Petrus Resources Ltd. — Interim / Quarterly Report 2020

Nov 12, 2020

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MANAGEMENT'S DISCUSSION & ANALYSIS September 30, 2020

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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 and nine months ended September 30, 2020. This MD&A is dated November 10, 2020 and should be read in conjunction with the Company's audited consolidated financial statements for the years ended December 31, 2019 and 2018 as well as the Company's interim consolidated financial statements as at September 30, 2020. The Company’s audited 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 Sept. 30, 2020 Three months ended Sept. 30, 2019	Three months ended Jun. 30, 2020 Three months ended Mar. 31, 2020 Three months ended Dec. 31, 2019
Average Production Natural gas (mcf/d) 26,181 30,998 Oil (bbl/d) 1,103 1,247 NGLs (bbl/d) 997 1,372	27,630 30,604 32,641 867 1,134 1,834 819 1,088 1,018
Total (boe/d) 6,463 7,785 Total (boe) 594,599 716,220	6,291 7,323 8,292 572,440 666,361 762,874
Light oil weighting 17 % 16 %	14 % 15 % 22 %
Realized Prices Natural gas ($/mcf) 2.51 1.12 Oil ($/bbl) 46.46 65.64 NGLs ($/bbl) 22.05 11.49	2.35 2.40 2.65 27.18 50.02 65.16 12.87 23.19 20.62
Total realized price ($/boe) 21.48 16.99	15.73 21.23 27.39
Royalty revenue 0.12 0.48 Royaltyexpense (2.09) (1.65)	0.06 0.30 0.13 (1.51) (2.85) (2.91)
Net oil and natural gas revenue ($/boe) 19.51 15.82	14.28 18.68 24.61
Operating expense (4.05) (4.44) Transportation expense (1.63) (1.25)	(4.44) (4.55) (4.47) (1.40) (1.05) (1.30)
Operating netback(1)($/boe) 13.83 10.13	8.44 13.08 18.84
Realized gain (loss) on derivatives ($/boe) 2.20 0.50 Other income 0.04 0.03 General & administrative expense (1.07) (1.08) Cash finance expense (2.16) (3.11) Decommissioning expenditures (0.13) (0.29)	6.39 1.76 (1.86) 0.17 0.07 — (1.43) (1.35) (1.91) (3.20) (3.13) (2.54) (0.15) (0.56) (0.41)
Funds flow & corporate netback(1)(2) ($/boe) 12.71 6.18	10.22 9.87 12.12
FINANCIAL (000s except $ per share) Three months ended Sept. 30, 2020 Three months ended Sept. 30, 2019	Three months ended Jun. 30, 2020 Three months ended Mar. 31, 2020 Three months ended Dec. 31, 2019
Oil and natural gas revenue 12,840 12,517 Net loss (3,678) (29,569) Net loss per share Basic (0.07) (0.60) Fully diluted (0.07) (0.60) Funds flow 7,551 4,427 Funds flow per share Basic 0.15 0.09 Fully diluted 0.15 0.09 Capital expenditures 2,543 2,734 Net dispositions — 651 Weighted average shares outstanding Basic 49,469 49,469 Fully diluted 49,469 49,469 As at period end Common shares outstanding Basic 49,469 49,469 Fully diluted 49,469 49,469 Total assets 179,895 296,367 Non-current liabilities 44,471 82,650 Net debt(1) 116,717 128,553	9,041 14,344 20,998 (6,281) (87,444) (3,332) (0.13) (1.77) (0.06) (0.13) (1.77) (0.06) 5,855 6,566 9,260 0.12 0.13 0.19 0.12 0.13 0.19 305 8,655 4,351 — — — 49,469 49,469 49,469 49,469 49,469 49,469 49,469 49,469 49,469 49,469 49,469 49,469 184,532 193,679 289,225 43,017 38,533 42,346 120,570 125,974 123,744

(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

Third quarter average production by area was as follows:

Third quarter average production by area was as follows:	Third quarter average production by area was as follows:
For the three months ended September 30, 2020 Ferrier Foothills Central Alberta Total
Natural gas (mcf/d) 20,028 1,251 Oil (bbl/d) 717 100 NGLs(bbl/d) 839 5	5,194 26,473 245 1,062 145 989
Total(boe/d) 4,894 313 1,256 6,463

Third quarter production averaged 6,463 boe/d compared to 6,291 boe/d in the second quarter of 2020. The increase is due to additional volumes from the two Cardium wells drilled in the first quarter of the year. These wells were intentionally restricted late in the first quarter due to depressed commodity prices but were returned to higher production rates in July. Third quarter production volumes were impacted by the scheduled 2.5 day turnaround at the Ferrier 2-25 gas plant in late September as well as turnaround work at a partner operated facility in the Foothills area; management estimates the impact on third quarter volumes to be approximately 170 boe/d.

