Petrus Resources Ltd. — Interim / Quarterly Report 2021

Aug 12, 2021

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SECOND QUARTER REPORT

For the three and six months ended June 30, 2021

Petrus Resources Ltd. (“Petrus” or the “Company”) (TSX: PRQ) is pleased to report financial and operating results as at and for the three and six months ended June 30, 2021. Petrus is focused on generating free cash flow for debt repayment and further development of its Ferrier Cardium asset.

Throughout the second quarter of 2021, global economies continued to show promise of a post-pandemic recovery. Increased demand for oil and natural gas persisted, which further strengthened commodity prices. Petrus generated funds flow of $8.1 million in the second quarter of 2021, which was 15% higher than in the first quarter of 2021. The Company’s production was 6,309 boe/d in the second quarter of 2021, an increase of 7% from 5,912 boe/d in the first quarter of 2021. The incremental production is attributable to 5 (3.2 net) recently drilled wells that were brought on production in late March and early April.

As uncertainty surrounding the COVID-19 pandemic endured and Petrus remained committed to debt repayment, the Company continued to execute a disciplined capital strategy throughout Q2 2021. Petrus will closely monitor the Canadian commodity price environment and evaluate subsequent quarter capital spending on an ongoing basis. Capital investments will remain focused in Ferrier where ownership of critical infrastructure supports low operating costs and high rates of return.

With balance sheet strength remaining a top priority for the Company, Petrus reduced net debt by $6.3 million in the second quarter of 2021, 5% reduction.

HIGHLIGHTS

• Commodity price improvements - Realized price per boe increased by 11% in the second quarter of 2021 compared to the first quarter. This is attributable to strengthening oil and NGL prices, which increased by 14% and 8%, respectively, quarter over quarter.

• Production - Increased production of 6,309 boe/d was associated with two new operated and three non-operated (1.2 net) wells being brought on production early in the quarter. These wells were drilled in the fourth quarter of 2020 and the first quarter of 2021 and the associated capital costs were largely incurred in those quarters.

• Operating netback - Operating netback increased to $11.8 million ($20.55 per boe) in the second quarter of 2021 from $10.2 million ($19.22 per boe) in the first quarter 2021, a 15% increase, and was up 144% from the Covid depressed second quarter of 2020..

• Funds flow - Petrus generated funds flow[(1)] of $8.1 million ($0.16 per share) in Q2 2021, which is 15% higher than the previous quarter and up 38% year over year.

CREDIT FACILITY EXTENSION

Subsequent to June 30, 2021, the lenders have extended the maturity date of the RCF from July 14 to August 13, 2021. The Company is actively engaged with the RCF lenders to further extend the maturity date of RCF. The Company is currently $73.5 million drawn against the RCF.

SECOND LIEN TERM LOAN EXTENSION

Effective June 15, 2021 Macquarie Bank Limited assigned the Company’s second lien term loan (“Term Loan”) to Blue Oak Partners (Canada) Inc. Subsequent to June 30, 2021, the Company extended the maturity of the Term Loan to October 14, 2021. The Company is actively engaged with the Term Loan lender to further extend the maturity date of Term Loan. The Company has approximately $39 million outstanding on the Term Loan.

2021 OUTLOOK

Consistent with the Company’s strategy of financial flexibility and balance sheet strength, Petrus will determine and provide guidance around quarterly capital spending as the year progresses. Throughout the balance of 2021 Petrus will continue to take a controlled approach to capital investments while also making quarterly payments of $2.75 million per quarter to the revolving credit facility. The Company has the financial and operational flexibility to respond quickly to changing market conditions and adjust capital investment plans accordingly. For the third quarter of 2021, the Board of Directors has approved a capital budget of $7.5 million for the drilling of 4 gross (1.5 net) Ferrier wells and investment in facility expansion in North Ferrier.

(1)Refer to "Non-GAAP Financial Measures" in the Management's Discussion & Analysis attached hereto.

(2)Refer to "Advisories - Forward-Looking Statements" in the Management's Discussion & Analysis attached hereto.

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MANAGEMENT'S DISCUSSION & ANALYSIS

June 30, 2021

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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 three months and six months ended June 30, 2021. This MD&A is dated August 10, 2021 and should be read in conjunction with the Company's audited consolidated financial statements for the years ended December 31, 2020 and 2019 as well as the Company's interim consolidated financial statements as at June 30, 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 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

