590 (58) (18) 279 26 (367) (23,000) 17,568 401 (18) (108) 220 24 22,640 (5,093) 35,634 During the year ended December 31, 2021, the Company incurred exploration and evaluation expense of $0.1 million which relates to expired and nearly expired undeveloped, non-core land (year ended December 31, 2020 – $0.02 million). During the year ended December 31, 2021, the Company capitalized $0.2 million of general and administrative expenses (“G&A”) (year ended December 31, 2020 – $0.3 million) and $0.02 million of non-cash share-based compensation directly attributable to exploration activities (year ended December 31, 2020 – $0.03 million). During the year ended December 31, 2021, the Company transferred $5.1 million from E&E assets to PP&E assets, related to the Ferrier, North Ferrier and Kakwa Cash Generating Units ("CGUs"), which were brought on production during the second and fourth quarters. Due to the increase in forward benchmark commodity prices during the year ended December 31, 2021, the Company identified indicators of impairment reversal in its Ferrier Cash Generating Unit ("CGU"). As a result, for the Ferrier CGU, the Company recorded an impairment reversal of $22.6 million on its E&E assets, as the recoverable amount exceeded the carrying value. No impairment or impairment reversal for E&E assets was recorded on other CGUs of the Company. Due to the significant decrease in forward benchmark commodity prices in the first quarter, the Company identified indicators of impairment and conducted an impairment test on all of the Company's CGUs during the year ended December 31, 2020. No impairment was recorded for the Foothills, Central Alberta and Kakwa CGUs during the year ended December 31, 2020. For the Ferrier CGU, the Company recorded an impairment loss of $23.0 million on its E&E assets for the quarter ended March 31, 2020. The Company also tested the Ferrier CGU for impairment on December 31, 2020 and did not record any further impairment. Page |41 6. PROPERTY, PLANT AND EQUIPMENT The components of the Company’s property, plant and equipment ("PP&E") assets are as follows: $000s Balance, December 31, 2019 Additions Capitalized G&A Capitalized share based compensation Transfer from exploration and evaluation assets (note 5) Depletion & depreciation Increase in decommissioning expenses Impairment provision Balance, December 31, 2020 Additions Property dispositions Capitalized G&A Capitalized share-based compensation (note 11) Transfers from exploration and evaluation assets (note 5) Depletion & depreciation Changes in decommissioning provision (note 9) Impairment reversal Balance, December 31, 2021 Cost 821,861 8,600 838 77 367 — 3,840 — 835,583 25,593 (14,495) 658 73 5,093 — 329 — 852,834 Accumulated DD&A (583,383) — — — Net book value 238,478 8,600 838 77 — (25,231) — (75,000) (683,614) — 12,439 — — — (22,992) — 80,580 (613,587) 367 (25,231) 3,840 (75,000) 151,969 25,593 (2,056) 658 73 5,093 (22,992) 329 80,580 239,247 At December 31, 2021, estimated future development costs of $343.5 million (December 31, 2020 – $252.3 million) associated with the development of the Company’s proved plus probable undeveloped reserves were included with the costs subject to depletion. During the year ended December 31, 2021, the Company capitalized $0.7 million of general and administrative expenses (“G&A”) (year ended December 31, 2020 – $0.8 million) and non-cash share-based compensation of $0.07 million (year ended December 31, 2020 – $0.08 million), directly attributable to development activities. During the year ended December 31, 2021, the Company recorded a gain of $0.4 million on the disposition of certain E&E and PP&E assets in the Foothills CGU for cash consideration of $0.1 million and the assumption of $2.4 million of decommissioning liabilities. During the year ended December 31, 2021, the Company transferred $5.1 million from E&E assets to PP&E assets, related to the Ferrier, North Ferrier and Kakwa CGUs that were brought on production during the second and fourth quarters. At December 31, 2021, in its Ferrier CGU, the Company identified indicator of impairment reversal as a result of improved commodity prices. For the Kakwa CGU, the Company identified an indicator of impairment due to the decrease in proved and probable reserve values. As a result of the above indicators, an impairment test on the Company’s PP&E assets was performed. For the Ferrier CGU, the Company recorded an impairment reversal of $84.3 million on its PP&E assets on