Petrus Resources Ltd.
Annual Report 2022

Plain-text annual report

ANNUAL REPORT December 31, 2022 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, 2022 and to provide 2022 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 2022 HIGHLIGHTS • • • • • Increased production – Total production increased by 55% to 9,113 boe/d in the fourth quarter of 2022, compared to 5,880 boe/d in the fourth quarter of 2021. Petrus achieved its exit production rate averaging 10,635 boe/d(1) during the last week of December 2022. Total funds flow up 228% – Petrus generated funds flow(2) and corporate netback(2) of $34.1 million and $40.70/boe in the fourth quarter of 2022, 228% and 111% higher, respectively, than the fourth quarter of the prior year. Increased capital activity – Petrus incurred capital expenditures of $37.8 million in the fourth quarter of 2022 compared to $12.2 million in the fourth quarter of 2021. The Company drilled and completed 6 gross (5.3 net) wells and spent $4.9 million on pipeline, equipment and facilities. Operating netback per boe up 20% – Operating netback(2) increased by 20% to $39.84/boe in the fourth quarter of 2022 up from $33.12/ boe in the fourth quarter of 2021, due to significantly higher realized prices. Commodity price improvement – Petrus' total realized price of $57.81/boe increased by 25% in the fourth quarter of 2022 compared to the fourth quarter of 2021 ($46.29/boe) as a result of higher commodity prices across all products. 2022 ANNUAL HIGHLIGHTS • • • • • • Total funds flow up 163% – Petrus generated funds flow and corporate netback of $87.7 million and $31.60/boe in 2022, 163% and 108% higher, respectively, than funds flow of $33.4 million and $15.19/boe in 2021. The Company achieved its target funds flow guidance for 2022. Successfully executed 2022 capital program – Petrus incurred $96.7 million of capital expenditures in 2022 (excluding acquisitions and dispositions), compared to $26.9 million in 2021. 85% of total capital went to drilling and completion costs related to 21 gross (15.6 net) wells in Ferrier and North Ferrier, 12% of capital went to pipeline, equipment and facilities costs, and the remaining capital went to land and corporate costs. 2022 capital spending was in line with budget guidance. Increased production – Petrus increased average annual production by 27% from 6,009 boe/d in 2021 to 7,604 boe/d in 2022. Debt restructuring complete – The Company entered into agreements with new lenders providing two new credit facilities ("New Facilities") totaling $55 million; at December 31, 2022, $28.9 million was drawn on the New Facilities. The refinancing completed the Company’s debt restructuring. Net debt reduction – Net debt(2) was $50.8 million at December 31, 2022, an 18% decrease from $61.8 million at December 31, 2021. The Company continues to manage its balance sheet with the goal of maintaining a net debt to funds flow ratio(2) of under 1x. Rights offering – Petrus closed a $20 million rights offering that was oversubscribed by 84%. 2023 OUTLOOK(3) In early January, the Petrus team returned to drilling in Ferrier to kick off the 2023 capital program. We have successfully drilled and completed all of the wells on the first pad site and production associated with these new wells came on in early March. The rig has moved to the second pad site where drilling operations are well underway. We expect to complete drilling by the end of March and we will suspend drilling and completion operations over spring break-up. Given the inherent volatility of our commodity-based business, Petrus has always been committed to being disciplined and flexible. The Company is continuously evaluating its 2023 capital program to ensure it meets the investment threshold to optimize shareholder return. By investing capital wisely and generating strong cash flow, Petrus aims to ensure the value of this cash flow is realized by its shareholders. The Company is now in a position to analyze options available to maximize shareholder value and is in the process of determining the optimum way forward. (1)Disclosure of production on a per boe basis consists of the constituent product types and their respective quantities. Refer to "BOE Presentation" and "Production and Product Type Information" for further details. (2)Non-GAAP measure or non-GAAP ratio. Refer to "Non-GAAP and Other Financial Measures" in the Management's Discussion & Analysis attached hereto. (3)Refer to "Advisories - Forward-Looking Statements" in the Management's Discussion & Analysis attached hereto. PRESIDENT’S MESSAGE This is my second letter to shareholders, and I’d like to reflect a bit on where we’ve come from and what we’ve done over the last couple of years because I think it illustrates the volatile nature of this business and reinforces the need to be flexible in responding to constantly changing market conditions. When I started here in April of 2021, Petrus was in a difficult position with high debt levels (4.1xCF), low commodity prices (AECO $3/GJ winter, WTI US$58/bbl), and hostile lenders looking to be repaid by whatever means necessary. Years of low prices and limited investment had resulted in production declining 45% to under 6,000 boe/d. The share price sat at $0.30. However, as we emerged from the worst of the pandemic and energy demand and prices started to improve, there was hope on the horizon. Everyone involved with Petrus believed the company had great people and assets, and that if we could just get the debt situation corrected, we could really start generating value for shareholders. We immediately set out to fix the debt problem. The unpleasant calls and meetings with bankers seemed never ending, but with the support of our shareholders, we were able to reduce debt from $117 million to $18 million. In May 2022 we ceased doing business with the hostile banks and brought in a much more supportive, local bank in ATB and a second lien loan with favorable terms from a major shareholder. Step one complete. Step two was to invest in our assets and get back to what Petrus was built to do – generate strong returns for shareholders through finding, developing, and producing oil and natural gas efficiently and profitably. The Russian invasion of Ukraine accelerated the increase in oil and gas prices, and we were finally in a position to take advantage. We fired up two rigs at the start of June 2022 and got to work. It was a bit of a rough start, but we were finally bringing new production on at the end of September, and it took off from there going from just over 6,000 boe/d in September to our exit rate of over 10,500 boe/d. It was a very busy time for the Petrus team and not without its challenges, but everyone felt good about what we were doing and were fully committed to making it a success. And, successful it was. The numbers speak for themselves. Production was up 66% from December, 2021 to December, 2022. Cash Flow was up 163% year over year and was the highest in company history. PDP value was up 107%. This kind of growth doesn’t just happen. Petrus’ team stepped up, showed their capabilities, and will be key to our success going forward. Step three to execute and deliver results is well underway. So, what’s next? First, we recognize there were some unique circumstances that contributed to last year’s success. Commodity prices were the strongest we have seen in some time, and Petrus’ lack of activity over the past few years made us well positioned to grow quickly. But growth is not our ultimate goal. Rather, our primary goals are to generate high rates of return from our capital program and high netbacks and cash flow from our operations. We believe the $138 million in capital invested over the last couple years is consistent with these goals. The growth is just a by- product of these smart investments. Going forward, the key will be that we continue to make good investment decisions with our shareholders’ money. Growth, guidance, or other extraneous factors should not and will not influence our decision on when and how to invest capital. This is important to keep in mind because our business is very dynamic and volatile. We must constantly assess our capital program along with the assumptions that underpin it and remain flexible to make changes when warranted. As I write this, the volatility of our business is again on display as winter gas prices have declined from $6.20/GJ in December to sub $3.00/GJ currently, with futures prices suggesting more of the same for the rest of the year. Costs have also increased significantly. It should, therefore, come as no surprise that we are re-evaluating our capital plan and will make changes if our expected returns do not meet our threshold. Steps two and three were investing capital wisely and generating strong cash flow. This is an ongoing process which is now well underway. Step four will be to ensure the value this cash flow represents is realized by our shareholders. We are at a size now where all options for maximizing shareholder value are available to us, and we are in the process of examining these options to determine the optimum way forward. Thank you for your support. Ken Gray President, Chief Executive Officer and Director RESERVES Petrus’ 2022 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, 2022 ("2022 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, 2022, 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 2022 Insite Report. The following table provides a summary of the Company’s before tax reserves as evaluated by Insite: As at December 31, 2022 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) Condensate NGL (mmbl) Other NGL (mbbl) 73,413 1,188 90,510 165,111 89,582 99,966 265,076 958 — 2,169 3,127 1,131 3,107 6,233 2,311 30 2,469 4,810 2,808 2,065 6,875 2,305 34 3,055 5,394 2,845 3,332 8,725 Total (mboe) NPV 0%(2) ($000s) NPV 5%(2) ($000s) NPV 10%(2) ($000s) 17,809 262 22,777 40,848 21,715 25,164 66,013 381,134 4,196 327,233 712,562 483,857 476,819 1,189,381 311,376 266,264 2,926 210,153 524,456 366,124 280,470 804,925 2,148 139,021 407,433 300,905 181,937 589,370 (1Tables may not add due to rounding. (2)NPV 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 2022, Petrus’ development program generated proved developed producing ("PDP") reserve volume additions of 7.5 mmboe. The Company also produced 2.8 mmboe and acquired 1.4 mmboe of PDP reserves. The Company ended the year with 17.8 mmboe of PDP reserves (31% crude oil and liquids). Petrus ended 2022 with $266.3 million, $407.4 million and $589.4 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 2022 Insite Report. In 2022, the Company realized Finding, Development and Acquisition (“FD&A”) costs of $12.50/boe for PDP reserves. Based on the 2022 Insite Report, the Company’s PDP reserve value before-tax, discounted at 10% is $2.16 per share (123,238,528 basic common shares outstanding at December 31, 2022). On the same basis, the P+P reserve value before tax, discounted at 10%, is $4.78 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 2022 Insite Report: Future Development Cost ($000s) 2023 2024 2025 2026 Total FDC, Undiscounted Total FDC, Discounted at 10% Total Proved Total Proved + Probable 112,557 119,861 81,369 — 313,786 277,551 122,732 177,167 158,927 60,998 519,823 442,376 PERFORMANCE RATIOS The following table highlights annual performance ratios for the Company from 2018 to 2022(3): December 31, 2022 December 31, 2021 December 31, 2020 December 31, 2019 December 31, 2018 Proved Producing FD&A ($/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 (undiscounted) ($000s) Total Proved + Probable FD&A ($/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 (undiscounted) ($000s) 12.58 12.70 5.31 3.20 2.91 12.50 12.61 5.39 3.22 2.93 18.24 33.99 12.18 3.79 2.01 15.64 8.90 5.41 0.78 1.58 14.54 8.53 5.50 0.84 1.70 10.51 9.24 15.30 4.50 2.35 4.83 4.83 5.20 1.20 2.60 4.71 4.71 5.20 1.20 2.70 1.29 1.29 10.90 (1.00) 9.80 13.31 12.81 3.80 0.40 1.20 12.49 12.03 4.80 0.50 1.30 1.09 (6.83) 9.90 0.30 14.40 37.76 42.27 4.60 0.20 0.40 11.34 11.55 5.60 0.60 1.40 8.73 8.16 11.10 1.30 1.80 313,786 233,684 156,815 174,027 194,757 15.66 36.12 19.68 6.63 2.34 10.57 8.36 23.29 5.10 2.33 0.37 0.37 17.70 (1.30) 33.70 (7.32) 190.21 15.40 — (2.10) 6.49 5.15 17.10 1.50 2.40 519,823 343,489 252,335 267,652 290,876 (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 2022 Insite Report and Insite's December 31, 2022 price forecast: As at December 31, 2022 ($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 Fully Diluted Share Proved Developed Producing Total Proved Proved + Probable 266,264 34,837 (50,808) 250,293 133,377 $1.88 407,433 34,837 (50,808) 391,462 133,377 $2.94 589,370 34,837 (50,808) 573,399 133,377 $4.30 (1)Based on the 2022 Insite Report, using the forecast future prices and costs. (2)Based on the exploration and evaluation assets as per the Company's December 31, 2022 audited consolidated financial statements. (3)Non-GAAP financial measure. See "Non-GAAP and Other Financial Measures" in the Management's Discussion & Analysis attached hereto. Page |6 MANAGEMENT'S DISCUSSION & ANALYSIS December 31, 2022 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, 2022. This MD&A is dated March 14, 2023 and should be read in conjunction with the Company's audited consolidated financial statements for the years ended December 31, 2022 and 2021. 