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.

The Company did resume drilling activity late in the third quarter as management accelerated a planned fourth quarter drilling operation to take advantage of favorable fall weather conditions. The completion and tie in of this well will comprise the majority of the $2.5 million in capital spending planned for the remainder of the year. With the high level of control afforded by operated assets and ownership of key infrastructure, the Company can adjust liquids content in the natural gas stream to maximize profitability of all products as well as adjust production rates quickly to respond to changing market conditions. With current pricing, new wells drilled in Petrus' core area of Ferrier can deliver payouts in under one year.

Petrus received support benefits from the Canada Emergency Wage Subsidy program and has made successful applications for grants under the Alberta Site Rehabilitation Program. The Company will continue to pursue programs announced by the Federal and Provincial Governments to support Canadian businesses, and the oil and gas industry specifically through the COVID-19 pandemic.

CAPITAL EXPENDITURES

Capital expenditures (excluding acquisitions and dispositions) totaled $2.5 million in the third quarter of 2020, which is consistent with the $2.7 million spent in the prior year comparative period. The Company participated in the drilling of 4 gross (3.0 net) light oil wells during the first nine months of 2020, compared to 7 gross (3.1 net) light oil wells during the first nine months of 2019.

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

obligations.
Capital Expenditures ($000s) Three months ended September 30, 2020 Three months ended September 30, 2019	Nine months ended September 30, 2020 Nine months ended September 30, 2019
Drill and complete 2,250 2,305 Oil and gas equipment — 40 Land and lease 5 — Capitalized general and administrative expense 288 389	9,881 9,736 765 2,855 35 19 820 1,146
Total capital expenditures 2,543 2,734	11,501 13,756
Gross (net) wells spud 1 (1.0) 4 (1.2)	4 (3.0) 7 (3.1)

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RESULTS OF OPERATIONS

FINANCIAL AND OPERATIONAL RESULTS OF OIL AND NATURAL GAS ACTIVITIES

	Three months ended Sept. 30, 2020 Three months ended Sept. 30, 2019	Three months ended Jun. 30, 2020 Three months ended Mar. 31, 2020 Three months ended Dec. 31, 2019
Average production Natural gas (mcf/d) Oil (bbl/d) NGLs (bbl/d)	26,181 30,998 1,103 1,247 997 1,372	27,630 30,604 32,641 867 1,134 1,834 819 1,088 1,018
Total (boe/d) Total (boe)	6,463 7,785 594,599 716,220	6,291 7,323 8,292 572,440 666,361 762,874
Revenue ($000s) Natural gas Oil NGLs Royalty revenue	6,035 3,192 4,714 7,529 2,022 1,450 69 346	5,903 6,690 7,970 2,143 5,161 10,995 959 2,296 1,931 36 197 102
Oil and natural gas revenue	12,840 12,517	9,041 14,344 20,998
Average realized prices Natural gas ($/mcf) Oil ($/bbl) NGLs ($/bbl)	2.51 1.12 46.46 65.64 22.05 11.49	2.35 2.40 2.65 27.18 50.02 65.16 12.87 23.19 20.62
Total realized price ($/boe) Hedging gain (loss) ($/boe)	21.48 16.99 2.20 0.50	15.73 21.23 27.39 6.39 1.76 (1.86)
Total price including hedging ($/boe)	23.68 17.49	22.12 22.99 25.53
Average benchmark prices	Three months ended Sept. 30, 2020 Three months ended Sept. 30, 2019	Three months ended Jun. 30, 2020 Three months ended Mar. 31, 2020 Three months ended Dec. 31, 2019
Natural gas AECO 5A (C$/GJ) AECO 7A (C$/GJ) Crude oil Mixed Sweet Blend Edm (C$/bbl) Natural gas liquids Propane Conway (US$/bbl) Butane Edmonton (C$/bbl)	2.02 0.87 2.04 0.99 48.96 69.21 19.78 15.56 19.04 24.78	1.89 1.93 2.35 1.81 2.03 2.21 32.17 52.28 66.81 14.54 15.40 19.78 14.56 42.42 36.96
Foreign exchange US$/C$	0.74 0.76	0.74 0.74 0.76

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FUNDS FLOW AND NET LOSS

Petrus generated funds flow of $7.6 million in the third quarter of 2020 compared to $4.4 million in the third quarter of 2019. The 71% increase is due to higher natural gas prices and lower operating costs. In the third quarter Petrus' total realized price was $21.48/boe compared to $16.99/boe in the third quarter of 2019.