December 31, 2021, as the recoverable amount exceeded the carrying amount. The impairment reversal amount reflects all of the original impairment charges recorded on March 31, 2020 and December 31, 2014, less associated depletion. In addition, for the Kakwa CGU, the Company recorded an impairment charge of $3.7 million on its PP&E assets. For the North Ferrier, Central Alberta and Foothills CGUs, the Company did not identify any indicator of impairment or impairment reversal. The recoverable amount, a level 3 input on the fair value hierarchy, was estimated at its fair value less costs to dispose, using an after--tax discount rate of 11.6% to 13.1%. A 1% increase in the discount rate would have increased impairment by approximately $11.7 million. A 1% decrease in the discount rate would decrease impairment by approximately $0.2 million. The Company uses the following forward commodity price estimates: Page |42 Year 2022 2023 2024 2025 2026 2027 2028 2029 2030 2031 2032 Canadian Light Sweet $/Bbl AECO $/MMbtu 86.77 81.25 78.75 80.33 81.93 83.57 85.24 86.95 88.69 90.46 92.27 3.55 3.25 3.05 3.13 3.19 3.26 3.32 3.39 3.46 3.52 3.60 Escalation rate of 2.0% thereafter. During the year ended December 31, 2020, due to the significant decrease in forward benchmark commodity prices in the first quarter, the Company identified indicators of impairment and conducted an impairment test on all of the Company's CGUs. No impairment was recorded for the Foothills and Central Alberta CGUs during the year ended December 31, 2020. For the Ferrier CGU, the Company recorded an impairment loss of $75 million on its PP&E asset on March 31, 2020, as the carrying amount exceeded the recoverable amount. The Company had also tested the Ferrier CGU for impairment on December 31, 2020 and did not record any further impairment. At December 31, 2021, the carrying balance of the right of use asset was $0.8 million. During 2021, Petrus recorded minor disposition transactions for petroleum and natural gas properties and equipment for total net cash consideration of $0.1 million. 7. DEBT Petrus has one debt instrument outstanding; a reserve-based, senior secured revolving credit facility with a syndicate of lenders, which is comprised of an operating facility and a syndicated facility (together, the “Revolving Credit Facility” or “RCF”). Revolving Credit Facility At December 31, 2021 the RCF was comprised of a $18.6 million operating facility and a $43.4 million syndicated facility with a maturity date of May 31, 2022. The Company has provided collateral by way of a debenture over all of the present and after acquired property of the Company. At December 31, 2021, the Company had a $0.6 million letter of credit outstanding against the RCF (December 31, 2020 – $0.6 million) and had drawn $57.7 million against the RCF (December 31, 2020 – $77.5 million). The amount of the RCF is subject to a borrowing base review performed on a semi-annual basis by the lenders, based primarily on reserves and commodity prices estimated by the lenders as well as other factors. In addition, asset dispositions require unanimous lender consent. A decrease in the borrowing base could result in a reduction to the available credit under the RCF. During the fourth quarter of 2021, the syndicate of lenders reconfirmed the Company's borrowing base of $64.8 million, which was reduced by $2.75 million on December 31, 2021 and will be reduced by a further $5.0 million on March 31, 2022. In addition, Petrus and the lenders under the RCF have agreed to a cash sweep provision under which 75% of excess cash flow will be used to accelerate repayment of the Company's First Lien Loan. The next scheduled borrowing base redetermination date for the RCF is on or before May 31, 2022. Debt Settlement - Term Loan Prior to September 30, 2021, Petrus had a second debt instrument, a subordinated secured term loan (the "Term Loan"). During the third quarter of 2021, the Company settled its Term Loan with a principal amount (carrying value) of $39.4 million (the "Second Lien Settlement") in consideration for the issuance of $15.8 million (the settlement amount) of common shares of Petrus ("Common Shares") to the holders of the Term Loan at an issue price of $0.55 per share. The difference between the carrying value and the settlement amount of the debt was added to contributed surplus in the amount of $18.1 million (net of the recovery of income taxes of $5.4 million). Liquidity At December 31, 2021, the Company had a working capital