ANNUAL REPORT
December 31, 2020
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.
Page |2
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)
Reserve Category
Proved Producing
Proved Non-Producing
Proved Undeveloped
Total Proved
Proved + Probable Producing
Total Probable
Conventional
Natural Gas
(mmcf)
Light and
Medium
Crude Oil
(mbbl)
53,172
309
52,448
105,929
66,071
65,186
1,158
8
943
2,109
1,435
2,231
NGL
(mbbl)
Total
(mboe)
NPV 0%(2)
($000s)
NPV 5%(2)
($000s)
NPV 10%(2)
($000s)
2,150
14
3,492
5,657
2,650
2,894
12,170
74
13,177
25,421
15,097
15,989
120,922
130,024
119,122
726
113,185
234,833
167,144
224,418
639
68,344
199,007
154,424
142,949
571
39,745
159,438
133,562
97,553
Total Proved Plus Probable
(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).
171,115
459,251
341,956
256,991
41,410
8,551
4,340
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.
Page |3
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 ($000s)
Total Proved
Total Proved + Probable
2021
2022
2023
2024
2025
2026
2027
Thereafter
Total FDC, Undiscounted
Total FDC, Discounted at 10%
28,582
45,758
57,783
6,164
12,944
5,583
—
—
156,815
129,059
36,242
70,913
65,731
20,582
28,895
11,129
18,844
—
252,335
198,745
PERFORMANCE RATIOS
The following table highlights annual performance ratios for the Company from 2016 to 2020:
Proved Producing
FD&A ($/boe) (1)(2)
F&D ($/boe) (1)(2)
Reserve Life Index (yr) (1)
Reserve Replacement Ratio (1)
FD&A Recycle Ratio (1)
Proved Developed
FD&A ($/boe) (1)(2)
F&D ($/boe) (1)(2)
Reserve Life Index (yr) (1)
Reserve Replacement Ratio (1)
FD&A Recycle Ratio (1)
Total Proved
FD&A ($/boe) (1)(2)
F&D ($/boe) (1)(2)
Reserve Life Index (yr) (1)
Reserve Replacement Ratio (1)
FD&A Recycle Ratio (1)
Future Development Cost ($000s)
December 31, 2020
December 31, 2019
December 31, 2018
December 31, 2017
December 31, 2016
4.83
4.83
5.2
1.2
2.6
4.71
4.71
5.2
1.2
2.7
1.29
1.29
10.9
(1.0)
9.8
13.31
12.81
3.8
0.4
1.2
12.49
12.03
4.8
0.5
1.3
1.09
(6.83)
9.9
0.3
14.4
37.76
42.27
4.6
0.2
0.4
11.34
11.55
5.6
0.6
1.4
8.73
8.16
11.1
1.3
1.8
13.05
11.57
4.1
1.6
1.1
16.74
14.62
4.5
1.2
0.9
14.33
12.03
8.0
1.1
1.0
(0.43)
9.89
4.4
0.4
(24.8)
(0.23)
7.69
5.3
0.7
(46.3)
(15.78)
2.46
9.8
0.5
(0.7)
156,815
174,027
194,757
182,086
201,556
0.37
0.37
(7.32)
Total Proved + Probable
FD&A ($/boe) (1)(2)
F&D ($/boe) (1)(2)
Reserve Life Index (yr) (1)
Reserve Replacement Ratio (1)
FD&A Recycle Ratio (1)
Future Development Cost ($000s)
(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.
252,335
267,652
269,144
283,030
290,876
350.09
190.21
(8.06)
(1.3)
(2.1)
14.87
17.28
(0.1)
33.7
17.7
12.3
17.1
5.15
6.49
14.6
15.4
2.4
1.0
1.7
1.5
—
—
Page |4
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)
Present Value Reserves, before tax (discounted at 10%) (1)
Undeveloped Land Value (2)
Net Debt (3)
Net Asset Value
Proved Developed
Producing
Total Proved
Proved + Probable
119,122
17,568
(114,361)
22,329
159,438
17,568
(114,361)
62,645
256,991
17,568
(114,361)
160,198
$3.24
Estimated Net Asset Value per Share
(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.
$0.45
$1.27
Page |5
MANAGEMENT’S DISCUSSION & ANALYSIS
The following is Management’s Discussion and Analysis ("MD&A") of the financial and operating results of Petrus Resources Ltd. ("Petrus"
or the "Company") as at and for the three and twelve months ended December 31, 2020. This MD&A is dated February 24, 2021 and
should be read in conjunction with the Company's audited consolidated financial statements for the years ended December 31, 2020 and
2019. The Company’s audited consolidated financial statements are prepared in accordance with Canadian generally accepted accounting
principles ("GAAP") which require publicly accountable enterprises to prepare their financial statements using International Financial
Reporting Standards ("IFRS"). Readers are directed to the "Advisories" section at the end of this MD&A regarding forward-looking
statements and boe presentation and to the section "Non-GAAP Financial Measures" herein.
The principal undertaking of Petrus is the investment in energy assets. The operations of the Company consist of the acquisition,
development, exploration and exploitation of these assets. The Company’s head office is located at 2400, 240 - 4th Avenue SW, Calgary,
Alberta, Canada. Additional information on Petrus, including the most recently filed Annual Information Form ("AIF"), are available under
the Company's profile on SEDAR (the System for Electronic Document Analysis and Retrieval) at www.sedar.com.
