PetrusResources

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 three and six months ended June 30, 2025. This MD&A is dated August 6, 2025 and should be read in conjunction with the Company's audited consolidated financial statements for the years ended December 31, 2024 and 2023 and the Company's interim consolidated financial statements for the three and six months ended June 30, 2025 and 2024. The Company's consolidated financial statements are prepared in compliance 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 1110, 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.sedarplus.ca.

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SELECTED FINANCIAL INFORMATION

(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 financial measure or non-GAAP ratio. Refer to "Non-GAAP and Other Financial Measures".

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RESULTS OF OPERATIONS

FINANCIAL AND OPERATIONAL RESULTS OF OIL AND NATURAL GAS ACTIVITIES

Second quarter average daily production by area was as follows:

(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.

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FUNDS FLOW AND NET INCOME (LOSS)

Petrus generated funds flow of $12.3 million in the second quarter of 2025, a 16% increase from $10.6 million in the same period of 2024. The increase was driven by higher natural gas prices, realized hedging gain, and lower royalty expense, partially offset by lower oil and NGL pricing and lower production volumes.

In the second quarter of 2025, natural gas sales increased by 38% to $6.9 million, up from $5.0 million in the second quarter of 2024. Petrus realized a hedging gain of $1.9 million during the quarter, compared to a hedging loss of $0.3 million in the second quarter of the prior year.

Petrus reported net income of $10.4 million in the second quarter of 2025, up from $2.8 million in the second quarter of 2024. The increase was primarily driven by a higher unrealized gain on financial instruments.

| ($000s except per share) | Three months ended
June 30, 2025 | Three months ended
June 30, 2024 | Six months ended
June 30, 2025 | Six months ended
June 30, 2024 |
| --- | --- | --- | --- | --- |
| Funds flow | 12,348 | 10,628 | 24,814 | 26,901 |
| Funds flow per share - basic | 0.10 | 0.09 | 0.20 | 0.22 |
| Funds flow per share - fully diluted | 0.09 | 0.08 | 0.19 | 0.22 |
| Net income (loss) | 10,380 | 2,789 | 7,292 | (2,544) |
| Net income (loss) per share - basic | 0.08 | 0.02 | 0.06 | (0.02) |
| Net income (loss) per share - fully diluted | 0.08 | 0.02 | 0.06 | (0.02) |
| Common shares outstanding (000s) | | | | |
| Basic | 129,634 | 124,372 | 129,634 | 124,372 |
| Fully diluted | 141,456 | 134,919 | 141,456 | 134,919 |
| Weighted average shares outstanding (000s) | | | | |
| Basic | 128,252 | 124,290 | 127,154 | 124,344 |
| Fully diluted | 130,656 | 126,559 | 129,519 | 124,344 |

OIL AND NATURAL GAS SALES

Second quarter average production in 2025 was 9,155 boe/d (35% liquids), 3% lower than the second quarter of 2024 (9,471 boe/d; 32% liquids). Second quarter oil and natural gas sales in 2025 was $21.5 million compared to $23.2 million in 2024. The 7% decrease is primarily due to lower oil prices and lower overall production volumes, partially offset by higher natural gas prices.

The following table provides a breakdown of composition of the Company's production volume by product:

| Production Volume by Product (%) | Three months ended
June 30, 2025 | Three months ended
June 30, 2024 | Six months ended
June 30, 2025 | Six months ended
June 30, 2024 |
| --- | --- | --- | --- | --- |
| Natural gas | 65 % | 68 % | 65 % | 68 % |
| Crude oil and condensate^{(1)} | 14 % | 14 % | 14 % | 15 % |
| Natural gas liquids | 21 % | 18 % | 21 % | 17 % |
| Total commodity sales from production | 100 % | 100 % | 100 % | 100 % |

(1) Refer to "Production and Product Type Information" for further details.