deficiency (excluding non-cash risk management assets and liabilities) of $62.0 million due to the classification of the Company's borrowings under its RCF as a current liability. However, the Company remains in compliance with all financial covenants pertaining to its debt, and based on current available information relating to future production volumes, forward commodity pricing, future costs including capital, operating and general and administrative, forward exchange rates, interest rates and taxes, all of which are subject to measurement uncertainty, management expects to comply with all financial covenants during the subsequent 12 month period. Financial Covenants The Company's RCF is subject to certain financial covenants. The following definitions are used in the covenant calculations for the debt instrument: Page |43 Working Capital Working Capital means Current Assets to Current Liabilities whereby Current Assets means on any date of determination, the current assets of Petrus that would, in accordance with IFRS, be classified as of that date as current assets plus any undrawn availability under the RCF, less any non-cash amount required to be included in current assets as the result of the application of IFRS including non-cash commodity and interest rate hedges assets and liabilities and whereby Current Liabilities means, on any date of determination, the liabilities of Petrus that would, in accordance with IFRS, be classified as of that date as current liabilities, excluding (a) non-cash obligations under IFRS including non-cash commodity and interest rate hedges assets and liabilities, and (b) the current portion of long-term debt. Working Capital Ratio means the ratio of Current Assets to Current Liabilities as defined above. The RCF carries the following covenants: i. ii. The Company is unable to borrow amounts greater than the RCF limit; and the Working Capital ratio shall not be less than 0.6:1.0. The key financial covenants as at December 31, 2021 are summarized in the following table. At December 31, 2021 the Company is in compliance with all financial covenants. Financial Covenant Description Working Capital Ratio 8. LEASES The Company's lease obligations are as follows: $000s Balance, December 31, 2020 Finance expense Lease payments Balance, December 31, 2021 The Company's future commitments associated with its lease obligations are as follows: $000s Less than 1 year 1 to 3 years Total lease payments Amounts representing finance expense Present value of lease obligation Current portion of lease obligation Non-current portion of lease obligation 9. DECOMMISSIONING OBLIGATION Required Ratio Over 0.60 As at December 31, 2021 1.17 1,012 69 (261) 820 As at December 31, 2021 271 646 917 (97) 820 217 603 The decommissioning liability was estimated based on the Company’s net ownership interest in all wells and facilities, the estimated costs to abandon and reclaim the wells and facilities and the estimated timing of the costs to be incurred in future periods. The estimated future cash flows have been discounted using an average risk free rate of 1.66 percent and an inflation rate of 2.00 percent (1.10 percent and 1.40 percent, respectively, at December 31, 2020). Changes in estimates in 2020 and 2021 are due to the change in the risk free and inflation rates and changes in the estimated future cash flow to reclaim the wells and facilities. The Company has estimated the net present value of the decommissioning obligations to be $41.6 million as at December 31, 2021 ($44.5 million at December 31, 2020). The undiscounted, uninflated total future liability at December 31, 2021 is $38.3 million ($41.4 million at December 31, 2020). The payments are expected to be incurred over the operating lives of the assets. Page |44 The following table reconciles the decommissioning liability: $000s Balance, December 31, 2019 Property dispositions Other adjustments Liabilities incurred Liabilities settled Change in estimates Accretion expense Balance, December 31, 2020 Property dispositions Other adjustments Liabilities incurred Liabilities settled Change in estimates Accretion expense Balance, December 31, 2021 10. FINANCIAL RISK MANAGEMENT 41,259 (98) (135) 320 (904) 3,520 494 44,456 (2,876) (373) 489 (674) (160) 707 41,569 The Company utilizes commodity contracts as a risk management technique to mitigate exposure to commodity price volatility. The following table summarizes the financial derivative contracts Petrus had outstanding as at December 