Petrus Resources Ltd. — Annual Report 2020

Feb 25, 2021

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ANNUAL REPORT December 31, 2020

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2020 HIGHLIGHTS

Petrus Resources Ltd. (“Petrus” or the “Company”) (TSX: PRQ) is pleased to report financial and operating results as at and for the three and twelve months ended December 31, 2020 and to provide 2020 year end reserves information as evaluated by Sproule Associates Limited ("Sproule"). The Company's Management's Discussion and Analysis ("MD&A") and audited consolidated financial statements are available on SEDAR (the System for Electronic Document Analysis and Retrieval) at www.sedar.com.

Given the significant turmoil in global energy markets in 2020, Petrus is pleased to report annual results that achieved the objectives management laid out for the year. This includes the generation of free cash flow in excess of capital expenditures used to repay debt and continue to strengthen the Company's balance sheet. Petrus generated $26.4 million of funds flow in 2020. This was used to fund a capital program of $14.3 million, the lowest in the Company's history, with the remainder used to reduce the balance drawn on the company’s Revolving Credit Facility (“RCF”). In light of the volatile commodity prices during the outbreak of the COVID-19 pandemic, the Company pursued a very disciplined capital program. To conserve cash, Petrus drilled 4 gross wells (3.2 net) during the year. The Company continues to focus the majority of capital spending in its Ferrier core area where ownership of key infrastructure generates low operating costs, high netbacks and quick capital payouts.

• Debt repayment - Reduction of debt was the top priority for the Company in 2020 and Petrus was successful in reducing net debt by $9.4 million during the year. Since December 31, 2015 Petrus has repaid $112.4 million (50%) of net debt. As part of the extension agreement reached in mid-2020 in respect of Petrus' second lien term loan ("Term Loan"), interest is now paid-in-kind and is added to the balance of the loan outstanding. Petrus focused on paying down the balance of the RCF, which was reduced by $14.8 million during the year, and is ahead of its required scheduled repayments.

• Stronger natural gas pricing – Natural gas prices showed marked improvement from the prior year and continue to strengthen. Petrus’ average realized price was $2.57/mcf in 2020, compared to $1.89/mcf in 2019, a 36% improvement. Company production was weighted 70% towards natural gas in 2020.

• Free funds flow – In 2020 Petrus generated funds flow of $26.4 million ($0.53/share), and invested $14.3 million in capital projects including the drilling of three 100% working interest wells. During the fourth quarter of 2020, Petrus generated funds flow of $6.4 million.

• Increased PDP reserves – In 2020, Petrus’ development program generated PDP reserve volume additions of 2.9 mmboe, or 1.2x production in the year. Despite decreased capital spending, the Company produced 2.4 mmboe during 2020 and ended the year with 12.2 mmboe of PDP reserves. Petrus realized Finding Development and Acquisition (“FD&A”) costs of $4.83/boe for PDP reserves, which are the best in the Company's history.

• Low operating costs – Total annual operating costs were $4.64/boe in 2020. The Company continues to focus on optimizing its cost structure, particularly in the Ferrier area, through facility ownership and control.

• Reduced general and administrative costs – Petrus reduced gross general and administrative expenses ("G&A") by $1.0 million in 2020, in comparison to 2019, to a total of $5.2 million. This marks the fourth consecutive year of G&A cost reductions and a 40% reduction since 2017.

2021 OUTLOOK

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 its 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.

Petrus is committed to maintaining its financial flexibility and the Company will determine subsequent quarter capital spending as the year progresses. With stronger forward oil and 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. Petrus' management continues to layer in additional hedged volumes into 2022.

Refer to "Non-GAAP Financial Measures" in the Management's Discussion & Analysis attached hereto. Refer to "Advisories - Forward-Looking Statements" in the Management's Discussion & Analysis attached hereto. Refer to "Advisories - Presentation" in the Management's Discussion & Analysis attached hereto.

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RESERVES

Petrus’ 2020 year end reserves were evaluated by independent reserves evaluator, Sproule Associates Limited, in accordance with the definitions, standards and procedures contained in the Canadian Oil and Gas Evaluation Handbook (“COGE Handbook”) and National instrument 51-101 - Standards of Disclosure for Oil and Gas Activities (“NI 51-101”) as of December 31, 2020 ("2020 Sproule Report"). Additional reserve information as required under NI 51-101 will be included in our Annual Information Form for the year ended December 31, 2020, which will be available under the Company's profile on SEDAR (the System for Electronic Document Analysis and Retrieval) at www.sedar.com.

Petrus has a reserves committee, comprised of independent board members, that reviews the qualifications and appointment of the independent reserves evaluator. The committee also reviews the procedures for providing information to the evaluators. All booked reserves are based upon annual evaluations by the independent qualified reserve evaluator conducted in accordance with the COGE Handbook and NI 51-101. The evaluations are conducted using all available geological and engineering data. The reserves committee has reviewed the reserves information and approved the 2020 Sproule Report.

The following table provides a summary of the Company’s before tax reserves as evaluated by Sproule:

As at December 31, 2020			Total Company Interest(1)(3)	Total Company Interest(1)(3)
		Light and
	Conventional	Medium
	Natural Gas	Crude Oil	NGL	Total NPV	0%(2)	NPV 5%(2)	NPV 10%(2)
Reserve Category	(mmcf)	(mbbl)	(mbbl)	(mboe) ($000s)		($000s)	($000s)
Proved Producing	53,172	1,158	2,150	12,170	120,922	130,024	119,122
Proved Non-Producing	309	8	14	74	726	639	571
Proved Undeveloped	52,448	943	3,492	13,177	113,185	68,344	39,745
Total Proved	105,929	2,109	5,657	25,421	234,833	199,007	159,438
Proved + Probable Producing	66,071	1,435	2,650	15,097	167,144	154,424	133,562
Total Probable	65,186	2,231	2,894	15,989	224,418	142,949	97,553
Total Proved Plus Probable	171,115	4,340	8,551	41,410	459,251	341,956	256,991

(1)Tables may not add due to rounding.

(2)NPV 0%, NPV 5% and NPV 10% refer to the risked net present value of the future net revenue of the Company's reserves, discounted by 0%, 5% and 10%, respectively and is presented before tax and based on Sproule's pricing assumptions.

(3)Total company interest reserve volumes presented above and in the remainder of this Annual Report are presented as the Company's total working interest before the deduction of royalties (but after including any royalty interests of Petrus).

In 2020, Petrus’ development program generated Proved Developed Producing ("PDP") reserve volume additions of 1.3 mmboe. The Company produced 2.4 mmboe during 2019 and ended the year with 12.2 mmboe of PDP reserve volume (34% oil and liquids).

Petrus ended 2020 with $119.7 million, $159.4 million and $257.0 million of Proved Developed ("PD"), Total Proved ("TP"), and Proved plus Probable (“P+P”), respectively, reserve value before-tax, discounted at 10%, based on the 2020 Sproule Report. In 2020, the Company realized Finding and Development (“FD&A”)[(1)(2)] costs of $4.83/boe for PDP reserves.

Based on the 2020 Sproule Report, the Company’s PDP reserve value before-tax, discounted at 10% is $2.41 per share. On the same basis, the P+P reserve value is $5.20 per share.

(1)Refer to "Oil and Gas Disclosures" in the Management's Discussion & Analysis attached hereto.

(2)Certain changes in FD&A and F&D produce non-meaningful figures as discussed in "Oil and Gas Disclosures" in the Management's Discussion & Analysis attached hereto. While FD&A and F&D costs, reserve life index, reserve replacement ratio and finding and development costs are commonly used in the oil and nature gas industry and have been prepared by management, these terms do not have a standardized meaning and may not be comparable to similar measures presented by other companies and, therefore, should not be used to make such comparisons.

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FUTURE DEVELOPMENT COST

Future Development Cost ("FDC") reflects Sproule's best estimate of what it will cost to bring the P+P undeveloped reserves on production. The following table provides a summary of the Company's FDC as set forth in the 2020 Sproule Report:

Future Development Cost ($000s)
	Total Proved	Total Proved + Probable
2021	28,582	36,242
2022	45,758	70,913
2023	57,783	65,731
2024	6,164	20,582
2025	12,944	28,895
2026	5,583	11,129
2027	—	18,844
Thereafter	—	—
Total FDC, Undiscounted	156,815	252,335
Total FDC, Discounted at 10%	129,059	198,745

PERFORMANCE RATIOS

The following table highlights annual performance ratios for the Company from 2016 to 2020:

	December 31, 2020	December 31, 2019	December 31, 2018	December 31, 2017	December 31, 2016
Proved Producing
FD&A ($/boe)(1)(2)	4.83	13.31	37.76	13.05	(0.43)
F&D ($/boe)(1)(2)	4.83	12.81	42.27	11.57	9.89
Reserve Life Index (yr)(1)	5.2	3.8	4.6	4.1	4.4
Reserve Replacement Ratio(1)	1.2	0.4	0.2	1.6	0.4
FD&A Recycle Ratio(1)	2.6	1.2	0.4	1.1	(24.8)
Proved Developed
FD&A ($/boe)(1)(2)	4.71	12.49	11.34	16.74	(0.23)
F&D ($/boe)(1)(2)	4.71	12.03	11.55	14.62	7.69
Reserve Life Index (yr)(1)	5.2	4.8	5.6	4.5	5.3
Reserve Replacement Ratio(1)	1.2	0.5	0.6	1.2	0.7
FD&A Recycle Ratio(1)	2.7	1.3	1.4	0.9	(46.3)
Total Proved
FD&A ($/boe)(1)(2)	1.29	1.09	8.73	14.33	(15.78)
F&D ($/boe)(1)(2)	1.29	(6.83)	8.16	12.03	2.46
Reserve Life Index (yr)(1)	10.9	9.9	11.1	8.0	9.8
Reserve Replacement Ratio(1)	(1.0)	0.3	1.3	1.1	0.5
FD&A Recycle Ratio(1)	9.8	14.4	1.8	1.0	(0.7)
Future Development Cost ($000s)	156,815	174,027	194,757	182,086	201,556
Total Proved + Probable
FD&A ($/boe)(1)(2)	0.37	(7.32)	6.49	14.87	350.09
F&D ($/boe)(1)(2)	0.37	190.21	5.15	17.28	(8.06)
Reserve Life Index (yr)(1)	17.7	15.4	17.1	12.3	14.6
Reserve Replacement Ratio(1)	(1.3)	—	1.5	1.7	(0.1)
FD&A Recycle Ratio(1)	33.7	(2.1)	2.4	1.0	—
Future Development Cost ($000s)	252,335	267,652	290,876	283,030	269,144

(1)Refer to "Oil and Gas Disclosures" in the Management's Discussion & Analysis attached hereto.