The following table presents oil and natural gas sales by product and the change from the prior comparative periods:

| Oil and Natural Gas Sales ($000s) | Three months ended
June 30, 2025 | Three months ended | | Six months ended
June 30, 2025 | Six months ended
June 30, 2024 | % Change |
| --- | --- | --- | --- | --- | --- | --- |
| | | June 30, 2024 | % Change | | | |
| Natural gas | 6,874 | 4,984 | 38 % | 14,099 | 14,274 | (1)% |
| Crude oil and condensate^{(1)} | 9,422 | 12,483 | (25)% | 19,450 | 25,062 | (22)% |
| Natural gas liquids | 5,170 | 5,639 | (8)% | 11,496 | 11,746 | (2)% |
| Royalty income | 40 | 44 | (9)% | 91 | 107 | (15)% |
| Total oil and natural gas sales | 21,506 | 23,150 | (7)% | 45,136 | 51,189 | (12)% |

(1) Refer to "Production and Product Type Information" for further details.

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The following table provides the average benchmark commodity prices and the Company's average realized commodity prices (before realized gain or loss on financial derivatives):

(1)Refer to "Production and Product Type Information" for further details.

Natural gas

Natural gas sales for the three months ended June 30, 2025 increased by 38% to $6.9 million, up from $5.0 million in the prior year comparative period. This increase was driven by higher natural gas prices. The average realized natural gas price in the second quarter of 2025 was $2.11/mcf, a 50% increase from $1.41/mcf in the second quarter of 2024. This increase reflects a significant rise in benchmark pricing, with AECO 5A and AECO 7A 43% and 44% higher, respectively. Natural gas production averaged 35,738 mcf/d during the quarter, an 8% decrease compared to 38,908 mcf/d in the same period last year. Natural gas accounted for 32% of total oil and gas sales for the quarter, compared to 22% in the second quarter of 2024.

Crude oil and condensate

Oil and condensate sales for the three months ended June 30, 2025 totaled $9.4 million, a 25% decrease from $12.5 million in the prior year comparative period, primarily due to lower prices. The average realized price of light oil and condensate was $83.31/bbl for the second quarter of 2025, down 20% from $103.77/bbl in the second quarter of 2024. Production averaged 1,243 bbl/d, a 6% decrease from 1,322 bbl/d in the same period last year. Oil and condensate represented 44% of total oil and gas sales for the quarter, down from 54% in the second quarter of 2024.

Natural gas liquids (NGLs)

NGL sales (excluding condensate), totaled $5.2 million for the three months ended June 30, 2025, representing an 8% decline from $5.6 million in the prior year period. The decrease was driven by lower realized pricing, despite a 17% increase in production to 1,955 bbl/d, up from 1,664 bbl/d in the second quarter of 2024. The Company's average realized blended NGL price for the quarter averaged $29.07/bbl, compared to $37.25/bbl in the prior year. NGLs accounted for 24% of total oil and natural gas sales for the quarter, consistent with the second quarter of 2024.

The Company's NGL production mix (excluding condensate) consists of ethane, propane, butane and pentane. The pricing received for NGL production is based on annual contracts effective the first of April each year. The contract prices are based on the product mix, the fractionation process required and the demand for fractionation facilities.

ROYALTY EXPENSE

Royalties are paid to the Government of Alberta and to gross overriding royalty owners. The following table shows the Company's royalty expense (net of royalty allowances and incentives) for the periods shown:

Royalty expense for the second quarter of 2025, net of royalty allowances and incentives, totaled $2.0 million, down from $3.3 million in the same period of 2024. On a six month basis, total royalty expense decreased to $4.7 million from $6.8 million in 2024. The decrease in royalties across both periods primarily reflects increased production from Crown Royalty Holiday eligible wells, as well as a greater contribution from wells subject to lower gross overriding royalties.

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RISK MANAGEMENT

The Company utilizes financial derivative contracts to mitigate commodity price risk and provide stability and sustainability to the Company's economic returns, funds flow, dividend payments and capital development plans. 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. 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.