31, 2021: Type Total Daily Volume (GJ) Average Price (CDN$/GJ) Fixed price 10,000 $2.61 Type Total Daily Volume (Bbl) Average Price (CDN$/Bbl) Fixed price 600 $62.73 Type Average Rate (%) Notional Amount (000s CDN$) Fixed rate 2.24 $5,000 Asset — — 934 15 949 Liability 2,488 2,488 986 41 1,027 Year ended Year ended December 31, 2021 (11,713) December 31, 2020 6,518 (2,409) (14,122) 1,661 8,179 Contract Period Natural Gas Swaps Jan. 1, 2021 to Mar. 31, 2022 Contract Period Crude Oil Swaps Jan. 1, 2022 to Mar. 31, 2022 Contract Period Interest Rate Swaps Jan.1, 2022 to Jan. 31, 2022 Risk management asset and liability: $000s At December 31, 2021 Current commodity derivatives $000s At December 31, 2020 Current commodity derivatives Non-current commodity derivatives Earnings impact of realized and unrealized gains (losses) on financial derivatives: $000s Realized gain (loss) on financial derivatives Unrealized gain (loss) on financial derivatives Net gain (loss) on financial derivatives Page |45 The Company had the following physical commodity contracts in place as at December 31, 2021: Contract Period Natural Gas Jan. 1, 2022 to Mar. 31, 2022 Apr. 1, 2022 to Oct. 31, 2022 Apr. 1, 2022 to Oct. 31, 2022 Apr. 1, 2022 to Oct. 31, 2022 Apr. 1, 2022 to Oct. 31, 2022 Nov. 1, 2022 to Mar. 31, 2023 Nov. 1, 2022 to Mar. 31, 2023 Nov. 1, 2022 to Mar. 31, 2023 Contract Period Crude Oil Jan. 1, 2022 to Mar. 31, 2022 11. SHARE CAPITAL Type Total Daily Volume (GJ) Price (CDN$/GJ) Fixed price Fixed price Fixed price Fixed price Fixed price Fixed price Fixed price Fixed price 1,000 2,000 1,000 2,000 1,000 1,000 1,000 1,000 $4.69 $3.38 $3.33 $3.65 $3.04 $3.78 $3.30 $3.50 Type Total Daily Volume (Bbl) Price (CDN$/Bbl) Fixed price 200 $95.60 Authorized The authorized share capital consists of an unlimited number of common voting shares without par value and an unlimited number of preferred shares. Issued and Outstanding Common shares ($000s) Balance, December 31, 2020 Common shares issued for private placement, equity conversion and debt settlement Common shares issued on exercise of stock options Share issue costs Balance, December 31, 2021 Number of Shares 49,469,358 46,909,092 329,462 — 96,707,912 Amount 430,119 25,800 138 (111) 455,946 The Company completed a private placement financing of an aggregate of $10 million of Common Shares at an issue price of $0.55 per share. All proceeds from the Equity Financing have been applied to outstanding indebtedness under the First Lien Loan (see note 7). Petrus had a second debt instrument, a subordinated secured term loan. During the third quarter of 2021, the Company settled its Term Loan with a principal amount (carrying value) of $39.4 million in consideration for the issuance of $15.8 million (the settlement amount) of common shares of Petrus to the holders of the Term Loan at an issue price of $0.55 per share. The difference between the carrying value and the settlement amount of the debt was added to contributed surplus in the amount of $18.1 million (net of the recovery of income taxes of $5.4 million) SHARE-BASED COMPENSATION Stock Options The Company has a stock option plan in place whereby it may issue stock options to employees, consultants and directors of the Company. The aggregate number of shares that may be acquired upon exercise of all options granted pursuant to the plans shall, at any date or time of determination, be equal to ten percent (10%) of the number that is equal to (i) the number of the Company’s basic common shares then issued and outstanding; minus (ii) a number equal to five (5) times the number of common shares that are issuable upon exercise of the then outstanding Performance Warrants, if any, minus (iii) a number equal to fifty percent (50%) of the number of common shares that have previously been issued upon the exercise of Performance Warrants, if any. At December 31, 2021, 5,562,549 (December 31, 2020 – 2,276,923) stock options were outstanding. The summary of stock option activity is presented below: Page |46 Balance, December 31, 2019 Granted Cancelled/forfeited Expired Balance, December 31, 2020 Granted Forfeited Expired Exercised Balance, December 31, 2021 Exercisable, December 31, 2021 Number of stock options 2,361,958 1,122,276 (353,320) (853,991) 2,276,923 4,637,500 (623,513) (198,780) (529,581) 5,562,549 215,851 Weighted average exercise price $2.87 $0.23 $1.06 $2.16 $0.40 $0.75 $0.36 $1.68 $0.28 $0.67 $0.29 The following table summarizes information about the stock options