Page |6
SELECTED FINANCIAL INFORMATION
OPERATIONS
Average Production
Natural gas (mcf/d)
Oil (bbl/d)
NGLs (bbl/d)
Total (boe/d)
Total (boe)
Light oil weighting
Realized Prices
Natural gas ($/mcf)
Oil ($/bbl)
NGLs ($/bbl)
Total realized price ($/boe)
Royalty income
Royalty expense
Net oil and natural gas revenue ($/boe)
Operating expense
Transportation expense
Operating netback(1) ($/boe)
Realized gain (loss) on derivatives ($/boe)
Other income
General & administrative expense
Cash finance expense
Decommissioning expenditures
Funds flow & corporate netback(1)(2)
($/boe)
FINANCIAL (000s except $ per share)
Oil and natural gas revenue
Net loss
Net loss per share
Basic
Fully diluted
Funds flow
Funds flow per share
Basic
Fully diluted
Capital expenditures
Net dispositions
Weighted average shares outstanding
Basic
Fully diluted
As at year end
Common shares outstanding
Basic
Fully diluted
Total assets
Non-current liabilities
Net debt(1)
Twelve months
ended
Twelve months
ended
Three months
ended
Three months
ended
Three months
ended
Three months
ended
Dec. 31, 2020
Dec. 31, 2019
Dec. 31, 2020
Sept. 30, 2020
Jun. 30, 2020
Mar. 31, 2020
27,640
1,021
980
6,608
32,032
1,616
1,351
8,306
26,177
980
1,014
6,357
26,181
1,103
997
6,463
2,418,259
3,031,659
584,860
594,599
27,630
867
819
6,291
572,440
30,604
1,134
1,088
7,323
666,361
15 %
19 %
15 %
17 %
14 %
15 %
2.57
44.14
20.84
20.67
0.16
(2.15)
18.68
(4.64)
(1.43)
12.61
2.70
0.15
(1.41)
(2.75)
(0.37)
10.93
1.89
64.11
22.13
23.35
0.20
(2.35)
21.20
(4.25)
(1.26)
15.69
(0.44)
0.03
(1.20)
(2.72)
(0.28)
11.08
3.07
49.64
23.52
24.05
0.13
(2.02)
22.16
(5.53)
(1.68)
14.95
0.65
0.31
(1.81)
(2.49)
(0.63)
10.98
2.51
46.46
22.05
21.48
0.12
(2.09)
19.51
(4.05)
(1.63)
13.83
2.20
0.04
(1.07)
(2.16)
(0.13)
12.71
2.35
27.18
12.87
15.73
0.06
(1.51)
14.28
(4.44)
(1.40)
8.44
6.39
0.17
(1.43)
(3.20)
(0.15)
10.22
2.40
50.02
23.19
21.23
0.30
(2.85)
18.68
(4.55)
(1.05)
13.08
1.76
0.07
(1.35)
(3.13)
(0.56)
9.87
Twelve months
ended
Twelve months
ended
Three months
ended
Three months
ended
Three months
ended
Three months
ended
Dec. 31, 2020
Dec. 31, 2019
Dec. 31, 2020
Sept. 30, 2020
Jun. 30, 2020
Mar. 31, 2020
50,368
(97,554)
(1.97)
(1.97)
26,397
0.53
0.53
14,298
—
49,469
49,469
49,469
49,469
177,914
45,321
114,361
71,398
(42,176)
(0.85)
(0.85)
33,625
0.68
0.68
18,073
651
49,472
49,472
49,469
49,469
289,225
42,346
123,744
14,143
(151)
12,840
(3,678)
—
—
6,423
0.13
0.13
2,797
—
49,469
49,469
49,469
49,469
177,914
45,321
114,361
(0.07)
(0.07)
7,551
0.15
0.15
2,543
—
49,469
49,469
49,469
49,469
179,895
44,471
116,717
9,041
(6,281)
(0.13)
(0.13)
5,855
0.12
0.12
305
—
49,469
49,469
49,469
49,469
184,532
43,017
120,570
14,344
(87,444)
(1.77)
(1.77)
6,566
0.13
0.13
8,655
—
49,469
49,469
49,469
49,469
193,679
38,533
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.
Page |7
OPERATIONS UPDATE
Fourth quarter average production by area was as follows:
For the three months ended December 31, 2020
Natural gas (mcf/d)
Oil (bbl/d)
NGLs (bbl/d)
Total (boe/d)
Ferrier
19,637
569
860
4,702
Foothills
1,425
113
7
357
Central Alberta
5,118
298
147
1,298
Total
26,180
980
1,014
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.
Capital Expenditures ($000s)
Drill and complete
Oil and gas equipment
Land and lease
Office
Capitalized general and administrative expense
Total capital expenditures
Gross (net) wells spud
Three months ended
Three months ended
Twelve months ended
Twelve months ended
December 31, 2020
December 31, 2019
December 31, 2020
December 31, 2019
1,585
777
57
—
378
2,797
1 (1.0)
3,604
283
17
8
439
4,351
3 (0.5)
11,477
1,612
92
—
1,117
14,298
4 (3.2)
12,871
3,635
37
24
1,506
18,073
10 (3.1)
The following table summarizes the dispositions for the reporting periods indicated:
Dispositions ($000s)
Dispositions
Total dispositions
Three months ended
Three months ended
Twelve months ended
Twelve months ended
December 31, 2020
December 31, 2019
December 31, 2020
December 31, 2019
—
—
—
—
—
—
651
651
Page |8
RESULTS OF OPERATIONS
FINANCIAL AND OPERATIONAL RESULTS OF OIL AND NATURAL GAS ACTIVITIES
Average production
Natural gas (mcf/d)
Oil (bbl/d)
NGLs (bbl/d)
Total (boe/d)
Total (boe)
Revenue ($000s)
Natural gas
Oil
NGLs
Royalty revenue
Oil and natural gas revenue
Average realized prices
Natural gas ($/mcf)
Oil ($/bbl)
NGLs ($/bbl)
Total realized price ($/boe)
Hedging gain (loss) ($/boe)
Total price including hedging
($/boe)
Average benchmark prices
Natural gas
AECO 5A (C$/GJ)
AECO 7A (C$/GJ)
Crude oil
Mixed Sweet Blend Edm
(C$/bbl)
Natural gas liquids
Propane Conway (US$/bbl)
Butane Edmonton (C$/bbl)
Foreign exchange
US$/C$
Twelve months
ended
Twelve months
ended
Three months
ended
Three months
ended
Three months
ended
Three months
ended
Dec. 31, 2020
Dec. 31, 2019
Dec. 31, 2020
Sept. 30, 2020