Petrus reported a net loss of $3.7 million in the third quarter of 2020, compared to $29.6 million in the third quarter of 2019. The net loss in the third quarter of 2020 is primarily due to decreased production and lower oil prices primarily due to the ongoing COVID-19 pandemic.

On a nine month basis, the Company generated a net loss of $97.4 million for the nine months ended September 30, 2020 compared to a net loss of $38.8 million for the nine months ended September 30, 2019. The increase in net loss is due to the $98 million impairment charge booked during the first quarter of 2020.

($000s except per share) Three months ended September 30, 2020 Three months ended September 30, 2019	Nine months ended September 30, 2020 Nine months ended September 30, 2019
Funds flow 7,551 4,427 Funds flow per share - basic 0.15 0.09 Funds flow per share - fully diluted 0.15 0.09	19,974 24,365 0.40 0.49 0.40 0.49
Net loss (3,678) (29,569) Net loss per share - basic (0.07) (0.60) Net loss per share - fully diluted (0.07) (0.60)	(97,403) (38,844) (1.97) (0.79) (1.97) (0.79)
Common shares outstanding (000s) Basic 49,469 49,469 Fully diluted 49,469 49,469	49,469 49,469 49,469 49,469
Weighted average shares outstanding (000s) Basic 49,469 49,469 Fully diluted 49,469 49,469	49,469 49,472 49,469 49,472

OIL AND NATURAL GAS REVENUE

Third quarter average production in 2020 was 6,463 boe/d (68% natural gas), 17% lower than the third quarter of 2019 (7,785 boe/d; 66% natural gas). Third quarter oil and natural gas revenue in 2020 was $12.8 million compared to $12.5 million in 2019. The 3% increase is due to higher natural gas prices partially offset by lower production.

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

Production Volume by Product (%) Three months ended September 30, 2020 Three months ended September 30, 2019	Nine months ended September 30, 2020 Nine months ended September 30, 2019
Natural gas 68 % 66 % Crude oil and condensate 17 % 16 % Natural gas liquids 15 % 18 %	70 % 64 % 15 % 19 % 15 % 17 %
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 September 30, 2020 Three months ended September 30, 2019 % Change	Nine months ended September 30, 2020 Nine months ended September 30, 2019 % Change
Natural gas 6,035 3,192 89 % Crude oil and condensate 4,714 7,529 (37) % Natural gas liquids 2,022 1,450 39 % Royalty revenue 69 346 (80) %	18,628 14,082 32 % 12,018 26,820 (55) % 5,277 8,986 (41) % 302 512 (41) %
Total oil and natural gas revenue 12,840 12,517 **3 % **	36,225 50,400 (28) %

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

Three months ended September 30, 2020 Three months ended September 30, 2019 % Change	Nine months ended September 30, 2020 Nine months ended September 30, 2019 % Change
Average benchmark prices Natural gas AECO 5A (C$/GJ) 2.02 0.86 135 % AECO 7A (C$/GJ) 2.04 0.99 106 % Crude oil Mixed Sweet Blend Edm (C$/bbl) 48.96 69.21 (29) % Natural gas liquids Propane Conway (US$/bbl) 19.78 15.56 27 % Butane Edmonton (C$/bbl) 19.04 24.78 (23) %	1.95 1.44 35 % 1.96 1.31 50 % 44.47 69.78 (36) % 16.57 20.52 (19) % 25.34 16.61 53 %
Average realized prices Natural gas ($/mcf) 2.51 1.12 124 % Oil ($/bbl) 46.46 65.64 (29) % NGLs ($/bbl) 22.05 11.49 92 %	2.42 1.62 49 % 42.39 63.69 (33) % 19.90 22.49 (12) %
Total average realized price 21.48 16.99 **26 % **	19.59 21.99 (11) %

Natural gas

Natural gas revenue for the nine months ended September 30, 2020 was $18.6 million which accounted for 52% of oil and natural gas revenue, compared to revenue of $14.1 million, which accounted for 28% in the prior year comparative period. The increase is due to 135% higher natural gas pricing (AECO 5A), partially offset by lower natural gas production.

Third quarter 2020 average realized natural gas price was $2.51/mcf, compared to $1.12/mcf in the third quarter of 2019 (124% increase). Due to low NGL pricing during the third quarter of 2020, Petrus modified the processing conditions at its gas plant in order to maximize profitability and received a premium in comparison to index prices due to the higher heat content of its natural gas.