The table below shows the realized and unrealized gain or loss on financial derivative contracts for the periods shown:

For the second quarter of 2025, the Company recognized a realized hedging gain of $1.9 million, compared to a realized hedging loss of $0.3 million in the second quarter of 2024. This gain resulted from natural gas and oil prices during the quarter trading below the prices fixed in the Company's hedging contracts. The realized hedging gain increased the Company's corporate netback by $2.31/boe during the quarter.

For the six months ended June 30, 2025, the Company recognized a realized hedging gain of $2.8 million in comparison to a gain of $2.3 million in the comparable period in 2024.

During the second quarter of 2025, the Company recognized an unrealized gain of $11.8 million in comparison to an unrealized gain of $2.8 million in the second quarter of 2024. Between March 31 and June 30, 2025, commodity prices declined, leading to an unrealized gain in the fair value of the outstanding financial derivatives contracts on June 30, 2025.

The Company's risk management contracts provide protection from significant changes in crude oil and natural gas commodity prices for 2025, 2026, and 2027. The Company endeavors to hedge approximately 55% to 60% of its forecasted production for up to 12 months forward, and approximately 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, dividend payment and capital development plans. A summary of Petrus' risk management contracts as at June 30, 2025 is included in note 8 of the Company's interim condensed consolidated financial statements as at and for the three and six months ended June 30, 2025.

The table below summarizes Petrus' quarterly average crude oil and natural gas hedged volumes and average cap and floor prices through financial derivative contracts as at the date of this MD&A:

(1) The volumes and prices reported are the weighted average volumes and prices for the period.

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OPERATING EXPENSE

The following table shows the Company's operating expense for the reporting periods shown:

For the three months ended June 30, 2025, net operating expense totaled $5.1 million, a 19% increase from $4.3 million during the prior year comparative period. The increase in total net operating expense is due to higher processing charges (related to NGL deep cut production), and higher property taxes and government fees. On a per boe basis, net operating expense was 23% higher at $6.10/boe in the second quarter of 2025 compared to $4.96/boe in the second quarter of 2024.

For the six months ended June 30, 2025, net operating expense totaled $10.5 million, a 2% increase from the prior year comparative period. The increase in total net operating expense is due to higher processing charges (related to additional NGL production), workover costs, regulatory fees and property taxes, partially offset by lower power costs. On a per boe basis, net operating expense was 9% higher at $6.42/boe for the six months ended June 30, 2025 compared to $5.87/boe in 2024.

TRANSPORTATION EXPENSE

The following table shows transportation expense paid in the reporting periods shown:

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 June 30, 2025, transportation expense was $1.4 million or $1.73/boe compared to $1.3 million or $1.46/boe in the prior year comparative period.

For the six months ended June 30, 2025, transportation expense was $2.8 million or $1.69/boe compared to $2.9 million or $1.64 /boe in the prior year comparative period. The decrease in total transportation expense is due to lower production volumes. On a per boe basis, transportation expense is essentially unchanged from the prior year.

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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:

For the three months ended June 30, 2025, gross G&A expense (before capitalization and overhead recoveries) was $1.6 million, a 6% increase compared to $1.5 million in the prior year comparative period. Second quarter net G&A expense in 2025 was $0.8 million compared to $1.2 million in the prior year comparative period. The lower net G&A expense is due to higher capital overhead recoveries as a result of the increased capital activity during the second quarter of 2025 compared to the same period in 2024.

For the six months ended June 30, 2025, gross G&A expense (before capitalization and overhead recoveries) was $3.4 million compared to $3.2 million in the prior year comparative period. Net G&A expense on a six month basis was $1.9 million or $1.18/boe, a decrease from the $2.3 million or $1.33/boe in the first half of 2024. The decrease is attributed to higher capital overhead recoveries.

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:

For the three months ended June 30, 2025, net share-based compensation expense was $0.4 million, down from $0.7 million in the prior year comparative period. For the six months ended June 30, 2025, net share based compensation expense was $0.9 million, compared to $1.3 million in 2024. Stock option expense was determined using the Black-Scholes option pricing model, incorporating assumptions including share price, price volatility, and dividend yield. Recent grants have lower option values due to reduced share price volatility and the introduction of regular dividends.

