Petrus Resources Ltd. — Management Reports 2023

Mar 16, 2023

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MANAGEMENT'S DISCUSSION & ANALYSIS December 31, 2022

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MANAGEMENT’S DISCUSSION & ANALYSIS

The following is Management’s Discussion and Analysis ("MD&A") of the financial and operating results of Petrus Resources Ltd. ("Petrus" or the "Company") as at and for the year ended December 31, 2022. This MD&A is dated March 14, 2023 and should be read in conjunction with the Company's audited consolidated financial statements for the years ended December 31, 2022 and 2021. The Company’s consolidated financial statements are prepared in accordance with Canadian generally accepted accounting principles ("GAAP") which require publicly accountable enterprises to prepare their financial statements using International Financial Reporting Standards ("IFRS"). Readers are directed to the "Advisories" section at the end of this MD&A regarding forward-looking statements and boe presentation and to the section "Non-GAAP and Other Financial Measures" herein.

The principal undertaking of Petrus is the investment in energy assets. The operations of the Company consist of the acquisition, development, exploration and exploitation of these assets. The Company’s head office is located at 2400, 240 - 4th Avenue SW, Calgary, Alberta, Canada. Additional information on Petrus, including the most recently filed Annual Information Form ("AIF"), are available under the Company's profile on SEDAR (the System for Electronic Document Analysis and Retrieval) at www.sedar.com.

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SELECTED FINANCIAL INFORMATION

OPERATIONS	Twelve months ended Dec. 31, 2022 Twelve months ended Dec. 31, 2021	Three months ended Dec. 31, 2022 Three months ended Sept. 30, 2022 Three months ended Jun. 30, 2022 Three months ended Mar. 31, 2022
Average production Natural gas (mcf/d) Oil (bbl/d) NGLs (bbl/d)	30,441 23,680 1,436 1,019 1,094 1,043	33,201 28,107 30,913 29,530 2,458 957 1,073 1,250 1,121 997 1,055 1,207
Total (boe/d) Total (boe)	7,604 6,009 2,775,561 2,193,432	9,113 6,639 7,280 7,379 838,375 610,722 662,456 664,010
Light oil weighting	19 % 17 %	27 % 14 % 15 % 17 %
Realized Prices Natural gas ($/mcf) Oil ($/bbl) NGLs ($/bbl)	6.03 4.03 113.19 78.82 63.26 44.09	6.04 5.02 7.74 5.20 106.85 111.04 133.36 110.12 56.90 62.25 74.63 60.12
Total realized price ($/boe)	54.63 36.90	57.81 46.62 63.33 49.31
Royalty income Royalty expense Loss on risk management activities	0.26 0.14 (8.70) (4.72) (2.17) —	0.15 0.37 0.25 0.29 (7.92) (11.84) (8.64) (6.89) (1.26) (0.81) (6.76) —
Net oil and natural gas revenue ($/boe)	44.02 32.32	48.78 34.34 48.18 42.71
Operating expense Transportation expense	(7.45) (5.89) (2.08) (1.79)	(6.86) (8.47) (7.92) (6.76) (2.08) (1.89) (2.16) (2.17)
Operating netback(1)($/boe)	34.49 24.64	39.84 23.98 38.10 33.78
Realized gain (loss) on financial derivatives ($/boe) Other income (cash) General & administrative expense Cash finance expense Decommissioning expenditures	(0.58) (5.34) 0.10 0.49 (1.22) (1.95) (1.14) (2.34) (0.05) (0.31)	2.89 1.00 — (6.98) 0.22 0.05 0.04 0.07 (1.10) (1.30) (1.70) (0.82) (1.18) (0.87) (1.46) (1.04) 0.03 (0.29) 0.06 (0.02)
Funds flow & corporate netback(1)($/boe)	31.60 15.19	40.70 22.57 35.04 24.99
FINANCIAL (000s except $ per share)	Twelve months ended Dec. 31, 2022 Twelve months ended Dec. 31, 2021	Three months ended Dec. 31, 2022 Three months ended Sept. 30, 2022 Three months ended Jun. 30, 2022 Three months ended Mar. 31, 2022
Oil and natural gas revenue Net income Net income per share Basic Fully diluted Funds flow(1) Funds flow per share(1) Basic Fully diluted Capital expenditures Weighted average shares outstanding Basic Fully diluted As at period end Common shares outstanding Basic Fully diluted Total assets Non-current liabilities Net debt(1)	152,350 81,268 60,868 114,556 0.53 1.83 0.51 1.76 87,716 33,354 0.76 0.53 0.73 0.51 96,744 26,916 115,189 62,557 119,525 65,207 123,239 96,708 133,377 103,889 381,057 290,492 63,021 42,172 50,808 61,779	48,590 28,701 42,119 32,940 22,097 9,822 18,046 10,903 0.18 0.08 0.16 0.11 0.17 0.08 0.15 0.11 34,117 13,789 23,208 16,601 0.28 0.11 0.21 0.17 0.27 0.11 0.20 0.16 37,792 49,513 4,932 5,064 122,545 122,058 111,795 99,189 127,600 126,822 117,203 103,250 123,239 122,197 122,017 106,907 133,377 131,482 131,302 113,883 381,057 356,050 302,472 308,744 63,021 61,778 50,924 46,702 50,808 48,465 13,895 50,044

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

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OPERATIONS UPDATE

Fourth quarter average production by area was as follows:

For the three months ended
December 31, 2022	Ferrier	North Ferrier	Foothills	Central Alberta	Kakwa		Total
Natural gas (mcf/d)	21,198	4,498	2,360	4,993		150		33,199
Oil (bbl/d)	1,872	237	81	247		21		2,458
NGLs (bbl/d)	834	120	7	150		10		1,121
Total (boe/d)	6,239	1,107	481	1,230		56		9,113

Fourth quarter 2022 production averaged 9,113 boe/d compared to 5,880 boe/d in the fourth quarter of 2021. Five gross (4.6 net) wells were spud in the Ferrier area during the quarter. Of these, four (3.6 net) wells were completed and on production by December 31, 2022.

CAPITAL EXPENDITURES

The Company's 2022 capital program accelerated in the second half of 2022 with capital expenditures (excluding acquisitions and dispositions) totaling $37.8 million in the fourth quarter of 2022, compared to $12.2 million in the prior year comparative period.

Capital expenditures (excluding acquisitions and dispositions) totaled $96.7 million in the year ended December 31, 2022, compared to $27.0 million in 2021. The increase from the prior year is attributed to the execution of the Company's 2022 capital program.

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

Capital Expenditures ($000s) Three months ended December 31, 2022 Three months ended December 31, 2021	Twelve months ended December 31, 2022 Twelve months ended December 31, 2021
Drill and complete 32,073 10,769 Oil and gas equipment and facilities 4,921 1,104 Land and lease 291 25 Capitalized general and administrative expense 507 337	81,953 21,882 11,853 3,918 1,759 274 1,179 941
Total capital expenditures 37,792 12,235	96,744 27,015
Gross (net) wells spud 5 (4.6) 3 (3.0)	20 (14.8) 10 (6.4)

During the first quarter of 2022, Petrus closed an acquisition in its core Ferrier area. Included in this acquisition was approximately 425 boe/d of production and 5,120 net acres of undeveloped land. The acquisition was made for total share consideration of 10 million shares ($15.2 million).