Crude oil and condensate

Oil and condensate revenue for the nine months ended September 30, 2020 was $12.0 million, which accounted for approximately 33% of oil and natural gas revenue, compared to revenue of $26.8 million, which accounted for 54% in the prior year comparative period.

The average realized price of Petrus’ light oil and condensate was $46.46/bbl for the third quarter of 2020 compared to $65.64/bbl in the third quarter of 2019. The decrease of 29% is attributable to the decrease in oil prices primarily due to 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 third quarter of 2020, the Company's realized NGL price averaged $22.05/bbl, compared to $11.49/bbl in the prior year. The 92% increase is attributed to higher contract prices for the NGL byproducts. Third quarter market pricing for propane at Conway increased 27% from the prior year. Petrus' butane production is priced as a function of WTI (oil) which also increased in the third 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 nine months ended September 30, 2020 was $5.3 million and accounted for 15% of oil and natural gas revenue, compared to revenue of $9.0 million accounting for 18% in the prior year comparative period. The decrease was due to lower 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	Nine months ended	Nine months ended
Royalty Expense ($000s)
	September 30, 2020	September 30, 2019	September 30, 2020	September 30, 2019
Crown	498	599	1,340	2,066
Percent of production revenue	4 %	5 %	4 %	4 %
Gross overriding	747	583	2,671	2,830
Total	1,245	1,182	4,011	4,896

Third quarter royalty expense of $1.2 million in 2020 was consistent with the prior year comparative period. On a nine month basis, total royalty expense (net of royalty allowances and incentives) decreased from $4.9 million in 2019 to $4.0 million in 2020. The decrease is due to lower oil prices and more favorable royalty rates.

Gross overriding royalties increased from $0.6 in the third quarter of 2019 to $0.7 million in the third quarter of 2020, due to higher natural gas and NGL pricing. Gross overriding royalties decreased from $2.8 million for the nine months ended September 30, 2019 to $2.7 million for the nine months ended September 30, 2020, due to decreased production and oil prices.

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. 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 September 30, 2020 Three months ended September 30, 2019	Nine months ended September 30, 2020 Nine months ended September 30, 2019
Realized hedging gain 1,308 360 Unrealized hedging gain (loss) (4,183) 1,368	6,138 73 1,170 (7,605)
Net gain (loss) on derivatives (2,875) 1,728	7,308 (7,532)

In the third quarter of 2020, the Company recognized a realized hedging gain of $1.3 million, compared to a $0.4 million gain in the third quarter of 2019. The realized gain was due to lower oil prices (relative to the respective contracts outstanding). The realized gain in the third quarter of 2020 increased the Company’s total realized price by $2.20/boe, compared to a decrease of $0.50/boe in 2019. The Company recognized a realized hedging gain of $6.1 million during the nine months ended September 30, 2020, in comparison to the $0.1 million gain realized in the same period of the prior year. The realized gain is due to lower oil prices than active hedging contracts.

During the third quarter of 2020, the Company recognized an unrealized loss of $4.2 million whereas during the third quarter of 2019 a $1.4 million unrealized gain was recorded. The unrealized loss recognized in the third quarter of 2020 is due to higher market natural gas prices than the prices on Petrus' hedge contracts.

The unrealized hedging gain of $1.2 million for the nine months ended September 30, 2020 (unrealized loss of $7.6 million for the nine months ended September 30, 2019) represents the change in the unrealized risk management net asset position during the first nine months of 2020. 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.

The Company’s risk management contracts provide protection from significant changes in crude oil and natural gas commodity prices for 2020, 2021 and 2022. The Company endeavors to hedge approximately half of its forecast production for the following year. The

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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 9 of the Company’s interim consolidated financial statements as at and for the period ended September 30, 2020. The table below summarizes Petrus’ average crude oil and natural gas hedged volumes. The average volume of oil hedged for the remainder of 2020 (750 bbl/d) represents 36% of third quarter 2020 average oil and natural gas liquids production. The 15,500 GJ/day average natural gas hedged for the remainder of 2020 represents 62% of third quarter 2020 average natural gas production.