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 ($/boe) Royalty income Royalty expense Loss on risk management activities Net oil and natural gas revenue ($/boe) Operating expense Transportation expense Operating netback(1) ($/boe) Realized gain (loss) on financial derivatives ($/boe) Other income (cash) General & administrative expense Cash finance expense Decommissioning expenditures Twelve months ended Twelve months ended Three months ended Three months ended Three months ended Three months ended Dec. 31, 2022 Dec. 31, 2021 Dec. 31, 2022 Sept. 30, 2022 Jun. 30, 2022 Mar. 31, 2022 30,441 1,436 1,094 7,604 23,680 1,019 1,043 6,009 33,201 2,458 1,121 9,113 2,775,561 2,193,432 838,375 28,107 957 997 6,639 610,722 30,913 1,073 1,055 7,280 29,530 1,250 1,207 7,379 662,456 664,010 19 % 17 % 27 % 14 % 15 % 17 % 6.03 113.19 63.26 54.63 0.26 (8.70) (2.17) 44.02 (7.45) (2.08) 34.49 (0.58) 0.10 (1.22) (1.14) (0.05) 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) 6.04 106.85 56.90 57.81 0.15 (7.92) (1.26) 48.78 (6.86) (2.08) 39.84 2.89 0.22 (1.10) (1.18) 0.03 5.02 111.04 62.25 46.62 0.37 (11.84) (0.81) 34.34 (8.47) (1.89) 23.98 1.00 0.05 (1.30) (0.87) (0.29) 7.74 133.36 5.20 110.12 74.63 63.33 0.25 (8.64) (6.76) 48.18 (7.92) (2.16) 38.10 — 0.04 (1.70) (1.46) 0.06 60.12 49.31 0.29 (6.89) — 42.71 (6.76) (2.17) 33.78 (6.98) 0.07 (0.82) (1.04) (0.02) Funds flow & corporate netback(1) ($/boe) 31.60 15.19 40.70 22.57 35.04 24.99 FINANCIAL (000s except $ per share) Oil and natural gas revenue Net income Net income per share Basic Fully diluted Funds flow(1) Funds flow per share (1) 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, 2022 152,350 Dec. 31, 2021 81,268 Dec. 31, 2022 48,590 Sept. 30, 2022 28,701 Jun. 30, 2022 42,119 Mar. 31, 2022 32,940 60,868 114,556 22,097 9,822 18,046 10,903 0.53 0.51 87,716 0.76 0.73 96,744 115,189 119,525 123,239 133,377 381,057 63,021 50,808 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 0.18 0.17 34,117 0.28 0.27 37,792 0.08 0.08 13,789 0.11 0.11 49,513 0.16 0.15 23,208 0.21 0.20 4,932 0.11 0.11 16,601 0.17 0.16 5,064 122,545 127,600 122,058 126,822 111,795 117,203 99,189 103,250 123,239 133,377 381,057 63,021 50,808 122,197 131,482 356,050 61,778 48,465 122,017 131,302 302,472 50,924 13,895 106,907 113,883 308,744 46,702 50,044 (1) Non-GAAP financial measure or non-GAAP ratio. 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, 2022 Natural gas (mcf/d) Oil (bbl/d) NGLs (bbl/d) Total (boe/d) Ferrier North Ferrier Foothills Central Alberta Kakwa Total 21,198 1,872 834 6,239 4,498 237 120 1,107 2,360 81 7 481 4,993 247 150 1,230 150 21 10 56 33,199 2,458 1,121 9,113 Fourth quarter 2022 production averaged 9,113 boe/d compared to 5,880 boe/d in the fourth quarter of 2021. Five gross (4.6 net) wells were spud in the Ferrier area during the quarter. Of these, four (3.6 net) wells were completed and on production by December 31, 2022. CAPITAL EXPENDITURES The Company's 2022 capital program accelerated in the second half of 2022 with capital expenditures (excluding acquisitions and dispositions) totaling $37.8 million in the fourth quarter of 2022, compared to $12.2 million in the prior year comparative period. Capital expenditures (excluding acquisitions and dispositions) totaled $96.7 million in the year ended December 31, 2022, compared to $27.0 million in 2021. The increase from the prior year is attributed to the execution of the Company's 2022 capital program. The following table shows capital expenditures for the reporting periods indicated, excluding acquisitions and dispositions. All capital is presented before decommissioning obligations. Capital Expenditures ($000s) Drill and complete Oil and gas equipment and facilities Land and lease 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, 2022 December 31, 2021 December 31, 2022 December 31, 2021 32,073 4,921 291 507 37,792 5 (4.6) 10,769 1,104 25 337 12,235 3 (3.0) 81,953 11,853 1,759 1,179 96,744 20 (14.8) 21,882 3,918 274 941 27,015 10 (6.4) During the first quarter of 2022, Petrus closed an acquisition in its core Ferrier area. Included in this acquisition was approximately 425 boe/d of production and 5,120 net acres of undeveloped land. The acquisition was made for total share consideration of 10 million shares ($15.2 million). 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) Loss on risk management ($/boe) Twelve months ended Twelve months ended Three months ended Three months ended Three months ended Three months ended Dec. 31, 2022 Dec. 31, 2021 Dec. 31, 2022 Sept. 30, 2022 Jun. 30, 2022 Mar. 31, 2022 30,441 1,436 1,094 7,604 23,680 1,019 1,043 6,009 33,201 2,458 1,121 9,113 28,107 957 997 6,639 30,913 1,073 1,055 7,280 29,530 1,250 1,207 7,379 2,775,561 2,193,432 838,375 610,722 662,456 664,010 67,025 59,348 25,267 710 152,350 6.03 113.19 63.26 54.63 (0.58) (2.17) 34,833 29,322 16,793 320 81,268 4.03 78.82 44.09 36.90 (5.34) — 18,434 24,163 5,869 124 48,590 6.04 106.85 56.90 57.81 2.89 12,990 9,776 5,708 227 28,701 5.02 111.04 62.25 46.62 1.00 21,771 13,022 7,162 164 42,119 7.74 133.36 74.63 63.33 — (1.26) (0.81) (6.76) 13,830 12,387 6,528 195 32,940 5.20 110.12 60.12 49.31 (6.98) — Total price including hedging ($/boe) 51.88 31.56 59.44 46.81 56.57 42.33 Average benchmark prices Natural gas AECO 5A (C$/GJ) AECO 7A (C$/GJ) Crude oil and NGLs Mixed Sweet Blend Edm (C$/bbl) WTI (US$/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, 2022 Dec. 31, 2021 Dec. 31, 2022 Sept. 30, 2022 Jun. 30, 2021 Mar. 31, 2022 5.04 5.22 119.41 94.23 0.74 3.43 3.38 80.48 67.96 0.79 4.85 5.29 108.14 82.65 3.95 5.29 115.94 91.56 6.86 5.95 134.99 108.41 4.49 4.35 117.57 94.29 0.74 0.77 0.79 0.79 Page |11 FUNDS FLOW AND NET INCOME Petrus generated funds flow of $34.1 million in the fourth quarter of 2022 compared to $10.4 million in the fourth quarter of 2021. The 228% increase is due to higher production and improved commodity prices. In the fourth quarter of 2022 Petrus' production was 9,113 boe/d, 55% higher than the 5,880 boe/d during the fourth quarter of 2021. The Company's total realized price was $57.81/boe in the fourth quarter of 2022 compared to $46.29/boe in the prior year comparative period. For the year ended December 31, 2022, Petrus generated funds flow of $87.7 million compared to $33.4 million in the prior year. The 163% increase is due to higher production and improved commodity prices. Petrus reported net income of $22.1 million in the fourth quarter of 2022, compared to net income of $114.6 million in the fourth quarter of 2021. The reduction in net income in the fourth quarter of 2022 compared to the fourth quarter of 2021 is primarily due to the impairment reversal of $103.2 million recorded in the fourth quarter of 2021. Excluding the impairment reversal, net income was 94% higher in the fourth quarter of 2022 compared to the prior year comparative period. The Company generated net income of $60.9 million for the year ended December 31, 2022 compared to net income of $114.6 million for the year ended December 31, 2021. The year over year change is due to the $103.2 million impairment reversal recorded in the fourth quarter of 2021. Excluding the impairment reversal, net income was 434% higher year over year. ($000s except per share) Funds flow Funds flow per share - basic Funds flow per share - fully diluted Net income Net income per share - basic Net income 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, 2022 December 31, 2021 December 31, 2022 December 31, 2021 34,117 0.28 0.27 22,097 0.18 0.17 123,239 133,377 122,545 127,600 10,418 0.11 0.10 114,633 1.19 1.11 96,708 103,889 96,660 102,868 87,716 0.76 0.73 60,868 0.53 0.51 123,239 133,377 115,189 119,525 33,354 0.53 0.51 114,556 1.83 1.76 96,708 103,889 62,557 65,207 OIL AND NATURAL GAS REVENUE Fourth quarter average production in 2022 was 9,113 boe/d (61% natural gas), 55% higher than the fourth quarter of 2021 (5,880 boe/d; 67% natural gas). Fourth quarter oil and natural gas revenue in 2022 was $48.6 million compared to $25.1 million in 2021. The 94% increase is due to higher production and improved commodity prices. Average production for the year ended December 31, 2022 was 7,604 boe/d (67% natural gas), 27% higher than 2021 (6,009 boe/d; 66% natural gas). Total oil and natural gas revenue increased from $81.3 million in 2021 to $152.4 million in 2022 due to higher production and improved 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 ($000s) Natural gas Crude oil and condensate Natural gas liquids Royalty income Total oil and natural gas revenue Three months ended Three months ended Twelve months ended Twelve months ended December 31, 2022 December 31, 2021 % Change December 31, 2022 December 31, 2021 % Change 18,434 24,163 5,869 124 48,590 11,781 8,273 4,985 31 25,070 56 % 192 % 18 % 300 % 94 % 67,025 59,348 25,267 710 152,350 34,833 29,322 16,793 320 81,268 92 % 102 % 50 % 122 % 87 % Page |12 The following table provides the average benchmark commodity prices and the Company's average realized commodity prices (before hedging and risk management gains/losses): Three months ended Three months ended Twelve months ended Twelve months ended December 31, 2022 December 31, 2021 % Change December 31, 2022 December 31, 2021 % Change Average benchmark prices Natural gas AECO 5A (C$/GJ) AECO 7A (C$/GJ) Crude oil Mixed Sweet Blend Edm (C$/bbl) Average realized prices Natural gas ($/mcf) Oil ($/bbl) NGLs ($/bbl) Total average realized price 4.85 5.29 108.14 6.04 106.85 56.90 57.81 4.41 4.68 10 % 13 % 5.04 5.22 3.43 3.38 47 % 54 % 92.97 16 % 119.41 80.48 48 % 5.45 89.71 56.35 46.29 11 % 19 % 1 % 25 % 6.03 113.19 63.26 54.63 4.03 78.82 44.09 36.90 50 % 44 % 43 % 48 % 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, 2022 December 31, 2021 December 31, 2022 December 31, 2021 61 % 27 % 12 % 100 % 67 % 17 % 16 % 100 % 67 % 19 % 14 % 100 % 66 % 17 % 17 % 100 % Natural gas Natural gas revenue for the year ended December 31, 2022 was $67.0 million, which increased 92% from the prior year ($34.8 million). The average realized natural gas price for the year ended December 31, 2022 increased 50% to $6.03/mcf from the prior year ($4.03/mcf). Natural gas production increased from 8.6 bcf in 2021 to 11.1 bcf in 2022, an increase of 29%. Natural gas revenue accounted for 44% of oil and natural gas revenue in 2022, compared to 43% in the prior year. Fourth quarter 2022 natural gas revenue was $18.4 million, which increased 56% from the prior year comparative period ($11.8 million). The average realized natural gas price in the fourth quarter of 2022 was $6.04/mcf, compared to $5.45/mcf in the fourth quarter of 2021 (11% increase). Natural gas production increased from 2.25 bcf in the fourth quarter of 2021 to 3.1 bcf in the fourth quarter of 2022. Natural gas revenue accounted for 38% of oil and natural gas revenue in the fourth quarter of 2022, compared to 47% in the prior year comparative period. Crude oil and condensate Oil and condensate revenue for the year ended December 31, 2022 was $59.3 million, which increased 102% from the prior year ($29.3 million). The average realized oil and condensate price for the year ended December 31, 2022 increased 44% to $113.19/bbl from the prior year ($78.82/bbl). Oil and