The decline in current-year share-based compensation expense reflects the expensing of newly granted stock options with lower fair value, while higher-valued options from prior periods have already been amortized and recognized in previous years.

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FINANCE EXPENSE

The components of finance expenses are as follows:

The decrease in total finance expense from the prior year comparative periods is due to lower interest rates charged on the Company's debt, while the average outstanding debt balances throughout the quarter were comparable for both periods.

DEPLETION AND DEPRECIATION

The following table compares depletion and depreciation expense recorded in the reporting periods shown:

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 reserve base.

For the three months ended June 30, 2025, the Company recorded depletion and depreciation of $10.2 million or $12.30/boe, compared to $10.3 million or $11.91/boe in the prior year comparative period. For the six months ended June 30, 2025, the Company recorded depletion and depreciation of $20.1 million or $12.28/boe, compared to $20.9 million or $11.91/boe in the prior year comparative period. The decrease in depletion and depreciation expense is attributed to lower production volumes.

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:

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At June 30, 2025, the Company had 129,634,315 common shares, 9,456,982 stock options, 470,000 restricted share units, and 1,894,868 deferred share units outstanding. At the date of this MD&A, the Company had 130,282,860 common shares, 9,372,984 stock options, 470,000 restricted share units, and 1,907,748 deferred share units outstanding.

Dividends

The Company has a Dividend Reinvestment Plan (the "DRIP") that enables eligible shareholders to reinvest all or part of their cash dividends into additional common shares of the Company. Participation in the DRIP is optional. Eligible shareholders who elect to reinvest their cash dividends under the DRIP will receive shares from treasury at a 3% discount to the market price. During the three and six months ended June 30, 2025, the Company paid monthly dividends of $0.01 per common share totaling $3.8 million and $7.6 million, respectively. These amounts include the value of the common shares issued under the DRIP. During the three and six months ended June 30, 2025, the Company issued a total of 2,124,123 and 4,129,645 common shares, respectively, pursuant to the DRIP. As the Company's Dividend Reinvestment Plan commenced during December 2024, no shares were issued for the three and six months ended June 30, 2024.

Normal Course Issuer Bid ("NCIB")

On June 26, 2025, the Company announced the approval of its renewed NCIB by the Toronto Stock Exchange ("the TSX"). The 2025 NCIB allows the Company to purchase up to 6,448,237 common shares over a period of twelve months, and expires on June 29, 2026.

Purchases are made on the open market through the TSX or alternative Canadian trading platforms at the market price of such common shares. All common shares purchased under the NCIB are cancelled. The total cost paid, including commissions and fees, is first charged to share capital to the extent of the average carrying value of the Company's common shares and the excess paid is recorded to retained earnings and any shortfall is recorded to contributed surplus.

For the three and six months ended June 30, 2025, there were no share repurchases. During the three months ended June 30, 2024, the Company repurchased 50,500 shares for cancellation at an average price of $1.29 per share totaling $0.1 million. During the six months ended June 30, 2024, the Company repurchased 396,100 shares for cancellation at an average price of $1.30 per share totaling $0.5 million.

Restricted Share Unit ("RSU") Award Plan

The Company has a restricted share unit award plan in place whereby it may issue restricted share units to officers, employees and consultants of the Company. Each RSU entitles the participants to receive, at the Company's discretion, either shares of the Company issued from treasury or acquired on the TSX or cash equal to the fair market value of the equivalent number of shares of the Company. All RSUs unless otherwise determined by the Board, vest as to one-third (1/3) annually over three years from the grant date. At June 30, 2025, 470,000 RSUs were issued and outstanding (December 31, 2024 – 470,000).

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. At June 30, 2025 and the date of this MD&A, 1,894,868 and 1,907,748, respectively, DSUs were issued and outstanding (December 31, 2024 – 1,811,963). 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.

On each date that a dividend payment is made, holders of DSUs; are credited with additional DSU; the number of additional DSUs is calculated by dividing the dividends that would have been paid to such holder if the DSUs held at the record date of the cash dividend had been common shares, by the fair market value of the common shares on the date on which the dividends are paid on the common shares.