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RESULTS OF OPERATIONS

FINANCIAL AND OPERATIONAL RESULTS OF OIL AND NATURAL GAS ACTIVITIES

	Twelve months ended Dec. 31, 2022 Twelve months ended Dec. 31, 2021	Twelve months ended Dec. 31, 2022 Twelve months ended Dec. 31, 2021	Three months ended Dec. 31, 2022 Three months ended Sept. 30, 2022 Three months ended Jun. 30, 2022 Three months ended Mar. 31, 2022
Average production Natural gas (mcf/d) Oil (bbl/d) NGLs (bbl/d)			33,201 28,107 30,913 29,530 2,458 957 1,073 1,250 1,121 997 1,055 1,207
	30,441 23,680 1,436 1,019 1,094 1,043
Total (boe/d) Total (boe)	7,604 6,009 2,775,561 2,193,432		9,113 6,639 7,280 7,379 838,375 610,722 662,456 664,010
Revenue ($000s) Natural gas Oil NGLs Royalty revenue	67,025 34,833 59,348 29,322 25,267 16,793 710 320		18,434 12,990 21,771 13,830 24,163 9,776 13,022 12,387 5,869 5,708 7,162 6,528 124 227 164 195
Oil and natural gas revenue	152,350 81,268		48,590 28,701 42,119 32,940
Average realized prices Natural gas ($/mcf) Oil ($/bbl) NGLs ($/bbl)	6.03 4.03 113.19 78.82 63.26 44.09		6.04 5.02 7.74 5.20 106.85 111.04 133.36 110.12 56.90 62.25 74.63 60.12
Total realized price ($/boe) Hedging gain (loss) ($/boe) Loss on risk management ($/boe)	54.63 36.90		57.81 46.62 63.33 49.31 2.89 1.00 — (6.98) (1.26) (0.81) (6.76) —
	(0.58) (5.34)
	(2.17) —
Total price including hedging ($/boe)	51.88 31.56		59.44 46.81 56.57 42.33
Average benchmark prices Twelve months ended Dec. 31, 2022		Twelve months ended Dec. 31, 2021	Three months ended Dec. 31, 2022 Three months ended Sept. 30, 2022 Three months ended Jun. 30, 2021 Three months ended Mar. 31, 2022
Natural gas AECO 5A (C$/GJ) 5.04 AECO 7A (C$/GJ) 5.22 Crude oil and NGLs Mixed Sweet Blend Edm (C$/bbl) 119.41 WTI (US$/bbl) 94.23 Foreign exchange US$/C$ 0.74		3.43 3.38 80.48	4.85 3.95 6.86 4.49 5.29 5.29 5.95 4.35 108.14 115.94 134.99 117.57 82.65 91.56 108.41 94.29 0.74 0.77 0.79 0.79
		67.96
		0.79

	Twelve months	Twelve months	Three months	Three months	Three months	Three months
Average benchmark prices	ended	ended	ended	ended	ended	ended
	Dec. 31, 2022	Dec. 31, 2021	Dec. 31, 2022	Sept. 30, 2022	Jun. 30, 2021	Mar. 31, 2022
Natural gas
AECO 5A (C$/GJ)	5.04	3.43	4.85	3.95	6.86	4.49
AECO 7A (C$/GJ)	5.22	3.38	5.29	5.29	5.95	4.35
Crude oil and NGLs
Mixed Sweet Blend Edm (C$/bbl)	119.41	80.48	108.14	115.94	134.99	117.57
WTI (US$/bbl)	94.23	67.96	82.65	91.56	108.41	94.29
Foreign exchange
US$/C$	0.74	0.79	0.74	0.77	0.79	0.79

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FUNDS FLOW AND NET INCOME

Petrus generated funds flow of $34.1 million in the fourth quarter of 2022 compared to $10.4 million in the fourth quarter of 2021. The 228% increase is due to higher production and improved commodity prices. In the fourth quarter of 2022 Petrus' production was 9,113 boe/d, 55% higher than the 5,880 boe/d during the fourth quarter of 2021. The Company's total realized price was $57.81/boe in the fourth quarter of 2022 compared to $46.29/boe in the prior year comparative period.

For the year ended December 31, 2022, Petrus generated funds flow of $87.7 million compared to $33.4 million in the prior year. The 163% increase is due to higher production and improved commodity prices.

Petrus reported net income of $22.1 million in the fourth quarter of 2022, compared to net income of $114.6 million in the fourth quarter of 2021. The reduction in net income in the fourth quarter of 2022 compared to the fourth quarter of 2021 is primarily due to the impairment reversal of $103.2 million recorded in the fourth quarter of 2021. Excluding the impairment reversal, net income was 94% higher in the fourth quarter of 2022 compared to the prior year comparative period.

The Company generated net income of $60.9 million for the year ended December 31, 2022 compared to net income of $114.6 million for the year ended December 31, 2021. The year over year change is due to the $103.2 million impairment reversal recorded in the fourth quarter of 2021. Excluding the impairment reversal, net income was 434% higher year over year.

($000s except per share)	Three months ended December 31, 2022 Three months ended December 31, 2021	Twelve months ended December 31, 2022 Twelve months ended December 31, 2021
Funds flow Funds flow per share - basic Funds flow per share - fully diluted	34,117 10,418 0.28 0.11 0.27 0.10	87,716 33,354 0.76 0.53 0.73 0.51
Net income Net income per share - basic Net income per share - fully diluted	22,097 114,633 0.18 1.19 0.17 1.11	60,868 114,556 0.53 1.83 0.51 1.76
Common shares outstanding (000s) Basic Fully diluted	123,239 96,708 133,377 103,889	123,239 96,708 133,377 103,889
Weighted average shares outstanding (000s) Basic Fully diluted	122,545 96,660 127,600 102,868	115,189 62,557 119,525 65,207

OIL AND NATURAL GAS REVENUE

Fourth quarter average production in 2022 was 9,113 boe/d (61% natural gas), 55% higher than the fourth quarter of 2021 (5,880 boe/d; 67% natural gas). Fourth quarter oil and natural gas revenue in 2022 was $48.6 million compared to $25.1 million in 2021. The 94% increase is due to higher production and improved commodity prices.

Average production for the year ended December 31, 2022 was 7,604 boe/d (67% natural gas), 27% higher than 2021 (6,009 boe/d; 66% natural gas). Total oil and natural gas revenue increased from $81.3 million in 2021 to $152.4 million in 2022 due to higher production and improved commodity prices.

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

Oil and Natural Gas Revenue ($000s) Three months ended December 31, 2022 Three months ended December 31, 2021 % Change	Twelve months ended December 31, 2022 Twelve months ended December 31, 2021 % Change
Natural gas 18,434 11,781 56 % Crude oil and condensate 24,163 8,273 192 % Natural gas liquids 5,869 4,985 18 % Royalty income 124 31 300 %	67,025 34,833 92 % 59,348 29,322 102 % 25,267 16,793 50 % 710 320 122 %
Total oil and natural gas revenue 48,590 25,070 **94 % **	152,350 81,268 87 %

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The following table provides the average benchmark commodity prices and the Company's average realized commodity prices (before hedging and risk management gains/losses):

	Three months ended December 31, 2022	Three months ended December 31, 2021	% Change	Twelve months ended December 31, 2022 Twelve months ended December 31, 2021 % Change
Average benchmark prices Natural gas AECO 5A (C$/GJ) AECO 7A (C$/GJ) Crude oil Mixed Sweet Blend Edm (C$/bbl) Average realized prices Natural gas ($/mcf) Oil ($/bbl) NGLs ($/bbl)	4.85 5.29 108.14 6.04 106.85 56.90	4.41 4.68 92.97		5.04 3.43 47 % 5.22 3.38 54 % 119.41 80.48 48 % 6.03 4.03 50 % 113.19 78.82 44 % 63.26 44.09 43 %
			10 % 13 %
			16 %
			11 % 19 % 1 %
		5.45 89.71
		56.35
Total average realized price	57.81	46.29	**25 % **	54.63 36.90 48 %

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

Production Volume by Product (%) Three months ended December 31, 2022 Three months ended December 31, 2021	Twelve months ended December 31, 2022 Twelve months ended December 31, 2021
Natural gas 61 % 67 % Crude oil and condensate 27 % 17 % Natural gas liquids 12 % 16 %	67 % 66 % 19 % 17 % 14 % 17 %
Total commodity sales from production 100 % 100 %	100 % 100 %

Natural gas

Natural gas revenue for the year ended December 31, 2022 was $67.0 million, which increased 92% from the prior year ($34.8 million). The average realized natural gas price for the year ended December 31, 2022 increased 50% to $6.03/mcf from the prior year ($4.03/mcf). Natural gas production increased from 8.6 bcf in 2021 to 11.1 bcf in 2022, an increase of 29%. Natural gas revenue accounted for 44% of oil and natural gas revenue in 2022, compared to 43% in the prior year.