condensate production increased from 372.0 mbbl in 2021 to 524.4 mbbl in 2022, an increase of 41%. Oil and condensate revenue accounted for 39% of oil and natural gas revenue in 2022, compared to 36% in the prior year. Fourth quarter 2022 oil and condensate revenue was $24.2 million, which increased 192% from the prior year comparative period ($8.3 million). The average realized oil and condensate price was $106.85/bbl for the fourth quarter of 2022 compared to $89.71/bbl in the fourth quarter of 2021, an increase of 19%. Oil and condensate production increased from 92.2 mbbl in the fourth quarter of 2021 to 226.1 mbbl in the fourth quarter of 2022, an increase of 145%. Oil and condensate revenue accounted for 50% of oil and natural gas revenue in the fourth quarter of 2022, compared to 33% in the prior year comparative period. Page |13 Natural gas liquids (NGLs) NGL revenue for the year ended December 31, 2022 was $25.3 million, which increased 50% from the prior year ($16.8 million). The average realized NGL price for the year ended December 31, 2022 increased 43% to $63.26/bbl from the prior year ($44.09/bbl). NGL production increased from 382.3 mbbl in 2021 to 399.5 mbbl in 2022, an increase of 5%. NGL revenue accounted for 17% of oil and natural gas revenue in 2022, compared to 21% in the prior year. Fourth quarter 2022 NGL revenue was $5.9 million, which increased 18% from the prior year comparative period ($5.0 million). The average realized NGL price was $56.90/bbl for the fourth quarter of 2022 which is consistent with the realized price of $56.35/bbl in the fourth quarter of 2021. NGL production increased from 89.0 mbbl in the fourth quarter of 2021 to 103.2 mbbl in the fourth quarter of 2022, an increase of 16%. NGL revenue accounted for 12% of oil and natural gas revenue in the fourth quarter of 2022, compared to 20% in the prior year comparative period. The Company’s NGL production mix consists of ethane, propane, butane and pentanes+. 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. NGL pricing is benchmarked to WTI. 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, 2022 December 31, 2021 December 31, 2022 December 31, 2021 4,194 9 % 2,443 6,637 1,941 8 % 1,487 3,428 15,463 10 % 8,698 24,161 5,797 7 % 4,564 10,361 Fourth quarter royalty expense increased from $3.4 million in 2021 to $6.6 million in 2022. On a twelve month basis, total royalty expense (net of royalty allowances and incentives) increased from $10.4 million in 2021 to $24.2 million in 2022. The increase in royalties for the fourth quarter and the year ended December 31, 2022 is due to higher revenue (as a result of increased commodity prices and production) and higher crown royalty rates. Gross overriding royalties increased from $1.5 million in the fourth quarter of 2021 to $2.4 million in the fourth quarter of 2022. Gross overriding royalties increased from $4.6 million for the year ended December 31, 2021 to $8.7 million for the year ended December 31, 2022. The increase for both periods is due to higher revenue (as a result of increased production and higher commodity prices). OTHER INCOME During the year ended December 31, 2022 the Company recorded $1.4 million as other income ($0.3 million cash). This amount mainly relates to the recognition of carbon credits ($0.6 million) the Company earned from installing emission reduction equipment and the recognition of a grant for decommissioning activities ($0.4 million). RISK MANAGEMENT The Company utilizes financial derivative contracts and physical commodity 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) for financial derivatives and premium (loss) on risk management activities for physical commodity contracts. The unrealized gain (loss) is recorded to demonstrate the change in fair value of the outstanding financial derivative contracts during 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 financial derivative 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, 2022 December 31, 2021 December 31, 2022 December 31, 2021 Realized hedging gain (loss) Unrealized hedging gain (loss) Net gain (loss) on derivatives 2,421 (1,959) 462 (5,148) 6,064 916 (1,601) 7,609 6,008 (11,713) (2,408) (14,121) In the fourth quarter of 2022, the Company recognized a realized hedging gain of $2.4 million compared to a loss of $5.1 million in the fourth quarter of 2021. The realized gain in the fourth quarter of 2022 increased the Company’s corporate netback by $2.89/boe, compared to a decrease of $9.52/boe in 2021. The Company recognized a realized hedging loss of $1.6 million during the year ended December 31, 2022, in comparison to the $11.7 million loss realized in 2021. The realized gain for the fourth quarter of 2022 was due to lower commodity prices (relative to the respective contracts settled) while the realized loss for the year ended December 31, 2022 was due to higher commodity prices (relative to the respective contracts settled). During the fourth quarter of 2022, the Company recognized an unrealized loss of $2.0 million compared to an unrealized gain of $6.1 million in the fourth quarter of 2021. The Company recognized an unrealized hedging gain of $7.6 million for the year ended December 31, 2022 compared to an unrealized loss of $2.4 million for the year ended December 31, 2021. The gain (loss) represents the change in the unrealized risk management net asset or liability position during the year ended December 31, 2022. The table below shows the premium (loss) on risk management activities related to physical commodity contracts for the periods shown: Net Loss on Risk Management Activities ($000s) Three months ended Three months ended Twelve months ended Twelve months ended December 31, 2022 December 31, 2021 December 31, 2022 December 31, 2021 Loss on physical commodity contracts Net loss on risk management activities (1,056) (1,056) — — (6,029) (6,029) — — During the fourth quarter of 2022, the Company recorded a loss of $1.1 million or $1.26/boe related to the settlement of its physical commodity contracts. For the year ended December 31, 2022, the Company recorded a loss of $6.0 million or $2.17/boe. The losses are a result of lower contract prices in comparison to benchmark prices during the periods. The average volume of gas hedged through physical commodity contracts during the fourth quarter of 2022 was 14,333 GJ/d at an average price of $3.98/GJ. There was no loss or premium recorded during the three and twelve months ended December 31, 2021 as there were no contracts outstanding during these periods. The Company’s risk management contracts provide protection from significant changes in crude oil and natural gas commodity prices for 2023 and 2024. The Company endeavors to hedge approximately half of its forecasted production for up to 12 months forward, and approximately 10% to 25% of its forecasted production for 12 to 24 months forward. The Company's hedging strategy is intended to provide stability and sustainability to the Company's economic returns, funds flow and capital development plan. A summary of Petrus’ risk management contracts as at December 31, 2022 is included in note 11 of the Company’s consolidated financial statements as at and for the year ended December 31, 2022. The 12,583 GJ/day of average natural gas hedged for the 2023 represents 40% of fourth quarter 2022 average natural gas production. The 1,375 bbl/day of average oil hedged for the 2023 represents 56% of fourth quarter 2022 average natural gas production. The following table summarizes the average and minimum and maximum cap and floor prices for the 2023 to 2024 oil and natural gas contracts outstanding as at the date of this report: Oil hedged (bbl/d) Avg. WTI cap price ($C/bbl) Avg. WTI floor price ($C/bbl) Natural gas hedged (GJ/d) Avg. AECO 7A cap price ($C/GJ) Avg. AECO 7A floor price ($C/GJ) Q1 Q2 1,100 112.23 103.79 6,000 6.67 6.67 1,400 109.98 103.35 15,000 4.10 4.10 2023 Q3 1,500 106.07 99.88 15,000 4.10 4.10 Q4 Avg.(1) Q1 Q2 1,500 105.84 99.65 14,333 4.39 4.39 1,375 108.23 101.48 12,583 4.49 4.49 1,100 99.13 99.13 14,000 4.53 4.53 1,000 99.09 99.09 4,000 3.26 3.26 2024 Q3 200 94.55 94.55 4,000 3.26 3.26 Q4 Avg.(1) 200 94.55 94.55 1,333 3.26 3.26 625 98.38 98.38 5,833 4.02 4.02 (1)The volumes and prices reported are the weighted average volumes and prices for the period. Page |15 The following table summarizes the quarterly average volume and average prices for the natural gas physical commodity contracts as at the date of this MD&A: Natural gas hedged (GJ/d) Avg. AECO 7A price ($C/GJ) (1)The volumes and prices reported are the weighted average volumes and prices for the period. Q1 Q2 14,000 4.17 — — 2023 Q3 Q4 Avg.(1) — — — — 3,500 4.17 OPERATING EXPENSE The following table shows the Company’s operating expense for the reporting periods shown: 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, 2022 December 31, 2021 December 31, 2022 December 31, 2021 5,173 878 6,051 (298) 5,753 6.86 2,182 745 2,927 (212) 2,715 5.02 16,954 4,853 21,807 (1,142) 20,665 7.45 11,134 2,719 13,853 (939) 12,914 5.89 For the three months ended December 31, 2022, net operating expense totaled $5.8 million, a 112% increase from $2.7 million during the prior year comparative period. Total operating expense is higher for three months ended December 31, 2022 due to higher production. On a per boe basis, net operating expense was 37% higher at $6.86/boe in the fourth quarter of 2022 compared to $5.02/boe in 2021. For the year ended December 31, 2022, net operating expense totaled $20.7 million, a 60% increase from the $12.9 million incurred in the prior year comparative period. Total operating expense for the year ended December 31, 2022 is mainly due to higher production. On a per boe basis, net operating expense was 27% higher at $7.45/boe in 2022 compared to $5.89/boe in 2021. On a per boe basis, the increase in net operating expense for the quarter and year ended December 31, 2022, is mainly attributable to inflationary pressures including the growing costs of power, fuel, trucking, and contract operating. Carbon tax expense was higher than the prior year comparative periods as well. The cost of gas gathering, compression and processing was also higher in 2022 as the Company had more volumes processed through third party facilities in the Foothills, Kakwa and North Ferrier areas. In addition, there was a decrease in third-party production flowing through Petrus' operated facilities, reducing fee recoveries. 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, 2022 December 31, 2021 December 31, 2022 December 31, 2021 1,743 2.08 1,010 1.87 5,772 2.08 3,920 1.79 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, 2022 transportation expense was $1.7 million or $2.08/boe compared to $1.0 million or $1.87/boe in the prior year comparative period. On a twelve month basis, transportation expense totaled $5.8 million, or $2.08/boe for 2022, which is 49% and 16% higher, respectively, than the $3.9 million of costs incurred (or $1.79/boe) in the prior year. The increase in transportation expense on a per boe basis is due to higher fuel surcharge and higher trucking costs due to increased fuel prices and volumes. 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: Page |16 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, 2022 December 31, 2021 December 31, 2022 December 31, 2021 1,750 407 223 2,380 (507) (947) 926 1.10 1,070 491 112 1,673 (289) (171) 1,213 2.24 4,103 1,733 879 6,715 (1,179) (2,147) 3,389 1.22 3,529 1,613 688 5,830 (878) (678) 4,274 1.95 G&A expense (net of capitalized G&A expense and overhead recoveries) for the fourth quarter of 2022 totaled $0.9 million or $1.10/boe, compared to $1.2 million or $2.24/boe in the fourth quarter of 2021. Gross G&A expense (before capitalized G&A expense and overhead recoveries) was higher than the the prior year ($2.4 million in the fourth quarter of 2022 compared to $1.7 million in the fourth quarter of 2021) due to increased staffing costs (additional staff required to support capital program). For the year ended December 31, 2022, net G&A expense was $3.4 million or $1.22/boe which is lower than the $4.3 million or $1.95/boe for the prior year comparative period (37% decrease on a per boe basis). For the year ended December 31, 2022 gross G&A expense was $6.7 million compared to $5.8 million in the prior year. The 16% increase is mainly due to increased staffing costs (additional staff required to support capital program). Net G&A is lower, on a per boe and total basis, due to the increased overhead recovery related to the higher production and capital activity in 2022 in comparison to the prior year comparative periods. 