LIQUIDITY AND CAPITAL RESOURCES

At June 30, 2025, 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 June 30, 2025, the RLF was comprised of a $70.0 million operating facility payable on demand by the lender and has an interest rate of Canada Prime plus 2.5%. 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. During the three months ended June 30, 2025, the borrowing base of the RLF was increased from $60.0 million to $70.0 million. The next semi-annual review is scheduled for October 31, 2025.

At June 30, 2025 the Company had drawn $38.3 million against the RLF (December 31, 2024 – $32.7 million).

Second Lien Facility

At June 30, 2025 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, 2027) with a fixed interest rate of 11% per annum and can be repaid at the discretion of the Company. The Second Lien Facility is a related party transaction with a major shareholder who owns approximately 21% of the outstanding shares of the Company. The

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total interest paid during the three and six months ended June 30, 2025 to the major shareholder, related to the Second Lien facility, was $0.7 million and $1.4 million, respectively.

Financial Covenants

The Company's RLF is subject to certain financial covenants. The key financial covenant as at June 30, 2025 is summarized in the following table. At June 30, 2025 the Company is in compliance with all financial covenants.

Liquidity

The following are the contractual maturities of financial liabilities as at June 30, 2025:

At June 30, 2025, the Company had a working capital deficiency (excluding non-cash risk management assets and liabilities) of $43.8 million, primarily due to the $38.3 million drawn on the RLF, which is classified as a current liability. The RLF has a credit limit of $70 million and is payable upon demand, with the borrowings classified as current liabilities as of June 30, 2025.

The commitments for which the Company is responsible are as follows:

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, inflation 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. Petrus is also exposed to risks related to the imposition of tariffs or other trade related measures by the United States, Canada and other countries on one another.

For a more in-depth discussion of risk management, see notes 8 and 13 of the Company's June 30, 2025 condensed interim consolidated financial statements.

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CAPITAL EXPENDITURES

Capital expenditures (excluding acquisitions and dispositions) totaled $13.2 million in the second quarter of 2025, compared to $6.9 million in the prior year comparative period. The second quarter 2025 capital expenditures includes $4.0 million for drilling and $6.3 million for completions. Four gross (2.0 net) of the wells drilled and completed during the first half of 2025 were brought on production in July 2025 and as a result did not contribute to second quarter results.

The following table shows capital expenditures (excluding acquisitions and dispositions) for the reporting periods indicated. All capital is presented before decommissioning obligations.

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SUMMARY OF QUARTERLY RESULTS

(1) Non-GAAP measure. Refer to "Non-GAAP and Other Financial Measures".
(2) 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.

The oil and natural gas exploration and production industry is cyclical in nature. Petrus' financial position, results of operations and corporate netback are affected by commodity prices, exchange rates, Canadian commodity price differentials and production levels. Petrus' average quarterly production has decreased from 9,880 boe/d in the third quarter of 2023 to 9,155 boe/d in the second quarter of 2025.

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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. 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, 2024.

OTHER FINANCIAL INFORMATION

Material accounting policies

The Company's material 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, 2024.

New standards and interpretations

The Company has not adopted any new standards and interpretations for the period ended June 30, 2025.

In April 2024, the International Accounting Standards Board (the "IASB") issued IFRS 18 "Presentation and Disclosure in Financial Statements", which provides presentation and disclosure requirements for the primary financial statements and related notes, replacing IAS 1 "Presentation of Financial Statements". IFRS 18 introduces defined categories for income and expenses and requires disclosure of new defined subtotals, including operating profit. The new standard also requires additional notes for management performance measures and disclosure of certain expenses by nature. There are some associated changes to the statement of cash flows, including the starting point for the calculation of cash flows from operating activities and the categorization of interest and dividends. IFRS 18 is effective January 1, 2027, with early adoption permitted. The new standard is required to be adopted retrospectively. The Company is assessing the impact of IFRS 18 on the Company's consolidated financial statements.