SELECTED FINANCIAL INFORMATION
OPERATIONS Three months ended Jun. 30, 2021 Three months ended Jun. 30, 2020	Three months ended Mar. 31, 2021 Three months ended Dec. 31, 2020 Three months ended Sept. 30, 2020
Average Production Natural gas (mcf/d) 24,291 27,630 Oil (bbl/d) 1,214 867 NGLs (bbl/d) 1,046 819	22,985 26,177 26,181 923 980 1,103 1,158 1,014 997
Total (boe/d) 6,309 6,291 Total (boe) 574,084 572,440	5,912 6,357 6,463 532,099 584,860 594,599
Light oil weighting 19 % 14 %	15 % 15 % 17 %
Realized Prices Natural gas ($/mcf) 3.28 2.35 Oil ($/bbl) 75.99 27.18 NGLs ($/bbl) 39.76 12.87	3.33 3.07 2.51 66.61 49.64 46.46 36.79 23.52 22.05
Total realized price ($/boe) 33.87 15.73	30.55 24.05 21.48
Royalty income 0.19 0.06 Royaltyexpense (4.87) (1.51)	0.15 0.13 0.12 (3.74) (2.02) (2.09)
Net oil and natural gas revenue ($/boe) 29.19 14.28	26.96 22.16 19.51
Operating expense (6.80) (4.44) Transportation expense (1.84) (1.40)	(6.12) (5.53) (4.05) (1.62) (1.68) (1.63)
Operating netback(1)($/boe) 20.55 8.44	19.22 14.95 13.83
Realized gain (loss) on derivatives ($/boe) (3.21) 6.39 Other income 1.77 0.17 General & administrative expense (2.41) (1.43) Cash finance expense (2.52) (3.20) Decommissioning expenditures (0.14) (0.15)	(2.28) 0.65 2.20 0.04 0.31 0.04 (1.65) (1.81) (1.07) (1.93) (2.49) (2.16) (0.27) (0.63) (0.13)
Funds flow & corporate netback(1)(2) ($/boe) 14.04 10.22	13.13 10.98 12.71
FINANCIAL (000s except $ per share) Three months ended Jun. 30, 2021 Three months ended Jun. 30, 2020	Three months ended Mar. 31, 2021 Three months ended Dec. 31, 2020 Three months ended Sept. 30, 2020
Oil and natural gas revenue 19,553 9,041 Net loss (4,265) (6,281) Net loss per share Basic (0.09) (0.13) Fully diluted (0.09) (0.13) Funds flow 8,070 5,855 Funds flow per share Basic 0.16 0.12 Fully diluted 0.16 0.12 Capital expenditures 663 305 Weighted average shares outstanding Basic 49,513 49,469 Fully diluted 49,513 49,469 As at period end Common shares outstanding Basic 49,559 49,469 Fully diluted 49,559 49,469 Total assets 176,629 184,532 Non-current liabilities 40,838 43,017 Net debt(1) 110,346 120,570	16,339 14,143 12,840 (3,155) (151) (3,678) (0.06) — (0.07) (0.06) — (0.07) 6,993 6,423 7,551 0.14 0.13 0.15 0.14 0.13 0.15 7,917 2,797 2,543 49,469 49,469 49,469 49,469 49,469 49,469 49,469 49,469 49,469 49,469 49,469 49,469 177,587 177,914 179,895 42,028 45,321 44,471 116,634 114,361 116,717

(1)Refer to "Non-GAAP Financial Measures" in the Management's Discussion & Analysis attached hereto.

(2)Corporate netback is equal to funds flow which is a comparable additional GAAP measure. Petrus analyzes these measures on an absolute value and per unit basis.

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OPERATIONS UPDATE

Second quarter average production by area was as follows:

For the three months ended June 30, 2021	Ferrier	Foothills	Central Alberta	Other	Total
Natural gas (mcf/d)	17,628	1,468	4,808	387	24,291
Oil (bbl/d)	667	111	272	164	1,214
NGLs(bbl/d)	902	—	125	19	1,046
Total(boe/d)	4,507	356	1,199	247	6,309

Second quarter production averaged 6,309 boe/d in 2021 compared to 6,291 boe/d in 2020. During the second quarter of 2021, production increased marginally compared to the same period in 2021 due to 5 gross (3.2 net) new wells being brought on production at the start of Q2 2021 offsetting production declines.

CAPITAL EXPENDITURES

Capital expenditures (net of dispositions) totaled $0.7 million in the second quarter of 2021, compared to $0.3 million in the prior year comparative period. Second quarter 2021 capital spending consisted almost entirely of non-discretionary maintenance capital.

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

Capital Expenditures ($000s) Three months ended June 30, 2021 Three months ended June 30, 2020	Six months ended June 30, 2021 Six months ended June 30, 2020
Drill and complete (74) 70 Oil and gas equipment 545 24 Land and lease 94 12 Dispositions (100) — Capitalized general and administrative expense 198 199	6,653 7,645 1,382 758 239 30 (100) — 406 525
Total capital expenditures 663 305	8,580 8,958
Gross (net) wells spud 2 (1.2) —	5 (2.2) 3 (2.0)

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RESULTS OF OPERATIONS

FINANCIAL AND OPERATIONAL RESULTS OF OIL AND NATURAL GAS ACTIVITIES

FINANCIAL AND OPERATIONAL RESULTS OF OIL AND NATURAL GAS ACTIVITIES
Three months ended Jun. 30, 2021 Three months ended Jun. 30, 2020	Three months ended Mar. 31, 2021 Three months ended Dec. 31, 2020 Three months ended Sept. 30, 2020
Average production Natural gas (mcf/d) 24,291 27,630 Oil (bbl/d) 1,214 867 NGLs (bbl/d) 1,046 819	22,985 26,177 26,181 923 980 1,103 1,158 1,014 997
Total (boe/d) 6,309 6,291 Total (boe) 574,084 572,440	5,912 6,357 6,463 532,099 584,860 594,599
Revenue ($000s) Natural gas 7,261 5,903 Oil 8,397 2,143 NGLs 3,784 959 Royalty revenue 111 36	6,889 7,395 6,035 5,532 4,475 4,714 3,836 2,195 2,022 82 78 69
Oil and natural gas revenue 19,553 9,041	16,339 14,143 12,840
Average realized prices Natural gas ($/mcf) 3.28 2.35 Oil ($/bbl) 75.99 27.18 NGLs ($/bbl) 39.76 12.87	3.33 3.07 2.51 66.61 49.64 46.46 36.79 23.52 22.05
Total realized price ($/boe) 33.87 15.73 Hedging gain (loss) ($/boe) (3.21) 6.39	30.55 24.05 21.48 (2.28) 0.65 2.20
Total price including hedging ($/boe) 30.66 22.12	28.27 24.70 23.68
Average benchmark prices Three months ended Jun. 30, 2021 Three months ended Jun. 30, 2020	Three months ended Mar. 31, 2021 Three months ended Dec. 31, 2020 Three months ended Sept. 30, 2020
Natural gas AECO 5A (C$/GJ) 2.93 1.89 AECO 7A (C$/GJ) 2.70 1.81 Crude oil Mixed Sweet Blend Edm (C$/bbl) 76.16 32.17 Natural gas liquids Propane Conway (US$/bbl) 34.86 14.54 Butane Edmonton (C$/bbl) 34.02 14.56	2.98 2.50 2.02 2.77 2.62 2.04 68.62 49.34 48.96 35.74 25.50 19.78 26.04 19.32 19.04
Foreign exchange US$/C$ 0.81 0.74	0.79 0.77 0.74

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FUNDS FLOW AND NET LOSS

Petrus generated funds flow of $8.1 million in the second quarter of 2021 compared to $5.9 million in the second quarter of 2020. The 37% increase is due to higher oil and natural gas prices partially offset by higher hedge loss and higher operating and general and administrative costs. In the second quarter of 2021 Petrus' total realized price was $33.87/boe compared to $15.73/boe in the second quarter of 2020.