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, 2022 December 31, 2021 December 31, 2022 December 31, 2021 614 (184) 430 164 (48) 116 1,630 (489) 1,141 355 (96) 259 Share-based compensation expense (net of capitalized portion) was $0.43 million for the fourth quarter of 2022, which is 258% higher than the $0.12 million recognized in the fourth quarter of the prior year. For the year ended December 31, 2022, net share-based compensation expense was $1.14 million, which is 340% higher than the $0.26 million in the prior year comparative period. The increase in stock based compensation expense for the current period and year-end compared to the prior year comparative periods is due to the Company's improved stock price resulting in higher value of stock options and a higher staffing level. FINANCE EXPENSE The following table illustrates the Company’s finance expense which includes cash and non-cash expenses: Finance Expense ($000s) Interest expense Foreign exchange loss (gain) 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, 2022 December 31, 2021 December 31, 2022 December 31, 2021 809 — 177 137 — 310 1,433 811 — 45 61 — 198 1,115 2,175 3 993 430 — 1,066 4,667 4,108 — 1,025 365 2,573 707 8,778 Fourth quarter total finance expense was $1.4 million in 2022, comprised of $0.3 million of non-cash accretion of its decommissioning obligations, $0.14 million of deferred financing costs, $0.8 million of cash interest expense and $0.18 million of finance fees. In the fourth Page |17 quarter of 2021, the Company incurred total finance expense of $1.1 million, comprised of $0.2 million in non-cash accretion of its decommissioning obligation, $0.8 million cash interest expense, $0.05 million of finance fees, and $0.06 million of deferred financing fee amortization. The increase in finance fees in the fourth quarter of 2022 is mainly due to the increase in accretion and finance fees. The Company incurred total finance expense of $4.7 million for the year ended December 31, 2022, which is 47% lower than the $8.8 million for the prior year. The decrease in total finance expense is due to a lower first lien loan balance throughout 2022 as well as the elimination of non-cash term loan interest payment-in-kind upon settlement of the term loan in 2021. 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, 2022 December 31, 2021 December 31, 2022 December 31, 2021 10,658 12.71 5,508 10.18 33,277 11.99 22,992 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 2022 of $10.7 million or $12.71/boe, compared to the fourth quarter of 2021, when $5.5 million or $10.18/boe was recorded. For the year ended December 31, 2022, the Company recorded $33.3 million or $11.99/boe, compared to $23.0 million or $10.43 per boe for the prior year comparative period. The increase in the depletion expense for the fourth quarter of 2022 and year ended December 31, 2022 compared to the prior year comparative periods is due to higher production in 2022. 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, 2022 December 31, 2021 December 31, 2022 December 31, 2021 — — (103,220) (103,220) — — (103,220) (103,220) 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 and Comprehensive Income. For more information, refer to notes 6 and 7 of the December 31, 2022 audited consolidated financial statements. Page |18 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, 2022 December 31, 2021 December 31, 2022 December 31, 2021 122,545 127,600 123,239 133,377 8,520 96,660 102,868 96,708 103,889 5,563 115,189 119,525 123,239 133,377 8,520 62,557 65,207 96,708 103,889 5,563 At December 31, 2022, the Company had 123,238,528 common shares and 8,519,709 stock options outstanding. As at the date of this MD&A, the Company had 123,711,355 common shares and 8,620,017 stock options outstanding. Deferred share units 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, 2022 and the date of this MD&A, 1,618,702 DSUs were issued and outstanding (December 31, 2021 – 1,618,702). 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. Rights Offering During the second quarter of 2022, the Company completed a rights offering (the “Rights Offering”) where the Company issued approximately 14.8 million common shares at $1.35 per share for aggregate gross proceeds to the Company of approximately $20.0 million. The issuance costs were estimated to be $0.4 million and the net proceeds of $19.6 million were utilized for debt repayment and towards working capital. The Company entered into a standby purchase agreement with each of Don Gray, Stuart Gray and Glen Gray (collectively, the "Stand-By Guarantors"). The Rights Offering was oversubscribed by 84% and as a result, the Stand-By Guarantors did not acquire any common shares in connection with the Rights Offering pursuant to their stand-by commitments. The Company had approximately 121.7 million shares outstanding following the Rights Offering with the Stand-By Guarantors owning approximately 71% of the outstanding shares. Property Acquisition During the first quarter of 2022, the Company completed an asset acquisition. The assets were acquired for share consideration of $15.2 million (10 million common shares of Petrus at $1.52 per share on closing date). Private placement 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. LIQUIDITY AND CAPITAL RESOURCES At December 31, 2022, Petrus had two debt instruments outstanding; a reserve-based, secured operating revolving loan facility with an Alberta-based financial institution (the “Revolving Loan Facility” or “RLF”) and a second lien secured term facility (the "Second Lien Facility"). Page |19 Revolving Loan Facility At December 31, 2022, the RLF was comprised of a $30.0 million operating facility payable on demand by the lender. The amount of the RLF is subject to a borrowing base review performed on a semi-annual basis by the lender, based primarily on reserves and commodity prices estimated by the lenders as well as other factors. The next semi-annual review is due on May 31, 2023. At December 31, 2022, the Company had a $0.6 million letter of credit outstanding against the RLF (December 31, 2021 – $0.6 million on the previous revolving credit facility) and had drawn $4.6 million against the RLF (December 31, 2021 – $57.7 million on the previous revolving credit facility). Second Lien Facility At December 31, 2022 the Company had $25.0 million outstanding on the $25 million Second Lien Facility. The Second Lien Facility is a three-year term facility (maturity date May 31, 2025 with an option to extend by an additional two years) with a fixed interest rate of 11% per annum and can be repaid at the discretion of the Company after the first year. The Second Lien Facility is a related party transaction with a major shareholder who owns approximately 21% of the outstanding shares of the Company (see note 20 of the Company's December 31, 2022 audited consolidated financial statements). The total interest paid in 2022 to the major shareholder, related to the Second Lien facility, was $1.1 million. Debt Settlement - Term Loan & Revolving Credit Facility During 2022, the Company entered into agreements with new lenders to the Company, providing two new credit facilities, as described above, (the “New Credit Facilities”) totaling $55 million. The New Credit Facilities, together with the net proceeds of the Company's Rights Offering (described above), were used to repay in full all amounts owing under the Company's previous revolving credit facility. The New Credit Facilities closed in May 2022. Prior to December 31, 2021, Petrus had 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 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). Financial Covenants The Company's RLF is subject to certain financial covenants. The following definitions are used in the covenant calculations for the debt instrument: 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 RLF, 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 key financial covenants as at December 31, 2022 are summarized in the following table. At December 31, 2022 the Company is in compliance with all financial covenants. Financial Covenant Description Working Capital Ratio Required Ratio Over 1.0 As at December 31, 2022 1.1 Liquidity At December 31, 2022, the Company had a working capital deficiency (excluding non-cash risk management assets and liabilities) of $26.0 million as the company had $45.2 million in current accounts payable due to the substantial increase in capital activity during the third and fourth quarters of 2022. Page |20 Contractual Maturities The following are the contractual maturities of financial liabilities as at December 31, 2022: $000s Accounts payable and accrued liabilities Bank indebtedness Lease obligations Long term debt Total Total 45,191 4,606 603 25,000 75,400 < 1 year 45,191 4,606 240 — 50,037 Commitments The commitments for which the Company is responsible are as follows: $000s Firm service transportation Total 11,240 < 1 year 2,582 1-5 years 8,658 1-5 years — — 363 25,000 25,363 > 5 years — 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 11 and 16 of the Company’s December 31, 2022 audited consolidated financial statements. Page |21 SUMMARY OF QUARTERLY RESULTS ($000s unless otherwise noted) Dec. 31, 2022 Sept. 30, 2022 Jun. 30, 2022 Mar. 31, 2022 Dec. 31, 2021 Sept. 30, 2021 Jun. 30, 2021 Mar. 31, 2021 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 Loss on risk management activities Net oil and natural gas revenue Transportation expense Operating expense Operating netback(1) Realized gain (loss) on financial derivatives Other income (cash) General and administrative expense Cash finance expense Decommissioning expenditures Corporate netback and funds flow(1) 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 (1)Non-GAAP measure. Refer to "Non-GAAP and Other Financial Measures". 33,201 28,107 30,913 29,530 23,494 23,942 24,291 22,985 2,458 1,121 9,113 957 997 6,639 1,073 1,055 7,280 1,250 1,207 7,379 1,002 962 5,880 937 1,010 5,937 1,214 1,046 6,309 923 1,158 5,912 838,375 610,722 662,456 664,010 540,924 546,227 574,084 532,099 48,590 28,701 42,119 32,940 25,070 20,306 19,553 16,339 (6,636) (7,228) (5,721) (4,576) (3,429) (2,150) (2,794) (1,989) (1,056) (497) (4,476) — — — — — 40,898 20,976 31,922 28,364 21,641 18,156 16,759 14,350 (1,743) (1,155) (1,434) (1,440) (1,010) (991) (1,057) (863) (5,753) (5,171) (5,249) (4,492) (2,715) (3,042) (3,903) (3,254) 33,402 14,650 25,239 22,432 17,916 14,123 11,799 10,233 2,421 186 (926) (987) 21 610 30 — 28 (4,632) (5,148) (3,504) (1,843) (1,215) 47 21 12 1,018 23 (793) (1,127) (543) (1,213) (804) (1,381) (876) (528) (180) (969) (689) (856) (1,803) (1,444) (1,029) 37 (14) (302) (150) (79) (143) 34,117 13,789 23,208 16,601 10,418 7,874 8,070 6,993 48,590 28,701 42,119 32,940 25,070 20,306 19,553 16,339 0.40 0.38 0.24 0.23 0.38 0.36 0.33 0.32 0.26 0.24 0.37 0.35 0.39 0.39 0.33 0.33 22,097 9,822 18,046 10,903 114,633 7,343 (4,265) (3,155) 0.18 0.17 0.08 0.08 0.16 0.15 0.11 0.11 1.19 1.11 0.14 0.13 (0.09) (0.09) (0.06) (0.06) 123,239 122,197 122,017 106,907 96,708 96,603 49,559 49,469 133,377 131,482 131,302 113,883 103,889 100,074 49,559 49,469 122,545 122,058 111,795 99,189 96,660 54,167 49,513 49,469 127,600 126,822 117,203 103,250 102,868 57,638 49,513 49,469 381,057 356,050 302,472 308,744 290,492 173,101 176,629 177,587 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 increased from 5,912 boe/d in the first quarter of 2021 to 9,113 boe/d in the fourth quarter of 2022. The 54% production increase is attributable to Petrus' shift in focus back to production growth and an increased capital program. Page |22 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, 2022 December 31, 2021 December 31, 2020 152,350 1.32 1.27 60,868 0.49 0.46 123,239 133,377 115,189 119,525 381,057 63,021 81,268 1.30 1.25 114,556 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 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, 2022. Russian/Ukrainian Conflict In February 2022, Russian military forces invaded Ukraine. The outcome of the ongoing war is uncertain and is likely to have wide-ranging consequences on the peace and stability of the region and the world economy. In addition, certain countries including Canada, have imposed strict financial and trade sanctions against Russia which may have far reaching effects on the global economy. Disruption of supplies of commodities from Russia could have a significant impact on worldwide commodity prices. The long-term impacts of the conflict and the sanctions imposed on Russia remain uncertain. Any negative impact on economic conditions and global markets from these developments could adversely affect our business, financial condition and liquidity including our ability to access capital and the related costs. The Company does not have sales, production, or operations within Russia or Ukraine, and the conflict has not directly impacted its operations (and is not expected to). Nevertheless, the ongoing war induces greater uncertainties in global financial markets and supply chain systems which could lead to volatility in oil prices, inflation rates, interest rates, financing costs, and shortage or delays for certain goods or services. The Company continues assessing its exposure. 