Petrus Resources Ltd. — Management Reports 2025

May 8, 2025

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 months ended March 31, 2025. This MD&A is dated May 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 months ended March 31, 2025 and 2024. 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 with International Financial Reporting Standards ("IFRS Accounting Standards") as issued by the International Accounting Standards Board ("IFRS Accounting Standards"). 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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PetrusResources

SELECTED FINANCIAL INFORMATION

OPERATIONS	Three months ended Mar. 31, 2025	Three months ended Mar. 31, 2024	Three months ended Dec. 31, 2024	Three months ended Sept. 30, 2024	Three months ended Jun. 30, 2024
Average Production
Natural gas (mcf/d)	35,689	40,174	36,178	37,368	38,908
Oil and condensate^{(1)} (bbl/d)	1,202	1,529	1,226	1,522	1,322
NGLs (bbl/d)	1,777	1,557	1,810	1,464	1,664
Total (boe/d)	8,929	9,783	9,066	9,215	9,471
Total (boe)^{(1)}	803,498	890,267	834,111	847,760	861,838
Liquids weighting	33 %	32 %	33 %	32 %	32 %
Realized Prices
Natural gas ($/mcf)	2.25	2.54	1.61	0.80	1.41
Oil and condensate^{(1)} ($/bbl)	92.73	90.38	93.60	90.80	103.77
NGLs ($/bbl)	39.54	43.09	36.90	36.81	37.25
Total realized price ($/boe)	29.35	31.42	26.45	24.07	26.81
Royalty income	0.06	0.07	0.03	0.05	0.05
Royalty expense	(3.36)	(3.89)	(3.85)	(3.06)	(3.83)
Net oil and natural gas revenue ($/boe)	26.05	27.60	22.63	21.06	23.03
Operating expense	(6.76)	(6.76)	(5.89)	(6.10)	(4.96)
Transportation expense	(1.65)	(1.81)	(1.44)	(1.46)	(1.46)
Operating netback^{(2)} ($/boe)	17.64	19.03	15.30	13.50	16.61
Realized gain (loss) on financial derivatives	1.14	2.90	3.04	2.49	(0.36)
Other income (cash)	0.02	0.05	1.19	0.09	0.05
General & administrative expense	(1.41)	(1.32)	(2.10)	(1.43)	(1.34)
Cash finance expense	(1.68)	(1.78)	(1.83)	(1.95)	(1.91)
Decommissioning expenditures	(0.19)	(0.61)	(0.61)	(0.12)	(0.72)
Funds flow & corporate netback ($/boe)^{(2)}	15.52	18.27	14.99	12.58	12.33
FINANCIAL (000s except $ per share)	Three months ended Mar. 31, 2025	Three months ended Mar. 31, 2024	Three months ended Dec. 31, 2024	Three months ended Sept. 30, 2024	Three months ended Jun. 30, 2024
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Oil and natural gas sales	23,630	28,039	22,085	20,446	23,150
Net income (loss)	(3,088)	(5,333)	(4,004)	5,302	2,789
Net income (loss) per share
Basic	(0.02)	(0.04)	(0.03)	0.04	0.02
Fully diluted	(0.02)	(0.04)	(0.03)	0.04	0.02
Funds flow^{(2)}	12,467	16,272	12,493	10,665	10,628
Funds flow per share^{(2)}
Basic	0.10	0.13	0.10	0.09	0.09
Fully diluted	0.10	0.13	0.10	0.08	0.08
Capital expenditures	17,279	12,343	7,705	4,859	6,907
Weighted average shares outstanding
Basic	126,043	124,299	124,497	124,372	124,290
Fully diluted	126,043	124,299	124,497	126,686	126,559
As at period end
Common shares outstanding
Basic	127,469	124,259	125,113	124,372	124,372
Fully diluted	138,501	134,484	134,919	134,952	134,919
Total assets	427,955	427,574	420,124	421,196	419,584
Non-current liabilities	68,176	59,995	65,475	62,869	59,511
Net debt^{(2)}	66,009	63,114	60,080	60,423	61,848