In May, 2024, the IASB issued amendments to IFRS 9 "Financial Instruments" and IFRS 7 "Financial Instruments: Disclosures" to clarify the date of recognition and derecognition of financial assets and liabilities and provide further clarification on the classification of certain financial assets. The amendments are effective January 1, 2026 and are to be applied retrospectively. The Company is evaluating the impact that these amendments will have on the consolidated financial statements.

Internal Controls over Financial Reporting

The Company's Chief Executive Officer ("CEO") and Chief Financial Officer ("CFO") have designed, or caused to be designed under their supervision, disclosure controls and procedures to provide reasonable assurance that: (i) material information relating to the Company is made known to the Company's CEO and CFO by others, particularly during the period in which the annual and interim 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 Company's CEO and CFO have designed, or caused to be designed under their supervision, internal controls over financial reporting to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in compliance with IFRS. The Company is required to disclose herein any change in the Company's internal controls over financial reporting that occurred during the period beginning on April 1, 2025 and ending on June 30, 2025 that has materially affected, or is reasonably likely to materially affect, the Company's internal controls over financial reporting. No changes in the Company's internal controls over financial reporting were identified during such period that have materially affected, or are reasonably likely to materially affect, the Company's internal controls over financial reporting.

It should be noted that a control system, including the Company's disclosure and internal controls and procedures, no matter how well conceived, can provide only reasonable, but not absolute assurance that the objectives of the control system will be met and it should not be expected that the disclosure and internal controls and procedures 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.

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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 sales. Operating netback is calculated as oil and natural gas sales less royalty expenses, operating expenses and transportation expenses. See below and under "Summary of Quarterly Results" for a reconciliation of operating netback to oil and natural gas sales.

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 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 and decommissioning expenditures, plus or minus other income (expense) and the realized gain (loss) on financial derivatives. See below and under "Summary of Quarterly Results" for a reconciliation of funds flow and corporate netback to oil and natural gas sales.

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.

| | Three months ended
June 30, 2025 | | Three months ended
June 30, 2024 | | Six months ended
June 30, 2025 | | Six months ended
June 30, 2024 | |
| --- | --- | --- | --- | --- | --- | --- | --- | --- |
| | $000s | $/boe | $000s | $/boe | $000s | $/boe | $000s | $/boe |
| Oil and natural gas sales | 21,506 | 25.82 | 23,150 | 26.86 | 45,136 | 27.58 | 51,189 | 29.22 |
| Royalty expense | (2,010) | (2.41) | (3,305) | (3.83) | (4,713) | (2.88) | (6,766) | (3.86) |
| Net oil and natural gas revenue | 19,496 | 23.41 | 19,845 | 23.03 | 40,423 | 24.70 | 44,423 | 25.36 |
| Transportation expense | (1,438) | (1.73) | (1,259) | (1.46) | (2,762) | (1.69) | (2,874) | (1.64) |
| Operating expense | (5,078) | (6.10) | (4,271) | (4.96) | (10,507) | (6.42) | (10,289) | (5.87) |
| Operating netback | 12,980 | 15.58 | 14,315 | 16.61 | 27,154 | 16.59 | 31,260 | 17.85 |
| Realized gain (loss) on financial derivatives | 1,923 | 2.31 | (307) | (0.36) | 2,835 | 1.73 | 2,276 | 1.30 |
| Other income (expense) | (57) | (0.07) | 40 | 0.05 | (41) | (0.02) | 88 | 0.05 |
| General & administrative expense | (797) | (0.96) | (1,152) | (1.34) | (1,930) | (1.18) | (2,330) | (1.33) |
| Cash finance expense | (1,473) | (1.77) | (1,650) | (1.91) | (2,824) | (1.73) | (3,231) | (1.84) |
| Decommissioning expenditures | (228) | (0.27) | (618) | (0.72) | (380) | (0.23) | (1,162) | (0.66) |
| Funds flow and corporate netback | 12,348 | 14.82 | 10,628 | 12.33 | 24,814 | 15.16 | 26,901 | 15.37 |

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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 and decommissioning 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.