(2)Certain changes in FD&A and F&D produce non-meaningful figures as discussed in "Oil and Gas Disclosures" in the Management's Discussion & Analysis attached hereto.While FD&A and F&D costs, reserve life index, reserve replacement ratio and finding and development costs are commonly used in the oil and nature gas industry and have been prepared by management, these terms do not have a standardized meaning and may not be comparable to similar measures presented by other companies and, therefore, should not be used to make such comparisons.

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NET ASSET VALUE

The following table shows the Company's Net Asset Value ("NAV"), calculated using Sproule's December 31, 2020 price forecast:

As at December 31, 2020 ($000s except per share)	Proved Developed
	Producing	Total Proved	Proved + Probable
Present Value Reserves, before tax (discounted at 10%)(1)	119,122	159,438	256,991
Undeveloped Land Value(2)	17,568	17,568	17,568
Net Debt(3)	(114,361)	(114,361)	(114,361)
Net Asset Value	22,329	62,645	160,198
Estimated Net Asset Value per Share	$0.45	$1.27	$3.24

(1)Based on the 2020 Sproule Report, using the forecast future prices and costs.

(2)Based on the exploration and evaluation assets as per the Company's December 31, 2020 audited consolidated financial statements.

(3)See "Non-GAAP Financial Measures" in the Management's Discussion & Analysis attached hereto.

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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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CONSOLIDATED ANNUAL FINANCIAL STATEMENTS As at and for the years ended December 31, 2020 and 2019

INDEPENDENT AUDITORS’ REPORT

To the Shareholders of Petrus Resources Ltd.

Opinion

We have audited the consolidated financial statements of Petrus Resources Ltd. (the Company), which comprise the consolidated balance sheets as at December 31, 2020 and 2019, and the consolidated statements of net loss and comprehensive loss, consolidated statements of changes in shareholders’ equity and consolidated statements of cash flows for the years then ended, and notes to the consolidated financial statements, including a summary of significant accounting policies.

In our opinion, the accompanying consolidated financial statements present fairly, in all material respects, the consolidated financial position of the Company as at December 31, 2020 and 2019, and its consolidated financial performance and its consolidated cash flows for the years then ended in accordance with International Financial Reporting Standards (IFRSs).

Basis for Opinion

We conducted our audit in accordance with Canadian generally accepted auditing standards. Our responsibilities under those standards are further described in the Auditor’s Responsibilities for the Audit of the Consolidated Financial Statements section of our report. We are independent of the Company in accordance with the ethical requirements that are relevant to our audit of the consolidated financial statements in Canada, and we have fulfilled our other ethical responsibilities in accordance with these requirements. We believe that the audit evidence we have obtained is sufficient and appropriate to provide a basis for our opinion.

Material Uncertainty Related to Going Concern

We draw attention to Note 2(a) in the consolidated financial statements, which indicates that the Company’s continued successful operations are dependent on its ability to restructure its debt or obtain additional financing. As stated in Note 2(a) these events or conditions indicate that a material uncertainty exists that casts significant doubt on the Company’s ability to continue as a going concern. Our opinion is not modified in respect of this matter.

Key Audit Matters

Key audit matters are those matters that, in our professional judgment, were of most significance in our audit of the financial statements of the current period. In addition to the matter described in the Material Uncertainty Related to Going Concern section, we have determined the matter described below to be the key audit matter to be communicated in our report. This matter was addressed in the context of our audit of the financial statements as a whole, and in forming our opinion thereon, and we do not provide a separate opinion on this matter. For the matter below, our description of how our audit addressed the matter is provided in that context.

We have fulfilled the responsibilities described in the Auditor’s Responsibilities for the Audit of the Consolidated Financial Statements section of our report, including in relation to this matter. Accordingly, our audit included the performance of procedures designed to respond to our assessment of the risks of material misstatement of the consolidated financial statements. The results of our audit procedures, including the procedures performed to address the matter below, provide the basis for our audit opinion on the accompanying consolidated financial statements.

Impairment of Property, Plant and Equipment (“PP&E”) and Exploration and Evaluation (“E&E”) Assets

As at December 31, 2020, the carrying value of PP&E and E&E was $152 million and $18 million, respectively. For the year ended December 31, 2020, an impairment charge of $75 million and $23 million was recorded with respect to PP&E and E&E, respectively. PP&E and E&E are tested for impairment only when circumstances indicate that the carrying value of a cash generating unit (‘CGU’) may exceed the recoverable amount. Impairment is determined by estimating a CGU’s respective recoverable amount. The recoverable amount of the Ferrier CGU was determined by using the value-in-use method, whereby the net cash flows are estimated using current business models and budgets approved by management for the CGU. The Company discloses significant judgments, estimates and assumptions in respect of impairment in Note 3 to the financial statements, and the results of their analysis in Note 5 and 6.

Auditing the estimated recoverable amount of the Company’s Ferrier CGU was complex due to the subjective nature of the various management inputs and assumptions and commodity price volatility. The primary inputs noted in the value-in-use model were production, pricing, royalties, operating costs, capital costs, general and administrative (G&A) expenses and discount rate.

To test the Company's estimated recoverable amount for the Ferrier CGU, we performed the following procedures, among others:

• Involved our valuation specialists to assess the methodology applied, and the various inputs utilized in determining the discount rate by referencing current industry, economic, and comparable company information, company and cash-flow specific risk premiums.

• Compared forecasted production against historically realized production.

• Compared forecasted prices used in the impairment test to third-party reserve engineer data.

• Assessed forecasted royalties, operating costs, G&A and capital cost data by comparing it to historical performance.

• Assessed the competence and objectivity of the Company’s external reserve engineer.

• Tested the completeness and accuracy of the reserve engineer report by agreeing all current year production, revenue, royalty, operating cost, and capital cost data to management’s accounting records.

• Evaluated the adequacy of the impairment note disclosure included in Notes 5 and 6 of the accompanying financial statements in relation to this matter.

Other Information

Management is responsible for the other information. The other information comprises:

• a. Management’s Discussion and Analysis

• b. Annual Report

Our opinion on the consolidated financial statements does not cover the other information and we do not express any form of assurance conclusion thereon.

In connection with our audit of the consolidated financial statements, our responsibility is to read the other information, and in doing so, consider whether the other information is materially inconsistent with the consolidated financial statements or our knowledge obtained in the audit or otherwise appears to be materially misstated.

We obtained Management’s Discussion & Analysis prior to the date of this auditor’s report. If, based on the work we have performed, we conclude that there is a material misstatement of this other information, we are required to report that fact. We have nothing to report in this regard.

We obtained the Annual Report prior to the date of this auditor’s report. If, based on the work we have performed, we conclude that there is a material misstatement of this other information, we are required to report that fact. We have nothing to report in this regard.

Responsibilities of Management and Those Charged with Governance for the Consolidated Financial Statements

Management is responsible for the preparation and fair presentation of the consolidated financial statements in accordance with IFRSs, and for such internal control as management determines is necessary to enable the preparation of consolidated financial statements that are free from material misstatement, whether due to fraud or error.

In preparing the consolidated financial statements, management is responsible for assessing the Company’s ability to continue as a going concern, disclosing, as applicable, matters related to going concern and using the going concern basis of accounting unless management either intends to liquidate the Company or to cease operations, or has no realistic alternative but to do so.

Those charged with governance are responsible for overseeing the Company’s financial reporting process.

Auditor’s Responsibilities for the Audit of the Consolidated Financial Statements

Our objectives are to obtain reasonable assurance about whether the consolidated financial statements as a whole are free from material misstatement, whether due to fraud or error, and to issue an auditor’s report that includes our opinion. Reasonable assurance is a high level of assurance, but is not a guarantee that an audit conducted in accordance with Canadian generally accepted auditing standards will always detect a material misstatement when it exists. Misstatements can arise from fraud or error and are considered material if, individually or in the aggregate, they could reasonably be expected to influence the economic decisions of users taken on the basis of these consolidated financial statements.

As part of an audit in accordance with Canadian generally accepted auditing standards, we exercise professional judgment and maintain professional skepticism throughout the audit. We also:

• a. Identify and assess the risks of material misstatement of the consolidated financial statements, whether due to fraud or error, design and perform audit procedures responsive to those risks, and obtain audit evidence that is sufficient and appropriate to provide a basis for our opinion. The risk of not detecting a material misstatement resulting from fraud is higher than for one resulting from error, as fraud may involve collusion, forgery, intentional omissions, misrepresentations, or the override of internal control.

• b. Obtain an understanding of internal control relevant to the audit in order to design audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of the Company’s internal control.