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, 2022. New standards and interpretations The Company has not adopted any new standards and interpretations for the year ended December 31, 2022. 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 Page |23 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 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, 2022 and have concluded that the Company's DC&P are effective at December 31, 2022 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, 2022, 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 October 1, 2022 and ended on December 31, 2022 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, 2022. Based on this evaluation, the Chief Executive Officer and Chief Financial Officer concluded that as at December 31, 2022, 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" (on an absolute and $/boe basis), "corporate netback" (on an absolute and $/boe basis), "funds flow" (on an absolute, per share (basic and fully diluted) and $/boe basis) and "net debt". These non-GAAP and other financial measures are not recognized measures under GAAP (IFRS) and do not have a standardized meaning prescribed by GAAP (IFRS). Accordingly, the Company's use of these terms may not be comparable to similarly defined measures presented by other companies. These non-GAAP and other financial measures should not be considered to be more meaningful than GAAP measures which are determined in accordance with IFRS as indicators of our performance. Management uses these non-GAAP and other financial measures for the reasons set forth below. Operating Netback Operating netback is a common non-GAAP financial measure used in the oil and natural gas industry which is a useful supplemental measure to evaluate the specific operating performance by product type at the oil and natural gas lease level. The most directly comparable GAAP measure to operating netback is oil and natural gas revenue. Operating netback is calculated as oil and natural gas revenue less royalty expenses, operating expenses, transportation expenses and loss on risk management activities. See below and under "Summary of Quarterly Results" for a reconciliation of operating netback to oil and natural gas revenue. Operating netback ($/boe) is a non-GAAP ratio 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 . It is calculated as operating netbacks divided by weighted average daily production on a per boe basis. See below. Corporate Netback and Funds Flow Corporate netback or funds flow 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 and funds flow are used interchangeably. Petrus analyzes these measures on an absolute value and on a per unit (boe) and per share (basic and fully diluted) basis as non-GAAP ratios. Management Page |24 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, cash finance expense, decommissioning expenditures, plus other income and the net realized gain (loss) on financial derivatives and risk management activities. See below and under "Summary of Quarterly Results" for a reconciliation of funds flow and corporate netback to oil and natural gas revenue. Corporate netback ($/boe) or funds flow ($/boe) is a non-GAAP ratio used in the oil and natural gas industry which evaluates the Company’s profitability at the corporate level. Management believes that funds flow ($/boe) or corporate netback ($/boe) provide information to assist a reader in understanding the Company's profitability relative to current commodity prices. It is calculated as corporate netbacks or funds flow divided by weighted average daily production on a per boe basis. See below. Funds flow per share (basic and fully diluted) is comprised of funds flow divided by basic or fully diluted weighted average common shares outstanding. Oil and natural gas revenue Royalty expense Loss on risk management activities Net oil and natural gas revenue Transportation expense Operating expense Operating netback Realized gain (loss) on financial derivatives Other income(1) General & administrative expense Cash finance expense(2) Decommissioning expenditures Funds flow and corporate netback Three months ended Three months ended Twelve months ended Twelve months ended December 31, 2022 December 31, 2021 December 31, 2022 December 31, 2021 $000s $/boe $000s $/boe $000s $/boe $000s $/boe 48,590 57.96 25,070 46.35 152,350 54.89 81,268 (6,636) (1,056) (7.92) (1.26) (3,429) (6.34) (24,161) (8.70) (10,361) — — (6,029) (2.17) — 40,898 48.78 21,641 40.01 122,160 44.02 70,907 (1,743) (5,753) 33,402 2,421 186 (926) (987) 21 34,117 (2.08) (6.86) 39.84 2.89 0.22 (1.10) (1.18) 0.03 40.70 (1,010) (2,715) 17,916 (5,148) 21 (1,213) (856) (302) (1.87) (5,772) (2.08) (3,920) (5.02) (20,665) (7.45) (12,914) 33.12 (9.52) 0.04 (2.24) (1.58) (0.56) 95,723 (1,601) 291 (3,389) (3,171) (137) 34.49 (0.58) 0.10 (1.22) (1.14) (0.05) 54,073 (11,713) 1,075 (4,274) (5,133) (674) 10,418 19.26 87,716 31.60 33,354 37.04 (4.72) — 32.32 (1.79) (5.89) 24.64 (5.34) 0.49 (1.95) (2.34) (0.31) 15.19 (1)Excludes non-cash government grant related to decommissioning expenditures. (2)Excludes non-cash Term Loan interest payment-in-kind. Net Debt Net debt is a non-GAAP financial measure and is calculated as the sum of long term debt and working capital (current assets and current liabilities), excluding the current financial derivative contracts and current portion of the lease obligation. Petrus uses net debt as a key indicator of its leverage and strength of its balance sheet. Net debt is reconciled, in the table below, to long-term debt which is the most directly comparable GAAP measure. ($000s) Long-term debt Current assets Current liabilities Current financial derivatives Current portion of lease obligation Net debt As at December 31, 2022 As at September 30, 2022 As at June 30, 2022 As at March 31, 2022 25,000 (29,849) 51,395 4,502 (240) 50,808 22,000 (29,905) 51,102 5,503 (235) 48,465 12,000 (18,783) 18,785 2,124 (231) 13,895 — (17,356) 67,625 — (225) 50,044 Net debt to funds flow ratio is a non-GAAP ratio used as a key indicator of our leverage and strength of our balance sheet. It is calculated as net debt divided by funds flow for the relevant period. OIL AND GAS DISCLOSURES Our oil and gas reserves statement for the year ended December 31, 2022, 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, which will be filed on SEDAR at www.sedar.com. Page |25 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. 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 audited consolidated financial statements as at and for the twelve months ended December 31, 2022. 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, 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: the Company's risk management and hedging strategy and its objectives, including our ability to mitigate commodity price risk and provide stability and sustainability to our economic returns, funds flow and capital development plan; our belief that our risk management contracts are effective economic hedges of our underlying business transactions; that our risk management contracts provide protection from significant changes in crude oil and natural gas commodity prices for 2023 and 2024; and the Company's intention not to settle its DSUs for cash. 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; industry conditions; currency fluctuation; changes in interest rates and inflation rates; 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; and the other risks and uncertainties described in the AIF. 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; 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; the effects of inflation on our profitability; future interest rates; 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 investors 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. These forward-looking statements are made as of the date of this MD&A and the Company disclaims any intent or obligation to update any forward-looking statements, 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 Page |26 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 mbbl bbl/d boe mboe mmboe boe/d GJ GJ/d mcf mcf/d mmcf/d bcf NGLs WTI thousand dollars dollars per barrel dollars per barrel of oil equivalent dollars per gigajoule dollars per thousand cubic feet barrel thousand 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 billion cubic feet natural gas liquids West Texas Intermediate Page |27 CONSOLIDATED ANNUAL FINANCIAL STATEMENTS As at and for the years ended December 31, 2022 and 2021 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, 2022 and 2021, and the consolidated statements of net income and comprehensive income, 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, 2022 and 2021, 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. 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. 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, 2022, the carrying values of PP&E and E&E assets were $315.8 million and $34.8 million, respectively. Refer to Note 7 and 6 of the consolidated financial statements for the Company’s PP&E and E&E disclosures, respectively, and Note 3 for Company’s policy on impairment assessment. Cash-generating units (“CGUs”) are assessed by management for indicators of impairment or impairment reversal at each reporting date. The Company concluded that no indicators of impairment or impairment reversal were present as at December 31, 2022. To test the Company's assessment of indicators of impairment or impairment reversal, we performed the following procedures, among others: - Evaluated the impact of the change in observable forecasted commodity prices relative to prices used in previous impairment test. - Assessed the competency and objectivity of the Company’s external reserve engineer. - Compared significant reserve report data to historical results, third party sources, and the Company’s development plan. Auditing the Company’s assessment of indicators of impairment or impairment reversal involved significant judgement due to forecast commodity prices and increase in the market interest rates. - We involved our valuation specialists to assist in evaluating discount rates and cash flow multiples for certain CGU’s based on observable market inputs and recent comparable transactions - Assessed the market capitalization of the Company against its net book value and investigated any contrary information. - Evaluated the adequacy of the disclosure included in Note 6 & 7 of the accompanying consolidated financial statements in relation to this matter. Other Information Management is responsible for the other information. The other information comprises: • 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: • 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. • Obtain an understanding of internal control relevant to the audit in order to design audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of the Company’s internal control. • Evaluate