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

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PetrusResources

RESULTS OF OPERATIONS

FINANCIAL AND OPERATIONAL RESULTS OF OIL AND NATURAL GAS ACTIVITIES

	Three months ended Mar. 31, 2025	Three months ended Mar. 31, 2024	Three months ended Dec. 31, 2024	Three months ended Sept. 30, 2024	Three months ended Jun. 30, 2024
Average production
Natural gas (mcf/d)	35,689	40,174	36,178	37,368	38,908
Oil and condensate(1) (bbl/d)	1,202	1,529	1,226	1,522	1,322
NGLs (bbl/d)	1,777	1,557	1,810	1,464	1,664
Total (boe/d)(1)	8,929	9,783	9,066	9,215	9,471
Total (boe)(1)	803,498	890,267	834,111	847,760	861,838
Sales ($000s)
Natural gas	7,225	9,290	5,357	2,734	4,984
Oil and condensate(1)	10,028	12,579	10,561	12,714	12,483
NGLs	6,326	6,107	6,144	4,958	5,639
Royalty revenue	51	63	23	40	44
Oil and natural gas sales	23,630	28,039	22,085	20,446	23,150
Average realized prices
Natural gas ($/mcf)	2.25	2.54	1.61	0.80	1.41
Oil and condensate(1) ($/bbl)	92.73	90.38	93.60	90.80	103.77
NGLs ($/bbl)	39.54	43.09	36.90	36.81	37.25
Total realized price ($/boe)	29.35	31.42	26.45	24.07	26.81
Hedging gain/(loss) ($/boe)	1.14	2.90	3.04	2.49	(0.36)
Total price including hedging ($/boe)	30.49	34.32	29.49	26.56	26.45
Average benchmark prices	Three months ended Mar. 31, 2025	Three months ended Mar. 31, 2024	Three months ended Dec. 31, 2024	Three months ended Sept. 30, 2024	Three months ended Jun. 30, 2024
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Natural gas
AECO 5A (C$/GJ)	2.05	2.36	1.40	0.65	1.12
AECO 7A (C$/GJ)	1.92	1.94	1.38	0.77	1.36
Crude oil
Mixed Sweet Blend Edm (C$/bbl)	94.89	94.79	92.87	98.48	105.97
WTI (US$/bbl)	71.42	76.96	69.79	75.09	80.57
Foreign exchange
US$/C$	0.70	0.74	0.72	0.73	0.73

(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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PetrusResources

FUNDS FLOW AND NET LOSS

Petrus generated funds flow of $12.5 million in the first quarter of 2025 compared to $16.3 million in the first quarter of 2024. The 23% decrease is primarily due to a 9% decline in production combined with a 7% decrease in realized commodity prices.

Petrus reported a net loss of $3.1 million in the first quarter of 2025, compared to a net loss of $5.3 million in the first quarter of 2024. The net loss in the first quarter of 2025 is primarily due to the non-cash unrealized hedging loss of $5.7 million recorded during the quarter. The unrealized hedging loss is a non-cash accounting mark-to-market adjustment mainly due to changes in the WTI benchmark pricing as at March 31, 2025 compared with the pricing for Petrus's crude oil swaps.

($000s except per share)	Three months ended March 31, 2025	Three months ended March 31, 2024
Funds flow	12,467	16,272
Funds flow per share - basic	0.10	0.13
Funds flow per share - fully diluted	0.10	0.13
Net loss	(3,088)	(5,333)
Net loss per share - basic	(0.02)	(0.04)
Net loss per share - fully diluted	(0.02)	(0.04)
Common shares outstanding (000s)
Basic	127,469	124,259
Fully diluted	138,501	134,484
Weighted average shares outstanding (000s)
Basic	126,043	124,299
Fully diluted	126,043	124,299

OIL AND NATURAL GAS SALES

First quarter oil and natural gas sales in 2025 were $23.6 million compared to $28.0 million in the first quarter of 2024. The 16% decrease is primarily due to a 9% decline in production combined with a 7% decrease in realized commodity prices.