• c. Evaluate the appropriateness of accounting policies used and the reasonableness of accounting estimates and related disclosures made by management.

• d. Conclude on the appropriateness of management’s use of the going concern basis of accounting and, based on the audit evidence obtained, whether a material uncertainty exists related to events or conditions that may cast significant doubt on the Company’s ability to continue as a going concern. If we conclude that a material uncertainty exists, we are required to draw attention in our auditor’s report to the related disclosures in the consolidated financial statements or, if such disclosures are inadequate, to modify our opinion. Our conclusions are based on the audit evidence obtained up to the date of our auditor’s report. However, future events or conditions may cause the Company to cease to continue as a going concern.

• e. Evaluate the overall presentation, structure and content of the consolidated financial statements, including the disclosures, and whether the consolidated financial statements represent the underlying transactions and events in a manner that achieves fair presentation.

We communicate with those charged with governance regarding, among other matters, the planned scope and timing of the audit and significant audit findings, including any significant deficiencies in internal control that we identify during our audit.

We also provide those charged with governance with a statement that we have complied with relevant ethical requirements regarding independence, and to communicate with them all relationships and other matters that may reasonably be thought to bear on our independence, and where applicable, related safeguards.

From the matters communicated with those charged with governance, we determine those matters that were of most significance in the audit of the consolidated financial statements of the current period and are therefore the key audit matters. We describe these matters in our auditor’s report unless law or regulation precludes public disclosure about the matter or when, in extremely rare circumstances, we determine that a matter should not be communicated in our report because the adverse consequences of doing so would reasonably be expected to outweigh the public interest benefits of such communication.

The engagement partner on the audit resulting in this independent auditor’s report is Ryan MacDonald.

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Chartered Professional Accountants Calgary, Alberta February 24, 2021

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CONSOLIDATED BALANCE SHEETS

(Presented in 000’s of Canadian dollars)

As at	December 31, 2020	December 31, 2019
ASSETS
Current
Cash	—	256
Deposits and prepaid expenses	1,150	1,328
Accounts receivable_(note 15)_	6,278	13,036
Risk management asset_(note 10)_	934	—
Total current assets	8,362	14,620
Non-current
Risk management asset_(note 10)_	15	11
Exploration and evaluation assets_(notes 5)_	17,568	36,116
Property, plant and equipment_(note 6)_	151,969	238,478
Total assets	177,914	289,225
LIABILITIES AND SHAREHOLDERS’ EQUITY
Current liabilities
Bank indebtedness	32	—
Current portion of long term debt_(note 7)_	114,049	127,002
Accounts payable and accrued liabilities_(note 15)_	7,708	11,362
Risk management liability_(note 10)_	986	1,679
Lease obligations_(note 8)_	188	136
Total current liabilities	122,963	140,179
Non-current liabilities
Lease obligations_(note 8)_	824	1,013
Decommissioning obligation_(note 9)_	44,456	41,259
Risk management liability (note 10)	41	74
Total liabilities	168,284	182,525
Shareholders’ equity
Share capital_(note 11)_	430,119	430,119
Contributed surplus	9,596	9,112
Deficit	(430,085)	(332,531)
Total shareholders' equity	9,630	106,700
Total liabilities and shareholders' equity	177,914	289,225

Going concern (note 2) Commitments (note 19) See accompanying notes to the consolidated financial statements

Approved by the Board of Directors,

(signed) “Don T. Gray”

(signed) “Donald Cormack”

Don T. Gray Chairman

Donald Cormack

Director

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CONSOLIDATED STATEMENTS OF NET LOSS AND COMPREHENSIVE LOSS

(Presented in 000’s of Canadian dollars, except per share amounts)

(Presented in 000’s of Canadian dollars, except per share amounts)
	Year ended	Year ended
	December 31, 2020	December 31, 2019
REVENUE
Oil and natural gas revenue(note 20)	50,368	71,398
Royaltyexpense	(5,194)	(7,114)
Net oil and natural gas revenue	45,174	64,284
Other income	354	106
Netgain(loss)on financial derivatives_(note 10)_	8,179	(12,617)
	53,707	51,773
EXPENSES
Operating_(note 13)_	11,223	12,873
Transportation	3,452	3,814
General and administrative_(note 14)_	3,409	3,644
Share-based compensation_(note 11)_	381	401
Finance_(note 17)_	9,593	9,513
Exploration and evaluation_(note 5)_	18	2,004
Depletion and depreciation_(note 6)_	25,231	36,564
Loss (gain) on sale of assets	(46)	481
Impairment_(notes 5 and 6)_	98,000	24,655
Total expenses	151,261	93,949
NET LOSS AND COMPREHENSIVE LOSS	(97,554)	(42,176)
Net loss per common share
Basic and diluted(note 12)	(1.97)	(0.85)

See accompanying notes to the consolidated financial statements

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CONSOLIDATED STATEMENTS OF CHANGES IN SHAREHOLDERS’ EQUITY

(Presented in 000’s of Canadian dollars)

(Presented in 000’s of Canadian dollars)
	Share	Contributed
	Capital	Surplus	Deficit	Total
Balance, December 31, 2018	430,119	8,384	(290,355)	148,148
Net loss	—	—	(42,176)	(42,176)
Share-based compensation	—	728	—	728
Balance, December 31, 2019	430,119	9,112	(332,531)	106,700
Net loss	—	—	(97,554)	(97,554)
Share-based compensation_(note 11)_	—	484	—	484
Balance, December 31, 2020	430,119	9,596	(430,085)	9,630

See accompanying notes to the consolidated financial statements

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CONSOLIDATED STATEMENTS OF CASH FLOWS

(Presented in 000’s of Canadian dollars)

(Presented in 000’s of Canadian dollars)
		Year ended	Year ended
		December 31, 2020	December 31, 2019
OPERATING ACTIVITIES
Net loss		(97,554)	(42,176)
Adjust items not affecting cash:
Share-based compensation_(note 11)_		381	401
Unrealized loss (gain) on financial derivatives (note 10)		(1,661)	11,273
Non-cash finance expenses_(note 17)_		1,119	1,272
Non-cash term loan interest payment-in-kind		1,813	—
Depletion and depreciation_(note 6)_		25,231	36,564
Impairment_(notes 5 and 6)_		98,000	24,655
Exploration and evaluation expense_(note 5)_		18	2,004
Loss (gain) on sale of assets		(46)	481
Decommissioning expenditures_(note 9)_		(904)	(849)
Funds flow		26,397	33,625
Change in operatingnon-cash workingcapital_(note 18)_		2,527	(5,803)
Cash flows from operating activities		28,924	27,822
FINANCING ACTIVITIES
Repayment of revolving credit facility_(note 18)_		(14,750)	(4,749)
Increase (repayment) of bank indebtedness_(note 18)_		32	(381)
Repayment of lease liabilities_(note 8)_		(137)	(400)
Change in financingnon-cash workingcapital_(note 18)_		162	196
Cash flows used in financing activities		(14,693)	(5,334)
INVESTING ACTIVITIES
Exploration and evaluation asset dispositions_(note 5)_		—	651
Exploration and evaluation asset expenditures_(note 5)_		(4,869)	(394)
Petroleum and natural gas property expenditures_(note 6)_		(9,439)	(17,655)
Other capital expenditures		—	(24)
Change in investingnon-cash workingcapital_(note 18)_		(179)	(4,873)
Cash used in investing activities		(14,487)	(22,295)
Increase in cash		(256)	193
Cash,beginningofperiod		256	63
Cash, end ofperiod		—	256
Cash interestpaid_(note 17)_		6,661	8,241

See accompanying notes to the consolidated financial statements

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NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

For the years ended December 31, 2020 and 2019

1. NATURE OF THE ORGANIZATION

Petrus Resources Ltd. (the “Company” or "Petrus") was incorporated under the laws of the Province of Alberta on November 25, 2015. The principal undertaking of Petrus is the investment in energy business-related assets. The operations of the Company consist of the acquisition, development, exploration and exploitation of these assets. These consolidated financial statements reflect only the Company’s proportionate interest in such activities and are comprised of the Company and its subsidiaries, Petrus Resources Corp. and Petrus Resources Inc.

The Company’s head office is located at 2400, 240 - 4th Avenue SW, Calgary, Alberta, Canada.

These consolidated financial statements, for the years ended December 31, 2020 and 2019, were approved by the Company’s Audit Committee and Board of Directors on February 24, 2021.

2. BASIS OF PRESENTATION

(a) Going Concern

These financial statements have been prepared in accordance with generally accepted accounting principles applicable to a going concern, which assumes that the Company will be able to realize its assets and discharge its liabilities in the normal course of business.

As at December 31, 2020, the Company's revolving credit facility ("RCF") and Term Loan was due on May 31, 2021 and July 31, 2021, respectively. The borrowings under the RCF and the Term Loan are classified as current liabilities in the December 31, 2020 consolidated financial statements. The Company remains in compliance with each financial covenant. However, the classification of the debt instruments resulted in a working capital deficiency (excluding non-cash risk management assets and liabilities) of $114.5 million as at December 31, 2020. For the year ended December 31, 2020, the Company generated funds flow of $26.4 million and reduced the amounts owing on its RCF by $14.8 million. The RCF syndicate of lenders had completed the semi-annual borrowing base review and reconfirmed the Company's borrowing base at $85.8 million.

The Company is actively engaging with the RCF syndicate of lenders and the Term Loan lender to extend the RCF and Term Loan. However, there can be no certainty as to the ability of the Company to successfully extend its RCF and Term Loan. There is a material uncertainty that may cast significant doubt on the Company’s ability to continue as a going concern. These financial statements do not include adjustments to the recoverability and classification of recorded asset and liabilities and related expenses that might be necessary should the Company be unable to continue as a going concern and therefore be required to realize its assets and liquidate its liabilities and commitments in other than the normal course of business at amounts different from those in the accompanying consolidated financial statements. Such adjustments could be material.