the appropriateness of accounting policies used and the reasonableness of accounting estimates and related disclosures made by management. • Conclude on the appropriateness of management’s use of the going concern basis of accounting and, based on the audit evidence obtained, whether a material uncertainty exists related to events or conditions that may cast significant doubt on the Company’s ability to continue as a going concern. If we conclude that a material uncertainty exists, we are required to draw attention in our auditor’s report to the related disclosures in the 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. • 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. Ernst & Young LLP Chartered Professional Accountants Calgary, Canada March 14, 2023 CONSOLIDATED BALANCE SHEETS (Presented in 000’s of Canadian dollars) As at December 31, 2022 December 31, 2021 ASSETS Current Cash Inventory (note 24) Deposits and prepaid expenses (note 25) Accounts receivable (note 16) Risk management asset (note 11) Total current assets Non-current Risk management asset (note 11) Exploration and evaluation assets (note 6) Property, plant and equipment (note 7) Total non-current assets Total assets LIABILITIES AND SHAREHOLDERS’ EQUITY Current liabilities Bank loan (note 8) Accounts payable and accrued liabilities (note 16) Risk management liability (note 11) Decommissioning obligation (note 10) Lease obligations (note 9) Total current liabilities Non-current liabilities Long term debt (note 8) Lease obligations (note 9) Decommissioning obligation (note 10) Total liabilities Shareholders’ equity Share capital (note 12) Contributed surplus Deficit Total shareholders' equity Total liabilities and shareholders' equity Commitments and contingencies (note 20) Related party transactions (note 22) See accompanying notes to the consolidated financial statements Approved by the Board of Directors, (signed) “Don T. Gray” Don T. Gray Chairman 40 1,197 1,862 22,248 4,502 29,849 619 34,837 315,752 351,208 381,057 4,607 45,191 — 1,357 240 51,395 25,000 363 37,658 114,416 492,241 29,061 (254,661) 266,641 381,057 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 (signed) “Donald Cormack” Donald Cormack Director Page |33 CONSOLIDATED STATEMENTS OF NET INCOME AND COMPREHENSIVE INCOME (Presented in 000’s of Canadian dollars, except per share amounts) REVENUE Oil and natural gas revenue (note 21) Royalty expense Loss on risk management activities (notes 11 and 21) Net oil and natural gas revenue Other income (note 26) Net gain (loss) on financial derivatives (note 11) Total income EXPENSES Operating (note 14) Transportation General and administrative (note 15) Share-based compensation (note 12) Finance (note 18) Exploration and evaluation (note 6) Depletion and depreciation (note 7) Gain on sale of assets Impairment (reversal) (notes 6 and 7) Total expenses INCOME BEFORE INCOME TAX Income tax recovery (note 23) NET INCOME AND COMPREHENSIVE INCOME Net income per common share Basic (note 13) Diluted (note 13) See accompanying notes to the consolidated financial statements Year ended Year ended December 31, 2022 December 31, 2021 152,350 (24,161) (6,029) 122,160 1,351 6,008 129,519 20,665 5,772 3,389 1,141 4,667 421 33,277 (681) — 68,651 60,868 — 60,868 0.53 0.51 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 Page |34 CONSOLIDATED STATEMENTS OF CHANGES IN SHAREHOLDERS’ EQUITY (Presented in 000’s of Canadian dollars) Balance, December 31, 2020 Net income Deferred Share Unit settlement Issuance of common shares Share issue costs Share-based compensation Balance, December 31, 2021 Net income Common shares issued for property acquisition (note 5) Common shares issued for rights offering (note 12) Issuance of common shares (note 12) Share issue costs (note 12) Share-based compensation (note 12) Balance, December 31, 2022 See accompanying notes to the consolidated financial statements Share Capital 430,119 — — 25,900 (111) — 455,908 — 15,200 20,003 1,427 (297) — 492,241 Contributed Surplus 9,596 — (223) 18,119 — 354 27,846 — — — (415) — 1,630 29,061 Deficit (430,085) 114,556 — — — — (315,529) 60,868 — — — — — (254,661) Total 9,630 114,556 (223) 44,019 (111) 354 168,225 60,868 15,200 20,003 1,012 (297) 1,630 266,641 Page |35 CONSOLIDATED STATEMENTS OF CASH FLOWS (Presented in 000’s of Canadian dollars) OPERATING ACTIVITIES Net income Adjust items not affecting cash: Share-based compensation (note 12) Unrealized (gain) loss on financial derivatives (note 11) Non-cash finance expenses (note 18) Non-cash term loan interest payment-in-kind (note 18) Depletion and depreciation (note 7) Impairment (reversal) (notes 6 and 7) Exploration and evaluation expense (note 6) Gain on sale of assets (note 7) Recovery of income taxes on debt settlement (note 23) Other income (note 21) Decommissioning expenditures (note 10) Funds flow Change in operating non-cash working capital (note 19) Cash flows from operating activities FINANCING ACTIVITIES Deferred Share Unit payment (note 12) Issuance of shares (note 12) Repayment of revolving credit facility Repayment of bank indebtedness Transaction costs on debt Repayment of lease liabilities (note 9) Proceeds from long term debt (note 8) Change in financing non-cash working capital (note 19) Cash flows used in financing activities INVESTING ACTIVITIES Property and equipment acquisitions (note 7) Property and equipment dispositions (note 7) Exploration and evaluation asset expenditures (note 6) Petroleum and natural gas property expenditures (note 7) Other capital expenditures Change in investing non-cash working capital (note 19) Cash flows used in investing activities Increase (decrease) in cash Cash, beginning of year Cash, end of year Cash interest paid (note 18) See accompanying notes to the consolidated financial statements Page |36 Year ended Year ended December 31, 2022 December 31, 2021 60,868 1,141 (7,609) 1,496 — 33,277 — 421 (681) — (1,060) (137) 87,716 12,891 100,607 — 21,132 (53,094) — (518) (217) 25,000 — (7,697) 243 — (1,645) (94,921) (175) (1,300) (97,798) (4,888) 4,928 40 3,171 114,556 259 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 NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS For the years ended December 31, 2022 and 2021 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, 2022 and 2021, were approved by the Company’s Audit Committee and Board of Directors on March 14, 2023. 2. BASIS OF PRESENTATION 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 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 Page |37 iii. iv. v. vi. 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. 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. Business Combinations The acquisition method of accounting is used to account for acquisitions of entities and assets that meet the definition of a business under IFRS. Identifiable assets acquired and liabilities and contingent liabilities assumed in a business combination are measured initially at their fair values at the acquisition date. The excess of the cost of acquisition over the fair value of the identifiable assets acquired and liabilities and contingent liabilities assumed is recorded as goodwill. If the cost of the acquisition is less than the fair value of the net assets acquired, the difference is recognized immediately in profit or loss. Business combination associated transaction costs are expensed when incurred. Within the IFRS Business Combinations guidance, there is an optional fair value concentration test. The concentration test is a simplified assessment that results in an asset acquisition if substantially all of the fair value of the gross assets is concentrated in a single identifiable asset or a group of similar identifiable assets. If an entity chooses not to apply the concentration test, or the test is failed, then the assessment focuses on the existence of a substantive process, and the acquisition is accounted for as a business combination. The cost of an acquisition that does not meet the definition of a business under IFRS and does not qualify as a business combination is measured as the fair value of the consideration given and liabilities incurred or assumed at the date of exchange. No goodwill arises on an asset acquisition and the cost of the assets acquired and liabilities assumed are allocated to the assets and liabilities on the basis of their relative fair values at the date of purchase. Asset acquisition associated transaction costs are capitalized as a cost of the acquisition. 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. Certain costs incurred prior to acquiring the legal rights to explore are charged directly to net income (loss). Page |38 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 net income or net 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. 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 Page |39 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 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. Page |40 (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. (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 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. Carbon credits Carbon credits that are held for sale in the ordinary course of business are recognized as inventory in the year credits are verified and are measured at the lower of cost or net realizable value. The cost of emission credits is determined at the market value of the credits in the year credits are verified. Upon sale of the carbon credits, the carrying amount is derecognized from inventory on the Consolidated Balance Sheet, recording any gain or loss on the Statements of Net Income and Comprehensive Income. Page |41 (o) New standards and interpretations IFRS 17 Insurance Contracts IFRS 17 requires insurance liabilities to be measured at a current fulfillment value and provides a more uniform measurement and presentation approach for all insurance contracts. These requirements are designed to achieve the goal of a consistent, principle-based accounting for insurance contracts. IFRS 17 supersedes IFRS 4 Insurance Contracts as of January 1, 2023. Amendments to IAS 1 On October 31, 2022, the International Accounting Standards Board (IASB) published "Non-current Liabilities with Covenants (Amendments to IAS 1)" to clarify how conditions with which an entity must comply within twelve months after the reporting period affect the classification of a liability. The amendments are effective for reporting periods beginning on or after January 1, 2024. The Company does not expect any impact to the financial statements due to these amendments. 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. 