Jun. 30, 2020
Mar. 31, 2020
27,640
1,021
980
6,608
32,032
1,616
1,351
8,306
2,418,259
3,031,659
26,023
16,493
7,472
380
50,368
2.57
44.14
20.84
20.67
2.70
23.37
22,052
37,815
10,917
614
71,398
1.89
64.11
22.13
23.35
(0.44)
22.91
26,177
980
1,014
6,357
584,860
7,395
4,475
2,195
78
14,143
3.07
49.64
23.52
24.05
0.65
24.70
26,181
1,103
997
6,463
594,599
6,035
4,714
2,022
69
12,840
2.51
46.46
22.05
21.48
2.20
23.68
27,630
867
819
6,291
572,440
5,903
2,143
959
36
9,041
2.35
27.18
12.87
15.73
6.39
22.12
30,604
1,134
1,088
7,323
666,361
6,690
5,161
2,296
197
14,344
2.40
50.02
23.19
21.23
1.76
22.99
Twelve months
ended
Twelve months
ended
Three months
ended
Three months
ended
Three months
ended
Three months
ended
Dec. 31, 2020
Dec. 31, 2019
Dec. 31, 2020
Sept. 30, 2020
Jun. 30, 2020
Mar. 31, 2020
2.09
2.12
45.69
17.94
23.23
0.75
1.67
1.54
69.03
20.34
21.70
0.75
2.50
2.62
49.34
25.50
19.32
0.77
2.02
2.04
48.96
19.78
19.04
0.74
1.89
1.81
32.17
14.54
14.56
0.74
1.93
2.03
52.28
15.40
42.42
0.74
Page |9
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)
Funds flow
Funds flow per share - basic
Funds flow per share - fully diluted
Net loss
Net loss per share - basic
Net loss per share - fully diluted
Common shares outstanding (000s)
Basic
Fully diluted
Weighted average shares outstanding (000s)
Basic
Fully diluted
Three months ended
Three months ended
Twelve months ended
Twelve months ended
December 31, 2020
December 31, 2019
December 31, 2020
December 31, 2019
6,424
0.13
0.13
(151)
—
—
49,469
49,469
49,469
49,469
9,260
0.19
0.19
(3,176)
(0.06)
(0.06)
49,469
49,469
49,469
49,469
26,397
0.53
0.53
(97,554)
(1.97)
(1.97)
49,469
49,469
49,469
49,469
33,625
0.68
0.68
(42,176)
(0.85)
(0.85)
49,469
49,469
49,472
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 (%)
Natural gas
Crude oil and condensate
Natural gas liquids
Total commodity sales from production
Three months ended
Three months ended
Twelve months ended
Twelve months ended
December 31, 2020
December 31, 2019
December 31, 2020
December 31, 2019
69 %
15 %
16 %
100 %
66 %
22 %
12 %
100 %
70 %
15 %
15 %
100 %
64 %
20 %
16 %
100 %
Page |10
The following table presents oil and natural gas revenue by product and the change from the prior comparative periods:
Oil and Natural Gas Revenue ($000s)
Three months ended
Three months ended
Twelve months
ended
Twelve months
ended
December 31, 2020
December 31, 2019
% Change
December 31, 2020
December 31, 2019
% Change
Natural gas
Crude oil and condensate
Natural gas liquids
Royalty income
Total oil and natural gas revenue
7,395
4,475
2,195
78
14,143
7,970
10,995
1,931
102
20,998
(7) %
(59) %
14 %
(24) %
(33) %
26,023
16,493
7,472
380
50,368
22,052
37,815
10,917
614
71,398
18 %
(56) %
(32) %
(38) %
(29) %
The following table provides the average benchmark the Company's average realized commodity prices:
Three months ended
Three months ended
Twelve months
ended
Twelve months
ended
December 31, 2020
December 31, 2019
% Change
December 31, 2020
December 31, 2019
% Change
Average benchmark prices
Natural gas
AECO 5A (C$/GJ)
AECO 7A (C$/GJ)
Crude oil
Mixed Sweet Blend Edm (C$/bbl)
Natural gas liquids
Propane Conway (US$/bbl)
Butane Edmonton (C$/bbl)
Average realized prices
Natural gas ($/mcf)
Oil ($/bbl)
NGLs ($/bbl)
Total average realized price
2.50
2.62
49.34
25.50
19.32
3.07
49.64
23.52
24.05
2.35
2.21
6 %
19 %
66.81
(26) %
19.78
36.96
2.65
65.16
20.62
27.39
29 %
(48) %
16 %
(24) %
14 %
(12) %
2.09
2.12
45.69
17.94
23.23
2.57
44.14
20.84
20.67
1.67
1.54
25 %
38 %
69.03
(34) %
20.34
21.70
1.89
64.11
22.13
23.35
(12) %
7 %
36 %
(31) %
(6) %
(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
Page |11
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:
Royalty Expense ($000s)
Crown
Percent of production revenue
Gross overriding
Total
Three months ended
Three months ended
Twelve months ended
Twelve months ended
December 31, 2020
December 31, 2019
December 31, 2020
December 31, 2019
443
3 %
738
1,181
1,232
6 %
986
2,218
1,785
4 %
3,409
5,194
3,298
5 %
3,816
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
Three months ended
Twelve months ended
Twelve months ended
December 31, 2020
December 31, 2019
December 31, 2020
December 31, 2019
Realized hedging gain (loss)
Unrealized hedging gain (loss)
Net gain (loss) on derivatives
381
491
872
(1,417)
(3,668)
(5,085)
6,518
1,661
8,179
(1,344)
(11,273)
(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.
Page |12
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 ($11.3 million unrealized loss in 2019) represents the change in the unrealized risk management net asset position during 2020. These
changes are a result of both the realization of hedging gains and losses during the year, changes related to contracts entered into during the
year and changes to commodity prices.