(b) Statement of Compliance

These consolidated financial statements have been prepared by management in accordance with International Financial Reporting Standards (“IFRS”) as issued by the International Accounting Standards Board (“IASB”).

(c) Measurement Basis

These consolidated financial statements were prepared on the basis of historical cost except for financial derivatives which are measured at fair value. This method is consistent with the method used in prior years. These consolidated financial statements are presented in Canadian dollars.

(d) Consolidation

These audited consolidated financial statements include the accounts of Petrus and its 100% owned subsidiaries, Petrus Resources Corp. and Petrus Resources Inc. Subsidiaries are consolidated from the date control is obtained until the date control ends. Control exists where the Company has power over the investee, exposure or rights to variable returns from the investee and the ability to use its power over the investee to affect returns. All intra-group balances and transactions are eliminated on consolidation.

(e) 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.

Depletion and reserve estimates

Petroleum and natural gas assets are depleted on a unit of production basis at a rate calculated by reference to proved and probable reserves determined in accordance with National Instrument 51-101 - Standards of Disclosure for Oil and Gas Activities (“NI 51-101”). The calculation incorporates the estimated future cost of developing and extracting those reserves. Proved and probable reserves are estimated using independent reservoir engineering reports and represent the estimated quantities of crude oil, natural gas and natural gas liquids which geological, geophysical and engineering data demonstrate with a specified degree of certainty to be recoverable in future years from known

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reservoirs and which are considered commercially producible. Reserves estimates, although not reported as part of the Company’s financial statements, can have a significant effect on net income (loss), assets and liabilities as a result of their impact on depletion and depreciation, decommissioning liabilities, deferred taxes, asset impairments and business combinations. Independent reservoir engineers perform evaluations of the Company’s petroleum and natural gas reserves on an annual basis. The estimation of reserves is an inherently complex process requiring significant judgment. Estimates of economically recoverable petroleum and natural gas reserves are based upon a number of variables and assumptions such as geoscientific interpretation, production forecasts, commodity prices, costs and related future cash flows, all of which may vary considerably from actual results. These estimates are expected to be revised upward or downward over time, as additional information such as reservoir performance becomes available or as economic conditions change.

Impairment indicators and cash-generating units

For purposes of impairment testing, exploration and evaluation assets and petroleum and natural gas assets are aggregated into cashgenerating units (“CGUs”), based on separately identifiable and largely independent cash inflows. The determination of the Company’s CGUs is subject to judgment.

The recoverable amounts of CGU’s and individual assets have been determined based on the higher of the value-in-use calculations and fair value less costs of disposal. These calculations require the use of estimates and assumptions, including the discount rate, future petroleum and natural gas prices, expected production volumes and anticipated recoverable quantities of proved and probable reserves. These assumptions are subject to change as new information becomes available and changes in economic conditions take place. Changes may impact the estimated life of the field and economical reserves recoverable and may require a material adjustment to the carrying value of exploration and evaluation assets and petroleum and natural gas assets. The Company monitors internal and external indicators of impairment relating to its tangible assets.

Technical feasibility and commercial viability of exploration and evaluation assets

The determination of technical feasibility and commercial viability, based on the presence of proved and probable reserves, results in the transfer of assets from exploration and evaluation assets to property, plant and equipment. As discussed above, the estimate of proved and probable reserves is inherently complex and requires significant judgment. Thus any material change to reserve estimates could affect the technical feasibility and commercial viability of the underlying assets.

Financial instruments

Financial instruments are subject to valuations at the end of each reporting period. Generally the valuation is based on active and efficient markets. However, certain financial instruments may not be traded on an efficient market or the market may disappear or be subject to conditions that impede the efficiency of the market.

Decommissioning obligation

At the end of the operating life of the Company’s facilities and properties and upon retirement of its petroleum and natural gas assets, decommissioning costs will be incurred by the Company. This requires judgment regarding abandonment date, future environmental and regulatory legislation, the extent of reclamation activities, the engineering methodology for estimating cost, future removal technologies in determining the removal cost and discount rates to determine the present value of these cash flows.

Income taxes

Tax provisions are based on enacted or substantively enacted laws. Changes in those laws could affect amounts recognized in income or loss both in the period of change, which would include any impact on cumulative provisions, and in future periods. Changes in tax laws in the jurisdictions in which the Company operates could limit the ability of the Company to obtain tax deductions in future periods. Income taxes are subject to measurement uncertainty. Significant judgment can be involved in the recognition of deferred tax assets.

Measurement of share-based compensation

Share-based compensation recorded pursuant to share-based compensation plans are subject to estimated fair values, forfeiture rates and the future attainment of performance criteria.

Contingencies

By their nature, contingencies will only be resolved when one or more future events occur or fail to occur. The assessment of contingencies inherently involves the exercise of significant judgment and estimates of the outcome of future events.

3. SIGNIFICANT ACCOUNTING POLICIES

(a) Revenue recognition

Revenue from contracts with customers is recognized when or as Petrus satisfies a performance obligation by transferring a promised good or service to a customer. The transfer of control of oil, natural gas, natural gas liquids usually occurs at a point in time and coincides with title passing to the customer and the customer taking physical possession. The transaction price for variable price contracts is based on the commodity price, adjusted for quality, location and other factors. The amount of revenue recognized is based on the agreed transaction price with any variability in transaction price recognized in the same period.

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(b) Exploration & evaluation assets

Capitalization

All costs incurred after the rights to explore an area have been obtained, such as geological and geophysical costs, other direct costs of exploration (drilling, testing and evaluating the technical feasibility and commercial viability of extraction) and appraisal and including any directly attributable general and administration costs and share-based payments, are accumulated and capitalized as exploration and evaluation assets.

Certain costs incurred prior to acquiring the legal rights to explore are charged directly to net income (loss).

Depletion & depreciation

Exploration and evaluation costs are not amortized prior to the conclusion of appraisal activities. At the completion of appraisal activities, if technical feasibility is demonstrated and commercial reserves are discovered, then the carrying value of the relevant exploration and evaluation asset will be reclassified as a property, plant and equipment asset into the CGU to which it relates, but only after the carrying value of the relevant exploration and evaluation asset has been assessed for impairment and, where appropriate, its carrying value adjusted. Technical feasibility and commercial viability are considered to be demonstrable when proved or probable reserves are determined to exist. If it is determined that technical feasibility and commercial viability have not been achieved in relation to the exploration and evaluation assets appraised, all other associated costs are written down to the recoverable amount in net income (loss).

Expired land leases included as undeveloped land in exploration and evaluation assets are recognized in exploration and evaluation cost in net income (loss) upon expiry and are considered prior to expiry. Management considers upcoming land lease expiries and may recognize the costs in advance of expiry.

Impairment

Indicators of impairment of exploration and evaluation assets are assessed at each reporting date which can include upcoming land lease expiries, third party land valuations and other information . When there are such indications, an impairment test is carried out and any resulting impairment loss is written off to net income (loss). The recoverable amount is the greater of fair value, less costs of disposal, or value-in-use.

(c) Property, plant and equipment

The Company’s property, plant and equipment is comprised of petroleum and natural gas assets and corporate assets.

Capitalization

Petroleum and natural gas assets are measured at cost less accumulated depletion and depreciation and accumulated impairment losses, if any. Petroleum and natural gas assets consists of the purchase price and costs directly attributable to bringing the asset to the location and condition necessary for its intended use. Petroleum and natural gas assets include developing and producing interests such as land acquisitions, geological and geophysical costs, facility and production equipment, including any directly attributable general and administration costs and share-based payments and the initial estimate of the costs of dismantling and removing an asset and restoring the site on which it was located.

Subsequent costs

Costs incurred subsequent to the determination of technical feasibility and commercial viability are recognized as developing and producing petroleum and natural gas interests when they increase the future economic benefits embodied in the specific asset to which they relate. Such capitalized petroleum and natural gas interests generally represent costs incurred in developing proved and/or probable reserves, and are accumulated on a field or geotechnical area basis. The cost of day-to-day servicing of an item of petroleum and natural gas assets is expensed in income or loss as incurred. Petroleum and natural gas assets are derecognized upon disposal or when no future economic benefits are expected to arise from the continued use of the asset. Any gain or loss arising from the disposal of an asset, determined as the difference between the net disposal proceeds and the carrying amount of the asset, is recognized in net income or loss.

Depletion and depreciation

The costs for petroleum and natural gas properties, including related pipelines and facilities, are depleted using a unit-of-production method based on the commercial proved and probable reserves.

Petroleum and natural gas assets are not depleted until production commences. This depletion calculation includes actual production in the period and total estimated proved and probable reserves attributable to the assets being depleted, taking into account total capitalized costs plus estimated future development costs necessary to bring those reserves into production. Relative volumes of reserves and production (before royalties) are converted at the energy equivalent conversion ratio of six thousand cubic feet of natural gas to one barrel of oil.

Proved and probable reserves are estimated using independent reservoir engineering reports and represent the estimated quantities of crude oil, natural gas and natural gas liquids which geological, geophysical and engineering data demonstrate with a specified degree of certainty to be recoverable in future years from known reservoirs and which are considered commercially producible.

Corporate assets are recorded at cost less accumulated depreciation. Depreciation is calculated on a declining balance method so as to write off the cost of these assets, less estimated residual values, over their estimated useful lives consistent with the treatment used for tax purposes.