Fourth quarter 2022 natural gas revenue was $18.4 million, which increased 56% from the prior year comparative period ($11.8 million). The average realized natural gas price in the fourth quarter of 2022 was $6.04/mcf, compared to $5.45/mcf in the fourth quarter of 2021 (11% increase). Natural gas production increased from 2.25 bcf in the fourth quarter of 2021 to 3.1 bcf in the fourth quarter of 2022. Natural gas revenue accounted for 38% of oil and natural gas revenue in the fourth quarter of 2022, compared to 47% in the prior year comparative period.

Crude oil and condensate

Oil and condensate revenue for the year ended December 31, 2022 was $59.3 million, which increased 102% from the prior year ($29.3 million). The average realized oil and condensate price for the year ended December 31, 2022 increased 44% to $113.19/bbl from the prior year ($78.82/bbl). Oil and condensate production increased from 372.0 mbbl in 2021 to 524.4 mbbl in 2022, an increase of 41%. Oil and condensate revenue accounted for 39% of oil and natural gas revenue in 2022, compared to 36% in the prior year.

Fourth quarter 2022 oil and condensate revenue was $24.2 million, which increased 192% from the prior year comparative period ($8.3 million). The average realized oil and condensate price was $106.85/bbl for the fourth quarter of 2022 compared to $89.71/bbl in the fourth quarter of 2021, an increase of 19%. Oil and condensate production increased from 92.2 mbbl in the fourth quarter of 2021 to 226.1 mbbl in the fourth quarter of 2022, an increase of 145%. Oil and condensate revenue accounted for 50% of oil and natural gas revenue in the fourth quarter of 2022, compared to 33% in the prior year comparative period.

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Natural gas liquids (NGLs)

NGL revenue for the year ended December 31, 2022 was $25.3 million, which increased 50% from the prior year ($16.8 million). The average realized NGL price for the year ended December 31, 2022 increased 43% to $63.26/bbl from the prior year ($44.09/bbl). NGL production increased from 382.3 mbbl in 2021 to 399.5 mbbl in 2022, an increase of 5%. NGL revenue accounted for 17% of oil and natural gas revenue in 2022, compared to 21% in the prior year.

Fourth quarter 2022 NGL revenue was $5.9 million, which increased 18% from the prior year comparative period ($5.0 million). The average realized NGL price was $56.90/bbl for the fourth quarter of 2022 which is consistent with the realized price of $56.35/bbl in the fourth quarter of 2021. NGL production increased from 89.0 mbbl in the fourth quarter of 2021 to 103.2 mbbl in the fourth quarter of 2022, an increase of 16%. NGL revenue accounted for 12% of oil and natural gas revenue in the fourth quarter of 2022, compared to 20% in the prior year comparative period.

The Company’s NGL production mix consists of ethane, propane, butane and pentanes+. The pricing received for NGL production is based on annual contracts effective the first of April each year. The contract prices are based on the product mix, the fractionation process required and the demand for fractionation facilities. NGL pricing is benchmarked to WTI.

ROYALTY EXPENSE

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

Royalty Expense ($000s) Three months ended December 31, 2022 Three months ended December 31, 2021	Twelve months ended December 31, 2022 Twelve months ended December 31, 2021
Crown 4,194 1,941 Percent of production revenue 9 % 8 %	15,463 5,797 10 % 7 %
Gross overriding 2,443 1,487	8,698 4,564
Total 6,637 3,428	24,161 10,361

Fourth quarter royalty expense increased from $3.4 million in 2021 to $6.6 million in 2022. On a twelve month basis, total royalty expense (net of royalty allowances and incentives) increased from $10.4 million in 2021 to $24.2 million in 2022. The increase in royalties for the fourth quarter and the year ended December 31, 2022 is due to higher revenue (as a result of increased commodity prices and production) and higher crown royalty rates.

Gross overriding royalties increased from $1.5 million in the fourth quarter of 2021 to $2.4 million in the fourth quarter of 2022. Gross overriding royalties increased from $4.6 million for the year ended December 31, 2021 to $8.7 million for the year ended December 31, 2022. The increase for both periods is due to higher revenue (as a result of increased production and higher commodity prices).

OTHER INCOME

During the year ended December 31, 2022 the Company recorded $1.4 million as other income ($0.3 million cash). This amount mainly relates to the recognition of carbon credits ($0.6 million) the Company earned from installing emission reduction equipment and the recognition of a grant for decommissioning activities ($0.4 million).

RISK MANAGEMENT

The Company utilizes financial derivative contracts and physical commodity contracts to mitigate commodity price risk and provide stability and sustainability to the Company's economic returns, funds flow and capital development plan. Petrus’ risk management program is governed by guidelines approved by its Board of Directors.

The impact of the contracts that were settled during the reporting periods are actual cash settlements and are recorded as realized hedging gains (losses) for financial derivatives and premium (loss) on risk management activities for physical commodity contracts. The unrealized gain (loss) is recorded to demonstrate the change in fair value of the outstanding financial derivative contracts during the financial reporting period for financial statement purposes. Petrus does not follow hedge accounting for any of its risk management contracts in place. Petrus considers all of its risk management contracts to be effective economic hedges of its underlying business transactions.

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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 December 31, 2022 Three months ended December 31, 2021	Twelve months ended December 31, 2022 Twelve months ended December 31, 2021
Realized hedging gain (loss) 2,421 (5,148) Unrealized hedging gain (loss) (1,959) 6,064	(1,601) (11,713) 7,609 (2,408)
Net gain (loss) on derivatives 462 916	6,008 (14,121)

In the fourth quarter of 2022, the Company recognized a realized hedging gain of $2.4 million compared to a loss of $5.1 million in the fourth quarter of 2021. The realized gain in the fourth quarter of 2022 increased the Company’s corporate netback by $2.89/boe, compared to a decrease of $9.52/boe in 2021. The Company recognized a realized hedging loss of $1.6 million during the year ended December 31, 2022, in comparison to the $11.7 million loss realized in 2021. The realized gain for the fourth quarter of 2022 was due to lower commodity prices (relative to the respective contracts settled) while the realized loss for the year ended December 31, 2022 was due to higher commodity prices (relative to the respective contracts settled).

During the fourth quarter of 2022, the Company recognized an unrealized loss of $2.0 million compared to an unrealized gain of $6.1 million in the fourth quarter of 2021. The Company recognized an unrealized hedging gain of $7.6 million for the year ended December 31, 2022 compared to an unrealized loss of $2.4 million for the year ended December 31, 2021. The gain (loss) represents the change in the unrealized risk management net asset or liability position during the year ended December 31, 2022.

The table below shows the premium (loss) on risk management activities related to physical commodity contracts for the periods shown:

Net Loss on Risk Management Activities ($000s) Three months ended December 31, 2022 Three months ended December 31, 2021	Twelve months ended December 31, 2022 Twelve months ended December 31, 2021
Loss on physical commodity contracts (1,056) —	(6,029) —
Net loss on risk management activities (1,056) —	(6,029) —

During the fourth quarter of 2022, the Company recorded a loss of $1.1 million or $1.26/boe related to the settlement of its physical commodity contracts. For the year ended December 31, 2022, the Company recorded a loss of $6.0 million or $2.17/boe. The losses are a result of lower contract prices in comparison to benchmark prices during the periods. The average volume of gas hedged through physical commodity contracts during the fourth quarter of 2022 was 14,333 GJ/d at an average price of $3.98/GJ. There was no loss or premium recorded during the three and twelve months ended December 31, 2021 as there were no contracts outstanding during these periods.