The Company’s risk management contracts provide protection from significant changes in crude oil and natural gas commodity prices for
2020, 2021 and 2022. The Company aims to hedge approximately half of its forecast production for the following year, and approximately
30% of its forecast production for the subsequent year. The Company's hedging strategy is intended to provide stability and sustainability
to the Company's economic returns, funds flow and capital development plan. A summary of Petrus’ risk management contracts is included
in note 10 of the Company’s consolidated financial statements as at and for the year ended December 31, 2020. The table below
summarizes Petrus’ average crude oil and natural gas hedged volumes. The average volume of oil hedged for 2021 (825 bbl/d) represents
41% of fourth quarter 2020 average oil production. The 15,250 GJ/day average natural gas hedged for 2021 represents 61% of fourth
quarter 2020 average natural gas production.
The following table summarizes the average fixed prices for the 2021 to 2022 oil and natural gas contracts outstanding as at the date of this
report:
Q1
Q2
2021
Q3
Q4
Avg.(1)
Q1
Q2
Oil hedged (bbl/d)
Avg. WTI fixed price ($C/bbl)
Natural gas hedged (GJ/d)
733
800
900
867
825
600
68.33
66.89
66.41
65.93
66.83
62.73
17,000
16,000
14,000
14,000
15,250
11,000
2.15
Avg. AECO 7A fixed price ($C/GJ)
(1)The volumes and prices reported are the weighted average volumes and prices for the period.
2.18
2.08
2.48
2.22
2.62
—
—
—
—
2022
Q3
—
—
—
—
Q4
Avg.(1)
—
—
150
—
—
2,750
—
2.62
OPERATING EXPENSE
The following table shows the Company’s operating expense for the reporting periods shown:
Operating Expense ($000s)
Fixed and variable operating expense
Processing, gathering and compression charges
Total gross operating expense
Overhead recoveries
Total net operating expense
Operating expense, net ($/boe)
Three months ended
Three months ended
Twelve months ended
Twelve months ended
December 31, 2020
December 31, 2019
December 31, 2020
December 31, 2019
2,853
631
3,484
(247)
3,237
5.53
2,655
980
3,635
(228)
3,407
4.47
9,673
2,463
12,136
(913)
11,223
4.64
10,668
3,167
13,835
(962)
12,873
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.
Page |13
TRANSPORTATION EXPENSE
The following table shows transportation expense paid in the reporting periods:
Transportation Expense ($000s)
Transportation expense
Transportation expense ($/boe)
Three months ended
Three months ended
Twelve months ended
Twelve months ended
December 31, 2020
December 31, 2019
December 31, 2020
December 31, 2019
983
1.68
991
1.30
3,452
1.43
3,814
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:
General and Administrative Expense ($000s)
Personnel, consultants and directors
Administrative expenses
Regulatory and professional expenses
Gross general and administrative expense
Capitalized general and administrative expense
Overhead recoveries
General and administrative expense
General and administrative expense ($/boe)
Three months ended
Three months ended
Twelve months ended
Twelve months ended
December 31, 2020
December 31, 2019
December 31, 2020
December 31, 2019
1,039
300
326
1,665
(378)
(228)
1,059
1.81
1,139
613
218
1,970
(439)
(72)
1,459
1.91
3,028
1,102
1,118
5,248
(1,117)
(722)
3,409
1.41
3,875
1,657
685
6,217
(1,506)
(1,067)
3,644
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)
Gross share-based compensation expense
Capitalized share-based compensation expense
Share-based compensation expense
Three months ended
Three months ended
Twelve months ended
Twelve months ended
December 31, 2020
December 31, 2019
December 31, 2020
December 31, 2019
163
(20)
143
125
34
159
483
(102)
381
529
(128)
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.
Page |14
FINANCE EXPENSE
The following table illustrates the Company’s finance expense which includes cash and non-cash expenses:
Finance Expense ($000s)
Interest expense
Deferred financing costs
Non-cash term loan interest payment-in-kind
Accretion on decommissioning obligations
Total finance expense
Three months ended
Three months ended
Twelve months ended
Twelve months ended
December 31, 2020
December 31, 2019
December 31, 2020
December 31, 2019
1,456
145
936
107
2,644
1,939
121
—
176
2,236
6,661
625
1,813
494
9,593
8,241
495
—
777
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 ($000s)
Depletion and depreciation expense
Depletion and depreciation expense ($/boe)
Three months ended
Three months ended
Twelve months ended
Twelve months ended
December 31, 2020
December 31, 2019
December 31, 2020
December 31, 2019
6,121
10.47
8,735
11.45
25,231
10.43
36,564
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 ($000s)
Impairment
Total
Three months ended
Three months ended
Twelve months ended
Twelve months ended
December 31, 2020
December 31, 2019
December 31, 2020
December 31, 2019
—
—
—
—
98,000
98,000
24,655
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.
Page |15
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:
Share Capital (000s)
Weighted average Common Shares outstanding
Basic
Fully diluted
Common shares outstanding
Basic
Fully diluted
Stock options outstanding
Three months ended
Three months ended
Twelve months ended
Twelve months ended
December 31, 2020
December 31, 2019
December 31, 2020
December 31, 2019
49,469
49,469
49,469
49,469
2,277
49,469
49,469
49,469
49,469
2,362
49,469
49,469
49,469
49,469
2,277
49,472
49,472
49,469
49,469
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.
Page |16
(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
Accounts payable and accrued liabilities
Risk management liability
Bank indebtedness and long term debt(1)
Lease obligations
Total
(1)Excludes deferred finance fees.
Total
7,708
1,027
114,081
1,012
123,828
< 1 year
7,708
986
114,081
188
122,963
The commitments for which the Company is responsible are as follows:
$000s
Firm service transportation
Total
12,994
< 1 year
2,045
1-5 years
9,539
1-5 years
—
41
—
824
865
> 5 years
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.
