Petrus Resources Ltd. — Management Reports 2021

Feb 25, 2021

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MANAGEMENT'S DISCUSSION & ANALYSIS December 31, 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 twelve months ended December 31, 2020. This MD&A is dated February 24, 2021 and should be read in conjunction with the Company's audited consolidated financial statements for the years ended December 31, 2020 and 2019. 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 Twelve months ended Dec. 31, 2020 Twelve months ended Dec. 31, 2019	Three months ended Dec. 31, 2020 Three months ended Sept. 30, 2020 Three months ended Jun. 30, 2020 Three months ended Mar. 31, 2020
Average Production Natural gas (mcf/d) 27,640 32,032 Oil (bbl/d) 1,021 1,616 NGLs (bbl/d) 980 1,351	26,177 26,181 27,630 30,604 980 1,103 867 1,134 1,014 997 819 1,088
Total (boe/d) 6,608 8,306 Total (boe) 2,418,259 3,031,659	6,357 6,463 6,291 7,323 584,860 594,599 572,440 666,361
Light oil weighting 15 % 19 %	15 % 17 % 14 % 15 %
Realized Prices Natural gas ($/mcf) 2.57 1.89 Oil ($/bbl) 44.14 64.11 NGLs ($/bbl) 20.84 22.13	3.07 2.51 2.35 2.40 49.64 46.46 27.18 50.02 23.52 22.05 12.87 23.19
Total realized price ($/boe) 20.67 23.35	24.05 21.48 15.73 21.23
Royalty income 0.16 0.20 Royaltyexpense (2.15) (2.35)	0.13 0.12 0.06 0.30 (2.02) (2.09) (1.51) (2.85)
Net oil and natural gas revenue ($/boe) 18.68 21.20	22.16 19.51 14.28 18.68
Operating expense (4.64) (4.25) Transportation expense (1.43) (1.26)	(5.53) (4.05) (4.44) (4.55) (1.68) (1.63) (1.40) (1.05)
Operating netback(1)($/boe) 12.61 15.69	14.95 13.83 8.44 13.08
Realized gain (loss) on derivatives ($/boe) 2.70 (0.44) Other income 0.15 0.03 General & administrative expense (1.41) (1.20) Cash finance expense (2.75) (2.72) Decommissioning expenditures (0.37) (0.28)	0.65 2.20 6.39 1.76 0.31 0.04 0.17 0.07 (1.81) (1.07) (1.43) (1.35) (2.49) (2.16) (3.20) (3.13) (0.63) (0.13) (0.15) (0.56)
Funds flow & corporate netback(1)(2) ($/boe) 10.93 11.08	10.98 12.71 10.22 9.87
FINANCIAL (000s except $ per share) Twelve months ended Dec. 31, 2020 Twelve months ended Dec. 31, 2019	Three months ended Dec. 31, 2020 Three months ended Sept. 30, 2020 Three months ended Jun. 30, 2020 Three months ended Mar. 31, 2020
Oil and natural gas revenue 50,368 71,398 Net loss (97,554) (42,176) Net loss per share Basic (1.97) (0.85) Fully diluted (1.97) (0.85) Funds flow 26,397 33,625 Funds flow per share Basic 0.53 0.68 Fully diluted 0.53 0.68 Capital expenditures 14,298 18,073 Net dispositions — 651 Weighted average shares outstanding Basic 49,469 49,472 Fully diluted 49,469 49,472 As at year end Common shares outstanding Basic 49,469 49,469 Fully diluted 49,469 49,469 Total assets 177,914 289,225 Non-current liabilities 45,321 42,346 Net debt(1) 114,361 123,744	14,143 12,840 9,041 14,344 (151) (3,678) (6,281) (87,444) — (0.07) (0.13) (1.77) — (0.07) (0.13) (1.77) 6,423 7,551 5,855 6,566 0.13 0.15 0.12 0.13 0.13 0.15 0.12 0.13 2,797 2,543 305 8,655 — — — — 49,469 49,469 49,469 49,469 49,469 49,469 49,469 49,469 49,469 49,469 49,469 49,469 49,469 49,469 49,469 49,469 177,914 179,895 184,532 193,679 45,321 44,471 43,017 38,533 114,361 116,717 120,570 125,974

(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

Fourth quarter average production by area was as follows:

For the three months ended December 31, 2020	Ferrier	Foothills	Central Alberta	Total
Natural gas (mcf/d)	19,637	1,425	5,118	26,180
Oil (bbl/d)	569	113	298	980
NGLs(bbl/d)	860	7	147	1,014
Total(boe/d)	4,702	357	1,298	6,357

Fourth quarter production averaged 6,357 boe/d in 2020 versus 6,463 boe/d in the third quarter. Production was lower due to natural declines as no new wells were brought on production during the quarter. One well completed during the fourth quarter is awaiting tie-in and is expected to be brought on production in the first quarter of 2021.

Petrus’ Board of Directors has approved a first quarter 2021 capital budget of $9.0 million to drill 3 gross (2.1 net) Cardium wells in the Ferrier area. With current commodity prices and the low operating cost structure utilizing company owned infrastructure, new wells operated by Petrus in the Ferrier area are expected to reach payout in under one year.