Petrus reported a net loss of $4.3 million in the second quarter of 2021, compared to a net loss of $6.3 million in the second quarter of 2020. The decrease in the net loss in the second quarter of 2021 compared to the second quarter of 2020 is primarily due to higher oil and natural gas prices as commodity prices continue to recover after the lows experienced during the second quarter of 2020 due to the ongoing COVID-19 pandemic.

On a six month basis, the Company generated a net loss of $7.4 million for the six months ended June 30, 2021 compared to a net loss of $93.7 million for the six months ended June 30, 2020. The decrease in net loss is due to the $98.0 million impairment loss booked during the first quarter of 2020.

($000s except per share) Three months ended June 30, 2021 Three months ended June 30, 2020	Six months ended June 30, 2021 Six months ended June 30, 2020
Funds flow 8,070 5,855 Funds flow per share - basic 0.16 0.12 Funds flow per share - fully diluted 0.16 0.12	15,062 12,422 0.30 0.25 0.30 0.25
Net loss (4,265) (6,281) Net loss per share - basic (0.09) (0.13) Net loss per share - fully diluted (0.09) (0.13)	(7,420) (93,725) (0.15) (1.89) (0.15) (1.89)
Common shares outstanding (000s) Basic 49,559 49,469 Fully diluted 49,559 49,469	49,559 49,469 49,559 49,469
Weighted average shares outstanding (000s) Basic 49,513 49,469 Fully diluted 49,513 49,469	49,491 49,469 49,491 49,469

OIL AND NATURAL GAS REVENUE

Second quarter average production in 2021 was 6,309 boe/d (64% natural gas), consistent with the second quarter of 2020 (6,291 boe/d; 73% natural gas). Second quarter oil and natural gas revenue in 2021 was $19.6 million compared to $9.0 million in 2020. The 116% increase is due to significantly higher oil and natural gas prices.

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

Production Volume by Product (%) Three months ended June 30, 2021 Three months ended June 30, 2020	Six months ended June 30, 2021 Six months ended June 30, 2020
Natural gas 64 % 73 % Crude oil and condensate 19 % 14 % Natural gas liquids 17 % 13 %	64 % 71 % 18 % 15 % 18 % 14 %
Total commodity sales from production 100 % 100 %	100 % 100 %

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 June 30, 2021 Three months ended June 30, 2020 % Change	Six months ended June 30, 2021 Six months ended June 30, 2020 % Change
Natural gas 7,261 5,903 23 % Crude oil and condensate 8,397 2,143 292 % Natural gas liquids 3,784 959 295 % Royalty income 111 36 208 %	14,150 12,593 12 % 13,929 7,304 91 % 7,620 3,255 134 % 193 233 (17) %
Total oil and natural gas revenue 19,553 9,041 **116 % **	35,892 23,385 53 %

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The following table provides the average benchmark and the Company's average realized commodity prices:

	Three months ended June 30, 2021 Three months ended June 30, 2020 % Change	Six months ended June 30, 2021 Six months ended June 30, 2020 % Change
Average benchmark prices Natural gas AECO 5A (C$/GJ) AECO 7A (C$/GJ) Crude oil Mixed Sweet Blend Edm (C$/bbl) Natural gas liquids Propane Conway (US$/bbl) Butane Edmonton (C$/bbl)	2.93 1.89 55 % 2.70 1.81 49 % 76.16 32.17 137 % 34.86 14.54 140 % 34.02 14.56 134 %	2.96 1.93 53 % 2.74 2.03 35 % 72.39 52.28 38 % 35.28 14.54 143 % 30.03 14.56 106 %
Average realized prices Natural gas ($/mcf) Oil ($/bbl) NGLs ($/bbl)	3.28 2.35 40 % 75.99 27.18 180 % 39.76 12.87 209 %	3.31 2.38 39 % 71.97 40.12 79 % 38.21 18.76 104 %
Total average realized price	33.87 15.73 **115 % **	32.27 18.69 73 %

Natural gas

Natural gas revenue for the six months ended June 30, 2021 was $14.2 million which accounted for 40% of oil and natural gas revenue, compared to revenue of $12.6 million, which accounted for 54% of oil and natural gas revenue in the prior year comparative period. Second quarter 2021 average realized natural gas price was $3.28/mcf, compared to $2.35/mcf in the second quarter of 2020 (40% increase). The increase in revenue for the second quarter and the six months ended June 30, 2021, compared to the same periods in 2020, was due to an increase in natural gas pricing (AECO 5A) of 55% and 53% respectively

Crude oil and condensate

Oil and condensate revenue for the six months ended June 30, 2021 was $13.9 million, which accounted for approximately 39% of oil and natural gas revenue, compared to revenue of $7.3 million, which accounted for 32% in the prior year comparative period.

The average realized price of Petrus’ light oil and condensate was $75.99/bbl for the second quarter of 2021 compared to $27.18 /bbl in the second quarter of 2020. The 180% increase is attributed to the increase in oil prices in the current quarter and six month period as prices continue to recover from the low pricing seen during the second quarter of 2020 due to the effects of the COVID-19 global pandemic.

Natural gas liquids (NGLs)

The Company’s NGL production mix consists of ethane, propane, butane and pentane. The pricing received for NGL production is based on annual contracts effective the first of April each year. The contract prices are based on the product mix, the fractionation process required and the demand for fractionation facilities. In the second quarter of 2021, the Company's realized NGL price averaged $39.76/bbl, compared to $12.87/bbl in the prior year. The 209% increase is attributed to higher contract prices for the NGL byproducts. Second quarter market pricing for propane at Conway increased 140% from the prior year. Petrus' butane production is priced as a function of WTI (oil) which also increased in the second quarter compared to the prior year.