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

Oil and Natural Gas Sales ($000s)	Three months ended March 31, 2025	Three months ended March 31, 2024	% Change
Natural gas	7,225	9,290	(22)%
Crude oil and condensate(1)	10,028	12,579	(20)%
Natural gas liquids	6,326	6,107	4 %
Royalty income	51	63	(19)%
Total oil and natural gas sales	23,630	28,039	(16)%

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

	Three months ended March 31, 2025	Three months ended March 31, 2024	% Change
Average production
Natural gas (mcf/d)	35,689	40,174	(11)%
Oil and condensate(1)(bbl/d)	1,202	1,529	(21)%
NGLs (bbl/d)	1,777	1,557	14 %
Total (boe/d)	8,929	9,783	(9)%
Total (boe)	803,498	890,267	(10)%
Liquids weighting	33 %	32 %	3 %

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

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PetrusResources

First quarter average production by area was as follows:

For the three months ended March 31, 2025	Ferrier	Foothills	Central Alberta	Total
Natural gas (mcf/d)	30,469	578	4,642	35,689
Oil and condensate (bbl/d)	882	65	255	1,202
NGLs (bbl/d)	1,630	7	140	1,777
Total (boe/d)	7,591	168	1,170	8,929

First quarter average production was 8,929 boe/d, essentially unchanged from 9,066 boe/d in the fourth quarter of 2024. With the completion of the North Ferrier to Ferrier pipeline, Petrus has consolidated the two areas into a single core Ferrier operating area. The following table provides the average benchmark commodity prices and the Company's average realized commodity prices (before hedging/ risk management gains/losses):

	Three months ended March 31, 2025	Three months ended March 31, 2024	% Change
Average benchmark prices
Natural gas
AECO 5A (C$/GJ)	2.05	2.36	(13)%
AECO 7A (C$/GJ)	1.92	1.94	(1)%
Crude oil
Mixed Sweet Blend Edm (C$/bbl)	94.89	94.79	— %
WTI (US$/bbl)	71.42	76.96	(7)%
Average realized prices
Natural gas ($/mcf)	2.25	2.54	(11)%
Oil and condensate ($/bbl)	92.73	90.38	3 %
NGLs ($/bbl)	39.54	43.09	(8)%
Total average realized price	29.35	31.42	(7)%

Natural gas

Natural gas sales for the three months ended March 31, 2025 decreased by 22% to $7.2 million, compared to sales of $9.3 million in the prior year comparative period. This decrease is primarily due to lower gas prices and lower production, both of which were down 11% year over year. Natural gas accounted for 31% of total oil and gas sales for the quarter compared to 33% in the first quarter of 2024.

Crude oil and condensate

Oil and condensate sales for the three months ended March 31, 2025 were down 20% to $10.0 million, compared to sales of $12.6 million in the prior year comparative period. This decrease is primarily due to a 21% decline in production. Oil and condensate accounted for 43% of total oil and gas sales for the quarter compared to 45% in the first quarter of 2024.

Natural gas liquids (NGLs)

NGL sales (excluding condensate) for the three months ended March 31, 2025 increased by 4% to $6.3 million, compared to sales of $6.1 million in the prior year comparative period. The increase is primarily due to higher production, up 14% from the prior comparative period, partially offset by an 8% decrease in pricing. The higher NGL volumes is due to strategic efforts to increase NGL recoveries. NGLs accounted for 27% of total oil and natural gas sales for the quarter compared to 22% in the first quarter of 2024.

The Company's NGL production mix (excluding condensate) 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.

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PetrusResources

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 ($000s)	Three months ended March 31, 2025	Three months ended March 31, 2024
Total royalties	2,703	3,461
Percent of production revenue	11.5 %	12.4 %
Royalties expense ($/boe)	3.36	3.89

First quarter royalty expense decreased from $3.5 million in 2024 to $2.7 million in 2025 primarily due to lower oil and natural gas sales. Royalties as a percentage of oil and natural gas sales and on a per boe basis also declined, driven by lower commodity prices.

As royalties are sensitive to both commodity prices and well production, the corporate royalty rates will fluctuate with commodity prices, gas cost allowance, well production rates, production decline of existing wells, performance and geographical location of new wells drilled.