Page |17
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)
Oil (bbl/d)
NGLs (bbl/d)
Total (boe/d)
Total (boe)
Financial Results
Oil and natural gas revenue
Royalty expense
26,177
26,181
27,630
30,604
32,641
30,998
32,350
32,145
980
1,014
6,357
1,103
997
6,463
867
819
6,291
1,134
1,088
7,323
1,834
1,018
8,292
1,247
1,372
7,785
1,679
1,576
8,647
1,704
1,444
8,505
584,860
594,599
572,440
666,361
762,874
716,220
786,819
765,488
14,143
12,840
9,041
14,344
20,998
12,517
17,652
20,231
(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
Operating expense
Operating netback
Realized gain (loss) on derivatives
Other income
(983)
(967)
(799)
(703)
(991)
(893)
(959)
(971)
(3,237)
(2,408)
(2,543)
(3,035)
(3,407)
(3,181)
(3,405)
(2,880)
8,740
381
184
8,220
1,308
23
4,832
3,656
99
8,707
14,382
7,261
11,933
14,021
1,174
(1,417)
48
7
360
21
(800)
78
513
—
General and administrative expense
(1,059)
(635)
(817)
(898)
(1,459)
(776)
(530)
(879)
Cash finance expense
Decommissioning expenditures
Corporate netback and funds flow
Oil and natural gas revenue
Per share - basic
Per share - fully diluted
Net income (loss)
Per share - basic
Per share - fully diluted
Common shares outstanding (000s)
Basic
Fully diluted
Weighted average shares outstanding (000s)
Basic
Fully diluted
Total assets
Net debt
(1,456)
(1,286)
(1,831)
(2,089)
(1,939)
(2,230)
(2,126)
(1,945)
(366)
(79)
(84)
(376)
(314)
(209)
(189)
(137)
6,424
7,551
5,855
6,566
9,260
4,427
8,366
11,573
14,143
12,840
9,041
14,344
20,998
12,517
17,652
20,231
0.29
0.29
0.26
0.26
0.18
0.18
0.29
0.29
0.42
0.42
0.25
0.25
0.36
0.36
0.41
0.41
(151)
(3,678)
(6,281)
(87,444)
(3,176)
(29,569)
2,863
(12,138)
—
—
(0.07)
(0.07)
(0.13)
(0.13)
(1.77)
(1.77)
(0.06)
(0.06)
(0.60)
(0.60)
0.06
0.06
(0.25)
(0.25)
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
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
49,483
49,483
177,914
179,895
184,532
193,679
289,225
296,367
328,912
336,974
(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.
Page |18
SELECTED ANNUAL INFORMATION
($000s unless otherwise noted)
For the year ended,
Oil and natural gas revenue
Per share - basic
Per share - fully diluted
Net loss
Per share - basic
Per share - fully diluted
Common shares outstanding (000s)
Basic
Fully diluted
Weighted avg. shares outstanding (000s)
Basic
Fully diluted
Total assets
Non-current liabilities
CRITICAL ACCOUNTING ESTIMATES
December 31, 2020
December 31, 2019
December 31, 2018
50,368
1.02
1.02
(97,554)
(1.97)
(1.97)
49,469
49,469
49,469
49,469
177,914
45,321
71,398
1.44
1.44
(42,176)
(0.85)
(0.85)
49,469
49,469
49,469
49,469
289,225
42,346
80,716
1.63
1.63
(3,284)
(0.07)
(0.07)
49,492
49,492
49,492
49,492
341,820
171,646
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.
Page |19
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.
Page |20
Three months ended
Three months ended
Twelve months ended
Twelve months ended
Dec. 31, 2020
Dec. 31, 2019
December 31, 2020
December 31, 2019
$000s
$/boe
$000s
$/boe
$000s
$/boe
$000s
$/boe
Oil and natural gas revenue
Royalty expense
14,143
24.18
20,998
27.52
50,368
20.83
71,398
(1,183)
(2.02)
(2,218)
(2.91)
(5,194)
(2.15)
(7,114)
Net oil and natural gas revenue
12,960
22.16
18,780
24.61
45,174
18.68
64,284
Transportation expense
Operating expense
Operating netback
Realized gain (loss) on financial derivatives
Other income
General & administrative expense
Cash finance expense(1)
Decommissioning expenditures
Funds flow and corporate netback
(1)Excludes non-cash term loan interest payment-in-kind.
(983)
(3,237)
8,740
381
184
(1,059)
(1,456)
(366)
(1.68)
(5.53)
14.95
0.65
0.31
(1.81)
(2.49)
(0.63)
(991)
(1.30)
(3,452)
(1.43)
(3,814)
(3,407)
(4.47)
(11,223)
(4.64)
(12,873)
14,382
(1,417)
7
(1,459)
(1,939)
(314)
18.84
(1.86)
—
(1.91)
(2.54)
(0.41)
30,499
6,518
354
(3,409)
(6,661)
(904)
12.61
2.70
0.15
(1.41)
(2.75)
(0.37)
47,597
(1,344)
106
(3,644)
(8,241)
(849)
6,424
10.98
9,260
12.12
26,397
10.93
33,625
23.55
(2.35)
21.20
(1.26)
(4.25)
15.69
(0.44)
0.03
(1.20)
(2.72)
(0.28)
11.08
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.
($000s)
Adjusted current assets(1)
Less: adjusted current liabilities(1)
Less: long term debt
As at December 31, 2020 As at December 31, 2019
7,428
(121,789)
—
(114,361)
14,620
(138,364)
—
(123,744)
Net debt
(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.
Page |21
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.
Page |22
Abbreviations
$000’s
$/bbl
$/boe
$/GJ
$/mcf
bbl
bbl/d
boe
mboe
mmboe
boe/d
GJ
GJ/d
mcf
mcf/d
mmcf/d
NGLs
WTI
thousand dollars
dollars per barrel
dollars per barrel of oil equivalent
dollars per gigajoule
dollars per thousand cubic feet
barrel
barrels per day
barrel of oil equivalent
barrel of oil equivalent
thousand barrel of oil equivalent
million barrel of oil equivalent per day
gigajoule
gigajoules per day
thousand cubic feet
thousand cubic feet per day
million cubic feet per day
natural gas liquids
West Texas Intermediate
Page |23
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
c.
d.
e.
circumstances, but not for the purpose of expressing an opinion on the effectiveness of the Company’s internal control.
Evaluate the appropriateness of accounting policies used and the reasonableness of accounting estimates and related disclosures made
by management.
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.
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.