granted and currently outstanding: Range of Exercise Price Stock Options Outstanding $0.23 - $0.50 $0.51 - $0.80 $0.81 - $1.00 Number granted Weighted average exercise price Weighted average remaining life (years) 911,288 3,636,261 1,015,000 5,562,549 $0.26 $0.70 $0.89 $0.67 1.47 2.78 3.01 2.61 During the year ended December 31, 2021, the Company granted 4,637,500 options which vest equally over three years, and upon vesting, expire 30 business days thereafter. The weighted average fair value of each option granted during the year ended December 31, 2021 of $0.27 was estimated on the date of grant using the Black-Scholes pricing model with the following weighted average assumptions: Risk free interest rate Expected life (years) Estimated volatility of underlying common shares (%) Estimated forfeiture rate Expected dividend yield (%) 2021 0.15% - 0.49% 1.08 - 3.08 100% to 113% 33 % — % 2020 0.20% - 0.29% 1.08 - 3.08 80% to 100% 20 % — % Petrus estimated the volatility of the underlying common shares by analyzing the Company's volatility as well as the volatility of peer group public companies with similar corporate structure, oil and gas assets and size. Deferred Share Unit ("DSU") Plan The Company has a deferred share unit plan in place whereby it may issue deferred share units to directors of the Company. The aggregate number of shares that may be issued from treasury of Petrus pursuant to the plan shall not exceed: (i) five percent (5%) of the number of issued and outstanding common shares of the Company (on a non-diluted basis) at the date of issue; and (ii) ten percent (10%) of the number of issued and outstanding common shares of the Company (on a non-diluted basis) at the date of issue, less the aggregate number of common shares of the Company reserved for issuance under any other share compensation plan. Each DSU entitles the participants to receive, at the Company's discretion, either shares of the Company or cash equal to the trading price of the equivalent number of shares of the Company. All DSUs granted vest and become payable upon retirement of the director. The compensation expense was calculated using the fair value method based on the trading price of the Company's shares on the grant date. At December 31, 2021, 1,618,702 DSUs were issued and outstanding (December 2020 – 2,158,270). During the first quarter of 2021, the Company settled 539,568 DSUs for $0.2 million in cash. Page |47 The following table summarizes the Company’s share-based compensation costs: $000s Expensed Capitalized to exploration and evaluation assets Capitalized to property, plant and equipment Deferred share units Total share-based compensation 12. EARNINGS (LOSS) PER SHARE Year ended Year ended December 31, 2021 259 24 73 — 356 December 31, 2020 152 26 77 229 484 Earnings (loss) per share amounts are calculated by dividing the net income (loss) for the period attributable to the common shareholders of the Company by the weighted average number of common shares outstanding during the period. Net income (loss) for the year ($000s) Weighted average number of common shares – basic (000s) Weighted average number of common shares – diluted (000s) Net income (loss) per common share – basic Net income (loss) per common share – diluted Year ended Year ended December 31, 2021 114,556 62,557 65,207 1.83 1.76 December 31, 2020 (97,554) 49,469 49,469 ($1.97) ($1.97) In computing diluted earnings per share for the year ended December 31, 2021, 5,562,549 outstanding stock options and 1,618,702 DSUs were considered (December 31, 2020 – 2,276,923 and 2,158,270 respectively). 4,547,549 stock options and 1,618,702 DSUs were included in calculating the number of diluted common shares. There were 1,015,000 stock options that were anti-dilutive as the exercise price was higher than the average share price during the year ended December 31, 2021. 