RISK MANAGEMENT

The Company utilizes financial derivative contracts to mitigate commodity price risk and provide stability and sustainability to the Company's economic returns, funds flow, and 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). The unrealized gain (loss) is recorded to demonstrate the change in fair value of the outstanding 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:

Net Gain (Loss) on Financial Derivatives ($000s)	Three months ended March 31, 2025	Three months ended March 31, 2024
Realized hedging gain	912	2,583
Unrealized hedging loss	(5,710)	(11,491)
Net loss on financial derivatives	(4,798)	(8,908)

In the first quarter, the Company recognized a realized hedging gain of $0.9 million, compared to $2.6 million in the first quarter of 2024. The realized gain is due to lower commodity prices relative to the respective contracts outstanding that were settled during the quarter. The realized gain in the first quarter of 2025 increased the Company's total price including hedging by $1.14/boe, compared to an increase of $2.90/boe in the first quarter of 2024.

During the first quarter of 2025, the Company recognized an unrealized hedging loss of $5.7 million compared to an unrealized loss of $11.5 million in the first quarter of 2024. The loss during the quarter represents the change in the unrealized risk management net asset or liability position as a result of the change in value of existing hedge contracts due to the change in commodity prices from the previous quarter.

The Company's risk management contracts provide protection from significant changes in crude oil and natural gas commodity prices out to 2027. The Company is targeting 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 payments and capital development plans. A summary of Petrus' risk management contracts as at March 31, 2025 is included in note 8 of the Company's consolidated interim financial statements as at and for the three months ended March 31, 2025.

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The following table summarizes the average cap and floor prices for the oil and natural gas contracts outstanding as at the date of this report:

	2025				2026					2027
	May/June	Q3	Q4	Avg.(1)	Q1	Q2	Q3	Q4	Avg.(1)	Q1	Q2	Q3	Q4	Avg.(1)
Oil hedged (bbl/d)	1,600	1,500	1,400	1,487	1,400	1,200	800	500	975	—	—	—	—	—
Avg. WTI cap price ($C/bbl)	95.04	95.26	94.05	94.75	91.24	91.27	90.18	89.14	90.76	—	—	—	—	—
Avg. WTI floor price ($C/bbl)	95.04	95.26	94.05	94.75	91.24	91.27	90.18	89.14	90.76	—	—	—	—	—
Natural gas hedged (GJ/d)	22,000	22,000	19,333	21,000	18,000	13,000	13,000	7,000	12,750	4,000	—	—	—	1,000
Avg. AECO 7A cap price ($C/GJ)	2.49	2.49	3.04	2.70	3.31	2.54	2.54	3.05	2.88	3.31	—	—	—	3.31
Avg. AECO 7A floor price ($C/GJ)	2.42	2.42	2.99	2.63	3.27	2.54	2.54	3.05	2.87	3.31	—	—	—	3.31

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

OPERATING EXPENSE

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

Operating Expense ($000s)	Three months ended March 31, 2025	Three months ended March 31, 2024
Fixed and variable operating expense	4,376	5,401
Processing, gathering and compression charges	1,356	951
Total gross operating expense	5,732	6,352
Overhead recoveries	(303)	(334)
Total net operating expense	5,429	6,018
Operating expense, net ($/boe)	6.76	6.76

For the three months ended March 31, 2025, net operating expense totaled $5.4 million, a 10% decrease from $6.0 million during the prior year comparative period. Total operating expense is lower in the first quarter of 2025 due to lower production. On a per boe basis, net operating expense was $6.76 boe/d in the first quarter of 2025 unchanged from the same period in 2024. The higher processing, gathering and compression charges is due to strategic efforts to increase NGL recoveries, resulting in higher NGL volumes this quarter.

TRANSPORTATION EXPENSE

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

Transportation Expense ($000s)	Three months ended March 31, 2025	Three months ended March 31, 2024
Transportation expense	1,324	1,615
Transportation expense ($/boe)	1.65	1.81

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 March 31, 2025 transportation expense was $1.3 million or $1.65/boe compared to $1.6 million or $1.81/boe in the prior year comparative period. The decrease in total transportation expense is due to lower production. On a per boe basis, transportation expense decreased due to the lower trucking and condensate hauling costs in comparison to the prior year period.