With stronger forward oil and natural gas prices than were experienced through most of 2020, Petrus management is forecasting stronger cash flow in 2021 than 2020 that will be used to fund a larger capital program and grow production from 2020 levels. Management anticipates that the 2020 capital plan will be funded by funds flow, with free funds flow used to continue significant debt reduction targets. With improved commodity pricing so far in 2021, Petrus has been active in adding price protection for the remainder of the year through additional forward sale contracts. The average volume of oil hedged for 2021 (825 bbl/d) represents 41% of fourth quarter 2020 average oil production. The 15,250 GJ/day average natural gas hedged for 2021 represents 61% of fourth quarter 2020 average natural gas production.

CAPITAL EXPENDITURES

Capital expenditures (excluding acquisitions and dispositions) totaled $2.8 million in the fourth quarter of 2020, compared to $4.4 million in 2019. The Company drilled one 1 gross (1.0 net) Cardium light oil well during the fourth quarter.

Capital expenditures (excluding acquisitions and dispositions) totaled $14.3 million in the year ended December 31, 2020, compared to $18.1 million in 2019. The decrease from the prior year is attributed to the Company's strategy to prioritize debt repayment and moderate capital spending.

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 December 31, 2020 Three months ended December 31, 2019	Twelve months ended December 31, 2020 Twelve months ended December 31, 2019
Drill and complete 1,585 3,604 Oil and gas equipment 777 283 Land and lease 57 17 Office — 8 Capitalized general and administrative expense 378 439	11,477 12,871 1,612 3,635 92 37 — 24 1,117 1,506
Total capital expenditures 2,797 4,351	14,298 18,073
Gross (net) wells spud 1 (1.0) 3 (0.5)	4 (3.2) 10 (3.1)

The following table summarizes the dispositions for the reporting periods indicated:

Dispositions ($000s) Three months ended December 31, 2020 Three months ended December 31, 2019	Twelve months ended December 31, 2020 Twelve months ended December 31, 2019
Dispositions — —	— 651
Total dispositions — —	— 651

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RESULTS OF OPERATIONS

FINANCIAL AND OPERATIONAL RESULTS OF OIL AND NATURAL GAS ACTIVITIES

Twelve months ended Dec. 31, 2020 Twelve months ended Dec. 31, 2019	Three months ended Dec. 31, 2020 Three months ended Sept. 30, 2020 Three months ended Jun. 30, 2020 Three months ended Mar. 31, 2020
Average production Natural gas (mcf/d) 27,640 32,032 Oil (bbl/d) 1,021 1,616 NGLs (bbl/d) 980 1,351	26,177 26,181 27,630 30,604 980 1,103 867 1,134 1,014 997 819 1,088
Total (boe/d) 6,608 8,306 Total (boe) 2,418,259 3,031,659	6,357 6,463 6,291 7,323 584,860 594,599 572,440 666,361
Revenue ($000s) Natural gas 26,023 22,052 Oil 16,493 37,815 NGLs 7,472 10,917 Royalty revenue 380 614	7,395 6,035 5,903 6,690 4,475 4,714 2,143 5,161 2,195 2,022 959 2,296 78 69 36 197
Oil and natural gas revenue 50,368 71,398	14,143 12,840 9,041 14,344
Average realized prices Natural gas ($/mcf) 2.57 1.89 Oil ($/bbl) 44.14 64.11 NGLs ($/bbl) 20.84 22.13	3.07 2.51 2.35 2.40 49.64 46.46 27.18 50.02 23.52 22.05 12.87 23.19
Total realized price ($/boe) 20.67 23.35 Hedging gain (loss) ($/boe) 2.70 (0.44)	24.05 21.48 15.73 21.23 0.65 2.20 6.39 1.76
Total price including hedging ($/boe) 23.37 22.91	24.70 23.68 22.12 22.99

Average benchmark prices Twelve months ended Dec. 31, 2020 Twelve months ended Dec. 31, 2019	Three months ended Dec. 31, 2020 Three months ended Sept. 30, 2020 Three months ended Jun. 30, 2020 Three months ended Mar. 31, 2020
Natural gas AECO 5A (C$/GJ) 2.09 1.67 AECO 7A (C$/GJ) 2.12 1.54 Crude oil Mixed Sweet Blend Edm (C$/bbl) 45.69 69.03 Natural gas liquids Propane Conway (US$/bbl) 17.94 20.34 Butane Edmonton (C$/bbl) 23.23 21.70	2.50 2.02 1.89 1.93 2.62 2.04 1.81 2.03 49.34 48.96 32.17 52.28 25.50 19.78 14.54 15.40 19.32 19.04 14.56 42.42
Foreign exchange US$/C$ 0.75 0.75	0.77 0.74 0.74 0.74

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FUNDS FLOW AND NET LOSS

Petrus generated funds flow of $6.4 million in the fourth quarter of 2020 compared to $9.3 million in 2019. The 30% decrease is due to lower production and total realized price in the fourth quarter of 2020; Petrus' total realized price was $24.05/boe compared to $27.39/boe in the prior year.

For the year ended December 31, 2020, Petrus generated funds flow of $26.4 million compared to $33.6 million in the prior year. The 22% decrease is due to lower production and lower oil prices during the year.