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Impairment

The assessment for impairment entails comparing the carrying value of the CGU with its recoverable amount: that is, the higher of fair value, less costs of disposal, and value in use. Petrus’ property, plant and equipment are grouped into CGUs based on separately identifiable and largely independent cash inflows considering geological characteristics, shared infrastructure and exposure to market risks. Estimates of future cash flows used in the calculation of the recoverable amount are based on reserve evaluation reports prepared by independent reservoir engineers.

The CGU’s are reviewed quarterly for indicators of impairment. Indicators are events or changes in circumstances that indicate that the carrying amount may not be recoverable. If indicators of impairment exist, the recoverable amount of the CGU is estimated. If the carrying amount of the CGU exceeds the recoverable amount, the CGU is written down with an impairment recognized in net income (loss).

The recoverable amount is the higher of fair value, less costs of disposal, and the value-in-use. Fair value, less costs of disposal, is derived by estimating the discounted after-tax future net cash flows. Discounted future net cash flows are based on forecast commodity prices and costs over the expected economic life of the reserves and discounted using market-based rates to reflect a market participant’s view of the risks associated with the assets. Value-in-use is assessed using the expected future cash flows discounted at a pre-tax rate.

Impairments of property, plant and equipment are reversed when there is significant evidence that the impairment has been reversed, but only to the extent of what the carrying amount would have been had no impairment been recognized.

(d) Decommissioning obligations

The Company’s activities give rise to dismantling, decommissioning and reclamation requirements. Costs related to these abandonment activities are estimated by management in consultation with the Company’s engineers based on risk-adjusted current costs which take into consideration current technology in accordance with existing legislation and industry practices.

Decommissioning obligations are measured at the present value of the best estimate of expenditures required to settle the obligations at the reporting date. When the fair value of the liability is initially measured, the estimated cost, discounted using a risk-free rate, is capitalized by increasing the carrying amount of the related petroleum and natural gas assets. The increase in the provision due to the passage of time, or accretion, is recognized as a finance expense. Increases and decreases due to revisions in the estimated future cash flows are recorded as adjustments to the carrying amount of the related petroleum and natural gas assets.

Actual costs incurred upon settlement of the liability are charged against the obligation to the extent that the obligation was previously established. The carrying amount capitalized in petroleum and natural gas assets is depleted in accordance with the Company’s depletion policy. The Company reviews the obligation at each reporting date and revisions to the estimated timing of cash flows, discount rates and estimated costs will result in an increase or decrease to the obligations. Any difference between the actual costs incurred upon settlement of the obligation and recorded liability is recognized as an increase or reduction in income.

(e) Finance expenses

Finance expense may be comprised of interest expense on borrowings, acquisition related (transaction) costs, foreign exchange expenses and accretion of the discount on decommissioning obligations.

(f) Financial instruments

Financial instruments are recognized initially at fair value plus any directly attributable transaction costs. Subsequent to initial recognition, financial instruments are measured based on their classification as described below:

• Fair value through profit or loss: Financial instruments under this classification include risk management assets and liabilities.

• Amortized cost: Financial instruments under this classification include cash, accounts receivable, deposits, bank indebtedness, accounts payable and long term debt.

(g) Share capital

Common shares are classified as equity. Incremental costs directly attributable to the issuance of common shares are recognized as a reduction in share capital, net of any tax effects.

(h) Flow-through shares

The resources expenditure deductions for income tax purposes related to exploratory activities funded by flow-through shares are renounced to investors in accordance with tax legislation. Upon issuance of a flow-through share, a liability is recognized representing the premium paid on flowthrough common shares over regular common shares. This liability is reduced as the expenditures are incurred and tax attributes are renounced.

(i) Income taxes

The Company’s income tax expense is comprised of current and deferred tax. Income tax expense is recognized through income or loss except to the extent that it relates to items recognized directly in equity, in which case the related income taxes are also recognized in equity.

Current tax is the expected tax payable on taxable income for the period, using tax rates enacted or substantively enacted at the reporting date, and any adjustment to tax payable in respect of previous years.

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Deferred tax is recognized on temporary differences between the carrying amounts of assets and liabilities in the financial statements and the corresponding tax basis used in the computation of taxable income. Deferred tax liabilities are generally recognized for all taxable temporary differences. Deferred tax assets are generally recognized for all deductible temporary differences to the extent that it is probable that taxable income will be available against which those deductible temporary differences can be utilized. Assessing the recoverability of deferred tax assets requires management to make significant estimates related to expectations of future taxable income. Estimates of future taxable income are based on forecast cash flows from operations and the application of existing tax laws in the jurisdictions of Alberta and Canada. The carrying amount of deferred tax assets is reviewed at the end of each reporting period and reduced to the extent that it is no longer probable that sufficient taxable income will be available to allow all or part of the asset to be recovered.

(j) Joint arrangements

A portion of the Company’s exploration, development and production activities are conducted jointly with others through unincorporated joint operations. These financial statements reflect only the Company’s proportionate interest of these joint operations and the proportionate share of the relevant revenue and related costs.

(k) Share-based compensation

Share-based compensation expense is determined based on the estimated fair value of shares on the date of grant. Forfeitures are estimated at the grant date and are subsequently adjusted to reflect actual forfeitures. The expense is recognized over the service period, with a corresponding increase to contributed surplus. The Company capitalizes the qualifying portion of share-based compensation expense directly attributable to the exploration and development activities of exploration and evaluation assets and petroleum and natural gas assets, with a corresponding decrease to share-based compensation expense. At the time the stock options or performance warrants are exercised, the issuance of common shares is recorded as an increase to shareholders’ capital and a corresponding decrease to contributed surplus.

For deferred share units (“DSUs”) that can be settled in cash or equity at the option of the Company, the fair value of the DSUs is recognized as stockbased compensation expense, with a corresponding increase in contributed surplus.

(l) Earnings per share

Earnings per share are presented for basic and diluted earnings. Basic per share information is computed by dividing the net income (loss) for the period attributable to equity owners of the Company by the weighted average number of common shares outstanding during the period. The weighted average number of shares for diluted earnings per share information is calculated using the treasury stock method whereby it is assumed that proceeds obtained upon exercise of performance warrants and stock options would be used to purchase common shares at the average market price during the period. The treasury stock method also assumes that the deemed proceeds related to unrecognized share-based payments expense are used to repurchase shares at the average market price during the period. Under the treasury stock method, stock options and share warrants have a dilutive effect only when the average market price of the common shares during the period exceeds the exercise price of the options or warrants (they are "inthe-money"). Exercise of in-the-money stock options and share warrants is assumed at the beginning of the year or date of issuance, if later. Should the Company have a loss for the period, stock options and share warrants would be anti-dilutive and therefore will have no effect on the determination of loss per share.

(m) Leases

At inception of a contract, the Company assesses whether a contract is, or contains a lease. A contract is, or contains a lease if the contract conveys the right to control the use of an identified asset for a period of time in exchange for consideration. To assess whether a a contract conveys the right to control the use of an identified asset, the Company assesses whether:

• the contract involves the use of an identified asset - this may be specified explicitly or implicitly, and should be physically distinct or represent substantially all of the capacity of a physically distinct asset. If the suppler has a substantive substitution right, the the asset is not identified;

• the Company has the right to obtain substantially all of the economic benefits from use of the asset throughout the period of use; and

• the Company has the right to direct the use of the asset. The Company has this right when it has the decision-making rights that are most relevant to changing how and for what purpose the asset is used is predetermined, the Company has the right to direct the use of the asset if either:

• the Company has the right to operate the asset; or

• the Company designed the asset in a way that predetermines how and for what purpose it will be used.

This policy is applied to contracts entered into, or changed, on or after January 1, 2019.

i) As a lessee

The Company recognizes a right-of-use ("ROU") asset and a lease liability at the lease commencement date. The ROU asset is initially measured at cost, which comprises the initial amount of the lease liability adjusted for any lease payments made at or before the commencement date, plus any initial direct costs incurred and an estimate of costs to dismantle and remove the underlying asset or to restore the underlying asset or the site on which it is located, less any lease incentives received.

The ROU asset is subsequently depreciated using the straight-line method from the commencement date to the earlier of the end of the useful life of the ROU asset or the end of the lease term. The estimated useful lives of ROU assets are determined on the same basis as those of property and equipment. In addition, the ROU asset is periodically reduced by impairment losses, if any, and adjusted for certain remeasurements of the lease liability.

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The lease liability is initially measured at the present value of the lease payments that are not paid at the commencement date, discounted using the intrest rate implicit in the lease or, if that rate cannot be readily determined, the Company's incremental borrowing rate. Generally, the Company uses its incremental borrowing rate as the discount rate.

(n) Government grants

Government grants are recognized when there is reasonable assurance that the Company will comply with the conditions attaching to it, and that the grant will be received. Grants related to income are presented in the Consolidated Statement of Comprehensive Income (loss) and are deducted in reporting the related expense. Grants related to assets are presented in the Consolidated Balance Sheet by deducting the grant in arriving at the carrying amount of the asset or recognized as other income.

(o) New standards and interpretations

There are no new standards or interpretations to report.

4. DETERMINATION OF FAIR VALUES

A number of the Company’s accounting policies and disclosures require the determination of fair value, for both financial and non-financial assets and liabilities. Fair values have been determined for measurement and/or disclosure purposes based on the following methods. When applicable, further information about the assumptions made in determining fair values is disclosed in the notes specific to that asset or liability.