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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:

General and Administrative Expense ($000s)	Three months ended March 31, 2025	Three months ended March 31, 2024
Personnel, consultants and directors	1,126	859
Administrative expenses	470	476
Regulatory and professional expenses	221	417
Gross general and administrative expense	1,817	1,752
Capitalized general and administrative expense	(293)	(252)
Overhead recoveries	(391)	(322)
General and administrative expense	1,133	1,178
General and administrative expense ($/boe)	1.41	1.32

For the three months ended March 31, 2025, gross G&A expense was $1.8 million which was consistent with the prior year comparative period.

First quarter net G&A expense in 2025 was $1.1 million or $1.41/boe, compared to $1.2 million or $1.32/boe in the first quarter of 2024. The net increase per boe is attributed to lower production in the current quarter.

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)	Three months ended March 31, 2025	Three months ended March 31, 2024
Gross share-based compensation expense	699	759
Capitalized share-based compensation expense	(210)	(199)
Share-based compensation expense	489	560

For the three months ended March 31, 2025, net share-based compensation expense was $0.5 million, which is 13% lower than the $0.6 million in the prior year comparative period. This reduction is due to lower stock price volatility estimates applied in the Black-Scholes option pricing model for recent grants, compared to the higher volatility estimates used for earlier grants.

FINANCE EXPENSE

The following table illustrates the Company's finance expense which includes cash and non-cash expenses:

$000s	Three months ended March 31, 2025	Three months ended March 31, 2024
Cash:
Interest	1,208	1,449
Finance fees	143	132
Total cash finance expenses	1,351	1,581
Non-cash:
Deferred financing costs	88	80
Accretion on decommissioning obligations	338	284
Total non-cash finance expenses	426	364
Total finance expenses	1,777	1,945

First quarter total finance expense was $1.8 million in 2025, comprised of $0.3 million of non-cash accretion of its decommissioning liabilities, $1.2 million of cash interest expense, $0.1 million of finance fees, and $0.1 million of deferred financing fee amortization (related to the Company's revolving loan facility ("RLF")). In the first quarter of 2024, the Company incurred total finance expense of $1.9 million,

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comprised of $0.3 million in non-cash accretion of its decommissioning liabilities, $1.4 million cash interest expense, $0.1 million of finance fees, and $0.1 million of deferred financing fee amortization. The 9% decrease in finance expense from the prior year comparative period is due to the decrease in interest rate on the RLF (as a result of the decreases to the Canada Prime rate by the Bank of Canada).

DEPLETION AND DEPRECIATION

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

Depletion and Depreciation Expense ($000s)	Three months ended March 31, 2025	Three months ended March 31, 2024
Depletion and depreciation expense	9,955	10,611
Depletion and depreciation expense ($/boe)	12.39	11.92

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 costs. Such costs are segregated and depleted on an area by area basis relative to the respective underlying proved plus probable reserve base.

For the three months ended March 31, 2025, the Company recorded depletion and depreciation expense of $10.0 million or $12.39/boe, compared to $10.6 million or $11.92/boe in the prior year comparative period. The decrease in depletion and depreciation expense is mainly 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:

Share Capital (000s)	Three months ended March 31, 2025	Three months ended March 31, 2024
Weighted average common shares outstanding
Basic	126,043	124,299
Fully diluted	126,043	124,299
Common shares outstanding
Basic	127,469	124,259
Fully diluted	138,501	134,484
Stock options outstanding	8,710	8,527
Restricted share units outstanding	470	—
Deferred share units outstanding	1,852	1,697

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At March 31, 2025, the Company had 127,469,302 common shares, 8,709,886 stock options, 470,000 restricted share units, and 1,852,255 deferred share units outstanding. As at the date of this MD&A, the Company had 128,207,712 common shares, 8,709,886 stock options, 470,000 restricted share units and 1,867,009 deferred share units outstanding.

Dividends

During the three months ended March 31, 2025, the Company paid monthly dividends of $0.01 per common share totaling $3.8 million. 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 common allowing for the issuance of common shares from treasury at a 3% discount to the market price. During the three months ended March 31, 2025, the Company issued a total of 2,005,522 common shares pursuant to the DRIP.

Normal Course Issuer Bid ("NCIB")

On June 25, 2024, the Company announced the approval of its renewed NCIB by the Toronto Stock Exchange ("the TSX"). The NCIB allows the Company to purchase up to 6,218,596 common shares over a period of twelve months (expiring no later than June 27, 2025).

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.