The Company’s risk management contracts provide protection from significant changes in crude oil and natural gas commodity prices for 2023 and 2024. The Company endeavors to hedge approximately half of its forecasted production for up to 12 months forward, and approximately 10% to 25% of its forecasted production for 12 to 24 months forward. The Company's hedging strategy is intended to provide stability and sustainability to the Company's economic returns, funds flow and capital development plan. A summary of Petrus’ risk management contracts as at December 31, 2022 is included in note 11 of the Company’s consolidated financial statements as at and for the year ended December 31, 2022. The 12,583 GJ/day of average natural gas hedged for the 2023 represents 40% of fourth quarter 2022 average natural gas production. The 1,375 bbl/day of average oil hedged for the 2023 represents 56% of fourth quarter 2022 average natural gas production.

The following table summarizes the average and minimum and maximum cap and floor prices for the 2023 to 2024 oil and natural gas contracts outstanding as at the date of this report:

	2023 2024	2023 2024
	Q1 Q2 Q3 Q4 Avg.(1)	Q1 Q2 Q3 Q4 Avg.(1)
Oil hedged (bbl/d) Avg. WTI cap price ($C/bbl) Avg. WTI floor price ($C/bbl)	1,100 1,400 1,500 1,500 1,375 112.23 109.98 106.07 105.84 108.23 103.79 103.35 99.88 99.65 101.48	1,100 1,000 200 200 625
		99.13 99.09 94.55 94.55 98.38 99.13 99.09 94.55 94.55 98.38
Natural gas hedged (GJ/d) Avg. AECO 7A cap price ($C/GJ) Avg. AECO 7A floor price ($C/GJ)	6,000 15,000 15,000 14,333 12,583 6.67 4.10 4.10 4.39 4.49 6.67 4.10 4.10 4.39 4.49	14,000 4,000 4,000 1,333 5,833
		4.53 3.26 3.26 3.26 4.02 4.53 3.26 3.26 3.26 4.02

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

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The following table summarizes the quarterly average volume and average prices for the natural gas physical commodity contracts as at the date of this MD&A:

date of this MD&A:
					2023
		Q1	Q2		Q3		Q4		Avg.(1)
Natural gas hedged (GJ/d)		14,000		—		—		—	3,500
Avg. AECO 7A price ($C/GJ)		4.17		—		—		—	4.17

(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 ($000s) Three months ended December 31, 2022 Three months ended December 31, 2021	Twelve months ended December 31, 2022 Twelve months ended December 31, 2021
Fixed and variable operating expense 5,173 2,182 Processing, gathering and compression charges 878 745	16,954 11,134 4,853 2,719
Total gross operating expense 6,051 2,927 Overhead recoveries (298) (212)	21,807 13,853 (1,142) (939)
Total net operating expense 5,753 2,715 Operating expense, net ($/boe) 6.86 5.02	20,665 12,914 7.45 5.89

For the three months ended December 31, 2022, net operating expense totaled $5.8 million, a 112% increase from $2.7 million during the prior year comparative period. Total operating expense is higher for three months ended December 31, 2022 due to higher production. On a per boe basis, net operating expense was 37% higher at $6.86/boe in the fourth quarter of 2022 compared to $5.02/boe in 2021.

For the year ended December 31, 2022, net operating expense totaled $20.7 million, a 60% increase from the $12.9 million incurred in the prior year comparative period. Total operating expense for the year ended December 31, 2022 is mainly due to higher production. On a per boe basis, net operating expense was 27% higher at $7.45/boe in 2022 compared to $5.89/boe in 2021.

On a per boe basis, the increase in net operating expense for the quarter and year ended December 31, 2022, is mainly attributable to inflationary pressures including the growing costs of power, fuel, trucking, and contract operating. Carbon tax expense was higher than the prior year comparative periods as well. The cost of gas gathering, compression and processing was also higher in 2022 as the Company had more volumes processed through third party facilities in the Foothills, Kakwa and North Ferrier areas. In addition, there was a decrease in third-party production flowing through Petrus' operated facilities, reducing fee recoveries.

TRANSPORTATION EXPENSE

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

Transportation Expense ($000s) Three months ended December 31, 2022 Three months ended December 31, 2021	Twelve months ended December 31, 2022 Twelve months ended December 31, 2021
Transportation expense 1,743 1,010 Transportation expense ($/boe) 2.08 1.87	5,772 3,920 2.08 1.79

Petrus pays commodity and demand charges for transporting its gas on pipeline systems. The Company also incurs trucking costs on the portion of its oil and natural gas liquids production that is not pipeline connected. For the three months ended December 31, 2022 transportation expense was $1.7 million or $2.08/boe compared to $1.0 million or $1.87/boe in the prior year comparative period. On a twelve month basis, transportation expense totaled $5.8 million, or $2.08/boe for 2022, which is 49% and 16% higher, respectively, than the $3.9 million of costs incurred (or $1.79/boe) in the prior year. The increase in transportation expense on a per boe basis is due to higher fuel surcharge and higher trucking costs due to increased fuel prices and volumes.

GENERAL AND ADMINISTRATIVE EXPENSE

The following table illustrates the Company’s general and administrative ("G&A") expense which is shown net of capitalized costs directly related to exploration and development activities:

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General and Administrative Expense ($000s) Three months ended December 31, 2022 Three months ended December 31, 2021	Twelve months ended December 31, 2022 Twelve months ended December 31, 2021
Personnel, consultants and directors 1,750 1,070 Administrative expenses 407 491 Regulatory and professional expenses 223 112	4,103 3,529 1,733 1,613 879 688
Gross general and administrative expenses 2,380 1,673 Capitalized general and administrative expenses (507) (289) Overhead recoveries (947) (171)	6,715 5,830 (1,179) (878) (2,147) (678)
General and administrative expenses 926 1,213 General and administrative expense ($/boe) 1.10 2.24	3,389 4,274 1.22 1.95

G&A expense (net of capitalized G&A expense and overhead recoveries) for the fourth quarter of 2022 totaled $0.9 million or $1.10/boe, compared to $1.2 million or $2.24/boe in the fourth quarter of 2021. Gross G&A expense (before capitalized G&A expense and overhead recoveries) was higher than the the prior year ($2.4 million in the fourth quarter of 2022 compared to $1.7 million in the fourth quarter of 2021) due to increased staffing costs (additional staff required to support capital program).

For the year ended December 31, 2022, net G&A expense was $3.4 million or $1.22/boe which is lower than the $4.3 million or $1.95/boe for the prior year comparative period (37% decrease on a per boe basis). For the year ended December 31, 2022 gross G&A expense was $6.7 million compared to $5.8 million in the prior year. The 16% increase is mainly due to increased staffing costs (additional staff required to support capital program).

Net G&A is lower, on a per boe and total basis, due to the increased overhead recovery related to the higher production and capital activity in 2022 in comparison to the prior year comparative periods.

SHARE-BASED COMPENSATION EXPENSE

The following table illustrates the Company’s share-based compensation expense which is shown net of capitalized costs directly related to exploration and development activities:

Share-Based Compensation Expense ($000s) Three months ended December 31, 2022 Three months ended December 31, 2021	Twelve months ended December 31, 2022 Twelve months ended December 31, 2021
Gross share-based compensation expense 614 164 Capitalized share-based compensation expense (184) (48)	1,630 355 (489) (96)
Share-based compensation expense 430 116	1,141 259

Share-based compensation expense (net of capitalized portion) was $0.43 million for the fourth quarter of 2022, which is 258% higher than the $0.12 million recognized in the fourth quarter of the prior year. For the year ended December 31, 2022, net share-based compensation expense was $1.14 million, which is 340% higher than the $0.26 million in the prior year comparative period. The increase in stock based compensation expense for the current period and year-end compared to the prior year comparative periods is due to the Company's improved stock price resulting in higher value of stock options and a higher staffing level.