Petrus' ownership and control of critical processing facilities enables the Company to respond and continually optimize its production revenue streams. To improve operating netback, during 2019, Petrus ceased sending certain natural gas for additional third party deepcut processing to extract additional NGLs. This resulted in lower NGL production volume, however, the heating value of natural gas sales increased and processing fees decreased. Petrus continues to monitor NGL market pricing and is able to modify its operations accordingly.

NGL revenue for the six months ended June 30, 2021 was $7.6 million and accounted for 21% of oil and natural gas revenue, compared to revenue of $3.3 million accounting for 14% in the prior year comparative period. The increase was due to higher NGL prices.

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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:

	Three months ended	Three months ended	Six months ended	Six months ended
Royalty Expense ($000s)
	June 30, 2021	June 30, 2020	June 30, 2021	June 30, 2020
Crown	1,811	316	2,843	841
Percent of production revenue	9 %	4 %	8 %	4 %
Gross overriding	983	551	1,940	1,925
Total	2,794	867	4,783	2,766

Second quarter royalty expense increased from $0.9 million in 2020 to $2.8 million in 2021. On a six month basis, total royalty expense (net of royalty allowances and incentives) increased from $2.8 million in 2020 to $4.8 million in 2021. The increase in royalties for the second quarter and the six months ended June 30, 2021 is due to higher revenues and higher commodity prices.

Gross overriding royalties increased from $0.6 million in the second quarter of 2020 to $1.0 million in the second quarter of 2021, due to higher revenues and commodity prices. Gross overriding royalties remained consistent at $1.9 million for the six months ended June 30, 2020 and $1.9 million for the six months ended June 30, 2021.

OTHER INCOME

During the second quarter of 2021, the Company recorded $1.0 million as other income. This amount relates to the settlement of an outstanding dispute associated with the transportation and marketing of its Ferrier area condensate volume.

RISK MANAGEMENT

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

The impact of the contracts that were outstanding 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 risk management contracts for the periods shown:

Net Gain (Loss) on Financial Derivatives ($000s) Three months ended June 30, 2021 Three months ended June 30, 2020	Six months ended June 30, 2021 Six months ended June 30, 2020
Realized hedging gain (loss) (1,843) 3,656 Unrealized hedging gain (loss) (5,493) (6,332)	(3,058) 4,830 (8,857) 5,353
Net gain (loss) on derivatives (7,336) (2,676)	(11,915) 10,183

In the second quarter of 2021, the Company recognized a realized hedging loss of $1.8 million, compared to a gain of $3.7 million in the second quarter of 2020. The realized loss in the second quarter of 2021 decreased the Company’s total realized price by $3.21/boe, compared to an increase of $6.39/boe in 2020. The Company recognized a realized hedging loss of $3.1 million during the six months ended June 30, 2021, in comparison to the $4.8 million gain realized in the same period of the prior year. The realized loss for the three and six months ended June 30, 2021 was due to higher commodity prices (relative to the respective contracts outstanding).

During the second quarter of 2021, the Company recognized an unrealized loss of $5.5 million compared to an unrealized loss of $6.3 million in the second quarter of 2020. The Company recognized an unrealized hedging loss of $8.9 million for the six months ended June 30, 2021 compared to an unrealized gain of $5.4 million for the six months ended June 30, 2020. The loss represents the change in the unrealized risk management net liability position during the first six months of 2021. This change is a result of both the realization of hedging gains in the period, changes related to contracts entered into during the period as well as changes to commodity prices.

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The Company’s risk management contracts provide protection from significant changes in crude oil and natural gas commodity prices for 2021 and 2022. The Company endeavors to hedge approximately half of its forecast production for the following year, and approximately 30% of its forecast production for the subsequent year. The Company's hedging strategy is intended to provide stability and sustainability to the Company's economic returns, funds flow and capital development plan. A summary of Petrus’ risk management contracts is included in note 8 of the Company’s interim consolidated financial statements as at and for the period ended June 30, 2021. The table below summarizes Petrus’ average crude oil and natural gas hedged volumes. The average volume of oil hedged for the remainder of 2021 (900 bbl/d) represents 40% of second quarter 2021 average oil and natural gas liquids production. The 13,335 GJ/day average natural gas hedged for the remainder of 2021 represents 55% of second quarter 2021 average natural gas production.

The following table summarizes the average and minimum and maximum cap and floor prices for the 2021 to 2022 oil and natural gas contracts outstanding as at June 30, 2021:

The following table summarizes the average and minimum and maximum cap and floor prices for the 2021 to 2022 oil and natural gas contracts outstanding as at June 30, 2021:	The following table summarizes the average and minimum and maximum cap and floor prices for the 2021 to 2022 oil and natural gas contracts outstanding as at June 30, 2021:
2021 2022
Q1 Q2 Q3 Q4 Avg.(1)	Q1 Q2 Q3 Q4 Avg.(1)
Oil hedged (bbl/d) 700 800 900 900 825 Avg. WTI cap price ($C/bbl) 68.42 66.94 66.46 65.85 66.83 Avg. WTI floor price ($C/bbl) 68.42 66.94 66.46 65.85 66.83	600 — — — 150 62.73 — — — — 62.73 — — — —
Natural gas hedged (GJ/d) 17,000 16,000 14,000 12,667 14,917 Avg. AECO 7A cap price ($C/GJ) 2.18 2.15 2.08 2.44 2.20 Avg. AECO 7A floor price ($C/GJ) 2.18 2.15 2.08 2.44 2.20	10,000 — — — 2,500 2.61 — — — 2.61 2.61 — — — 2.61

(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 ($000s) Three months ended June 30, 2021 Three months ended June 30, 2020	Six months ended June 30, 2021 Six months ended June 30, 2020
Fixed and variable operating expense 3,422 2,074 Processing, gathering and compression charges 720 671	6,425 4,659 1,207 1,352
Total gross operating expense 4,142 2,745 Overhead recoveries (239) (202)	7,632 6,011 (475) (433)
Total net operating expense 3,903 2,543 Operating expense, net ($/boe) 6.80 4.44	7,157 5,578 6.47 4.50

For the three months ended June 30, 2021, net operating expense totaled $3.9 million, a 53% increase from $2.5 million during the prior year comparative period. On a per boe basis, net operating expense was 53% higher at $6.80/boe in the second quarter of 2021 compared to $4.44/boe in 2020.