Chartered Professional Accountants
Calgary, Alberta
February 24, 2021
CONSOLIDATED BALANCE SHEETS
(Presented in 000’s of Canadian dollars)
As at
December 31, 2020
December 31, 2019
ASSETS
Current
Cash
Deposits and prepaid expenses
Accounts receivable (note 15)
Risk management asset (note 10)
Total current assets
Non-current
Risk management asset (note 10)
Exploration and evaluation assets (notes 5)
Property, plant and equipment (note 6)
Total assets
LIABILITIES AND SHAREHOLDERS’ EQUITY
Current liabilities
Bank indebtedness
Current portion of long term debt (note 7)
Accounts payable and accrued liabilities (note 15)
Risk management liability (note 10)
Lease obligations (note 8)
Total current liabilities
Non-current liabilities
Lease obligations (note 8)
Decommissioning obligation (note 9)
Risk management liability (note 10)
Total liabilities
Shareholders’ equity
Share capital (note 11)
Contributed surplus
Deficit
Total shareholders' equity
Total liabilities and shareholders' equity
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”
Don T. Gray
Chairman
—
1,150
6,278
934
8,362
15
17,568
151,969
177,914
32
114,049
7,708
986
188
122,963
824
44,456
41
168,284
430,119
9,596
(430,085)
9,630
177,914
256
1,328
13,036
—
14,620
11
36,116
238,478
289,225
—
127,002
11,362
1,679
136
140,179
1,013
41,259
74
182,525
430,119
9,112
(332,531)
106,700
289,225
(signed) “Donald Cormack”
Donald Cormack
Director
Page |28
CONSOLIDATED STATEMENTS OF NET LOSS AND COMPREHENSIVE LOSS
(Presented in 000’s of Canadian dollars, except per share amounts)
REVENUE
Oil and natural gas revenue (note 20)
Royalty expense
Net oil and natural gas revenue
Other income
Net gain (loss) on financial derivatives (note 10)
EXPENSES
Operating (note 13)
Transportation
General and administrative (note 14)
Share-based compensation (note 11)
Finance (note 17)
Exploration and evaluation (note 5)
Depletion and depreciation (note 6)
Loss (gain) on sale of assets
Impairment (notes 5 and 6)
Total expenses
NET LOSS AND COMPREHENSIVE LOSS
Net loss per common share
Basic and diluted (note 12)
See accompanying notes to the consolidated financial statements
Year ended
Year ended
December 31, 2020
December 31, 2019
50,368
(5,194)
45,174
354
8,179
53,707
11,223
3,452
3,409
381
9,593
18
25,231
(46)
98,000
151,261
(97,554)
(1.97)
71,398
(7,114)
64,284
106
(12,617)
51,773
12,873
3,814
3,644
401
9,513
2,004
36,564
481
24,655
93,949
(42,176)
(0.85)
Page |29
CONSOLIDATED STATEMENTS OF CHANGES IN SHAREHOLDERS’ EQUITY
(Presented in 000’s of Canadian dollars)
Balance, December 31, 2018
Net loss
Share-based compensation
Balance, December 31, 2019
Net loss
Share-based compensation (note 11)
Balance, December 31, 2020
See accompanying notes to the consolidated financial statements
Share
Capital
430,119
—
—
430,119
—
—
430,119
Contributed
Surplus
8,384
—
728
9,112
—
484
9,596
Deficit
(290,355)
(42,176)
—
(332,531)
(97,554)
—
(430,085)
Total
148,148
(42,176)
728
106,700
(97,554)
484
9,630
Page |30
Year ended
Year ended
December 31, 2020
December 31, 2019
(97,554)
(42,176)
381
(1,661)
1,119
1,813
25,231
98,000
18
(46)
(904)
26,397
2,527
28,924
(14,750)
32
(137)
162
(14,693)
—
(4,869)
(9,439)
—
(179)
(14,487)
(256)
256
—
6,661
401
11,273
1,272
—
36,564
24,655
2,004
481
(849)
33,625
(5,803)
27,822
(4,749)
(381)
(400)
196
(5,334)
651
(394)
(17,655)
(24)
(4,873)
(22,295)
193
63
256
8,241
CONSOLIDATED STATEMENTS OF CASH FLOWS
(Presented in 000’s of Canadian dollars)
OPERATING ACTIVITIES
Net loss
Adjust items not affecting cash:
Share-based compensation (note 11)
Unrealized loss (gain) on financial derivatives (note 10)
Non-cash finance expenses (note 17)
Non-cash term loan interest payment-in-kind
Depletion and depreciation (note 6)
Impairment (notes 5 and 6)
Exploration and evaluation expense (note 5)
Loss (gain) on sale of assets
Decommissioning expenditures (note 9)
Funds flow
Change in operating non-cash working capital (note 18)
Cash flows from operating activities
FINANCING ACTIVITIES
Repayment of revolving credit facility (note 18)
Increase (repayment) of bank indebtedness (note 18)
Repayment of lease liabilities (note 8)
Change in financing non-cash working capital (note 18)
Cash flows used in financing activities
INVESTING ACTIVITIES
Exploration and evaluation asset dispositions (note 5)
Exploration and evaluation asset expenditures (note 5)
Petroleum and natural gas property expenditures (note 6)
Other capital expenditures
Change in investing non-cash working capital (note 18)
Cash used in investing activities
Increase in cash
Cash, beginning of period
Cash, end of period
Cash interest paid (note 17)
See accompanying notes to the consolidated financial statements
Page |31
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
Page |32
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 cash-
generating 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.
Page |33
(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.
Page |34
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 flow-
through 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.
Page |35
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 stock-
based 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 "in-
the-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.
Page |36
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.
Page |37
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
Additions
Disposition
Exploration and evaluation expense
Capitalized G&A
Capitalized share-based compensation
Transfers to property, plant and equipment (note 6)
Impairment
Balance, December 31, 2019
Additions
Disposition
Exploration and evaluation expense
Capitalized G&A
Capitalized share-based compensation (note 11)
Transfers to property, plant and equipment (note 6)
Impairment
Balance, December 31, 2020
42,410
18
(1,177)
(2,004)
376
32
(453)
(3,086)
36,116
4,590
(58)
(18)
279
26
(367)
(23,000)
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.