During the three months ended March 31, 2025 there were no share repurchases (three months ended March 31, 2024 - 345,600).

Restricted Share Unit Award ("RSU") 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 common 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 common shares of the Company. All RSUs, unless otherwise determined by the Board of Directors, vest as to one-third (1/3) annually over three years from the grant date. At March 31, 2025, 470,000 RSUs were issued and outstanding (December 31, 2024 – 470,000).

Deferred Share Units ("DSU") Plan

The Company has a deferred share unit plan in place whereby it may issue deferred share units ("DSUs") to directors of the Company. At March 31, 2025 1,852,255 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 DSUs; 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 March 31, 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 March 31, 2025, the RLF was comprised of a $60 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 lender as well as other factors. The next semi-annual review is due on October 31, 2025.

At March 31, 2025 the Company had drawn $30.7 million against the RLF (December 31, 2024 – $32.7 million). Subsequent to March 31, 2025, as part of the semi-annual review, the borrowing base was increased from $60 million to $70 million.

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Second Lien Facility

At March 31, 2025 the Company had $25 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 total interest paid during the three months ended March 31, 2025 was $0.7 million (three months ended March 31, 2024 - $0.7 million).

Financial Covenant

The key financial covenant under the Company's RLF as at March 31, 2025 is highlighted in the following table. At March 31, 2025 the Company is in compliance with all financial covenants.

Financial Covenant Description	Required Ratio	As at March 31, 2025
Working Capital Ratio	Over 1.00	1.66

Liquidity

The following are the contractual maturities of financial liabilities as at March 31, 2025:

$000s	Total	< 1 year	1-5 years
Accounts payable and accrued liabilities	25,415	25,415	—
Risk management liability	3,117	1,779	1,338
Bank indebtedness	608	608	—
Revolving loan facility	34,772	34,772	—
Lease obligations	1,082	164	918
Long term debt	31,638	2,750	28,888
Total	96,632	65,488	31,144

At March 31, 2025, the Company had a working capital deficiency (excluding non-cash risk management assets and liabilities) of $41.0 million, primarily due to $30.7 million drawn on the RLF, which is classified as a current liability. The RLF has a credit limit of $60 million and is payable upon demand, with borrowings classified as current liabilities as of March 31, 2025. Current liabilities also includes $25.4 million in current accounts payable as a result of the capital activity during the first quarter of 2025. The Company expects the working capital deficiency to diminish over the next 12 months as the RLF is paid down by the cash flow from operations.

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

$000s	Total	< 1 year	1-5 years	> 5 years
Firm service transportation	6,723	3,197	3,526	—

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 March 31, 2025 condensed interim consolidated financial statements.

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CAPITAL EXPENDITURES

Capital expenditures totaled $17.3 million in the first quarter of 2025, compared to $12.3 million in the prior year comparative period. Current quarter expenditures include $7.2 million for drilling and $3.7 million for completions. Due to the timing of activity, these wells contributed limited production during the quarter. Petrus also constructed a pipeline to connect its remaining North Ferrier properties to the Ferrier processing facility, further consolidating its infrastructure in the area.

The following table shows capital expenditures for the reporting periods indicated. All capital is presented before decommissioning obligations.

Capital Expenditures ($000s)	Three months ended March 31, 2025	Three months ended March 31, 2024
Drill and complete	10,911	9,519
Pipelines	5,178	980
Oil and gas equipment	756	1,264
Office	141	6
Capitalized general and administrative expense	293	574
Total capital expenditures	17,279	12,343
Gross (net) wells spud	7 (4.1)	10 (5.3)

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SUMMARY OF QUARTERLY RESULTS