5. ACQUISITIONS On March 14, 2022, Petrus completed the acquisition of certain oil and liquids rich natural gas weighted properties within its Ferrier core area from a privately owned limited partnership and its general partner. The acquired partnership was managed and directed by an officer and director of Petrus and two of Petrus' major shareholders owned or controlled, in aggregate, approximately 69.5% and 50% of the acquired partnership's units and shares, respectively. Page |42 Given the close proximity of the acquired properties to the Company's existing assets and infrastructure, the acquired properties are synergistic to existing operations and complementary to current development plans. The assets were acquired for share consideration of $15.2 million (10 million common shares of Petrus at $1.52 per share on closing date). The Company applied the optional concentration test permitted under IFRS 3 to the acquisition which resulted in the acquired assets being accounted for as an asset acquisition. As such the purchase price was allocated to the identifiable assets and liabilities based on their relative fair values at the date of acquisition. Assets acquired in the transaction will be included in the Ferrier CGU. Asset acquisition transaction costs of $0.3 million were capitalized as a cost of the asset. The amounts recognized on the date of acquisition to identifiable net assets were as follows: $000s (except share and per share amounts) Net assets acquired: Cash & cash equivalents Accounts receivable & other assets Accounts payable & accrued liabilities Property, plant and equipment Decommissioning obligation Net assets acquired Purchase consideration: Common shares issued to partners Price of Petrus common shares ($ per share) on close date Total purchase consideration 6. EXPLORATION AND EVALUATION ASSETS The components of the Company’s exploration and evaluation ("E&E") assets are as follows: $000s Balance, December 31, 2020 Additions Disposition Exploration and evaluation expense Capitalized G&A Capitalized share-based compensation Transfers to property, plant and equipment (note 7) Impairment reversal Balance, December 31, 2021 Acquisitions Exploration and evaluation expense Capitalized G&A Capitalized share-based compensation (note 12) Transfers to property, plant and equipment (note 7) Balance, December 31, 2022 434 496 (406) 16,765 (2,089) 15,200 10,000,000 $1.52 15,200 17,568 401 (18) (108) 220 24 (5,093) 22,640 35,634 1,349 (421) 295 122 (2,142) 34,837 During the year ended December 31, 2022, the Company incurred exploration and evaluation expense of $0.4 million which relates to expired and nearly expired undeveloped, non-core land (year ended December 31, 2021 – $0.11 million). During the year ended December 31, 2022, the Company capitalized $0.3 million of general and administrative expenses (“G&A”) (year ended December 31, 2021 – $0.2 million) and $0.12 million of non-cash share-based compensation directly attributable to exploration activities (year ended December 31, 2021 – $0.02 million). During the year ended December 31, 2022, the Company transferred $2.1 million from E&E assets to PP&E assets, related to the Ferrier and North Ferrier Cash Generating Units ("CGUs"). At December 31, 2022, the Company did not identify any indicators of impairment or impairment reversals, related to its E&E assets, in any of its CGUs. Page |43 2021 Impairment Reversal 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. The impairment reversal amount reflects all of the original impairment charges recorded on March 31, 2020 and December 31, 2014, less associated depletion. No impairment or impairment reversal for E&E assets was recorded on other CGUs of the Company. 7. PROPERTY, PLANT AND EQUIPMENT The components of the Company’s property, plant and equipment ("PP&E") assets are as follows: $000s Balance, December 31, 2020 Additions Property dispositions Capitalized G&A Capitalized share based compensation Transfer from exploration and evaluation assets (note 6) Depletion & depreciation Increase in decommissioning expenses Impairment reversal Balance, December 31, 2021 Additions Property acquisition (note 5) Property dispositions Capitalized G&A Capitalized share-based compensation (note 12) Transfers from exploration and evaluation assets (note 6) Depletion & depreciation Changes in decommissioning provision (note 10) Balance, December 31, 2022 Cost 835,583 25,593 (14,495) 658 73 5,093 — 329 — 852,834 94,145 16,765 (71) 884 367 2,142 — (4,450) 962,616 Accumulated DD&A (683,614) — 12,439 — — — (22,992) — 80,580 (613,587) — — — — — — (33,277) — (646,864) Net book value 151,969 25,593 (2,056) 658 73 5,093 (22,992) 329 80,580 239,247 94,145 16,765 (71) 884 367 2,142 (33,277) (4,450) 315,752 At December 31, 2022, estimated future development costs of $519.8 million (December 31, 2021 – $343.5 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, 2022, the Company capitalized $0.9 million of general and administrative expenses (“G&A”) (year ended December 31, 2021 – $0.7 million) and non-cash share-based compensation of $0.37 million (year ended December 31, 2021 – $0.07 million), directly attributable to development activities. During the year ended December 31, 2022, the Company recorded a gain of $0.7 million on the disposition of certain PP&E assets in the Foothills and Central Alberta CGUs related to the disposal of ARO associated with these assets. During the year ended December 31, 2022, the Company transferred $2.1 million from E&E assets to PP&E assets, related to the Ferrier and North Ferrier CGUs. During 2022, Petrus recorded minor disposition transactions for petroleum and natural gas properties and equipment for total net cash consideration of $0.07 million. At December 31, 2022, the carrying balance of the right of use asset was $0.5 million. At December 31, 2022, the Company did not identify any indicators of impairment or impairment reversals, related to its PP&E assets, in any of its CGUs. 2021 Impairment Reversal At December 31, 2021, in its Ferrier CGU, the Company identified an 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 indicators of impairment or impairment reversal. Page |44 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 used the following forward commodity price estimates: 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. 8. DEBT At December 31, 2022, Petrus had two debt instruments outstanding; a reserve-based, secured operating revolving loan facility with an Alberta-based financial institution (the “Revolving Loan Facility” or “RLF”) and a second lien secured term facility (the "Second Lien Facility"). Revolving Loan Facility At December 31, 2022, the RLF was comprised of a $30.0 million operating facility payable on demand by the lender. The amount of the RLF is subject to a borrowing base review performed on a semi-annual basis by the lender, based primarily on reserves and commodity prices estimated by the lenders as well as other factors. The next semi-annual review is due on May 31, 2023. At December 31, 2022, the Company had a $0.6 million letter of credit outstanding against the RLF (December 31, 2021 – $0.6 million on the previous revolving credit facility) and had drawn $4.6 million against the RLF (December 31, 2021 – $57.7 million on the previous revolving credit facility). Second Lien Facility At December 31, 2022 the Company had $25.0 million outstanding on the $25 million Second Lien Facility. The Second Lien Facility is a three-year term facility (maturity date May 31, 2025 with an option to the borrower to extend by an additional two years) with a fixed interest rate of 11% per annum and can be repaid at the discretion of the Company after the first year. The Second Lien Facility is a related party transaction with a major shareholder who owns approximately 21% of the outstanding shares of the Company (see note 22). The total interest paid in 2022 to the major shareholder, related to the Second Lien facility, was $1.1 million. Debt Settlement - Term Loan & Revolving Credit Facility During 2022, the Company entered into agreements with new lenders to the Company, providing two new credit facilities, as described above, (the “New Credit Facilities”) totaling $55 million. The New Credit Facilities, together with the net proceeds of the Company's recently closed $20 million rights offering, were used to repay in full all amounts owing under the Company's previous revolving credit facility (the "Revolving Credit Facility" or "RCF"). The New Credit Facilities closed in May 2022. Prior to December 31, 2021, Petrus had 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 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). Financial Covenants The Company's RLF is subject to certain financial covenants. The following definitions are used in the covenant calculations for the debt instrument: 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 RLF, 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. Page |45 The key financial covenants as at December 31, 2022 are summarized in the following table. At December 31, 2022 the Company is in compliance with all financial covenants. Financial Covenant Description Working Capital Ratio 9. LEASES The Company's lease obligations are as follows: $000s Balance, December 31, 2021 Finance expense Lease payments Balance, December 31, 2022 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 10. DECOMMISSIONING OBLIGATION Required Ratio Over 1.0 As at December 31, 2022 1.1 820 54 (271) 603 As at December 31, 2022 277 369 646 (43) 603 240 363 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 3.31 percent and an inflation rate of 3.00 percent (1.66 percent and 2.0 percent, respectively, at December 31, 2021). Changes in estimates in 2021 and 2022 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 $39.0 million as at December 31, 2022 ($41.6 million at December 31, 2021). The undiscounted, uninflated total future liability at December 31, 2022 is $41.7 million ($38.3 million at December 31, 2021). The payments are expected to be incurred over the operating lives of the assets. The following table reconciles the decommissioning liability: $000s Balance, December 31, 2020 Property dispositions Other adjustments Liabilities incurred Liabilities settled Change in estimates Accretion expense Balance, December 31, 2021 Property acquisitions (note 3) Property dispositions Other adjustments Liabilities incurred Liabilities settled Change in estimates Accretion expense Balance, December 31, 2022 Page |46 44,456 (2,876) (373) 489 (674) (160) 707 41,569 2,089 (681) (441) 1,231 (137) (5,681) 1,066 39,015 11. FINANCIAL RISK MANAGEMENT The Company utilizes commodity contracts as a risk management technique to mitigate exposure to commodity price volatility. The following table summarizes the financial derivative contracts Petrus had outstanding as at December 31, 2022: Contract Period Natural Gas Swaps Jan. 1, 2023 to Mar. 31, 2023 Apr. 1, 2023 to Oct. 31, 2023 Nov. 1, 2023 to Mar. 31, 2024 Apr. 1, 2024 to Oct. 31, 2024 Contract Period Crude Oil Swaps Jan 1, 2023 to Jun 30, 2023 Jan. 1, 2023 to Dec 31 2023 Jul. 1, 2023 to Dec 31 2023 Oct. 1, 2023 to Dec 31, 2023 Jan. 1 2024 to Jun 30, 2024 Contract Period Crude Oil Collars Jan. 1 2023 to Dec 31, 2023 Type Total Daily Volume (GJ) Average Price (CDN$/GJ) Fixed price Fixed price Fixed price Fixed price 6,000 13,000 11,000 3,000 $6.67 $4.35 $4.91 $3.52 Type Total Daily Volume (Bbl) Average Price (CDN$/Bbl) Fixed price Fixed price Fixed price Fixed price Fixed price 600 200 500 100 800 $110.57 $104.15 $101.94 $102.15 $99.83 Type Total Daily Volume (Bbl) Average Price (CDN$/Bbl) Costless collar 300 $90.00-120.95 The following table summarizes the physical commodity contracts in place at December 31, 2022: Contract Period Natural Gas Jan. 1, 2023 to Mar. 31, 2023 Type Total Daily Volume (GJ) Average Price (CDN$/GJ) Fixed price 14,000 $4.25 During the year ended December 31, 2022, the Company realized a loss on risk management activities of $6.0 million (year ended December 31, 2021 - nil). Risk management asset and liability: $000s At December 31, 2022 Current commodity derivatives Non-current commodity derivatives $000s At December 31, 2021 Current commodity derivatives Non-current commodity derivatives Earnings impact of realized and unrealized gains (losses) on financial derivatives: $000s Realized loss on financial derivatives Unrealized gain (loss) on financial derivatives Net gain (loss) on financial derivatives Asset 4,502 619 5,121 — — — Liability — — — 2,488 — 2,488 Year ended Year ended December 31, 2022 (1,601) 7,609 6,008 December 31, 2021 (11,713) (2,409) (14,122) Page |47 12. SHARE CAPITAL 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 except number of shares) Balance, December 31, 2021 Common shares issued for property acquisition Common shares issued in a rights offering Common shares issued on exercise of stock options Share issue costs Balance, December 31, 2022 Number of shares 96,707,912 10,000,000 14,817,347 1,713,269 — 123,238,528 Amount 455,908 15,200 20,003 1,427 (297) 492,241 Rights Offering During the year ended December 31, 2022, the Company completed a rights offering (the “Offering”). Pursuant to the Offering, the Company issued 14.8 million common shares at $1.35 per share for aggregate gross proceeds to the Company of $20.0 million. The issuance costs were $0.3 million and the net proceeds of $19.6 million were utilized for debt repayment and towards working capital. The Company entered into a standby purchase agreement with three investors (collectively, the "Stand-By Guarantors") who each own more than 20% of the outstanding shares of the Company. As a result of the exercise of the basic subscription privilege and additional subscription privilege by the holders of rights (including the Stand-By Guarantors), the Stand-By Guarantors did not acquire any Common Shares in connection with the Rights Offering pursuant to their stand-by commitments. The basic and additional subscriptions totaled 184% of the common shares of the Company available through the Rights Offering. The Company had approximately 121.7 million shares outstanding following the rights offering with the Stand-By Guarantors owning approximately 71% of the outstanding shares. Property Acquisition During the first quarter of 2022, the Company completed an asset acquisition. The assets were acquired for share consideration of $15.2 million (10 million common shares of Petrus at $1.52 per share on closing date). 