The following table summarizes the average and minimum and maximum cap and floor prices for the 2020 to 2022 oil and natural gas contracts outstanding as at September 30, 2020:

	2020		2021	2022	2022
	Q1 Q2 Q3 Q4	Avg.(1)	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)	1,450 1,150 950 750 73.23 76.33 76.71 75.12 73.23 76.33 76.71 75.12	1,075	500 300 300 300 72.83 74.02 72.80 72.80 72.83 74.02 72.80 72.80	350	— — — — — — — — — — — — — — —
		75.16 75.16		73.07 73.07
Natural gas hedged (GJ/d) Avg. AECO 7A cap price ($C/GJ) Avg. AECO 7A floor price ($C/GJ)	15,500 15,167 15,022 15,500 1.76 1.58 1.61 1.91 1.76 1.58 1.61 1.91	15,297	15,000 11,000 9,000 5,667 2.05 1.98 1.84 2.27 2.05 1.98 1.84 2.27	10,167	4,000 — — —1,000 2.48 — — — 2.48 2.48 — — — 2.48
		1.72 1.72		2.02 2.02

(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 ($000s) Three months ended September 30, 2020 Three months ended September 30, 2019	Nine months ended September 30, 2020 Nine months ended September 30, 2019
Fixed and variable operating expense 2,010 2,456 Processing, gathering and compression charges 631 980	6,669 7,860 1,983 2,340
Total gross operating expense 2,641 3,436 Overhead recoveries (233) (255)	8,652 10,200 (666) (734)
Total net operating expense 2,408 3,181 Operating expense, net ($/boe) 4.05 4.44	7,986 9,466 4.36 4.17

For the three months ended September 30, 2020, net operating expense totaled $2.4 million, a 24% decrease from $3.2 million during the prior year comparative period. The decrease is attributable to Petrus' improved operating cost structure and decreased activity related to well workover projects. On a per boe basis it was 9% lower at $4.05/boe in the third quarter of 2020 compared to $4.44/boe in 2019.

For the nine months ended September 30, 2020, net operating expense totaled $8.0 million, a 16% decrease from the $9.5 million incurred in the comparable period of the prior year. On a per boe basis, operating expense for the nine months ended September 30, 2020 was 5% higher at $4.36/boe in the third quarter of 2020 compared to $4.17/boe in 2019 due to lower production in 2020.

TRANSPORTATION EXPENSE

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

Transportation Expense ($000s) Three months ended September 30, 2020 Three months ended September 30, 2019	Nine months ended September 30, 2020 Nine months ended September 30, 2019
Transportation expense 967 893 Transportation expense ($/boe) 1.63 1.25	2,469 2,823 1.35 1.24

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 September 30, 2020 transportation expense was $1.0 million or $1.63/boe compared to $0.9 million or $1.25/boe in the prior year comparative period. The increase in total transportation expense is attributed to the pipeline firm transportation contract that began in the second quarter of 2020.

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On a nine month basis, transportation expense totaled $2.5 million, or $1.35/boe for 2020, which is 13% lower and 9% higher, respectively, than the costs incurred ($2.8 million or $1.24/ boe) in the prior year comparative period. The decrease in total transportation expense is attributed to decreased tolls on midstream pipelines, decreased NGL volume transported by trucking and lower production.

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:

related to exploration and development activities:
General and Administrative Expense ($000s) Three months ended September 30, 2020 Three months ended September 30, 2019	Nine months ended September 30, 2020 Nine months ended September 30, 2019
Personnel, consultants and directors 569 706 Administrative expenses 335 268 Regulatory and professional expenses 33 264	1,989 2,643 802 933 792 671
Gross general and administrative expense 937 1,238 Capitalized general and administrative expense (214) (336) Overhead recoveries (88) (126)	3,583 4,247 (739) (1,067) (494) (995)
General and administrative expense 635 776 General and administrative expense ($/boe) 1.07 1.08	2,350 2,185 1.28 0.96

G&A expense (net of capitalized G&A expense and overhead recoveries) for the third quarter of 2020 totaled $0.6 million or $1.07/boe, compared to $0.8 million or $1.08/boe in the third quarter of 2019. Gross G&A expense (before capitalized G&A expense and overhead recoveries) was 24% lower than the prior year ($0.9 million in the third quarter of 2020 compared to $1.2 million in the third quarter of 2019). G&A expense is lower due to lower staffing levels and the federal wage subsidy program.

For the nine months ended September 30, 2020, gross G&A expense was $3.6 million compared to $4.2 million in the prior year comparative period, which represents a 16% decrease. Third quarter G&A expense in 2020 was $2.4 million or $1.28/boe which is higher than the $2.2 million or $0.96/boe in the third quarter of 2019 (33% increase on a per boe basis due to 17% lower production).

The net increases are attributed to lower overhead recoveries while the gross G&A decreases are due to lower office rent expense and staffing costs as a result of lower staffing levels and the federal wage subsidy program.