For the six months ended June 30, 2021, net operating expense totaled $7.2 million, a 28% increase from the $5.6 million incurred in the prior year comparative period.

The increase in operating expense for the quarter and six months ended June 30, 2021 is due to the following:

• higher property tax and regulatory fees that were deferred or reduced in 2020 as a result of COVID-19 reliefs;

• previous year billing adjustments for the non-operated gas processing fee;

• lower cost recovery from third parties;

• higher electricity prices;

• increased workover activity; and

• carbon tax and related compliance expenses.

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TRANSPORTATION EXPENSE

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

Transportation Expense ($000s) Three months ended June 30, 2021 Three months ended June 30, 2020	Six months ended June 30, 2021 Six months ended June 30, 2020
Transportation expense 1,057 799 Transportation expense ($/boe) 1.84 1.40	1,920 1,502 1.74 1.21

Petrus pays commodity and demand charges for transporting its gas on pipeline systems. The Company also incurs trucking costs on the portion of its oil and natural gas liquids production that is not pipeline connected. For the three months ended June 30, 2021 transportation expense was $1.1 million or $1.84/boe compared to $0.8 million or $1.40/boe in the prior year comparative period. On a six month basis, transportation expense totaled $1.9 million, or $1.74 per boe for 2021, which is 27% and 43% higher, respectively, than the $1.5 million costs incurred (or $1.21 per boe) in the prior year comparative period. The increase in transportation expense is attributed to the pipeline firm transportation contract that began towards the end of the second quarter of 2020.

GENERAL AND ADMINISTRATIVE EXPENSE

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

General and Administrative Expense ($000s) Three months ended June 30, 2021 Three months ended June 30, 2020	Six months ended June 30, 2021 Six months ended June 30, 2020
Personnel, consultants and directors 1,216 583 Administrative expenses 322 340 Regulatory and professional expenses 83 162	1,776 1,421 794 466 380 759
Gross general and administrative expense 1,621 1,085 Capitalized general and administrative expense (198) (199) Overhead recoveries (42) (69)	2,950 2,646 (406) (525) (287) (406)
General and administrative expense 1,381 817 General and administrative expense ($/boe) 2.41 1.43	2,257 1,715 2.04 1.38

G&A expense (net of capitalized G&A expense and overhead recoveries) for the second quarter of 2021 totaled $1.4 million or $2.41 per boe, compared to $0.8 million or $1.43 per boe in the second quarter of 2020. Gross G&A expense (before capitalized G&A expense and overhead recoveries) was 49% higher than the prior year ($1.62 million in the second quarter of 2021 compared to $1.09 million in the second quarter of 2020) due to one-time expenses related to management changes and lower wage subsidy from the government in the second quarter of 2021.

For the six months ended June 30, 2021, gross G&A expense was $3.0 million compared to $2.6 million in the prior year comparative period, which represents a 11% increase. Second quarter G&A expense in 2021 was $2.3 million or $2.04/boe which is higher than the $1.7 million or $1.38/boe in the second quarter of 2020 (47% increase on a per boe basis).

The net increases in G&A are attributed to lower overhead recoveries while the gross increases in G&A are due to one-time expenses related to management changes and lower wage subsidy from the government during the second quarter of 2021.

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 June 30, 2021 Three months ended June 30, 2020	Six months ended June 30, 2021 Six months ended June 30, 2020
Gross share-based compensation expense 37 68 Capitalized share-based compensation expense (15) (28)	144 157 (32) (63)
Share-based compensation expense 22 40	112 94

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Share-based compensation expense (net of capitalized portion) was $0.02 million for the second quarter of 2021, which is 45% lower than the $0.04 million recognized in the second quarter of the prior year. For the six months ended June 30, 2021, net share-based compensation expense was $0.11 million, which is 19% lower than the $0.09 million in the prior year comparative period. The decrease in stock based compensation expense for the three and six months period in the current year compared to the prior year period is due to options fully vesting during 2020 and fewer new grants during 2021.

FINANCE EXPENSE

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

Finance Expense ($000s) Three months ended June 30, 2021 Three months ended June 30, 2020	Six months ended June 30, 2021 Six months ended June 30, 2020
Interest expense 1,444 1,831 Deferred financing costs 116 123 Non-cash term loan interest payment-in-kind 965 — Accretion on decommissioning obligations 196 110	2,474 3,919 260 244 1,901 — 318 292
Total finance expense 2,721 2,064	4,953 4,455

Second quarter total finance expense was $2.7 million in 2021, comprised of $0.2 million of non-cash accretion of its decommissioning obligations, $1.4 million of cash interest expense and $1.0 million of non-cash term loan interest payment-in-kind related to the Term Loan. In the second quarter of 2020, the Company incurred total finance expense of $2.1 million, comprised of $0.1 million in non-cash accretion of its decommissioning obligation, $1.8 million cash interest expense and $0.1 million of deferred financing fee amortization.

The Company incurred total finance expense of $5.0 million for the six months ended June 30, 2021, which is higher than the $4.5 million for the prior year comparative period.

The increases in total finance expense are due to legal and professional fees incurred related to the loan extension and higher interest rates, partially offset by lower first lien balances.

DEPLETION AND DEPRECIATION

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

Depletion and Depreciation Expense ($000s) Three months ended June 30, 2021 Three months ended June 30, 2020	Six months ended June 30, 2021 Six months ended June 30, 2020
Depletion and depreciation expense 5,972 5,611 Depletion and depreciation expense ($/boe) 10.40 9.80	11,605 13,351 10.49 10.78

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 second quarter of 2021 of $6.0 million or $10.40 per boe, compared to the second quarter of 2020, when $5.6 million or $9.80 per boe was recorded. The increase in the depletion expense for the second quarter of 2021 compared to the second quarter of 2020 was primarily due to new well brought on production during the quarter.