Petroleum and natural gas properties and equipment and exploration and evaluation assets

The fair value of petroleum and natural gas properties and equipment recognized in a business combination and for impairment testing, is based on market values. The market value of petroleum and natural gas properties and equipment is the estimated amount for which property, plant and equipment could be exchanged on the acquisition date between a willing buyer and a willing seller in an arm’s length transaction after proper marketing wherein the parties had each acted knowledgeably, prudently and without compulsion. The market value of oil and natural gas interests (included in petroleum and natural gas properties and equipment) and intangible exploration and evaluation assets is estimated with reference to the discounted cash flow expected to be derived from oil and natural gas production based on externally prepared reserve reports. The risk-adjusted discount rate is specific to the asset with reference to general market conditions. The value-in-use and the fair value less costs of disposal value, or value, used to determine the recoverable amount of the impaired petroleum and natural gas properties are classified as Level 3 fair value measurements. Refer to “Financial Instruments” section below for fair value hierarchy classifications.

Derivatives

The fair value of commodity price risk management contracts is determined by discounting the difference between the contracted prices and published forward price curves as at the balance sheet date, using the remaining contracted oil and natural gas volumes and a risk-free interest rate (based on published government rates). The fair value of options is based on option models that use published information with respect to volatility, prices, interest rates and counter-party credit risks.

Share-based payments

The fair value of employee share-based payments is measured using a Black-Scholes option-pricing model. Measurement inputs include share price on measurement date, exercise price of the instrument, expected volatility in share price (based on weighted average historic volatility adjusted for changes expected due to publicly available information), weighted average expected life of the instruments (based on historical experience and general option holder behavior), expected dividend yield, risk-free interest rate (based on government bonds) and estimated forfeiture rate at each reporting date.

Financial instruments

The Company’s fair value measurements require disclosure about how the fair value was determined based on significant levels of inputs described in the following hierarchy:

• Level 1 - Quoted prices are available in active markets for identical assets or liabilities as of the reporting date. Active markets are those in which transactions occur in sufficient frequency and volume to provide pricing information on an ongoing basis.

• Level 2 - Pricing inputs are other than quoted prices in active markets included in Level 1. Prices in Level 2 are either directly or indirectly observable as of the reporting date. Level 2 valuations are based on inputs, including quoted forward prices for commodities, time value and volatility factors, which can be substantially observed or corroborated in the marketplace.

• Level 3 - Valuations in this level are those with inputs for the asset or liability that are not based on observable market data.

Assessment of the significance of a particular input to the fair value measurement requires judgment and may affect the placement within the fair value hierarchy level. The Company’s risk management contracts are considered Level 2.

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5. EXPLORATION AND EVALUATION ASSETS

The components of the Company’s exploration and evaluation ("E&E") assets are as follows:

$000s
Balance, December 31, 2018	42,410
Additions	18
Disposition	(1,177)
Exploration and evaluation expense	(2,004)
Capitalized G&A	376
Capitalized share-based compensation	32
Transfers to property, plant and equipment_(note 6)_	(453)
Impairment	(3,086)
Balance, December 31, 2019	36,116
Additions	4,590
Disposition	(58)
Exploration and evaluation expense	(18)
Capitalized G&A	279
Capitalized share-based compensation_(note 11)_	26
Transfers to property, plant and equipment_(note 6)_	(367)
Impairment	(23,000)
Balance, December 31, 2020	17,568

During the year ended December 31, 2020, the Company capitalized $0.3 million of general and administrative expenses (“G&A”) (2019 – $0.4 million) and $0.03 million of non-cash share-based compensation directly attributable to exploration activities (2019 – $0.03 million).

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, Central Alberta and Kakwa CGUs during the year ended December 31, 2020. For the Ferrier CGU, the Company recorded an impairment loss of $23.0 million on its E&E assets for the quarter ended March 31, 2020. The Company had also tested the Ferrier CGU for impairment on December 31, 2020 and did not record any further impairment.

As at December 31, 2019, the book value of the Company's net assets was greater than its market capitalization. The Company considered this to be an indicator of impairment and performed an impairment test on all CGUs. The Company determined the fair value less costs of disposal for its two non-core CGUs based on interest expressed during the sales process for its Foothills and Central Alberta assets. The Company recorded an impairment loss of $3.1 million on its E&E assets in the Foothills and Central Alberta CGUs during the year ended December 31, 2019. For the Ferrier CGU, no impairment charge was required was recorded during the year ended December 31, 2019.

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6. PROPERTY, PLANT AND EQUIPMENT

The components of the Company’s property, plant and equipment assets are as follows:

$000s	Cost	Accumulated DD&A	Net book value
Balance, December 31, 2018	801,090	(525,250)	275,840
Additions	16,550	—	16,550
Transition adjustment of right of use asset(1)	742	—	742
Addition of right of use asset(1)	709	—	709
Capitalized G&A	1,129	—	1,129
Capitalized share-based compensation_(note 11)_	97	—	97
Transfers from exploration and evaluation assets_(note 5)_	453	—	453
Depletion & depreciation	—	(36,564)	(36,564)
Increase in decommissioning provision_(note 9)_	1,091	—	1,091
Impairment	—	(21,569)	(21,569)
Balance, December 31, 2019	821,861	(583,383)	238,478
Additions	8,600	—	8,600
Capitalized G&A	838	—	838
Capitalized share-based compensation_(note 11)_	77	—	77
Transfers from exploration and evaluation assets_(note 5)_	367	—	367
Depletion & depreciation	—	(25,231)	(25,231)
Increase in decommissioning provision_(note 9)_	3,840	—	3,840
Impairment	—	(75,000)	(75,000)
Balance, December 31, 2020	835,583	(683,614)	151,969

(1)Right of use asset pertains to corporate office lease.

At December 31, 2020, estimated future development costs of $252.3 million (2019 – $267.7 million) associated with the development of the Company’s proved plus probable undeveloped reserves were included with the costs subject to depletion. During the year ended December 31, 2020, the Company capitalized $0.8 million of general and administrative expenses (“G&A”) (2019 – $1.1 million) and non-cash share-based compensation of $0.1 million (2019 – $0.1 million), directly attributable to development activities.

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 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 $75 million on its PP&E asset on March 31, 2020, as the carrying amount exceeded the recoverable amount. The Company had also tested the Ferrier CGU for impairment on December 31, 2020 and did not record any further impairment.

The recoverable amount, a level 3 input on the fair value hierarchy, was estimated at its value-in-use, using a pre-tax discount rate of 11.0% to 12.5%. A 1% increase in the discount rate would have increase impairment by approximately $7 million. A 1% decrease in the discount rate would decrease impairment by approximately $6 million. The Company uses the following forward commodity price estimates:

	Canadian Light Sweet
Year	40 API $/Bbl	AECO $/MMbtu
2021	54.55		2.86
2022	57.14		2.78
2023	63.64		2.69
2024	64.91		2.75
2025	66.21		2.80
2026	67.53		2.86
2027	68.88		2.91
2028	70.26		2.97
2029	71.66		3.03
2030	73.10		3.09
2031	74.56		3.15

Escalation rate of 2.0% thereafter.

As at December 31, 2019, the book value of the Company's net assets was greater than its market capitalization. The Company considered this to be an indicator of impairment and performed an impairment test of each of its CGUs. The Company determined the fair value less costs of disposal for its two

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non-core CGUs based on interest expressed during the sales process for its Foothills and Central Alberta assets. The Company recorded an impairment loss of $21.6 million on its PP&E assets in the Foothills and Central Alberta CGUs during the year ended December 31, 2019. For the Ferrier CGU the recoverable amount exceeded the carrying value therefore no impairment was recorded. The recoverable amount, a level 3 input on the fair value hierarchy (see note 4), was estimated at fair value less costs of disposal based on proved plus probable reserves and applying an after-tax discount rate ranging from 9% to 10% on the estimated future cash flow.

At December 31, 2020, the carrying balance of the right of use asset was $1.0 million (December 31, 2019 - $1.2 million).

7. DEBT

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 redetermined borrowing base.

(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 ("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 December 31, 2020, the Company had a working capital deficiency (excluding non-cash risk management assets and liabilities) of $114.5 million which has increased due to the reclassification of the Company's borrowings under its RCF and Term Loan. See note 2(a).

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 Company's RCF and Term Loan are subject to certain financial covenants. The following definitions are used in the covenant calculations for both debt instruments:

Working Capital

Working Capital means Current Assets to Current Liabilities whereby Current Assets means on any date of determination, the current assets of Petrus that would, in accordance with IFRS, be classified as of that date as current assets plus any undrawn availability under the RCF, less any non-cash amount required to be included in current assets as the result of the application of IFRS including non-cash commodity and interest rate

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hedges assets and liabilities and whereby Current Liabilities means, on any date of determination, the liabilities of Petrus that would, in accordance with IFRS, be classified as of that date as current liabilities, excluding (a) non-cash obligations under IFRS including non-cash commodity and interest rate hedges assets and liabilities, and (b) the current portion of long-term debt.

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

The RCF carries the following covenants:

• i. The Company is unable to borrow amounts greater than the RCF limit; and

• ii. the Working Capital ratio shall not be less than 0.6:1.0.

The key financial covenant as at December 31, 2020 is summarized in the following table. At December 31, 2020 the Company is in compliance with its financial covenants.