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:

exploration and development activities:
Share-Based Compensation Expense ($000s) Three months ended September 30, 2020 Three months ended September 30, 2019	Nine months ended September 30, 2020 Nine months ended September 30, 2019
Gross share-based compensation expense 163 113 Capitalized share-based compensation expense (19) (45)	320 404 (82) (162)
Share-based compensation expense 144 68	238 242

Share-based compensation expense (net of capitalized portion) was $0.14 million for the third quarter of 2020, which is 111% higher than the $0.07 million recognized in the third quarter of the prior year.

For the nine months ended September 30, 2020, net share-based compensation expense was $0.24 million, which is consistent with the prior year comparative period.

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FINANCE EXPENSE

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

Finance Expense ($000s) Three months ended September 30, 2020 Three months ended September 30, 2019	Nine months ended September 30, 2020 Nine months ended September 30, 2019
Interest expense 1,286 2,230 Deferred financing costs 236 117 Non-cash term loan interest payment-in-kind 877 — Accretion on decommissioning obligations 95 189	5,205 6,302 480 374 877 — 387 601
Total finance expense 2,494 2,536	6,949 7,277

Third quarter total finance expense was $2.5 million in 2020, comprised of $0.1 million of non-cash accretion of its decommissioning obligations, $1.3 million of cash interest expense, $0.2 million of deferred financing fee amortization and $0.9 million of non-cash term loan interest payment-in-kind, all of which are related to the RCF and Term Loan (as such terms terms are defined below). In the third quarter of 2019, the Company incurred total finance expense of $2.5 million, comprised of $0.2 million in non-cash accretion of its decommissioning obligation, $2.2 million cash interest expense and $0.1 million of deferred financing fee amortization. The decrease in total finance expense from the prior year comparative period is due to a lower RCF balance outstanding.

The Company incurred total finance expense of $6.9 million for the nine months ended September 30, 2020, which is lower than the $7.3 million for the prior year comparative period. This is due to a lower RCF balance outstanding.

DEPLETION AND DEPRECIATION

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

Depletion and Depreciation Expense ($000s) Three months ended September 30, 2020 Three months ended September 30, 2019	Nine months ended September 30, 2020 Nine months ended September 30, 2019
Depletion and depreciation expense 5,759 8,895 Depletion and depreciation expense ($/boe) 9.69 12.42	19,110 27,829 10.42 12.27

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 third quarter of 2020 of $5.8 million or $9.69 per boe, compared to the third quarter of 2019, when $8.9 million or $12.42 per boe was recorded. For the nine months ended September 30, 2020, the Company recorded $19.1 million or $10.42 per boe, compared to $27.8 million or $12.27 per boe for the prior year. The decreases are due to lower production volume and the impairment charge recorded in the first quarter of 2020 that reduced the depreciation expense per boe.

IMPAIRMENT

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

Impairment ($000s)	Three months ended September 30, 2020 Three months ended September 30, 2019	Nine months ended September 30, 2020 Nine months ended September 30, 2019
Impairment	— 24,655	98,000 24,655
Total	— 24,655	98,000 24,655

Petrus recognized an impairment loss of $98.0 million in the Ferrier CGU during the nine months ended September 30, 2020, compared to $24.7 million in the prior year comparative period. The impairment booked in the first quarter of 2020 was 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 4 and 5 of the September 30, 2020 interim 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:

periods shown:
Share Capital (000s)	Three months ended September 30, 2020 Three months ended September 30, 2019	Nine months ended September 30, 2020 Nine months ended September 30, 2019
Weighted average common shares outstanding Basic Fully diluted Common shares outstanding Basic Fully diluted Stock options outstanding	49,469 49,469 49,469 49,469 49,469 49,469 49,469 49,469 1,908 2,343	49,469 49,472 49,469 49,472 49,469 49,469 49,469 49,469 1,908 2,343

At September 30, 2020, the Company had 49,469,358 common shares and 1,907,826 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 September 30, 2020, 1,673,164 DSUs were issued and outstanding (December 31, 2019 – 1,177,510). 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.

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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 “RCF”). The second is a subordinated secured term loan (the “Term Loan”).

(a) Revolving Credit Facility

At September 30, 2020, the RCF was comprised of a $20 million operating facility and a $65.8 million syndicated term-out facility. The Company has provided collateral by way of a debenture over all of the present and after acquired property of the Company. The RCF's maturity date is May 31, 2021.

At September 30, 2020, the Company had a $0.6 million letter of credit outstanding against the RCF (December 31, 2019 – $0.7 million) and had drawn $80.3 million against the RCF (December 31, 2019 – $92.3 million).