($000s unless otherwise noted)	Mar. 31, 2025	Dec. 31, 2024	Sept. 30, 2024	Jun. 30, 2024	Mar. 31, 2024	Dec. 31, 2023	Sept. 30, 2023	Jun. 30, 2023
Average Production
Natural gas (mcf/d)	35,689	36,178	37,368	38,908	40,174	39,891	42,045	44,010
Oil and condensate^{(2)}(bbl/d)	1,202	1,226	1,522	1,322	1,529	1,218	1,316	1,670
NGLs (bbl/d)	1,777	1,810	1,465	1,664	1,557	1,607	1,556	1,486
Total (boe/d)	8,929	9,066	9,215	9,471	9,783	9,474	9,880	10,492
Total (boe)^{(3)}	803,498	834,111	847,760	861,838	890,267	871,567	908,985	954,738
Financial Results
Oil and natural gas sales	23,630	22,085	20,446	23,150	28,039	26,747	28,273	29,266
Royalty expense	(2,703)	(3,212)	(2,593)	(3,305)	(3,461)	(4,167)	(3,061)	(3,492)
Gain (loss) on risk management activities	—	—	—	—	—	—	—	32
Net oil and natural gas revenue	20,927	18,873	17,853	19,845	24,578	22,580	25,212	25,806
Transportation expense	(1,324)	(1,203)	(1,239)	(1,259)	(1,615)	(1,271)	(1,401)	(1,341)
Operating expense	(5,429)	(4,915)	(5,172)	(4,271)	(6,018)	(4,419)	(6,086)	(5,566)
Operating netback^{(1)}	14,174	12,755	11,442	14,315	16,945	16,890	17,725	18,899
Realized gain (loss) on financial derivatives	912	2,539	2,115	(307)	2,583	1,737	1,102	3,398
Other income (cash)	17	991	77	40	48	(161)	34	37
General and administrative expense	(1,133)	(1,752)	(1,209)	(1,152)	(1,178)	(319)	(1,158)	(1,476)
Cash finance expense	(1,351)	(1,530)	(1,657)	(1,650)	(1,581)	(1,246)	(1,148)	(1,269)
Decommissioning expenditures	(152)	(510)	(103)	(618)	(545)	(376)	(312)	(549)
Corporate netback and funds flow^{(1)}	12,467	12,493	10,665	10,628	16,272	16,525	16,243	19,040
Oil and natural gas sales	23,630	22,085	20,446	23,150	28,039	26,747	28,273	29,266
Per share - basic	0.19	0.18	0.16	0.19	0.23	0.22	0.23	0.24
Per share - fully diluted	0.19	0.18	0.16	0.18	0.23	0.21	0.23	0.23
Net income (loss)	(3,088)	(4,004)	5,302	2,789	(5,333)	39,708	(11,293)	5,043
Per share - basic	(0.02)	(0.03)	0.04	0.02	(0.04)	0.32	(0.09)	0.04
Per share - fully diluted	(0.02)	(0.03)	0.04	0.02	(0.04)	0.32	(0.09)	0.04
Common shares outstanding (000s)
Basic	127,469	125,113	124,372	124,372	124,259	124,266	123,867	123,849
Fully diluted	138,501	134,919	134,952	134,919	134,484	134,542	134,436	134,423
Weighted average shares outstanding (000s)
Basic	126,043	124,497	124,372	124,290	124,299	123,812	123,743	123,752
Fully diluted	126,043	124,497	126,686	126,559	124,299	124,840	123,743	127,040
Total assets	427,955	420,124	421,196	419,584	427,574	437,842	380,100	383,231

(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 10,492 boe/d in the second quarter of 2023 to 8,929 boe/d in the first 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 Accounting Standards

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 Control 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 accordance 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 January 1, 2025 and ending on March 31, 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), "net debt" and "net debt to annualized funds flow ratio". 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