FINANCE EXPENSE

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

Finance Expense ($000s) Three months ended December 31, 2022 Three months ended December 31, 2021	Twelve months ended December 31, 2022 Twelve months ended December 31, 2021
Interest expense 809 811 Foreign exchange loss (gain) — — Finance fees 177 45 Deferred financing costs 137 61 Non-cash term loan interest payment-in-kind — — Accretion on decommissioning obligations 310 198	2,175 4,108 3 — 993 1,025 430 365 — 2,573 1,066 707
Total finance expense 1,433 1,115	4,667 8,778

Fourth quarter total finance expense was $1.4 million in 2022, comprised of $0.3 million of non-cash accretion of its decommissioning obligations, $0.14 million of deferred financing costs, $0.8 million of cash interest expense and $0.18 million of finance fees. In the fourth

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quarter of 2021, the Company incurred total finance expense of $1.1 million, comprised of $0.2 million in non-cash accretion of its decommissioning obligation, $0.8 million cash interest expense, $0.05 million of finance fees, and $0.06 million of deferred financing fee amortization. The increase in finance fees in the fourth quarter of 2022 is mainly due to the increase in accretion and finance fees.

The Company incurred total finance expense of $4.7 million for the year ended December 31, 2022, which is 47% lower than the $8.8 million for the prior year. The decrease in total finance expense is due to a lower first lien loan balance throughout 2022 as well as the elimination of non-cash term loan interest payment-in-kind upon settlement of the term loan in 2021.

DEPLETION AND DEPRECIATION

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

Depletion and Depreciation Expense ($000s) Three months ended December 31, 2022 Three months ended December 31, 2021	Twelve months ended December 31, 2022 Twelve months ended December 31, 2021
Depletion and depreciation expense 10,658 5,508 Depletion and depreciation expense ($/boe) 12.71 10.18	33,277 22,992 11.99 10.43

Depletion and depreciation expense is calculated on a unit-of-production (boe) basis. This fluctuates period to period primarily as a result of changes in the underlying proved plus probable reserve base and in the amount of costs subject to depletion and depreciation, including future development cost. Such costs are segregated and depleted on an area by area basis relative to the respective underlying proved plus probable reserve base.

Petrus recorded depletion and depreciation expense in the fourth quarter of 2022 of $10.7 million or $12.71/boe, compared to the fourth quarter of 2021, when $5.5 million or $10.18/boe was recorded.

For the year ended December 31, 2022, the Company recorded $33.3 million or $11.99/boe, compared to $23.0 million or $10.43 per boe for the prior year comparative period.

The increase in the depletion expense for the fourth quarter of 2022 and year ended December 31, 2022 compared to the prior year comparative periods is due to higher production in 2022.

IMPAIRMENT (REVERSAL)

The following table illustrates impairment losses and reversals recorded in the reporting periods shown:

Impairment (Reversal) ($000s) Three months ended December 31, 2022 Three months ended December 31, 2021	Twelve months ended December 31, 2022 Twelve months ended December 31, 2021
Impairment (reversal) — (103,220)	— (103,220)
Total — (103,220)	— (103,220)

During 2021, Petrus recorded an impairment reversal of $106.9 million in its Ferrier CGU due to the significant increase in forward benchmark commodity prices at December 31, 2021 compared to December 31, 2020. In addition, Petrus also recognized an impairment loss of $3.7 million in its Kakwa CGU. The impairment reversal was allocated to PP&E ($80.6 million) and E&E ($22.6 million). The $103.2 million net amount of the impairment reversal was recorded in the Consolidated Statements of Net Income and Comprehensive Income. For more information, refer to notes 6 and 7 of the December 31, 2022 audited consolidated financial statements.

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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 December 31, 2022 Three months ended December 31, 2021	Twelve months ended December 31, 2022 Twelve months ended December 31, 2021
Weighted average common shares outstanding Basic 122,545 96,660 Fully diluted 127,600 102,868 Common shares outstanding Basic 123,239 96,708 Fully diluted 133,377 103,889 Stock options outstanding 8,520 5,563	115,189 62,557 119,525 65,207 123,239 96,708 133,377 103,889 8,520 5,563

At December 31, 2022, the Company had 123,238,528 common shares and 8,519,709 stock options outstanding. As at the date of this MD&A, the Company had 123,711,355 common shares and 8,620,017 stock options outstanding.

Deferred share units

The Company has a deferred share unit plan in place whereby it may issue deferred share units ("DSUs") to directors of the Company. At December 31, 2022 and the date of this MD&A, 1,618,702 DSUs were issued and outstanding (December 31, 2021 – 1,618,702). Each DSU entitles the participants to receive, at the Company's discretion, either common shares or a cash equivalent to the number of DSUs multiplied by the current trading price of the equivalent number of common shares. All DSUs vest and become payable upon retirement of the director. The DSUs are included as equity as the company does not intend to settle the DSUs for cash.

Rights Offering

During the second quarter of 2022, the Company completed a rights offering (the “Rights Offering”) where the Company issued approximately 14.8 million common shares at $1.35 per share for aggregate gross proceeds to the Company of approximately $20.0 million. The issuance costs were estimated to be $0.4 million and the net proceeds of $19.6 million were utilized for debt repayment and towards working capital.

The Company entered into a standby purchase agreement with each of Don Gray, Stuart Gray and Glen Gray (collectively, the "Stand-By Guarantors"). The Rights Offering was oversubscribed by 84% and as a result, the Stand-By Guarantors did not acquire any common shares in connection with the Rights Offering pursuant to their stand-by commitments. The Company had approximately 121.7 million shares outstanding following the Rights Offering with the Stand-By Guarantors owning approximately 71% of the outstanding shares.

Property Acquisition

During the first quarter of 2022, the Company completed an asset acquisition. The assets were acquired for share consideration of $15.2 million (10 million common shares of Petrus at $1.52 per share on closing date).

Private placement

During the third quarter of 2021, the Company completed a private placement financing of an aggregate of $10 million of common shares at an issue price of $0.55 per share. All proceeds from the equity financing were applied to outstanding indebtedness under the Company's first lien loan. Prior to September 30, 2021, Petrus had a second debt instrument, a subordinated secured term loan (the "Term Loan"). During the third quarter of 2021, the Company settled the Term Loan with a principal amount (carrying value) of $39.4 million in consideration for the issuance of $15.8 million (the settlement amount) of common shares of Petrus to the holders of the Term Loan at an issue price of $0.55 per share. The difference between the loan amount and the value of the shares was recorded as contributed surplus.

LIQUIDITY AND CAPITAL RESOURCES

At December 31, 2022, Petrus had two debt instruments outstanding; a reserve-based, secured operating revolving loan facility with an Alberta-based financial institution (the “Revolving Loan Facility” or “RLF”) and a second lien secured term facility (the "Second Lien Facility").

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Revolving Loan Facility

At December 31, 2022, the RLF was comprised of a $30.0 million operating facility payable on demand by the lender. The amount of the RLF is subject to a borrowing base review performed on a semi-annual basis by the lender, based primarily on reserves and commodity prices estimated by the lenders as well as other factors. The next semi-annual review is due on May 31, 2023.

At December 31, 2022, the Company had a $0.6 million letter of credit outstanding against the RLF (December 31, 2021 – $0.6 million on the previous revolving credit facility) and had drawn $4.6 million against the RLF (December 31, 2021 – $57.7 million on the previous revolving credit facility).

Second Lien Facility

At December 31, 2022 the Company had $25.0 million outstanding on the $25 million Second Lien Facility. The Second Lien Facility is a three-year term facility (maturity date May 31, 2025 with an option to extend by an additional two years) with a fixed interest rate of 11% per annum and can be repaid at the discretion of the Company after the first year. The Second Lien Facility is a related party transaction with a major shareholder who owns approximately 21% of the outstanding shares of the Company (see note 20 of the Company's December 31, 2022 audited consolidated financial statements). The total interest paid in 2022 to the major shareholder, related to the Second Lien facility, was $1.1 million.