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 year ended December 31, 2024. 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: that the Company utilizes financial derivative contracts and physical commodity contracts to mitigate commodity price risk and provide stability and sustainability to Company's economic returns, funds flow, and dividend payments and capital development plan; that the Company's risk management contracts provide protection from

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significant changes in crude oil and natural gas commodity prices for 2025, 2026 and 2027; that the Company endeavors to hedge approximately 60% of its forecasted production for up to 12 months forward, and approximately 25% of its forecasted production for 12 to 24 months forward; that the Company's hedging strategy is intended to provide stability and sustainability to the Company's economic returns, funds flow and capital development plan; the Company's belief that the decrease in royalties primarily reflects increased production from Crown Royalty Holiday eligible wells, as well as a greater contribution from wells subject to lower gross overriding royalties; and that the Company does not intend 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 risk that (i) the tariffs that are currently in effect on goods exported from or imported into Canada continue in effect for an extended period of time, the tariffs that have been threatened are implemented, that tariffs that are currently suspended are reactivated, the rate or scope of tariffs are increased, or new tariffs are imposed, including on oil and natural gas, (ii) the U.S. and/or Canada imposes any other form of tax, restriction or prohibition on the import or export of products from one country to the other, including on oil and natural gas, and (iii) the tariffs imposed or threatened to be imposed by the U.S. on other countries and retaliatory tariffs imposed or threatened to be imposed by other countries on the U.S., will trigger a broader global trade war which could have a material adverse effect on the Canadian, U.S. and global economies, and by extension the Canadian oil and natural gas industry and the Company, including by decreasing demand for (and the price of) oil and natural gas, disrupting supply chains, increasing costs, causing volatility in global financial markets, and limiting access to financing; 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; and/or increase our costs, decrease our production, or otherwise impede our ability to operate our business; extreme weather events, such as wild fires, floods, drought and extreme cold or warm temperatures, each of which could result in substantial damage to our assets and/or increase our costs, decrease our production, or otherwise impede our ability to operate our business; stock market volatility; ability to access sufficient capital from internal and external sources; that the amount of dividends that we pay may be reduced or suspended entirely; that we reduce or suspend the repurchase of shares under our NCIB; 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: duration and impact of tariffs that are currently in effect on goods exported from or imported into Canada, and that other than the tariffs that are currently in effect, neither the U.S. nor Canada (i) increases the rate or scope of such tariffs, reenacts tariffs that are currently suspended, or imposes new tariffs, on the import of goods from one country to the other, including on oil and natural gas, and/or (ii) imposes any other form of tax, restriction or prohibition on the import or export of products from one country to the other, including on oil and natural gas; the amount of dividends that we will pay the number of shares that we will repurchase under our NCIB; 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 costs and 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 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.

Production and Product Type Information

References to crude oil (or oil), natural gas liquids ("NGLs"), natural gas and average daily production in this document refer to the light and

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medium crude oil, conventional natural gas, and NGLs product types, as applicable, as defined in National Instrument 51-101 ("NI 51-101"), except as noted below. NI 51-101 includes condensate within the NGLs product type. The Company has disclosed condensate as combined with crude oil and separately from other NGLs since the price of condensate as compared to other NGLs is currently significantly higher and the Company believes that this crude oil and condensate presentation provides a more accurate description of its operations and results therefrom. Crude oil therefore refers to light oil, medium oil, and condensate. NGLs refers to ethane, propane, butane and pentane combined. Natural gas refers to conventional natural gas.

Dividend Advisory

The Company's future dividends, if any, and the level thereof is uncertain. Any decision to pay dividends on the common shares (including the actual amount, the declaration date, the record date and the payment date in connection therewith) will be subject to the discretion of the Board of Directors and may depend on a variety of factors, including, without limitation the Company's business performance, financial condition, financial requirements, growth plans, expected capital requirements and other conditions existing at such future time including, without limitation, contractual restrictions and satisfaction of the solvency tests imposed on the Company under applicable corporate law. There can be no assurance that the Company will pay dividends in the future.

Abbreviations

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