Financial Covenant Description	Required Ratio	As at December 31, 2020
Working Capital Ratio	Over 0.6	1.67

8. LEASES

The Company's lease obligations are as follows:

The Company's lease obligations are as follows:
$000s
Balance, January 1, 2020	1,149
Finance expense	82
Leasepayments	(219)
Balance, December 31, 2020	1,012

The Company's future commitments associated with its lease obligations are as follows:

$000s
	As at December 31, 2020
Less than 1 year	262
1 to 3 years	825
4 to 5 years	92
After 5years	—
Total lease payments	1,179
Amounts representingfinance expense	(167)
Present value of lease obligation	1,012
Current portion of lease obligation	188
Non-currentportion of lease obligation	824

9. DECOMMISSIONING OBLIGATION

The decommissioning liability was estimated based on the Company’s net ownership interest in all wells and facilities, the estimated costs to abandon and reclaim the wells and facilities and the estimated timing of the costs to be incurred in future periods. The estimated future cash flows have been discounted using an average risk free rate of 1.10 percent and an inflation rate of 1.40 percent (2019 – 1.76 percent and 1.75 percent, respectively). Changes in estimates in 2019 and 2020 are due to the changes in the risk free rate and changes in the estimated future cash flow to reclaim the wells and facilities. The Company has estimated the net present value of the decommissioning obligations to be $44.5 million as at December 31, 2020 (December 31, 2019 – $41.3 million). The undiscounted, uninflated total future liability at December 31, 2020 is $41.4 million (December 31, 2019 – $41.4 million). The payments are expected to be incurred over the operating lives of the assets.

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The following table reconciles the decommissioning liability:

$000s
Balance, December 31, 2018	40,224
Property dispositions	(24)
Liabilities incurred	729
Liabilities settled	(849)
Change in estimates	402
Accretion expense	777
Balance, December 31, 2019	41,259
Property dispositions	(98)
Other adjustments	(135)
Liabilities incurred	320
Liabilities settled	(904)
Change in estimates	3,520
Accretion expense	494
Balance, December 31, 2020	44,456

10. FINANCIAL RISK MANAGEMENT

The Company utilizes commodity contracts as a risk management technique to mitigate exposure to commodity price volatility. The following table summarizes the financial derivative contracts Petrus had outstanding as at December 31, 2020:

Contract Period	Type	Total Daily Volume (GJ)	Average Price (CDN$/GJ)
Natural Gas Swaps
Jan. 1, 2021 to Mar. 31, 2021	Fixed price	13,000	$3.39
Jan. 1, 2021 to May. 31, 2021	Fixed price	3,000	$2.67
Jan. 1, 2021 to Oct. 31, 2021	Fixed price	1,000	$1.53
Apr. 1, 2021 to Oct. 31, 2021	Fixed price	10,000	$2.02
Nov. 1, 2021 to Dec. 31, 2021	Fixed price	5,000	$2.81
Nov. 1, 2021 to Mar. 31, 2022	Fixed price	5,000	$2.51
Jan. 1, 2022 to Mar. 31, 2022	Fixed price	2,000	$2.61
Contract Period	Type	Total Daily Volume (Bbl)	Average Price (CDN$/Bbl)
Crude Oil Swaps
Jan. 1, 2021 to Mar. 31, 2021	Fixed price	200	$71.06
Jan. 1, 2021 to Jun. 30, 2021	Fixed price	300	$74.02
Jul. 1, 2021 to Dec. 31, 2021	Fixed price	500	$66.64
Jan. 1, 2022 to Mar. 31, 2022	Fixed price	200	$60.00
Contract Period	Type	Average Rate (%)	Notional Amount (000s CDN$)
Interest Rate Swaps
Jan. 1, 2021 to Dec. 31, 2022	Fixed rate	2.34	$20,000

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Risk management asset and liability:
$000s At December 31, 2020	Asset	Liability
Current commodity derivatives	934	986
Non-current commodityderivatives	15	41
	949	1,027
$000s At December 31, 2019
Current commodity derivatives	—	1,679
Non-current commodityderivatives	11	74
	11	1,753
Earnings impact of realized and unrealized gains (losses) on financial derivatives:
$000s	Year ended	Year ended
	December 31, 2020	December 31, 2019
Realized gain (loss) on financial derivatives	6,518	(1,344)
Unrealized gain (loss) on financial derivatives	1,661	(11,273)
Net gain (loss) on financial derivatives	8,179	(12,617)

11. SHARE CAPITAL

Authorized

The authorized share capital consists of an unlimited number of common voting shares without par value and an unlimited number of preferred shares.

Issued and Outstanding

Common shares ($000s)	Number of Shares	Amount
Balance, December 31, 2018	49,491,840	430,119
Cancelled(1)	(22,482)	—
Balance, December 31, 2019 and December 31, 2020	49,469,358	430,119

(1)On February 4, 2019, 22,482 shares were cancelled pursuant to the Arrangement Agreement between Phoscan Chemical Corp. and Petrus Resources Ltd. (and the 3 year sunset clause therein).

SHARE-BASED COMPENSATION

Stock Options

The Company has a stock option plan in place whereby it may issue stock options to employees, consultants and directors of the Company. The aggregate number of shares that may be acquired upon exercise of all options granted pursuant to the plans shall, at any date or time of determination, be equal to ten percent (10%) of the number that is equal to (i) the number of the Company’s basic common shares then issued and outstanding; minus (ii) a number equal to five (5) times the number of common shares that are issuable upon exercise of the then outstanding Performance Warrants, if any, minus (iii) a number equal to fifty percent (50%) of the number of common shares that have previously been issued upon the exercise of Performance Warrants, if any.

At December 31, 2020, 2,276,923 (December 31, 2019 – 2,361,958) stock options were outstanding. The summary of stock option activity is presented below:

	Number of stock	Weighted average
	options	exerciseprice
Balance, December 31, 2018	**3,082,880 **	$2.87
Granted	1,386,357	$0.33
Cancelled/forfeited	(707,069)	$1.74
Expired	(1,400,210)	$4.20
Balance, December 31, 2019	**2,361,958 **	$2.87
Granted	1,122,276	$0.23
Cancelled/forfeited	(353,320)	$1.06
Expired	(853,991)	$2.16
Balance, December 31, 2020	**2,276,923 **	$0.40
Exercisable, December 31, 2020	**288,599 **	$0.75

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The following table summarizes information about the stock options granted since inception:

Range of Exercise Price	Stock	Options Outstanding	Options Outstanding	Stock	Options Exercisable	Options Exercisable
			Weighted			Weighted
		Weighted	average		Weighted	average
	Number	average	remaining life	Number	average	remaining life
	granted	exercise price	(years)	exercisable	exercise price	(years)
$0.26 - $0.86	2,131,923	$0.30	2.33	227,599	$0.25	0.1
$1.49 -$2.33	145,000	$1.84	0.31	61,000	$0.49	0.01
	**2,276,923 **	$1.75	1.69	288,599	$0.75	0.1

During the year ended December 31, 2020 and the year ended December 31, 2019, the Company granted options which vest equally over three years, and upon vesting, expire 30 business days thereafter. The weighted average fair value of each option granted during the year ended December 31, 2020 of $0.11 (2019 – $0.11) was estimated on the date of grant using the Black-Scholes pricing model with the following weighted average assumptions:

	2020	2019
Risk free interest rate	0.20% - 0.29%	1.57% - 1.83%
Expected life (years)	1.08 - 3.08	1.08 - 3.08
Estimated volatility of underlying common shares (%)	80% to 100%	73% - 81%
Estimated forfeiture rate	20 %	20 %
Expected dividendyield (%)	— %	— %

Petrus estimated the volatility of the underlying common shares by analyzing the Company's volatility as well as the volatility of peer group public companies with similar corporate structure, oil and gas assets and size.

Deferred Share Unit ("DSU") Plan

The Company has a deferred share unit plan in place whereby it may issue deferred share units to directors of the Company. The aggregate number of shares that may be issued from treasury of Petrus pursuant to the plan shall not exceed: (i) five percent (5%) of the number of issued and outstanding common shares of the Company (on a non-diluted basis) at the date of issue; and (ii) ten percent (10%) of the number of issued and outstanding common shares of the Company (on a non-diluted basis) at the date of issue, less the aggregate number of common shares of the Company reserved for issuance under any other share compensation plan.

Each DSU entitles the participants to receive, at the Company's discretion, either shares of the Company or cash equal to the trading price of the equivalent number of shares of the Company. All DSUs granted vest and become payable upon retirement of the director.

The compensation expense was calculated using the fair value method based on the weighted average trading price of the Company's shares for the five trading days ending on the reporting period date. At December 31, 2020, 2,158,270 DSUs were issued and outstanding (2019 –1,177,510).

The following table summarizes the Company’s share-based compensation costs:

The following table summarizes the Company’s share-based compensation costs:
	~~Year ended~~	~~Year ended~~
$000s	December 31, 2020	December 31, 2019
Expensed	152	401
Capitalized to exploration and evaluation assets	26	32
Capitalized to property, plant and equipment	77	97
Deferred share units	229	198
Total share-based compensation	484	728

12. LOSS PER SHARE

Loss per share amounts are calculated by dividing the net loss for the year attributable to the common shareholders of the Company by the weighted average number of common shares outstanding during the period.

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	Year ended	Year ended
	December 31, 2020	December 31, 2019
Net loss for the period ($000s)	(97,554)	(42,176)
Weighted average number of common shares – basic (000s)	49,469	49,472
Weighted average number of common shares – diluted(000s)	49,469	49,472
Net loss per common share – basic	($1.97)	($0.85)
Net loss per common share – diluted	($1.97)	($0.85)

In computing diluted loss per share for the year ended December 31, 2020, 2,276,923 outstanding stock options and 2,158,270 DSUs were considered (December 31, 2019 – 2,361,958 and 739,046, respectively), which were excluded from the calculation as their impact was anti-dilutive.