Page |38
6. PROPERTY, PLANT AND EQUIPMENT
The components of the Company’s property, plant and equipment assets are as follows:
$000s
Balance, December 31, 2018
Additions
Transition adjustment of right of use asset(1)
Addition of right of use asset(1)
Capitalized G&A
Capitalized share-based compensation (note 11)
Transfers from exploration and evaluation assets (note 5)
Depletion & depreciation
Increase in decommissioning provision (note 9)
Impairment
Balance, December 31, 2019
Additions
Capitalized G&A
Capitalized share-based compensation (note 11)
Transfers from exploration and evaluation assets (note 5)
Depletion & depreciation
Increase in decommissioning provision (note 9)
Impairment
Balance, December 31, 2020
(1)Right of use asset pertains to corporate office lease.
Cost
801,090
16,550
742
709
1,129
97
453
—
1,091
—
821,861
8,600
838
77
367
—
3,840
—
835,583
Accumulated
DD&A
(525,250)
—
—
—
—
—
—
(36,564)
—
(21,569)
(583,383)
—
—
—
—
(25,231)
—
(75,000)
(683,614)
Net book value
275,840
16,550
742
709
1,129
97
453
(36,564)
1,091
(21,569)
238,478
8,600
838
77
367
(25,231)
3,840
(75,000)
151,969
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:
Year
2021
2022
2023
2024
2025
2026
2027
2028
2029
2030
2031
Canadian Light Sweet
40 API $/Bbl
AECO $/MMbtu
54.55
57.14
63.64
64.91
66.21
67.53
68.88
70.26
71.66
73.10
74.56
2.86
2.78
2.69
2.75
2.80
2.86
2.91
2.97
3.03
3.09
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
Page |39
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 re-
determined 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
Page |40
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.
ii.
The Company is unable to borrow amounts greater than the RCF limit; and
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
Working Capital Ratio
8. LEASES
The Company's lease obligations are as follows:
$000s
Balance, January 1, 2020
Finance expense
Lease payments
Balance, December 31, 2020
The Company's future commitments associated with its lease obligations are as follows:
$000s
Less than 1 year
1 to 3 years
4 to 5 years
After 5 years
Total lease payments
Amounts representing finance expense
Present value of lease obligation
Current portion of lease obligation
Non-current portion of lease obligation
9. DECOMMISSIONING OBLIGATION
Required Ratio
Over 0.6
As at December 31, 2020
1.67
1,149
82
(219)
1,012
As at December 31, 2020
262
825
92
—
1,179
(167)
1,012
188
824
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.
Page |41
The following table reconciles the decommissioning liability:
$000s
Balance, December 31, 2018
Property dispositions
Liabilities incurred
Liabilities settled
Change in estimates
Accretion expense
Balance, December 31, 2019
Property dispositions
Other adjustments
Liabilities incurred
Liabilities settled
Change in estimates
Accretion expense
Balance, December 31, 2020
10. FINANCIAL RISK MANAGEMENT
40,224
(24)
729
(849)
402
777
41,259
(98)
(135)
320
(904)
3,520
494
44,456
The Company utilizes commodity contracts as a risk management technique to mitigate exposure to commodity price volatility. The following table
summarizes the financial derivative contracts Petrus had outstanding as at December 31, 2020:
Contract Period
Natural Gas Swaps
Jan. 1, 2021 to Mar. 31, 2021
Jan. 1, 2021 to May. 31, 2021
Jan. 1, 2021 to Oct. 31, 2021
Apr. 1, 2021 to Oct. 31, 2021
Nov. 1, 2021 to Dec. 31, 2021
Nov. 1, 2021 to Mar. 31, 2022
Jan. 1, 2022 to Mar. 31, 2022
Contract Period
Crude Oil Swaps
Jan. 1, 2021 to Mar. 31, 2021
Jan. 1, 2021 to Jun. 30, 2021
Jul. 1, 2021 to Dec. 31, 2021
Jan. 1, 2022 to Mar. 31, 2022
Contract Period
Interest Rate Swaps
Jan. 1, 2021 to Dec. 31, 2022
Type
Total Daily Volume (GJ)
Average Price (CDN$/GJ)
Fixed price
Fixed price
Fixed price
Fixed price
Fixed price
Fixed price
Fixed price
13,000
3,000
1,000
10,000
5,000
5,000
2,000
$3.39
$2.67
$1.53
$2.02
$2.81
$2.51
$2.61
Type
Total Daily Volume (Bbl)
Average Price (CDN$/Bbl)
Fixed price
Fixed price
Fixed price
Fixed price
200
300
500
200
$71.06
$74.02
$66.64
$60.00
Type
Average Rate (%)
Notional Amount (000s CDN$)
Fixed rate
2.34
$20,000
Page |42
Risk management asset and liability:
$000s At December 31, 2020
Current commodity derivatives
Non-current commodity derivatives
$000s At December 31, 2019
Current commodity derivatives
Non-current commodity derivatives
Earnings impact of realized and unrealized gains (losses) on financial derivatives:
$000s
Realized gain (loss) on financial derivatives
Unrealized gain (loss) on financial derivatives
Net gain (loss) on financial derivatives
11. SHARE CAPITAL
Asset
934
15
949
—
11
11
Liability
986
41
1,027
1,679
74
1,753
Year ended
Year ended
December 31, 2020
6,518
December 31, 2019
(1,344)
1,661
8,179
(11,273)
(12,617)
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)
Amount
Balance, December 31, 2018
430,119
Cancelled(1)
—
Balance, December 31, 2019 and December 31, 2020
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).