For the six months ended June 30, 2021, the Company recorded $11.6 million or $10.49 per boe, compared to $13.4 million or $10.78 per boe for the prior year. The decrease in depletion and depreciation expense is attributed to the impairment recorded in 2020 that lowered the DD&A per boe.

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IMPAIRMENT

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

Impairment ($000s)	Three months ended June 30, 2021 Three months ended June 30, 2020	Six months ended June 30, 2021 Six months ended June 30, 2020
Impairment	— —	— 98,000
Total	— —	— 98,000

Petrus recognized an impairment loss of $98.0 million in the Ferrier CGU during the six months ended June 30, 2020, due to the significant decrease in forward benchmark commodity prices at March 31, 2020 compared to December 31, 2019. For more information, refer to notes 3 and 4 of the June 30, 2021 interim consolidated financial statements.

SHARE CAPITAL

The Company's authorized share capital consists of an unlimited number of common shares and an unlimited number of preferred shares. The Company has not issued any preferred shares. The following table details the number of issued and outstanding securities for the periods shown:

Share Capital (000s) Three months ended June 30, 2021 Three months ended June 30, 2020	Six months ended June 30, 2021 Six months ended June 30, 2020
Weighted average common shares outstanding Basic 49,513 49,469 Fully diluted 49,513 49,469 Common shares outstanding Basic 49,559 49,469 Fully diluted 49,559 49,469 Stock options outstanding 2,098 1,437	49,491 49,469 49,491 49,469 49,559 49,469 49,559 49,469 2,098 1,437

At June 30, 2021, the Company had 49,558,622 common shares and 2,098,325 stock options outstanding.

The Company has a deferred share unit plan in place whereby it may issue deferred share units ("DSUs") to directors of the Company. At June 30, 2021, 1,618,702 DSUs were issued and outstanding (December 31, 2020 – 2,158,270). Each DSU entitles the participants to receive, at the Company's discretion, either common shares or a cash equivalent to the number of DSUs multiplied by the current trading price of the equivalent number of common shares. All DSUs vest and become payable upon retirement of the director.

LIQUIDITY AND CAPITAL RESOURCES

Petrus has two debt instruments outstanding. The first is a reserve-based, senior secured revolving credit facility with a syndicate of lenders, which is comprised of an operating facility and a syndicated term-out facility (together, the “Revolving Credit Facility” or “RCF”). The second is a subordinated secured term loan (the “Term Loan”).

(a) Revolving Credit Facility

At June 30, 2021 the RCF was comprised of a $20.0 million operating facility and a $57.5 million syndicated term-out facility with a maturity date of July 14, 2021. The Company has provided collateral by way of a debenture over all of the present and after acquired property of the Company.

At June 30, 2021, the Company had a $0.6 million letter of credit outstanding against the RCF (June 30, 2020 – $0.6 million) and had drawn $74.4 million against the RCF (June 30, 2020 – $86.2 million).

The amount of the RCF is subject to a borrowing base review performed on a semi-annual basis by the lenders, based primarily on reserves and commodity prices estimated by the lenders as well as other factors. In addition, asset dispositions require unanimous lender consent. A decrease in the borrowing base could result in a reduction to the available credit under the RCF. The next scheduled borrowing base redetermination date for the RCF is on or before November 30, 2021. In the event that the lenders reduce the borrowing base below the amount drawn at the time of redetermination, the Company has 60 days to eliminate any shortfall by repaying amounts in excess of the new re-determined borrowing base.

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Subsequent to June 30, 2021, the lenders have extended the maturity date of the RCF from July 14 to August 13, 2021. The Company is actively engaged with the RCF lenders to further extend the maturities dates of RCF.

(b) Term Loan

At June 30, 2021 the Company had a $38.7 million Term Loan outstanding (December 31, 2020 – $36.5 million), which was due September 14, 2021. The Company has provided collateral by way of a debenture over all of the present and after acquired property of the Company. The Term Loan bears interest that accrues at a per annum rate of the (three-month) Canadian Dealer Offered Rate plus 975 basis points. All of the interest will be made by way of payment-in-kind ("PIK") and added to the outstanding balance of the Term Loan in lieu of monthly payment of cash interest.

Subsequent to June 30, 2021, the Company extended the maturity of the Term Loan to October 14, 2021.

Liquidity

At June 30, 2020, the Company had a working capital deficiency (excluding non-cash risk management assets and liabilities) of $110.3 million due to the Company's borrowings under its RCF and Term Loan classified as current liabilities. See note 2 and 5 of the Company's June 30, 2021 interim consolidated financial statements. The Company remains in compliance with all financial covenants pertaining to its debt. Subsequent to June 30, 2021, the Company had extended both the RCF and Term Loan to August 13, 2021 and October 14, 2021, respectively. It will continue to seek a longer term financing arrangement, which will eliminate or reduce in working capital deficiency.

Financial Covenants

The Company's RCF and Term Loan are subject to certain financial covenants. For the financial covenants' definitions and calculation methodology refer to the Company's Audited Consolidated Financial Statements as at and for the year ended December 31, 2020.

The key financial covenants are summarized in note 5 of the June 30, 2021 interim consolidated financial statements.

The following are the contractual maturities of financial liabilities as at June 30, 2021:

The following are the contractual maturities of financial liabilities as at June 30, 2021:
$000s Total < 1 year	1-5 years
Accounts payable and accrued liabilities 11,370 11,370 Risk management liability 8,936 8,936 Bank indebtedness and current portion of long term debt(1) 113,114 113,114 Lease obligations 918 202	—
	— — 716
Total 134,338 133,622	716

(1)Excludes deferred finance fees.

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

$000s	Total	< 1 year	1-5 years	> 5 years
Firm service transportation	12,482	2,045	9,309	1,128

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 8 and 13 of the Company’s June 30, 2021 interim consolidated financial statements.