Petrus reported a net loss of $0.2 million in the fourth quarter of 2020, compared to a net loss of $3.2 million in the fourth quarter of 2019. The net loss in the fourth quarter of 2020 compared to the prior year is primarily due to the accounting for unrealized hedging on financial derivatives; during the fourth quarter of 2020 a $0.5 million unrealized gain was recorded, whereas during the the fourth quarter of 2019, the Company recognized an unrealized loss of $3.7 million, which had a material impact on net loss in the fourth quarter of 2019. The differences are due to changes in commodity prices at December 31 of the respective years.

On a twelve month basis, the Company generated a net loss of $97.6 million in 2020 compared to a net loss of $42.2 million in 2019. The increase is primarily due to the $98.0 million impairment expense recorded during the first quarter of 2020 on the Company's Ferrier CGU assets.

($000s except per share) Three months ended December 31, 2020 Three months ended December 31, 2019	Twelve months ended December 31, 2020 Twelve months ended December 31, 2019
Funds flow 6,424 9,260 Funds flow per share - basic 0.13 0.19 Funds flow per share - fully diluted 0.13 0.19	26,397 33,625 0.53 0.68 0.53 0.68
Net loss (151) (3,176) Net loss per share - basic — (0.06) Net loss per share - fully diluted — (0.06)	(97,554) (42,176) (1.97) (0.85) (1.97) (0.85)
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

Fourth quarter average production in 2020 was 6,357 boe/d (15% light oil), 23% lower than 2019 (8,292 boe/d; 22% light oil). Fourth quarter oil and natural gas revenue in 2020 was $14.1 million compared to $21.0 million in 2019. The 33% decrease is due to to 23% lower production and lower oil prices.

Annual average production in 2020 was 6,608 boe/d (15% light oil), 20% lower than 2019 (8,306 boe/d; 19% light oil). Total oil and natural gas revenue decreased from $71.4 million for the year ended December 31, 2019 to $50.4 million in 2020 due to 20% 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 December 31, 2020 Three months ended December 31, 2019	Twelve months ended December 31, 2020 Twelve months ended December 31, 2019
Natural gas 69 % 66 % Crude oil and condensate 15 % 22 % Natural gas liquids 16 % 12 %	70 % 64 % 15 % 20 % 15 % 16 %
Total commodity sales from production 100 % 100 %	100 % 100 %

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

Oil and Natural Gas Revenue ($000s) Three months ended December 31, 2020 Three months ended December 31, 2019 % Change	Twelve months ended December 31, 2020 Twelve months ended December 31, 2019 % Change
Natural gas 7,395 7,970 (7) % Crude oil and condensate 4,475 10,995 (59) % Natural gas liquids 2,195 1,931 14 % Royalty income 78 102 (24) %	26,023 22,052 18 % 16,493 37,815 (56) % 7,472 10,917 (32) % 380 614 (38) %
Total oil and natural gas revenue 14,143 20,998 **(33) % **	50,368 71,398 (29) %

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

Three months ended December 31, 2020 Three months ended December 31, 2019 % Change	Twelve months ended December 31, 2020 Twelve months ended December 31, 2019 % Change
Average benchmark prices Natural gas AECO 5A (C$/GJ) 2.50 2.35 6 % AECO 7A (C$/GJ) 2.62 2.21 19 % Crude oil Mixed Sweet Blend Edm (C$/bbl) 49.34 66.81 (26) % Natural gas liquids Propane Conway (US$/bbl) 25.50 19.78 29 % Butane Edmonton (C$/bbl) 19.32 36.96 (48) %	2.09 1.67 25 % 2.12 1.54 38 % 45.69 69.03 (34) % 17.94 20.34 (12) % 23.23 21.70 7 %
Average realized prices Natural gas ($/mcf) 3.07 2.65 16 % Oil ($/bbl) 49.64 65.16 (24) % NGLs ($/bbl) 23.52 20.62 14 %	2.57 1.89 36 % 44.14 64.11 (31) % 20.84 22.13 (6) %
Total average realized price 24.05 27.39 **(12) % **	20.67 23.35 (11) %

Natural gas

Natural gas revenue for the year ended December 31, 2020 was $26.0 million which accounted for 52% of oil and natural gas revenue, compared to revenue of $22.1 million which accounted for 31% in 2019. The increase is due to higher natural gas prices.

Fourth quarter 2020 average realized natural gas price was $3.07/mcf, compared to $2.65/mcf in 2019 (16% increase). Fourth quarter 2020 natural gas revenue was $7.4 million which accounted for 53% of oil and natural gas revenue, compared to revenue of $8.0 million accounting for 38% in 2019. Fourth quarter natural gas revenue increased from 2019 due to 6% higher natural gas pricing.

Crude oil and condensate

Oil and condensate revenue for the fourth quarter of 2020 was $4.5 million accounted for approximately 32% of oil and natural gas revenue, compared to revenue of $11.0 million, accounting for 53% in 2019.

The average realized price of Petrus’ light oil and condensate was $49.64/bbl for the fourth quarter of 2020 compared to $65.16/bbl for the prior year. The decrease of 24% is attributable to the 26% lower oil pricing.

Oil and condensate revenue for the year ended December 31, 2020 was $16.5 million, which accounted for 33% of oil and natural gas revenue, compared to revenue of $37.8 million, which accounted for 53% in 2019.