In July 2020, the Company completed its annual RCF review. The borrowing base of the RCF was updated to $88.5 million, with a maturity date of May 31, 2021. The borrowing base of the RCF is required to reduce by $2.75 million at the end of each fiscal quarter. The RCF extension includes the removal of the Total Debt to Adjusted EBITDA ratio as well as the Proved and PDP Asset Coverage Ratios from the financial covenants, and the Working Capital ratio covenant has been updated to a minimum test of 0.6:1.0 (or such lower amount as agreed to by the majority of the lenders under the RCF which shall not be less than 0.5:1.0). As part of the RCF extension the Bankers Acceptance Stamping fees will range between 350 bps and 600 bps which will result in an increase in the RCF interest rate of between 150 bps and 250 bps.

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. In the event that the lenders reduce the borrowing base below the amount drawn at the time of redetermination, the Company has 30 days to eliminate any shortfall by repaying amounts in excess of the new re-determined borrowing base.

Subsequent to September 30, 2020, the lenders reconfirmed the Company's borrowing base at $85.8 million.

(b) Term Loan

At September 30, 2020 the Company had a $36 million (December 31, 2019 – $35 million) Term Loan outstanding (excluding $0.4 million of unamortized deferred financing costs), which is due July 31, 2021. The Company has provided collateral by way of a debenture over all of the present and after acquired property of the Company.

In July 2020, the Company extended the maturity of the Term Loan to July 31, 2021. 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. The Term Loan extension also includes the removal of the Total Debt to EBITDA ratio as well as the Proved and PDP Asset Coverage Ratios from the financial covenants. The Working Capital ratio covenant has been updated to a minimum test of 0.6:1.0 (or such lower amount as agreed to by the lenders under the Term Loan which shall not be less than 0.5:1.0).

Liquidity

At September 30, 2020, the Company had a working capital deficiency (excluding non-cash risk management assets and liabilities) of $116.7 million due to the classification of the Company's borrowings under its RCF and Term Loan as current liabilities. See note 2 of the Company's September 30, 2020 interim consolidated financial statements. However, the Company remains in compliance with all financial covenants pertaining to its debt.

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, 2019.

The key financial covenants as at September 30, 2020 are summarized in the following table. At September 30, 2020 the Company is in compliance with all financial covenants.

Financial Covenant Description	Required Ratio	As at September 30, 2020
WorkingCapital Ratio	Over 0.60	1.49

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The following are the contractual maturities of financial liabilities as at September 30, 2020:

$000s	Total	< 1 year	1-5 years
Accounts payable and accrued liabilities	7,978	7,978	—
Risk management liability	2,494	1,872	622
Bank indebtedness and current portion of long term debt(1)	116,178	116,178	—
Lease obligations	1,248	262	986
Total	127,898	126,290	1,608

(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	14,211	2,152	10,364	1,695

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 9 and 14 of the Company’s September 30, 2020 interim consolidated financial statements.

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SUMMARY OF QUARTERLY RESULTS

SUMMARY OF QUARTERLY RESULTS
($000s unless otherwise noted)	Sept. 30, 2020 Jun. 30, 2020 Mar. 31, 2020 Dec. 31, 2019 Sept. 30, 2019 Jun. 30, 2019 Mar. 31, 2019 Dec. 31, 2018
Average Production Natural gas (mcf/d) Oil (bbl/d) NGLs (bbl/d)	26,181 27,630 30,604 32,641 30,998 32,350 32,145 30,480 1,103 867 1,134 1,834 1,247 1,679 1,704 1,358 997 819 1,088 1,018 1,372 1,576 1,444 1,496
Total (boe/d) Total (boe)	6,463 6,291 7,323 8,292 7,785 8,647 8,505 7,934 594,599 572,440 666,361 762,874 716,220 786,819 765,488 730,819
Financial Results Oil and natural gas revenue Royalty expense	12,840 9,041 14,344 20,998 12,517 17,652 20,231 16,064 (1,245) (867) (1,899) (2,218) (1,182) (1,355) (2,359) (2,436)
Net oil and natural gas revenue	11,595 8,174 12,445 18,780 11,335 16,297 17,872 13,628
Transportation expense Operating expense	(967) (799) (703) (991) (893) (959) (971) (855) (2,408) (2,543) (3,035) (3,407) (3,181) (3,405) (2,880) (3,851)
Operating netback	8,220 4,832 8,707 14,382 7,261 11,933 14,021 8,922
Realized gain (loss) on derivatives Other income General and administrative expense Cash finance expense Decommissioning expenditures	1,308 3,656 1,174 (1,417) 360 (800) 513 (573) 23 99 48 7 21 78 — 268 (635) (817) (898) (1,459) (776) (530) (879) (1,065) (1,286) (1,831) (2,089) (1,939) (2,230) (2,126) (1,945) (2,370) (79) (84) (376) (314) (209) (189) (137) (152)
Corporate netback and funds flow	7,551 5,855 6,566 9,260 4,427 8,366 11,573 5,030
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(1)	12,840 9,041 14,344 20,998 12,517 17,652 20,231 16,064 0.26 0.18 0.29 0.42 0.25 0.36 0.41 0.32 0.26 0.18 0.29 0.42 0.25 0.36 0.41 0.32 (3,678) (6,281) (87,444) (3,176) (29,569) 2,863 (12,138) 21,063 (0.07) (0.13) (1.77) (0.06) (0.60) 0.06 (0.25) 0.43 (0.07) (0.13) (1.77) (0.06) (0.60) 0.06 (0.25) 0.43 49,469 49,469 49,469 49,469 49,469 49,469 49,469 49,492 49,469 49,469 49,469 49,469 49,469 49,469 49,469 49,492 49,469 49,469 49,469 49,469 49,469 49,469 49,483 49,492 49,469 49,469 49,469 49,469 49,469 49,469 49,483 49,492 179,895 184,532 193,679 289,225 296,367 328,912 336,974 341,820 (116,717) (120,570) (125,974) (123,744) (128,553) (130,619) (136,382) (139,214)