13. OPERATING EXPENSES The Company’s operating expenses consisted of the following expenditures: $000s Fixed and variable operating expenses Processing, gathering and compression charges Total gross operating expenses Overhead recoveries Total net operating expenses 14. GENERAL AND ADMINISTRATIVE EXPENSES The Company’s general and administrative expenses consisted of the following expenditures: $000s Gross general and administrative expenses Capitalized general and administrative expenses Overhead recoveries General and administrative expenses 2021 11,134 2,719 13,853 (939) 12,914 2021 5,830 (878) (678) 4,274 2020 9,673 2,463 12,136 (913) 11,223 2020 5,248 (1,117) (722) 3,409 Page |48 15. FINANCIAL INSTRUMENTS Risks associated with financial instruments Credit risk The Company’s accounts receivable are with customers and joint venture partners in the petroleum and natural gas business and are subject to normal credit risk. Concentration of credit risk is mitigated by marketing the majority of the Company’s production to reputable and financially sound purchasers under normal industry sale and payment terms. As is common in the petroleum and natural gas industry in western Canada, Petrus’ receivables relating to the sale of petroleum and natural gas are received on or about the 25th day of the following month. Of the $9.7 million of accounts receivable outstanding at December 31, 2021 (December 31, 2020 – $6.3 million), $7.4 million is owed from 3 parties (December 31, 2020 – $4.7 million from 3 parties), and the balances were received subsequent to December 31, 2021. The Company considers accounts receivable outstanding past 120 days to be 'past due'. At December 31, 2021, the Company had an allowance for doubtful accounts of $0.5 million (December 31, 2020 – $0.5 million). At December 31, 2021, 90% of Petrus’ accounts receivable were aged less than 120 days and 10% of Petrus' accounts receivable were aged greater than 120 days. The Company does not anticipate any material collection issues. The Company’s risk management assets and cash are with chartered Canadian banks and the Company does not consider these assets to carry material credit risk. Liquidity risk At December 31, 2021, the Company had a $62.0 million RCF, on which $57.7 million was drawn (December 31, 2020 – $77.5 million). While the Company is exposed to the risk of reductions to the borrowing base of the RCF, the Company anticipates it will continue to have adequate liquidity to fund its financial liabilities through funds flow and available credit capacity from its RCF. The Company's RCF's maturity date is May 31, 2022. The Company requires an extension or refinancing of its RCF. The borrowings under the RCF are classified as current liabilities in the December 31, 2021 consolidated financial statements which has no impact on the debt covenants and the Company remains in compliance with each of its covenants. However, the reclassification of the debt instruments resulted in a working capital deficit of $62.0 million as of December 31, 2021. For the year ended December 31, 2021 the Company generated funds flow of $33.4 million and reduced its debt $56.3 million from December 31, 2020. Management is actively seeking alternative debt or equity financing to refinance the RCF prior to May 31, 2022. The following are the contractual maturities of financial liabilities as at December 31, 2021: $000s Accounts payable and accrued liabilities Risk management liability Current portion of long term debt Lease obligations Total Total 19,690 2,488 57,700 820 80,698 < 1 year 19,690 2,488 57,700 217 80,095 1-5 years — — — 603 603 Interest Rate Risk Interest rate risk is the risk that future cash flows will fluctuate as a result of changes in market interest rates. The Company’s cash, bank indebtedness and accounts receivable are not exposed to significant interest rate risk. The RCF is exposed to interest rate cash flow risk as the instrument is priced on a floating interest rate subject to fluctuations in market interest rates. The remainder of Petrus’ financial assets and liabilities are not exposed to interest rate risk. To manage exposure to interest rate volatility, the Company entered into interest rate swap contracts (note 10). A 1% increase in the Canadian prime interest rate during the year ended December 31, 2021 would have decreased net income by approximately $0.8 million, which relates to interest expense on the average outstanding RCF, net of any interest rate swaps to fix the interest rate on loans, assuming that all other variables remain constant (December 31, 2020 – $1.0 million). A 1% decrease in the Canadian prime interest rate during the year would result in an opposite impact on net income. Commodity Price Risk Commodity price risk is the risk that the fair value of future cash flows will fluctuate as a result of changes in commodity prices. A significant change in commodity prices can materially impact the Company’s borrowing base limit under its Revolving Credit Facility and may reduce the Company’s ability to raise capital. Commodity prices for petroleum and natural gas are not only influenced by