The average realized price of Petrus’ light oil and condensate was $44.14/bbl for 2020 compared to $64.11/bbl for the prior year. The decrease of 31% is attributable to lower oil pricing.

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 fourth quarter of 2020, the Company's realized NGL price averaged $23.52/bbl, compared to $20.62/bbl in the prior year. The 14% decrease is attributed to higher contract prices for the NGL byproducts. Fourth quarter

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market pricing for propane at Conway increased 29% from the prior year. Petrus' butane production is priced as a function of WTI (oil) which also decreased in the fourth quarter compared to the prior year. In 2020, the Company's realized NGL price averaged $20.84/bbl compared to $22.13/bbl in 2019. The 6% decrease in realized pricing is attributed to lower market pricing for propane at Conway.

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 the third quarter of 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.

Fourth quarter 2020 NGL revenue was $2.2 million and accounted for 16% of oil and natural gas revenue, compared to revenue of $1.9 million accounting for 9% in 2019.

NGL revenue for the year ended December 31, 2020 was $7.5 million and accounted for 15% of oil and natural gas revenue, compared to revenue of $10.9 million accounting for 15% in 2019.

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:

expense (net of royalty allowances and incentives) for the periods shown:
Royalty Expense ($000s) Three months ended December 31, 2020 Three months ended December 31, 2019	Twelve months ended December 31, 2020 Twelve months ended December 31, 2019
Crown 443 1,232 Percent of production revenue 3 % 6 %	1,785 3,298 4 % 5 %
Gross overriding 738 986	3,409 3,816
Total 1,181 2,218	5,194 7,114

Fourth quarter royalty expense decreased from $2.2 million in 2019 to $1.2 million in 2020. For the year, total royalty expense decreased from $7.1 million in 2019 to $5.2 million in 2020. The decreases are due to lower production and oil prices and more favorable royalty rates.

Fourth quarter gross overriding royalties decreased from $1.0 million in 2019 to $0.7 million in 2020, due to lower oil prices. Gross overriding royalties for the year decreased from $3.8 million in 2019 to $3.4 million in 2020, due to the decrease in production and lower oil and NGL 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 (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 December 31, 2020 Three months ended December 31, 2019	Twelve months ended December 31, 2020 Twelve months ended December 31, 2019
Realized hedging gain (loss) 381 (1,417) Unrealized hedging gain (loss) 491 (3,668)	6,518 (1,344) 1,661 (11,273)
Net gain (loss) on derivatives 872 (5,085)	8,179 (12,617)

In the fourth quarter, the Company recognized a realized hedging gain of $0.4 million in 2020, compared to a $1.4 million loss in 2019. The realized gain in the fourth quarter is due to lower oil commodity prices (relative to the respective contracts outstanding). The realized gain in the fourth quarter of 2020 increased the Company’s total realized price by $0.65/boe, compared to a decrease of $1.86/boe in 2019.

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For the year, the Company recognized a realized hedging gain of $6.5 million in 2020, compared to the $1.3 million loss realized in 2019. Similar to the fourth quarter, the realized gain for the year is due to lower oil commodity prices (relative to the respective contracts outstanding). The realized gain increased Petrus' total realized price by $2.70/boe in 2020, compared to a decrease of $0.44/boe in 2019.

The fourth quarter unrealized hedging gain of $0.5 million in 2020 ($3.7 million unrealized loss in 2019) represents the change in the unrealized net risk management position during the quarter. The unrealized hedging gain of $0.4 million for the year ended December 31, 2020 ($11.3 million unrealized loss in 2019) represents the change in the unrealized risk management net asset position during 2020. These changes are a result of both the realization of hedging gains and losses during the year, changes related to contracts entered into during the year and 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 aims 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 10 of the Company’s consolidated financial statements as at and for the year ended December 31, 2020. The table below summarizes Petrus’ average crude oil and natural gas hedged volumes. The average volume of oil hedged for 2021 (825 bbl/d) represents 41% of fourth quarter 2020 average oil production. The 15,250 GJ/day average natural gas hedged for 2021 represents 61% of fourth quarter 2020 average natural gas production.

The following table summarizes the average fixed prices for the 2021 to 2022 oil and natural gas contracts outstanding as at the date of this report:

2021	2022
Q1 Q2 Q3 Q4 Avg.(1)	Q1 Q2 Q3 Q4 Avg.(1)
Oil hedged (bbl/d) 733 800 900 867 825 Avg. WTI fixed price ($C/bbl) 68.33 66.89 66.41 65.9366.83	600 — — — 150 62.73 — — — —
Natural gas hedged (GJ/d) 17,000 16,000 14,000 14,00015,250 Avg. AECO 7A fixed price ($C/GJ) 2.18 2.15 2.08 2.48 2.22	11,000 — — —2,750
	2.62 — — — 2.62

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

OPERATING EXPENSE

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

Operating Expense ($000s) Three months ended December 31, 2020 Three months ended December 31, 2019	Twelve months ended December 31, 2020 Twelve months ended December 31, 2019
Fixed and variable operating expense 2,853 2,655 Processing, gathering and compression charges 631 980	9,673 10,668 2,463 3,167
Total gross operating expense 3,484 3,635 Overhead recoveries (247) (228)	12,136 13,835 (913) (962)
Total net operating expense 3,237 3,407 Operating expense, net ($/boe) 5.53 4.47	11,223 12,873 4.64 4.25

Fourth quarter net operating expense totaled $3.2 million in 2020, a 5% decrease from $3.4 million in 2019. On a per boe basis, operating expense was 24% higher at $5.53/boe in 2020 compared to $4.47/boe in 2019. The increases are attributable to well workover projects completed in the fourth quarter of 2020.