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, 2022, 8,519,709 (December 31, 2021 – 5,562,549) stock options were outstanding. The summary of stock option activity is presented below: Balance, December 31, 2020 Granted Forfeited Expired Exercised Balance, December 31, 2021 Granted Expired Exercised Balance, December 31, 2022 Exercisable, December 31, 2022 Number of stock options 2,276,923 4,637,500 (623,513) (198,780) (529,581) 5,562,549 4,677,500 (7,071) (1,713,269) 8,519,709 498,958 Weighted average exercise price $0.40 $0.75 $0.36 $1.68 $0.28 $0.67 $2.27 $0.74 $0.60 $1.56 $0.64 Page |48 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 - $0.89 $1.78 $2.25 $2.81 Number granted Weighted average exercise price Weighted average remaining life (years) 392,204 2,653,335 796,670 1,020,000 2,602,500 1,055,000 8,519,709 $0.24 $0.71 $0.89 $1.78 $2.25 $2.81 $1.56 0.6 1.8 2.0 2.8 2.5 3.0 2.3 During the year ended December 31, 2022, the Company granted 4,677,500 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, 2022 of $0.91 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 (%) 2022 2.46% - 4.34% 1.08 - 3.25 100% to 113% 33 % — % 2021 0.15% - 0.49% 1.08 - 3.08 100% to 113% 33 % — % 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, 2022, 1,618,702 DSUs were issued and outstanding (December 31, 2021 – 1,618,702). 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 Total share-based compensation 13. EARNINGS PER SHARE Year ended Year ended December 31, 2022 1,141 122 367 1,630 December 31, 2021 259 24 73 356 Earnings per share amounts are calculated by dividing the net income for the period attributable to the common shareholders of the Company by the weighted average number of common shares outstanding during the period. Page |49 Net income for the year ($000s) Weighted average number of common shares – basic (000s) Weighted average number of common shares – diluted (000s) Net income per common share – basic Net income per common share – diluted Year ended Year ended December 31, 2022 60,868 115,189 119,525 $0.53 $0.51 December 31, 2021 114,556 62,557 65,207 $1.83 $1.76 In computing diluted earnings per share for the year ended December 31, 2022, 8,519,709 outstanding stock options and 1,618,702 DSUs were considered (December 31, 2021 – 5,562,549 and 1,618,702 respectively). 2,717,962 stock options and 1,618,702 DSUs were included in calculating the number of diluted common shares. There were 5,801,747 stock options that were anti-dilutive as the exercise price was higher than the average share price during the year ended December 31, 2022. 14. 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 15. 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 16. FINANCIAL INSTRUMENTS Risks associated with financial instruments Year ended Year ended December 31, 2022 16,954 December 31, 2021 11,134 4,853 21,807 (1,142) 20,665 2,719 13,853 (939) 12,914 Year ended Year ended December 31, 2022 6,715 (1,179) (2,147) December 31, 2021 5,830 (878) (678) 3,389 4,274 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 $22.2 million of accounts receivable outstanding at December 31, 2022 (December 31, 2021 – $9.7 million), $15.3 million is owed from 2 parties (December 31, 2021 – $7.4 million from 3 parties), and the balances were received subsequent to December 31, 2022. At December 31, 2022, the Company had an allowance for doubtful accounts of $0.1 million (December 31, 2021 – $0.5 million). The Company considers accounts receivable outstanding past 120 days to be 'past due'. At December 31, 2022, 99.8% of Petrus’ accounts receivable were aged less than 120 days and 0.2% 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, 2022, the Company had a $30.0 million RLF, of which $4.6 million was drawn (December 31, 2021 – $57.7 million on the previous RCF which has been repaid in full). For the year ended December 31, 2022, the Company generated cash flow from operating activities of $100.6 million. During the year ended December 31, 2022, the Company entered into agreements with new lenders and repaid the previous RCF in full (see note 8). Page |50 The following are the contractual maturities of financial liabilities as at December 31, 2022: $000s Accounts payable and accrued liabilities Bank indebtedness Lease obligations (discounted) Long term debt Total Total 45,191 4,606 603 25,000 75,400 < 1 year 45,191 4,606 240 — 50,037 1-5 years — — 363 25,000 25,363 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 RLF 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. A 1% increase in the Canadian prime interest rate during the year ended December 31, 2022 would have decreased net income by approximately $0.3 million, which relates to interest expense on the average outstanding RLF, assuming that all other variables remain constant (December 31, 2021 – $0.8 million). A 1% decrease in the Canadian prime interest rate during the year would result in an opposite impact on net income for 2022 and 2021. 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 11). 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, 2022, it was estimated that a $0.25/GJ decrease in the price of natural gas would have increased net income by $1.4 million (December 31, 2021 – $0.2 million). An opposite change in commodity prices would result in an opposite impact on net income for the period. As at December 31, 2022, it was estimated that a $5.00/CDN WTI/bbl decrease in the price of oil would have increased net income by $3.1 million (December 31, 2021 – $0.3 million). An opposite change in commodity prices would result in an opposite impact on net income for the period. 17. 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. 18. FINANCE EXPENSES The components of finance expenses are as follows: $000s Cash: Interest and finance fees Finance fees Foreign exchange Total cash finance expenses Non-cash: Deferred financing costs Non-cash term loan interest payment-in-kind Accretion on decommissioning obligations (note 10) Total non-cash finance expenses Total finance expenses Year ended Year ended December 31, 2022 December 31, 2021 2,175 993 3 3,171 430 — 1,066 1,496 4,667 4,108 1,025 — 5,133 365 2,573 707 3,645 8,778 Page |51 19. 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 Inventory and others Accounts receivable Accounts payable and accrued liabilities Operating activities Financing activities Investing activities Year ended Year ended December 31, 2022 December 31, 2021 (362) (518) (515) (12,515) 25,501 11,591 12,891 — (1,300) 199 (178) — (3,455) 11,982 8,548 (366) (179) 9,089 The following table reconciles the changes in liability resulting from financing activities: $000s Balance, December 31, 2021 Cash flows Balance, December 31, 2022 Bank Indebtedness Revolving Credit Facility Term Loan Total Liabilities from Financing Activities — — — 57,700 (53,093) 4,607 — — — 57,700 (28,093) 29,607 20. COMMITMENTS AND CONTINGENCIES COMMITMENTS The commitments for which the Company is responsible are as follows: $000s Firm service transportation Total 11,240 < 1 year 2,582 1-5 years 8,658 > 5 years — 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. 21. REVENUE The following table presents Petrus' oil and natural gas revenue disaggregated by product type: $000s Production & royalty revenue Oil and condensate sales Natural gas sales Natural gas liquids sales Royalty revenue Total oil and natural gas revenue Royalty expense Loss on risk management activities Net oil and natural gas revenue 22. RELATED PARTY TRANSACTIONS Page |52 Year ended Year ended December 31, 2022 December 31, 2021 59,348 67,025 25,267 710 152,350 (24,161) (6,029) 122,160 29,322 34,833 16,793 320 81,268 (10,361) — 70,907 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 Year ended Year ended December 31, 2022 1,245 December 31, 2021 1,307 445 1,690 85 1,392 During the year ended December 31, 2022, the Company completed its debt restructuring transactions, which included the Second Lien Facility in the form of a promissory note held by a major shareholder, owning approximately 21% of the outstanding shares of the Company (see note 8). During the year ended December 31, 2022, the Company closed an asset acquisition that was considered a related party transaction (see note 5). During the year ended December 31, 2022, the Company entered into a standby purchase agreement with three investors (collectively, the "Stand-By Guarantors") who each own more than 20% of the outstanding shares of the Company. The Company entered into a standby purchase agreement with each of Don Gray, Stuart Gray and Glen Gray (collectively, the "Stand-By Guarantors"). The Rights Offering was oversubscribed by 84% and as a result, the Stand- By Guarantors did not acquire any Common Shares in connection with the Rights Offering pursuant to their stand-by commitments. The Company had approximately 121.7 million share outstanding following the Rights Offering with the Stand-By Guarantors owning approximately 71% of the outstanding shares. 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. 23. DEFERRED INCOME TAXES $000s Income 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 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, 2022 and 2021 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 Year ended Year ended December 31, 2022 December 31, 2021 60,868 23.0 % 14,000 1 306 (80) 1,059 (15,286) — — % 2022 27,439 (8,661) (184) (19,771) 1,178 — 109,132 23.0 % 25,100 1 82 — 1,615 (32,222) (5,424) (5) % 2021 19,116 (9,561) — (8,983) (572) — The company has unrecognized deductible temporary differences in the form of non-capital loss carry-forward of approximately $120.7 million (2021 - $224.8 million). The Company had non-capital losses of approximately $206.7 million (2021 – $263.9 million) which may be applied against future income for Canadian tax purposes. These non-capital losses expire in 2028 and onwards. Page |53 At December 31, 2022, the Company has determined it is currently not probable that future taxable profits will be available against which the tax benefits will be utilized. 24. INVENTORY The components of the Company’s inventory at December 31, 2022 and 2021 are as follows: $000s Oil and gas equipment inventory Carbon credits Inventory 25. DEPOSITS AND PREPAID EXPENSES The components of the Company’s deposits and prepaid expenses as at December 31, 2022 and 2021 are as follows: 2022 578 619 1,197 2022 229 414 19 172 1,028 1,862 2021 — — — 2021 150 12 18 118 652 950 Year ended Year ended December 31, 2022 619 441 291 December 31, 2021 — — 1,448 1,351 1,448 $000s Prepaid interest and bank fees Prepaid insurance Prepaid operating expenses Prepaid software Deposits Deposits and prepaid expenses 26. OTHER INCOME The following table presents Petrus' other income by category: $000s Carbon credits Government grant for decommissioning activities Other Other income During the year ended December 31, 2021, the Company recorded $1.4 million as other income. The amount was related to the settlement of an outstanding dispute associated with the transportation and marketing of condensate volume in the Company's Ferrier area. Page |54 CORPORATE INFORMATION OFFICERS & VICE PRESIDENTS DIRECTORS SOLICITOR OFFICERS Ken Gray, P.Eng President and Chief Executive Officer DIRECTORS Don T. Gray Chairman Scottsdale, Arizona Mathew Wong, CPA, CFA, CPA (WA, USA) Chief Financial Officer Ken Gray Calgary, Alberta Matt Skanderup Chief Operating Officer Lindsay Hatcher Vice President, Commercial & Corporate Development 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 ATB Financial 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 |55 

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