Canadian and United States demand, but also by world events that dictate the levels of supply and demand. The Company manages the risks associated with changes in commodity prices by entering into a variety of financial derivative contracts (see note 10). The Company assesses the effects of movement in commodity prices on net loss. When assessing the potential impact of these commodity price changes, the Company believes a $5/CDN WTI/bbl change in the price of oil and a $0.25/GJ change in the price of natural gas are reasonable measures. As at December 31, 2021, it was estimated that a $0.25/GJ decrease in the price of natural gas would have increased net income by $0.2 million (December 31, 2020 – $1.3 million). An opposite change in commodity prices would result in an opposite impact on net income for the period. As at December 31, 2021, it was estimated that a $5.00/CDN WTI/bbl decrease in the price of oil would have increased net income by $0.3 million (December 31, 2020 – $1.1 million). An opposite change in commodity prices would result in an opposite impact on net income for the period. Page |49 16. CAPITAL MANAGEMENT The Company’s general capital management policy is to maintain a sufficient capital base in order to manage its business to enable the Company to increase the value of its assets and therefore its underlying share value. In the management of capital, the Company includes share capital and total net debt, which is made up of debt and working capital (current assets less current liabilities). The Company manages its capital structure and makes adjustments in light of economic conditions and the risk characteristics of the underlying assets. In order to maintain or adjust the capital structure, Petrus may issue new equity, increase or decrease debt, adjust capital expenditures and acquire or dispose of assets. 17. FINANCE EXPENSES The components of finance expenses are as follows: $000s Cash: Interest and finance fees Total cash finance expenses Non-cash: Deferred financing costs Non-cash term loan interest payment-in-kind Accretion on decommissioning obligations (note 9) Total non-cash finance expenses Total finance expenses 18. SUPPLEMENTAL CASH FLOW INFORMATION The following table reconciles the changes in non-cash working capital as disclosed in the statements of cash flows: $000s Source (use) in non-cash working capital: Deposits and prepaid expenses Transaction costs on debt Investments Accounts receivable Accounts payable and accrued liabilities Operating activities Financing activities Investing activities 2021 5,133 5,133 365 2,573 707 3,645 8,778 2021 199 (178) (3) (3,455) 11,982 8,545 (366) (179) 9,089 2020 6,661 6,661 625 1,813 494 2,932 9,593 2020 179 (773) — 6,758 (3,655) 2,509 2,527 162 (179) The following table reconciles the changes in liability resulting from financing activities: $000s Balance, December 31, 2020 Cash flows Payment-in-kind Non-cash changes Balance, December 31, 2021 Bank Indebtedness Revolving Credit Facility Term Loan Total Liabilities from Financing Activities 32 (32) — — — 77,484 (19,800) — 16 57,700 36,565 — 2,573 (39,138) — 114,081 (19,832) 2,573 (39,122) 57,700 19. COMMITMENTS AND CONTINGENCIES COMMITMENTS The commitments for which the Company is responsible are as follows: Page |50 $000s Firm service transportation Total 13,197 < 1 year 2,465 1-5 years 10,392 > 5 years 340 CONTINGENCIES In the normal course of Petrus’ operations, the Company may become involved in, named as a party to, or be the subject of, various legal proceedings. The outcome of outstanding, pending or future proceedings cannot be predicted with certainty. Petrus does not anticipate that these claims will have a material impact on its financial position. 20. REVENUE The following table presents Petrus' oil and natural gas revenue disaggregated by product type: $000s Production Revenue Oil and condensate sales Natural gas sales Natural gas liquids sales Total oil and natural gas production revenue Royalty revenue Total oil and natural gas revenue 2021 29,322 34,833 16,793 80,948 320 81,268 2020 16,493 26,023 7,472 49,988 380 50,368 During the year ended December 31, 2021, the Company recorded $1.4 million as other income. This amount mainly relates to the settlement of an outstanding dispute associated with the transportation and marketing of its Ferrier area condensate volume. 