For the year ended December 31, 2020, net operating expense totaled $11.2 million, an 13% decrease from the $12.9 million in 2019. The decrease is attributable to 23% lower production partially offset by an increase in well workover projects. On a per boe basis operating expense was $4.64/boe for the year ended December 31, 2020, 9% higher than the $4.25/boe in 2019. The increase is related to lower production.

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TRANSPORTATION EXPENSE

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

TRANSPORTATION EXPENSE The following table shows transportation expense paid in the reporting periods:
Transportation Expense ($000s) Three months ended December 31, 2020 Three months ended December 31, 2019	Twelve months ended December 31, 2020 Twelve months ended December 31, 2019
Transportation expense 983 991 Transportation expense ($/boe) 1.68 1.30	3,452 3,814 1.43 1.26

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. Fourth quarter 2020 transportation expense was $1.0 million or $1.68/boe compared to $1.0 million or $1.30/boe in 2019. The increase in transportation expense per boe is attributed to 23% lower production. For the year ended December 31, 2020, transportation expense totaled $3.5 million, or $1.43/boe, compared to $3.8 million or $1.26/boe in 2019. The total decrease is attributed to decreased trucking costs and the increase on a per boe basis is due to decreased 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 ($000s) Three months ended December 31, 2020 Three months ended December 31, 2019	Twelve months ended December 31, 2020 Twelve months ended December 31, 2019
Personnel, consultants and directors 1,039 1,139 Administrative expenses 300 613 Regulatory and professional expenses 326 218	3,028 3,875 1,102 1,657 1,118 685
Gross general and administrative expense 1,665 1,970 Capitalized general and administrative expense (378) (439) Overhead recoveries (228) (72)	5,248 6,217 (1,117) (1,506) (722) (1,067)
General and administrative expense 1,059 1,459 General and administrative expense ($/boe) 1.81 1.91	3,409 3,644 1.41 1.20

Fourth quarter gross G&A expense was 35% lower than the prior year ($1.7 million in 2020 compared to $2.0 million in 2019) which is attributed to lower office expenses and staffing costs due to fewer personnel. Fourth quarter 2020 G&A expense (net) was $1.1 million or $1.81/boe, compared to $1.5 million or $1.91/boe in 2019. The decreases in 2020 on a net basis are attributed to increased cost efficiencies and higher overhead recoveries due to higher capital activity.

For the year ended December 31, 2020, gross G&A expense was $5.2 million compared to $6.2 million in 2019, which represents a 21% decrease. Annual G&A expense (net) in 2020 was $3.4 million or $1.41/boe compared to $3.6 million or $1.20/boe in 2019 due to lower production. The decreases are attributed to lower office rent (IFRS 16), and fewer personnel resulting in lower office and personnel expenses.

SHARE-BASED COMPENSATION EXPENSE

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

Share-Based Compensation Expense ($000s) Three months ended December 31, 2020 Three months ended December 31, 2019	Twelve months ended December 31, 2020 Twelve months ended December 31, 2019
Gross share-based compensation expense 163 125 Capitalized share-based compensation expense (20) 34	483 529 (102) (128)
Share-based compensation expense 143 159	381 401

Fourth quarter net share-based compensation expense was $0.1 million in 2020, which is 10% lower than the $0.2 million in 2019. For the year ended December 31, 2020, net share-based compensation expense was $0.4 million, which is consistent with the $0.4 million in 2019.

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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 December 31, 2020 Three months ended December 31, 2019	Twelve months ended December 31, 2020 Twelve months ended December 31, 2019
Interest expense 1,456 1,939 Deferred financing costs 145 121 Non-cash term loan interest payment-in-kind 936 — Accretion on decommissioning obligations 107 176	6,661 8,241 625 495 1,813 — 494 777
Total finance expense 2,644 2,236	9,593 9,513

Fourth quarter total finance expense was $2.6 million in 2020, comprised of $0.9 million of non-cash accretion of its decommissioning obligations, $1.5 million of cash interest expense, $0.1 million of deferred financing fee amortization, both of which are related to the RCF and Term Loan (as defined below), and $0.9 million of non-cash term loan interest payment-in-kind. In the fourth quarter of 2019, the Company incurred total finance expense of $2.2 million, comprised of $0.2 million in non-cash accretion of its decommissioning obligation, $1.9 million cash interest expense and $0.1 million of deferred financing fee amortization. The Company incurred total finance expense of $9.6 million for the year ended December 31, 2020, which is higher than the $9.5 million for 2019. The decrease is due to the lower RCF balance outstanding.

The increase in total finance expense from the prior year is due to the financing costs related to the RCF and Term Loan extensions as well as higher interest rates.