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SUMMARY OF QUARTERLY RESULTS

SUMMARY OF QUARTERLY RESULTS
($000s unless otherwise noted)	Jun. 30, 2021 Mar. 31, 2021 Dec. 31, 2020 Sept. 30, 2020 Jun. 30, 2020 Mar. 31, 2020 Dec. 31, 2019 Sept. 30, 2019
Average Production Natural gas (mcf/d) Oil (bbl/d) NGLs (bbl/d)	24,291 22,985 26,177 26,181 27,630 30,604 32,641 30,998 1,214 923 980 1,103 867 1,134 1,834 1,247 1,046 1,158 1,014 997 819 1,088 1,018 1,372
Total (boe/d) Total (boe)	6,309 5,912 6,357 6,463 6,291 7,323 8,292 7,785 574,084 532,099 584,860 594,599 572,440 666,361 762,874 716,220
Financial Results Oil and natural gas revenue Royalty expense	19,553 16,339 14,143 12,840 9,041 14,344 20,998 12,517 (2,794) (1,989) (1,183) (1,245) (867) (1,899) (2,218) (1,182)
Net oil and natural gas revenue	16,759 14,350 12,960 11,595 8,174 12,445 18,780 11,335
Transportation expense Operating expense	(1,057) (863) (983) (967) (799) (703) (991) (893) (3,903) (3,254) (3,237) (2,408) (2,543) (3,035) (3,407) (3,181)
Operating netback	11,799 10,233 8,740 8,220 4,832 8,707 14,382 7,261
Realized gain (loss) on derivatives Other income General and administrative expense Cash finance expense Decommissioning expenditures	(1,843) (1,215) 381 1,308 3,656 1,174 (1,417) 360 1,018 23 184 23 99 48 7 21 (1,381) (876) (1,059) (635) (817) (898) (1,459) (776) (1,444) (1,029) (1,456) (1,286) (1,831) (2,089) (1,939) (2,230) (79) (143) (366) (79) (84) (376) (314) (209)
Corporate netback and funds flow	8,070 6,993 6,424 7,551 5,855 6,566 9,260 4,427
Oil and natural gas revenue Per share - basic Per share - fully diluted Net income (loss) Per share - basic Per share - fully diluted Common shares outstanding (000s) Basic Fully diluted Weighted average shares outstanding (000s) Basic Fully diluted Total assets Net debt	19,553 16,339 14,143 12,840 9,041 14,344 20,998 12,517 0.39 0.33 0.29 0.26 0.18 0.29 0.42 0.25 0.39 0.33 0.29 0.26 0.18 0.29 0.42 0.25 (4,265) 3,365 (151) (3,678) (6,281) (87,444) (3,176) (29,569) (0.09) 0.07 — (0.07) (0.13) (1.77) (0.06) (0.60) (0.09) 0.07 — (0.07) (0.13) (1.77) (0.06) (0.60) 49,559 49,469 49,469 49,469 49,469 49,469 49,469 49,469 49,559 49,469 49,469 49,469 49,469 49,469 49,469 49,469 49,513 49,469 49,469 49,469 49,469 49,469 49,469 49,469 49,513 49,469 49,469 49,469 49,469 49,469 49,469 49,469 176,629 177,587 177,914 179,895 184,532 193,679 289,225 296,367 (110,346) (116,634) (114,361) (116,717) (120,570) (125,974) (123,744) (128,553)

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 price differentials and production levels. Petrus’ average quarterly production decreased from 8,292 boe/d in the fourth quarter of 2019 to 6,309 boe/d in the second quarter of 2021. The 23% production decrease is attributable to Petrus' disciplined capital program, prioritizing debt repayment as well as certain production volumes in the Foothills area being shut-in due to uneconomic natural gas pricing.

Commodity price improvements enable higher reinvestment in exploration, development and acquisition activities as they increase the cash flows from operating activities. Commodity price reductions reduce revenues received and can challenge the economics of the Company's development program as the quantity of reserves may not be economically recoverable. Petrus' investment in its assets, and its ability to replace and grow reserve volumes, will be dependent on its ability to obtain debt and equity financing as well as the funds it receives from operations.

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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. 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, 2020.

In March 2020, the World Health Organization declared the COVID-19 outbreak a global pandemic. The rapid outbreak and subsequent measures intended to limit the spread of COVID-19 have contributed to a significant increase in economic uncertainty, with more volatile commodity prices, currency exchange rates and interest rates. The duration and severity of the business disruptions and reduction in consumer activity nationally and internationally and the resulting financial effect is difficult to reliably estimate. The results of the potential economic downturn and any potential resulting direct or indirect effect on the Company has been considered in management’s estimates at period end; however, there could be a further prospective material effect in future periods.

OTHER FINANCIAL INFORMATION

Significant accounting policies

The Company’s significant accounting policies can be read in note 3 of the Company’s audited consolidated financial statements as at and for the year ended December 31, 2020.

New standards and interpretations

The Company has not adopted any new standards and interpretations for the period ended June 30, 2021.

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 April 1, 2021 and ending on June 30, 2021 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 FINANCIAL MEASURES

This MD&A makes reference to the terms "operating netback", "funds flow and corporate netback" and "net debt". These indicators 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. Management uses these terms 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 at the oil and natural gas lease level. The most directly comparable

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GAAP measure to operating netback is funds flow. Operating netback is calculated as oil and natural gas revenue less royalties, operating and transportation expenses. It is presented on an absolute value and per unit basis.