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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 sales. Operating netback is calculated as oil and natural gas sales less royalty expenses, operating expenses and transportation expenses, plus or minus the gain (loss) on risk management activities. 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, less cash finance expense, less decommissioning expenditures, plus or minus other income (cash) and plus or minus the net realized gain (loss) on financial derivatives. See below and under "Summary of Quarterly Results" for a reconciliation of funds flow and corporate netback to oil and natural gas 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 March 31, 2025	Three months ended Dec. 31, 2024	Three months ended Sept. 30, 2024	Three months ended Jun. 30, 2024	Three months ended March 31, 2024
	$000s	$/boe	$000s	$/boe	$000s	$/boe	$000s	$/boe	$000s	$/boe
Oil and natural gas sales	23,630	29.41	22,085	26.48	20,446	24.12	23,150	26.86	28,039	31.50
Royalty expense	(2,703)	(3.36)	(3,212)	(3.85)	(2,593)	(3.06)	(3,305)	(3.83)	(3,461)	(3.89)
Net oil and natural gas revenue	20,927	26.05	18,873	22.63	17,853	21.06	19,845	23.03	24,578	27.61
Transportation expense	(1,324)	(1.65)	(1,203)	(1.44)	(1,239)	(1.46)	(1,259)	(1.46)	(1,615)	(1.81)
Operating expense	(5,429)	(6.76)	(4,915)	(5.89)	(5,172)	(6.10)	(4,271)	(4.96)	(6,018)	(6.76)
Operating netback	14,174	17.64	12,755	15.30	11,442	13.50	14,315	16.61	16,945	19.03
Realized gain (loss) on financial derivatives	912	1.14	2,539	3.04	2,115	2.49	(307)	(0.36)	2,583	2.90
Other income(1)	17	0.02	991	1.19	77	0.09	40	0.05	48	0.05
General & administrative expense	(1,133)	(1.41)	(1,752)	(2.10)	(1,209)	(1.43)	(1,152)	(1.34)	(1,178)	(1.32)
Cash finance expense	(1,351)	(1.68)	(1,530)	(1.83)	(1,657)	(1.95)	(1,650)	(1.91)	(1,581)	(1.78)
Decommissioning expenditures	(152)	(0.19)	(510)	(0.61)	(103)	(0.12)	(618)	(0.72)	(545)	(0.61)
Funds flow and corporate netback	12,467	15.52	12,493	14.99	10,665	12.58	10,628	12.33	16,272	18.27

(1) Excludes non-cash government grant related to decommissioning expenditures.

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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.

($000s)	As at March 31, 2025	As at Dec. 31, 2024	As at Sept. 30, 2024	As at Jun. 30, 2024	As at March 31, 2024
Long-term debt	25,000	25,000	25,000	25,000	25,000
Current assets	(15,763)	(17,583)	(20,258)	(16,333)	(21,081)
Current liabilities	59,788	51,268	48,458	52,379	61,099
Current financial derivatives	(1,779)	2,632	7,690	1,276	(716)
Current portion of lease obligation	(164)	(164)	(230)	(237)	(263)
Current portion of decommissioning liabilities	(1,073)	(1,073)	(237)	(237)	(925)
Net debt	66,009	60,080	60,423	61,848	63,114

Net debt to annualized funds flow ratio

Net debt to annualized funds flow ratio is a non-GAAP ratio because each of its components is a non-GAAP financial measure. This non-GAAP ratio is used by management as a key indicator of our leverage and the strength of our balance sheet. It is calculated by dividing our net debt at the end of the quarter by the funds flow for the quarter after it is annualized by multiplying it by four. Net debt to annualized fund flow ratio is not a standardized measure and, therefore, may not be comparable with the calculation of similar measures by other entities.

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 to mitigate commodity price risk and provide stability and sustainability to the Company's economic returns, funds flow, and dividend payments and capital development plans; that the Company's risk management contracts provide protection from 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, dividend payments, and capital development plans; the Company's anticipated firm service transportation commitments; and the amounts thereof; that the Company does not intend to settle its DSUs for cash; that the Company plans to remediate its working capital deficiency by utilizing the available borrowing room under its RLF and cash flow from operating activities; that our net debt is expected to decline in the second half of the year and is forecast to return to our 2025 guidance target of $60 million by year-end; the anticipated timing of implementation of the new accounting standards and the potential impact on the Company; 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.

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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: the 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 the 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 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.

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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

S000's	thousand dollars
S/bbl	dollars per barrel
S/boe	dollars per barrel of oil equivalent
S/GJ	dollars per gigajoule
S/mcf	dollars per thousand cubic feet
bbl	barrel
mbbl	thousand barrel
bbl/d	barrels per day
boe	barrel of oil equivalent
mboe	thousand barrel of oil equivalent
mmboe	million barrel of oil equivalent
boe/d	barrel of oil equivalent per day
GJ	gigajoule
GJ/d	gigajoules per day
mcf	thousand cubic feet
mcf/d	thousand cubic feet per day
mmcf/d	million cubic feet per day
bcf	billion cubic feet
NGLs	natural gas liquids
WTI	West Texas Intermediate

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