DEPLETION AND DEPRECIATION

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

Depletion and Depreciation Expense ($000s) Three months ended December 31, 2020 Three months ended December 31, 2019	Twelve months ended December 31, 2020 Twelve months ended December 31, 2019
Depletion and depreciation expense 6,121 8,735 Depletion and depreciation expense ($/boe) 10.47 11.45	25,231 36,564 10.43 12.06

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.

Fourth quarter depletion and depreciation expense in 2020 was $6.1 million or $10.47/boe, compared to $8.7 million or $11.45/boe in 2019. For the year ended December 31, 2020, the Company recorded $25.2 million or $10.43/boe, compared to $36.6 million or $12.06/ boe in 2019. The decreases in depletion and depreciation expense per boe are attributed to the impairment recorded in the first quarter of 2020.

IMPAIRMENT

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

IMPAIRMENT The following table illustrates impairment losses recorded in the reporting periods:
Impairment ($000s) Three months ended December 31, 2020 Three months ended December 31, 2019	Twelve months ended December 31, 2020 Twelve months ended December 31, 2019
Impairment — —	98,000 24,655
Total — —	98,000 24,655

During the year ended December 31, 2020, due to the significant decrease in forward benchmark commodity prices in the first quarter, the Company identified indicators of impairment and conducted an impairment test on all of the Company's Cash Generating Units ("CGUs"). No impairment was recorded for the Foothills and Central Alberta CGUs during the year ended December 31, 2020. For the Ferrier CGU, the Company recorded an impairment loss of $98.0 million. For more information, refer to notes 5 and 6 of the December 31, 2020 consolidated financial statements.

Petrus has certain CGUs that are not core to the Company. As such, a sales process was put in place to potentially divest of the Company's Foothills and Central Alberta CGUs during 2019. Based on interest expressed in the Foothills and Central Alberta assets, and information obtained through the divestiture process, Petrus recognized an impairment loss of $24.7 million during the year ended December 31, 2019.

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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 ("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:

securities for the periods shown:
Share Capital (000s) Three months ended December 31, 2020 Three months ended December 31, 2019	Twelve months ended December 31, 2020 Twelve months ended December 31, 2019
Weighted average Common Shares outstanding Basic 49,469 49,469 Fully diluted 49,469 49,469 Common shares outstanding Basic 49,469 49,469 Fully diluted 49,469 49,469 Stock options outstanding 2,277 2,362	49,469 49,472 49,469 49,472 49,469 49,469 49,469 49,469 2,277 2,362

At December 31, 2020, the Company had 49,469,358 common shares and 2,276,923 stock options outstanding.

The Company issued 1,122,276 stock options during the year ended December 31, 2020:

• (a) 748,179 stock options were issued on August 18, 2020 at an exercise price of $0.23.

• (b) 374,097 stock options were issued on November 30, 2020 at an exercise price of $0.24.

The Company has a deferred share unit plan in place whereby it may issue deferred share units ("DSUs") to directors of the Company. At December 31, 2020, 2,158,270 (December 31, 2019 – 1,177,510) DSUs were issued and outstanding. Each DSU entitles the participants to receive, at the Company's discretion, either Common Shares or 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 December 31, 2020, the RCF was comprised of a $20 million operating facility and a $63 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 December 31, 2020, the Company had a $0.6 million letter of credit outstanding against the RCF (December 31, 2019 – $0.7 million) and had drawn $77.5 million against the RCF (December 31, 2019 – $92.3 million) excluding non-cash deferred financing fees of $0.3 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.

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(b) Term Loan

At December 31, 2020 the Company had a $37 million (December 31, 2019 – $35 million) Term Loan outstanding, 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 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 December 31, 2020, the Company had a working capital deficiency (excluding non-cash risk management assets and liabilities) of $114.5 million due to the classification of the Company's borrowings under its RCF and Term Loan.

However, the Company remains in compliance with all financial covenants pertaining to its debt, and based on current available information relating to future production volumes, forward commodity pricing, future costs including capital, operating and general and administrative, forward exchange rates, interest rates and taxes, all of which are subject to measurement uncertainty, management expects to comply with all financial covenants during the subsequent 12 month period.

Financial Covenants

The RCF and the Term Loan carry financial covenants that are described in note 7 of the Company's December 31, 2020 audited annual consolidated financial statements. The Company was in compliance with all financial covenants at December 31, 2020.

The following are the contractual maturities of financial liabilities as at December 31, 2020:

$000s	Total	< 1 year	1-5 years
Accounts payable and accrued liabilities	7,708	7,708	—
Risk management liability	1,027	986	41
Bank indebtedness and long term debt(1)	114,081	114,081	—
Lease obligations	1,012	188	824
Total	123,828	122,963	865

(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	12,994	2,045	9,539	1,410

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 10 and 15 of the Company’s December 31, 2020 consolidated financial statements.