Debt Settlement - Term Loan & Revolving Credit Facility

During 2022, the Company entered into agreements with new lenders to the Company, providing two new credit facilities, as described above, (the “New Credit Facilities”) totaling $55 million. The New Credit Facilities, together with the net proceeds of the Company's Rights Offering (described above), were used to repay in full all amounts owing under the Company's previous revolving credit facility. The New Credit Facilities closed in May 2022.

Prior to December 31, 2021, Petrus had a subordinated secured term loan (the "Term Loan"). During the third quarter of 2021, the Company settled its Term Loan with a principal amount (carrying value) of $39.4 million in consideration for the issuance of $15.8 million (the settlement amount) of common shares of Petrus to the holders of the Term Loan at an issue price of $0.55 per share. The difference between the carrying value and the settlement amount of the debt was added to contributed surplus in the amount of $18.1 million (net of the recovery of income taxes of $5.4 million).

Financial Covenants

The Company's RLF is subject to certain financial covenants. The following definitions are used in the covenant calculations for the debt instrument:

Working Capital

Working Capital means Current Assets to Current Liabilities whereby Current Assets means on any date of determination, the current assets of Petrus that would, in accordance with IFRS, be classified as of that date as current assets plus any undrawn availability under the RLF, less any non-cash amount required to be included in current assets as the result of the application of IFRS including non-cash commodity and interest rate hedges assets and liabilities and whereby Current Liabilities means, on any date of determination, the liabilities of Petrus that would, in accordance with IFRS, be classified as of that date as current liabilities, excluding (a) non-cash obligations under IFRS including non-cash commodity and interest rate hedges assets and liabilities, and (b) the current portion of long-term debt.

Working Capital Ratio means the ratio of Current Assets to Current Liabilities as defined above.

The key financial covenants as at December 31, 2022 are summarized in the following table. At December 31, 2022 the Company is in compliance with all financial covenants.

Financial Covenant Description	Required Ratio	As at December 31, 2022
WorkingCapital Ratio	Over 1.0	1.1

Liquidity

At December 31, 2022, the Company had a working capital deficiency (excluding non-cash risk management assets and liabilities) of $26.0 million as the company had $45.2 million in current accounts payable due to the substantial increase in capital activity during the third and fourth quarters of 2022.

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Contractual Maturities

The following are the contractual maturities of financial liabilities as at December 31, 2022:

Contractual Maturities The following are the contractual maturities of financial	liabilities as at December 31, 2022:
$000s	Total	< 1 year	1-5 years
Accounts payable and accrued liabilities	45,191	45,191	—
Bank indebtedness	4,606	4,606	—
Lease obligations	603	240	363
Longterm debt	25,000	—	25,000
Total	75,400	50,037	25,363

Commitments

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

$000s	Total	< 1 year	1-5 years	> 5 years
Firm service transportation	11,240	2,582	8,658	—

Risk Management

Petrus is engaged in the acquisition, development, exploration and exploitation of oil and natural gas in western Canada. The Company is exposed to a number of risks, both financial and operational, through the pursuit of its strategic objectives. Actively managing these risks improves the ability to effectively execute Petrus' business strategy. Financial risks associated with the oil and natural gas industry include fluctuations in commodity prices, interest rates, currency exchange rates and the cost of goods and services. Financial risks also include third party credit risk and liquidity risk. Operational risks include reservoir performance uncertainties, competition, regulatory, environment and safety concerns.

For a more in-depth discussion of risk management, see notes 11 and 16 of the Company’s December 31, 2022 audited consolidated financial statements.

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SUMMARY OF QUARTERLY RESULTS

SUMMARY OF QUARTERLY RESULTS
($000s unless otherwise noted)	Dec. 31, 2022	Sept. 30, 2022	Jun. 30, 2022	Mar. 31, 2022	Dec. 31, 2021	Sept. 30, 2021	Jun. 30, 2021	Mar. 31, 2021
Average Production
Natural gas (mcf/d)	33,201	28,107	30,913	29,530	23,494	23,942	24,291	22,985
Oil (bbl/d)	2,458	957	1,073	1,250	1,002	937	1,214	923
NGLs (bbl/d)	1,121	997	1,055	1,207	962	1,010	1,046	1,158
Total (boe/d)	9,113	6,639	7,280	7,379	5,880	5,937	6,309	5,912
Total (boe)	838,375	610,722	662,456	664,010	540,924	546,227	574,084	532,099
Financial Results
Oil and natural gas revenue	48,590	28,701	42,119	32,940	25,070	20,306	19,553	16,339
Royalty expense	(6,636)	(7,228)	(5,721)	(4,576)	(3,429)	(2,150)	(2,794)	(1,989)
Loss on risk management activities	(1,056)	(497)	(4,476)	—	—	—	—	—
Net oil and natural gas revenue	40,898	20,976	31,922	28,364	21,641	18,156	16,759	14,350
Transportation expense	(1,743)	(1,155)	(1,434)	(1,440)	(1,010)	(991)	(1,057)	(863)
Operating expense	(5,753)	(5,171)	(5,249)	(4,492)	(2,715)	(3,042)	(3,903)	(3,254)
Operating netback(1)	33,402	14,650	25,239	22,432	17,916	14,123	11,799	10,233
Realized gain (loss) on financial derivatives	2,421	610	—	(4,632)	(5,148)	(3,504)	(1,843)	(1,215)
Other income (cash)	186	30	28	47	21	12	1,018	23
General and administrative expense	(926)	(793)	(1,127)	(543)	(1,213)	(804)	(1,381)	(876)
Cash finance expense	(987)	(528)	(969)	(689)	(856)	(1,803)	(1,444)	(1,029)
Decommissioning expenditures	21	(180)	37	(14)	(302)	(150)	(79)	(143)
Corporate netback and funds flow(1)	34,117	13,789	23,208	16,601	10,418	7,874	8,070	6,993
Oil and natural gas revenue	48,590	28,701	42,119	32,940	25,070	20,306	19,553	16,339
Per share - basic	0.40	0.24	0.38	0.33	0.26	0.37	0.39	0.33
Per share - fully diluted	0.38	0.23	0.36	0.32	0.24	0.35	0.39	0.33
Net income (loss)	22,097	9,822	18,046	10,903	114,633	7,343	(4,265)	(3,155)
Per share - basic	0.18	0.08	0.16	0.11	1.19	0.14	(0.09)	(0.06)
Per share - fully diluted	0.17	0.08	0.15	0.11	1.11	0.13	(0.09)	(0.06)
Common shares outstanding (000s)
Basic	123,239	122,197	122,017	106,907	96,708	96,603	49,559	49,469
Fully diluted	133,377	131,482	131,302	113,883	103,889	100,074	49,559	49,469
Weighted average shares outstanding (000s)
Basic	122,545	122,058	111,795	99,189	96,660	54,167	49,513	49,469
Fully diluted	127,600	126,822	117,203	103,250	102,868	57,638	49,513	49,469
Total assets	381,057	356,050	302,472	308,744	290,492	173,101	176,629	177,587

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

The oil and natural gas exploration and production industry is cyclical in nature. Petrus' financial position, results of operations and corporate netback are affected by commodity prices, exchange rates, Canadian commodity price differentials and production levels. Petrus’ average quarterly production has increased from 5,912 boe/d in the first quarter of 2021 to 9,113 boe/d in the fourth quarter of 2022. The 54% production increase is attributable to Petrus' shift in focus back to production growth and an increased capital program.