13. OPERATING EXPENSES

The Company’s operating expenses consisted of the following expenditures:

$000s
	2020	2019
Fixed and variable operating expenses	9,673	10,668
Processing, gathering and compression charges	2,463	3,167
Total gross operating expenses	12,136	13,835
Overhead recoveries	(913)	(962)
Total net operating expenses	11,223	12,873

14. GENERAL AND ADMINISTRATIVE EXPENSES

The Company’s general and administrative expenses consisted of the following expenditures:

$000s
	2020	2019
Gross general and administrative expense	5,248	6,217
Capitalized general and administrative expense	(1,117)	(1,506)
Overhead recoveries	(722)	(1,067)
General and administrative expense	3,409	3,644

15. FINANCIAL INSTRUMENTS

RISKS ASSOCIATED WITH FINANCIAL INSTRUMENTS

Credit risk

The Company’s accounts receivable are with customers and joint venture partners in the petroleum and natural gas business and are subject to normal credit risk. Concentration of credit risk is mitigated by marketing the majority of the Company’s production to reputable and financially sound purchasers under normal industry sale and payment terms. As is common in the petroleum and natural gas industry in western Canada, Petrus’ receivables relating to the sale of petroleum and natural gas are received on or about the 25th day of the following month. Of the $6.3 million of accounts receivable outstanding at December 31, 2020 (December 31, 2019 – $13.0 million), $4.7 million is owed from 3 parties (December 31, 2019 – $5.7 million from 3 parties), and the balances were received subsequent to year end. The Company considers accounts receivable outstanding past 120 days to be 'past due'. At December 31, 2020, the Company had an allowance for doubtful accounts of $0.5 million (December 31, 2019 – $0.4 million). At December 31, 2020, 91% of Petrus’ accounts receivable were aged less than 120 days and 9% of Petrus' accounts receivable were aged greater than 120 days. The Company does not anticipate any material collection issues.

The Company’s risk management assets and cash are with chartered Canadian banks and the Company does not consider these assets to carry material credit risk.

Liquidity risk

At December 31, 2020, the Company had an $83.0 million RCF, on which $77.5 million was drawn (December 31, 2019 – $92.3 million). While the Company is exposed to the risk of reductions to the borrowing base of the RCF, the Company anticipates it will continue to have adequate liquidity to fund its financial liabilities through funds flow and available credit capacity from its RCF. The next scheduled borrowing base redetermination date for the RCF is on or before May 31, 2021. See additional discussion in note 7.

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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.

Interest Rate Risk

Interest rate risk is the risk that future cash flows will fluctuate as a result of changes in market interest rates. The Company’s cash, bank indebtedness and accounts receivable are not exposed to significant interest rate risk. The RCF and Term Loan are exposed to interest rate cash flow risk as the instruments are priced on a floating interest rate subject to fluctuations in market interest rates. The remainder of Petrus’ financial assets and liabilities are not exposed to interest rate risk. To manage exposure to interest rate volatility, the Company entered into interest rate swap contracts (note 10). A 1% increase in the Canadian prime interest rate during the year ended December 31, 2020 would have increased net loss by approximately $1.0 million, respectively, which relates to interest expense on the average outstanding RCF and Term Loan, net of any interest rate swaps to fix the interest rate on loans, during the year assuming that all other variables remain constant (December 31, 2019 – increase net loss by $1.1 million). A 1% decrease in the Canadian prime interest rate during the year would result in an opposite impact on net loss.

Commodity Price Risk

Commodity price risk is the risk that the fair value of future cash flows will fluctuate as a result of changes in commodity prices. A significant change in commodity prices can materially impact the Company’s borrowing base limit under its Revolving Credit Facility and may reduce the Company’s ability to raise capital. Commodity prices for petroleum and natural gas are not only influenced by Canadian and United States demand, but also by world events that dictate the levels of supply and demand.

The Company manages the risks associated with changes in commodity prices by entering into a variety of financial derivative contracts (see note 10). The Company assesses the effects of movement in commodity prices on net loss. When assessing the potential impact of these commodity price changes, the Company believes a $5/CDN WTI/bbl change in the price of oil and a $0.25/GJ change in the price of natural gas are reasonable measures.

As at December 31, 2020, it was estimated that a $0.25/GJ decrease in the price of natural gas would have decreased net loss by $1.3 million (December 31, 2019 – $1.5 million). An opposite change in commodity prices would result in an opposite impact on net loss. As at December 31, 2020, it was estimated that a $5.00/CDN WTI/bbl decrease in the price of oil would have decreased net loss by $1.1 million (December 31, 2019 – $0.2 million). An opposite change in commodity prices would result in an opposite impact on net loss.

16. CAPITAL MANAGEMENT

The Company’s general capital management policy is to maintain a sufficient capital base in order to manage its business to enable the Company to increase the value of its assets and therefore its underlying share value. In the management of capital, the Company includes share capital and total net debt, which is made up of debt and working capital (current assets less current liabilities). The Company manages its capital structure and makes adjustments in light of economic conditions and the risk characteristics of the underlying assets. In order to maintain or adjust the capital structure, Petrus may issue new equity, increase or decrease debt, adjust capital expenditures and acquire or dispose of assets.

17. FINANCE EXPENSES

The components of finance expenses are as follows:

$000s
	2020	2019
Cash:
Interest	6,661	8,241
Total cash finance expenses	6,661	8,241
Non-cash:
Deferred financing costs	625	495
Non-cash term loan interest payment-in-kind	1,813	—
Accretion on decommissioningobligations_(note 9)_	494	777
Total non-cash finance expenses	2,932	1,272
Total finance expenses	9,593	9,513

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18. SUPPLEMENTAL CASH FLOW INFORMATION

The following table reconciles the changes in non-cash working capital as disclosed in the statements of cash flows:

$000s
		2020	2019
Source (use) in non-cash working capital:
Deposits and prepaid expenses		179	(31)
Transaction costs on debt		(773)	196
Accounts receivable		6,758	(361)
Accountspayable and accrued liabilities		(3,655)	(10,284)
		2,509	(10,480)
Operating activities		2,527	(5,803)
Financing activities		162	196
Investingactivities		(179)	(4,873)

The following table reconciles the changes in liability resulting from financing activities:

$000s	Bank Indebtedness	Revolving Credit Facility	**Term Loan **	Total Liabilities from Financing Activities
Balance, December 31, 2019	—	92,250	34,752	127,002
Cash flows	32	(14,750)	—	(14,718)
Payment-in-kind	—	—	1,813	1,813
Non-cash changes	—	(16)	—	(16)
Balance, December 31, 2020	32	77,484	36,565	114,082

19. COMMITMENTS AND CONTINGENCIES

COMMITMENTS

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

CONTINGENCIES

In the normal course of Petrus’ operations, the Company may become involved in, named as a party to, or be the subject of, various legal proceedings. The outcome of outstanding, pending or future proceedings cannot be predicted with certainty. Petrus does not anticipate that these claims will have a material impact on its financial position.

20. REVENUE

The following table presents Petrus' oil and natural gas revenue disaggregated by product type:

$000s
	2020	2019
Production Revenue
Oil and condensate sales	16,493	37,815
Natural gas sales	26,023	22,052
Naturalgas liquids sales	7,472	10,917
Total oil and natural gas production revenue	49,988	70,784
Royaltyrevenue	380	614
Total oil and naturalgas revenue	50,368	71,398

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21. RELATED PARTY TRANSACTIONS

The Company considers its directors and officers to be key management personnel. The following table outlines transactions with key management personnel:

$000s	2020	2019
Salaries, consulting fees, benefits and director fees, gross	890	1,646
Share based compensation,gross	228	473
	1,118	2,119

22. DEFERRED INCOME TAXES

$000s
	2020	2019
Loss before taxes	(97,554)	(42,176)
Combined federal and provincial tax rate	24.0 %	26.5 %
Computed “expected” tax recovery	(23,413)	(11,177)
Increase/(decrease) in taxes resulting from:
Permanent items	4	4
Share based payments	103	108
Share issuance costs	—	(94)
Impact of rate change	976	9,767
True up and other	596	(355)
Unrecognized deferred income tax asset	21,734	1,747
Deferred tax expense (recovery)	—	—
Effective tax rate	— %	— %

The components of the Company’s deferred tax position at December 31, 2020 and 2019 are as follows:

$000s
	2020	2019
Exploration and evaluation assets and property, plant and equipment	—	(7,652)
Share issuance costs	—	155
Non capital loss carry-forwards	—	7,267
Unrealized hedgingloss	—	230
Deferred tax liability	—	—

The Company has unrecognized deductible temporary differences of approximately $341.3 million (2019 – $246.8 million) which may be applied against future income for Canadian tax purposes. These amounts include non-capital losses which begin to expire in 2027. At December 31, 2020, the Company has determined it is currently not probable that future taxable profits will be available against which the tax benefits will be utilized.

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CORPORATE INFORMATION

OFFICERS

Neil Korchinski, P. Eng. President and Chief Executive Officer

Chris Graham Vice President, Finance and Chief Financial Officer

DIRECTORS

Don T. Gray Chairman Scottsdale, Arizona

Neil Korchinski Calgary, Alberta

SOLICITOR

Burnet, Duckworth & Palmer LLP Calgary, Alberta

AUDITOR

Ernst & Young LLP Chartered Professional Accountants Calgary, Alberta

Patrick Arnell Calgary, Alberta

Donald Cormack Calgary, Alberta

Stephen White Calgary, Alberta

INDEPENDENT RESERVE EVALUATORS

Sproule and Associates Calgary, Alberta

BANKERS

TD Securities (Syndicate Lead Agent) Calgary, Alberta

Macquarie Bank Limited Houston, Texas

TRANSFER AGENT

Odyssey Trust Company Calgary, Alberta

HEAD OFFICE

2400, 240 – 4th Avenue S.W. Calgary, Alberta T2P 4H4 Phone: 403-984-9014 Fax: 403-984-2717

WEBSITE

www.petrusresources.com

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