(1)Refer to "Non-GAAP 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 price differentials and production levels. Petrus’ average quarterly production decreased from 7,934 boe/d in the fourth quarter of 2018 to 6,463 boe/d in the third quarter of 2020. The 19% production decrease is attributable to Petrus' shift in focus to liquids production growth in order to maximize value in light of the current natural gas commodity price environment as well as certain development activity postponed to prioritize debt repayment.

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, 2019.

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, 2019.

New standards and interpretations

The Company has not adopted any new standards and interpretations for the period ended September 30, 2020.

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 July 1, 2020 and ending on September 30, 2020 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 Sept. 30, 2020 Three months ended Sept. 30, 2019	Nine months ended September 30, 2020 Nine months ended September 30, 2019
$000s $/boe $000s $/boe	$000s $/boe $000s $/boe
Oil and natural gas revenue 12,840 21.59 12,517 17.47 Royalty expense (1,245) (2.09) (1,182) (1.65)	36,225 19.76 50,400 22.22 (4,011) (2.19) (4,896) (2.16)
Net oil and natural gas revenue 11,595 19.50 11,335 15.82	32,214 17.57 45,504 20.06
Transportation expense (967) (1.63) (893) (1.25) Operating expense (2,408) (4.05) (3,181) (4.44)	(2,469) (1.35) (2,823) (1.24) (7,986) (4.36) (9,466) (4.17)
Operating netback 8,220 13.82 7,261 10.13	21,759 11.86 33,215 14.65
Realized gain (loss) on financial derivatives 1,308 2.20 360 0.50 Other income 23 0.04 21 0.03 General & administrative expense (635) (1.07) (776) (1.08) Cash finance expense (1,286) (2.16) (2,230) (3.11) Decommissioning expenditures (79) (0.13) (209) (0.29)	6,138 3.35 73 0.03 170 0.09 99 0.04 (2,350) (1.28) (2,185) (0.96) (5,205) (2.84) (6,302) (2.78) (538) (0.29) (535) (0.24)
Funds flow and corporate netback 7,551 12.70 4,427 6.18	19,974 10.89 24,365 10.74

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 September 30, 2020	As at December 31, 2019
Adjusted current assets(1)	7,030	14,620
Less: adjusted current liabilities(1)	(123,747)	(138,364)
Net debt	(116,717)	(123,744)

(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, 2019, 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 production results are not necessarily indicative of long-term performance of the relevant wells or of ultimate recovery of hydrocarbons.

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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

In particular, forward-looking statements included in this MD&A include, but are not limited to, statements with respect to: revenue outlook for Petrus for the remainder of 2020 and into 2021; Petrus having adequate liquidity to execute the Company's business plan over the coming year; the Company continuing its efforts to divest certain non-core assets and evaluate other sources of capital to improve its balance sheet; capital spending planned for the remainder of 2020; the Company's ability to adjust liquids content in the natural gas stream to maximize profitability of all products as well as adjust production rates quickly to respond to changing market conditions; planned debt repayments; the Company's continued pursuit programs announced by the Federal and Provincial Governments; the Company's ability to modify its operations; 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.

This MD&A contains future-oriented financial information and financial outlook information (collectively, "FOFI") about Petrus' prospective results of operations including, without limitation, its revenue outlook for Petrus for the remainder of 2020 and into 2021, liquidity to execute the Company's business plan over the coming year and 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.

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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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