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SUMMARY OF QUARTERLY RESULTS

SUMMARY OF QUARTERLY RESULTS
($000s unless otherwise noted)	Dec. 31, 2020	Sept. 30, 2020	Jun. 30, 2020	Mar. 31, 2020	Dec. 31, 2019	Sept. 30, 2019	Jun. 30, 2019	Mar. 31, 2019
Average Production
Natural gas (mcf/d)	26,177	26,181	27,630	30,604	32,641	30,998	32,350	32,145
Oil (bbl/d)	980	1,103	867	1,134	1,834	1,247	1,679	1,704
NGLs (bbl/d)	1,014	997	819	1,088	1,018	1,372	1,576	1,444
Total (boe/d)	6,357	6,463	6,291	7,323	8,292	7,785	8,647	8,505
Total (boe)	584,860	594,599	572,440	666,361	762,874	716,220	786,819	765,488
Financial Results
Oil and natural gas revenue	14,143	12,840	9,041	14,344	20,998	12,517	17,652	20,231
Royalty expense	(1,183)	(1,245)	(867)	(1,899)	(2,218)	(1,182)	(1,355)	(2,359)
Net oil and natural gas revenue	12,960	11,595	8,174	12,445	18,780	11,335	16,297	17,872
Transportation expense	(983)	(967)	(799)	(703)	(991)	(893)	(959)	(971)
Operating expense	(3,237)	(2,408)	(2,543)	(3,035)	(3,407)	(3,181)	(3,405)	(2,880)
Operating netback	8,740	8,220	4,832	8,707	14,382	7,261	11,933	14,021
Realized gain (loss) on derivatives	381	1,308	3,656	1,174	(1,417)	360	(800)	513
Other income	184	23	99	48	7	21	78	—
General and administrative expense	(1,059)	(635)	(817)	(898)	(1,459)	(776)	(530)	(879)
Cash finance expense	(1,456)	(1,286)	(1,831)	(2,089)	(1,939)	(2,230)	(2,126)	(1,945)
Decommissioning expenditures	(366)	(79)	(84)	(376)	(314)	(209)	(189)	(137)
Corporate netback and funds flow	6,424	7,551	5,855	6,566	9,260	4,427	8,366	11,573
Oil and natural gas revenue	14,143	12,840	9,041	14,344	20,998	12,517	17,652	20,231
Per share - basic	0.29	0.26	0.18	0.29	0.42	0.25	0.36	0.41
Per share - fully diluted	0.29	0.26	0.18	0.29	0.42	0.25	0.36	0.41
Net income (loss)	(151)	(3,678)	(6,281)	(87,444)	(3,176)	(29,569)	2,863	(12,138)
Per share - basic	—	(0.07)	(0.13)	(1.77)	(0.06)	(0.60)	0.06	(0.25)
Per share - fully diluted	—	(0.07)	(0.13)	(1.77)	(0.06)	(0.60)	0.06	(0.25)
Common shares outstanding (000s)
Basic	49,469	49,469	49,469	49,469	49,469	49,469	49,469	49,469
Fully diluted	49,469	49,469	49,469	49,469	49,469	49,469	49,469	49,469
Weighted average shares outstanding (000s)
Basic	49,469	49,469	49,469	49,469	49,469	49,469	49,469	49,483
Fully diluted	49,469	49,469	49,469	49,469	49,469	49,469	49,469	49,483
Total assets	177,914	179,895	184,532	193,679	289,225	296,367	328,912	336,974
Net debt	(114,361)	(116,717)	(120,570)	(125,974)	(123,744)	(128,553)	(130,619)	(136,382)

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 8,505 boe/d in the first quarter of 2019 to 6,357 boe/d in the fourth quarter of 2020. The 25% 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. In addition the decrease is due to certain production volume 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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SELECTED ANNUAL INFORMATION

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($000s unless otherwise noted)
For the year ended,	December 31, 2020	December 31, 2019	December 31, 2018
Oil and natural gas revenue	50,368	71,398	80,716
Per share - basic	1.02	1.44	1.63
Per share - fully diluted	1.02	1.44	1.63
Net loss	(97,554)	(42,176)	(3,284)
Per share - basic	(1.97)	(0.85)	(0.07)
Per share - fully diluted	(1.97)	(0.85)	(0.07)
Common shares outstanding (000s)
Basic	49,469	49,469	49,492
Fully diluted	49,469	49,469	49,492
Weighted avg. shares outstanding (000s)
Basic	49,469	49,469	49,492
Fully diluted	49,469	49,469	49,492
Total assets	177,914	289,225	341,820
Non-current liabilities	45,321	42,346	171,646

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 consolidated financial statements as at and for the year ended December 31, 2020.

OTHER FINANCIAL INFORMATION

Significant accounting policies

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

New standards and interpretations

The Company's discussion on new standards and interpretations can be read in note 3 of the Company’s consolidated financial statements as at and for the period ended December 31, 2020.

Disclosure Controls and Procedures

Petrus’ Chief Executive Officer and Chief Financial Officer have designed, or caused to be designed under their supervision, disclosure controls and procedures ("DC&P"), as defined by National Instrument 52-109 – Certification of Disclosure in Issuers’ Annual and Interim Filings (“NI 52-109”), to provide reasonable assurance that: (i) material information relating to the Company is made known to the Company's Chief Executive Officer and Chief Financial Officer by others, particularly during the period in which the annual filings are being prepared; and (ii) information required to be disclosed by the Company in its annual filings, interim filings or other reports filed or submitted by it under securities legislation is recorded, processed, summarized and reported within the time period specified in securities legislation. The Chief Executive Officer and Chief Financial Officer of Petrus have evaluated, or caused to be evaluated under their supervision, the effectiveness of the Company's DC&P as at December 31, 2020 and have concluded that the Company's DC&P are effective at December 31, 2020 for the foregoing purposes.