Number of Shares
49,491,840
(22,482)
49,469,358
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:
Balance, December 31, 2018
Granted
Cancelled/forfeited
Expired
Balance, December 31, 2019
Granted
Cancelled/forfeited
Expired
Balance, December 31, 2020
Exercisable, December 31, 2020
Number of stock
options
3,082,880
1,386,357
(707,069)
(1,400,210)
2,361,958
1,122,276
(353,320)
(853,991)
2,276,923
288,599
Weighted average
exercise price
$2.87
$0.33
$1.74
$4.20
$2.87
$0.23
$1.06
$2.16
$0.40
$0.75
Page |43
The following table summarizes information about the stock options granted since inception:
Range of Exercise Price
Stock Options Outstanding
Stock Options Exercisable
$0.26 - $0.86
$1.49 - $2.33
Number
granted
2,131,923
145,000
2,276,923
Weighted
average
exercise price
$0.30
$1.84
$1.75
Weighted
average
remaining life
(years)
2.33
0.31
1.69
Number
exercisable
227,599
61,000
288,599
Weighted
average
exercise price
$0.25
$0.49
$0.75
Weighted
average
remaining life
(years)
0.1
0.01
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:
Risk free interest rate
Expected life (years)
Estimated volatility of underlying common shares (%)
Estimated forfeiture rate
Expected dividend yield (%)
2020
0.20% - 0.29%
1.08 - 3.08
80% to 100%
20 %
— %
2019
1.57% - 1.83%
1.08 - 3.08
73% - 81%
20 %
— %
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:
$000s
Expensed
Capitalized to exploration and evaluation assets
Capitalized to property, plant and equipment
Deferred share units
Total share-based compensation
12. LOSS PER SHARE
Year ended
Year ended
December 31, 2020
152
26
77
229
484
December 31, 2019
401
32
97
198
728
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.
Page |44
Net loss for the period ($000s)
Weighted average number of common shares – basic (000s)
Weighted average number of common shares – diluted (000s)
Net loss per common share – basic
Net loss per common share – diluted
Year ended
Year ended
December 31, 2020
(97,554)
49,469
49,469
($1.97)
($1.97)
December 31, 2019
(42,176)
49,472
49,472
($0.85)
($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
Fixed and variable operating expenses
Processing, gathering and compression charges
Total gross operating expenses
Overhead recoveries
Total net operating expenses
14. GENERAL AND ADMINISTRATIVE EXPENSES
The Company’s general and administrative expenses consisted of the following expenditures:
$000s
Gross general and administrative expense
Capitalized general and administrative expense
Overhead recoveries
General and administrative expense
15. FINANCIAL INSTRUMENTS
RISKS ASSOCIATED WITH FINANCIAL INSTRUMENTS
2020
9,673
2,463
12,136
(913)
11,223
2020
5,248
(1,117)
(722)
3,409
2019
10,668
3,167
13,835
(962)
12,873
2019
6,217
(1,506)
(1,067)
3,644
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.
Page |45
The following are the contractual maturities of financial liabilities as at December 31, 2020:
$000s
Accounts payable and accrued liabilities
Risk management liability
Bank indebtedness and long term debt(1)
Lease obligations
Total
(1)Excludes deferred finance fees.
Total
7,708
1,027
114,081
1,012
123,828
< 1 year
7,708
986
114,081
188
122,963
1-5 years
—
41
—
824
865
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
Cash:
Interest
Total cash finance expenses
Non-cash:
Deferred financing costs
Non-cash term loan interest payment-in-kind
Accretion on decommissioning obligations (note 9)
Total non-cash finance expenses
Total finance expenses
Page |46
2020
6,661
6,661
625
1,813
494
2,932
9,593
2019
8,241
8,241
495
—
777
1,272
9,513
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
Source (use) in non-cash working capital:
Deposits and prepaid expenses
Transaction costs on debt
Accounts receivable
Accounts payable and accrued liabilities
Operating activities
Financing activities
Investing activities
2020
2019
179
(773)
6,758
(3,655)
2,509
2,527
162
(179)
(31)
196
(361)
(10,284)
(10,480)
(5,803)
196
(4,873)
The following table reconciles the changes in liability resulting from financing activities:
$000s
Balance, December 31, 2019
Cash flows
Payment-in-kind
Non-cash changes
Balance, December 31, 2020
Bank Indebtedness
—
32
—
—
32
Revolving Credit
Facility
92,250
(14,750)
—
(16)
77,484
Term Loan Total Liabilities from
Financing Activities
127,002
(14,718)
1,813
(16)
114,082
34,752
—
1,813
—
36,565
19. COMMITMENTS AND CONTINGENCIES
COMMITMENTS
The commitments for which the Company is responsible are as follows:
$000s
Firm service transportation
Total
12,994
< 1 year
2,045
1-5 years
9,539
> 5 years
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
Production Revenue
Oil and condensate sales
Natural gas sales
Natural gas liquids sales
Total oil and natural gas production revenue
Royalty revenue
Total oil and natural gas revenue
2020
16,493
26,023
7,472
49,988
380
50,368
2019
37,815
22,052
10,917
70,784
614
71,398
Page |47
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
Salaries, consulting fees, benefits and director fees, gross
Share based compensation, gross
22. DEFERRED INCOME TAXES
$000s
Loss before taxes
Combined federal and provincial tax rate
Computed “expected” tax recovery
Increase/(decrease) in taxes resulting from:
Permanent items
Share based payments
Share issuance costs
Impact of rate change
True up and other
Unrecognized deferred income tax asset
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
Exploration and evaluation assets and property, plant and equipment
Share issuance costs
Non capital loss carry-forwards
Unrealized hedging loss
Deferred tax liability
2020
890
228
1,118
2019
1,646
473
2,119
2020
(97,554)
24.0 %
(23,413)
4
103
—
976
596
21,734
—
— %
2020
—
—
—
—
—
2019
(42,176)
26.5 %
(11,177)
4
108
(94)
9,767
(355)
1,747
—
— %
2019
(7,652)
155
7,267
230
—
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.
Page |48
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
Patrick Arnell
Calgary, Alberta
Donald Cormack
Calgary, Alberta
Stephen White
Calgary, Alberta
SOLICITOR
Burnet, Duckworth & Palmer LLP
Calgary, Alberta
AUDITOR
Ernst & Young LLP
Chartered Professional Accountants
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
Page |49