Funds Flow and Corporate Netback

Corporate netback is a common non-GAAP financial measure used in the oil and natural gas industry which evaluates the Company’s profitability at the corporate level. Corporate netback is equal to funds flow which is a directly comparable GAAP measure. Petrus analyzes these measures on an absolute value and per unit basis. 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. It is calculated, in the following table, as the operating netback less general and administrative expense, finance expense, decommissioning expenditures, plus other income and the net realized gain (loss) on financial derivatives.

the net realized gain (loss) on financial derivatives.
Three months ended Jun. 30, 2021 Three months ended Jun. 30, 2020	Six months ended June 30, 2021 Six months ended June 30, 2020
$000s $/boe $000s $/boe	$000s $/boe $000s $/boe
Oil and natural gas revenue 19,553 34.06 9,041 15.79 Royalty expense (2,794) (4.87) (867) (1.51)	35,892 32.44 23,385 18.88 (4,783) (4.32) (2,766) (2.23)
Net oil and natural gas revenue 16,759 29.19 8,174 14.28	31,109 28.12 20,619 16.65
Transportation expense (1,057) (1.84) (799) (1.40) Operating expense (3,903) (6.80) (2,543) (4.44)	(1,920) (1.74) (1,502) (1.21) (7,157) (6.47) (5,578) (4.50)
Operating netback 11,799 20.55 4,832 8.44	22,032 19.91 13,539 10.94
Realized gain (loss) on financial derivatives (1,843) (3.21) 3,656 6.39 Other income 1,018 1.77 99 0.17 General & administrative expense (1,381) (2.41) (817) (1.43) Cash finance expense(1) (1,444) (2.52) (1,831) (3.20) Decommissioning expenditures (79) (0.14) (84) (0.15)	(3,058) (2.77) 4,830 3.90 1,041 0.94 147 0.12 (2,257) (2.04) (1,715) (1.38) (2,474) (2.24) (3,920) (3.16) (222) (0.20) (459) (0.37)
Funds flow and corporate netback 8,070 14.04 5,855 10.22	15,062 13.60 12,422 10.05

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

Net Debt

Net debt is a non-GAAP financial measure and is calculated as current assets (excluding unrealized financial derivative assets) less current liabilities (excluding unrealized financial derivative liabilities, right-of-use lease obligations, and deferred share unit liabilities) and long term debt. Petrus uses net debt as a key indicator of its leverage and strength of its balance sheet. There is no GAAP measure that is reasonably comparable to net debt.

reasonably comparable to net debt.
($000s)	As at June 30, 2021	As at December 31, 2020
Adjusted current assets(1)	14,138	7,428
Less: adjusted current liabilities(1)	(124,484)	(121,789)
Net debt	(110,346)	(114,361)

(1)Adjusted for unrealized risk management assets, liabilities, lease obligations and unrealized deferred share unit liabilities.

OIL AND GAS DISCLOSURES

Our oil and gas reserves statement for the year ended December 31, 2020, which includes disclosure of our oil and natural gas reserves and other oil and natural gas information in accordance with NI 51-101, is contained in the AIF. The recovery and reserve estimates contained herein are estimates only and there is no guarantee that the estimated reserves will be recovered.

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

While the references in this document to initial production rates are useful in confirming the presence of hydrocarbons, such rates are not determinative of the rates at which such wells will continue production and decline thereafter. Additionally, such rates may also include recovered "load oil" fluids used in well completion stimulation. While encouraging, readers are cautioned not to place reliance on such rates in calculating the aggregate production for the Company. In all cases in this document, initial

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production results are not necessarily indicative of long-term performance of the relevant wells or of ultimate recovery of hydrocarbons.

ADVISORIES

Basis of Presentation

Financial data presented above has largely been derived from the Company’s financial statements, prepared in accordance with GAAP which require publicly accountable enterprises to prepare their financial statements using IFRS. Accounting policies adopted by the Company are set out in the notes to the consolidated financial statements as at and for the twelve months ended December 31, 2019. The reporting and the measurement currency is the Canadian dollar. All financial information is expressed in Canadian dollars, unless otherwise stated.

Forward-Looking Statements

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

In particular, forward-looking statements included in this MD&A include, but are not limited to, statements with respect to: prospective changes to the terms of the RCF and Term Loan; Petrus' capital program, flexibility and utilization of free cash flow; Petrus' utilization of Federal and Provincial programs; Petrus' expectations regarding second half 2021 production volumes; Petrus' ability to modify its operations, including its ability to adjust liquid volumes and the results thereof; expectations regarding the adequacy of Petrus' liquidity and the funding of its financial liabilities; the impact of the current economic environment on Petrus; the performance characteristics of the Company's crude oil, NGL and natural gas properties; future prospects; the focus of and timing of capital expenditures; access to debt and equity markets; Petrus' future operating and financial results; capital investment programs; supply and demand for crude oil, NGL and natural gas; future royalty rates; drilling, development and completion plans and the results therefrom; and treatment under governmental regulatory regimes and tax laws. In addition, statements relating to “reserves” are deemed to be forward-looking statements, as they involve the implied assessment, based on certain estimates and assumptions, that the reserves described can be profitably produced in the future.

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

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This MD&A contains future-oriented financial information and financial outlook information (collectively, "FOFI") about Petrus' prospective results of operations including, without limitation, its ability to repay debt, which are subject to the same assumptions, risk factors, limitations, and qualifications as set forth above. Readers are cautioned that the assumptions used in the preparation of such information, although considered reasonable at the time of preparation, may prove to be imprecise and, as such, undue reliance should not be placed on FOFI. Petrus' actual results, performance or achievement could differ materially from those expressed in, or implied by, these FOFI, or if any of them do so, what benefits Petrus will derive therefrom. Petrus has included the FOFI in order to provide readers with a more complete perspective on Petrus' future operations and such information may not be appropriate for other purposes.

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

BOE Presentation

The oil and natural gas industry commonly expresses production volumes and reserves on a barrel of oil equivalent (“boe”) basis whereby natural gas volumes are converted at the ratio of six thousand cubic feet to one barrel of oil. The intention is to sum oil and natural gas measurement units into one basis for improved measurement of results and comparisons with other industry participants. Petrus uses the 6:1 boe measure which is the approximate energy equivalence of the two commodities at the burner tip. Boe’s do not represent an economic value equivalence at the wellhead and therefore may be a misleading measure if used in isolation.

Abbreviations

$000’s 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 bbl/d barrels per day boe barrel of oil equivalent mboe barrel of oil equivalent mmboe thousand barrel of oil equivalent boe/d million 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 NGLs natural gas liquids WTI West Texas Intermediate

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