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SELECTED ANNUAL INFORMATION

($000s unless otherwise noted)
For the year ended,	December 31, 2022	December 31, 2021	December 31, 2020
Oil and natural gas revenue	152,350	81,268	50,368
Per share - basic	1.32	1.30	1.02
Per share - fully diluted	1.27	1.25	1.02
Net income (loss)	60,868	114,556	(97,554)
Per share - basic	0.49	1.18	(1.97)
Per share - fully diluted	0.46	1.10	(1.97)
Common shares outstanding (000s)
Basic	123,239	96,708	49,469
Fully diluted	133,377	103,889	49,469
Weighted avg. shares outstanding (000s)
Basic	115,189	62,557	49,469
Fully diluted	119,525	65,207	49,469
Total assets	381,057	290,492	177,914
Non-current liabilities	63,021	42,172	45,321

CRITICAL ACCOUNTING ESTIMATES

The timely preparation of financial statements in conformity with IFRS requires management to make judgments, estimates and assumptions that affect the application of accounting policies and reported amounts of assets and liabilities and income and expenses. Accordingly, actual results may differ from these estimates. Estimates and underlying assumptions are reviewed on an ongoing basis. Revisions to accounting estimates are recognized in the period in which the estimates are revised and in any future periods affected. Significant estimates and judgments made by management in the preparation of the financial statements are outlined below. The Company’s critical accounting estimates can be read in note 2 to the Company’s audited consolidated financial statements as at and for the year ended December 31, 2022.

Russian/Ukrainian Conflict

In February 2022, Russian military forces invaded Ukraine. The outcome of the ongoing war is uncertain and is likely to have wide-ranging consequences on the peace and stability of the region and the world economy. In addition, certain countries including Canada, have imposed strict financial and trade sanctions against Russia which may have far reaching effects on the global economy. Disruption of supplies of commodities from Russia could have a significant impact on worldwide commodity prices. The long-term impacts of the conflict and the sanctions imposed on Russia remain uncertain. Any negative impact on economic conditions and global markets from these developments could adversely affect our business, financial condition and liquidity including our ability to access capital and the related costs. The Company does not have sales, production, or operations within Russia or Ukraine, and the conflict has not directly impacted its operations (and is not expected to). Nevertheless, the ongoing war induces greater uncertainties in global financial markets and supply chain systems which could lead to volatility in oil prices, inflation rates, interest rates, financing costs, and shortage or delays for certain goods or services. The Company continues assessing its exposure.

OTHER FINANCIAL INFORMATION

Significant accounting policies

The Company’s significant accounting policies can be read in note 3 of the Company’s audited consolidated financial statements as at and for the year ended December 31, 2022.

New standards and interpretations

The Company has not adopted any new standards and interpretations for the year ended December 31, 2022.

Disclosure Controls and Procedures

Petrus’ Chief Executive Officer and Chief Financial Officer have designed, or caused to be designed under their supervision, disclosure controls and procedures ("DC&P"), as defined by National Instrument 52-109 – Certification of Disclosure in Issuers’ Annual and Interim

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Filings (“NI 52-109”), to provide reasonable assurance that: (i) material information relating to the Company is made known to the Company's Chief Executive Officer and Chief Financial Officer by others, particularly during the period in which the annual filings are being prepared; and (ii) information required to be disclosed by the Company in its annual filings, interim filings or other reports filed or submitted by it under securities legislation is recorded, processed, summarized and reported within the time period specified in securities legislation. The Chief Executive Officer and Chief Financial Officer of Petrus have evaluated, or caused to be evaluated under their supervision, the effectiveness of the Company's DC&P as at December 31, 2022 and have concluded that the Company's DC&P are effective at December 31, 2022 for the foregoing purposes.

Internal Control over Financial Reporting

Internal control over financial reporting (“ICFR”), as defined in NI 52-109, includes those policies and procedures that: (i) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of assets of Petrus; (ii) are designed to provide reasonable assurance that transactions are recorded as necessary to permit preparation of the consolidated financial statements in accordance with generally accepted accounting principles and that receipts and expenditures of Petrus are being made in accordance with authorizations of management and Directors of Petrus; and (iii) are designed to provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the Company’s assets that could have a material effect on the consolidated financial statements.

The Chief Executive Officer and the Chief Financial Officer are responsible for establishing and maintaining ICFR for Petrus. For the year ended December 31, 2022, they have designed ICFR, or caused it to be designed under their supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with IFRS. The control framework used to design the Company’s ICFR is the framework in Internal Control – Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission. There has not been any change in Petrus' ICFR that occurred during the period beginning October 1, 2022 and ended on December 31, 2022 that has materially affected, or is reasonably likely to materially affect, Petrus' ICFR.

Under the supervision of the Chief Executive Officer and the Chief Financial Officer, Petrus conducted an evaluation of the effectiveness of the Company’s ICFR as at December 31, 2022. Based on this evaluation, the Chief Executive Officer and Chief Financial Officer concluded that as at December 31, 2022, Petrus maintained effective ICFR. It should be noted that while the Chief Executive Officer and Chief Financial Officer believe that the Company’s controls provide a reasonable level of assurance with regard to their effectiveness, a control system, no matter how well conceived or operated, can provide only reasonable, not absolute, assurance that the objectives of the control system will be met and it should not be expected that the control system will prevent all errors or fraud.

NON-GAAP AND OTHER FINANCIAL MEASURES

This MD&A makes reference to the terms "operating netback" (on an absolute and $/boe basis), "corporate netback" (on an absolute and $/boe basis), "funds flow" (on an absolute, per share (basic and fully diluted) and $/boe basis) and "net debt". These non-GAAP and other financial measures are not recognized measures under GAAP (IFRS) and do not have a standardized meaning prescribed by GAAP (IFRS). Accordingly, the Company's use of these terms may not be comparable to similarly defined measures presented by other companies. These non-GAAP and other financial measures should not be considered to be more meaningful than GAAP measures which are determined in accordance with IFRS as indicators of our performance. Management uses these non-GAAP and other financial measures for the reasons set forth below.

Operating Netback

Operating netback is a common non-GAAP financial measure used in the oil and natural gas industry which is a useful supplemental measure to evaluate the specific operating performance by product type at the oil and natural gas lease level. The most directly comparable GAAP measure to operating netback is oil and natural gas revenue. Operating netback is calculated as oil and natural gas revenue less royalty expenses, operating expenses, transportation expenses and loss on risk management activities. See below and under "Summary of Quarterly Results" for a reconciliation of operating netback to oil and natural gas revenue.

Operating netback ($/boe) is a non-GAAP ratio used in the oil and natural gas industry which is a useful supplemental measure to evaluate the specific operating performance by product type at the oil and natural gas lease level . It is calculated as operating netbacks divided by weighted average daily production on a per boe basis. See below.

Corporate Netback and Funds Flow

Corporate netback or funds flow is a common non-GAAP financial measure used in the oil and natural gas industry which evaluates the Company’s profitability at the corporate level. Corporate netback and funds flow are used interchangeably. Petrus analyzes these measures on an absolute value and on a per unit (boe) and per share (basic and fully diluted) basis as non-GAAP ratios. Management

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believes that funds flow and corporate netback provide information to assist a reader in understanding the Company's profitability relative to current commodity prices. They are calculated as the operating netback less general and administrative expense, cash finance expense, decommissioning expenditures, plus other income and the net realized gain (loss) on financial derivatives and risk management activities. See below and under "Summary of Quarterly Results" for a reconciliation of funds flow and corporate netback to oil and natural gas revenue.

Corporate netback ($/boe) or funds flow ($/boe) is a non-GAAP ratio used in the oil and natural gas industry which evaluates the Company’s profitability at the corporate level. Management believes that funds flow ($/boe) or corporate netback ($/boe) provide information to assist a reader in understanding the Company's profitability relative to current commodity prices. It is calculated as corporate netbacks or funds flow divided by weighted average daily production on a per boe basis. See below.