21. RELATED PARTY TRANSACTIONS The Company considers its directors and officers to be key management personnel. The following table outlines transactions with key management personnel: $000s Salaries, consulting fees, benefits and director fees, gross Share based compensation, gross 2021 1,307 85 1,392 2020 890 228 1,118 During the third quarter of 2021, the Chairman of the Company acquired 15,636,364 Common Shares at an issue price of $0.55 per share for total proceeds of $8.6 million. An individual related to the Chairman of the Company acquired 2,545,455 Common Shares at an issue price of $0.55 per share for total proceeds of $1.4 million. Two individuals related to the Chairman of the Company settled their Term Loan with the Company for 28,727,273 Common Shares at an issue price of $0.55 per share. Page |51 22. DEFERRED INCOME TAXES $000s Income (loss) before taxes Combined federal and provincial tax rate Computed “expected” tax recovery Increase/(decrease) in taxes resulting from: Permanent items Share based payments Share issuance costs Impact of rate change True up and other Unrecognized deferred income tax asset Deferred tax expense (recovery) Effective tax rate The components of the Company’s deferred tax position at December 31, 2021 and 2020 are as follows: $000s Exploration and evaluation assets and property, plant and equipment Asset retirement obligations Share issuance costs Non capital loss carry-forwards Unrealized hedging loss Deferred tax liability 2021 109,132 23.0 % 25,100 1 82 — — 1,615 (32,222) (5,424) (5) % 2021 19,116 (9,561) — (8,983) (572) — 2020 (97,554) 24.0 % (23,413) 4 103 — 976 596 21,734 — — % 2020 — — — — — — The company has unrecognized deductible temporary differences in the form of non-capital loss carry-forward of approximately 224.8 million (2020 - $341.3 million). The Company had non-capital losses of approximately $263.9 million (2020 – $217.8 million) which may be applied against future income for Canadian tax purposes. These non-capital losses expire in 2027 and onwards. At December 31, 2021, the Company has determined it is currently not probable that future taxable profits will be available against which the tax benefits will be utilized. 23. SUBSEQUENT EVENTS Subsequent to December 31, 2021, the Company entered into a definitive agreement to acquire producing oil and gas properties that are held by a privately owned limited partnership and its general partner (the "Acquired Entities") for total consideration of approximately $14.4 million, consisting of 10 million common shares of the Company issued at a deemed price of $1.44 per share based on the volume weighted average trading price of the common shares of the Company on the TSX for the five trading days prior to the date of the Agreement (the "Acquisition"). The Acquisition is expected to close in March 2022 and is subject to customary closing conditions. The Acquisition is a related party transaction under applicable securities legislation as the Acquired Entities are managed and directed by the President and Chief Executive Officer of the Company, and the President and Chief Executive Officer of the Company and two of Petrus' controlling shareholders own or control, in aggregate, approximately 70% of the limited partnership's units and 50% of the general partner's shares. Under IFRS 3, if the acquisition date of a business combination is after the end of the reporting period, but prior to the publication of the consolidated financial statements, the Company must provide the information required under IFRS 3 unless the initial accounting for the business combination is incomplete. Due to the nature of the acquisition, the allocation of the purchase price has not been provided because that information has not yet been finalized. Page |52 CORPORATE INFORMATION OFFICER & VICE PRESIDENT Ken Gray, P.Eng President and Chief Executive Officer DIRECTORS Don T. Gray Chairman Scottsdale, Arizona Mathew Wong, CPA, CFA, CPA (WA, USA) Vice President, Finance Ken Gray Calgary, Alberta Patrick Arnell Calgary, Alberta Donald Cormack Calgary, Alberta Peter Verburg Calgary, Alberta SOLICITOR Burnet, Duckworth & Palmer LLP Calgary, Alberta AUDITOR Ernst & Young LLP Chartered Professional Accountants Calgary, Alberta INDEPENDENT RESERVE EVALUATORS InSite Petroleum Consultants Ltd. Calgary, Alberta BANKERS TD Securities (Syndicate Lead Agent) Calgary, Alberta TRANSFER AGENT Odyssey Trust Company Calgary, Alberta HEAD OFFICE 2400, 240 – 4th Avenue S.W. Calgary, Alberta T2P 4H4 Phone: 403-984-9014 Fax: 403-984-2717 WEBSITE www.petrusresources.com Page |53 

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