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Internal Control over Financial Reporting

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

The Chief Executive Officer and the Chief Financial Officer are responsible for establishing and maintaining ICFR for Petrus. For the year ended December 31, 2020, they have designed ICFR, or caused it to be designed under their supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with IFRS. The control framework used to design the Company’s ICFR is the framework in Internal Control – Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission.

Under the supervision of the Chief Executive Officer and the Chief Financial Officer, Petrus conducted an evaluation of the effectiveness of the Company’s ICFR as at December 31, 2020. Based on this evaluation, the Chief Executive Officer and Chief Financial Officer concluded that as at December 31, 2020, Petrus maintained effective ICFR. It should be noted that while the Chief Executive Officer and Chief Financial Officer believe that the Company’s controls provide a reasonable level of assurance with regard to their effectiveness, a control system, no matter how well conceived or operated, can provide only reasonable, not absolute, assurance that the objectives of the control system will be met and it should not be expected that the control system will prevent all errors or fraud.

NON-GAAP FINANCIAL MEASURES

This MD&A makes reference to the terms "operating netback", "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 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.

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Three months ended Dec. 31, 2020 Three months ended Dec. 31, 2019	Twelve months ended December 31, 2020 Twelve months ended December 31, 2019
$000s $/boe $000s $/boe	$000s $/boe $000s $/boe
Oil and natural gas revenue 14,143 24.18 20,998 27.52 Royalty expense (1,183) (2.02) (2,218) (2.91)	50,368 20.83 71,398 23.55 (5,194) (2.15) (7,114) (2.35)
Net oil and natural gas revenue 12,960 22.16 18,780 24.61	45,174 18.68 64,284 21.20
Transportation expense (983) (1.68) (991) (1.30) Operating expense (3,237) (5.53) (3,407) (4.47)	(3,452) (1.43) (3,814) (1.26) (11,223) (4.64) (12,873) (4.25)
Operating netback 8,740 14.95 14,382 18.84	30,499 12.61 47,597 15.69
Realized gain (loss) on financial derivatives 381 0.65 (1,417) (1.86) Other income 184 0.31 7 — General & administrative expense (1,059) (1.81) (1,459) (1.91) Cash finance expense(1) (1,456) (2.49) (1,939) (2.54) Decommissioning expenditures (366) (0.63) (314) (0.41)	6,518 2.70 (1,344) (0.44) 354 0.15 106 0.03 (3,409) (1.41) (3,644) (1.20) (6,661) (2.75) (8,241) (2.72) (904) (0.37) (849) (0.28)
Funds flow and corporate netback 6,424 10.98 9,260 12.12	26,397 10.93 33,625 11.08

(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 December 31, 2020	As at December 31, 2019
Adjusted current assets(1)	7,428	14,620
Less: adjusted current liabilities(1)	(121,789)	(138,364)
Less: long term debt	—	—
Net debt	(114,361)	(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, 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.

F&D and FD&A Costs

FD&A cost is defined as capital costs for the time period including change in FDC divided by change in reserves including revisions and production for that same time period. F&D cost is defined as capital costs for the time period including change in FDC divided by change in reserves including revisions and production for that same time period, excluding acquisitions and dispositions. Both F&D and FD&A costs take into account reserves revisions during the year on a per boe basis. The methodology used to calculate F&D costs includes disclosure required to bring the proved undeveloped and probable reserves to production. Annually, changes in forecast FDC occur as a result of Petrus' development, acquisition and disposition activities, undeveloped reserve revision and capital cost estimates. These values reflect the independent evaluator's best estimate of the cost to bring the proved and probable undeveloped reserves to production. In 2019, the P+P FD&A and F&D costs including changes in FDC can generate non meaningful information because acquisitions and dispositions can have a significant impact on our ongoing reserves replacement costs.

Reserve Life Index

Reserve life index is defined as total reserves by category divided by the annualized fourth quarter production.

Reserve Replacement Ratio

The reserve replacement ratio is calculated by dividing the yearly change in reserves net of production by the actual annual production for the year.

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

FD&A Recycle Ratio

The FD&A recycle ratio is calculated by dividing field netback by FD&A.

Management uses oil and gas metrics for its own performance measurements and to provide shareholders with measures to compare Petrus' operations overtime. 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.

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, 2020. 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: Petrus focus on paying down the balance of the RCF; the Company's focus on optimizing its cost structure, particularly in the Ferrier area, through facility ownership and control; Petrus' commitment to maintaining its financial flexibility and expectation that it will determine subsequent quarter capital spending as the year progresses; forecast cash flow in 2021 and the use thereof; managements expectation that the 2020 capital plan will be funded by funds flow, with free funds flow used to continue significant debt reduction targets; management expectation that it will continue to layer in hedges; expectations regarding the payout of new wells in the Ferrier area; the drilling 3 gross (2.1 net) Cardium wells under Petrus' first quarter 2021 capital budget; the Company's strategy to prioritize debt repayment and moderate capital spending; Petrus' ability to modify its operations according to NGL market pricing; the intent of the Company's hedging strategy; 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, forecast cash flow in 2021, managements expectation that the 2020 capital plan will be funded by funds flow, expectations regarding the payout of new wells in the Ferrier area, Petrus' 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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