Funds flow per share (basic and fully diluted) is comprised of funds flow divided by basic or fully diluted weighted average common shares outstanding.

outstanding.
	Three months ended December 31, 2022 Three months ended December 31, 2021	Twelve months ended December 31, 2022 Twelve months ended December 31, 2021
	$000s $/boe $000s $/boe	$000s $/boe $000s $/boe
Oil and natural gas revenue Royalty expense Loss on risk management activities	48,590 57.96 25,070 46.35 (6,636) (7.92) (3,429) (6.34) (1,056) (1.26) — —	152,350 54.89 81,268 37.04 (24,161) (8.70) (10,361) (4.72) (6,029) (2.17) — —
Net oil and natural gas revenue	40,898 48.78 21,641 40.01	122,160 44.02 70,907 32.32
Transportation expense Operating expense	(1,743) (2.08) (1,010) (1.87) (5,753) (6.86) (2,715) (5.02)	(5,772) (2.08) (3,920) (1.79) (20,665) (7.45) (12,914) (5.89)
Operating netback	33,402 39.84 17,916 33.12	95,723 34.49 54,073 24.64
Realized gain (loss) on financial derivatives Other income(1) General & administrative expense Cash finance expense(2) Decommissioning expenditures	2,421 2.89 (5,148) (9.52) 186 0.22 21 0.04 (926) (1.10) (1,213) (2.24) (987) (1.18) (856) (1.58) 21 0.03 (302) (0.56)	(1,601) (0.58) (11,713) (5.34) 291 0.10 1,075 0.49 (3,389) (1.22) (4,274) (1.95) (3,171) (1.14) (5,133) (2.34) (137) (0.05) (674) (0.31)
Funds flow and corporate netback	34,117 40.70 10,418 19.26	87,716 31.60 33,354 15.19

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

(2)Excludes non-cash Term Loan interest payment-in-kind.

Net Debt

Net debt is a non-GAAP financial measure and is calculated as the sum of long term debt and working capital (current assets and current liabilities), excluding the current financial derivative contracts and current portion of the lease obligation. Petrus uses net debt as a key indicator of its leverage and strength of its balance sheet. Net debt is reconciled, in the table below, to long-term debt which is the most directly comparable GAAP measure.

directly comparable GAAP measure.
($000s)	As at December 31, 2022	As at September 30, 2022	As at June 30, 2022	As at March 31, 2022
Long-term debt	25,000	22,000	12,000	—
Current assets	(29,849)	(29,905)	(18,783)	(17,356)
Current liabilities	51,395	51,102	18,785	67,625
Current financial derivatives	4,502	5,503	2,124	—
Current portion of lease obligation	(240)	(235)	(231)	(225)
Net debt	50,808	48,465	13,895	50,044

Net debt to funds flow ratio is a non-GAAP ratio used as a key indicator of our leverage and strength of our balance sheet. It is calculated as net debt divided by funds flow for the relevant period.

OIL AND GAS DISCLOSURES

Our oil and gas reserves statement for the year ended December 31, 2022, which includes disclosure of our oil and natural gas reserves and other oil and natural gas information in accordance with NI 51-101, is contained in the AIF, which will be filed on SEDAR at www.sedar.com.

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Management uses oil and gas metrics for its own performance measurements and to provide shareholders with measures to compare Petrus' operations over time. Readers are cautioned that the information provided by these metrics, or that can be derived from the metrics presented in this MD&A, should not be relied upon for investment or other purposes.

ADVISORIES

Basis of Presentation

Financial data presented above has largely been derived from the Company’s financial statements, prepared in accordance with GAAP which require publicly accountable enterprises to prepare their financial statements using IFRS. Accounting policies adopted by the Company are set out in the notes to the audited consolidated financial statements as at and for the twelve months ended December 31, 2022. The reporting and the measurement currency is the Canadian dollar. All financial information is expressed in Canadian dollars, unless otherwise stated.

Forward-Looking Statements

Certain information regarding Petrus set forth in this MD&A contains forward-looking statements within the meaning of applicable securities law, that involve substantial known and unknown risks and uncertainties. The use of any of the words “anticipate”, “continue”, “estimate”, “expect”, “may”, “will”, “project”, “should”, “believe” and similar expressions are intended to identify forward-looking statements. Such statements represent Petrus’ internal projections, estimates, beliefs, plans, objectives, assumptions, intentions or statements about future events or performance. These statements are only predictions and actual events or results may differ materially. Although Petrus believes that the expectations reflected in the forward-looking statements are reasonable, it cannot guarantee future results, levels of activity, performance or achievement since such expectations are inherently subject to significant business, economic, competitive, political and social uncertainties and contingencies. Many factors could cause Petrus’ actual results to differ materially from those expressed or implied in any forward-looking statements made by, or on behalf of, Petrus.

In particular, forward-looking statements included in this MD&A include, but are not limited to, statements with respect to: the Company's risk management and hedging strategy and its objectives, including our ability to mitigate commodity price risk and provide stability and sustainability to our economic returns, funds flow and capital development plan; our belief that our risk management contracts are effective economic hedges of our underlying business transactions; that our risk management contracts provide protection from significant changes in crude oil and natural gas commodity prices for 2023 and 2024; and the Company's intention not to settle its DSUs for cash. In addition, statements relating to “reserves” are deemed to be forward-looking statements, as they involve the implied assessment, based on certain estimates and assumptions, that the reserves described can be profitably produced in the future.

These forward-looking statements are subject to numerous risks and uncertainties, most of which are beyond the Company’s control, including: the impact of general economic conditions; volatility in market prices for crude oil, NGL and natural gas; industry conditions; currency fluctuation; changes in interest rates and inflation rates; imprecision of reserve estimates; liabilities inherent in crude oil and natural gas operations; environmental risks; incorrect assessments of the value of acquisitions and exploration and development programs; competition; the lack of availability of qualified personnel or management; changes in income tax laws or changes in tax laws and incentive programs relating to the oil and gas industry; hazards such as fire, explosion, blowouts, cratering, and spills, each of which could result in substantial damage to wells, production facilities, other property and the environment or in personal injury; stock market volatility; ability to access sufficient capital from internal and external sources; and the other risks and uncertainties described in the AIF. With respect to forward-looking statements contained in this MD&A, Petrus has made assumptions regarding: future commodity prices and royalty regimes; availability of skilled labour; timing and amount of capital expenditures; future exchange rates; the impact of increasing competition; conditions in general economic and financial markets; availability of drilling and related equipment and services; effects of regulation by governmental agencies; the effects of inflation on our profitability; future interest rates; and future operating costs. Management has included the above summary of assumptions and risks related to forward-looking information provided in this MD&A in order to provide investors with a more complete perspective on Petrus’ future operations and such information may not be appropriate for other purposes. Petrus’ actual results, performance or achievement could differ materially from those expressed in, or implied by, these forward-looking statements and, accordingly, no assurance can be given that any of the events anticipated by the forward-looking statements will transpire or occur, or if any of them do so, what benefits that the Company will derive therefrom. Readers are cautioned that the foregoing lists of factors are not exhaustive.

These forward-looking statements are made as of the date of this MD&A and the Company disclaims any intent or obligation to update any forward-looking statements, whether as a result of new information, future events or results or otherwise, other than as required by applicable securities laws.

BOE Presentation

The oil and natural gas industry commonly expresses production volumes and reserves on a barrel of oil equivalent (“boe”) basis whereby natural gas volumes are converted at the ratio of six thousand cubic feet to one barrel of oil. The intention is to sum oil and natural gas

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measurement units into one basis for improved measurement of results and comparisons with other industry participants. Petrus uses the 6:1 boe measure which is the approximate energy equivalence of the two commodities at the burner tip. Boe’s do not represent an economic value equivalence at the wellhead and therefore may be a misleading measure if used in isolation.

Abbreviations $000’s thousand dollars $/bbl dollars per barrel $/boe dollars per barrel of oil equivalent $/GJ dollars per gigajoule $/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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